IVANHOE ENERGY INC - FORM 10-Q

Attached files

file	filename
EX-32.2 - EXHIBIT 32.2 - IVANHOE ENERGY INC	c23487exv32w2.htm
EX-31.2 - EXHIBIT 31.2 - IVANHOE ENERGY INC	c23487exv31w2.htm
EX-31.1 - EXHIBIT 31.1 - IVANHOE ENERGY INC	c23487exv31w1.htm
EX-32.1 - EXHIBIT 32.1 - IVANHOE ENERGY INC	c23487exv32w1.htm

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 September 30, 2011
Commission file number: 000-30586

Ivanhoe Energy Inc.

(Exact name of registrant as specified in its charter)



Yukon, Canada		98-0372413
(State or other jurisdiction of		(IRS Employer
incorporation or organization)		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 October 31, 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			24

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk			33

ITEM 4: Controls and Procedures			33

PART II

ITEM 1: Legal Proceedings			34

ITEM 6: Exhibits			35

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)


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

Assets
Current Assets
Cash and cash equivalents		3		58,168			68,317			24,362
Accounts receivable				8,248			6,359			5,021
Note receivable				222			264			225
Prepaid and other				690			2,859			771

				67,328			77,799			30,379

Intangible		4		310,430			273,568			207,750
Property, plant and equipment		5		46,966			40,618			41,983
Long term receivables				3,723			2,433			839

				428,447			394,418			280,951


Liabilities and Shareholders’ Equity
Current Liabilities
Accounts payable and accrued liabilities				23,032			21,482			10,779
Debt		6		—			39,832			—
Derivative instruments		7		286			8,447			13,023
Income taxes				734			—			530
Decommissioning costs				—			—			753

				24,052			69,761			25,085

Long term debt		6		60,146			—			36,934
Long term derivative instruments		7		1,810			—			—
Long term provisions				1,366			3,008			2,187
Deferred income taxes				21,901			21,165			22,336

				109,275			93,934			86,542


Shareholders’ Equity
Share capital		10		586,108			550,562			422,322
Contributed surplus		11		25,677			23,141			18,724
Accumulated deficit				(292,613	)		(273,219	)		(246,637	)

				319,172			300,484			194,409

				428,447			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 and Comprehensive Loss
(Unaudited)


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

Revenue
Oil				10,769			4,177			28,277			15,554
Interest				219			88			429			130

				10,988			4,265			28,706			15,684


Expenses
Operating		13		5,489			2,996			15,351			9,702
Exploration and evaluation		4		2,143			788			2,143			2,378
General and administrative				12,239			10,898			37,400			28,423
Depletion and depreciation		5		2,131			1,490			5,853			4,948
Foreign currency exchange gain				(670	)		(1,188	)		(1,133	)		(2,289	)
Derivative instruments gain		7		(5,429	)		(622	)		(12,629	)		(20,405	)
Interest				431			4			798			12
Gain on derecognition of long term provision				(1,900	)		—			(1,900	)		—

				14,434			14,366			45,883			22,769


Loss before income taxes				(3,446	)		(10,101	)		(17,177	)		(7,085	)

(Provision for) recovery of income taxes
Current				(682	)		—			(1,481	)		(115	)
Deferred				(29	)		496			(736	)		49

				(711	)		496			(2,217	)		(66	)


Net loss and comprehensive loss				(4,157	)		(9,605	)		(19,394	)		(7,151	)


Net loss per common share
Basic and diluted				(0.01	)		(0.03	)		(0.06	)		(0.02	)


Weighted average number of common shares (000s)
Basic and diluted				338,592			334,012			342,173			325,153

(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 loss and comprehensive loss				—		—		—			(7,151	)		(7,151	)
Shares issued for cash, net of share issue costs				50,000		121,697		—			—			121,697
Shares issued for services				280		799		—			—			799
Exercise of stock options		11		1,171		4,323		(2,225	)		—			2,098
Exercise of purchase warrants				2		9		—			—			9
Share-based compensation expense		11		—		—		3,811			—			3,811

Balance September 30, 2010				334,012		549,150		20,310			(253,788	)		315,672


			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				—		—		—			(19,394	)		(19,394	)
Shares issued for services				169		335		—			—			335
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		—		—		4,767			—			4,767

Balance September 30, 2011				344,139		586,108		25,677			(292,613	)		319,172

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

IVANHOE ENERGY INC.

Condensed Consolidated Statements of Cash Flows
(Unaudited)


			Three Months Ended						Nine Months Ended
			September 30,						September 30,
(US$000s)	Note		2011			2010			2011			2010

Operating Activities
Net loss				(4,157	)		(9,605	)		(19,394	)		(7,151	)
Adjustments to reconcile net loss to cash from operating activities
Depletion and depreciation		5		2,131			1,490			5,853			4,948
Share-based compensation expense		11		1,680			1,379			4,927			3,811
Unrealized foreign currency exchange (gain) loss				636			(1,496	)		(1,144	)		(2,834	)
Unrealized gain on derivative instruments		7		(5,429	)		(622	)		(12,629	)		(20,405	)
Current income tax expense				682			—			1,481			115
Deferred income tax expense (recovery)				29			(496	)		736			(49	)
Exploration and evaluation expense		4		2,143			788			2,143			2,378
Interest expense				431			4			798			12
Finance costs				—			—			269			—
Derecognition of long term provision				(1,900	)		—			(1,900	)		—
Other				25			(2	)		13			—
Current income tax paid				(423	)		(8	)		(747	)		(646	)
Decommissioning costs settled				—			3			—			(179	)
Changes in non-cash working capital items		14		(1,062	)		652			916			380

Net cash used in operating activities				(5,214	)		(7,913	)		(18,678	)		(19,620	)


Investing Activities
Intangible expenditures				(12,368	)		(16,654	)		(36,140	)		(50,794	)
Property, plant and equipment expenditures				(4,475	)		(821	)		(11,938	)		(3,056	)
Long term receivables				(845	)		(442	)		(1,308	)		(1,288	)
Interest paid				(1,039	)		(790	)		(2,042	)		(1,634	)
Changes in non-cash working capital items		14		(4,254	)		854			324			3,709

Net cash used in investing activities				(22,981	)		(17,853	)		(51,104	)		(53,063	)


Financing Activities
Shares and warrants issued on private placements, net of share issue costs				—			(69	)		—			135,696
Convertible debentures issued, net of issue costs		6		—			—			72,914			—
Repayment of convertible note		6		(41,421	)		—			(41,421	)		—
Proceeds from exercise of options and warrants		8, 11		—			8			29,873			2,102
Changes in non-cash working capital items		14		104			(41	)		57			(2	)

Net cash provided by (used in) financing activities				(41,317	)		(102	)		61,423			137,796


Foreign exchange gain (loss) on cash and cash equivalents held in a foreign currency				(5,628	)		2,299			(1,790	)		3,623

Increase (decrease) in cash and cash equivalents, for the period				(75,140	)		(23,569	)		(10,149	)		68,736
Cash and cash equivalents, beginning of period				133,308			116,667			68,317			24,362

Cash and cash equivalents, end of period				58,168			93,098			58,168			93,098

(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 September 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 September 30, 2011, Ivanhoe had an accumulated deficit of $292.6 million and working capital of $43.6 million excluding derivative financial liabilities. For the nine months ended September 30, 2011, cash used in operating activities was $18.7 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 September 30, 2011 Financial Statements were approved by the Board of Directors and authorized for issue on October 25, 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”, 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 17. 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 derivative 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. On 4 August 2011, the IASB issued an exposure draft proposing to change the mandatory effective date of IFRS 9 to annual periods beginning on or after January 1, 2015.

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 Standing Interpretations Committee (“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 loss or net assets of the Company.

3. CASH AND CASH EQUIVALENTS


	September 30,		December 31,		January 1,
	2011		2010		2010
Cash at banks and on hand		57,145		10,147		6,797
Term deposits		—		57,670		—
Money market accounts		—		—		14,715
Restricted cash		1,023		500		2,850

		58,168		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													Total
						Latin						HTL^TM		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		21,974			7,481		9,550			39,005			—		39,005
Exploration and evaluation expense		(2,143	)		—		—			(2,143	)		—		(2,143	)

Balance September 30, 2011		57,966			131,236		29,075			218,277			92,153		310,430

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 nine months ended September 30, 2011, $1.7 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		11,015		—		—		11,015		1,190			12,205
Disposals		—		—		—		—		(5	)		(5	)

Balance September 30, 2011		46,954		—		—		46,954		14,194			61,148


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		5,032		—		—		5,032		821			5,853
Disposals		—		—		—		—		(1	)		(1	)

Balance September 30, 2011		11,228		—		—		11,228		2,954			14,182


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 September 30, 2011		35,726		—		—		35,726		11,240			46,966

Oil and Gas Property and Equipment

In the nine months ended September 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

6.1 Convertible Note


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

Carrying amount		—		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.

In the nine months ended September 30, 2011, $1.5 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 nine months ended September 30, 2011 (three months and nine months ended September 30, 2010 — nil).

6.2 Convertible Debentures

September 30,

December 31,

January 1,

2011

2010

Convertible debentures

70,565

—

Unamortized financing costs and derivative instrument

(10,419

)

—

Carrying amount

60,146

—

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 September 30, 2011 was $60.1 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. The remaining unamortized financing costs in the table above include $8.7 million related to the option as well as $1.7 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 nine months ended September 30, 2011, $0.3 million and $0.7 million, respectively, was recorded as interest expense (three and nine months ended September 30, 2010 — nil). In the nine months ended September 30, 2011, $1.0 million (year ended December 31, 2010 — nil) of interest from the Convertible Debentures was capitalized to E&E assets and $0.1 million (year ended December 31, 2010 — nil) was capitalized to PP&E assets.

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		—			—			—			9,852			—		9,852
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	)		(7,577	)		286		(8,806	)
Foreign exchange gains		—			—			—			(465	)		—		(465	)

Balance September 30, 2011		—			—			—			1,810			286		2,096

The gain on derivative instruments of $12.6 million for the nine months ended September 30, 2011, (nine months ended September 30, 2010 — $20.4 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 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 September 30, 2011		—			—

All of the Company’s purchase warrants have expired in 2011 and no purchase warrants remain outstanding at September 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 TSX 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 September 30, 2011 (December 31, 2010 — $1.2 million) as the Convertible Note was paid in full on July 11, 2011.

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 $1.8 million at September 30, 2011 (December 31, 2010 — nil), calculated with the Black-Scholes valuation method using a weighted average risk-free interest rate of 1.39%, 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 $1.2 million. Increasing the volatility by 10% would increase the fair value by $1.7 million.

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 September 30, 2011 was $0.3 million, calculated with the Black Scholes valuation method using an estimated share value of $17.13, an exercise price of $30.00 per share, a risk-free interest rate of 0.90%, a dividend yield of 0.0%, an expected life of approximately five months and an estimated volatility of 65.6%, 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 $0.1 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 remote.

9.2 Operating Lease Arrangements

In the three months and nine months ended September 30, 2011, the Company expended $0.4 million and $1.3 million, respectively, (three months and nine months ended September 30, 2010 — $0.3 million and $0.9 million, respectively) on operating leases relating to the rental of office space, which expire between 2011 and 2013.

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


Remainder of 2011			428
2012-2013			1,133

			1,561

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$15.0 million, as a conditional, final payment for the 2008 purchase transaction.

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. Similarly, agreements entered into by the Company may contain cancellation fees or liquidated damages provisions for early termination. 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.

10. SHARE CAPITAL


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

Issued and Outstanding		344,139,428 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 nine months ended September 30, 2011 and 2010.

11. SHARE-BASED PAYMENTS

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

Three months ended

Nine months ended

September 30,

2011

2010

2011

2010

Share-based expense related to

Equity settled transactions

1,533

1,379

4,768

3,811

Cash settled transactions

147

—

159

—

Total share-based expense

1,680

1,379

4,927

3,811

Share-based payments capitalized as E&E assets

—

335

799

11.1 Stock Option Plan

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

September 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

1,914

2.66

6,041

2.56

Exercised

(1,687

)

2.50

(2,743

)

2.28

Expired

(710

)

2.97

(635

)

2.60

Forfeited

(1,082

)

2.42

(749

)

2.64

Outstanding, end of period

15,362

2.25

16,927

2.24

Exercisable, end of period

7,370

2.12

7,324

2.19

The weighted average share price at the date of exercise for stock options exercised in the nine months end September 30, 2011 was Cdn$3.15 (nine months ended September 30, 2010 — Cdn$3.50).

The weighted average fair value of stock options granted from the stock option plan during the nine months ended September 30, 2011 was Cdn$1.58 (nine months ended September 30, 2010 — Cdn$1.99) per option at the grant date using the Black Scholes option pricing model. The weighted average assumptions used for the calculation were:


Nine months ended September 30,	2011			2010
Expected life (in years)		6.3			6.1
Volatility ⁽¹⁾		74.4	%		98.5	%
Dividend yield		—			—
Risk-free rate		2.7	%		3.0	%
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 September 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		5,223		2.2		1.71
2.15 to 2.71		8,526		4.8		2.39
2.77 to 3.44		1,613		5.1		3.21

		15,362		3.9		2.25

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:


	September 30, 2011
				Weighted Average
	Number of RSUs			Fair Value
	(000s)⁽¹⁾			(Cdn$)
Outstanding, beginning of period		—			—
Granted		1,115			1.62
Forfeited		(132	)		1.89

Outstanding, end of period		983			1.59


(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 nine months ended September 30, 2011 was Cdn$1.62 per RSU at the grant date using the Black Scholes option pricing model. The weighted average assumptions used for the calculation were:


	Nine months ended
	September 30, 2011
Expected life (in years)		3.0
Volatility ⁽¹⁾		62.9	%
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:


	September 30,
	2011
Current liabilities related to RSUs		90
Long term liabilities related to RSUs		69
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 September 30, 2011		10,770			—			—			—			218			10,988
For the three months ended September 30, 2010		4,177			—			—			—			88			4,265

For the nine months ended September 30, 2011		28,281			—			—			—			425			28,706
For the nine months ended September 30, 2010		15,559			—			—			—			125			15,684

Segment income (loss)
For the three months ended September 30, 2011		(3,485	)		(625	)		(2,070	)		(2,839	)		4,862			(4,157	)
For the three months ended September 30, 2010		(2,218	)		(875	)		(2,917	)		(953	)		(2,642	)		(9,605	)

For the nine months ended September 30, 2011		(5,196	)		(2,911	)		(5,937	)		(7,846	)		2,496			(19,394	)
For the nine months ended September 30, 2010		(3,838	)		(2,826	)		(6,583	)		(3,667	)		9,763			(7,151	)

Segment assets ⁽²⁾
As at September 30, 2011		107,362			131,692			36,893			102,458			50,042			428,447
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 September 30, 2011		142,265			141,988			58,507			85,151			(318,636	)		109,275
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 September 30, 2011		7,649			1,451			3,268			—			—			12,368
For the three months ended September 30, 2010		8,907			2,752			4,995			—			—			16,654

For the nine months ended September 30, 2011		21,755			5,298			9,087			—			—			36,140
For the nine months ended September 30, 2010		13,395			24,094			13,305			—			—			50,794

Capital investments — Property, plant and equipment
For the three months ended September 30, 2011		4,713			—			(2	)		(236	)		—			4,475
For the three months ended September 30, 2010		592			—			176			70			(17	)		821

For the nine months ended September 30, 2011		11,014			—			55			869			—			11,938
For the nine months ended September 30, 2010		2,043			3			263			376			371			3,056


(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 $411.6 million at September 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

Nine months ended

September 30,

2011

2010

2011

2010

Asia

Field operating

1,695

1,244

5,010

3,908

Windfall levy

2,584

637

6,343

2,317

Engineering support

126

135

339

375

4,405

2,016

11,692

6,600

Technology Development FTF operating costs

1,084

980

3,659

3,102

Total operating costs

5,489

2,996

15,351

9,702

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. SUPPLEMENTAL CASH FLOW INFORMATION

Changes in Non-Cash Activities


	Three months ended						Nine months ended
	September 30,						September 30,
	2011			2010			2011			2010
Operating activities
Accounts receivable		29			1,338			(2,617	)		1,029
Note receivable		10			(4	)		43			(35	)
Prepaid and other current assets		54			1,092			(94	)		414
Accounts payable and accrued liabilities		(1,155	)		(1,774	)		3,584			(1,028	)

		(1,062	)		652			916			380

Investing activities
Accounts receivable		177			(298	)		733			(327	)
Prepaid and other current assets		22			(1,055	)		2,263			(972	)
Accounts payable and accrued liabilities		(4,453	)		2,207			(2,672	)		5,008

		(4,254	)		854			324			3,709

Financing activities
Accounts payable and accrued liabilities		104			(41	)		57			(2	)

		(5,212	)		1,465			1,297			4,087

15. 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				Nine months ended
		September 30,				September 30,
Related Party	Nature of Transaction	2011		2010		2011		2010
Global Mining Management Corp.	Administration		117		313		446		954
Ivanhoe Capital Aviation Ltd.	Aircraft		300		300		900		900
I2MS.Net PTE Ltd.	Information systems		51		80		159		264
Ivanhoe Capital Services Ltd.	Administration		125		108		246		191
SouthGobi Resources Ltd.	Administration		38		38		115		38
Ibex Resources Inc.	Business development		—		6		—		39
1092155 Ontario Inc.	HTL^TM technology		12		15		32		42
Ensyn Technologies Inc.	HTL^TM technology		—		—		—		7
Ivanhoe Capital PTE Ltd.	Administration		17		10		132		19
Ivanhoe Mines Ltd.	Administration		—		—		—		13

			660		870		2,030		2,467

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


		September 30,		December 31,		January 1,
Related Party	Nature of Transaction	2011		2010		2010
Global Mining Management Corp.	Administration		67		86		40
I2MS.Net PTE Ltd.	Information systems		16		13		17
SouthGobi Resources Ltd.	Administration		13		38		—
Ivanhoe Capital Services Ltd.	Administration		43		70		15
Ivanhoe Capital PTE Ltd.	Administration		—		—		—

			139		207		72

16. REMUNERATION OF KEY MANAGEMENT PERSONNEL

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

Three months ended

Nine months ended

September 30,

2011

2010

2011

2010

Base salaries or fees and other cash payments

743

737

3,123

2,925

Employer’s contributions to retirement plan

Share-based compensation expense

753

581

2,289

1,615

1,507

1,335

5,449

4,590

17. 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.

17.1 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 the Company’s 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.

17.2 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 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 September 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			93,098			—			93,098
Accounts receivable		5,021			—			5,021			6,359			—			6,359			4,332			—			4,332
Note receivable		225			—			225			264			—			264			260			—			260
Prepaid and other current assets		771			—			771			2,859			—			2,859			1,329			—			1,329

		30,379			—			30,379			77,799			—			77,799			99,019			—			99,019

Intangible assets		92,153			115,597	a		207,750			92,153			197,193	a		273,568			92,153			174,655	a		259,172
					—									(7,482	)b								(5,356	)b
					—									175	c								98	c
					—									(8,471	)g								(2,378	)g
Property, plant and equipment, net		158,392			(115,597	)a		41,983			237,200			(197,193	)a		40,618			213,685			(174,655	)a		39,624
					(904	)b								(2,014	)b								(1,407	)b
					92	c								189	c								205	c
					—									2,436	f								1,796	f
Long term receivables		839			—			839			2,433			—			2,433			2,126			—			2,126

		281,763			(812	)		280,951			409,585			(15,167	)		394,418			406,983			(7,042	)		399,941


Liabilities and Shareholders’ Equity
Current Liabilities
Accounts payable and accrued liabilities		10,779			—			10,779			21,482			—			21,482			14,394			—			14,394
Debt		—			—			—			39,832			—			39,832			38,279			—			38,279
Derivative financial instruments		—			13,023	d		13,023			—			8,447	d		8,447			—			6,613	d		6,613
Income tax payable		530			—			530			—			—			—			—			—			—
Decommissioning costs		753			—			753			—			—			—			—			—			—

		12,062			13,023			25,085			61,314			8,447			69,761			52,673			6,613			59,286

Long term debt		36,934			—			36,934			—			—			—			—			—			—
Long term provisions		2,095			92	c		2,187			2,644			364	c		3,008			2,396			301	c		2,697
Deferred income tax liability		22,643			(307	)b		22,336			21,518			(367	)b		21,165			22,624			(349	)b		22,286
					—									14	f								11	f

		73,734			12,808			86,542			85,476			8,458			93,934			77,693			6,576			84,269


Shareholders’ Equity
Share capital		422,322			—			422,322			550,562			—			550,562			549,220			(70	)e		549,150
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			20,343			(2,946	)d		20,310
					1,642	e								3,105	e								2,913	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	)		(275,782	)		21,994			(253,788	)

		208,029			(13,620	)		194,409			324,109			(23,625	)		300,484			329,290			(13,618	)		315,672

		281,763			(812	)		280,951			409,585			(15,167	)		394,418			406,983			(7,042	)		399,941

Reconciliation of Consolidated Statements of Loss and Comprehensive Loss


	Three months ended September 30, 2010									Nine months ended September 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		4,177			—			4,177			15,554			—			15,554			21,720			—			21,720
Interest		88			—			88			130			—			130			208			—			208

		4,265			—			4,265			15,684			—			15,684			21,928			—			21,928


Expenses
Operating		2,955			41	b		2,996			9,607			95	b		9,702			13,514			111	b		13,625
Exploration and evaluation		—			788	g		788			—			2,378	g		2,378			—			8,471	g		8,471
General and administrative		8,120			2,451	b		10,898			21,459			5,763	b		28,423			32,864			8,481	b		42,807
					327	e								1,201	e								1,462	e
Depletion and depreciation		2,079			(589	)f		1,490			6,744			(1,796	)f		4,948			8,960			(2,436	)f		6,524
Foreign currency exchange		(1,188	)		—			(1,188	)		(2,289	)		—			(2,289	)		(3,325	)		—			(3,325	)
Derivative instruments gain		—			(622	)d		(622	)		—			(20,405	)d		(20,405	)		—			(18,571	)d		(18,571	)
Interest		6			(2	)		4			14			(2	)c		12			24			—			24

		11,972			2,394			14,366			35,535			(12,766	)		22,769			52,037			(2,482	)		49,555


Loss before income taxes		(7,707	)		(2,394	)		(10,101	)		(19,851	)		12,766			(7,085	)		(30,109	)		2,482			(27,627	)

(Provision for) recovery of income taxes
Current		—			—			—			(115	)		—			(115	)		(126	)		—			(126	)
Deferred		479			21	b		496			19			41	b		49			1,125			60	b		1,171
					(4	)f								(11	)f								(14	)f

		479			17			496			(96	)		30			(66	)		999			46			1,045


Net loss and comprehensive loss		(7,228	)		(2,377	)		(9,605	)		(19,947	)		12,796			(7,151	)		(29,110	)		2,528			(26,582	)


Notes to reconciliation

a.		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 “Exploration for and evaluation of mineral resources”, these properties were reclassified as intangible assets.

b.		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.

c.		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.

d.		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 warrants 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.

e.		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.

f.		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.

g.		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.


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 newly enacted safety and environmental rules; 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 analyses 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 including the risk that the outcome that they predict 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, or to raise capital on acceptable terms; 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 Form 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

This Form 10-Q should be read in conjunction with the Company’s September 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 17 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, as issued by the International Accounting Standards Board, 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 U.S. DOLLARS, EXCEPT PER SHARE AND PRODUCTION DATA INCLUDING REVENUES AND COSTS PER BOE.

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


bbl	=	barrel	mbbls/d	=	thousand barrels per day
bbls/d	=	barrels per day	mboe	=	thousands of barrels of oil equivalent
boe	=	barrel of oil equivalent	mboe/d	=	thousands of barrels of oil equivalent per day
boe/d	=	barrels of oil equivalent per day	mmbbls	=	million barrels
mbbls	=	thousand barrels	mmbls/d	=	million barrels per day

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

Electronic copies of the Company’s filings with the SEC and the CSA are available, free of charge, through the Company’s website (www.ivanhoeenergy.com) or, upon request, by contacting its investor relations department at (403) 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 loss presented under Canadian GAAP to IFRS is included in Note 17 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						Nine months
	ended September 30,						ended September 30,
($000, except as stated)	2011			2010			2011			2010
Average daily production (bbls/d)		1,029			610			992			760
Realized oil prices ($/bbl)		113.74			74.41			104.40			74.92
Oil revenue		10,769			4,177			28,277			15,554
Capital expenditures		16,843			17,475			48,078			53,850

Cash flow used in operating activities		(5,214	)		(7,913	)		(18,678	)		(19,620	)
Net loss		(4,157	)		(9,605	)		(19,394	)		(7,151	)
Net loss per share, basic and diluted		(0.01	)		(0.03	)		(0.06	)		(0.02	)

Oil production increased in the nine months ended September 30, 2011 as Ivanhoe received additional volumes to offset capital expenditures incurred at Dagang in 2011. Additional production in combination with stronger realized prices, resulted in higher oil revenue for the Company. The net loss in the nine months ended September 30, 2011 was $19.4 million compared to a $7.2 million net loss in the prior period. Although oil revenue increased in 2011, net income was impacted by higher operating and general and administrative expenses as well as lower non-cash foreign currency exchange and derivative instrument gains in comparison to 2010.

Capital expenditures totaled $16.8 million in the three months ended September 30, 2011. In China, the Yixin-2 and Zitong-1 gas wells were gas flow tested and down hole electronic recorders were run until late July. Analysis of the data collected is ongoing and results will provide critical information for completion and stimulation techniques for future exploitation programs on the Zitong Block. At Dagang, two wells were drilled in the third quarter and one well was completed, in addition to the continuation of the Company’s fracture stimulation program.

In the Nyalga basin of Mongolia, drilling was concluded at the Company’s first exploration well at N16-1E-1A. The well was plugged and abandoned as it did not encounter oil shows in the reservoir. However, the well provided information that will be used in combination with seismic data to guide future drilling. The drilling rig was subsequently mobilized to a second site, N16-2E-B, located approximately 12 kilometres from the first well. Drilling commenced in the middle of September.

In Canada, regulators completed their initial review of the Company’s Environmental Impact Assessment for the Tamarack project and Ivanhoe received expected Supplemental Information Requests in the third quarter of 2011. Ivanhoe anticipates submitting the additional information to the regulators in the fourth quarter of 2011.

In Ecuador, the Company continued internal processing and interpretation of the seismic data acquired during the second quarter of 2011 from the Company’s 190-kilometre 2-D survey of Block 20. Early interpretation indicates deeper faulting, with the potential to trap lighter oil resources which could prove beneficial for blending purposes and overall project economics. Additionally, initial internal interpretations may also suggest an extension of the field beyond what was originally estimated.

RESULTS OF OPERATIONS

Three months

Nine months

ended September 30,

2011

2010

2011

2010

Asia (net bbls)

Dagang

92,576

52,420

261,105

195,424

Daqing

2,098

3,711

9,749

12,173

Total production

94,674

56,131

270,854

207,597

Average daily production (bbls/d)

1,029

610

992

760

Pricing

Average realized oil price ($/bbl)

113.74

74.41

104.40

74.92

West Texas Intermediate (WTI) ($/bbl)

89.40

76.06

95.31

77.54

Oil Revenue

Ivanhoe’s oil revenue in the three and nine months ended September 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 capital activity at Dagang in the three and nine months ended September 30, 2011, additional oil production was allocated to Ivanhoe.

Net Revenue from Operations


	Three months						Nine months
	ended September 30,						ended September 30,
($/bbl)	2011			2010			2011			2010
Oil revenue⁽¹⁾		113.74			74.41			104.40			74.92
Less operating costs
Field operating		(17.91	)		(22.15	)		(18.50	)		(18.82	)
Windfall Levy		(27.30	)		(11.34	)		(23.42	)		(11.16	)
Engineering and support costs		(1.34	)		(2.42	)		(1.25	)		(1.81	)

Net operating revenue⁽¹⁾		67.19			38.50			61.23			43.13
Depletion		(19.53	)		(23.41	)		(18.56	)		(23.55	)

Net revenue from operations⁽¹⁾		47.66			15.09			42.67			19.58


(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

Nine months

ended September 30,

2011

2010

2011

2010

Asia

Field operating

1,695

1,244

5,010

3,908

Windfall Levy

2,584

637

6,343

2,317

Engineering support

126

135

339

375

4,405

2,016

11,692

6,600

Technology Development

FTF operating costs

1,084

980

3,659

3,102

Total operating costs

5,489

2,996

15,351

9,702

Operating costs in China rose $2.4 million and $5.1 million, respectively, in the three and nine months ended September 30, 2011, over the comparable periods of 2010. 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 additional production volumes. On a per barrel basis, field operating costs were $4.24/bbl lower in the three months ended September 30, 2011 compared to the prior year as field staff focused their efforts on drilling and completion activities in the Company’s Dagang field. On a per barrel basis, year to date field operating costs in the nine months ended September 30, 2011 were consistent with the prior year.

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. FTF operating costs in the three months ended September 30, 2011 were consistent with costs sustained during the third quarter of 2010. FTF operating costs to date in 2011 are higher than in 2010 due to activities 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 in the second quarter of 2011.

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 (“E&E”) expense only if sufficient reserves cannot be established. In the three and nine months ended September 30, 2011, $2.1 million of drilling costs were expensed in connection with the exploration well in Mongolia that was plugged and abandoned.

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, $0.8 million and $2.4 million of geological costs incurred in prior periods were expensed as E&E costs in the three and nine months ended September 30, 2010.

General and Administrative

G&A expenses were higher in the three and nine months ended September 30, 2011, than in the comparable periods. In the third quarter of 2011, professional fees rose due to higher legal costs incurred in connection with the proceedings described in Part II of this Form 10-Q and increasing contract engineering costs related to Ivanhoe’s HTL^TM technology. The Company also incurred additional staff, office and travel costs in the third quarter of 2011.

In the nine months ended September 30, 2011, G&A increased over the prior period due to additional staff, office and travel costs. Professional fees rose in comparison to the prior year as a result of higher legal costs, contract engineering costs related to Ivanhoe’s HTL^TM technology and other services. G&A in 2011 also included financing and filing fees associated with the Cdn$73.3 million convertible unsecured subordinated debentures (“Convertible Debentures”) issued in the second quarter of 2011.

Depletion and Depreciation

Depletion and depreciation expense in the three months ended September 30, 2011 was higher than in the third quarter of 2010 due to additional production in Asia during the current quarter.

Depletion and depreciation expense in the nine month ended September 30, 2011 increased in comparison to 2010 due to a combination of factors. Depletion in Asia rose $0.2 million in 2011 due to higher year to date production, despite a lower depletion rate from additional Dagang reserves. The depreciation expense associated with the de-activated and dismantled Commercial Demonstration Facility (“CDF”) and FTF was $0.6 million higher in the current year due to revisions to the CDF salvage values reducing depreciation in 2010.

On a per barrel basis, depletion in Asia decreased in the three and nine months ended September 30, 2011 in comparison to the prior periods due to additional proved and probable reserves booked at Dagang at January 1, 2011.

Foreign Exchange

The Company incurred a lower foreign exchange gain in the third quarter of 2011 compared to the third quarter of 2010. The Canadian dollar weakened in comparison to the US dollar during the current quarter. As a result, foreign exchange gains on the Company’s Convertible Debentures were offset by foreign exchange losses incurred on the translation of Canadian dollar cash. The Canadian dollar strengthened against the US dollar during the third quarter of 2010 resulting in a higher net foreign exchange gain than in the current quarter.

In the nine months ended September 30, 2011, the foreign exchange gain was less than in the prior comparable period. In the prior year, the Company incurred a large foreign exchange gain in the first quarter of 2010 due to the Canadian dollar strengthening against the US dollar in the first quarter of 2010, which was partially offset by a loss incurred in the second quarter of 2010 when the Canadian dollar weakened.

Derivative Instruments

In the third quarter of 2011, the Company incurred an unrealized gain of $5.4 million on the revaluation of the convertible component of its Convertible Debentures. The unrealized gain of $0.6 million in the third quarter of 2010 resulted from the revaluation of the Company’s share purchase warrants issued in 2006, 2009 and 2010 (“Purchase Warrants”).

In the nine months ended September 30, 2011, the unrealized gain on derivative instruments was less than in the prior comparable period. The unrealized gain on the Convertible Debentures totaled $7.6 million to date in 2011. A combination of the expiry and revaluation of the Company’s Purchase Warrants resulted in a gain of $4.1 million and a gain of $1.2 million was recognized on the revaluation of the convertible portion of the Cdn$40.0 million convertible promissory note (“Convertible Note”). 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 loss of $0.3 million.

The $20.4 million unrealized gain recognized in the nine months ended September 30, 2010 stemmed from a $16.0 million and $4.3 million gain, respectively, on the revaluation of the Purchase Warrants and Convertible Note.

Provision for Income Taxes

Current taxes in China increased in both the three and nine months ended September 30, 2011, due to higher oil revenue than in the comparable periods. Ivanhoe incurred a future tax expense of $0.7 million to date in 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.


	Total		2011		2012		2013		2014		After 2014
Long term debt		69,939		—		—		—		—		69,939
Interest		20,349		2,259		4,021		4,021		4,021		6,027
Decommissioning provisions⁽¹⁾		2,111		—		—		317		—		1,794
Lease commitments		1,561		428		867		266		—		—

		93,960		2,687		4,888		4,604		4,021		77,760


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

Long Term Debt and Interest

As described in the Financial Statements, the Company issued Cdn$73.3 million of Convertible Debentures, maturing on June 30, 2016. 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 September 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 productive wells will not be abandoned while the Company has an economic interest in the field.

Operating Leases

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

Other

Should Ivanhoe receive government and other approvals necessary to develop the northern border of one of the Tamarack project leases, the Company will be required to make a cash payment to Talisman Energy Canada (“Talisman”) of up to Cdn$15.0 million, as a conditional, final payment for the 2008 purchase transaction.

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 flows, are summarized in the following table:


	Three months						Nine months
	ended September 30,						ended September 30,
	2011			2010			2011			2010
Cash used in operating activities		(5,214	)		(7,913	)		(18,678	)		(19,620	)
Cash used in investing activities		(22,981	)		(17,853	)		(51,104	)		(53,063	)
Cash provided by (used in) financing activities		(41,317	)		(102	)		61,423			137,796

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. 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 or available on acceptable terms.

Operating Activities

In the three and nine months ended September 30, 2011, cash used in operating activities was lower than in 2010 as growth in revenue exceeded increases in operating costs and G&A expenses.

Investing Activities

E&E Expenditures

E&E capital expenditures in the nine months ended September 30, 2011 totaled $36.1 million. The Yixin-2 and Zitong-1 gas wells at the Company’s Zitong project in China were drilled and fracture stimulated. Subsequent to post-fracture gas flow tests, down-hole electronic recorders were installed to gather additional pressure data during an extended shut-in period and analysis of the data collected is ongoing.

In the Nyalga basin of Mongolia, expenditures incurred on the Company’s first exploration well at N16-1E-1A were expensed when the well did not encounter oil shows in the reservoir. The drilling rig was mobilized to a second site, N16-2E-B, and drilling commenced in the middle of September.

In Canada, regulators completed their initial review of the Company’s Environmental Impact Assessment for the Tamarack project and, as is customary, provided the Company with an initial set of Supplemental Information Requests in the third quarter of 2011. Ivanhoe anticipates submitting the additional information to the regulators in the fourth quarter of 2011.

In Ecuador, the Company concluded its 190-kilometre 2-D seismic survey of Block 20 initiated during the second quarter of 2011. The initial phase of shooting was completed in July and analysis of the data is ongoing.

PP&E Expenditures

In the nine months ended September 30, 2011, PP&E additions totaled $11.9 million. At Dagang, four wells were drilled, of which three were completed and fracture stimulated in 2011. A well drilled in 2010 was completed in early 2011. In addition, the fracture stimulation program at Dagang has been ongoing throughout 2011.

Financing Activities

Cash provided by financing activities was higher in the nine months ended September 30, 2011 than in the prior periods. In June 2011, the Company raised $72.9 million, net of issuance costs, through the issuance of the Convertible Debentures. 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 $29.9 million were raised through the exercise of purchase warrants and stock options.

In comparison, the Company raised $135.7 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 nine months ended September 30, 2010.

Capital Structure


	September 30,		December 31,
As at	2011		2010
Debt		—		39,832
Long term debt		60,146		—
Shareholders’ equity		319,172		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 such financing, or obtain it on favorable terms, 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 acceptance by CNPC, Ivanhoe will proceed with a 150-square-kilometre 3-D seismic program covering certain areas of the Zitong Block. The seismic program will assist in planning and designing a horizontal well-path for three wells in the Guan and Wen structures. It is anticipated that this program will be executed in the next 24 to 30 months and will provide the groundwork for the eventual development of the Zitong Block.

Following the drilling and abandonment of the Company’s first exploration well in Mongolia, the Company mobilized the rig to a second location in east-central Mongolia. Drilling of the second well began in mid-September and is targeting a total depth of approximately 2,500 metres.

In Canada, Alberta Environment (AENV) and the Energy Resources Conservation Board (ERCB) have completed their initial review of Ivanhoe Energy’s Application for the Tamarack integrated oil sands project, which is comprised of a two-phased 40,000 bbl/d steam-assisted gravity drainage thermal recovery (SAGD) and Heavy-to-Light (HTL) facility. The first round of Supplementary Information Requests (SIRS) was received from the regulators in the third quarter of 2011 and the Company will submit responses to these SIRs in the fourth quarter of 2011. It is anticipated that the regulatory approval process will be complete later in 2012. Project advancement, as currently envisaged, is subject to regulatory approval and financing.

Ivanhoe completed its 190-kilometre 2-D seismic survey over the southern portion of Block 20 in Ecuador and processing is ongoing. Internal 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. This internal analysis will be followed by expert external interpretation in the fourth quarter of 2011. The Company anticipates securing the necessary drilling licenses and environmental permits by the end of 2011 for wells to be drilled as part of the appraisal phase of the project.

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 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 September 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 September 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, also have been awarded costs and fees as the prevailing parties in the trial court.

On August 13, 2010, the plaintiffs filed a notice of appeal challenging the district court’s judgment and some of its related orders. The appeal is currently pending in the United States Court of Appeals for the Tenth Circuit. Briefing on the appeal is complete and the Court heard oral arguments on May 9, 2011, in Denver, Colorado. There has been no ruling as of yet 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 and subsidiaries 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. Plaintiffs’ motion to remand remains pending, as do Company’s defendants’ motion to dismiss and a motion to compel arbitration of certain claims. 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

	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:		November 9, 2011

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