Edgar Filing: IVANHOE ENERGY INC

eh1300453_10ka1.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-K/A

(Amendment No. 1)

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 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)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class		Name of each exchange on which registered
Common Shares, No Par Value		Toronto Stock Exchange The NASDAQ Capital Market

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. þ Yes o No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. o Yes þ No

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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

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 of June 30, 2011, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $547,464,841 based on the Toronto Stock Exchange closing price on that date. At March 5, 2012, the registrant had 344,139,428 common shares outstanding.

EXPLANATORY NOTE

This Amendment No. 1 to the Annual Report on Form 10-K/A (this “Form 10-K/A”) amends the Annual Report on Form 10-K for the year ended December 31, 2011 of Ivanhoe Energy, Inc. (the “Company”), which was filed with the Securities and Exchange Commission on March 15, 2012 (the “Form 10-K”). This Form 10-K/A is being filed (1) to provide additional disclosure in respect of the Company’s relationship with one key customer, conversion of proved undeveloped reserves to proved developed reserves in the five year period since their initial disclosure as proved undeveloped reserves, drilling activity, summary results of operations and financial position for the years ended December 31, 2007, 2008 and 2009, respectively, and general and administrative expenses, (2) to amend the Company’s disclosure of its proved and probable reserves in compliance with Disclosure by Registrant’s Engaged in Oil and Gas Producing Activities as required by Regulation S-K, (3) to file revised reserve engineer reports for the year ended December 31, 2011 (which revised reports do not contain any revisions to total proved reserves) and (4) to correct certain typographical errors.

Except as described above, this Form 10-K/A does not amend, update or change any other items or disclosures in the Form 10-K for the year ended December 31, 2011 and does not purport to reflect any information or events subsequent to the filing thereof.

TABLE OF CONTENTS

PART I	ITEMS 1 AND 2: Business and Properties	4
	ITEM 1A: Risk Factors	13
	ITEM 1B: Unresolved Staff Comments	18
	ITEM 3: Legal Proceedings	19
PART II	ITEM 5: Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	19
	ITEM 6: Selected Financial Data	22
	ITEM 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
	ITEM 7A: Quantitative and Qualitative Disclosures About Market Risk	33
	ITEM 8: Financial Statements and Supplementary Data	34
	ITEM 9: Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	76
	ITEM 9A: Controls and Procedures	76
PART III	ITEM 10: Directors, Executive Officers and Corporate Governance	78
	ITEM 11: Executive Compensation	83
	ITEM 12: Security and Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	98
	ITEM 13: Certain Relationships and Related Transactions, and Director Independence	100
	ITEM 14: Principal Accounting Fees and Services	100
PART IV	ITEM 15: Exhibits and Financial Statement Schedules	102

ABBREVIATIONS

As generally used in the oil and gas industry and in this Annual Report on Form 10-K/A (“Annual Report”), 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. A boe is derived by converting six thousand cubic feet of gas to one barrel of oil (6 mcf/1 bbl). 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.

CURRENCY AND EXCHANGE RATES

Unless otherwise specified, all reference to “dollars” or to “$” are to US dollars and all references to “Cdn$” are to Canadian dollars. The noon-day exchange rates for Cdn$1.00, as reported by the Bank of Canada, were:

(US$)	2011	2010
Closing	0.98	1.01
High	1.06	1.01
Low	0.94	0.93
Average noon	1.01	0.97

On March 5, 2012, the noon-day exchange rate was US$0.99 for Cdn$1.00.

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SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

With the exception of historical information, certain matters discussed in this Annual Report, including those appearing in Items 1 and 2 – Business and Properties and Item 7 – 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 Annual Report 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 Annual Report 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 this Annual Report. 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 Annual Report 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.

AVAILABLE INFORMATION

The principal executive offices of Ivanhoe Energy Inc. (“Ivanhoe,” the “Company,” “we,” “our,” or “us”) are located at 999 Canada Place, Suite 654, Vancouver, British Columbia, V6C 3E1, and our registered and records office is located at 300-204 Black Street, Whitehorse, Yukon, Y1A 2M9.

Electronic copies of the Company’s filings with the United States Securities and Exchange Commission (the “SEC”) and the Canadian Securities Administrators (the “CSA”) are available, free of charge, through our website (www.ivanhoeenergy.com) or, upon request, by contacting our investor relations department at (403) 817-1108. The information on our website is not, and shall not be, deemed to be part of this Annual Report.

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Alternatively, the SEC and the CSA each maintains a website (www.sec.gov and www.sedar.com) that contains our reports, proxy and information statements and other published information that have been filed or furnished with the SEC and the CSA. Further, a copy of this Annual Report is located at the SEC’s Public Reference Room at 100 F Street, NE, Washington, D.C. 20549. Information on the operation of the Public Reference Room can be obtained by calling the SEC at 1-800-SEC-0330.

PART I

ITEMS 1 AND 2: BUSINESS AND PROPERTIES

GENERAL

Ivanhoe is an independent international heavy oil development and production company focused on pursuing long term growth in its reserve base and production using advanced technologies, including its HTL™ technology. Core operations are in Canada, Ecuador, China and Mongolia, with business development opportunities worldwide.

The Company was incorporated pursuant to the laws of the Yukon Territory of Canada, on February 21, 1995, under the name 888 China Holdings Limited. On June 3, 1996, the Company changed its name to Black Sea Energy Ltd. On June 24, 1999, Black Sea Energy Ltd. merged with Sunwing Energy Ltd. (“Sunwing”), and the name was changed to Ivanhoe Energy Inc.

In 2005, Ivanhoe completed a merger with Ensyn Group Inc. (“Ensyn”) acquiring the proprietary, patented heavy oil upgrading process called HTL™. In July 2008, the Company acquired from Talisman Energy Canada (“Talisman”) oil sand interests, including certain oil sand leases in the Athabasca region of Canada (“Tamarack” or the “Tamarack Project”). Later in 2008, the Company signed a contract with the Ecuador state oil companies to explore and develop Ecuador’s Pungarayacu heavy oil field in Block 20. In 2009, Ivanhoe sold its wholly owned subsidiary, Ivanhoe Energy (USA) Inc., disposing of its oil and gas exploration and production operations in the United States (“US”). Also in 2009, the Company acquired a production sharing contract for the Nyalga Block XVI in Mongolia, through the takeover of PanAsian Petroleum Inc., a privately-owned corporation.

CORPORATE STRATEGY

Ivanhoe continues to pursue its core strategies, which are:

—

Utilize long-standing knowledge and relationships in the Far East to pursue conventional oil and gas production and exploration opportunities;

—

Seek out heavy oil development projects globally that have operational needs that can benefit from our proprietary HTL™ technology; and

—

Bias new country entry and business development to projects that, because of their remote setting, geo-political status or operational needs, have been overlooked by the broader industry, subsequently expanding efforts in the new locations to more conventional oil and gas industry activities.

Pursuing Natural Gas in China

Ivanhoe’s wholly-owned subsidiary, Sunwing, has been conducting operations in China since the mid-1990s. In particular, Sunwing is focused on a key natural gas exploration project (the Zitong Block) in Sichuan Province of China. Sichuan is the oldest and one of the most productive gas producing regions of China. Sinopec and PetroChina have made significant gas discoveries in blocks adjacent to Sunwing’s Zitong Block.

The Sichuan Basin, located in central China approximately 930 miles southwest of Beijing, is the country’s largest gas-producing region, currently producing more than 800 mmcf/d and estimated by Chinese officials to contain a natural gas resource potential of 260 tcf. There is a strong and growing local market for natural gas, with approximately 120 million people living within the basin and with well-developed grid connections to adjacent industrial and population areas.

Natural gas sales are regulated in China and current prices are approximately $5.00/mcf at the wellhead. As part of China’s commitment to develop cleaner sources of energy, demand for natural gas is projected to continue to grow in the country and Sunwing’s goal is to tap into this burgeoning market.

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

The global oil and gas industry is being impacted by the declining availability of low cost replacement reserves. This has resulted in volatility in oil markets and marked shifts in the demand and supply landscape. Ivanhoe believes that long term demand and the natural decline of conventional oil production will see the development of higher cost and lower value resources, including heavy oil.

Heavy oil developments can be segregated into two types: conventional heavy oil that flows to the surface without steam enhancement and non-conventional heavy oil and bitumen. While the Company focuses on the non-conventional heavy oil, both types of oil play an important role in our corporate strategy.

Production of conventional heavy oil has been steadily increasing worldwide, led by Canada and Latin America but with significant contributions from most other oil basins, including the Middle East and the Far East, as producers struggle to replace declines in light oil reserves. Even without the impact of the large non-conventional heavy oil projects in Canada and Venezuela, world heavy oil production has become increasingly more common.

With regard to non-conventional heavy oil and bitumen, a dramatic increase in interest and activity has been fuelled by higher prices, in addition to various key advances in technology, including improved remote sensing, horizontal drilling and new thermal techniques. This has enabled producers to more effectively access the extensive heavy oil resources around the world.

These newer technologies, together with higher oil prices, have generated increased interest in heavy oil resources. Nevertheless, remaining challenges for profitable exploitation include: i) the requirement for steam and electricity to help extract heavy oil; ii) the need for diluent to move the oil once it is at the surface; iii) the heavy versus light oil price differentials that the producer is faced with when the product gets to market; and iv) conventional upgrading technologies are limited to very large scale, high capital cost facilities. These challenges can lead to “distressed” assets, where economics are poor, or to “stranded” assets, where the resource cannot be economically produced and lies fallow.

Ivanhoe’s Value Proposition

With the application of the HTL™ process, Ivanhoe seeks to address the key heavy oil development challenges and can do so at a relatively small minimum economic scale.

Ivanhoe’s HTL™ upgrading is a partial upgrading process that is designed to operate in facilities as small as 10,000 to 30,000 bbls/d. This is substantially smaller than the minimum economic scale for conventional stand-alone upgraders such as delayed cokers, which typically operate at scales of over 100,000 bbls/d. The HTL™ process is based on carbon rejection, a tried and tested concept in heavy oil processing. The key advantage of HTL™ is that it is a very fast process, with processing times typically under a few seconds. This results in smaller, less costly facilities and eliminates the need for hydrogen addition, an expensive, large minimum scale step typically required in conventional upgrading. HTL™ has the added advantage of converting the by-products from the upgrading process into onsite energy, rather than generating large volumes of low value coke.

The HTL™ process offers significant advantages as a field located upgrading alternative, integrated with the upstream heavy oil production operation. HTL™ provides four key benefits to the producer:

—

virtual elimination of external energy requirements for steam generation and/or power for upstream operations;

—

elimination of the need for diluent or blend oils for transport;

—

capture of the majority of the heavy versus light oil value differential; and

—

relatively small minimum economic scale of operations suited for field upgrading and for smaller field developments.

The economics of a project are effectively dictated by the advantages that HTL™ can bring to a particular opportunity. The more stranded the resource and the fewer monetization alternatives that the resource owner has, the greater the opportunity Ivanhoe will have to establish its unique value proposition.

Implementation Strategy

Ivanhoe is an oil and gas company with a unique technology which addresses several major problems confronting the oil and gas industry today and the Company believes it has a competitive advantage because of its patented upgrading process. In addition, because Ivanhoe has experienced thermal recovery teams, the Company is in a position to add value and leverage its technology advantage by working with partners on stranded heavy oil resources around the world.

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The Company’s continuing strategy is as follows:

—

Advance its two key heavy oil projects – in Canada and Ecuador. Continue to deploy personnel and financial resources in support of the Company’s goal to become a significant heavy oil producer.

—

Advance the HTL™ process. Additional development work will continue to advance the HTL™ process through the commercial application of HTL™ upgrading in Canada, Ecuador and beyond.

—

Advance its natural gas project in the Zitong Block in Sichuan Province, China. Through its wholly-owned subsidiary, Sunwing Energy, proceed with additional planning and operational analysis to develop an appraisal program leading to a full development plan for the Zitong block.

—

Enhance the Company’s financial position to support its major projects. Implementation of large projects requires significant capital outlays. The Company is working on various financing initiatives and establishing the relationships required for future development activities.

—

Build internal capabilities. The Company continues to seek to build its internal leadership and technical capabilities through the addition of key personnel associated with each major project.

—

Continue to deploy the personnel and the financial resources to capture additional opportunities for development projects utilizing the Company’s HTL™ process. Commercialization of the Company’s upgrading process requires close alignment with partners, suppliers, host governments and financiers.

PROPERTY DESCRIPTIONS

Our oil and gas operations are located in three geographic areas: Asia, Canada and Ecuador. The Technology Development area captures costs incurred to develop, enhance and identify improvements in the application of the HTL™ technology. Production, revenues, net income, capital expenditures and identifiable assets for these segments appear in Note 19 to the consolidated financial statements and in the MD&A in this Annual Report.

Asia

China

Zitong

In November 2002, we entered into a 30 year production sharing contract (“PSC”) with China National Petroleum Corporation (“CNPC”) for the Zitong block, which covers an area of approximately 248,000 gross acres after contractual relinquishments in the Sichuan basin. In 2006, we farmed out 10% of our working interest in the Zitong block to Mitsubishi Gas Chemical Company Inc. of Japan (“MGC”) for $4.0 million.

In Phase I of the contract, Ivanhoe reprocessed 1,649 miles of existing 2D seismic data and acquired 705 miles of new 2D seismic data. Two wells were drilled and although both wells encountered expected reservoirs and gas was tested on the second well, neither well demonstrated commercially viable flow rates and both wells were suspended. In Phase II of the contract, the Yixin-2 and Zitong-1 gas wells were drilled in late 2010 and completed in early 2011. Both wells encountered gas in the Xu-4 Formation and were shut-in for pressure build-up following initial flow and pressure tests.

On December 30, 2011, the Company entered into a supplementary agreement to the Contract for Exploration, Development and Production in Zitong Block, Sichuan Basin with CNPC for the Zitong block (“Supplementary Agreement”). The Supplementary Agreement effectively extends the exploration period under the PSC by creating a 36 month evaluation phase beginning July 1, 2011, for the performance of additional work. The Supplementary Agreement is subject to ratification by the Ministry of Commerce of the People’s Republic of China.

On January 11, 2012, Ivanhoe signed a binding Memorandum of Understanding which contemplates a transaction (the “Zitong Transaction”) whereby Ivanhoe will assign its entire working interest in the Zitong PSC to Shell China Exploration and Production Company Limited (“Shell”). Completion of the Zitong Transaction is subject to government approvals and other prescribed conditions, including rights of first refusal by both CNPC and Ivanhoe’s working interest partner, MGC.

Dagang

Ivanhoe’s oil production originates in the Kongnan oilfield in Dagang, Hebei Province, China (the “Dagang field”). We have a 30 year PSC with CNPC, covering an area of 10,255 gross acres. From 2000 to 2007, we drilled 46 wells and commercial production commenced on January 1, 2009. The project reached cost recovery in

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September 2009 and our working interest decreased to 49%. Operations in the Dagang field will revert to CNPC at the end of the 20 year production phase of the contract or earlier if the field is abandoned.

In 2011, quotas restricted production to 80,000 gross tonnes or 1,600 bbls/d gross. Actual production in 2011 averaged 967 bbls/d net. The production quota in 2012 remains set at 80,000 gross tonnes. The Company's production was sold entirely to CNPC. If CNPC chose not to purchase the Company's production, the Company would be materially adversely affected. The Company believes that it is unlikely that CNPC would choose not to purchase our production.

Mongolia

Through a merger with PanAsian Petroleum Inc. in November 2009, we acquired a PSC for the Nyalga Block XVI in the Khenti and Tov provinces in Mongolia. The block covers an area of approximately 3.1 million gross acres, after a 25% relinquishment in 2010. The five year exploration period is divided into three consecutive phases, consisting of two years (“Phase I”), one year (“Phase II”) and two years (“Phase III”), with the ability to nominate a two year extension following Phase I or Phase II.

During the initial seismic program, approximately 16% of the block in the Delgerkhaan area was declared by the Mongolian government to be a historical site and operations in this area were suspended. A letter from the Mineral Resources and Petroleum Authority of Mongolia (“MRPAM”) stated that the obligations under year one of Phase I would be extended for one year from the time the Company is allowed to re-enter the suspended area. To date, access has not been granted and discussions with MRPAM are ongoing. As a result, the government adjusted the dates on which the project year begins. Phase II is now considered to have commenced on July 20, 2010.

From late 2009 through the first quarter of 2010, the Company acquired an additional 465 kilometres of 2-D seismic across Block XVI, for a total of 925 kilometres of 2-D seismic data over the Kherulen sub-basin. The seismic was used to drill two wells in 2011. The first exploration well, N16-1E-1A, was drilled and abandoned as the well did not encounter oil shows in the reservoir. The Company observed oil staining, fluorescence and increases in background gas at its second exploration well site at N16-2E-B.

Canada

Tamarack, acquired from Talisman in 2008, is a 6,880 acre lease located approximately 10 miles northeast of Fort McMurray, Alberta, Canada. The Tamarack integrated oil sands project (“Tamarack” or the “Tamarack Project”) is comprised of a two-phased 40,000 bbl/d steam-assisted gravity drainage thermal recovery (“SAGD”) and HTL™ facility. Our independent reserve evaluator, GLJ Petroleum Consultants Ltd. (“GLJ”), has assigned total 3P reserves of 219 mmbbls of bitumen to Tamarack. Talisman held a 20% back-in right which expired in July 2011. Additionally, in 2011, Ivanhoe repaid a $40 million promissory note to Talisman that was part of the initial purchase price.

Ivanhoe filed an Environmental Impact Assessment for the Tamarack Project in November 2010. Regulators completed their initial review of the Company’s application and, as is customary, provided an initial set of Supplemental Information Requests in the third quarter of 2011. The Company submitted the supplemental information to the regulators in the fourth quarter of 2011.

As the regulatory process unfolds, Ivanhoe continues to engage and consult with numerous local and aboriginal stakeholders to identify potential project impacts and mitigations and economic and employment opportunities for residents of area communities. It is anticipated that the regulatory approval process will be completed later in 2012. Project advancement, as currently envisaged, is subject to regulatory approval, financing and board sanction.

Ecuador

In October 2008, Ivanhoe Energy Ecuador Inc., an indirect wholly owned subsidiary, signed a 30 year contract with the Ecuador state oil companies Petroecuador and Petroproduccion. The contract gives Ivanhoe the right to explore and develop the Pungarayacu heavy oil field in Block 20, an area of 426 square miles, approximately 125 miles southeast of Quito, Ecuador’s capital city. The Company anticipates using HTL™ technology, as well as providing advanced oilfield technology, expertise and capital to develop, produce and upgrade heavy oil from the Pungarayacu field. The Company may also explore for lighter oil in the contract area and blend any light oil discoveries with the heavy oil for delivery to Petroproduccion.

In 2010, Ivanhoe drilled its first two appraisal wells in the Pungarayacu field. The second, IP-5b, well was successfully drilled, cored and logged to a total depth of 1,080 feet. The well was perforated in the Hollin oil sands and steam was successfully injected into the reservoir resulting in production of heated heavy oil. In 2011, the heavy crude oil extracted from the IP-5B well was successfully upgraded to local pipeline specifications using Ivanhoe’s proprietary HTL™ upgrading process. Later in 2011, the Company completed a 190-kilometre 2-D seismic survey over the southern portion

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of Block 20. Following the analysis of the seismic program, Ivanhoe began preparing to drill one exploration well into the deeper Hollin and pre-cretaceous horizons in the southern part of the Pungarayacu Block to test the potential of lighter oil resources, which would prove beneficial for blending purposes and overall project economics.

RESERVES, PRODUCTION AND RELATED INFORMATION

In addition to the information provided below, please refer to the “Supplementary Disclosures About Oil and Gas Production Activities (Unaudited)” set forth in Item 8 in this Annual Report for certain details regarding the Company’s oil and gas proved reserves, the estimation process and production by country. We have not filed with nor included in reports to any other US federal authority or agency, any estimates of total proved oil reserves since the beginning of the last fiscal year.

The following table presents estimated proved, probable and possible oil reserves as of December 31, 2011:

Summary of Oil and Gas Reserves Using Average 2011 Prices

Oil

Bitumen

China

Canada

Total

(mbbl)

Dagang

Other

Total China

Tamarack

Consolidated

Proved

Developed

1,160

1,235

–

1,235

Undeveloped

400

–

400

–

400

Total proved

1,560

1,635

–

1,635

Probable

Developed

356

–

356

–

356

Undeveloped

425

–

425

138,987

139,412

Possible

Developed

–

Undeveloped

–

32,864

China

Proved Reserves

Net proved reserves at December 31, 2011 were 1,635 mbbls. Production during the year was offset by in-field performance improvements from continued water injections and our ongoing hydraulic fracture stimulation program in the Dagang field. Four wells were drilled in 2011, and, in combination with geological review and reservoir mapping, supported additional future drilling locations.

In 2011, 153 mbbls were transferred from proved undeveloped to the proved developed category as a result of $3.4 million in capital spending related to drilling and completion activities in 2011. The transfer of reserves from proved undeveloped to the proved category was immaterial in 2010. The Company does not have any proved undeveloped reserves that have remained unconverted to proved developed reserves for longer than five years or more since their initial disclosure as proved reserves and all proved undeveloped reserves as of December 31, 2011 are expected to be converted to proved developed reserves within five years of their initial disclosure as proved developed reserves.

However, timing and pace of oil field developments is inherently uncertain. Unexpected geologic conditions; equipment failures; equipment delivery delays; accidents; adverse weather; government and joint venture partner approval delays; construction or start-up delays; economic conditions; and other associated risks may result in project delays. There can be no assurance that the development of any of our undeveloped reserves will occur as currently scheduled or at all.

Probable Reserves

At December 31, 2011, probable reserves in China were 822 mbbls. Additional probable reserves were assigned based on production improvements and increased recovery factors discussed under proved reserves.

Basis of Reserve Estimates

Reserve estimates were calculated using recovery forecasts based on historical production, supported by volumetric estimates using geological parameters. Recoveries rarely exceed 15% of the volumetrically calculated original oil-in-place per well spacing, which is judged acceptable for a water flood in a light oil reservoir. Improvements in production history and production declines are used for a review of producing reserves. With further mapping and geological reviews, proved and probable undeveloped reserves may then be assigned to future drilling and well optimizations.

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Canada

Probable and Possible Reserves

No additional reserves were assigned to Tamarack in 2011 as further reserve development is subject to regulatory approval of the Company’s application for the project, sanctioning by the Board of Directors and further delineation drilling.

Possible reserves are within the Tamarack Project application area, but have a lower degree of certainty compared to our probable reserves due to lower quality reservoir characteristics or decreased certainty based on the level of reservoir delineation.

Basis of Reserves Estimates

Recovery estimates for Tamarack are based on a combination of reservoir simulation, detailed reservoir characterization and analogue project performance

Internal Control over Reserve Estimation

Management is responsible for the estimates of oil and gas reserves and for preparing related disclosures. Estimates and related disclosures in this Annual Report are prepared in accordance with SEC requirements, generally accepted industry practices in the US and the standards of the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”) modified to reflect SEC requirements. As a Canadian public company, we are also subject to the disclosure requirements of National Instrument 51-101 (‘‘NI 51-101’’) of the CSA, which requires us to disclose reserves and other oil and gas information in accordance with the prescribed standards of NI 51-101 which differ, in certain respects, from SEC requirements. See the Special Note to Canadian Investors on page 11.

The process of estimating reserves requires complex judgments and decision making based on available geological, geophysical, engineering and economic data. To estimate the economically recoverable oil and gas reserves and related future net cash flows, we consider many factors and make various assumptions including:

—

expected reservoir characteristics based on geological, geophysical and engineering assessments;

—

future production rates based on historical performance and expected future operating and investment activities;

—

future oil and gas prices and quality differentials;

—

assumed effects of regulation by governmental agencies; and

—

future development and operating costs.

We believe these factors and assumptions are reasonable based on the information available to us at the time we prepared our estimates. However, these estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change.

Reserve estimates are categorized by the level of confidence that they will be economically recoverable. Proved reserves are those quantities of oil and gas, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible in future years from known reservoirs under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and gas actually recovered will equal or exceed the estimate. To achieve reasonable certainty, the technologies used in the estimation process have been demonstrated to yield results with consistency and repeatability.

Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Therefore, probable reserves have a higher degree of uncertainty than proved reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. Although possible reserve locations are found by “stepping out” from proved reserve locations, estimates of probable and possible reserves are, by their nature, more speculative than estimates of proved reserves and, accordingly, are subject to substantially greater risk of being realized.

Our reserve estimates were prepared by GLJ and reviewed by our in-house Senior Engineering Advisor (“SEA”). Our SEA is a professional engineer (P.Eng.) in Alberta, with over 29 years of broad petroleum engineering experience in the oil and gas industry in Canada and internationally. His past experience includes reserves estimations for government filings, reservoir development engineering for both oil and gas projects, economic evaluations for potential acquisitions and dispositions, production operations, project management, budgeting and corporate planning.

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All reserve information in this Annual Report is based on estimates prepared by GLJ. The technical personnel responsible for preparing the reserve estimates at GLJ meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas by the Society of Petroleum Engineers. GLJ is an independent firm of petroleum engineers, geologists, geophysicists and petrophysicists; they do not own an interest in our properties and are not employed on a contingent fee basis.

Our Board of Directors reviews the current reserve estimates and related disclosures as presented by the independent qualified reserves evaluators in their reserve report. Our Board of Directors has approved the reserve estimates and related disclosures.

Special Note to Canadian Investors

Ivanhoe is a SEC registrant and files annual reports on Form 10-K; accordingly, our reserves estimates and regulatory securities disclosures are prepared based on SEC disclosure requirements. In 2003, the CSA adopted NI 51-101 which prescribes standards that Canadian companies are required to follow in the preparation and disclosure of reserves and related information.

Until 2010, we had an exemption from certain requirements of NI 51-101 which permitted us to substitute disclosures based on SEC requirements for some of the annual disclosure required by NI 51-101 and to prepare our reserve estimates and related disclosures in accordance with SEC requirements, generally accepted industry practices in the US as promulgated by the Society of Petroleum Engineers and the standards of the COGE Handbook, modified to reflect SEC requirements. This exemption is no longer available to us for reserve reporting in Canada.

We have, however, received another exemption from the CSA which, among other things, allows us to disclose reserves and related information in accordance with applicable US disclosure requirements provided that we also make disclosure of our reserves and other oil and gas information in accordance with applicable NI 51-101 requirements. We disclose reserve information in accordance with applicable US disclosure requirements in this Annual Report. We disclose reserves and other oil and gas information in accordance with applicable NI 51-101 requirements in our Form 51-101F1, Statement of Reserves Data and Other Oil and Gas Information, which is filed with the CSA and available at www.sedar.com.

The reserve quantities disclosed in this Annual Report represent reserves calculated on an average, first-day-of-the-month price during the 12 month period preceding the end of the year for 2011, using the standards contained in SEC Regulations S-X and S-K and Accounting Standards Codification 932 Extractive Activities – Oil and Gas (section 235-55), formerly Statement of Financial Accounting Standards No. 69, “Disclosures About Oil and Gas Producing Activities”. Such information differs from the corresponding information prepared in accordance with Canadian disclosure standards under NI 51-101. The primary differences between the current SEC requirements and the NI 51-101 requirements are as follows:

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SEC registrants apply SEC reserves definitions and prepare their reserves estimates in accordance with SEC requirements and generally accepted industry practices in the US, whereas NI 51-101 requires adherence to the definitions and standards promulgated by the COGE Handbook;

—

the SEC mandates disclosure of proved reserves calculated using an average, first-day-of-the-month price during the 12 month period preceding and existing costs only, whereas NI 51-101 requires disclosure of reserves and related future net revenues using forecasted prices, with additional constant pricing disclosure being optional;

—

the SEC mandates disclosure of reserves by geographic area only, whereas NI 51-101 requires disclosure of more reserve categories and product types; and

—

the SEC leaves the engagement of independent qualified reserves evaluators to the discretion of a company’s board of directors, whereas NI 51-101 requires issuers to engage such evaluators.

The foregoing is a general and non-exhaustive description of the principal differences between SEC disclosure requirements and NI 51-101 requirements. Please note that the differences between SEC and NI 51-101 requirements may be material.

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Production, Sales Prices and Production Costs

	2011		2010
Oil production (bbls/d)		967		788
Average sales price ($/bbl)		105.93		75.52
Average operating costs (1) ($/bbl)		44.10		33.05

(1)

Average operating costs per unit of production, based on net interest after royalties, represent lifting costs, including a windfall gain levy. According to the “Administrative Measures on Collection of Windfall Gain Levy on Oil Exploitation Business,” enterprises exploiting and selling oil in China are subject to a windfall gain levy (the “Windfall Levy”) if the monthly weighted average price of oil exceeds a certain threshold. Average operating costs exclude depletion and depreciation, income taxes, interest, selling and general administrative expenses

Ivanhoe’s oil production originates in Asia, specifically the Dagang and Daqing fields in China. The majority of our production comes from Dagang and is sold to the Chinese national petroleum company.

Drilling Activity

Net Exploratory

Net Development

Total

(net wells)(1)

Productive

Dry Holes

Total

Productive

Dry Holes

Total

Wells Drilled

Asia

2011(2)

–

1.0

2.5

–

2.5

3.5

(1)

Net wells are the sum of fractional working interests owned in gross wells.

(2)

At December 31, 2010, we were actively drilling Zitong-1 and Yixin-2 wells in our Zitong project and one well in our Dagang field. No wells were completed in 2010.

Wells in Progress

At December 31, 2011, we were not actively drilling any wells.

Producing Oil Wells

The Company does not have any producing gas wells. The Company had 49.0 gross (24.0 net) productive oil wells in Asia, as at December 31, 2011.

Acreage

Developed Acres

Undeveloped Acres(1)

Gross

Net

Gross

Net

Asia – China(2)

1,724

845

253,496

225,683

Asia – Mongolia

–

3,107,907

Canada

–

7,520

Latin America

–

272,639

(1)

Undeveloped acreage is considered to be those acres on which wells have not been drilled or completed to a point that would permit production of commercial quantities of oil and gas regardless of whether or not such acreage contains proved reserves.

(2)

The number of developed acres disclosed in respect of our China properties relates only to those portions of the field covered by our producing operations and does not include the remaining portions of the field previously developed by CNPC.

The Tamarack lease in Canada will expire in October 2016, but Ivanhoe has sufficient drill density to be granted a continuation by the Alberta Department of Energy one year prior to expiry or upon first production, whichever comes first.

We signed a specific services contract with the state oil companies of Ecuador in October 2008 that allows us to develop Block 20 for a term of 30 years, extendable by mutual agreement of the parties, for two additional periods of five years each, depending on the interests of the State and in conformity with local laws.

Subsequent to the completion of Phase II of the Zitong PSC, acreage not identified for development and future production was relinquished to CNPC in 2011. The remaining Zitong acreage will be relinquished upon termination of the PSC in 2032.

Under the terms of the Dagang PSC, acreage in the Dagang field will revert to CNPC upon contract termination in 2027, at the latest, unless Ivanhoe abandons the field before then.

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Acreage in Mongolia is subject to periodic relinquishments up to the end of the exploration period and the remaining acreage designated for appraisal and development will expire 20 years after the final commercial discovery on the Nyalga block.

TECHNOLOGY DEVELOPMENT

The Company’s Technology Development segment captures HTL™ activities. In April 2005, Ivanhoe merged with Ensyn and thereby obtained an exclusive, irrevocable license to the HTL™ process for all applications other than biomass. The Company has since continued to expand patent coverage to protect innovations to the HTL™ technology and to significantly extend Ivanhoe’s portfolio of HTL™ intellectual property. Ivanhoe is the assignee of five granted US patents and currently has six US patent applications pending. In other countries, the Company has 11 patents granted and 41 patents are pending. In addition, Ivanhoe owns exclusive, irrevocable licenses to 21 global patents for the rapid thermal processing process as it pertains to petroleum. The expiration date for Ivanhoe’s key patents is 2028.

Ivanhoe has a feedstock test facility (“FTF”) at the Southwest Research Institute in San Antonio, Texas. The FTF is a small 10-15 bbls/d, highly flexible, state-of-the-art facility which will permit analysis of crude oil in small volumes. In 2010, the FTF supported basic and front-end engineering for a commercial-scale HTL™ plant for the Tamarack Project in Canada. In 2011, activities at the FTF focused on the assay and analyses related to the successful upgrading of the heavy oil recovered from the Pungarayacu IP-5B well in Ecuador.

CERTAIN FACTORS AFFECTING THE BUSINESS

Competition

The oil and gas industry is highly competitive. Our position in the oil and gas industry, which includes the search for and development of new sources of supply, is particularly competitive. Our competitors include major, intermediate and junior oil and gas companies and other individual producers and operators, many of which have substantially greater financial and human resources and more developed and extensive infrastructure. Our larger competitors, by reason of their size and relative financial strength, can more easily access capital markets and may enjoy a competitive advantage in the recruitment of qualified personnel. They may be able to more easily absorb the burden of any changes in laws and regulations in the jurisdictions in which we do business, adversely affecting our competitive position. Our competitors may be able to pay more for producing oil and gas properties and may be able to define, evaluate, bid for, and purchase a greater number of properties and prospects. Further, these companies may enjoy technological advantages and may be able to implement new technologies more rapidly. Our ability to acquire additional properties in the future will depend upon our ability to conduct efficient operations, evaluate and select suitable properties, implement advanced technologies, and consummate transactions in a highly competitive environment. The oil and gas industry also competes with other industries in supplying energy, fuel and other needs of consumers.

Environmental Regulations

Our oil and gas and HTL™ operations are subject to various levels of government regulation relating to the protection of the environment in the countries in which we operate. We believe that our operations comply in all material respects with applicable environmental laws.

Environmental legislation imposes, among other things, restrictions, liabilities and obligations in connection with the generation, handling, storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases and emissions of various substances to the environment. As well, environmental laws regulate the qualities and compositions of the products sold and imported. Environmental legislation also requires that wells, facility sites and other properties associated with our operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. In addition, certain types of operations, including exploration and development projects and significant changes to certain existing projects, may require the submission and approval of environmental impact assessments. Compliance with environmental legislation can require significant expenditures and failure to comply with environmental legislation may result in the imposition of fines and penalties and liability for clean-up costs and damages. We anticipate that changes in environmental legislation may require, among other things, reductions in emissions to the air from our operations and result in increased capital expenditures.

Operations in Canada are governed by comprehensive federal, provincial and municipal regulations. We submitted the Regulatory Application/Environmental Impact Assessment for the Tamarack Project to the Government of Alberta in November 2010. The regulatory process is expected to conclude near the end of 2012. In addition, the Company will be required to obtain numerous ancillary approvals prior to commencing operations and will be subject to ongoing environmental monitoring and auditing requirements.

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China, Mongolia and Ecuador continue to develop and implement more stringent environmental protection regulations and standards for different industries. Projects are currently monitored by governments based on the approved standards specified in the environmental impact statements prepared for individual projects, located on the Company’s website.

Government Regulations

Our business is subject to certain federal, state, provincial and local laws and regulations in the regions in which we operate relating to the exploration for, and development, production and marketing of, crude oil and gas, as well as environmental and safety matters. In addition, the Chinese and Mongolian governments regulate various aspects of foreign company operations in their respective countries. Such laws and regulations have generally become more stringent in recent years in Canada, Ecuador, China and Mongolia, often imposing greater liability on a larger number of potentially responsible parties. Because the requirements imposed by such laws and regulations are frequently changed, we are not able to predict the ultimate cost of compliance.

EMPLOYEES

As at December 31, 2011, we had 212 employees actively engaged in the business. None of our employees are unionized.

ITEM 1A: RISK FACTORS

Our operations are exposed to various risks, some of which are common to other companies in the oil and gas industry and some of which are unique to our operations. Certain risks set out below constitute “forward-looking statements” and readers should refer to the “Special Note Regarding Forward-Looking Statements” on page 4.

Our ability to continue as a going concern may be adversely affected by inadequate funding

We have a history of operating losses and cash flow from operating activities will not be sufficient to meet our current obligations and fund future capital projects. Historically, we have relied upon equity capital as our principal source of funding. The operation of our business is dependent upon our ability to obtain additional capital to preserve our interests in current projects and to meet obligations associated with future projects. We may seek financing from 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 we will be able to obtain such financing or obtain it on favorable terms and any future equity issuances may be dilutive to investors. Obtaining financing may be hampered by the inability to attract strategic investors to our projects on acceptable terms, volatility in equity and debt markets and a sustained decrease in the market price of our common shares. Without access to additional financing or other cash generating activities, there is material uncertainty that casts substantial doubt that the Company will be able to continue as a going concern.

We may not be able to fund our substantial capital requirements

Our business is capital intensive and the advancement of our exploration projects in China and Mongolia, development projects in Canada and Ecuador and HTL™ initiatives require significant funding. Since cash flows from existing operations are insufficient to fund future capital expenditures, we intend to finance future capital projects with 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 or from the sale of existing assets. There is no assurance that we will be able to obtain such financing or obtain it on favorable terms and any future equity issuances may be dilutive to investors. Obtaining financing in the future may be hampered by the inability to attract strategic investors to our projects on acceptable terms, volatility in equity and debt markets and a sustained decrease in the market price of our common shares. If we fail to obtain adequate funding when needed, we may have to delay or forego potentially valuable project acquisition and development opportunities or default on existing funding commitments to third parties and forfeit or dilute our rights in existing oil and gas property interests.

Talisman’s security interest in our assets could impede our ability to secure third party debt

Through our acquisition of Tamarack in 2008, we incurred a series of debt obligations in favor of Talisman secured by a first fixed charge and security interest in the Tamarack oil sands leases and a general security interest in all of our present and after acquired property, other than our equity interests in our subsidiaries (through which we hold our assets in China, Mongolia and Ecuador and our HTL™ technology). Although we have satisfied substantially all of the material debt obligations we owed to Talisman, we remain subject to a contingent payment obligation of up to Cdn$15.0 million, which is also secured by Talisman’s security interest. This contingent obligation becomes due and payable if and when we obtain the requisite government and other approvals necessary to develop the northern border of one of the leases. We are obliged to use commercially reasonable efforts to obtain these approvals. However, despite our efforts, the risks inherent in oil field development, including potential environmental considerations, create significant uncertainty as to

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when, if ever, we will be able to obtain these approvals and, consequently, we cannot predict when, if ever, this contingent obligation will become due and payable or when Talisman’s security interest will be released and discharged.

The Talisman security interest restricts our ability to grant security over our Tamarack project assets to secure debt obligations to third parties that we may create in the future. Assets unencumbered by the Talisman security interest may be insufficient as collateral to secure these obligations. This could adversely affect our ability to obtain debt financing or to obtain it on favorable terms. Since Talisman’s security interest secures a contingent obligation of potentially indefinite duration, we cannot predict when, and on what terms, we will be able to mitigate this risk.

The volatility of oil prices may affect our financial results

Our revenues, operating results, profitability and future growth are highly dependent on the price of oil. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. Even relatively modest changes in oil prices may significantly change our revenues, results of operations, cash flows and proved reserves. Historically, the market for oil has been volatile and is likely to continue to be volatile in the future.

Oil prices may fluctuate widely in response to relatively minor changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, such as weather conditions; overall global economic conditions; terrorist attacks or military conflicts; political and economic conditions in oil producing countries; the ability of members of the Organization of Petroleum Exporting Countries (“OPEC”) to agree to and maintain oil price and production controls; the level of demand and the price and availability of alternative fuels; speculation in the commodity futures markets; technological advances affecting energy consumption; governmental regulations and approvals; and proximity and capacity of oil pipelines and other transportation facilities. These factors and the volatility of the energy markets make it extremely difficult to predict future oil price movements with any certainty.

We may be required to take write-downs if oil prices decline, our estimated development costs increase or our exploration results deteriorate

We may be required to write-down the carrying value of our properties if oil prices decline or if we have substantial downward adjustments to our estimated proved reserves, increases in our estimates of development costs or deterioration in our exploration results. See “Critical Accounting Principles and Estimates – Impairment” in Item 7, MD&A, of this Annual Report.

Estimates of proved reserves and future net revenue may change if the assumptions on which such estimates are based prove to be inaccurate

Our estimated reserves are based on many assumptions that may turn out to be inaccurate. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment, the assumptions used regarding prices for oil and gas, production volumes, required levels of operating and capital expenditures and quantities of recoverable oil reserves. Any significant variance from the assumptions used could result in the actual quantity of our reserves and future net cash flow being materially different from the estimates we report. In addition, actual results of drilling, testing and production and changes in oil and gas prices after the date of the estimate may result in revisions to our reserve estimates. Revisions to prior estimates may be material.

We may incur significant costs on exploration or development which may prove unsuccessful or unprofitable

There can be no assurance that the costs we incur on exploration or development will result in an acceptable level of economic return. We may misinterpret geological or engineering data, which may result in material losses from unsuccessful exploration or development drilling efforts. We bear the risks of project delays and cost overruns due to unexpected geologic conditions; equipment failures; equipment delivery delays; accidents; adverse weather; government and joint venture partner approval delays; construction or start-up delays; and other associated risks. Such risks may delay expected production and/or increase production costs.

We compete for oil and gas properties and personnel with many other exploration and development companies throughout the world who have access to greater resources

We operate in a highly competitive environment and compete with oil and gas companies and other individual producers and operators, many of which have longer operating histories and substantially greater financial and other resources. Many of these companies not only explore for and produce oil and gas, but also carry on refining operations and market petroleum and other products on a worldwide basis. We also compete with companies in other industries supplying energy, fuel and other needs to consumers. Our larger competitors, by reason of their size and relative financial strength, can more easily access capital markets and may enjoy a competitive advantage in the recruitment of qualified personnel. They may be able to absorb the burden of any changes in laws and regulations in the jurisdictions in which we do

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business and handle longer periods of reduced oil and gas prices more easily. Our competitors may be able to pay more for productive oil and gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects.

We compete with other companies to recruit and retain the limited number of individuals who possess the requisite skills and experience that are relevant to our business. This competition exposes us to the risk that we will have to pay increased compensation to such employees or increase the Company’s reliance and associated costs from partnering or outsourcing arrangements. There can be no assurance that employees with the abilities and expertise we require will be available.

Changes to laws, regulations and government policies in the jurisdictions in which we operate could adversely affect our ability to develop our projects

Our projects in Canada, Ecuador, China and Mongolia are subject to various international, federal, state, provincial, territorial and local laws and regulations relating to the exploration for and the development, production, upgrading, marketing, pricing, taxation and transportation of heavy oil, bitumen and related products and other matters, including environmental protection.

The exercise of discretion by governmental authorities under existing legislation and regulations, the amendment of existing legislation and regulations or the implementation of new legislation or regulations, affecting the oil and gas industry could materially increase the cost of developing and operating our projects and could have a material adverse impact on our business. There can be no assurance that laws, regulations and government policies relevant to our projects will not be changed in a manner which may adversely affect our ability to develop and operate them. Failure to obtain all necessary permits, leases, licenses and approvals, or failure to obtain them on a timely basis, could result in delays or restructuring of our projects and increase costs, all of which could have a material adverse effect on our business.

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

Complying with environmental and other government regulations could be costly and could negatively impact our production

Our operations are governed by various international, federal, state, provincial, territorial and local laws and regulations. Oil, gas, oil sands and heavy oil extraction, upgrading and transportation operations are subject to extensive regulation. Various approvals are required before such activities may be undertaken. We are subject to laws and regulations that govern the operation and maintenance of our facilities, the discharge of materials into the environment and other environmental protection issues. These laws and regulations may, among other potential consequences, require that we acquire permits before commencing drilling; restrict the substances that can be released into the environment with drilling and production activities; limit or prohibit drilling activities in protected areas such as wetlands or wilderness areas; require that reclamation measures be taken to prevent pollution from former operations; require remedial measures to mitigate pollution from former operations, such as plugging abandoned wells and remediating contaminated soil and groundwater; and require remedial measures be taken with respect to property designated as a contaminated site.

The costs of complying with environmental laws and regulations in the future may harm our business. Furthermore, future changes in environmental laws and regulations may result in stricter standards and enforcement, larger fines and liability, and increased capital expenditures and operating costs, any of which could have a material adverse effect on our financial condition or results of operations.

No assurance can be given with respect to the impact of future environmental laws or the approvals, processes or other requirements thereunder or our ability to develop or operate our projects in a manner consistent with our current expectations. No assurance can be given that environmental laws will not limit project development or materially increase the cost of production, development or exploration activities or otherwise adversely affect our financial condition, results of operations or prospects.

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Our business involves many operating risks that can cause substantial losses; insurance may not protect us against all these risks

Our operations are subject to many risks inherent in the oil and gas industry, including fires; natural disasters; adverse weather conditions; explosions; encountering formations with abnormal pressures; encountering unusual or unexpected geological formations; blowouts; cratering; unexpected operational events; equipment malfunctions; pipeline ruptures; spills; compliance with environmental and government regulations and title problems, any of which could cause us to experience material losses.

We are insured against some, but not all, of the hazards associated with our business, so we may sustain losses that could be substantial due to events that are not insured or are underinsured. The occurrence of an event that is not covered or not fully covered by insurance could have a material adverse impact on our financial condition and results of operations. We do not carry business interruption insurance and, therefore, the loss and delay of revenues resulting from curtailed production are not insured.

Under environmental laws and regulations, we could be liable for personal injury, clean-up costs and other environmental and property damages, as well as administrative, civil and criminal penalties. We maintain limited insurance coverage for sudden and accidental environmental damages as well as environmental damage that occurs over time. However, we do not believe that insurance coverage for the full potential liability of environmental damages is available at a reasonable cost. Accordingly, we could be liable, or could be required to cease production, if environmental damage occurs.

SAGD technologies for in-situ recovery of heavy oil and bitumen are energy intensive and may be unsustainable

We intend to integrate established SAGD thermal recovery techniques with our patented HTL™ upgrading process. Heavy oil recovery using the SAGD process is subject to technical and financial uncertainty. Current SAGD technologies for in-situ recovery of heavy oil and bitumen are energy intensive, requiring significant consumption of natural gas and other fuels for the production of steam used in the recovery process. The amount of steam required in the production process can also vary and impact costs. The performance of the reservoir can also impact the timing and levels of production using SAGD technology. While the technology is now being used by several producers, commercial application of this technology is still in the early stages relative to other methods of production and, accordingly, in the absence of an extended operating history, there can be no assurances with respect to the sustainability of SAGD operations.

We may not successfully commercialize our HTL™ technology

Success in commercializing our HTL™ technology in the oil and gas industry depends on our ability to economically design, construct and operate commercial-scale plants and a variety of other factors, many of which are outside our control. To date, commercial-scale HTL™ plants have only been constructed in the bio-mass industry.

Technological advances could render our HTL™ technology obsolete

We expect that technological advances in the processes and procedures for upgrading heavy oil and bitumen into lighter, less viscous products will continue to progress. It is possible that those advances could cause our HTL™ technology to become uncompetitive or obsolete.

Alternate sources of energy could lower the demand for our HTL™ technology

Alternative sources of energy are continually under development. If reliance upon petroleum based fuels decreases, the demand for our HTL™ upgraded product may decline. It is possible that technological advances in engine design and performance could reduce the use of petroleum based fuels, which would also lower the demand for our HTL™ upgraded product.

Efforts to commercialize our HTL™ technology may give rise to claims of infringement upon the patents or other proprietary rights of others

We own a license to use the HTL™ technology that we are seeking to commercialize, but we may not become aware of claims of infringement upon the patents or other rights of others in this technology until after we have made a substantial investment in the development and commercialization of projects utilizing the technology. Third parties may claim that the technology infringes upon past, present or future patented technologies. Legal actions could be brought against us and our licensors claiming damages and seeking an injunction that would prevent us from testing or commercializing the technology. If an infringement action were successful, in addition to potential liability for damages, we and our licensors could be required to obtain a claiming party’s license in order to continue to test or commercialize the technology. Any required license might not be made available or, if available, might not be available on acceptable terms, and we could be prevented entirely from testing or commercializing the technology. We may have to expend substantial resources in litigation defending against the infringement claims of others. Many possible claimants, such as the major energy

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companies that have or may be developing proprietary heavy oil upgrading technologies competitive with our technology, may have significantly more resources to spend on litigation.

A breach of confidentiality obligations could put us at competitive risk and potentially damage our business

While discussing potential business relationships with third parties, we may disclose confidential information on operating results or proprietary intellectual property. Although confidentiality agreements are signed by third parties prior to the disclosure of any confidential information, a breach could put us at competitive risk and may cause significant damage to our business. The harm to our business from a breach of confidentiality cannot presently be quantified, but may be material and may not be compensable in damages. There is no assurance that, in the event of a breach of confidentiality, we will be able to obtain equitable remedies, such as injunctive relief, from a court of competent jurisdiction in a timely manner, if at all, in order to prevent or mitigate any damage to our business that such a breach of confidentiality may cause.

Certain projects are at a very early stage of development

Our projects are at varying stages of development. We have submitted the Regulatory Application/Environmental Impact Assessment for the Tamarack Project to the Government of Alberta. The regulatory process is expected to take approximately 24 months; however, we could be forced to go to a hearing and there is no assurance that the process will be completed on a timely basis. Construction of the Tamarack Project could be significantly delayed. Additionally, the Government of Alberta may not approve the project as proposed, or it may place certain conditions upon the approval, which could significantly impair the economics of the project. Our Zitong project in China and projects in Ecuador and Mongolia are at a very early stage of development; no reserves have yet been established and no detailed feasibility or engineering studies have yet been produced.

There can be no assurances that these projects will be completed within any anticipated time frame or within the parameters of any anticipated capital cost. We have yet to establish a defined schedule for financing and fully developing such projects. In our efforts to continue developing these projects, we may experience delays, interruption of operations or increased costs as a result of unanticipated events and circumstances. These include breakdowns or failures of equipment or processes; construction performance falling below expected levels of output or efficiency; design errors; challenges to proprietary technology; contractor or operator errors; non-performance by third party contractors; labor disputes; disruptions or declines in productivity; increases in materials or labor costs; inability to attract sufficient numbers of qualified workers; delays in obtaining, or conditions imposed by, regulatory approvals; violation of permit requirements; disruption in the supply of energy; and catastrophic events such as fires, earthquakes, storms or explosions.

Our heavy oil project in Canada may be exposed to title risks and aboriginal claims

With respect to the heavy oil leases that we acquired from Talisman, there is a risk that our ownership of those leases may be subject to prior unregistered agreements or interests or undetected claims or interests that could impair our title. Any such impairment could jeopardize our entitlement to the economic benefits, if any, associated with the leases, which could have a material adverse effect on our financial condition, results of operations and ability to execute our business plans in a timely manner, if at all.

Aboriginal peoples have claimed aboriginal title and rights to large areas of land in western Canada where oil and gas operations are conducted, including claims that, if successful, could affect the timing of the development of our heavy oil leases, or the manner in which we can conduct future operations, and have a material adverse effect on our business.

Our investment in Ecuador may be at risk if the agreement through which we hold our interest in the Block 20 project is challenged or cannot be enforced

We hold our interest in the Block 20 heavy oil project in Ecuador through a services agreement with Petroecuador and its subsidiary Petroproduccion. The agreement is governed by the laws of Ecuador. Although the agreement has been translated into English, the official and governing language of the agreement is Spanish and if any discrepancy exists between the official Spanish version of the agreement and the English translation, the official Spanish version prevails. There may be ambiguities, inconsistencies and anomalies between the official Spanish version of the agreement and the English translation that could materially affect how our rights and obligations under the agreement are conclusively interpreted and such interpretations may be materially adverse to our interests.

The dispute resolution provisions of the Block 20 agreement stipulate that disputes involving industrial property, including intellectual property, and technical or economic issues are subject to international arbitration. Other disputes are subject to resolution through mediation or arbitration in Ecuador. There is a risk that we, and the other parties to the Block 20 agreement, will be unable to agree upon the proper forum for the resolution of a dispute based on the subject matter of

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the dispute. There can also be no assurance that the other parties will comply with the dispute resolution provisions or otherwise voluntarily submit to arbitration.

Government policy in Ecuador may change to discourage foreign investment or requirements not foreseen may be implemented. There can be no assurance that our investments and assets in Ecuador will not be subject to nationalization, requisition or confiscation, whether legitimate or not, by any authority or body. While the Block 20 agreement contains provisions for compensation and reimbursement of losses we may suffer under such circumstances, there is no assurance that such provisions would effectively restore the value of our original investment. There can be no assurance that Ecuadorian laws protecting foreign investments will not be amended or abolished or that the existing laws will be enforced or interpreted to provide adequate protection against any or all of the risks described above. There can also be no assurance that the Block 20 agreement will prove to be enforceable or provide adequate protection against any or all of the risks described above.

Our business may be harmed if we are unable to retain our interests in licenses, leases and production sharing contracts

Some of our properties are held under licenses and leases, working interests in licenses and leases or production sharing contracts. If we fail to meet the specific requirements of the instrument through which we hold our interest, it may terminate or expire. We may not be able to meet any or all of the obligations required to maintain our interest in each such license, lease or production sharing contract. Some of our property interests will terminate unless we fulfill such obligations. If we are unable to satisfy these obligations on a timely basis, we may lose our rights in these properties. The termination of our interests in these properties may harm our business.

Our principal shareholder may significantly influence our business

As at the date of this Annual Report, our largest shareholder, Robert M. Friedland, owned approximately 15.49% of our common shares. As a result, he has the voting power to significantly influence our policies, business and affairs and the outcome of any corporate transaction or other matter, including mergers, consolidations and the sale of all, or substantially all, of our assets. In addition, the concentration of our ownership may have the effect of delaying, deterring or preventing a change in control that otherwise could result in a premium in the price of our common shares.

If we lose our key management and technical personnel, our business may suffer

We rely upon a relatively small group of key management personnel. Given the technological nature of our business, we also rely heavily upon our scientific and technical personnel. Our ability to implement our business strategy may be constrained and the timing of implementation may be impacted if we are unable to attract and retain sufficient personnel. We do not maintain any key man insurance. We do not have employment agreements with all of our key management and technical personnel and we cannot assure that these individuals will remain with us in the future. An unexpected partial or total loss of their services would harm our business.

Information regarding our future plans reflects our current intent and is subject to change

We describe our current exploration and development plans in this Annual Report. Whether we ultimately implement our plans will depend on the availability and cost of capital; the HTL™ technology process test results; additional seismic data or reprocessed existing data; current and projected oil or gas prices; costs and availability of drilling rigs and other equipment; supplies; personnel; success or failure of activities in similar areas; changes in estimates of project completion costs; and our ability to attract other industry partners to acquire a portion of the working interest to reduce costs and exposure to risks.

We will continue to gather data about our projects and it is possible that additional information will cause us to alter our schedule or determine that a project should not be pursued at all. Our plans regarding our projects might change.

ITEM 1B: UNRESOLVED STAFF COMMENTS

None.

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ITEM 3: LEGAL PROCEEDINGS

The Company is a defendant in a lawsuit filed 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. The Company removed the case to the United States District Court for the Eastern District of California and all of the defendants have answered and filed counterclaims for attorneys’ fees. Defendants filed a motion to dismiss certain claims and to compel arbitration of others. Plaintiffs’ filed a motion to remand the case to state court. On December 23, 2011, the Magistrate Judge denied plaintiffs’ motion to remand and issued findings and recommendations that would send all of the parties and all of the claims to arbitration should the district court Judge assigned to the case adopt them. On January 19, 2012 the district court Judge adopted the Magistrate Judge’s findings and recommendations in full, ordered the parties to arbitration and stayed the district court proceedings to allow for the completion of the arbitration. 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.

PART II

ITEM 5: MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common shares trade on the Toronto Stock Exchange (the “TSX”) and The NASDAQ Capital Market (“NASDAQ”) under the symbols “IE” and “IVAN” respectively. The trading range of our common shares is as follows:

		TSX (Cdn$)				NASDAQ (US$)
		High		Low		High		Low
2011	Q1		3.58		2.67		3.67		2.75
	Q2		2.84		1.58		2.97		1.60
	Q3		1.96		1.02		2.03		0.99
	Q4		1.47		0.75		1.46		0.72
2010	Q1		3.90		2.90		3.79		2.75
	Q2		3.36		1.97		3.37		1.87
	Q3		2.19		1.59		2.08		1.50
	Q4		2.89		2.15		2.88		2.10
2009	Q1		1.53		0.57		1.22		0.45
	Q2		2.16		1.38		1.85		1.10
	Q3		2.98		1.31		2.81		1.13
	Q4		3.25		2.20		3.12		2.02

On December 30, 2011, the closing price of our common shares was Cdn$1.12 on the TSX and $1.12 on NASDAQ.

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As at December 31, 2011, a total of 344,139,428 of our common shares were issued and outstanding and held by 187 holders of record with an estimated 26,343 additional shareholders whose common shares were held for them in street name or nominee accounts.

DIVIDENDS

We have not paid any dividends on our outstanding common shares since we were incorporated and we do not anticipate that we will do so in the foreseeable future. The declaration of dividends on our common shares is, subject to certain statutory restrictions described below, within the discretion of our Board of Directors based on their assessment of, among other factors, our earnings or lack thereof, our capital and operating expenditure requirements and our overall financial condition. Under the Yukon Business Corporations Act, our Board of Directors has no discretion to declare or pay a dividend on our common shares if they have reasonable grounds for believing that we are, or after payment of the dividend would be, unable to pay our liabilities as they become due or that the realizable value of our assets would, as a result of the dividend, be less than the aggregate sum of our liabilities and the stated capital of our common shares.

EXEMPTIONS FROM CERTAIN NASDAQ MARKETPLACE RULES

As a Canadian issuer listed on NASDAQ, we are not required to comply with certain of NASDAQ’s Marketplace Rules and instead may comply with applicable Canadian requirements. As a foreign private issuer, we are only required to comply with the following NASDAQ rules: (i) we must have an audit committee that satisfies applicable NASDAQ requirements and that is composed of directors each of whom satisfy NASDAQ’s prescribed independence standards; (ii) we must provide NASDAQ with prompt notification after an executive officer of the Company becomes aware of any material non-compliance by us with any applicable NASDAQ Marketplace Rule; (iii) our common shares must be eligible for a Direct Registration Program operated by a clearing agency registered under Section 17A of the Exchange Act; and (iv) we must provide a brief description of any significant differences between our corporate governance practices and those followed by US companies quoted on NASDAQ.

Applicable Canadian rules pertaining to corporate governance require us to disclose in our management proxy circular, on an annual basis, our corporate governance practices, including whether or not our independent directors hold regularly scheduled meetings at which only independent directors are present, but there is no legal requirement in Canada for independent directors to hold regularly scheduled meetings at which only independent directors are present.

Although our independent directors hold meetings from time to time, as and when considered necessary or desirable by the independent lead director or by any other independent director, such meetings are not regularly scheduled. Our non-management directors hold regularly scheduled meetings but not all of our non-management directors are independent.

ENFORCEABILITY OF CIVIL LIABILITIES

We are a company incorporated under the laws of the Yukon Territory of Canada. Some of our directors, controlling shareholders, officers and representatives of the experts named in this Annual Report reside outside the US and a substantial portion of their assets and our assets are located outside the US. As a result, it may be difficult to effect service of process within the US upon the directors, controlling shareholders, officers and representatives of experts who are not residents of the US or to enforce against them judgments obtained in the courts of the US based upon the civil liability provisions of the federal securities laws or other laws of the US. There is doubt as to the enforceability in Canada, against us or against any of our directors, controlling shareholders, officers or experts who are not residents of the US, in original actions or in actions for enforcement of judgments of US courts, of liabilities based solely upon civil liability provisions of the US federal securities laws. Therefore, it may not be possible to enforce those actions against us, our directors, officers, controlling shareholders or experts named in this Annual Report.

EXCHANGE CONTROLS AND TAXATION

There is no law or governmental decree or regulation in Canada that restricts the export or import of capital, or affects the remittance of dividends, interest or other payments to a non-resident holder of our common shares, other than withholding tax requirements.

There is no limitation imposed by the laws of Canada, the laws of the Yukon Territory, or our constating documents on the right of a non-resident to hold or vote our common shares, other than as provided in the Investment Canada Act (Canada) (the “Investment Act”), which generally prohibits a reviewable investment by an investor that is not a “Canadian”, as defined, unless after review, the minister responsible for the Investment Act is satisfied that the investment is likely to be of net benefit to Canada. An investment in our common shares by a non-Canadian who is not a “WTO investor” (which includes governments of, or individuals who are nationals of, member states of the World Trade Organization and

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corporations and other entities which are controlled by them), at a time when we were not already controlled by a WTO investor, would be reviewable under the Investment Act under two circumstances. First, if it was an investment to acquire control (within the meaning of the Investment Act) and the value of our assets, as determined under Investment Act regulations, was Cdn$5 million or more. Second, the investment would also be reviewable if an order for review was made by the federal cabinet of the Canadian government on the grounds that the investment related to Canada’s cultural heritage or national identity (as prescribed under the Investment Act), regardless of asset value (a “Cultural Business”). Currently, an investment in our common shares by a WTO investor, or by a non-Canadian at a time when we were already controlled by a WTO investor, would be reviewable under the Investment Act if it was an investment to acquire control and the value of our assets, as determined under Investment Act regulations, was not less than a specified amount, which for 2012 is Cdn$330 million. The Investment Act provides detailed rules to determine if there has been an acquisition of control. For example, a non-Canadian would acquire control of us for the purposes of the Investment Act if the non-Canadian acquired a majority of our outstanding common shares. The acquisition of less than a majority, but one-third or more, of our common shares would be presumed to be an acquisition of control of us unless it could be established that, on the acquisition, we were not controlled in fact by the acquirer through the ownership of common shares. An acquisition of control for the purposes of the Investment Act could also occur as a result of the acquisition by a non-Canadian of all or substantially all of our assets.

The Canadian Federal Government has announced certain forthcoming amendments (the “Amendments”) to the Investment Act. Once they come into force, the Amendments would generally raise the thresholds that trigger governmental review. Specifically, with respect to WTO investors, the Amendments would see the thresholds for the review of direct acquisitions of control of a business which is not a Cultural Business increase from the current Cdn$330 million (based on book value) to Cdn$600 million (to be based on the “enterprise value” of the Canadian business) for the two years after the Amendments come into force, to Cdn$800 million in the following two years and then to Cdn$1 billion for the next two years. Thereafter, the threshold is to be adjusted to account for inflation. The Amendments will come into force when the government enacts regulations which, among other things, will provide how the “enterprise value” is to be determined.

The Investment Act also provides that the Minister of Industry may initiate a review of any acquisition by a non-Canadian of our common shares or assets if the Minister considers that the acquisition “could be injurious to (Canada’s) national security”.

Amounts that we may, in the future, pay or credit, or be deemed to have paid or credited, to shareholders as dividends in respect of the common shares held at a time when the beneficial owner is not a resident of Canada within the meaning of the Income Tax Act (Canada), will generally be subject to Canadian non-resident withholding tax of 25% of the amount paid or credited, which may be reduced under the Canada-US Income Tax Convention (1980), as amended, (the “Convention”). Currently, under the Convention, the rate of Canadian non-resident withholding tax on the gross amount of dividends paid or credited to a US resident that is entitled to the benefits of the Convention is generally 15%. However, if the beneficial owner of such dividends is a US resident corporation that is entitled to the benefits of the Convention and owns 10% or more of our voting stock, the withholding rate is reduced to 5%. In the case of certain tax-exempt entities, which are residents of the US for the purpose of the Convention, the withholding tax on dividends may be reduced to 0%.

SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS

See table under “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” set forth in Item 12 in this Annual Report.

PERFORMANCE GRAPH

See table under “Executive Compensation” set forth in Item 11 in this Annual Report.

SALES OF UNREGISTERED SECURITIES

All securities we issued during the years ended December 31, 2011 and 2010, which were not registered under the Act, have been detailed in previously filed Form 10-Qs and Form 8-Ks.

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ITEM 6. SELECTED FINANCIAL DATA

SUMMARY OF SELECTED FINANCIAL DATA

The following table presents selected financial data based on International Financial Reporting Standards (“IFRS”) for the two most recent financial years.

($000s, except per share amounts)	2011			2010
Results of Operations
Revenues		37,979			21,928
Net loss		(25,276	)		(26,582	)
Net loss per share – basic and diluted		(0.07	)		(0.08	)

Financial Position
Total assets		413,710			394,418
Long term debt		61,892			–
Long term derivative instruments		1,617			–
Long term provisions		1,919			3,008

US GAAP INFORMATION FOR PRIOR YEARS

($000s, except per share amounts)	2009			2008			2007
Results of Operations
Revenues		17,152			55,335			27,281
Net loss from continuing operations		(32,679	)		(47,911	)		(23,080	)
Net loss from continuing operations per share – basic and diluted		(0.12	)		(0.19	)		(0.10	)

Financial Position
Total assets		262,717			292,847			251,627
Long term debt		38,005			40,392			10,412
Long term provisions		2,095			3,828			2,639

ITEM 7: MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Highlights			23
Results of Operations
Revenue			23
Netbacks			24
Operating Costs			24
Exploration and Evaluation			24
General and Administrative			25
Depletion and Depreciation			25
Foreign Exchange			25
Derivative Instruments			25
Gain on Derecognition of Long Term Provision			25
Provision for Income Taxes			25
Liquidity and Capital Resources			26
Critical Accounting Principles and Estimates			28
New Accounting Pronouncements			30

The following MD&A should be read in conjunction with the audited consolidated financial statements for the year ended December 31, 2011 (the “Financial Statements”). The Financial Statements have been prepared in accordance with and using accounting policies in full compliance with IFRS and International Accounting Standards (“IAS”) issued by the International Accounting Standards Board (“IASB”) and Interpretations of the International Financial Reporting Interpretations Committee, effective for the Company’s reporting for the year ended December 31, 2011.

As a foreign private issuer in the US, Ivanhoe is permitted to file with the SEC financial statements prepared under IFRS without a reconciliation to US generally accepted accounting principles (“GAAP”). It is possible that some of our accounting policies under IFRS could be different from US GAAP.

The date of this discussion is March 15, 2012. Unless otherwise noted, tabular amounts are in thousands of US dollars. Oil and gas production, revenue, reserves and related measures are presented net of royalty payments to governments.

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HIGHLIGHTS

($000, except as stated)	2011			2010
Production (bbls/d)		967			788
Realized oil prices ($/bbl)		105.93			75.52
Oil revenue		37,403			21,720
Capital expenditures		51,060			70,980

Cash flow used in operating activities		(26,245	)		(31,290	)
Net loss		(25,276	)		(26,582	)
Net loss per share – basic and diluted		(0.07	)		(0.08	)

Oil production increased in 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 2011 was $25.3 million compared to a $26.6 million net loss in 2010. 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. The current year also benefitted from lower exploration and evaluation expenses than in the prior year.

Capital expenditures totaled $51.1 million in 2011. In China, the Yixin-2 and Zitong-1 gas wells at the Company’s Zitong project in China were tested and fracture stimulated. At Dagang, four wells were drilled and completed in 2011. A well drilled in 2010 was also completed in early 2011. The fracture stimulation program at Dagang continued throughout 2011.

In the Nyalga basin of Mongolia, Ivanhoe’s first exploration well, N16-1E-1A, was drilled and abandoned as the well did not encounter oil shows in the reservoir. The Company observed oil staining, fluorescence and increases in background gas at its second exploration well site at N16-2E-B.

In Canada, regulators completed their initial review of the Company’s application 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. The Company submitted the supplemental information to the regulators in the fourth quarter of 2011. Project advancement, as currently envisaged, is subject to regulatory approval and financing.

In Ecuador, Ivanhoe completed a 190-kilometre 2-D seismic survey of Block 20. Following analysis of the seismic program, the Company plans to drill an exploration well into the deeper Hollin and pre-cretaceous horizons in the southern part of the Pungarayacu Block. The well will test the potential for lighter oil resources, which would prove beneficial for blending purposes and overall project economics.

RESULTS OF OPERATIONS

Revenue

	2011		2010
Oil revenue ($000s)		37,403		21,720

Production
Asia (net bbls)
Dagang		341,258		273,868
Daqing		11,842		13,751
Total production		353,100		287,619
Average daily production (bbls/d)		967		788

Pricing
Average realized oil price ($/bbl)		105.93		75.52
Average Brent ($/bbl)		110.63		80.25

Oil revenue in 2011 rose in comparison to 2010 due to a combination of higher production volumes and stronger realized prices. Gross oil production from the Dagang field in China was relatively constant. However, the terms of the Company’s PSC at Dagang with 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 higher levels of capital activity at Dagang in 2011, additional oil production was allocated to Ivanhoe.

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Dagang production is sold at the prior three month rolling average price of Cinta crude, which historically averages $2.00/bbl less than Brent crude, the standard the Company uses for its China reserve estimates. Following the increase in Cinta crude prices in 2011, our realized oil prices rose compared to 2010.

Netbacks

($/bbl)	2011			2010
Realized oil prices(1)		105.93			75.52
Less operating costs
Field operating		(19.68	)		(19.81	)
Windfall Levy		(23.18	)		(11.59	)
Engineering and support costs		(1.24	)		(1.76	)
Net operating revenue(1)		61.83			42.36
Depletion		(19.54	)		(21.54	)
Net revenue from operations(1)		42.29			20.82

(1)

Realized oil prices per barrel, net operating revenue per barrel and net revenue 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

($000s)	2011		2010
Asia
Field operating		6,947		5,699
Windfall Levy		8,185		3,333
Engineering support		438		507
		15,570		9,539
Technology Development
FTF operating costs		4,561		4,086
Total operating costs		20,131		13,625

Operating costs in China rose by $6.0 million in 2011 in comparison to 2010. The increase is primarily attributable to the Windfall Levy administered by the People’s Republic of China which rises with higher oil prices. Historically, the Windfall Levy was imposed at progressive rates from 20% to 40% on the portion of the monthly weighted average sales price exceeding $40.00/bbl. Effective November 1, 2011, the Ministry of Finance of the People’s Republic of China raised the Windfall Levy threshold to $55.00/bbl.

Field operating costs in total increased over the prior year due to additional production volumes in 2011. However, on a per barrel basis, field operating costs in 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 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 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 2011, $2.1 million of drilling costs were expensed in connection with the exploration well in Mongolia that was plugged and abandoned. In addition, it was determined that $0.7 million of expenditures related to the seismic program in Ecuador would have limited future value and were therefore charged to E&E expense.

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; consequently $3.5 million of geological costs incurred in prior periods were expensed as E&E costs in 2010. Ivanhoe drilled two appraisal wells on Block 20 in Ecuador in 2010. The first appraisal well, IP-15, encountered cementing and completion problems prior to steam injection operations, therefore testing was suspended without recovering oil. As a result, $4.9 million of drilling and testing costs were expensed as E&E costs in the fourth quarter of 2010.

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General and Administrative

G&A expenses mainly consist of staff, office and legal and other contract service costs. G&A expenses incurred in 2011 were $5.6 million higher in comparison to 2010. Staff costs rose $4.5 million as a result of the Company’s growing commitments to its projects around the world including updating its employee compensation program in 2011 which increased the estimated payment for the short term incentive compensation over the prior year. Professional fees increased as incremental legal costs of $1.4 million were incurred in connection with the proceedings described in Part I, Item 3 of this Form 10-K/A and $0.4 million of additional contract engineering costs related to Ivanhoe’s HTL™ technology were incurred to investigate new applications. G&A in 2011 also includes $0.3 million of financing and filing fees associated with the Cdn$73.3 million convertible unsecured subordinated debentures (“Convertible Debentures”) issued in the second quarter of 2011. Rising costs in 2011 were offset by lower charitable contributions; in 2010, the Company committed to a $1.0 million donation to flood victims in Ecuador.

Depletion and Depreciation

Depletion and depreciation expense in 2011 rose in comparison to 2010 due to a combination of factors. Depletion in Asia increased $0.7 million in 2011 due to higher production, despite a lower depletion rate as the result of additional Dagang reserves recorded on January 1, 2011. The depreciation expense incurred by the Technology segment was $0.6 million higher in 2011 due to revisions of the dismantled Commercial Demonstration Facility salvage values reducing depreciation in 2010.

Foreign Exchange

The Company incurred a smaller net foreign exchange gain in 2011 in comparison to the prior year. The Canadian dollar was stronger than the US dollar in the first nine months of 2011, subsequently weakening in the fourth quarter of 2011. Net foreign exchange gains incurred on the translation of the Company’s Canadian dollar denominated cash, debt and payables in the first three quarters of 2011 were partially offset by net foreign exchange losses in the fourth quarter.

In the first quarter of 2010, the Company incurred a net foreign exchange gain on the translation of its Canadian dollar cash raised in the Cdn$150.0 million private placement when the Canadian dollar strengthened against the US dollar, which was partially offset by a net foreign exchange loss incurred in the second quarter of 2010 when the Canadian dollar weakened. In the second half of 2010, additional foreign exchange gains were incurred on the translation of monetary items as the Canadian dollar continued to strengthen relative to the US dollar.

Derivative Instruments

In 2011, the unrealized gain on derivative instruments was less than in the prior year. An unrealized gain on the Convertible Debentures totaled $7.8 million and a combination of the expiry and revaluation of the Company’s Purchase Warrants resulted in a gain of $4.1 million. Additionally, a gain of $1.2 million was recognized on the revaluation of the convertible portion of the Cdn$40.0 million convertible promissory note issued to Talisman (“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 $0.2 million in the current year.

The $18.6 million unrealized gain recorded in 2010 stemmed from a $15.0 million and $3.6 million gain, respectively, on the revaluation of the Purchase Warrants and Convertible Note.

Gain on Derecognition of Long Term Provision

As part of a 2005 merger agreement, the Company assumed a $1.9 million contingent obligation. In the third quarter of 2011, the Company determined, based on recent events and clarification of contract terms, that satisfaction of the specific contractual contingencies was unlikely and the liability was derecognized.

Provision for Income Taxes

Current taxes increased due to higher oil revenue in 2011 than in the comparable period. Ivanhoe incurred a future tax recovery of $3.4 million in 2011 due to capital spending in China and continued operating loss carryforwards in the US.

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LIQUIDITY AND CAPITAL RESOURCES

Contractual Obligations and Commitments

The following information about our 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 are cancelable with a 30 day notification period.

	Total		2012		2013		2014		2015		After 2015
Long term debt		72,085		–		–		–		–		72,085
Interest on long term debt		18,647		4,145		4,145		4,145		4,145		2,067
Short term debt and interest		10,658		10,658		–		–		–		–
Asset retirement obligations(1)		2,201		–		386		–		–		1,815
Zitong appraisal program		75,510		40,680		31,680		3,150		–		–
Leases		4,508		1,734		1,278		592		402		502
Total		183,609		57,217		37,489		7,887		4,547		76,469

(1)

Represents undiscounted asset retirement obligations after inflation. The discounted value of these estimated obligations ($1.6 million) is provided for in the consolidated 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.

Short Term Debt and Interest

On December 30, 2011, Ivanhoe entered into a loan agreement for $10.0 million with Ivanhoe Capital Finance Ltd. The funds were advanced on January 3, 2012 and incur interest at a rate of 13.3% per annum. The principal balance matures in 180 days or earlier in the case of certain events.

Decommissioning Provisions

The Company is required to remedy the effect of our activities on the environment at our operating sites by dismantling and removing production facilities and remediating any damage caused. At December 31, 2011, Ivanhoe estimated the total undiscounted, inflated cost to settle its asset retirement obligations in Canada, for the FTF in the US and in Ecuador was $2.2 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.

Leases

The Company has long term leases for office space and vehicles, which expire between 2012 and 2017.

Zitong Appraisal Program

The terms of the Supplementary Agreement call for the completion of an appraisal program by the end of June 2014. The work program is expected to consist of a 160 sq. km of 3D seismic survey, as well as drilling and completing three horizontal wells on the Guan and Wen structures.

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 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.

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

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

Sources and Uses of Cash

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

	2011			2010
Net cash used in operating activities		(26,245	)		(31,290	)
Net cash used in investing activities		(85,422	)		(68,684	)
Net cash provided by financing activities		61,423			138,286

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

Cash used in operating activities in the current year 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 for the Company in 2011 totaled $37.4 million. The Yixin-2 and Zitong-1 gas wells at the Company’s Zitong project in China were tested 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. The data was analyzed and will be used in future operations.

In the Nyalga basin of Mongolia, expenditures incurred on the Company’s first exploration well at N16-1E-1A were expensed. The drilling rig was mobilized to a second site, N16-2E-B, and drilling commenced in the middle of September where oil staining, fluorescence and increases in background gas were observed.

In Canada, regulators have completed their initial review of the Company’s application 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. The Company submitted supplemental information to the regulators in the fourth quarter of 2011.

In Ecuador, the Company completed a 190-kilometre 2-D seismic survey of Block 20. The seismic data will assist in the selection of future drilling locations.

In comparison, Ivanhoe spent $65.3 million on E&E capital expenditure in 2010. The Company successfully drilled two wells, Yixin-2 and Zitong-1, to total depth. Ivanhoe completed its winter delineation drilling program at Tamarack in early 2010 and, in November 2010, submitted its regulatory application to the Government of Alberta. Two appraisal wells were drilled in 2010 on Block 20 in Ecuador. The first appraisal well, IP-15, encountered certain cementing and completion problems prior to steam injection operations and testing was suspended without recovering oil. The second appraisal well, IP-5b, was successfully drilled, cored and logged.

Property, Plant and Equipment Expenditures

In 2011, property, plant and equipment (“PP&E”) additions totaled $13.7 million. At Dagang, four wells were drilled and completed. A well drilled in 2010 was also completed in early 2011. The fracture stimulation program at Dagang continued throughout the year.

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In 2010, $5.6 million of PP&E additions were incurred as the Company conducted five fracture stimulations at the Dagang field during the year.

Restricted Cash

Ivanhoe was required to post a $20.0 million performance bond as part of the completion and signing of the Supplementary Agreement with CNPC in December 2011.

Financing Activities

Cash provided by financing activities was lower in 2011 than in the prior year. 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 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 2010.

Capital Structure

As at December 31,	2011		2010
Debt		–		39,832
Long term debt		61,892		–
Shareholders’ equity		314,137		300,484

Ivanhoe intends to use its cash and cash equivalent balance to fulfill its commitments and partially fund operations in 2012. 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. 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, and through the sale of interests in existing oil and gas properties. 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.

CRITICAL ACCOUNTING PRINCIPLES AND ESTIMATES

The Financial Statements have been prepared in accordance with IFRS as issued by the IASB. The Financial Statements are not subject to qualification relating to the application of IFRS as issued by the IASB.

A detailed summary of the Company’s significant accounting policies is included in Note 3 to the Financial Statements. Some of these policies involve critical accounting estimates as they require the Company to make particularly subjective or complex judgments about matters that are inherently uncertain and because of the likelihood that materially different amounts could be reported under different conditions or using different assumptions. The following section discusses critical accounting estimates and assumptions and how they affect the amounts reported in the Company’s Financial Statements.

Intangible E&E Assets

Management must determine if intangible E&E assets, which have not yet resulted in the discovery of proved reserves, should continue to be capitalized or charged to E&E expense. When making this determination, Ivanhoe considers factors such as the Company’s drilling results, planned exploration and development activities, the financial capacity of the Company to further develop the property, the ability to use the Company’s HTL™ technology in certain projects, lease expiries, market conditions and technical recommendations from its exploration staff.

Although the Company believes its estimates are reasonable and consistent with current conditions, internal planning and expected future operations, such estimates are subject to significant uncertainties and judgments. Ivanhoe cannot predict if an event that triggers impairment will occur, when it will occur or how it will affect the reported asset amounts.

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Impairment

Property, Plant and Equipment

The Company periodically assesses its oil and gas assets, or groups of assets, for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable. Among other things, an impairment may be triggered by falling oil and gas prices, a significant negative revision to reserve estimates, the inability to use the Company’s HTL™ technology in certain projects, changes in capital costs or the inability to raise sufficient financial resources to further develop the property.

Cash flow estimates for the Company’s impairment assessments require significant assumptions about future prices and costs, production, reserves volumes and discount rates, as well as potential benefits from the application of its HTL™ technology. Given the significant assumptions required and the likelihood that actual conditions will differ, the assessment of impairment is considered to be a critical accounting estimate.

It is difficult to determine and assess how a change in future costs, production, reserves volumes, or the application of HTL™ technology could impact Ivanhoe’s impairment tests. A 1% increase in the discount rate and a 5% decrease in the forward pricing used in the calculation of cash flows from proved plus probable reserves as at December 31, 2011, would not impair the Company’s development project.

Intangible Technology Assets

The Company’s intangible technology assets consist of an exclusive, irrevocable license to deploy its HTL™ technology. Ivanhoe annually reviews the technology assets for impairment or if an adverse event or change occurs. Indicators of adverse events could include HTL™ patent expiries, advancements of new technologies or the inability to successfully commercialize the HTL™ technology. The intangible asset impairment is a critical accounting estimate because it requires Ivanhoe to make assumptions about competitive technological developments, the successful commercialization of its HTL™ technology and future cash flows from the HTL™ technology.

Ivanhoe cannot predict if an event that triggers impairment will occur, when it will occur or how it will affect the reported asset amounts. Although the Company believes its estimates are reasonable and consistent with current conditions, internal planning and expected future operations, such estimates are subject to significant uncertainties and judgments.

Oil and Gas Reserves

The process of estimating quantities of reserves is inherently uncertain and complex. It requires significant judgments and decisions based on available geological, geophysical, engineering and economic data. These estimates may change substantially as additional data from ongoing development activities and production becomes available and as economic conditions impacting oil and gas prices and costs change. Such revisions could be upwards or downwards. For details on our reserve estimation process, refer to the section titled “Reserves, Production and Related Information” in Items 1 and 2 of this Annual Report.

Reserve estimates have a material impact on depletion and the Company’s impairment evaluations, which in turn have a material impact on earnings. Total proved and probable reserves estimates are used to determine rates used in the unit-of-production depletion calculations. In the year ended December 31, 2011, depletion expense of $6.9 million was recorded. If proved and probable reserves estimates changed by 10%, the Company’s depletion and depreciation expense would have changed by approximately $0.7 million, assuming all other variables remained constant.

Option Pricing Model

The Company uses the Black-Scholes option pricing model to measure the fair value of stock options and equity settled Restricted Share Units (“RSUs”) on the date of grant. Determining the fair value of stock-based awards on the grant date requires judgment, including estimating the expected life of the award, the expected volatility of the Company’s common shares and expected dividends. In addition, judgment is required to estimate the number of awards that are expected to be forfeited. Changes in assumptions can materially affect the estimated fair value, and therefore, the existing models do not necessarily provide precise measures of fair value.

Convertible Debentures

On June 9, 2011, the Company issued Cdn$73.3 million of Convertible Debentures. The Canadian dollar denominated debt is considered to contain an embedded derivative since the functional currency of the Company is the US dollar. As a result, the Convertible Debentures were bifurcated into debt and the convertible option, which was recognized at fair value using the Black-Scholes valuation method. Changes in the fair value of the convertible option are recorded in earnings; therefore the valuation of the convertible option is a critical accounting estimate.

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The Black-Scholes valuation method requires the input of highly subjective assumptions regarding expected volatility of the Company’s share price and the risk-free interest rate. If the volatility used to fair value the convertible component at December 31, 2011 decreased by 10%, the fair value of the convertible option would decrease by $1.1 million. If volatility increased by 10%, the fair value of the convertible option would increase by $1.6 million.

Convertible Note

In connection with the acquisition of the Tamarack leases in July 2008 from Talisman, the Company issued a Cdn$40.0 million Convertible Note. The Canadian dollar denominated debt was considered to contain an embedded derivative since the functional currency of the Company is the US dollar. As a result, the Convertible Note was bifurcated into debt and the convertible option, which was recognized at fair value using the Black-Scholes valuation method. Changes in the fair value of the convertible option were recorded in earnings, and as a result, the valuation of the convertible option was a critical accounting estimate prior to the maturity of the Convertible Note on July 11, 2011.

Deferred Income Taxes

Ivanhoe operates in a specialized industry and in several tax jurisdictions. As a result, the Company’s income is subject to various rates of taxation. The breadth of the Company’s operations and the global complexity of tax regulations require assessments of uncertainties and judgments in estimating the taxes that the Company will ultimately pay. The final taxes paid are dependent upon many factors, including negotiations with taxation authorities in various jurisdictions, uncertain tax positions and resolution of disputes arising from federal, provincial, state and local tax audits.

The deferred income tax liability is a critical accounting estimate because it requires Ivanhoe to make assumptions about the resolution of these uncertainties and the associated final taxes may result in adjustments to the Company’s tax assets and tax liabilities.

NEW ACCOUNTING PRONOUNCEMENTS

Transition to International Financial Reporting Standards

Effective January 1, 2011, Ivanhoe adopted IFRS, as issued by the IASB, as the Company’s basis for accounting. Most adjustments required on transition to IFRS were made retrospectively against opening retained earnings as of the date of the first comparative statement of financial position. Transitional adjustments relating to those standards where comparative ﬁgures are not required to be restated will only be made as of the ﬁrst day of the year of adoption.

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First-time Adoption of International Financial Reporting Standards

“First-Time Adoption of International Financial Reporting Standards” (“IFRS 1”) provides companies adopting IFRS for the ﬁrst time with a number of optional exemptions and mandatory exceptions to the general requirement for full retrospective application of IFRS where retrospective restatement would either be onerous or would not provide more useful information. As a result of relying upon the exemptions described below, there was no material impact in these areas at the date of transition to IFRS.

Area of IFRS		Summary of Exemption Available
Property, plant and equipment		Companies may elect to report property, plant and equipment from oil and gas operations on the opening statement of financial position on the transition date at a deemed cost, instead of the actual cost, as though IFRS had been adopted retroactively. The deemed cost of an item may be either its fair value at the date of transition to IFRS or an amount reported under Canadian GAAP. The exemption can be applied on an asset-by-asset basis. Ivanhoe elected to report property, plant and equipment from oil and gas operations in its opening statement of financial position on the transition date at the deemed cost previously calculated under Canadian GAAP.
Decommissioning liabilities		In accounting for changes in decommissioning liabilities, IFRS requires changes in such obligations to be added to, or deducted from, the cost of the asset to which they relate. The adjusted depreciable amount of the asset is then depreciated prospectively over its remaining useful life. Rather than recalculating the effect of all such changes throughout the life of the obligation, companies may elect to measure the liability and the related depreciation effects at the date of transition to IFRS. Ivanhoe elected to measure only those decommissioning liabilities outstanding from the FTF on the date of transition to IFRS.
Stock-based compensation		Companies may elect not to apply IFRS 2, “Share-Based Payment,” to stock options granted on or before November 7, 2002, or which vested before the date of transition to IFRS. Ivanhoe elected to utilize this exemption for the all stock options awarded after November 7, 2002, that vested before January 1, 2010.
Business combinations		Companies may elect to either restate all past business combinations in accordance with IFRS 3, “Business Combinations,” or to apply an elective exemption from applying IFRS 3 to past business combinations. Ivanhoe elected to utilize this exemption and transactions entered into prior to the transition date will not be restated.

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Areas of Signiﬁcance

IFRS had a significant impact on the Company’s ongoing accounting in the areas described below, in addition to the impact of transition policy choices made under IFRS 1.

Accounting Policy Area		Impact of Policy Adoption
Exploration and evaluation assets		The Company followed the full cost method of accounting for its oil and gas operations under Canadian (“Cdn”) GAAP, whereby all costs related to the exploration for, and development of, oil and gas reserves were capitalized and periodically evaluated for impairment. Under IFRS, exploration costs will initially be capitalized as E&E assets until it can be determined if sufficient quantities of reserves have been found to justify commercial production. If commercial quantities of reserves are found, E&E assets will be reclassified to oil and gas properties and development costs and, if not, E&E assets will be expensed on the consolidated statement of loss. Costs incurred in connection with our projects in Canada, Ecuador, Mongolia and exploration projects in China were reclassified as E&E assets, while producing assets in China continued to be classified as oil and gas properties and development costs on the consolidated statement of financial position.
Impairments		Cdn GAAP generally used a two-step approach to impairment testing: ﬁrst comparing asset carrying values with undiscounted future cash ﬂows to determine whether impairment exists and then measuring any impairment by comparing asset carrying values with fair values calculated using discounted cash flows. International Accounting Standard 36, “Impairment of Assets,” uses a one-step approach for both testing and measuring of impairment, with asset carrying values compared directly with the higher of fair value less costs to sell and value in use (which uses discounted future cash ﬂows). This may potentially result in more write downs where carrying values of assets were previously supported under Cdn GAAP on an undiscounted cash ﬂow basis, but could not be supported on a discounted cash ﬂow basis. IFRS also requires the reversal of any previous impairment losses where circumstances have changed such that impairments have been reduced. Cdn GAAP prohibited the reversal of impairment losses. IFRS will result in greater variability in our operating results and asset carrying values.
Capitalized G&A		G&A directly related to exploration and development activities was capitalized as oil and gas properties and development costs under Cdn GAAP. The threshold to capitalize G&A is higher under IFRS; therefore, less G&A will be capitalized in the future and G&A on the consolidated statement of loss will be higher as a result.
Financial instruments		Under Cdn GAAP, the equity component of the Company’s Convertible Note and the common share 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 our functional currency are accounted for as derivatives. Since our Convertible Note and common share purchase warrants are denominated in Cdn dollars and our functional currency is US dollars, these items were reclassified from shareholders’ equity to liabilities under IFRS. Additionally, IFRS requires derivative instruments to be recorded at fair value with changes in their fair value recognized in the consolidated statement of loss. This will create variability in our results of operations and the carrying value of liabilities.
Stock-based compensation		Stock options were accounted for using the fair value method under Cdn GAAP. The fair value was determined using the Black- Scholes option pricing model and recorded as compensation expense on a straight-line basis over the period that the stock options vested. Under IFRS 2, “Share-Based Payment,” compensation expense will be charged to earnings on a graded vesting basis. This will accelerate the compensation expense recognized on the consolidated statement of loss in comparison to Cdn GAAP.

New Accounting Pronouncements

The information contained in Note 3.18, Standards and Interpretations Issued But Not Yet Adopted, to our Financial Statements in Part II, Item 8 is incorporated by reference into this Part II, Item 7.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements that would have a material adverse effect on our liquidity, consolidated financial position or results of operations.

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ITEM 7A: QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed in varying degrees to normal market risks inherent in the oil and gas industry, including commodity price risk, foreign currency exchange rate risk, credit risk and liquidity risk. We recognize these risks and manage our operations to minimize our exposures to the extent practicable.

COMMODITY PRICE RISK

Commodity price risk related to oil prices is one of Ivanhoe’s most significant market risk exposures. The Company’s operating results and financial condition are influenced by the prices the Company receives for its oil production. Oil prices may fluctuate widely in response to a variety of factors including global and domestic economic conditions, weather conditions, political stability, transportation facilities, the price and availability of alternative fuels and government regulations.

Based on estimated 2012 production, a US$1.00/bbl change in the price of oil would increase or decrease net income and cash flows from operations for 2012 by US$0.82/bbl. In the past, Ivanhoe has used derivatives to minimize variability in the Company’s cash flow from operations when required to do so by loan covenants. However, no hedging contracts were in place in 2011 and the Company does not anticipate using hedging contracts in 2012 to manage its commodity price risk.

FOREIGN CURRENCY EXCHANGE RATE RISK

Ivanhoe is exposed to foreign currency exchange rate risk as a result of incurring capital expenditures and operating costs in currencies other than the US dollar. A substantial portion of our activities are transacted in or referenced to US dollars, including oil sales in Asia, capital spending in Ecuador and ongoing FTF operations. A portion of our transactions are in other currencies, such as Dagang operating costs paid in Chinese renminbi, Tamarack exploration activities funded in Cdn dollars and the Cdn dollar Convertible Debentures issued in 2011. The Company did not enter into any foreign currency derivatives in 2011, nor do we anticipate using foreign currency derivatives in 2012. To help reduce the Company’s exposure to foreign currency exchange rate risk, it seeks to hold assets and liabilities denominated in the same currency when appropriate.

The following table shows the Company’s exposure to foreign currency exchange rate risk on its net loss and comprehensive loss for 2011, assuming reasonably possible changes in the relevant foreign currency. This analysis assumes all other variables remain constant.

(Increase) Decrease in Net Loss and Comprehensive Loss	10% Increase or Weakening		10% Decrease or Strengthening
Chinese renminbi		1,953		(2,387	)
Canadian dollar		3,685		(3,711	)

CREDIT RISK

Ivanhoe is exposed to credit risk with respect to its cash and cash equivalents, restricted cash, accounts receivable, note receivable and long term receivables. The Company’s maximum exposure to credit risk at December 31, 2011, is represented by the carrying amount of these non-derivative financial assets. Most of the Company’s credit exposures are with counterparties in the energy industry and are therefore exposed to normal industry credit risks. Ivanhoe manages its credit risk by only entering into sales contracts with established entities.

The Company believes its exposure to credit risk related to cash and cash equivalents, as well as restricted cash, is minimal due to the quality of the financial institutions where the funds are held and the nature of the deposit instruments.

Currently, all of the Company’s oil production is sold to one national oil corporation. As a result, 96% of the outstanding accounts receivable balance at December 31, 2011 (December 31, 2010 – 85%) is due from a national oil corporation. Long term value-added tax receivable from the Ecuadorian government will be recoverable upon commencement of commercial operations. Ivanhoe considers the risk of default on these items to be low due to the Company’s ongoing operations in China and Ecuador.

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LIQUIDITY RISK

Liquidity risk is the risk that suitable sources of funding for the Company’s business activities may not be available. Since cash flows from existing operations are insufficient to fund future capital expenditures, we intend to finance future capital projects with a combination of strategic investors and/or public and private debt and equity markets, either at the parent company level or at the project level or from the sale of existing assets. There is no assurance that we will be able to obtain such financing or obtain it on favorable terms.

NON-IFRS FINANCIAL MEASURES

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

ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Report of Independent Registered Chartered Accountants	35
Consolidated Financial Statements
Consolidated Statements of Financial Position	36
Consolidated Statements of Loss and Comprehensive Loss	37
Consolidated Statements of Changes in Equity	38
Consolidated Statements of Cash Flows	39
Notes to the Consolidated Financial Statements	40
Supplementary Disclosures About Oil and Gas Production Activities (Unaudited)	71

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REPORT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS

To the Board of Directors and Shareholders of Ivanhoe Energy Inc.,

We have audited the accompanying consolidated financial statements of Ivanhoe Energy Inc. and subsidiaries (the “Company”), which comprise the consolidated statements of financial position as at December 31, 2011, December 31, 2010 and January 1, 2010, and the consolidated statements of loss and comprehensive loss, statements of changes in equity, and statements of cash flows for the years ended December 31, 2011 and December 31, 2010, and the notes to the consolidated financial statements.

Management’s Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditor’s Responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Ivanhoe Energy Inc. and subsidiaries as at December 31, 2011, December 31, 2010 and January 1, 2010 and their financial performance and cash flows for the years ended December 31, 2011 and December 31, 2010 in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board.

Emphasis of Matter

Without qualifying our opinion, we draw attention to Note 1 in the consolidated financial statements which indicates that as of December 31, 2011, the Company had an accumulated deficit of $298.5 million, and working capital of $30.7 million, excluding assets held for sale and derivative financial liabilities, and during the year ended December 31, 2011, cash used in operating activities was $26.2 million and the Company expects to incur further losses in the development of its business. These conditions, along with other matters as set forth in Note 1, indicate the existence of a material uncertainty that casts substantial doubt about the Company’s ability to continue as a going concern.

Other Matter

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 15, 2012 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ Deloitte & Touche LLP
Independent Registered Chartered Accountants

March 15, 2012

Calgary, Canada

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PART I FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

IVANHOE ENERGY INC.

Consolidated Statements of Financial Position

			December 31,			December 31,			January 1,
(US$000s)	Note		2011			2010			2010

Assets
Current Assets
Cash and cash equivalents		5		16,890			68,317			24,362
Restricted cash		6		20,500			–			–
Accounts receivable		11		7,859			6,359			5,021
Note receivable				227			264			225
Prepaid and other				1,411			2,859			771
Assets held for sale		7		41,902			–			–
				88,789			77,799			30,379

Intangible		8		273,986			273,568			207,750
Property, plant and equipment		9		46,979			40,618			41,983
Long term receivables		11		3,956			2,433			839
				413,710			394,418			280,951

Liabilities and Shareholders’ Equity
Current Liabilities
Accounts payable and accrued liabilities				15,548			21,482			10,779
Debt		10		–			39,832			–
Derivative instruments		11, 12		183			8,447			13,023
Income taxes		14		641			–			530
Decommissioning costs				–			–			753
				16,372			69,761			25,085

Long term debt		10		61,892			–			36,934
Long term derivative instruments		11, 12		1,617			–			–
Long term provisions		13		1,919			3,008			2,187
Deferred income taxes		14		17,773			21,165			22,336
				99,573			93,934			86,542

Shareholders’ Equity
Share capital		16		586,108			550,562			422,322
Contributed surplus		16		26,524			23,141			18,724
Accumulated deficit				(298,495	)		(273,219	)		(246,637	)
				314,137			300,484			194,409
				413,710			394,418			280,951

Nature of operations and going concern			1

(See accompanying Notes to the Consolidated Financial Statements)

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IVANHOE ENERGY INC.

Consolidated Statements of Loss and Comprehensive Loss

			Year Ended December 31,
(US$000s, except share and per share amounts)	Note		2011			2010

Revenue
Oil				37,403			21,720
Interest				576			208
				37,979			21,928

Expenses and other
Operating		21		20,131			13,625
Exploration and evaluation		8		2,774			8,471
General and administrative				48,449			42,807
Depletion and depreciation		9		8,030			6,524
Foreign currency exchange gain				(355	)		(3,325	)
Derivative instruments gain		11		(12,965	)		(18,571	)
Interest				361			24
Gain on derecognition of long term provision		13		(1,900	)		–
				64,525			49,555

Loss before income taxes				(26,546	)		(27,627	)

(Provision for) recovery of income taxes
Current		14		(2,122	)		(126	)
Deferred		14		3,392			1,171
				1,270			1,045

Net loss and comprehensive loss				(25,276	)		(26,582	)

Net loss per common share, basic and diluted				(0.07	)		(0.08	)

Weighted average number of common shares
Basic and diluted (000s)				342,678			327,442

(See accompanying Notes to the Consolidated Financial Statements)

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IVANHOE ENERGY INC.

Consolidated Statements of Changes in Equity

			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				–		–		–			(26,582	)		(26,582	)
Shares issued for cash, net of share issue costs		16		50,000		121,697		–			–			121,697
Shares issued for services				280		799		–			–			799
Exercise of stock options		17		1,524		5,735		(3,940	)		–			1,795
Exercise of purchase warrants				2		9		–			–			9
Share-based compensation expense		17		–		–		8,357			–			8,357
Balance December 31, 2010				334,365		550,562		23,141			(273,219	)		300,484


			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				–		–		–			(25,276	)		(25,276	)
Shares issued for services				169		335		–			–			335
Exercise of stock options		17		985		4,164		(2,231	)		–			1,933
Exercise of purchase warrants		16		8,620		31,047		–			–			31,047
Share-based compensation expense		17		–		–		5,614			–			5,614
Balance December 31, 2011				344,139		586,108		26,524			(298,495	)		314,137
(See accompanying Notes to the Consolidated Financial Statements)

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IVANHOE ENERGY INC.

Consolidated Statements of Cash Flows

			Year Ended December 31,
(US$000s)	Note		2011			2010

Operating Activities
Net loss				(25,276	)		(26,582	)
Adjustments to reconcile net loss to cash from operating activities
Depletion and depreciation		9		8,030			6,524
Exploration and evaluation expense		8		–			3,537
Share-based compensation expense		17		5,883			7,557
Unrealized foreign currency exchange gain				(446	)		(3,523	)
Unrealized derivative instruments gain		11		(12,965	)		(18,571	)
Current income tax expense		14		2,122			126
Deferred income tax recovery		14		(3,392	)		(1,171	)
Interest expense				361			24
Finance costs				269			–
Gain on derecognition of long term provision		13		(1,900	)		–
Other				50			(38	)
Current income tax paid				(1,481	)		(656	)
Interest paid				(333	)		–
Decommissioning costs settled				–			(179	)
Changes in non-cash working capital items		22		2,833			1,662
Net cash used in operating activities				(26,245	)		(31,290	)

Investing Activities
Intangible expenditures				(37,390	)		(65,347	)
Property, plant and equipment expenditures				(13,670	)		(5,633	)
Restricted cash				(20,500	)		–
Long term receivables				(1,536	)		(1,558	)
Interest paid				(4,011	)		(1,610	)
Changes in non-cash working capital items		22		(8,315	)		5,464
Net cash used in investing activities				(85,422	)		(68,684	)

Financing Activities
Shares and warrants issued on private placements, net of share issue costs		16		–			135,696
Convertible debentures issued, net of issue costs		10		72,914			–
Repayment of convertible note		10		(41,421	)		–
Proceeds from exercise of options and warrants		12, 17		29,873			2,600
Changes in non-cash working capital items		22		57			(10	)
Net cash provided by financing activities				61,423			138,286

Foreign exchange gain (loss) on cash and cash equivalents held in a foreign currency				(1,183	)		5,643
Increase (decrease) in cash and cash equivalents, for the year				(51,427	)		43,955
Cash and cash equivalents, beginning of year				68,317			24,362
Cash and cash equivalents, end of year				16,890			68,317
(See accompanying Notes to the Consolidated Financial Statements)

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IVANHOE ENERGY INC.

Notes to the 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, Canada, 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™ technology, that are designed to 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 December 31, 2011 audited consolidated 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 December 31, 2011, Ivanhoe had an accumulated deficit of $298.5 million and working capital of $30.7 million, excluding assets held for sale and derivative financial liabilities. In the year ended December 31, 2011, cash used in operating activities was $26.2 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, and through the sale of interests in existing oil and gas properties. There is no assurance that the Company 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 material uncertainty that casts substantial doubt that the Company will be able to continue as a going concern.

The December 31, 2011 Financial Statements were approved by the Board of Directors and authorized for issue on March 1, 2012.

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 IFRS as issued by the International Accounting Standards Board (“IASB”). 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 27.

The Financial Statements have been prepared on an historical cost basis, except derivative instruments, which are measured at fair value as explained in accounting policies set out in Note 3.

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3. SIGNIFICANT ACCOUNTING POLICIES

3.1 Basis of Consolidation

The Financial Statements incorporate the financial statements of the Company, its subsidiaries, all of which are wholly owned, and special purpose entities that are controlled by the Company. All intercompany balances, transactions, revenue and expenses are eliminated on consolidation. The consolidated accounts are prepared using uniform accounting policies.

Certain of the Company’s exploration and development activities are conducted jointly with others through jointly controlled operations. The Financial Statements reflect only the Company’s proportionate interest in such activities.

3.2 Foreign Currency Translation

The Company and its subsidiaries’ reporting currency and the functional currency of its operations is the US dollar as this is the principal currency of the economic environments in which they operate.

Monetary assets and liabilities denominated in foreign currencies are translated at the exchange rate in effect on the date of the statement of financial position. Non-monetary assets and liabilities, as well as operating transactions, are translated at the exchange rate prevailing at the time of the transaction. Translation gains and losses are reflected in earnings.

3.3 Cash and Cash Equivalents

Cash and cash equivalents includes cash on hand, deposits at banks, restricted cash and short term highly liquid investments with original maturities of three months or less.

3.4 Restricted Cash

Restricted cash balances that are not expected to be released within three months or less are reported separately from restricted cash balances included in cash and cash equivalents.

3.5 Intangible Assets

i. Exploration and Evaluation Assets

Costs of exploring for, and evaluating, oil and gas properties are initially capitalized as intangible exploration and evaluation assets (“E&E assets”). Costs may include license fees, technical studies, seismic programs, exploratory drilling and directly attributable general and administrative costs. Interest on borrowings incurred to finance qualifying E&E assets is capitalized.

If E&E assets result in sufficient proved reserves to justify commercial production and technical feasibility can be established, the assets will be tested for impairment and reclassified as property, plant and equipment (“PP&E”). If E&E assets result in sufficient reserves to justify commercial production, but those reserves cannot be classified as proved, the assets will be tested for impairment and continue to be capitalized as intangible assets as long as progress is being made to assess the reserves and economic viability of the well and/or related project. If sufficient reserves cannot be established, the corresponding E&E assets are charged to exploration and evaluation expense (“E&E expense”).

E&E assets which may be attributable to a broad exploration area, such as license fees, technical studies or seismic programs, will be reclassified to PP&E or charged to E&E expense to best reflect the nature of the assets. Costs incurred prior to establishing the legal right to explore an area are charged to E&E expense as incurred.

ii. Technology Assets

The Company’s HTL™ technology license (“Technology Assets”) consist of an exclusive, irrevocable license to deploy its HTL™ technology. Technology Assets are measured at cost and classified as an intangible asset. Amortization of the Technology Assets will commence when the technology is available for use in field operations.

iii. Derecognition

An intangible asset is derecognized on disposal or when no future economic benefits are expected from use or disposal. Gains or losses arising from derecognition are measured as the difference between the net disposal proceeds and the carrying amount of the asset and are recognized in profit or loss when the intangible asset is derecognized.

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3.6 Property, Plant and Equipment

i. Oil and Gas Property and Equipment

PP&E is reported at cost less accumulated depletion, depreciation and accumulated impairment losses. PP&E may include the purchase price, reclassified E&E assets, any costs directly attributable to bringing the asset to the location and condition necessary for its intended use and decommissioning costs. Interest on borrowings incurred to finance qualifying PP&E is capitalized until the asset is capable of fulfilling its intended use.

PP&E is depleted using the unit-of-production method based on proved plus probable reserves, taking into account associated future development costs. For purposes of these calculations, production and reserves of natural gas are converted to barrels on an energy equivalent basis at a ratio of six thousand cubic feet of natural gas for one barrel of oil. Depletion rates are updated annually unless there is a material change in circumstances, in which case they would be updated more frequently.

ii. Other Assets

Furniture and equipment are depreciated on a straight-line basis over the estimated useful life of the respective assets, ranging from three to five years. The Feedstock Test Facility (“FTF”) is depreciated over its expected economic life of 20 years.

3.7 Assets Held for Sale

Non-current assets are classified as held for sale if their carrying amounts will be recovered through a sale transaction rather than through continuing use. This classification is required when the sale is highly probable and the asset is available for immediate sale in its present condition. For the sale to be highly probable, management must be committed to a plan to sell the asset, the asset must be actively marketed for sale at a price that is reasonable in relation to its fair value and the sale is expected to be completed within one year.

Non-current assets classified as held for sale are measured at the lower of the carrying amount and fair value less costs to sell, with impairments recognized in the consolidated statement of loss in the period measured. Non-current assets held for sale are presented in current assets within the consolidated statement of financial position. Assets held for sale are not depleted, depreciated or amortized.

3.8 Impairment

The Company periodically assesses tangible and intangible assets or groups of assets for impairment annually or earlier whenever events or changes in circumstances indicate the carrying value of an asset may not be recoverable. Individual assets are grouped into cash generating units for impairment purposes at the lowest level at which there are identifiable cash inflows that are largely independent of the cash inflows of other groups of assets.

If indicators of impairment exist, the recoverable amount of the asset group is estimated. An asset group’s recoverable amount is the higher of its fair value less costs to sell and its value in use. In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and risks specific to the asset. Where the carrying amount of an asset group exceeds its recoverable amount, the asset group is considered impaired and is written down to its recoverable amount.

Previously recognized impairment losses are reversed if there has been a change in the estimates used to determine the asset group’s recoverable amount. If that is the case, the carrying amount of the asset group is increased to its revised recoverable amount which cannot exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognized in prior periods. Such a reversal is recognized in earnings. Subsequent to a reversal of impairment, the depletion or depreciation expense is adjusted in future periods to allocate the asset group’s revised carrying amount, less any residual value, over its remaining useful life.

3.9 Decommissioning Provision

The Company recognizes a provision for decommissioning costs when it has an obligation to dismantle and remove its PP&E or restore the site on which it is located. The provision is estimated as the present value of the expected future expenditures, determined in accordance with local conditions and requirements, discounted at a risk-free rate. A corresponding amount is added to the carrying value of the related asset and is amortized as an expense over the economic life of the asset. The

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carrying amount of the provision is increased for the passage of time and adjusted for changes to the current market-based discount rate, amount and/or timing of the underlying cash flows needed to settle the obligation. Actual decommissioning costs incurred reduce the obligation. Any difference between the recorded decommissioning provision and the actual costs incurred is recorded as a gain or loss in the settlement period.

3.10 Provisions and Contingencies

Provisions are recognized when the Company has a present obligation (legal or constructive) that has arisen as a result of a past event and it is probable that a future outflow of resources will be required to settle the obligation, provided that a reliable estimate can be made of the amount of the obligation.

Provisions are measured at the present value of the expenditures expected to be required to settle the obligation using a pre-tax rate that reflects current market assessments of the time value of money and the risks specific to the obligation. When it is appropriate to discount a provision, the increase in the provision due to passage of time is recognized as interest expense.

3.11 Financial Assets

Financial assets are classified as i) loans and receivables, ii) available-for-sale, iii) financial assets at fair value through profit or loss, or iv) as held-to-maturity. Ivanhoe determines the classification of its financial assets upon initial recognition. Financial assets are recognized initially at fair value and subsequent measurement depends upon their classification.

i. Loans and Receivables

Loans and receivables are non-derivative financial assets, with fixed or determinable payments, that are not quoted in an active market. Such assets are carried at amortized cost using the effective interest method if the time value of money is significant. Gains and losses are recognized in income when the loans and receivables are derecognized or impaired, as well as through the amortization process. The Company’s cash and cash equivalents, restricted cash, accounts receivable, note receivable and long term receivables are classified as loans and receivables.

ii. Available-for-Sale

Available-for-sale financial assets are measured at fair value, with gains or losses recognized within other comprehensive income. Accumulated changes in fair value are recorded as a separate component of equity until the investment is derecognized or impaired. The Company does not currently have any financial assets classified as available‐for‐sale.

iii. Financial Assets at Fair Value Through Profit or Loss

Financial assets are classified as fair value through profit or loss (“FVTPL”) when the financial asset is held for trading or it is designated as FVTPL. Financial assets classified as FVTPL are measured at fair value with unrealized gains and losses recognized through earnings. The Company currently does not have any financial assets classified at FVTPL.

iv. Held-to-Maturity

Held-to-maturity investments are non-derivative financial assets with fixed or determinable payments and fixed maturity dates that the Company has the intent and ability to hold to maturity. These investments are recognized on a trade date basis and are subsequently measured at amortized cost using the effective interest method. The Company does not currently have any financial assets classified as held-to-maturity.

v. Impairment

Financial assets, other than those at FVTPL, are assessed for indicators of impairment annually. Financial assets are impaired when there is evidence that the estimated future cash flows of the investment have been impacted. For financial assets carried at amortized cost, the amount of the impairment is the difference between the asset’s carrying amount and the present value of the estimated future cash flows, discounted at the financial asset’s original effective interest rate.

The carrying amount of all financial assets, excluding accounts receivables, is directly reduced by the impairment loss. The carrying amount of accounts receivable is reduced through the use of an allowance account. Subsequent recoveries of amounts previously written off are recorded against the allowance account. Changes in the carrying amount of the allowance account are recognized in earnings.

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With the exception of available-for-sale equity instruments, which are revalued through other comprehensive income, if, in a subsequent period, the amount of the impairment loss decreases and the decrease relates to an event occurring after the impairment was recognized, the previously recognized impairment loss is reversed through earnings. On the date of the impairment reversal, the carrying amount of the financial asset cannot exceed its amortized cost had it not been impaired.

vi. Derecognition

Financial assets are derecognized when the rights to receive cash flows from the investments have expired, or have been transferred, and the Company has transferred substantially all risks and rewards of ownership.

3.12 Financial Liabilities

Financial liabilities are classified as i) financial liabilities at FVTPL or ii) as other financial liabilities measured at amortized cost. Ivanhoe determines the classification of its financial liabilities upon initial recognition. The measurement of financial liabilities depends on their classification.

i. Financial Liabilities at Fair Value Through Profit or Loss

Financial liabilities classified as FVTPL include financial liabilities held for trading and financial liabilities designated upon initial recognition as FVTPL. Derivatives, including bifurcated embedded derivatives, are also classified as FVTPL. Changes in the fair value of financial liabilities classified as FVTPL are recognized through earnings. The Company’s derivative instruments are classified as financial liabilities at FVTPL.

ii. Other Financial Liabilities

Financial liabilities classified as other financial liabilities are initially recognized at fair value less directly attributable transaction costs. After initial recognition, other financial liabilities are measured at amortized cost using the effective interest method. The Company’s accounts payable and accrued liabilities, debt, long term obligation and long term accrued liabilities are classified as other financial liabilities.

3.13 Oil and Gas Revenue

Sales of oil and gas production are recognized when the risks and rewards of ownership pass to the buyer, collection is reasonably assured and the price is reasonably determinable. Oil and gas revenue represents the Company’s share and is recorded net of royalty payments to governments and other mineral interest owners.

3.14 Income Tax

Income tax expense represents the sum of tax currently payable and deferred tax.

i. Current income tax

Income tax assets and liabilities are measured at the amount expected to be recovered from, or paid to, the taxation authorities. The tax rates and tax laws used to compute the amount are those that are enacted or substantively enacted by the date of the statement of financial position.

ii. Deferred income tax

Using the liability method, deferred income tax is provided for on taxable and deductible differences between the tax basis of assets and liabilities in comparison to their carrying amounts for financial reporting purposes.

Deferred income tax liabilities are recognized for all taxable temporary differences, except:

—

where the deferred income tax liability arises from the initial recognition of goodwill or of an asset or liability in a transaction that is not a business combination and, at the time of the transaction, affects neither accounting profit nor taxable profit or loss; and

—

in respect of taxable temporary differences associated with investments in subsidiaries, jointly controlled entities and associates, where the timing of the reversal of the temporary differences can be controlled and it is probable that the temporary differences will not reverse in the foreseeable future.

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Deferred income tax assets are recognized for all deductible temporary differences, carry-forward of unused tax credits and unused tax losses, to the extent that it is probable that taxable profit will be available against which the deductible temporary differences and the carry-forward of unused tax credits and unused tax losses can be utilized except:

—

where the deferred income tax asset relating to the deductible temporary difference arises from the initial recognition of an asset or liability in a transaction that is not a business combination and, at the time of the transaction, affects neither the accounting profit nor taxable profit or loss; and

—

in respect of deductible temporary differences associated with investments in subsidiaries, jointly controlled entities and associates, deferred tax assets are recognized only to the extent that it is probable that the temporary differences will reverse in the foreseeable future and taxable profit will be available against which the temporary differences can be utilized.

The carrying amount of deferred tax assets is reviewed at each date of the statement of financial position and reduced to the extent that it is no longer probable that sufficient taxable profit will be available to allow all, or part, of the deferred income tax asset to be utilized. Unrecognized deferred income tax assets are reassessed at each date of the statement of financial position and are recognized to the extent that it has become probable that future taxable profit will allow the deferred tax asset to be recovered.

Deferred tax assets and liabilities are measured at the tax rates that are expected to apply to the year when the asset is expected to be realized or the liability is expected to be settled, based on tax rates (and tax laws) that have been enacted or substantively enacted at the date of the statement of financial position.

Deferred income tax relating to items recognized directly in equity is recognized in equity and not in earnings.

Deferred income tax assets and deferred income tax liabilities are offset if, and only if, a legally enforceable right exists to set off current tax assets against current tax liabilities and the deferred tax assets and liabilities relate to income taxes levied by the same taxation authority on either the same taxable entity or different taxable entities which intend to either settle current tax liabilities and assets on a net basis, or to realize the assets and settle the liabilities simultaneously, in each future period in which significant amounts of deferred tax assets or liabilities are expected to be settled or recovered.

3.15 Borrowing Costs

For qualifying assets, which take a substantial period of time to get ready for intended use, interest on borrowings incurred to finance E&E assets and PP&E is capitalized until the asset is capable of fulfilling its intended use. Capitalized borrowing costs cannot exceed the actual interest and financing costs incurred. All other interest and financing costs are recognized in earnings in the period in which they are incurred.

3.16 Share-Based Payments

Equity settled share-based payments in the form of stock options granted to directors, employees and those providing similar services to Ivanhoe and its subsidiaries, are measured at fair value on the grant date and expensed on a graded basis over the vesting period of each annual installment. The cumulative expense for equity settled transactions incorporates a forfeiture rate to reflect the Company’s best estimate of the number of equity instruments that will ultimately vest.

Cash settled share-based payments, such as the restricted share units granted to eligible employees, are measured at fair value on the grant date and are re-valued at each subsequent reporting period until vested. The awards are expensed on a graded basis over the vesting period of each annual installment. A forfeiture rate is applied in the same manner as described for equity settled awards. No expense is recognized for awards that do not ultimately vest.

Shares issued from the stock bonus plan are measured at fair value on the grant date.

3.17 Income or Loss per Common Share

Basic net income or loss per common share is computed by dividing net income by the weighted average number of common shares outstanding during the period. Diluted net income per common share amounts are calculated based on net income divided by dilutive common shares. Dilutive common shares are arrived at by adding common shares issuable on conversion of options or purchase warrants to weighted average common shares, assuming that proceeds received from the exercise of in-the-money stock options and purchase warrants are used to purchase common shares at the average market price; dilution from the Company’s convertible debt is considered using the “if converted” method.

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3.18 Standards and Interpretations Issued But Not Yet Adopted

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.

i. 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, 2015.

ii. 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” and Standing Interpretations Committee 12, “Special Purpose Entities” that provide a single model on how entities should prepare consolidated financial statements. This standard is effective for reporting periods on or after January 1, 2013, with earlier adoption permitted.

iii. IFRS 11 Joint Arrangements (“IFRS 11”)

IFRS 11, issued in May 2011, establishes principles for financial reporting by entities involved in a joint arrangement and distinguishes between joint operations and joint ventures. IFRS 11 supersedes the current IAS 31, “Interests in Joint Ventures” and Standing Interpretations Committee 13, “Jointly Controlled Entities-Non Monetary Contributions by Venturers” and is effective for reporting periods beginning on or after January 1, 2013, with earlier adoption permitted.

iv. 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.

v. 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, with earlier adoption permitted.

vi. 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, with earlier adoption 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.

4. CRITICAL ACCOUNTING JUDGMENTS AND KEY SOURCES OF ESTIMATION UNCERTAINITY

The preparation of financial statements in accordance with IFRS requires management to make estimates and assumptions in certain circumstances that affect reported amounts. The most sensitive estimates affecting the Financial Statements are in the areas set out below. Actual results may differ from these estimates.

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4.1 Critical Judgments in Applying Accounting Policies

i. E&E Assets

Management must determine if E&E assets, which have not yet resulted in the discovery of proved reserves, should continue to be capitalized or charged to E&E expense. When making this determination, management considers factors such as the Company’s drilling results, planned exploration and development activities, the financial capacity of the Company to further develop the property, the ability to use the Company’s HTL™ technology in certain projects, lease expiries, market conditions and technical recommendations from its exploration staff.

ii. Impairment

a. Property, Plant and Equipment

Ivanhoe annually evaluates its oil and gas assets or groups of assets for impairment or whenever events or changes in circumstances indicate the carrying value may not be recoverable. Among other things, an impairment may be triggered by falling oil and gas prices, a significant negative revision to reserve estimates, the inability to use the Company’s HTL™ technology in certain projects, changes in capital costs or the inability to raise sufficient financial resources to further develop the property. Cash flow estimates for the Company’s impairment assessments require significant assumptions about future prices and costs, production, reserves, discount rates and potential benefits from the application of its HTL™ technology.

b. Intangible Technology Assets

Ivanhoe annually reviews the intangible Technology Assets for impairment or if an adverse event or change occurs. Indicators of adverse events could include HTL™ patent expiries, advancements of new technologies or the inability to successfully commercialize the HTL™ technology. The impairment of the Technology Assets requires management to make assumptions about competitive technological developments, the successful commercialization of the Company’s HTL™ technology and future cash flows from the HTL™ technology.

4.2 Key Sources of Estimation Uncertainty

i. Oil and Gas Reserves

The process of estimating quantities of reserves is inherently uncertain and complex. It requires significant judgment and decisions based on available geological, geophysical, engineering and economic data. These estimates may change substantially as additional data from ongoing development activities and production becomes available and as economic conditions impacting oil and gas prices and costs change. Such revisions could be upwards or downwards. Reserve estimates have a material impact on depletion and the Company’s impairment evaluations, which in turn have a material impact on earnings.

The recoverable value of the Company’s PP&E is calculated based on future net cash flows from proved plus probable reserves, discounted at a pre-tax rate that includes risks specific to the asset. A 1% increase in the discount rate and a 5% decrease in the forward pricing used in the calculation of cash flows from proved plus probable reserves as at December 31, 2011, would not impair the Company’s development projects.

ii. HTL™ Technology

Future cash flows from HTL™ technology is a key source of estimation uncertainty as it requires management to make assumptions about the successful commercialization of the HTL™ technology and competitive technological developments. Success in commercializing the HTL™ technology in the oil and gas industry depends on the Company’s ability to economically design, construct and operate commercial-scale plants and a variety of other factors. Ivanhoe expects that technological advances in the processes and procedures for upgrading heavy oil and bitumen into lighter, less viscous products will continue to progress. It is possible that those advances could cause the HTL™ technology to become uncompetitive or obsolete.

iii. Option Pricing Models

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forfeited. Changes in assumptions can materially affect the estimated fair value, and therefore, the existing models do not necessarily provide precise measures of fair value.

iv. Convertible Note and Convertible Debentures

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 Canadian dollar denominated debt is considered to contain an embedded derivative since the functional currency of the Company is the US dollar. As a result, the Convertible Note was bifurcated into debt and the convertible option, which was recognized at fair value using the Black-Scholes valuation method. The Black-Scholes valuation method requires the input of highly subjective assumptions regarding expected volatility of the Company’s share price and risk-free interest rate, and is therefore considered to be a crucial accounting estimate.

On June 9, 2011, the Company issued Cdn$73.3 million of 5.75% convertible unsecured subordinated debentures (“Convertible Debentures”). The Canadian dollar denominated debt is considered to contain an embedded derivative since the functional currency of the Company is the US dollar. As a result, the Convertible Debentures were bifurcated into debt and the convertible option, which was recognized at fair value using the Black-Scholes valuation method. The Black-Scholes valuation method requires the input of highly subjective assumptions regarding expected volatility of the Company’s share price and risk-free interest rate, and is therefore considered to be a crucial accounting estimate.

v. Deferred Income Taxes

Ivanhoe operates in a specialized industry in several tax jurisdictions. As a result, income is subject to various rates of taxation. The breadth of the Company’s operations and the global complexity of tax regulations require assessments of uncertainties and judgments in estimating the taxes it will ultimately pay. The final taxes paid are dependent upon many factors, including negotiations with taxing authorities in various jurisdictions, uncertain tax positions and resolution of disputes arising from federal, provincial, state and local tax audits. The resolution of these uncertainties and the associated final taxes may result in adjustments to the Company’s tax assets and tax liabilities.

5. CASH AND CASH EQUIVALENTS

	December 31, 2011		December 31, 2010		January 1, 2010
Cash at banks and on hand		16,867		10,147		6,797
Term deposits		–		57,670		–
Money market accounts		–		–		14,715
Restricted cash		23		500		2,850
		16,890		68,317		24,362

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

6. RESTRICTED CASH

December 31,

2011

December 31,

2010

January 1,

2010

Ecuador performance bond

500

–

Zitong performance bond

20,000

–

20,500

–

In December 2011, Ivanhoe was required to post a $20.0 million performance bond as part of the completion and signing of a supplementary agreement to the Contract for Exploration, Development and Production in Zitong Block, Sichaun Basin with China National Petroleum Corporation (“CNPC”) for the Zitong block (“Supplementary Agreement”).

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7. ASSETS HELD FOR SALE

Sunwing Zitong Energy (“SZE”), a wholly owned subsidiary of the Company, signed a binding Memorandum of Understanding to assign 100% of its participating interest in the Zitong Production Sharing Contract (“PSC”) to Shell. The transaction is subject to government approvals and other prescribed conditions. There is no assurance that this transaction will close as described.

In exchange for SZE’s interest in the Zitong block, Ivanhoe will receive a cash payment of up to $85.0 million as reimbursement for past qualified and recoverable costs incurred. In addition, Ivanhoe will receive a further cash payment upon closing of up to $75.0 million, contingent on the timing of the receipt of full government approvals and third-party consents and waivers for the transaction. Should SZE receive government approval for the transaction, Shell will become liable for the performance bond disclosed in Note 6, resulting in a release of restricted cash back to the Company.

The carrying value of the Zitong asset, which is comprised of E&E expenditures, was $41.9 million at December 31, 2011; capital expenditures were previously reported in the Asia segment.

8. INTANGIBLE ASSETS

	Exploration and Evaluation Assets
	Asia			Canada		Latin America			Total			HTL™ Technology		Total Intangible Assets
Cost
Balance January 1, 2010		14,411			94,431		6,755			115,597			92,153		207,750
Additions		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		23,094			9,697		12,303			45,094			–		45,094
Exploration and evaluation expense		(2,124	)		–		(650	)		(2,774	)		–		(2,774	)
Assets reclassified as held for sale		(41,902	)		–		–			(41,902	)		–		(41,902	)
Balance December 31, 2011		17,203			133,452		31,178			181,833			92,153		273,986

Amortization of the HTL™ technology has not commenced and its carrying value had not been impaired since it was acquired in 2005.

Intangible assets within the Asia segment exclude a 10% partner working interest in the Zitong block.

In the year ended December 31, 2011, $2.1 million (December 31, 2010 – $2.1 million) of employee benefits directly attributable to E&E assets were capitalized. In addition, in the year ended December 31, 2011, $0.3 million (December 31, 2010 – $0.8 million) related to share-based compensation costs were capitalized to E&E assets.

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9. PROPERTY, PLANT AND EQUIPMENT

	Oil and Gas Property and Equipment
	Asia		Canada		Latin America		Total		Other Assets			Total PP&E
Cost
Balance January 1, 2010		31,816		–		–		31,816		11,373			43,189
Additions		4,123		–		–		4,123		1,648			5,771
Disposals		–		–		–		–		(12	)		(12	)
Balance December 31, 2010		35,939		–		–		35,939		13,009			48,948
Additions		12,923		–		–		12,923		1,471			14,394
Disposals		–		–		–		–		(3	)		(3	)
Balance December 31, 2011		48,862		–		–		48,862		14,477			63,339

Accumulated Depletion and Depreciation
Balance January 1, 2010		–		–		–		–		1,206			1,206
Depletion and depreciation		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		6,899		–		–		6,899		1,132			8,031
Disposals		–		–		–		–		(1	)		(1	)
Balance December 31, 2011		13,095		–		–		13,095		3,265			16,360

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 December 31, 2011		35,767		–		–		35,767		11,212			46,979

Oil and Gas Property and Equipment

In the year ended December 31, 2011, $0.1 million (December 31, 2010 – $0.1 million) of employee benefits directly attributable to PP&E were capitalized.

Other Assets

Other assets include the Company’s FTF at the Southwest Research Institute in San Antonio, Texas, and general furniture and fixtures.

The Company performed a ceiling test calculation at December 31, 2011 and 2010 and January 1, 2010 to assess the recoverable value of its oil and gas properties. The present value of future net revenue from the Company’s proved plus probable reserves exceeded the carrying value of the Company’s oil and gas properties in 2011 and 2010 therefore no impairment was recorded.

Security

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 (Note 15). The contingent payment is secured by a first fixed charge and security interest in favor of Talisman, including over the oil sands leases, and a general security interest in all of the Company’s present and after acquired property other than equity interests in the Company’s subsidiaries (through which it holds assets in China, Mongolia and Ecuador and the HTL™ technology).

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10. DEBT

10.1 Convertible Note

	December 31, 2011		December 31, 2010			January 1, 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, the Company issued the Cdn$40.0 million Convertible Note which matured on July 11, 2011 and was repaid in full.

In the year ended December 31, 2011, $1.5 million (December 31, 2010 – $2.5 million) of interest and accretion from the Convertible Note was capitalized to E&E assets. No interest from the Convertible Note was recorded as interest expense in the year ended December 31, 2011 (December 31, 2010 – nil).

10.2 Convertible Debentures

December 31,

2011

December 31,

2010

January 1,

2010

Convertible Debentures

72,085

–

Unamortized financing costs and derivative instrument

(10,193

)

–

Carrying amount

61,892

–

On June 9, 2011, the Company issued Cdn$73.3 million in 5.75% convertible unsecured subordinated debentures at a price of Cdn$1,000 per debenture. The issuance included a public offering 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 with the redemption price being settled using either cash or common shares.

The carrying amount of the Convertible Debentures at December 31, 2011 was $61.9 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 bifurcated and recognized at fair value as a long term derivative liability as further described in Note 12.1. The remaining unamortized amount is composed of $8.6 million of unamortized value related to the derivative as well as $1.6 million in transaction costs. Transaction costs of $0.3 million were allocated to the derivative and charged to earnings at initial recognition.

Interest incurred on the Convertible Debentures was recorded as follows:

	Year ended
	December 31,
	2011		2010
Interest expense		333		–
Capitalized to E&E		2,878		–
Capitalized to PP&E		319		–
Total interest incurred on Convertible Debentures		3,530		–

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11. FINANCIAL INSTRUMENTS

11.1 Fair Value of Financial Instruments Measured at Amortized Cost

Except as detailed below, the fair value of the Company’s financial instruments recognized at amortized cost approximates their carrying value due to the short term maturity of these instruments.

December 31,

2011

December 31,

2010

January 1,

2010

Convertible Debentures

Carrying amount

61,892

–

Fair value

51,901

–

The fair value of the liability component of the Convertible Debentures was estimated using the closing price of the publically traded debentures at December 31, 2011.

11.2 Financial Instruments Measured at Fair Value Through Profit and Loss

The Company classifies its financial instruments according to the fair value hierarchy outlined in IFRS 7, “Financial Instruments: Disclosures,” as described below:

—

Level 1 – using quoted prices in active markets for identical assets or liabilities.

—

Level 2 – using inputs for the asset or liability, other than quoted prices, that are observable either directly (i.e. as prices) or indirectly (i.e. derived from prices).

—

Level 3 – using inputs for the asset or liability that are not based on observable market data, such as prices based on internal models or other valuation methods.

The following table presents the Company’s derivative instruments measured at FVTPL:

	Level 1			Level 2									Level 3
	2006 Purchase Warrants			2009 & 2010 Purchase Warrants			2008 Convertible Component of Debt			2011 Convertible Component of Debentures			Subsidiary Option		Total Fair Value
Balance January 1, 2010		7,582			667			4,773			–			–		13,022
Issuance of purchase warrants		–			13,999			–			–			–		13,999
Exercise of purchase warrants		(3	)		–			–			–			–		(3	)
Derivative gains through profit and loss		(1,964	)		(13,050	)		(3,557	)		–			–		(18,571	)
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	)
Derivative (gains) losses through profit and loss		(3,267	)		2,968			(1,216	)		(7,810	)		183		(9,142	)
Expiration of purchase warrants through profit and loss		(2,346	)		(1,477	)		–			–			–		(3,823	)
Foreign exchange gains		–			–			–			(425	)		–		(425	)
Balance December 31, 2011		–			–			–			1,617			183		1,800

The gain on derivative instruments of $13.0 million for the year ended December 31, 2011, (December 31, 2010 – $18.6 million) originated from the expiration and revaluation of derivative instruments measured at FVTPL.

Where the instrument is quoted in an active market, the movement in fair value due to credit risk is calculated as the change in fair value that is not attributable to changes in market risk. Where the instrument is not quoted in an active market, the fair value is calculated using a valuation technique that incorporates credit risk by discounting the cash flows using a credit-adjusted rate which reflects the level at which the Company could issue similar instruments at the reporting date. The amount of change in the fair value, during the period and cumulatively, of designated financial liabilities through FVTPL that is attributable to changes in credit risk is determined to be nil.

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11.3 Risks Arising from Financial Instruments

In the normal course of operations, the Company is exposed to market risks resulting from movements in commodity prices, foreign currency exchange rates and interest rates, which may result in fluctuations in the fair value or future cash flows of its financial instruments.

i. Commodity Price Risks

Commodity price risk refers to the risk that the value of a financial instrument or cash flows associated with the instrument will fluctuate due to the changes in market commodity prices. Oil prices and quality differentials are influenced by worldwide factors such as Organization of Petroleum Exporting Countries (“OPEC”) actions, political events and supply and demand fundamentals. The Company may periodically use different types of derivative instruments to manage its exposure to price volatility. However, no hedging contracts were in place in the year for 2011.

ii. Foreign Currency Exchange Rate Risk

Ivanhoe is exposed to foreign currency exchange rate risk as a result of incurring capital expenditures and operating costs in currencies other than the US dollar. A substantial portion of the Company’s activities are transacted in, or referenced to, US dollars, including oil sales in Asia, capital spending in Ecuador and ongoing FTF operations. A portion of transactions are in other currencies, such as Asia operating costs paid in Chinese renminbi, Canada exploration activities funded in Canadian dollars and the Convertible Debentures issued in Canadian dollars in 2011. The Company did not enter into any foreign currency derivatives in 2011. To help reduce the Company’s exposure to foreign currency exchange rate risk, the Company seeks to hold assets and liabilities denominated in the same currency when appropriate.

(Increase) Decrease in Net Loss and Comprehensive Loss	Change From a 10% Increase or Weakening		Change From a 10% Decrease or Strengthening
Chinese renminbi		1,953		(2,387	)
Canadian dollar		3,685		(3,711	)

iii. Interest Rate Risk

Interest rate risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate as a result of changes in market interest rates. Interest rate risk arises from interest-bearing borrowings which have a variable interest rate. The Company’s net loss and comprehensive loss would not have been impacted by an interest rate change in 2011 as interest related to the Convertible Debentures is fixed and interest resulting from the Convertible Note was capitalized to E&E assets.

iv. Credit Risk

The Company believes its exposure to credit risk related to cash and cash equivalents and restricted cash is minimal due to the quality of the financial institutions where the funds are held and the nature of the deposit instruments. Most of the Company’s credit exposures are with counterparties in the energy industry and are therefore exposed to normal industry credit risks. Ivanhoe manages its credit risk by entering into sales contracts only with established entities.

Currently, all of the Company’s oil production is sold to one national oil corporation. As a result, 96% of the outstanding accounts receivable balance at December 31, 2011 (December 31, 2010 – 85%, January 1, 2010 – 94%) is due from a national oil corporation. Long term receivables are primarily composed of value-added tax receivable amounts from the Ecuadorian government and will be recoverable upon commencement of commercial operations. Ivanhoe considers the risk of default on these items to be low due to the Company’s ongoing operations in China and Ecuador.

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	December 31, 2011		December 31, 2010		January 1, 2010
Accounts receivable – current		7,859		6,329		5,004
Accounts receivable – over 90 days		–		30		17
		7,859		6,359		5,021

v. Liquidity Risk

Liquidity risk is the risk that suitable sources of funding for the Company’s business activities may not be available. Since cash flows from existing operations are insufficient to fund operations and future capital expenditures, Ivanhoe intends to finance future capital projects with a combination of strategic investors and/or public and private debt and equity markets, either at the parent company level or at the project level or from the sale of existing assets. There is no assurance that the Company will be able to obtain such financing, or obtain it on favorable terms.

The contractual maturity of the fixed rate derivative and non-derivative financial liabilities are shown in the table below. The amounts presented represent the future undiscounted cash flows and therefore may not equate to the values presented in the statement of financial position.

As at December 31, 2011

Less than

1 year

1 to 2 years

3 to 4 years

Derivative financial liabilities

Subsidiary option

183

–

Convertible debenture

–

1,617

Non-derivative financial liabilities

Accounts payable and accrued liabilities

15,548

–

Debt and interest

4,145

8,290

78,297

12. DERIVATIVE INSTRUMENTS

12.1 Convertible Debentures

The Company issued Cdn$73.3 million in Convertible Debentures in the second quarter of 2011, as described in Note 10.2. The outstanding principal amount is convertible into common shares of the Company. The fair value of the convertible component was $1.6 million at December 31, 2011, calculated with the Black-Scholes valuation method using a risk-free interest rate of 1.27%, a dividend yield of 0.0%, a weighted average volatility factor of 40% and an expected life of 4.5 years.

If the volatility used to fair value the convertible component decreased by 10%, the fair value would decrease by $1.1 million. If volatility increased by 10%, the fair value of the convertible option would increase by $1.6 million.

12.2 Convertible Note

The Company issued a Cdn$40.0 million Convertible Note, as described in Note 10.1. 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 December 31, 2011 (December 31, 2010 – $1.2 million) as the Convertible Note was paid in full on July 11, 2011.

12.3 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. Upon exercising the Subsidiary Option, Cdn$25.0 million of existing inter-corporate indebtedness owed by the subsidiary to the Company (through an intermediate subsidiary) would be converted into additional common shares of the subsidiary, thereby diluting the private investor’s equity interest to 14.286%. The Subsidiary Option was valid for one year and expired unexercised on January 26, 2012. The option was determined to have a nominal value on the date of grant.

The fair value of the Subsidiary Option as at December 31, 2011 was $0.2 million, calculated using the Black-Scholes valuation method using an estimated share value of $17.99, an exercise price of $30.00 per share, a risk-free interest rate of

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1.00%, a dividend yield of 0.0%, an expected life of approximately one month and an estimated volatility of 87.1%, which approximates the volatility of Ivanhoe’s publically traded common shares.

12.4 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 December 31, 2011		–			–

All of the Company’s purchase warrants expired in 2011 and no purchase warrants remain outstanding at December 31, 2011.

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

Year of Issue	Price Per Special Warrant		Outstanding(1) (000s)		Fair Value ($US000s)		Expiry Date	Exercise Price Per Share	Cash Value on Exercise ($US000s)		Valuation Method
2006		US$2.23		11,398		5,615	May 2011	Cdn$2.93(2)		33,577	Quoted Market Price
2009		N/A		735		11	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 US$2.63 per share until the fifth anniversary date of the closing. In September 2006, these warrants were listed on the Toronto Stock Exchange and the exercise price was changed to Cdn$2.93.

At December 31, 2010, the fair value of the purchase warrants issued in 2009 and 2010 was calculated using a weighted average risk-free interest rate of 1.0%, a dividend yield of 0.0%, a weighted average volatility factor of 66.6% and an expected life of two months.

13. LONG TERM PROVISIONS

	December 31, 2011		December 31, 2010
Decommissioning provision
Balance, beginning of year		1,108		1,040
Liabilities incurred		–		642
Liabilities settled		–		(179	)
Revisions in cash flow estimates		59		(488	)
Unwinding of discount		27		23
Change in discount rates		373		70
Balance, end of year		1,567		1,108
Long term obligation		–		1,900
Long term accrued liabilities		352		–
		1,919		3,008

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13.1 Decommissioning Provision

The decommissioning provision represents the present value of decommissioning costs related to oil and gas properties in Canada, the FTF, and oil and gas properties in Ecuador, which are expected to be incurred in 2013, 2029 and 2038 respectively. The Company records a provision for the estimated future cost of decommissioning oil and gas properties and the FTF on a discounted basis. The provision for the costs of decommissioning these oil and gas properties and the FTF has been estimated, using current prices and discounted using a risk-free interest rate of 1.1% to 2.4% at December 31, 2011 (December 31, 2010 – 2.0% to 3.7%).

The Company 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.

13.2 Long term obligation

13.3 Long term accrued liabilities

Long term accrued liabilities include share-based payments arising from cash-settled awards from the Restricted Share Unit plan (Note 17) and a finance lease obligation related to vehicle leases in Ecuador.

14. INCOME TAXES

The Company and its subsidiaries are required to individually file tax returns in each of the jurisdictions in which they operate. The provision for income taxes differs from the amount computed by applying the statutory income tax rates to the net losses before income taxes. The combined Canadian federal and provincial statutory rates as at December 31, 2011 and 2010 were 26.5% and 28.0%, respectively. The sources and tax effects for the differences are as follows:

	For the year ended
	December 31,
	2011			2010
Loss from continuing operations before income taxes		(26,546	)		(27,627	)
Combined Canadian federal and provincial statutory rates		26.5	%		28.0	%
Tax benefit		(7,035	)		(7,736	)
Compensation not deductible		1,410			1,604
Tax losses and deferred deductions not recognized as deferred tax assets		10,111			5,830
Foreign net losses affected at higher income tax rates		(867	)		(396	)
Expiry of tax loss carry-forwards		172			982
Derivative and other gains not taxable		(3,784	)		–
Share issue costs		(662	)		(633	)
Net currency exchange gains not taxable		(144	)		(911	)
Change in prior year estimate of tax loss carry-forwards		368			(1,306	)
Effect of change in effective income tax rates on deferred tax assets		–			1,096
Other differences		(839	)		425
Provision for (recovery of) income taxes		(1,270	)		(1,045	)

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Significant components of the Company’s deferred income tax assets and liabilities are as follows:

	December 31, 2011					December 31, 2010
	Assets		Liabilities			Assets		Liabilities
Assets held for sale		10,475		(10,475	)		–		–
Property, plant and equipment		3,325		(3,344	)		–		(1,379	)
Intangible assets		–		(39,209	)		–		(48,021	)
Tax loss carry-forwards		21,105		–			27,885		–
Tax credit carry-forwards		350		–			350		–
		35,255		(53,028	)		28,235		(49,400	)

As at December 31, 2011, the Company’s deferred income tax liability is $17.8 million in the consolidated statement of financial position, which is composed of $14.1 million in the US tax jurisdiction, $1.0 million in China and $2.7 million related to Mongolia.

The Company has recorded deferred tax assets only to the extent that they offset deferred tax liabilities in respect of income taxes expected to be levied by a particular taxation authority on a particular taxable entity or where different taxable entities can be expected to realize the assets and settle the liabilities simultaneously.

The Company has not recorded deferred income tax assets in respect of the following:

	December 31, 2011		December 31, 2010
Tax loss carry-forwards		172,617		139,390
Financing costs		6,334		6,801
		178,951		146,191

The consolidated loss carry-forward amounts and the year of expiry as at December 31, 2011, are shown in the following table. In China, the loss carry-forwards have no expiration period. A loss of approximately Cdn$55.3 million from the disposition of Russian operations in 2000, is a capital loss for Canadian income tax purposes, and is available for carry-forward against future Canadian capital gains indefinitely and is not included in the deferred income tax assets above.

Year of Expiry
2012			2,327
2014			5,426
2015			7,040
2018			2,093
2019			1,078
2020 to 2025			5,508
2026 to 2031			175,141
No expiry			81,115
			279,728

As at December 31, 2011, the Company’s loss carry-forwards is composed of $144.2 million in Canada, $81.1 million in China and $54.4 million in the United States.

At December 31, 2011, current income taxes payable is $0.6 million (December 31, 2010 – nil; January 1, 2010 – $0.5 million).

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15. COMMITMENTS AND CONTINGENCIES

15.1 Zitong Appraisal Program

The terms of the Supplementary Agreement call for the completion of a $75.5 million appraisal program by the end of June 2014.

15.2 Operating Lease Arrangements

In the year ended December 31, 2011, the Company expended $1.8 million (December 31, 2010 – $1.4 million) on operating leases relating to the rental of office space, which expire between June 2012 and March 2017.

At December 31, 2011, future net minimum payments for operating leases were:

2012			1,734
2013			1,278
2014			592
2015			402
After 2015			502
			4,508

15.3 Other

16. SHAREHOLDERS’ EQUITY

16.1 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)

In 2011, cash proceeds of $29.9 million were raised through the exercise of purchase warrants and stock options.

In 2010, the Company raised $135.7 million, net of $6.0 million of issuance costs, through a private placement of 50 million special warrants at a price of Cdn$3.00 per special warrant. The Canadian dollar purchase warrants were considered to contain an embedded derivative since the functional currency of the Company is the US dollar. As a result, they were bifurcated into debt and the convertible option, which was recognized at a fair value of approximately $14.0 million using the Black-Scholes valuation method.

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See the Consolidated Statements of Changes in Equity for the change in common shares issued in the years ended December 31, 2011 and 2010.

16.2 Contributed Surplus

Contributed surplus at January 1, 2010 consisted solely of share-based compensation expense from equity settled awards.

17. 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:

	Year ended
	December 31,
	2011		2010
Share-based expense related to
Equity settled transactions		5,614		7,557
Cash settled transactions		269		–
Total share-based expense		5,883		7,557
Share-based payments capitalized as E&E assets		335		799

17.1 Stock Option Plan

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

	December 31, 2011					December 31, 2010
	Number of Stock Options (000s)			Weighted Average Exercise Price (Cdn$)		Number of Stock Options (000s)			Weighted Average Exercise Price (Cdn$)
Outstanding, beginning of year		16,927			2.24		15,013			2.27
Granted		2,924			2.06		6,041			2.56
Exercised		(1,687	)		2.44		(2,743	)		2.28
Expired		(710	)		2.90		(635	)		2.60
Forfeited		(1,706	)		2.46		(749	)		2.64
Outstanding, end of year		15,748			2.14		16,927			2.24

Exercisable, end of year		8,231			2.13		7,324			2.19

Shares authorized for issue under the option plan at December 31, 2011 were 24.1 million (December 31, 2010 – 23.4 million).

The weighted average share price per option at the date of exercise for stock options exercised in the year ended December 31, 2011 was Cdn$3.15 (December 31, 2010 – Cdn$3.23).

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The weighted average fair value of stock options granted from the stock option plan during the year ended December 31, 2011 was Cdn$1.22 (December 31, 2010 – Cdn$1.81) per option at the grant date using the Black-Scholes option pricing model. The weighted average assumptions used for the calculation were:

Year ended December 31,	2011			2010
Expected life (in years)		6.4			6.3
Volatility (1)		74.0	%		87.3	%
Dividend yield		–			–
Risk-free rate		2.2	%		2.6	%
Estimated forfeiture rate		6.6	%		5.5	%

(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 December 31, 2011:

Range of Exercise Prices (Cdn$)	Outstanding (000s)		Weighted Average Remaining Contractual Life (years)		Weighted Average Exercise Price (Cdn$)
0.92 to 1.29		1,000		7.0		0.92
1.30 to 1.89		3,942		1.8		1.61
1.90 to 2.79		9,524		4.3		2.34
2.80 to 3.44		1,282		5.0		3.27
		15,748		3.9		2.14

17.2 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 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:

	December 31, 2011
	Number of RSUs (000s) (1)			Weighted Average Fair Value (Cdn$)
Outstanding, beginning of year		–			–
Granted		1,115			1.62
Forfeited		(178	)		2.08
Outstanding, end of year		937			1.53

(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 year ended December 31, 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:

	Year ended December 31, 2011
Expected life (in years)		3.0
Volatility (1)		64.8	%
Dividend yield		–
Risk-free rate		1.2	%
Estimated forfeiture rate		6.1	%

(1)

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

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

	December 31, 2011
Current liabilities related to RSUs		152
Long term liabilities related to RSUs		117
Intrinsic value of vested RSUs		–

18. RETIREMENT PLANS

In 2001, the Company adopted a defined contribution retirement or thrift plan (“401(k) Plan”) to assist US employees in providing for retirement or other future financial needs. Employees’ contributions (up to the maximum allowed by US tax laws) are matched 100% by the Company. Payments are also made to a state managed plan for employees in China.

For the year ended December 31, 2011, the Company paid $0.4 million for retirement plan contributions (year ended December 31, 2010 – $0.4 million).

19. 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.

The accounting policies of the segments are the same as the Company’s consolidated 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. Segment liabilities include intercompany balances.

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The following tables present the Company’s segment income (loss), capital investments and identifiable assets and liabilities.

Year ended December 31, 2011	Asia			Canada			Latin America			Technology Development			Corporate			Total
Revenue
Oil(1)		37,403			–			–			–			–			37,403
Interest		4			–			–			–			572			576
		37,407			–			–			–			572			37,979

Expenses
Operating		15,570			–			–			4,561			–			20,131
Exploration and evaluation		2,124			–			650			–			–			2,774
General and administrative		12,086			3,257			7,645			4,026			21,435			48,449
Depletion and depreciation		7,053			9			138			555			275			8,030
Foreign currency exchange (gain) loss		275			(6	)		3			–			(627	)		(355	)
Derivative instruments (gain) loss		183			–			–			–			(13,148	)		(12,965	)
Interest		26			6			32			8			289			361
Gain on derecognition of long term provision		–			–			–			–			(1,900	)		(1,900	)
		37,317			3,266			8,468			9,150			6,324			64,525

Income (loss) before income taxes		90			(3,266	)		(8,468	)		(9,150	)		(5,752	)		(26,546	)

(Provision for) recovery of income taxes
Current		(2,115	)		–			–			–			(7	)		(2,122	)
Deferred		(989	)		–			–			(1,389	)		5,770			3,392
		(3,104	)		–			–			(1,389	)		5,763			1,270

Net income (loss) and comprehensive income (loss)		(3,014	)		(3,266	)		(8,468	)		(10,539	)		11			(25,276	)

Capital investments – Intangible		20,390			6,280			10,720			–			–			37,390
Capital investments – Property, plant and equipment		12,733			–			43			879			15			13,670

As at December 31, 2011
Assets(2)		107,902			133,880			40,216			102,435			29,277			413,710
Liabilities(3)		140,621			144,531			64,362			87,822			(337,763	)		99,573
As at December 31, 2010
Assets(2)		85,273			123,890			24,392			101,899			58,964			394,418
Liabilities(3)		114,980			131,277			42,162			76,747			(271,232	)		93,934
As at January 1, 2010
Assets(2)		57,528			94,594			7,778			101,893			19,158			280,951
Liabilities(3)		81,047			98,262			13,145			56,909			(162,821	)		86,542

(1)

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

(2)

Assets include investments in subsidiaries that are eliminated for consolidation within the Corporate segment.

(3)

Liabilities for the Corporate segment include intercompany receivables of $428.7 million at December 31, 2011 (December 31, 2010 – $352.5 million; January 1, 2010 – $216.7 million) resulting in a negative balance.

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Year ended December 31, 2010	Asia			Canada			Latin America			Technology Development			Corporate			Total
Revenue
Oil(1)		21,720			–			–			–			–			21,720
Interest		6			–			–			–			202			208
		21,726			–			–			–			202			21,928

Expenses
Operating		9,539			–			–			4,086			–			13,625
Exploration and evaluation		3,537			–			4,934			–			–			8,471
General and administrative		8,413			3,719			9,525			953			20,197			42,807
Depletion and depreciation		6,303			9			52			(83	)		243			6,524
Foreign currency exchange gain		(62	)		(15	)		–			–			(3,248	)		(3,325	)
Derivative instruments gain		–			–			–			–			(18,571	)		(18,571	)
Interest		–			6			8			10			–			24
		27,730			3,719			14,519			4,966			(1,379	)		49,555

Income (loss) before income taxes		(6,004	)		(3,719	)		(14,519	)		(4,966	)		1,581			(27,627	)

(Provision for) recovery of income taxes
Current		(111	)		–			–			–			(15	)		(126	)
Deferred		(73	)		–			–			1,244			–			1,171
		(184	)		–			–			1,244			(15	)		1,045

Net income (loss) and comprehensive income (loss)		(6,188	)		(3,719	)		(14,519	)		(3,722	)		1,566			(26,582	)

Capital investments – Intangible		27,261			26,526			11,560			–			–			65,347
Capital investments – Property, plant & equipment		4,580			3			308			351			391			5,633

(1)

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

20. CAPITAL MANAGEMENT

The Company defines capital as total shareholders’ equity and debt. At December 31, 2011, the Company is not subject to any financial covenants. The Company’s objectives are to safeguard Ivanhoe’s ability to continue as a going concern, to continue the exploration and development of its projects and to maintain a flexible capital structure which optimizes the costs of capital at an acceptable risk. To manage its capital requirements, the Company prepares an annual expenditure budget that is updated periodically. The annual and updated budgets are approved by the Board of Directors. Ivanhoe’s capital structure at December 31 was:

As at December 31,	2011		2010
Debt		–		39,832
Long term debt		61,892		–
Shareholders’ equity		314,137		300,484

The Company’s main source of funds has historically been public and private equity and debt markets. The Company does not anticipate cash flow from operating activities will be sufficient to meet its operating and capital obligations and, as such, the Company intends to finance its operating and capital projects from a combination of strategic investors in its projects and/or public and private debt and equity markets, either at a parent company level or at a project level.

Cash provided by financing activities was lower in 2011 than in the prior year. 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 on July 11, 2011, as well as operating expenses and capital expenditures. In 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 2010.

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In order to maximize ongoing development efforts, the Company does not pay dividends. The Company’s invests its cash in highly liquid, short term, interest‐bearing investments with maturities of 90 days or less to correspond with the expected timing of expenditures.

21. OPERATING EXPENSES

Operating expenses for the Company are comprised of the following:

Year ended December 31,	2011		2010
Asia
Field operating		6,947		5,699
Windfall levy		8,185		3,333
Engineering support		438		507
		15,570		9,539
Technology Development
FTF operating costs		4,561		4,086
Total operating costs		20,131		13,625

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. On November 1, 2011, China’s Ministry of Finance raised the windfall levy threshold from US$40.00 per barrel to US$55.00 per barrel.

22. SUPPLEMENTAL CASH FLOW INFORMATION

Changes in Non-Cash Activities

	Year ended
	December 31,
	2011			2010
Operating activities
Accounts receivable		(2,210	)		(551	)
Note receivable		38			(39	)
Prepaid and other current assets		(301	)		176
Accounts payable and accrued liabilities		5,306			2,076
		2,833			1,662
Investing activities
Accounts receivable		716			(775	)
Prepaid and other current assets		1,748			(2,264	)
Accounts payable and accrued liabilities		(10,779	)		8,503
		(8,315	)		5,464
Financing activities
Accounts payable and accrued liabilities		57			(10	)
		(5,425	)		7,116

23. 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, the Company shares office space, furnishings, equipment, air travel and communications facilities in various international locations. Ivanhoe also shares the costs of employing administrative and non-executive management personnel at these offices. Related party transactions are in the normal course of business which the Company believes to be valued at fair market value.

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The breakdown of the related party expenses for the year ended December 31 is as follows:

Related Party	Nature of Transaction	2011		2010
Global Mining Management Corp.	Administration		585		1,107
Ivanhoe Capital Aviation Ltd.	Aircraft		1,200		1,200
I2MS.Net PTE Ltd.	Information systems		222		374
Ivanhoe Capital Services Ltd.	Administration		407		293
SouthGobi Resources Ltd.	Administration		154		77
Ibex Resources Inc.	Business development		–		40
1092155 Ontario Inc.	HTL™ technology		44		52
Ensyn Technologies Inc.	HTL™ technology		14		7
Ivanhoe Capital PTE Ltd.	Administration		150		75
Ivanhoe Mines Ltd.	Administration		–		13
			2,776		3,238

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

Related Party	Nature of Transaction	December 31, 2011		December 31, 2010		January 1, 2010
Global Mining Management Corp.	Administration		52		86		40
I2MS.Net PTE Ltd.	Information systems		18		13		17
SouthGobi Resources Ltd.	Administration		13		38		–
Ivanhoe Capital Services Ltd.	Administration		93		70		15
Ivanhoe Capital PTE Ltd.	Administration		7		–		–
			183		207		72

Ivanhoe sold Cdn$7.7 million of the Convertible Debentures, on a private placement basis and on the same terms as the public offering (Note 10.2), to certain officers and directors.

24. REMUNERATION OF KEY MANAGEMENT PERSONNEL

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

Year ended December 31,	2011		2010
Base salaries or fees and other cash payments		3,762		3,675
Employer’s contributions to retirement plan		87		66
Share-based compensation expense		2,780		2,398
		6,629		6,139

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25. INVESTMENTS IN SUBSIDIARIES

Ivanhoe has investments in the following 100% owned subsidiaries which principally affect the operating results or net assets of the Company. Subsidiaries which are inactive or immaterial have been omitted.

Name of Subsidiary	Jurisdiction of Incorporation or Formation
Sunwing Holding Corporation *	Barbados
Sunwing Energy Ltd.	Bermuda
Sunwing Zitong Energy Ltd.	British Virgin Islands
Pan-China Resources Ltd.	British Virgin Islands
Ivanhoe Energy Mongolia Inc. *	Alberta
PanAsian Energy Ltd.	Nevis
Shaman LLC	Mongolia
Ivanhoe Energy Latin America Inc. *	British Columbia
Ivanhoe Energy Ecuador Inc.	British Columbia
Ivanhoe Energy Canada Inc. *	Alberta
Ivanhoe Energy Holdings Inc. *	Nevada
Ivanhoe HTL Petroleum Ltd.	Nevada

* - subsidiary held directly by Ivanhoe Energy Inc. All other companies are held through subsidiary undertakings.

26. SUBSEQUENT EVENTS

Ivanhoe entered into an unsecured loan agreement on December 30, 2011 with Ivanhoe Capital Finance Ltd. (“ICFL”) for $10.0 million. The funds were advanced to the Company on January 3, 2012. The outstanding balance is subordinate in repayment to all amounts owing under the loan to UBS Securities LLC. Interest on the loan is 13.33% per annum, calculated monthly and due upon maturity. On March 14, 2012, the ICFL loan agreement was amended to provide that at ICFL’s option, the outstanding amount of the loan may be converted into common shares of the Company at Cdn$0.96 per share.

In January 2010, one of the Company’s subsidiaries granted a private investor an 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. The Subsidiary Option was valid for one year and expired unexercised on January 26, 2012.

In March 2012, the Company signed a credit agreement for a $50.0 million loan with UBS Securities LLC, which will be accessible once minor filings are completed. The loan matures in twelve months, includes an initial draw of $30.0 million, and a feature which allows Ivanhoe to elect to increase the total amount of the loan by an incremental $20.0 million. The loan agreement contains customary terms and covenants for a transaction of this nature.

27. 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 are presented in Note 3 of the Company’s Financial Statements.

Under IFRS 1, “First-time Adoption of International Financial Reporting Standards,” (“IFRS 1”) 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.

27.1 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; estimates were not adjusted with the benefit of hindsight. The Company has utilized the following exemptions to its opening statement of financial position dated January 1, 2010:

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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.

27.2 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 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, $8.6 million of 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.

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Reconciliation of Consolidated Statements of Financial Position

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

Assets
Current Assets
Cash and cash equivalents		24,362			–				24,362			68,317			–				68,317
Accounts receivable		5,021			–				5,021			6,359			–				6,359
Note receivable		225			–				225			264			–				264
Prepaid and other		771			–				771			2,859			–				2,859
		30,379			–				30,379			77,799			–				77,799

Intangible		92,153			115,597		a		207,750			92,153			197,193		a		273,568
					–										(7,482	)	b
					–										175		c
					–										(8,471	)	g
Property, plant and equipment		158,392			(115,597	)	a		41,983			237,200			(197,193	)	a		40,618
					(904	)	b								(2,014	)	b
					92		c								189		c
					–										2,436		f
Long term receivables		839			–				839			2,433			–				2,433
		281,763			(812	)			280,951			409,585			(15,167	)			394,418

Liabilities and Shareholders’ Equity
Current Liabilities
Accounts payable and accrued liabilities		10,779			–				10,779			21,482			–				21,482
Debt		–			–				–			39,832			–				39,832
Derivative instruments		–			13,023		d		13,023			–			8,447		d		8,447
Income taxes		530			–				530			–			–				–
Decommissioning costs		753			–				753			–			–				–
		12,062			13,023				25,085			61,314			8,447				69,761

Long term debt		36,934			–				36,934			–			–				–
Long term provisions		2,095			92		c		2,187			2,644			364		c		3,008
Deferred income taxes		22,643			(307	)	b		22,336			21,518			(367	)	b		21,165
					–										14		f
		73,734			12,808				86,542			85,476			8,458				93,934

Shareholders’ Equity
Share capital		422,322			–				422,322			550,562			–				550,562
Purchase warrants		19,427			(19,427	)	d		–			33,423			(33,423	)	d		–
Contributed surplus		20,029			(2,947	)	d		18,724			22,983			(2,947	)	d		23,141
					1,642		e								3,105		e
Convertible note		2,086			(2,086	)	d		–			2,086			(2,086	)	d		–
Accumulated deficit		(255,835	)		9,198				(246,637	)		(284,945	)		11,726				(273,219	)
		208,029			(13,620	)			194,409			324,109			(23,625	)			300,484
		281,763			(812	)			280,951			409,585			(15,167	)			394,418

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Reconciliation of Consolidated Statements of Loss and Comprehensive Loss

	Year ended December 31, 2010
	Canadian			Effect of
(US$000s)	GAAP			Transition				IFRS

Revenue
Oil		21,720			–				21,720
Interest		208			–				208
		21,928			–				21,928

Expenses
Operating		13,514			111		b		13,625
Exploration and evaluation		–			8,471		g		8,471
General and administrative		32,864			8,481		b		42,807
					1,462		e
Depletion and depreciation		8,960			(2,436	)	f		6,524
Foreign currency exchange gain		(3,325	)		–				(3,325	)
Derivative instruments gain		–			(18,571	)	d		(18,571	)
Interest		24			–				24
		52,037			(2,482	)			49,555

Loss before income taxes		(30,109	)		2,482				(27,627	)

(Provision for) recovery of income taxes
Current		(126	)		–				(126	)
Deferred		1,125			60		b		1,171
					(14	)	f
		999			46				1,045
Net loss and comprehensive loss		(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 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 instruments.

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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.

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.

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SUPPLEMENTARY DISCLOSURES ABOUT OIL AND GAS PRODUCTION ACTIVITIES

(Unaudited)

(all tabular amounts are expressed in US$000s, except reserves and depletion rate amounts)

The following information about the Company’s oil and gas producing activities is presented in accordance with Accounting Standards Codification 932 Extractive Activities – Oil and Gas (section 235-55) formerly US SFAS No. 69, “Disclosures About Oil and Gas Producing Activities”.

Oil and Gas Reserves

Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations.

Proved developed oil and gas reserves are proved reserves that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Estimates of oil and gas reserves are subject to uncertainty and will change as additional information regarding the producing fields and technology becomes available and as future economic conditions change.

Reserves presented in this section represent the Company’s share of reserves, excluding royalty interests of others. The reserves were based on the estimates by the independent petroleum engineering firm of GLJ Petroleum Consultants Ltd. The changes in the Company’s net proved oil reserves in China for the three-year period ended December 31, 2011, were as follows:

(mbbls)	Developed			Undeveloped			Total(1)
Net proved reserves, December 31, 2008		863			169			1,032
Revisions of previous estimates		489			46			535	(2)
Production		(466	)		-			(466	)
Net proved reserves, December 31, 2009		886			215			1,101
Revisions of previous estimates		667			258			925	(3)
Production		(288	)		-			(288	)
Net proved reserves, December 31, 2010		1,265			473			1,738
Revisions of previous estimates		271			(171	)		100
Extensions and discoveries		52			98			150
Production		(353	)		-			(353	)
Net proved reserves, December 31, 2011		1,235			400			1,635

(1)

None of the Company’s proved oil reserves are related to bitumen.

(2)

The oil reserve revision is due to improved production and fracture performance of the Dagang property in relation to what was estimated in the 2008 reserve report.

(3)

The reserve revision in 2010 is mainly related to lower estimated decline rates on the Dagang property based on production to date.

Net proved producing reserves in China as at December 31, were as follows:

(mbbls)
2009			885
2010			1,265
2011			1,235

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Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas Reserves

For the years ended December 31, 2011, 2010, and 2009 future net cash flows were computed using 12 month historical average prices in estimating the Company’s proved oil reserves, current costs, and statutory tax rates adjusted for tax deductions, that relate to existing proved oil reserves. The following standardized measure of discounted future net cash flows from proved oil reserves was computed using prices of $93.91, $76.35 and $58.00 per bbl of oil in 2011, 2010 and 2009, respectively. A discount rate of 10% was applied in determining the standardized measure of discounted future net cash flows.

The Company does not believe that this information reflects the fair market value of its oil and gas properties. Actual future net cash flows will differ from the presented estimated future net cash flows in that:

—

future production from proved reserves will differ from estimated production;

—

future production may also include production from probable and possible reserves;

—

future, rather than average annual, prices and costs will apply; and

—

existing economic, operating and regulatory conditions are subject to change.

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The standardized measure of discounted future net cash flows for China as at December 31 in each of the three most recently completed financial years were as follows:

	2011
Future cash inflows		178,378
Future development and restoration costs		(12,260	)
Future production costs		(75,639	)
Future income taxes		(14,656	)
Future net cash flows		75,823
10% annual discount		(20,713	)
Standardized measure		55,110


		2010
Future cash inflows		132,745
Future development and restoration costs		(7,209	)
Future production costs		(58,790	)
Future income taxes		(12,238	)
Future net cash flows		54,508
10% annual discount		(14,861	)
Standardized measure		39,647


		2009
Future cash inflows		63,862
Future development and restoration costs		(3,307	)
Future production costs		(36,825	)
Future income taxes		(593	)
Future net cash flows		23,137
10% annual discount		(4,589	)
Standardized measure		18,548

Note: The Company is using current costs in the preparation of the information shown in the tables above and to determine proved reserves. However, future production costs may not be easily comparable to historical production costs. The two main causes of difficulty in analyzing future production costs when compared to historical spending are summarized as follows:

In March 2006, the Ministry of Finance of the Peoples Republic of China (“PRC”) issued the “Administrative Measures on Collection of Windfall Gain Levy on Oil Exploitation Business” (the “Windfall Levy Measures”). According to the Windfall Levy Measures, effective as of March 26, 2006, enterprises exploiting and selling oil in the PRC are subject to a windfall gain levy (the “Windfall Levy”) if the monthly weighted average price of oil is above $40.00/bbl. The Windfall Levy is imposed at progressive rates from 20% to 40% on the portion of the weighted average sales price exceeding $40.00/bbl. As a result, the cost associated with the Windfall Levy is not related to production volumes but instead is related to the commodity price. As an example, as oil prices increased during 2008, the amount of the Windfall Levy also increased significantly, resulting in a $13.46 per bbl increase in 2008 when compared to 2007. The Windfall Levy accounted for $21.14/bbl cost of the total $43.92/bbl operating costs in our China operations, or in absolute terms $10.4 million of the total $21.5 million. This compared to only $4.00/bbl or $1.9 million in absolute terms incurred during 2009. On November 1, 2011, China’s Ministry of Finance raised the windfall levy threshold from $40.00/bbl to $55.00/bbl.

Effective January 1, 2009, the Dagang field reached “Commercial Production” status as defined by the Production Sharing Contract with our partner CNPC. The effect of this change is that the Company no longer pays 100% of operating costs but now pays 82%, representing the “pre-cost recovery” proportionate share. Effective September 1, 2009, the project reached cost recovery and the working interests changed to 51% CNPC and 49% for the Company. In our 2008 independent reserve report that was used to prepare the standardized measure disclosures above, the 49/51% reversion was estimated based on total costs yet to recover.

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Changes in standardized measure of discounted future net cash flows from China as at December 31 in each of the three most recently completed financial years were as follows:

	2011
Sale of oil and gas, net of production costs		(21,833	)
Net changes in prices and production costs		24,927
Extensions and discoveries, net of future production and development costs		9,426
Net change in future development costs		(18,571	)
Development costs incurred during the period that reduced future development costs		12,605
Revisions of previous quantity estimates		4,485
Accretion of discount		3,965
Net change in income taxes		(2,418	)
Changes in production rates (timing) and other		2,877
Increase		15,463
Standardized measure, beginning of year		39,647
Standardized measure, end of year		55,110

	2010
Sale of oil and gas, net of production costs		(12,216	)
Net changes in prices and production costs		15,878
Extensions and discoveries, net of future production and development costs		–
Net change in future development costs		(8,082	)
Development costs incurred during the period that reduced future development costs		4,924
Revisions of previous quantity estimates		31,578
Accretion of discount		1,855
Net change in income taxes		(11,645	)
Changes in production rates (timing) and other		(1,193	)
Increase		21,099
Standardized measure, beginning of year		18,548
Standardized measure, end of year		39,647

	2009
Sale of oil and gas, net of production costs		(14,777	)
Net changes in prices and production costs		6,396
Extensions and discoveries, net of future production and development costs		–
Net change in future development costs		(3,536	)
Development costs incurred during the period that reduced future development costs		3,712
Revisions of previous quantity estimates		11,106
Accretion of discount		1,409
Net change in income taxes		(593	)
Changes in production rates (timing) and other		745
Increase		4,462
Standardized measure, beginning of year		14,086
Standardized measure, end of year		18,548

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Costs incurred in oil and gas property acquisition, exploration, and development activities for the Company’s oil and gas properties for the years ended December 31 were as follows:

	2011		2010
Canada
Exploration		9,697		29,324
		9,697		29,324
Ecuador
Property acquisition
Unproved		767		1,237
Exploration		11,536		16,467
		12,303		17,704
Asia
Exploration		23,094		27,261
Development		12,923		4,123
		36,017		31,384
Total		58,017		78,412

The depletion rates, on a net production basis, were as follows:

China ($/bbl)
2011			19.54
2010			21.54

The results of operations from producing activities for the years ended December 31 were as follows:

	2011			2010
Oil revenue		37,403			21,720
Operating		(15,570	)		(9,539	)
Depletion		(7,053	)		(6,303	)
Results of operations from producing activities		14,780			5,878

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A: CONTROLS AND PROCEDURES

The Company’s management, including our Executive Chairman 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 December 31, 2011. Based upon this evaluation, management concluded that these controls and procedures were effective to ensure that (1) information required to be disclosed in the Company’s reports under the Exchange Act is accumulated and communicated to the Company’s Executive Chairman and Chief Financial Officer to allow timely decisions regarding required disclosure and (2) 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. Any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives.

MANAGEMENT REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is a process designed by, or under the supervision of, the Company’s principal executive and principal financial officers and effected by the Company’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that:

—

pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;

—

provide reasonable assurance that transactions are recorded as necessary to permit preparation of consolidated financial statements in accordance with Canadian generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and

—

provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the consolidated financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2011. In making this assessment, the Company’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework. Based on our assessment, management has concluded that, as of December 31, 2011, the Company’s internal control over financial reporting was effective based on those criteria. Management has reviewed the results of its assessment with the Audit Committee of the Board of Directors. Deloitte & Touche LLP, the Company’s Independent Registered Chartered Accountants that audited the consolidated financial statements included in Item 8 of this Form 10-K, has also audited the effectiveness of the Company’s internal control over financial reporting as of December 31, 2011, as stated in their report which immediately follows.

/s/ Carlos A. Cabrera		/s/ Gerald D. Schiefelbein
Carlos A. Cabrera		Gerald D. Schiefelbein
Executive Chairman		Chief Financial Officer

March 15, 2012

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REPORT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS

To the Board of Directors and Shareholders of Ivanhoe Energy Inc.

We have audited the internal control over financial reporting of Ivanhoe Energy Inc. and subsidiaries (the “Company”) as of December 31, 2011, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management Report of Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Canadian generally accepted auditing standards and Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2011 of the Company and our report dated March 15, 2012 expressed an unqualified opinion on those financial statements.

/s/ Deloitte & Touche LLP
Independent Registered Chartered Accountants

March 15, 2012

Calgary, Canada

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CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

There were no changes in the Company’s internal control over financial reporting that occurred during the fourth quarter of 2011 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART III

ITEM 10: DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Each director is elected for a one-year term or until his successor has been duly elected or appointed. All of our directors were elected at our last annual general meeting of shareholders (“AGM”) held on April 27, 2011. The term of office of each director concludes at our next AGM, unless the director’s office is earlier vacated in accordance with our by-laws.

Name	Age	Positions Held	Ivanhoe Director Since
Carlos A. Cabrera	60	Executive Chairman	2010
Robert M. Friedland	61	Founder and Executive Co-Chairman	1995
A. Robert Abboud	82	Independent Lead Director	2006
Howard R. Balloch	60	Director	2002
Brian F. Downey	70	Director	2005
Robert G. Graham	58	Director	2005
Peter G. Meredith	68	Director	2007
Alexander A. Molyneux	37	Director	2010
Robert A. Pirraglia	62	Director	2005

Officers serve at the pleasure of the Board of Directors.

Name	Age	Current Position	Executive Officer Since
Carlos A. Cabrera	60	Executive Chairman	2011
Robert M. Friedland	61	Founder and Executive Co-Chairman	2008
David A. Dyck	50	President and Chief Operating Officer	2010
Gerald D. Schiefelbein	53	Chief Financial Officer	2009
K. C. Patrick Chua	56	Executive Vice President	1999
Gerald G. Moench	63	Executive Vice President	1999
Greg G. Phaneuf	42	Executive Vice President, Corporate Development	2010
Michael A. Silverman	58	Executive Vice President, Technology and Chief Technology Officer	2007
Edwin J. Veith	53	Executive Vice President, Upstream	2007

A. ROBERT ABBOUD

Mr. Abboud has been the Independent Lead Director of the Company since May 2006 and serves as a member of the Company’s Audit, Nominating and Corporate Governance and Executive Committees. He was Co-Chairman of the Company from May 2006 to December 2011. Mr. Abboud has been President and Chief Executive Officer of A. Robert Abboud and Company, a private investment company, since 1984, and has had a 46-year career in oil and gas, banking and foreign affairs. He was previously President and Chief Operating Officer of Occidental Petroleum Corporation, Chairman and Chief Executive Officer of First Chicago Corporation and The First National Bank of Chicago, Chairman and Chief Executive Officer of First City Bancorporation of Texas, Chairman of ACB International, Ltd., a joint venture that included the Bank of China and a subsidiary of the Chinese Ministry of Foreign Relations and Trade. Mr. Abboud has served as a member of the Board of Directors of AMOCO and as Audit Committee Chairman for AAR Corporation, Alberto-Culver Company, Hartmarx Corporation, ICN Pharmaceuticals Inc. and Inland Steel Industries. Mr. Abboud holds a Bachelor of Arts (Cum Laude) from Harvard College, a J.D. from Harvard Law School and a Master of Business Administration from Harvard Business School, and is a member of the Illinois and Massachusetts Bar Associations, as well as the Federal Bar and American Bar Associations. Mr. Abboud was selected to serve on our Board due to his extensive experience at the senior executive and board level in the oil and gas industry and in international finance, and for the financial acumen, strategic insight, acute business judgment and international business experience he brings to the Company.

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ROBERT M. FRIEDLAND

Mr. Friedland has been Founder and Executive Co-Chairman of the Company since May 2008. A co-founder of the Company, Mr. Friedland has been a director since February 1995, Deputy Chairman of the Company from June 1999 to May 2008, President of the Company from May 2008 to May 2010 and Chief Executive Officer of the Company from May 2008 to December 2011. Mr. Friedland has served on the Company’s Executive Committee since its formation in October 2008 and was Chair of the Executive Committee from October 2008 to December 2011. Mr. Friedland served as Executive Chairman of Ivanhoe Mines Ltd., a Canadian public company with extensive operating, development and exploration interests in the Asia Pacific region from March 1994 to May 2011 and was appointed as Chief Executive Officer in October 2010. Mr. Friedland is Chairman (since 1991) and President (since 1988) of Ivanhoe Capital Corporation, a private company based in Singapore that specializes in providing venture capital and project financing for international business enterprises, predominantly in the fields of energy and minerals. He has also been Chairman since 2000, and was President from 2003-2008, of Ivanplats Limited, a private company with assets in Africa, and was Chairman of Potash One Inc., a Canadian public company, from May 2009 to January 2011. Mr. Friedland brings many valuable attributes to our Board, including his extensive experience in international corporate finance and as a senior executive and director of several internationally-focused natural resource companies and his proven track record in overseeing the exploration for, and discovery of, major resource deposits in Canada, Mongolia, Africa and elsewhere.

HOWARD R. BALLOCH

Mr. Balloch has been a director of the Company since January 2002. Mr. Balloch is the Chair of both the Nominating and Corporate Governance and Compensation and Benefits Committees, and is a member of the Executive Committee. He is Chairman of Canaccord Genuity Asia Limited, following the acquisition by Canaccord Financial Inc. of The Balloch Group, the investment advisory firm he founded in 2001. A veteran Canadian diplomat, Mr. Balloch began serving as Canada’s ambassador to the People’s Republic of China, Mongolia and the Democratic People’s Republic of Korea in 1996 after a 20-year career in the Government of Canada’s Department of Foreign Affairs and International Trade and Privy Council Office. Mr. Balloch is Vice Chairman of the Canada China Business Council, having served as its President between 2001 and 2006. Mr. Balloch holds a Bachelor of Arts (Honours) degree in Political Science and Economics and a Master of Arts in International Relations from McGill University, and completed Ph.D. studies at the University of Toronto and at Fondation Nationale de Sciences Politiques, Paris. Mr. Balloch was selected to serve as a director on our Board based on his experience as a Canadian diplomat and as an international businessman, his extensive knowledge of foreign affairs and the political and regulatory environment in many of the key regions in which the Company operates, including China and Mongolia, and his knowledge and experience in matters of public company governance.

CARLOS A. CABRERA

Mr. Cabrera has been a director of the Company since May 2010 and was appointed as Executive Chairman of the Company in December 2011. Mr. Cabrera serves as the Chair of the Executive Committee and served as a member of the Audit, Nominating and Corporate Governance and Compensation and Benefits Committees from May 2010 to December 2011. Mr. Cabrera is the former Chairman (January 2009 to July 2009), President and Chief Executive Officer (from December 2006 to January 2009) of UOP LLC, a Honeywell company. During his 35 year career with UOP, he held several managerial and technology positions, including Senior Vice President of Refining and Petrochemicals, Senior Vice President of Process Technology and Equipment and Vice President of Corporate Development and New Ventures. Mr. Cabrera served as the President and Chief Executive Officer of the National Institute of Low Carbon and Clean Energy (NICE), a wholly owned subsidiary of the Shenua Group, based in Beijing, China, from December 2010 to November 2011 and remains to date on its Advisory Board. Mr. Cabrera has also served as a director of GEVO, Inc. since June 2010 and is a member of its Nominating and Corporate Governance and Audit Committees. In January 2012, he joined the Board of Directors of the Gas Technology Institute, a US based leading research institute, development and training organization serving energy and environmental markets. Mr. Cabrera has been a member of the Executive Board of Big West Oil LLC, a private US oil company, since December 2011. Mr. Cabrera also serves as a Distinguished Associate to the World Energy Consultancy Firm FACTS. Mr. Cabrera serves on the Global Advisory Board of the University of Chicago Booth School of Business. During Mr. Cabrera’s 36 years in the refining and petrochemicals industry, he has been granted seven U.S. patents, authored numerous publications and frequently serves on industry panels as a recognized business and technical leader. He has a Bachelor of Science degree in chemical engineering from the University of Kentucky and a Master’s degree in business administration from the University of Chicago. Mr. Cabrera brings to the Board extensive experience in petroleum refining, gas processing and petrochemical production as well as international business development and senior executive management experience.

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BRIAN F. DOWNEY

Mr. Downey joined the Board of Directors in July 2005 and was appointed Chairman of the Audit Committee at that time. Mr. Downey also serves as a member of the Compensation and Benefits Committee and the Nominating and Corporate Governance Committee. Mr. Downey has been President of Downey & Associates Management Inc., a real estate holding company, since July 1986, and Financial Advisor to Lending Solutions, Inc., a full-service loan call centre located in the US whose clients are primarily US and Canadian financial institutions, since January 2002. From 1995 to 2002 he was a principal and served as Chief Executive Officer (“CEO”) of Lending Solutions, Inc., and from 1986 to 1995 he served as President and Chief Executive Officer of Credit Union Central of Canada, the national trade association and national liquidity facility for all credit unions in Canada. Mr. Downey has a Certified Management Accountant (CMA) designation from the University of Manitoba and is a Member of the Society of Management Accountants of Ontario. Mr. Downey was selected to serve as a director on our Board due to his extensive experience and expertise in financial and accounting matters. Mr. Downey is the Company’s “audit committee financial expert” within the meaning of the Securities Exchange Act of 1934.

DR. ROBERT G. GRAHAM

Dr. Graham has been a director of the Company since April 2005 and served as the Company’s Chief Technology Officer from April 2007 to September 2007. Dr. Graham co-founded Ensyn and served on the board and in various senior executive roles with Ensyn until it was acquired by the Company in 2005. Since then, he has served as Chairman (since June 2007) and Chief Executive Officer (since July 2008), and President and Chief Executive Officer (from April 2005 to June 2007) of Ensyn Corporation. Dr. Graham has been working on the commercial development of the RTP™ biomass refining and petroleum upgrading technologies since the early 1980’s. This work culminated in the development of commercial RTP applications in the wood industry in the late 1980’s and the establishment of Ensyn Renewables Inc. to capitalize on commercial projects for this business. In 1997, Dr. Graham initiated the application of this commercial RTP™ technology in the petroleum industry. Dr. Graham holds Bachelor of Science and Bachelor of Science Honours degrees from Carlton University, and a Master of Engineering and Ph.D. in Chemical Engineering from the University of Western Ontario. Dr. Graham brings unique skill, expertise and experience to our Board as the inventor of our HTL™ technology and as a scientist and businessman with extensive experience in the technology industry.

PETER G. MEREDITH

Mr. Meredith joined the Board of Directors in December 2007 and serves as a member of the Executive Committee. He previously served as a director from 1996 to 1999 and as the Company’s Chief Financial Officer from June 1999 to January 2000. Mr. Meredith has been Deputy Chairman of Ivanhoe Mines Ltd. since May 2006 and was Chief Financial Officer of Ivanhoe Mines Ltd. from May 2004 to May 2006 and from June 1999 to November 2001. He is also the Chairman (since October, 2009) and was previously Chief Executive Officer (June 2007 to October 2009) of SouthGobi Resources Ltd., and served as Chief Financial Officer of Ivanhoe Capital Corporation from June 2001 to March 2009. Prior to joining the Company, Mr. Meredith spent 31 years with Deloitte & Touche LLP, Chartered Accountants, where he retired as a partner in 1996. He was a member of its Canadian board of directors from 1991 to 1996. Mr. Meredith is a Chartered Accountant and is a member of the Institute of Chartered Accountants of British Columbia, the Institute of Chartered Accountants of Ontario and the Ordre des Comptables Agrees du Quebec. Mr. Meredith was selected to serve as a director on our Board due to his extensive experience at the senior executive and board level with international resource companies and his financial accounting, reporting and corporate finance expertise, and the depth of his knowledge of the Company’s operations and of the political and regulatory requirements of the regions in which the Company operates derived from his involvement in leadership roles with the Company and other resource companies operating in similar regions since 1996.

ALEXANDER A. MOLYNEUX

Mr. Molyneux has been a director of the Company since 2010. Mr. Molyneux is President and Chief Executive Officer of Canadian-based SouthGobi Resources Ltd. (TSX:SGQ, HK:1878). SouthGobi is focused on exploration and development of its Permian-age coal deposits in Mongolia’s South Gobi region to supply a wide range of coal products to markets in Mongolia and China. SouthGobi’s largest shareholder is Ivanhoe Mines Ltd. Before joining SouthGobi in 2009, Mr. Molyneux was Head of Metals and Mining Investment Banking for Citigroup where he established a leading metals and mining investment banking business in Asia. During a distinguished career at Citigroup and UBS, he advised on coal-related public offerings, mergers and acquisitions, bond and debt offerings totaling several billion dollars. Mr. Molyneux holds a Bachelor’s degree in Economics from Monash University in Australia. Mr. Molyneux was selected to serve as a director on our Board based on his comprehensive background in the areas of international capital markets, corporate finance and investment banking in Asia and elsewhere and his experience in doing business in the natural resource sector in China and Mongolia.

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ROBERT A. PIRRAGLIA

Mr. Pirraglia has been a director of the Company since April 2005 and acted as the Chair of the Business Development Committee from August 2007 until May 2008. He is currently a member of the Audit Committee, Compensation and Benefits Committee and the Nominating and the Corporate Governance Committee. Mr. Pirraglia is an engineer and attorney with more than 25 years of experience in the development of energy projects and projects employing innovative technologies. He served on the board of Ensyn Group, Inc. starting in 1996, and was also Chief Operating Officer of Ensyn Group, Inc. from September 1998 to April 2005. He was appointed the President of Ensyn Corporation in June 2011 and was the Chief Operating Officer and Vice President of the company from April 2005 to October 2007 and Executive Vice President of the company from October 2007 to June 2011. Mr. Pirraglia has been a member of the Management Committee of Envergent Technologies LLC since October 2007. He is also a director of RAP Management Corporation. In addition to being a founder and manager of several energy and waste processing companies, Mr. Pirraglia has provided management and business consulting services to various US, Canadian and European companies. Mr. Pirraglia holds a Bachelor of Electrical Engineering degree from New York University and a J.D. from Fordham University School of Law. Mr. Pirraglia brings significant legal, technical and project management experience and expertise to our Board as well as governance experience from acting as a public company director.

DAVID A. DYCK

Mr. Dyck was appointed President and Chief Operating Officer of the Company in May 2010 and continues to serve as President and Chief Executive Officer of Ivanhoe Energy Canada Inc. Mr. Dyck was the Executive Vice President, Capital Markets from October 2009 to May 2010. Prior to his appointment with Ivanhoe Energy Canada Inc., Mr. Dyck served as President and Chief Executive Officer of LeaRidge Capital Inc. (January 2008 to October 2009) and as Senior Vice President Finance and Chief Financial Officer of Western Oil Sands Inc. (April 2000 to October 2007).

GERALD D. SCHIEFELBEIN

Mr. Schiefelbein has been the Chief Financial Officer of the Company since November 2009. Prior to his appointment as Chief Financial Officer, Mr. Schiefelbein served as Chief Financial Officer, Oil Americas – BP p.l.c. (September 2007 to February 2009), Controller, Oil Americas – BP p.l.c. (February 2006 to September 2007) and Controller, Other Businesses and Corporate (September 2003 to February 2006) for BP p.l.c., one of the world’s largest energy companies.

K. C. PATRICK CHUA

Mr. Chua has been Executive Vice President of the Company since June 1999 and Chairman of the Company’s subsidiary Sunwing Energy Ltd. since April 2004. From March 2000 to April 2004 he was President of Sunwing Energy Ltd.

GERALD G. MOENCH

Mr. Moench has been Executive Vice President of the Company since June 1999 and President of the Company’s subsidiary Sunwing Energy Ltd. since April 2004.

GREG G. PHANEUF

Mr. Phaneuf was appointed Executive Vice President, Corporate Development of the Company in March 2011 and prior thereto, was Senior Vice President, Corporate Development since September 2010. Previous to his tenure with the Company, Mr. Phaneuf acted as Vice President, Corporate Development, for The Churchill Corporation from September 2009 to September 2010, Vice President and Chief Financial Officer of Seven Generations Energy, a private energy resource and development company, from January 2008 to June 2009 and Treasurer of Western Oil Sands Inc. from September 2004 to October 2007.

MICHAEL A. SILVERMAN

Mr. Silverman has been the Executive Vice President, Technology and Chief Technology Officer of the Company since September, 2007. From May, 2007 to September, 2007 he was Vice President, Technology of the Company. Prior to joining the Company, Mr. Silverman served as Vice President, Petrochemicals (May 2004 to May 2007) and Director, Technology Center (May 2000 to May 2004) for KBR, Inc.

EDWIN J. VEITH

Mr. Veith has been Executive Vice President, Upstream of the Company since September 2007. Mr. Veith has also been Vice President, HTL Technology of Ivanhoe Energy (USA) Inc. from November 2005 until June 2009. From June 2001 to November 2005, he was Chief Reservoir Engineer of Ivanhoe Energy (USA) Inc.

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OTHER PUBLIC COMPANY DIRECTORSHIPS

The following is information respecting directorships held by our directors over the last five years at public and registered investment companies.

Messrs. Meredith and Friedland are directors of Ivanhoe Mines Ltd. and Ivanhoe Australia Limited. Mr. Balloch is a director of Methanex Corporation and was previously a director of Ivanhoe Mines Ltd., East Energy Corp., Canaccord Financial Inc. and Tiens Biotech Group USA Inc. Mr. Friedland was a director of Potash One Inc., a Canadian public company. Mr. Meredith is also a director of Entrée Gold Inc., SouthGobi Resources Ltd. and Great Canadian Gaming Corporation, and was previously a director of Jinshan Gold Mines Inc. (renamed China Gold International) and Olympus Pacific Minerals Inc. Mr. Molyneux is a director of SouthGobi Resources Ltd. Mr. Cabrera is also a director of GEVO, Inc.

BOARD COMMITTEES

As required under the Business Corporations Act (Yukon) and under section 3(a)(58)(A) of the Exchange Act, our Board of Directors has a separately designated standing Audit Committee. The members of the Audit Committee are Messrs. Brian F. Downey (Chair), A. Robert Abboud and Robert A. Pirraglia. Mr. Downey, one of our current independent directors, has been determined by the Board of Directors to be an Audit Committee financial expert. We believe that Mr. Downey’s prior experience working as a Certified Management Accountant and significant financial and business experience at the executive levels of management qualifies him to be an Audit Committee financial expert.

We also have a Compensation and Benefits Committee, a Nominating and Corporate Governance Committee and an Executive Committee. The current members of the Compensation and Benefits Committee are Messrs. Howard R. Balloch (Chair), Robert A. Pirraglia and Brian F. Downey. The current members of the Nominating and Corporate Governance Committee are Messrs. Howard R. Balloch (Chair), Robert A. Pirraglia, Brian F. Downey and A. Robert Abboud. The current members of the Executive Committee are Messrs. Carlos A. Cabrera (Chair), Robert M. Friedland, A. Robert Abboud, Howard R. Balloch, David A. Dyck and Peter G. Meredith.

CODE OF BUSINESS CONDUCT AND ETHICS

We have a Code of Business Conduct and Ethics applicable to all employees, consultants, officers and directors regardless of their position in our organization, at all times and everywhere we do business. The Code of Business Conduct and Ethics provides that our employees, consultants, officers and directors will uphold our commitment to a culture of honesty, integrity and accountability and that we require the highest standards of professional and ethical conduct from our employees, consultants, officers and directors. The Code of Business Conduct and Ethics was amended in November 2007 to reflect our adoption of a whistleblower policy and to update our internal reporting process in connection with Code-related matters.

A copy of our Code of Business Conduct and Ethics, as amended, may be obtained, without charge, by request to Ivanhoe Energy Inc., Suite 654-999 Canada Place, Vancouver, British Columbia, Canada V6C 3E1, Attention: Corporate Secretary or by phone to 604-688-8323.

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ITEM 11. EXECUTIVE COMPENSATION

We are a foreign private issuer that voluntarily files its annual reports on Form 10-K. As permitted by Item 402(a)(1) of Regulation S-K, we follow the disclosure requirements applicable in Canada with respect to executive compensation (Form 51-102 F6 of the CSA), which we believe address the requirements of, and require more detailed information than, Items 6.B and 6.E.2 of Form 20-F.

COMPENSATION DISCUSSION AND ANALYSIS

Executive Summary

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The purpose of the Company’s compensation program for senior executives is to provide incentives to attract, motivate and retain qualified and experienced executives, to ensure their interests are aligned with shareholders and to provide fair transparent and defensible compensation.

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The Board, through its Compensation and Benefits Committee (the “Compensation Committee”) is committed to the transparent presentation of its compensation program.

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The three principal elements that make up the compensation program are: base salary, performance bonus and long term incentives.

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Salary for senior executives is targeted at the median of the market while overall compensation, inclusive of salary, performance incentive bonus and long term incentives is targeted at the seventy-fifth percentile of the market.

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Overall incentive compensation is awarded based on both corporate objectives (compliance, financing and growth) and individual performance objectives.

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Long term incentives are comprised of incentive stock options and RSUs.

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In 2011 Mr. Friedland, Founder and Executive Co-Chairman, voluntarily waived a salary for acting as an executive of the Company and did not participate in the compensation program for executives. Although Mr. Friedland remains eligible to receive incentive compensation as determined by the Compensation Committee and the Board from time to time, he did not receive any such compensation in 2011.

In 2011, the individuals who served as our principal executive officer, our principal financial officer and the other three most highly compensated executive officers as of the end of 2011 (the “Named Executive Officers” or “NEOs”) were:

NEO		Position Held
Carlos A. Cabrera		Executive Chairman
Robert M. Friedland		Founder and Executive Co-Chairman (formerly Executive Chairman and Chief Executive Officer)
David A. Dyck		President and COO
Gerald D. Schiefelbein		Chief Financial Officer
Michael A. Silverman		Executive Vice President and Chief Technology Officer
Edwin Veith		Executive Vice President, Upstream

Compensation Committee

The Company’s executive compensation program is administered by the Compensation Committee. The Compensation Committee’s responsibilities include the following:

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reviewing and approving corporate goals and objectives for the principal executive officer’s compensation, evaluating his performance and setting his compensation level;

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reviewing and making recommendations to the Board with respect to the adequacy and form of compensation and benefits of all executive officers and directors;

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administering and making recommendations to the Board with respect to the Company’s incentive compensation plans and equity-based plans;

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reviewing the Company’s compensation program and the specific performance objectives and targets set to establish short term and long term incentive awards;

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recommending to the Board the principal executive officer’s performance evaluation which takes into consideration the principal executive officer’s annual objectives as established by the Board and input the Committee has received from other Board members with respect to the principal executive officer’s performance; and

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determining the recipients of, and the nature and size of share compensation awards and bonuses granted from time to time.

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All Compensation Committee members are independent directors. The Committee met five times during the year. All meetings of the Committee are documented in the form of meeting minutes. The Committee is made up of the following members, all of whom have experience in dealing with compensation matters:

—

Mr. Howard Balloch has served as the Chair of the Company’s Compensation and Nominating and Corporate Governance Committees since 2004 and 2003 respectively. Mr. Balloch has also served on the compensation committees of Ivanhoe Mines Ltd. and Methanex Corporation. He is the Chairman of Canaccord Genuity Asia Limited, a boutique investment banking firm that provides financial advisory services, and chairs its Compensation Committee (management level). In these various roles, Mr. Balloch has had frequent interaction with professional compensation advisors with matters pertaining to executive and director compensation;

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Mr. Brian Downey has served as a member of the Compensation Committee since May 2006. He was the President and Chief Executive Officer of the Credit Union Central of Canada from 1986 to 1995 and the Chief Executive Officer of Lending Solutions, Inc. from November 1995 to January 2002. During Mr. Downey’s career in the financial services industry, he has had extensive experience with matters pertaining to senior management compensation; and

—

Mr. Robert Pirraglia has served as a member of the Company’s Compensation Committee since May 2008. He was appointed as the President of Ensyn Corporation in June 2011 and was the Chief Operating Officer and Vice President of the company from April 2005 to October 2007 and Executive Vice President of the company from October 2007 to June 2011. Mr. Pirraglia is an engineer and attorney with more than 25 years of experience in project development and has provided executive management and business consulting services to various U.S., Canadian and European companies. Mr. Pirraglia has been a member of the Management Committee of Envergent Technologies LLC since October 2007 and is also a director of a number of family-owned companies. In these roles, Mr. Pirraglia has regularly addressed executive and director compensation matters.

In addition, during 2011 until his appointment as an executive of the Company in December, 2011, Mr. Carlos A. Cabrera served on the Compensation Committee. Mr. Cabrera has experience with compensation matters from his career as a senior corporate executive.

In establishing policies covering base salaries, benefits, annual incentive bonuses and long term incentives, the Compensation Committee takes into consideration the recommendations of management. The Compensation Committee may seek compensation advice where appropriate from external consultants. When the Compensation Committee considers it necessary or advisable, it may retain, at the Company’s expense, outside consultants or advisors to assist or advise the Committee on any matter within its mandate. The Committee has the sole authority to retain and terminate any such consultants or advisors.

In the second quarter of 2010 the Compensation Committee engaged the services of the consulting firm Mercer Canada Ltd. (“Mercer”) to undertake a comprehensive review of executive compensation for executive positions and other senior management positions, including the development of a comparator group for the company to help the Company establish its compensation plan components with reference to its peers (the “Mercer Study”). No external consultants were hired during 2011, although the Company does review and participate in certain market studies as to compensation market standards, including the Mercer Total Compensation Survey for Energy Sector published in August of each year setting out reward levels as a general benchmark for industry in Canada (the “Mercer Annual Market Study”). In 2011 no fees were paid to compensation consultants, apart from nominal fees to participate in market studies, including the Mercer Annual Market Study.

Compensation and Benefits Philosophy and Goals

In determining the nature and quantum of compensation for the Company’s executive officers the Company is seeking to achieve the following objectives, in approximately an equal level of importance:

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to provide a strong incentive to management to contribute to the achievement of Ivanhoe’s short-term and long-term corporate goals;

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to ensure that the interests of Ivanhoe’s executive officers and the interests of the Company’s shareholders are aligned;

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to ensure that Ivanhoe is able to attract, retain and motivate executive officers of the highest caliber in light of the strong competition in the oil and gas industry for qualified personnel;

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to recognize that the successful implementation of Ivanhoe’s corporate strategy cannot necessarily be measured, at this stage of its development, only with reference to quantitative measurement criteria of corporate or individual performance; and

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to provide fair, transparent, and defensible compensation.

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In addition, the Company strives to follow guiding principles to be cost effective and competitive, to promote internal equity, to represent both value of the job and value of the person, to link compensation decisions to results, and to both be responsive to local factors within a global outlook.

NEOs and directors are not permitted to purchase financial instruments, including, for greater certainty, prepaid variable forward contracts, equity swaps collars, or units of exchange funds, that are designed to hedge or offset a decrease in market value of equity securities granted as compensation or held, directly or indirectly, by the NEO or director in accordance with the Company’s Corporate Disclosure, Confidentiality and Securities Trading Policy.

Recent Developments Related to Executive Compensation

As part of a re-alignment of the Company’s leadership team, effective December 12, 2011, Carlos A. Cabrera was appointed as Executive Chairman and Robert M. Friedland continued in his role as Founder and Executive Co-Chairman, but relinquished his role as Chief Executive Officer.

How the Company Makes Compensation Decisions

The Compensation Committee oversees and sets the general guidelines and principles for the implementation of the Company’s executive compensation policies, assesses the individual performance of the Company’s executive officers and makes recommendations to the Board of Directors. Based on these recommendations, the Board of Directors makes decisions concerning the nature and scope of the compensation to be paid to the Company’s executive officers. The Compensation Committee bases its recommendations to the Board on Ivanhoe’s compensation philosophy and on individual and corporate performance.

The Compensation Committee annually reviews, and recommends to the Board, the cash compensation, any annual performance bonus, long term incentive grants and overall compensation package for each of the Corporation’s executive officers.

Decisions for base salary adjustments are usually made during the first quarter of the new fiscal year. In the normal course of business, corporate goals and certain individual goals upon which performance bonuses are, in part, made for a fiscal year are set at the beginning of the fiscal year, and decisions on actual bonuses and incentive awards are reviewed during the first quarter following the end of the fiscal year and awarded as soon as practicable thereafter. Management presents its compensation recommendations for consideration by the Compensation Committee. The Compensation Committee presents its recommendations for overall compensation for base pay, bonuses and incentives to the Board for its approval.

Notwithstanding the adoption of a more formalized approach following the development of the Company’s compensation plan in 2010, based on the Mercer Study, the Compensation Committee and the Board retain a significant level of discretion in making compensation decisions, particularly in determining the satisfaction of broad performance criteria and overall personal performance in determining the percentage of target bonus and long term incentive that is ultimately awarded within the established bonus framework. The Compensation Committee and Board also retain flexibility in making compensation awards outside of the compensation plan framework where circumstances justify such awards.

In designing and implementing the Company’s compensation policy the Compensation Committee and the Board regularly assess, as part of their respective deliberations, the risks associated with the Company’s policies and practices. The structure of incentive compensation for executives is designed not to focus on a single metric, which in the Company’s view could be distortive, but instead a combination of both corporate and personal objectives as well as discretion in the ultimate awards, that balance both long term and short term objectives and a subjective view of overall performance. The policies are designed to preserve cash to the extent practicable, with executives participating in the upside potential of the Company through stock options and RSUs that aim to mirror shareholder returns. Consideration of risk is also directly incorporated into the incentive compensation by including compliance as an important factor in corporate objectives for bonus and long term incentive awards.

Peer Comparator Group

The comparator group for the Company for purpose of developing the compensation program includes oil and gas companies with international operations, oil sands operations and similar market capitalization. The comparator group included Pacific Rubiales Energy Corporation, Black Pearl Resources Inc., Niko Resources Ltd., Connacher Oil & Gas Ltd., Athabasca Oil Sands Corporation, OPTI Canada Inc., Petrobank Energy & Resources Ltd., TransGlobe Energy Corporation, Bankers Petroleum Ltd., Ithaca Energy Inc., Gran Tierra Energy Inc., Calvalley Petroleum Inc., Paramount Resources Ltd., Pan Orient Energy Corporation, Southern Pacific Resources Corporation and Transatlantic Petroleum Ltd. For compensation decisions in 2010, specific reference was not made to this comparator group but rather

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benchmarking at the median (for salary) and seventy-fifth percentile (for overall compensation) was done with reference to appropriate data from the Mercer Annual Market Study, adjusted for inflation.

Elements of Total Compensation

The compensation package that the Company provides to its executive officers generally consists of base salary, annual performance bonuses and equity incentives. The Company’s compensation policy reflects a belief that an element of total compensation for the Company’s executive officers should be “at risk” and in the form of common shares or incentive stock options so as to create a strong link to build shareholder value. In setting compensation levels, the Compensation Committee takes into account an executive’s past performance, future expectations for performance and also considers both the cumulative compensation being granted to executives as well as internal and external equity amongst the Company’s executives. At this stage of the Company’s development, the Company also considers the available cash resources of the Company.

The following summarizes the primary purpose of each compensation element and its emphasis:

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base salary – paid in cash as a fixed amount of compensation for performing the day to day responsibilities of the job;

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performance bonus – annual award, paid in cash and earned for the achievement of near term critical strategic corporate and project goals; and

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long term incentive awards – annual equity award, in the form of a combination of stock options and RSUs, granted to align the interests of the executive with longer term Company goals, the creation of shareholder value and the retention of key executives.

Base Salary

The base salaries of the Company’s executive officers are determined at the commencement of employment as an executive officer by the terms of the executive officer’s employment contract. The base salary is determined by a subjective assessment of each individual’s performance, experience and other factors the Company believes to be relevant, including prevailing industry demand for personnel having comparable skills and performing similar duties, the compensation the individual could reasonably expect to receive from a competitor and the Company’s ability to pay.

Under the Company’s compensation program and onward, salary levels are to be assessed using a pay grade system that is consistent with industry practice. Each of the Company’s employees, including the Company’s executive officers, is placed in a pay grade based upon his or her position, knowledge, skills, relevant experience and credentials. Annual salary increases are made based on performance and the relative position within a pay grade. The Compensation Committee also considers retention risks, succession requirements and compensation changes in the market in determining salary changes. Salary targets for executives are generally targeted at a median salary determined, in 2011, with reference to the relevant ranges set out in the Mercer Annual Market Study.

Cash Performance Bonus

The annual bonus program is intended to align the performance of the Company’s employees with the near term critical goals defined in the annual business plan. The program calls on the same pay grade system used to establish base salary to be used for determining the bonus targets for each employee.

Under the compensation plan for 2011 and onwards, cash bonuses are awarded to the Company’s executive officers and senior non-executive management based on the performance of the Company, the success in meeting, or exceeding, defined corporate and individual performance targets and the discretionary assessment of the executive’s performance by the Compensation Committee and the Board. For executive officers, potential bonus awards can range from 55% to 75% of base salary multiplied by a weighted achievement factor ranging from 0% to 200%.

Long Term Incentive Plan

Equity based compensation is granted to the Company’s executive officers and management. This long term incentive portion of salary is meant to retain key employees over the long term and to focus the efforts of those individuals on shareholder return and the longer broader goals of the organization. To remain competitive within the industry, equity grants in the form of stock options and RSUs are used to enhance the overall total compensation package.

Equity based compensation is determined as a percentage of base pay and may have a combination of stock option grants and RSUs, the combination of which is determined by the pay grade level. The higher the grade level the higher the weighting towards “at risk” stock option grants.

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All outstanding stock options that have been granted under the Company’s Equity Incentive Plan were granted at prices not less than 100% of the fair market value of the Company’s common shares on the dates such options were granted. In addition, the Board of Directors has traditionally taken an approach to vesting that is based on the passage of time and option exercise periods and vesting schedules for options granted to executive officers are determined by the Compensation Committee and the Board of Directors.

During 2011, the Company established a RSU Plan to provide a form of equity compensation that is less dilutive than options as the RSU Plan does not involve any issue of shares from treasury. The RSU Plan is administered by the Board which has the power make decisions about the awarding of RSUs. The awards under the RSU Plan consist of common shares of the Company purchased on the Toronto Stock Exchange through a Trustee. Generally RSUs vest in thirds on the first, second, and third anniversaries of the date of grant. On the date of vesting, in lieu of common shares, employees may receive a cash amount equal to the fair market value of the common shares then deliverable. If an employee voluntarily leaves the employment of the Company any unvested RSUs are forfeited by the employee under the terms of the RSU Plan. In the event of a termination without cause, as defined in the RSU Plan, all unvested RSUs are terminated six months after the date of termination; provided however that in the event such termination without cause occurs within six months following a change of control, all unvested RSUs vest on the earlier of the next vesting date for the applicable RSU award and the effective time of such termination.

While the Compensation Committee and the Board retain flexibility in apportioning long-term incentive compensation as between stock options and RSUs, the targeted allocation for NEOs is generally expected to be in the range of 60% to 80% weighting for stock options and 20% to 40% for RSUs for a given award.

Long term incentive awards granted under the compensation plan are awarded according to performance and the success in meeting or exceeding the annual established corporate and project targets. For NEOs, potential value of equity grants can range from 160% to 225% of base salary multiplied by a weighted achievement factor ranging from 0% to 200%.

EXECUTIVE COMPENSATION DECISIONS

Salary Compensation

Robert M. Friedland, Founder and Executive Co-Chairman, has voluntarily waived a cash salary from the Company. Mr. Carlos A. Cabrera, Executive Chairman, was hired December 2011 and his annual salary was set based on his experience, prevailing industry demand and other factors relevant to the negotiation for his hiring.

In 2011, the base salaries for the other NEOs were increased by 4.2% over the previous year. These increases were determined with reference to externally generated compensation data from the Canadian oil and gas industry upon which the Compensation Committee relied, including the Mercer Annual Market Study.

Short Term and Long Term Incentive Compensation Awards Made in 2011 Relating to 2010 Performance

The following chart sets out the value of bonus (short term incentive) and long term incentive compensation awarded during 2011 relating to 2010 performance for each of the NEOs receiving such compensation in 2011.

	2010		Target Bonus			Target		Target Long Term Incentive			Target Long Term		Percentage of Bonus and Long Term Incentive Awarded Based on						Percentage of Target Awarded (between			Bonus		Long Term Incentive
Name	Salary ($)		(% of Salary)			Bonus ($)		(% of Salary)			Incentive ($)		Corporate Objectives			Personal Objectives			0% and 200%)			Awarded ($)		Awarded(2) ($)

David A. Dyck(1)		353,921		75	%		265,440		225	%		796,322		100	%		0	%		70	%		197,831		487,557	(3)
Gerald D. Schiefelbein(1)		264,523		55	%		145,487		160	%		423,236		60	%		40	%		95	%		146,267		367,644	(4)
Michael A. Silverman		283,687		55	%		156,027		160	%		453,896		60	%		40	%		95	%		148,225		384,942	(5)
Edwin J. Veith		263,627		55	%		144,994		160	%		421,802		60	%		40	%		80	%		115,995		301,239	(6)

(1)

Amounts paid in Canadian dollars to Messrs. Dyck and Schiefelbein were converted to US currency based on the Bank of Canada monthly average exchange rate during the pay periods.

(2)

The value of the stock options awarded is the estimated fair value on date of grant calculated using the Black-Scholes option pricing model, with the following assumptions: an estimated volatility equal to the historical volatility of the Company’s common shares over a period equal to the expected life of the option, an estimated dividend yield of $nil, a risk free rate of return equal to the rate currently available on federal government zero-coupon bonds with a term equal to the expected life of the option and an expected life approximating the term of the option. The value of stock options with a Canadian dollar exercise price was converted to US dollars using the Bank of Canada closing exchange rate on date of grant, for example, Cdn$1.00 to US$1.02 on May 24, 2011.

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(3)

Consists of 43,352 RSUs which vest as to one third on each of May 24 of 2012, 2013 and 2014, and options to purchase 239,337 common shares exercisable at Cdn$2.65, expiring on May 24, 2018, and vesting as to 25% on each of May 24 of 2012, 2013, 2014 and 2015.

(4)

Consists of 62,162 RSUs which vest as to one third on each of May 24 of 2012, 2013 and 2014, and options to purchase 128,695 common shares exercisable at Cdn$2.65, expiring on May 24, 2018 and vesting as to 25% on each of May 24 of 2012, 2013, 2014 and 2015.

(5)

Consists of 65,087 RSUs which vest as to one third on each of May 24 of 2012, 2013 and 2014, and options to purchase 134,750 common shares exercisable at Cdn$2.65, expiring on May 24, 2018 and vesting as to 25% on each of May 24 of 2012, 2013, 2014 and 2015.

(6)

Consists of 50,934 RSUs which vest as to one third on each of May 24 of 2012, 2013 and 2014, and options to purchase 105,450 common shares exercisable at Cdn$2.65, expiring on May 24, 2018 and vesting as to 25% on each of May 24 of 2012, 2013, 2014 and 2015.

The following chart sets out the corporate performance objectives that contributed to the determination of NEOs receiving annual incentive compensation in 2011 in respect of 2010 performance. In determining the weighted achievement factor for incentive compensation as a percentage of targeted incentive compensation in the chart above, corporate objectives were weighted by the Compensation Committee and Board at approximately 60% in the case of Messrs. Schiefelbein, Silverman and Veith with the balance represented by a discretionary assessment of performance objectives for each such executive. The final percentage of target awarded was subject to a discretionary personal assessment of overall job performance by the Compensation Committee and the Board. Mr. Dyck’s weighted achievement factor was weighted principally on corporate objectives as well as a discretionary assessment of overall job performance.

Corporate Performance Objectives (Awarded in 2011 Based on 2010 Performance)	Performance Results	Weighting
Compliance: absence of environmental, health, safety, legal and regulatory violations	Exceeded: no material violations	20%
Financing: raise sufficient capital to fund operations of the Company for current year	Met: raised sufficient capital to fund operations in current year	50%
Growth: identify and secure new business opportunities beyond existing projects	Not Met: no new projects secured in 2010	30%

The weighted assessment of the corporate performance, based on the items in the table above, was determined by the Board and Compensation Committee as having been 70% achieved.

For 2010 performance, Mr. Dyck was evaluated on the corporate performance criteria together with a discretionary assessment of his job performance, without reference to any individual performance objectives. The Board awarded Mr. Dyck an overall performance assessment for 2010 of 70% of target.

Mr. Silverman was given personal objectives to effectively run the Feedstock Test Facility, to defend and enhance the HTL intellectual property, and to effectively participate in road shows, capital raising and business development activities. Mr. Silverman was determined to have achieved all significant personal objectives. The Board took particular note of his success in extending the patent protection for the HTL intellectual property. Based on the foregoing and a discretionary assessment as to overall job performance, Mr. Silverman was given an overall performance assessment for 2010 of 95% of target.

Mr. Schiefelbein was given personal objectives to successfully handle accounting, external reporting, tax, Sarbanes-Oxley compliance and securities filing responsibilities. Mr. Schiefelbein was rated as having achieved all his objectives as well as having successfully relocated the accounting activities and systems from Bakersfield to Calgary. Based on the foregoing and a discretionary assessment as to overall job performance, Mr. Schiefelbein was given an overall performance assessment for 2010 of 95% of target.

Mr. Veith was given personal objectives to complete delineation drilling for the Tamarack project, complete regulatory filings for Tamarack, as well as to support road shows, capital raising and A&D activities. Mr. Veith successfully completed the delineation drilling project, however the Tamarack regulatory filing was completed later in 2010 than originally scheduled. Based on the foregoing and a discretionary assessment to overall job performance, Mr. Veith was given a performance assessment for 2010 of 80% of target.

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Short Term and Long Term Incentive Compensation Awards made in 2011 and 2012 Relating to 2011 Performance

The following chart sets out the value of bonus (short term incentive) and long term incentive compensation awarded in respect of 2011 performance for each of the NEOs receiving such compensation in 2011.

	2011			Target Bonus			Target			Target Long Term Incentive			Target Long Term		Percentage of Bonus and Long Term Incentive Awarded Based on						Percentage of Target Awarded (between			Bonus			Long Term Incentive
Name	Salary ($)			(% of Salary)			Bonus ($)			(% of Salary)			Incentive ($)		Corporate Objectives			Personal Objectives			0% and 200%)			Awarded ($)			Awarded(1) ($)

David A. Dyck		426,088	(2)		75	%		319,566	(3)		225	%		958,698		100	%		0	%		35	%		118,886	(3)		356,658
Gerald D. Schiefelbein		287,567	(2)		55	%		158,161			160	%		460,107		60	%		40	%		61	%		95,148	(3)		276,792
Michael A. Silverman		295,056			55	%		162,281	(3)		160	%		472,090		60	%		40	%		61	%		98,991			287,975
Edwin J. Veith		274,176			55	%		150,796			160	%		438,682		60	%		40	%		56	%		83,692			243,468

(1)

Represents the value of compensation, determined in the first quarter of 2012 with respect to 2011 performance, to be satisfied by a grant of options and/or RSUs to be specified and granted at a later date.

(2)

Amounts paid in Canadian dollars to Messrs. Dyck and Schiefelbein were converted to US currency based on the Bank of Canada monthly average exchange rate during the pay periods.

(3)

The 2011 cash bonuses have not yet been paid, therefore amounts awarded to Messrs. Dyck and Schiefelbein have been converted to US currency for disclosure purposes using the March 5, 2012 Bank of Canada noon exchange rate.

The following chart sets out the corporate performance objectives applicable to NEOs receiving annual incentive compensation in respect of 2011 performance. In determining the weighted achievement factor for incentive compensation as a percentage of targeted incentive compensation in the chart, these corporate objectives were weighted by the Compensation Committee and Board at approximately 60% in the case of Messrs. Schiefelbein, Silverman and Veith with the balance represented an assessment of performance objectives for each such executive as well as a discretionary assessment overall job performance. Mr. Dyck’s weighted achievement factors were weighted principally on corporate objectives.

Corporate Performance Objectives (In Respect of 2011 Performance)	Weighting	Performance	Achievement of Target
Compliance: absence of environmental, health, safety, legal and regulatory violations (based on a target and level of 1 incident and maximum goal of no incidents)	20%	50% - partially met (2 minor incidents)	10%
Financing: raise sufficient capital to fund operation of the Company	50%	50% - partially met (activity financed during the year rather than at beginning of year)	25%
Growth: determined by share price, based on target level of Cdn$4.47	30%	0% - not met	0%
	100%		35%

The weighted assessment of corporate performance based on the items in the table above was determined by the Board and the Compensation Committee to have been 35% achieved.

For 2011 performance, Mr. Dyck was evaluated on the corporate performance criteria of having achieved 35% of target.

Mr. Silverman was rated 100% on having exceeded his personal project objectives in respect of the development and further efficiencies related to the Feedstock Test Facility and to defend and enhance the HTL intellectual property. Mr. Silverman was accordingly given an overall weighted achievement factor of 61%.

Mr. Schiefelbein was rated 100% upon having exceeded his personal objectives to successfully handle accounting, external reporting, tax, Sarbanes-Oxley compliance, and securities filings and human resources issues including the development of the RSU plan. Mr. Schiefelbein was accordingly given an overall weighted achievement factor of 61%.

Mr. Veith was rated 86% on achievement of his personal objectives largely related to the further development of the Tamarack project, as well as his contributions to corporate finance activities of the Company. Mr. Veith was accordingly given an overall weighted achievement factor of 56%.

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In connection with the management restructuring in December 2011, Mr. Dyck was granted an extraordinary grant of options to purchase 250,000 common shares exercisable at Cdn$0.92, expiring on December 16, 2018 and vesting as to 25% on each of December 16 of 2012, 2013, 2014 and 2015. In connection with his hiring in December, 2011 Mr. Cabrera was awarded stock options to purchase 650,000 common shares exercisable at Cdn$0.92, expiring on December 16, 2018 and vesting as to 25% on each of May 24 of 2012, 2013, 2014 and 2015.

Other Compensation

In 2011, Mr. Dyck received an annual retirement allowance benefit of $21,123 and Company paid parking of $5,326.

Employees of Ivanhoe Energy Holdings Inc. may participate in Ivanhoe’s 401(k), a defined contribution plan that includes Employee and Company contributions. See also “Pension Plan” below. In 2011, the Company paid Mr. Silverman $22,000 for the purpose of contributing to his 401(k) retirement plan. In 2011, Mr. Veith was paid $20,400 for the purpose of contributing to his 401(k) retirement plan as well as $66,328 as an expatriate housing allowance.

All NEOs participate in insurance plans offered to all employees, including group life insurance, accidental death and dismemberment, Business Travel Accidental coverage and Supplemental Business Travel Medical coverage calendar year.

In the first quarter of 2012, the Compensation Committee and the Board determined the quantum of long-term incentive compensation relating to 2011 compensation for certain executive officers, to be awarded in the future by the grant of combination of stock options and RSUs. As these awards have not yet been granted, the quantum of these awards is included in “All Other Compensation” in the Summary Compensation table below. See also “Short Term and Long Term Incentive Compensation Awards made in 2011 and 2012 relating to 2011 Performance” above.

Performance Graph

The following graph shows the change in a Cdn$100 investment in Ivanhoe common shares over the past five years, compared to the S&P/TSX Composite Index, the S&P/TSX Oil & Gas Exploration & Production and the S&P/TSX Energy Sector Index as at December 30, 2011. The Company’s common shares were part of the S&P/TSX Composite Index from March 22, 2010 until December 9, 2011.

(Cdn$)		2006		2007		2008		2009		2010		2011
	Ivanhoe Energy Inc.		100.00		98.73		36.94		188.54		173.25		71.34
	S&P/TSX Composite Index		100.00		107.16		69.63		91.00		104.14		92.61
	S&P/TSX Oil & Gas Exploration & Production Index		100.00		106.04		70.03		96.13		105.13		83.82
	S&P/TSX Energy Sector Index		100.00		105.00		66.85		90.23		99.25		87.07

The trend in overall compensation paid to the Company’s executive officers over the past five years has not specifically tracked the performance of the market price of the Company’s common shares, or the S&P/TSX Composite Index, particularly since 2007. Overall compensation for NEOs increased during the period.

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Option-Based Awards

Please see the section “Incentive Compensation” in the Compensation Discussion and Analysis for a discussion of the Company’s approach to option-based awards.

In 2011, the Company issued option-based awards under its Equity Incentive Plan to executive officers as described under the heading “2011 Executive Compensation Decisions.”

SUMMARY COMPENSATION TABLE

The following table sets forth all compensation earned by the individuals who served as our NEOs. Our NEOs may change from year to year due to fluctuations in our executive officers’ annual compensation.

Name and Principal Position	Year	Salary(1) ($)		Share-Based Awards(2) ($)		Option-Based Awards(3) ($)			Non-Equity Incentive Plan Compensation - Annual Incentive Awards(4) ($)		Pension Value ($)		All Other Compensation ($)			Total Compensation ($)
Carlos A. Cabrera	2011(5)		27,237		–		421,316	(6)		–		–		99,870	(6)		548,423
Executive Chairman	2010		–		–		408,504	(6)		–		–		53,667	(6)		462,171
	2009		–		–		–			–		–		–			–
Robert M. Friedland	2011(7)		–		–		–			–		–		–			–
Founder and Executive Co–Chairman	2010		–		–		1,497,797			–		–		–			1,497,797
Founder and Executive Co–Chairman	2009		–		–		–			–		–		–			–
David A. Dyck	2011		426,088		–		126,920			118,886		–		383,107	(8)(9)		1,055,001
President & COO	2010		353,921		117,697		669,419	(10)		197,831		–		24,917			1,363,785
	2009(11)		82,842		–		982,223			42,424		–		5,463			1,112,952
Gerald D. Schiefelbein	2011		287,567		–		–			95,148		–		276,792	(9)		659,507
CFO	2010		264,523		168,765		393,593	(12)		146,267		–		–			973,148
	2009(13)		61,750		–		392,889			29,874		–		–			484,513
Michael A. Silverman	2011		295,056		–		–			98,991		22,000		292,175	(9)		708,222
Executive VP, Technology & CTO	2010		283,687		176,706		402,950	(14)		148,225		22,000		–			1,033,568
Executive VP, Technology & CTO	2009		272,250		–		228,623			134,942		22,000		–			657,815
Edwin J. Veith	2011		274,176		–		–			83,692		20,400		315,122	(9)(15)		693,390
Executive VP, Upstream	2010		263,627		138,282		357,671	(16)		115,995		22,000		122,715	(17)		1,020,290
	2009		253,000		–		228,623			128,936		21,083		–			631,642

(1)

Amounts paid in Canadian dollars to Messrs. Dyck and Schiefelbein were converted to US currency based on the Bank of Canada monthly average closing exchange rate during the pay periods.

(2)

The value of the RSUs awarded is the estimated fair value on date of grant, which is calculated as the number of RSUs awarded multiplied by the weighted average price of the Company’s common shares for the five trading days immediately preceding the date of grant, converted to US dollars using the Bank of Canada exchange rate on date of grant. Share-based awards in the form of RSUs in respect of 2010 compensation (awarded in May 2011) were not previously disclosed as they were not finalized by the filing date of our 2010 10K report.

(3)

The value of the stock options awarded is the estimated fair value on date of grant calculated using the Black-Scholes option pricing model, with the following assumptions: an estimated volatility equal to the historical volatility of the Company’s common shares over a period equal to the expected life of the option, an estimated dividend yield of $nil, a risk free rate of return equal to the rate currently available on federal government zero-coupon bonds with a term equal to the expected life of the option and an expected life approximating the term of the option. The value of stock options with a Canadian dollar exercise price was converted to US dollars using the Bank of Canada closing exchange rate on date of grant. Stock options awarded in May 2011, in respect of 2010 compensation, were not previously disclosed as they were not finalized by the filing date of our 2010 10K report.

(4)

Cash bonuses were paid in 2011 and 2010 in connection with the NEOs performance in the prior year. The 2010 bonuses, awarded in 2011, were not previously disclosed as the amounts had not yet been finalized by the filing date of our 2010 10K report. Cash bonuses paid to Messrs. Dyck and Schiefelbein were converted to US currency based on the Bank of Canada monthly average closing exchange rate during the pay period.

The 2011 cash bonuses have not yet been paid; any cash bonuses awarded in respect of 2011 performance have been accrued with the expectation that they will be dispensed to the recipient of the award during 2012, either incrementally or in a lump sum, at the Company’s discretion. Amounts awarded to Messrs. Dyck and Schiefelbein have been converted to US currency for disclosure purposes using the March 5, 2012 Bank of Canada noon exchange rate.

(5)

Mr. Cabrera was appointed as Executive Chairman, effective December 12, 2011, and was employed for approximately one half month in 2011.

(6)

Mr. Cabrera is also a director of the Company. Pursuant to the Company’s policies regarding management directors, Mr. Cabrera did not receive compensation from the Company for acting as a director subsequent to his appointment as Executive Chairman. Prior to his appointment, Mr. Cabrera earned $91,323 in option-based awards and $99,870 in fees for his service as a director in 2011. In 2010, Mr. Cabrera earned $408,504 in option-based awards and $53,667 in fees for his service as a director.

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(7)

Mr. Friedland relinquished his role as Chief Executive Officer of the Company, effective December 12, 2011, but continues to serve as Founder and Executive Co-Chairman. Mr. Friedland is also a director of the Company. Pursuant to the Company’s policies regarding management directors, Mr. Friedland does not receive compensation from the Company for acting as a director.

(8)

Mr. Dyck received an annual retirement allowance of $21,123, which was paid in Canadian dollars and converted to US currency using the Bank of Canada monthly average closing exchange rate during the pay periods.

(9)

Includes the estimated value of compensation to be satisfied by a grant of stock options and/or RSUs, to be specified and granted at a later date, as follows: Mr. Dyck $356,658, Mr. Schiefelbein $276,792, Mr. Silverman $287,975 and Mr. Veith $243,468. Such options and/or RSUs may have a materially different value depending upon the date of award and option pricing model used for valuation purposes.

(10)

Includes $369,860 of option-based awards granted to Mr. Dyck in 2011, in connection with his performance in 2010, and $299,559 of previously disclosed option-based awards granted in 2010.

(11)

Mr. Dyck joined the Company effective October 21, 2009, and was employed for approximately two months during 2009.

(12)

Includes $198,879 of option-based awards granted to Mr. Schiefelbein in 2011, in connection with his performance in 2010, and $194,714 of previously disclosed option-based awards granted in 2010.

(13)

Mr. Schiefelbein joined the Company effective October 1, 2009, and was employed for three months during 2009.

(14)

Includes $208,236 of option-based awards granted to Mr. Silverman in 2011, in connection with his performance in 2010, and $194,714 of option-based awards granted in 2010.

(15)

Mr. Veith received $66,328 as an expatriate housing allowance. The amount of income taxes payable by Ivanhoe in connection with Mr. Veith’s 2011 compensation was not finalized by the filing date of the 2011 10K report.

(16)

Includes $162,957 of option-based awards granted to Mr. Veith in 2011, in connection with his performance in 2010, and $194,714 of previously disclosed option-based awards granted in 2010.

(17)

Mr. Veith was paid $28,570 as an expatriate housing allowance upon his relocation to Canada in July 2010. The Company paid $90,800 on behalf of Mr. Veith for the difference between the income taxes that he was required to pay in Canada, on account of amounts paid to him by the Company in 2010, and the income taxes that Mr. Veith would otherwise have been required to pay had he remained in the US.

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INCENTIVE PLAN AWARDS

To value stock options awarded to our NEOs, we used the Black-Scholes option pricing model. The actual value realized on exercises may be higher or lower depending on our common share price at the time of exercise.

Outstanding option-based awards at December 31, 2011

Option Awards

Share-Based Awards

Name

Number Of Securities

Underlying Unexercised

Options (#)

Option

Exercise

Price

($)

Option

Expiration

Date

Total Value of

Unexercised

Options(1)

(US$)

Number of

RSUs That

Have Not

Vested (#)

Market Value

of RSUs That

Have Not

Vested (US$)(2)

Carlos A. Cabrera

650,000

Cdn$0.92

Dec 16, 2018

127,829

–

50,000

Cdn$2.65

Apr 28, 2018

–

200,000

Cdn$2.00

Jul 28, 2017

–

100,000

Cdn$2.63

May 18, 2017

–

Robert M. Friedland

1,000,000

Cdn$2.28

Oct 28, 2017

–

2,500,000

Cdn$1.61

Mar 5, 2013

–

David A. Dyck

250,000

Cdn$0.92

Dec 16, 2018

49,165

43,352

47,743

239,337

Cdn$2.65

May 24, 2018

–

200,000

Cdn$2.28

Oct 28, 2017

–

500,000

Cdn$2.51

Oct 15, 2016

–

Gerald D. Schiefelbein

128,695

Cdn$2.65

May 24, 2018

–

62,162

68,459

130,000

Cdn$2.28

Oct 28, 2017

–

200,000

Cdn$2.51

Oct 1, 2016

–

Michael A. Silverman

134,750

Cdn$2.65

May 24, 2018

–

65,087

71,680

130,000

Cdn$2.28

Oct 28, 2017

–

150,000

Cdn$2.22

Sept 17, 2014

–

54,000

US$1.92

Oct 4, 2012

–

30,000

US$1.92

Sept 19, 2012

–

20,000

US$2.06

May 28, 2012

–

Edwin J. Veith

105,450

Cdn$2.65

May 24, 2018

–

50,934

56,093

130,000

Cdn$2.28

Oct 28, 2017

–

150,000

Cdn$2.22

Sept 17, 2014

–

158,000

US$1.92

Oct 4, 2012

–

(1)

Calculated as the difference between the December 30, 2011, closing market price of the Company’s common shares and the exercise price of the options, multiplied by the number of unexercised options. The value of options with a US dollar exercise price is calculated using the NASDAQ closing price of $1.12 per common share. The value of options with a Canadian dollar exercise price is calculated using the TSX closing price of Cdn$1.12 per common share and converted to US dollars using the December 30, 2011, Bank of Canada closing rate. Where the exercise price exceeds the market value per common share, the value is zero.

(2)

Calculated as the December 30, 2011, closing market price of the Company’s common shares multiplied by the number of unexercised RSUs and converted to US dollars using the December 30, 2011, Bank of Canada closing rate.

Incentive plan awards – value vested in 2011

Name	Option-Based Awards Value Vested During the Year(1) (US$)		Share-Based Awards Value Vested During the Year (US$)
Carlos A. Cabrera		–		–
Robert M. Friedland		899,413		–
David A. Dyck		–		–
Gerald D. Schiefelbein		–		–
Michael A. Silverman		42,552		–
Edwin J. Veith		111,485		–

(1)

Calculated as the difference between the closing market price of the Company’s common shares on the vesting date and the exercise price of the options, multiplied by the number of options vesting in the current year. The value of options with a Canadian dollar exercise price were converted to US dollars using the Bank of Canada closing rate on the vesting date. Where the exercise price exceeds the market price per common share, the value is zero.

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PENSION PLAN

Employees of Ivanhoe Energy Holdings Inc. (the “Employees”) may participate in Ivanhoe’s 401(k) (the “Plan”). The Plan is a defined contribution plan that includes Employee and Company contributions. Employees may contribute up to the maximum amount established by the Internal Revenue Code and the Company may elect to make annual discretionary matching and profit sharing contributions. Employee contributions vest immediately and Company contributions vest after two years of service. Investment decisions are made by the Employee from a variety of investment options.

The following table represents the value of accumulated pension assets within the Plan for Messrs. Veith and Silverman. There were no above-market or preferential earnings provisions.

Name	Accumulated Value at January 1, 2011 ($)		Compensatory(1) ($)			Non-compensatory(2) ($)			Accumulated Value at December 31, 2011 ($)
Edwin J. Veith		354,792		(31,058	)		(44,436	)		279,298
Michael A. Silverman		152,970		15,935			18,264			187,169

(1)

Represents employer contributions, distributions and earnings.

(2)

Represents employee contributions, distributions and earnings.

TERMINATION AND CHANGE OF CONTROL BENEFITS

The Company has written contracts of employment with Messrs. Cabrera, Dyck, Schiefelbein and Silverman. In the case of termination for cause or voluntary resignation, the employment contracts do not result in incremental payments, payables or benefits, and therefore have been excluded from the following discussion.Perquisites and other personal benefits totalling less than $50,000 have also been omitted.

Estimated incremental payments are based on the individual’s annual salary as at December 31, 2011. Any amounts payable in Canadian dollars have been translated to US dollars using the December 30, 2011, Bank of Canada closing rate. Unexercised stock options were valued using the December 30, 2011, closing market price of the Company’s common shares and stock options with a Canadian dollar exercise price were converted to US dollars using the December 30, 2011, Bank of Canada closing rate.

Carlos A. Cabrera

Mr. Cabrera’s employment contract provides that:

(a)

in the case of termination without cause or termination upon disability, the Company must pay twelve months wages in a lump sum, cause all of the unvested stock options that would vest in the succeeding twelve months to vest immediately and generally remain exercisable for six months;

(b)

in the case of termination of the employment contract by the Company within twelve months of a change of control, the Company must pay a lump sum equal to two times the sum of i) Mr. Cabrera’s current salary, and ii) the average of the two highest value aggregate annual performance bonuses paid to Mr. Cabrera by the Company during the two completed fiscal years of the Company in which Mr. Cabrera was employed by the Company that preceded the date of such termination. All stock options will vest immediately and generally remain exercisable for six months;

(c)

Mr. Cabrera is bound by a non-competition clause effective until the later of twelve months after the termination of active employment or the date he no longer receives compensation of any kind under the employment contract;

(d)

Mr. Cabrera is bound by a non-solicitation clause effective for twelve months after the termination of active employment; and

(e)

Mr. Cabrera is bound by a confidentiality clause that is effective for three years after the termination of active employment.

The estimated incremental payments to Mr. Cabrera in the above scenarios are (a) a lump sum of US$550,000 and accelerated vesting of stock options valued at US$31,957; and (b) a lump sum of US$1,100,000 and accelerated vesting of stock options valued at US$127,829.

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David A. Dyck

Mr. Dyck’s employment contract provides that:

(a)

(b)

in the case of termination of the employment contract by the Company within twelve months of a change of control, the Company must pay twelve months wages in a lump sum and cause all stock options to vest immediately and generally remain exercisable for six months; and

(c)

Mr. Dyck is bound by a confidentiality clause that is effective for three years after the termination of active employment.

The estimated incremental payments to Mr. Dyck in the above scenarios are (a) a lump sum of US$442,485 and accelerated vesting of stock options valued at US$12,291; and (b) a lump sum of US$442,485 and accelerated vesting of stock options valued at US$49,165.

Gerald D. Schiefelbein

Mr. Schiefelbein’s employment contract provides that:

(a)

(b)

in the case of termination of the employment contract by the Company within twelve months of a change of control, the Company must pay twelve months wages in a lump sum and cause all of the unvested stock options to vest immediately and remain generally exercisable for six months;

(c)

Mr. Schiefelbein is bound by a non-competition clause effective until the later of twelve months after the termination of active employment or the date he no longer receives compensation of any kind under the employment contract;

(d)

Mr. Schiefelbein is bound by a non-solicitation clause effective for twelve months after the termination of active employment; and

(e)

Mr. Schiefelbein is bound by a confidentiality clause that is effective for three years after the termination of active employment.

The estimated incremental payments to Mr. Schiefelbein in the above scenarios are (a) a lump sum of US$281,325 and accelerated vesting of stock options valued at US$nil; and (b) a lump sum of US$281,325 and accelerated vesting of stock options valued at US$nil.

Michael A. Silverman

Mr. Silverman’s employment contract provides that

(a)

in the case of termination without cause: (i) during the fourth or fifth year of employment, the Company must pay six months wages in a lump sum, and (ii) beyond the fifth anniversary of employment, the Company must pay three months wages in a lump sum, and in both cases the Company must cause all of the unvested stock options that would vest in the succeeding twelve months to vest immediately and generally remain exercisable for six months;

(b)

(c)

Mr. Silverman is bound by a non-competition clause effective until the later of six months after the termination of active employment or the date he no longer receives compensation of any kind under the employment contract;

(d)

Mr. Silverman is bound by a non-solicitation clause effective for twelve months after the termination of active employment; and

(e)

Mr. Silverman is bound by a confidentiality clause that is effective for three years after the termination of active employment.

The estimated incremental payments to Mr. Silverman in the above scenarios are (a) a lump sum of (i) US$147,528 or (ii) US$73,764, and accelerated vesting of stock options valued at US$nil; and (b) a lump sum of US$295,056 and accelerated vesting of stock options valued at US$nil.

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RSU Plan

If a NEO is terminated without cause within six months of a change of control, all of his unvested RSUs shall vest on the earlier of the original vesting date or upon termination.

Name	Value of RSUs Upon Change of Control ($)(1)
Carlos A. Cabrera		–
Robert M. Friedland		–
David A. Dyck		47,743
Gerald D. Schiefelbein		68,459
Michael A. Silverman		71,680
Edwin J. Veith		56,093

(1)

DIRECTOR COMPENSATION

Each non-management director other than Mr. Abboud, the Independent Lead Director, receives US$40,000 per annum for acting as a director of the Company. Mr. Abboud, Independent Lead Director, receives US$80,000 per annum.

Mr. Cabrera, as Chairman and Lead Director of the Company’s wholly owned subsidiaries, Ivanhoe Energy Latin America Inc. and Ivanhoe Energy Ecuador Inc., received US$80,000 per annum, prior to his appointment as Executive Chairman of the Company. Pursuant to the Company’s policies regarding management directors, Mr. Cabrera will not receive compensation from the Company for acting as a director subsequent to his appointment on December 12, 2011 as Executive Chairman.

Mr. Balloch receives an additional $5,000 each for his duties as Chairman of the Nominating and Corporate Governance and Compensation and Benefits Committees. Mr. Downey receives an additional $10,000 for his duties as Chairman of the Audit Committee. In addition, directors receive $1,000 for each board meeting and committee meeting attended in person or by conference telephone.

NON-MANAGEMENT DIRECTOR COMPENSATION TABLE

The following compensation was earned by non-management directors in 2011.

Name	Fees Earned ($)		Option-Based Awards(1) (US$)		Total ($)
A. Robert Abboud		102,000		91,323		193,323
Howard R. Balloch		74,000		142,091		216,091
Brian F. Downey		78,000		91,323		169,323
Robert G. Graham		53,000		91,323		144,323
Peter G. Meredith		51,000		91,323		142,323
Alexander A. Molyneux		49,000		91,323		140,323
Robert A. Pirraglia		63,000		91,323		154,323

(1)

Estimated fair value of stock options on date of grant calculated using the Black-Scholes option pricing model. Key assumptions are outlined in Note 17 to the Financial Statements. The value of stock options with a Canadian dollar exercise price was converted to US dollars using the Bank of Canada exchange rate on date of grant.

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Outstanding option-based awards at December 31, 2011

Name

Number of Securities

Underlying Unexercised

Options (#)

Option

Exercise Price

($)

Option

Expiration

Date

Total Value of Unexercised in-the-Money Options(1)

(US$)

A. Robert Abboud

50,000

Cdn$2.65

Apr 28, 2018

–

50,000

Cdn$3.26

Apr 29, 2017

–

50,000

US$2.69

May 29, 2013

–

Howard R. Balloch

100,000

Cdn$0.92

Dec 16, 2018

19,666

50,000

Cdn$2.65

Apr 28, 2018

–

50,000

Cdn$3.26

Apr 29, 2017

–

50,000

Cdn$1.51

Apr 29, 2016

–

50,000

Cdn$2.66

May 29, 2013

–

50,000

Cdn$2.30

May 3, 2012

–

Brian F. Downey

50,000

Cdn$2.65

Apr 28, 2018

–

50,000

Cdn$3.26

Apr 29, 2017

–

50,000

Cdn$1.51

Apr 29, 2016

–

Robert G. Graham

50,000

Cdn$2.65

Apr 28, 2018

–

50,000

Cdn$3.26

Apr 29, 2017

–

50,000

Cdn$1.51

Apr 29, 2016

–

50,000

Cdn$2.66

May 29, 2013

–

200,000

Cdn$2.29

Mar 8, 2012

–

Peter G. Meredith

50,000

Cdn$2.65

Apr 28, 2018

–

50,000

Cdn$3.26

Apr 29, 2017

–

50,000

Cdn$1.51

Apr 29, 2016

–

50,000

Cdn$2.66

May 29, 2013

–

100,000

Cdn$1.68

Mar 11, 2013

–

150,000

Cdn$1.52

Dec 19, 2012

–

Alexander A. Molyneux

50,000

Cdn$2.65

Apr 28, 2018

–

100,000

Cdn$2.63

May 18, 2017

–

80,000

Cdn$2.22

Sep 17, 2014

–

Robert A. Pirraglia

50,000

Cdn$2.65

Apr 28, 2018

–

50,000

Cdn$3.26

Apr 29, 2017

–

50,000

Cdn$1.51

Apr 29, 2016

–

50,000

US$2.69

May 29, 2013

–

50,000

US$2.06

May 3, 2012

–

(1)

Incentive plan awards – value vested in 2011

Name		Option-Based Awards Value Vested During the Year(1) (US$)
A. Robert Abboud		–
Howard R. Balloch		–
Brian F. Downey		–
Robert G. Graham		18,735
Peter G. Meredith		28,628
Alexander A. Molyneux		–
Robert A. Pirraglia		–

(1)

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ITEM 12: SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Ivanhoe’s common shares are the only class of voting securities. The following table shows each person or group who beneficially owns (pursuant to SEC Regulations) more than 5% of our voting securities as at March 5, 2012. With the exception of Mr. Friedland, the information below is based solely on filing under Regulation 13D under the Exchange Act.

Name and Address of Beneficial Owner	Number of Shares Beneficially Owned(1)		Percentage of Class
Robert M. Friedland 150 Beach Road #25-03 The Gateway West Singapore 189720	54,045,058	(2)	15.49
Manulife Asset Management (US) LLC 101 Huntington Avenue Boston, Massachusetts USA 02199	32,287,826		9.38
Caisse de dépôt et placement du Québec 1000 place Jean-Paul-Riopelle Montreal, Quebec, H2Z 2B3	19,442,822		5.60

(1)

Beneficial ownership is determined in accordance with the rules of the SEC and generally includes voting or investment power with respect to securities. Unissued common shares subject to options, warrants or other convertible securities currently exercisable or convertible, or exercisable or convertible within 60 days, are deemed outstanding for the purpose of computing the beneficial ownership of common shares of the person holding such convertible security but are not deemed outstanding for computing the beneficial ownership of common shares of any other person.

(2)

Includes 48,794,620 issued common shares held indirectly through Newstar Securities SRL (“Newstar”), Premier Mines SRL and Evershine SRL, companies controlled by Mr. Friedland. Also includes 2,750,000 unissued common shares issuable upon the exercise of stock options, 2,083,333 unissued common shares issuable upon the exercise of convertible debentures held indirectly through Newstar and 417,105 common shares held directly by Mr. Friedland.

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Security Ownership of Management

The following table sets forth the beneficial ownership, pursuant to SEC Regulations, as at March 5, 2012, of our common shares by each of our directors, our executive officers and by all of our directors and executive officers as a group:

Name of Beneficial Owner	Amount And Nature of Beneficial Ownership(1) (a)			Percentage of Class (b)		Incentive Stock Options Included in (a) (c)
A. Robert Abboud		959,028			0.28		150,000
Robert M. Friedland		54,045,058	(2)		15.49		2,750,000
Howard R. Balloch		344,642			0.10		250,000
Carlos A. Cabrera		350,000			0.10		350,000
Brian F. Downey		304,468			0.09		150,000
Robert G. Graham		4,746,726			1.38		400,000
Peter G. Meredith		517,261			0.15		450,000
Alexander A. Molyneux		227,761			0.07		198,000
Robert A. Pirraglia		565,929			0.16		250,000
David A. Dyck		660,000			0.19		300,000
Gerald D. Schiefelbein		132,500			0.04		132,500
Patrick Chua		259,318			0.08		205,000
Gerald Moench		262,651			0.08		172,500
Greg G. Phaneuf		66,000			0.02		50,000
Michael A. Silverman		249,759			0.07		226,500
Edwin J. Veith		348,626			0.10		280,500
All directors and executive officers as a group (16 persons)		64,039,727			18.39		6,315,000

(1)

(2)

Securities Authorized for Issuance under Equity Compensation Plans

All of the incentive stock options and equity compensation awards the Company granted in 2011 were made under the Company’s Equity Incentive Plan. The Equity Incentive Plan is the only equity compensation plan the Company has in effect and is intended to further align the interests of the Company’s directors and management with the Company’s long term performance and the long term interests of the Company’s shareholders. The Company’s shareholders have approved the Equity Incentive Plan and all amendments thereto. The following information is as at December 31, 2011:

Plan category	Number of Securities to be Issued Upon Exercise of Outstanding Options		Weighted-Average Exercise Price of Outstanding Options (Cdn$)	Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans
Equity compensation plans approved by Security holders		15,727,827	2.14		6,423,581
Equity compensation plans not approved by Security holders(1)		20,000	2.15		–
Total		15,747,827	2.14		6,423,581

(1)

20,000 stock options were granted as employment inducements and therefore were not granted under the Company’s stock option plan.

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ITEM 13: CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

RELATED TRANSACTIONS

Ivanhoe is party to cost sharing agreements with other companies, some of which are wholly or partially owned by Mr. Friedland. 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. In 2011, our share of these costs was $1.5 million. In 2008, we agreed, as part of our cost sharing arrangements and in connection with Mr. Friedland’s position as Founder and Executive Co-Chairman, to share the costs of operating an aircraft owned by a private company of which Mr. Friedland is the sole shareholder. Ivanhoe paid $1.2 million towards aircraft operating costs in 2011. A director of the Company, Dr. Robert Graham, was engaged to provide services through his private consulting company. In 2011, the Company paid $44,000 to his firm.

Ivanhoe entered into a $10.0 million unsecured loan agreement on December 30, 2011 with Ivanhoe Capital Finance Ltd. (“ICFL”), a company wholly owned by Mr. Friedland. The funds were advanced to the Company on January 3, 2012. Interest on the loan is 13.33% per annum, calculated monthly and due upon maturity. On March 14, 2012, the ICFL loan agreement was amended to provide that at ICFL’s option, the outstanding amount of the loan may be converted into common shares of the Company at Cdn$0.96 per share.

Our Board of Directors recognizes that related party transactions present a heightened risk of conflicts of interest and therefore has a written policy that is part of our Code of Business Conduct and Ethics. This policy prohibits activities that could give rise to conflicts of interest, unless they are specifically approved by the Board of Directors. Directors and officers are obligated to inform us of any related party transactions and any proposed related party transactions. In addition, we present a summary of related party transactions to the Audit Committee on a quarterly basis for its review and approval.

DIRECTOR INDEPENDENCE

We undertook a review of the independence of our directors and, using the definitions and independence standards for directors established under NASDAQ and CSA’s National Instrument 58-101, “Disclosure of Corporate Governance Practices.” As a result of this review, we determined that each of Messrs. Abboud, Balloch, Downey, Graham and Pirraglia is considered to be an independent director.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

In considering the nature of the services provided by Deloitte & Touche LLP (“Deloitte”), the Audit Committee determined that such services are compatible with the provision of independent audit services. The Audit Committee discussed these services with Deloitte and our management to determine that they were permitted in accordance with the rules and regulations concerning auditor independence under the Rules of Professional Conduct of the Institute of Chartered Accountants of Alberta, the rules and standards of the Public Company Accounting Oversight Board and the securities laws and regulations administered by the SEC. In accordance with our policy, all of the services outlined below were pre-approved by our Audit Committee.

(US$000s)	2011		2010
Audit fees		599		535
Audit related fees		92		89
Tax fees		141		217
Other fees		104		236
		936		1,077

Audit fees in 2011 and 2010 include services related to the audit of our annual consolidated financial statements and the review of our interim consolidated financial statements. Fees were also incurred in 2011 and 2010 for the audit of internal controls related to requirements under the United States Sarbanes-Oxley Act of 2002 and similar Canadian regulatory compliance.

Audit related fees include services performed to translate the annual and quarterly consolidated financial statements into French as well as the reimbursement of the pro-rata share of annual fees charged to each audit firm by the Canadian Public Accountability Board.

Tax services performed by Deloitte, outside of normal audit procedures, consisted of tax compliance and tax planning and advice. Tax compliance services consisted of federal, state and local income tax return assistance, preparation of

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expatriate tax returns and assistance with tax return filings in certain foreign jurisdictions. Tax planning and advice was rendered in connection with the structuring of intercompany transactions as well as proposed mergers, acquisitions and disposals.

Other fees in 2011 and 2010 relate to services provided in connection with the issuance of the Convertible Debentures and in connection with a common share prospectus respectively. Both 2011 and 2010 include fees related to services provided in support for the Company’s transition to IFRS on January 1, 2011, and for a subscription to an accounting research tool and human capital salary information.

AUDIT COMMITTEE PRE-APPROVAL POLICY

The Audit Committee has adopted a pre-approval policy for non-audit services that may be provided by the Company’s auditors. A description of the services expected to be performed by Deloitte in the following fiscal year is presented to the Audit Committee for approval. If services that were not pre-approved are required, approval may be granted by the Chairman of the Audit Committee. However, the Chairman must inform the Audit Committee, at the next regularly scheduled meeting, of any services that were pre-approved by him. Additionally, the Audit Committee generally requests a range of fees associated with each proposed service. On a quarterly basis, the Audit Committee reviews the status of services and fees incurred year-to-date against the original estimates and the forecast of remaining services and fees.

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

We refer you to the Financial Statements and Supplementary Data in Item 8 of this Annual Report where these documents are listed. The following exhibits are filed as part of this Annual Report:

		Incorporated by Reference

Exhibit Number	Description of Document	Form	Filing Date/ Period End Date	Exhibit Number (if different)
3.1	Articles of Ivanhoe Energy Inc. as amended to May 3, 2007	10-K	March 17, 2008	–

3.2	Bylaws of Ivanhoe Energy Inc. as amended May 15, 2001 and further amended March 8, 2007	10-K	March 17, 2008	–

4.1	Debenture Indenture dated June 9, 211 between Ivanhoe Energy Inc. and BNY Trust Company of Canada	10-Q	August 9, 2011	4.1

10.1	Petroleum Contract for Kongnan Block, Dagang Oilfield of the People’s Republic of China dated September 8, 1997 between China National Petroleum Corporation and Pan-China Resources Ltd., as amended June 11, 1999	20-F	February 28, 2000	3.15

10.2	Petroleum Contract dated September 19, 2002 between China National Petroleum Corporation and Pan-China Resources Ltd. for Zitong Block, Sichuan Basin of the People’s Republic of China	10-K	March 20, 2003	10.12

10.3	Amended and Restated License Agreement dated December 8, 1997 between Ensyn Technologies Inc. and Ensyn Group, Inc. and as amended on February 12, 1999	10-K	March 15, 2006	10.12

10.4	Indemnification Agreements entered into during the first quarter of 2008 between Ivanhoe Energy Inc. and its executive officers and directors	10-K	March 17, 2008	10.16

10.5	Employment Agreement, dated May 2, 2007 between Ivanhoe Energy Inc. and Michael Silverman	10-K	March 17, 2008	10.17

10.6	Asset Transfer Agreement dated July 11, 2008 between Ivanhoe Energy Inc. and Talisman Energy Canada	10-Q	August 11, 2008	10.1

10.7	Back-In Agreement dated July 11, 2008 between Ivanhoe Energy Inc. and Talisman Energy Canada	10-Q	August 11, 2008	10.2

10.8	Fixed and Floating Charge Debenture of Ivanhoe Energy Inc. in favour of Talisman Energy Canada dated July 11, 2008 in the principal sum of Cdn$67.5 million	10-Q	November 10, 2008	10.3

10.9	Pledge Agreement dated July 11, 2008 between Ivanhoe Energy Inc. and Talisman Energy Canada	10-Q	November 10, 2008	10.4

10.10	English translation of Specific Services Contract dated October 8, 2008 between Ivanhoe Energy Ecuador Inc., Empresa Estatal de Petroleos del Ecuador, Petroecuador and Empresa Estatal de Exploracion y Produccion de Petroleos del Ecuador, Petroproduccion	10-K	March 16, 2009	10.24

10.11	English translation of Contract Modification to the Specific Services Contract dated February 13, 2009 between Ivanhoe Energy Ecuador Inc., Empresa Estatal de Petroleos del Ecuador, Petroecuador and Empresa Estatal de Exploracion y Produccion de Petroleos del Ecuador, Petroproduccion	10-K	March 16, 2009	10.25

10.12	Employment Agreement dated October 1, 2009 between Ivanhoe Energy Inc. and Gerald D. Schiefelbein	8-K	November 17, 2009	10.1

10.13	Employment Agreement dated October 1, 2009 between Ivanhoe Energy Inc. and David A. Dyck	10-K	March 16, 2010	10.20

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		Incorporated by Reference

Exhibit Number	Description of Document	Form	Filing Date/ Period End Date	Exhibit Number (if different)
10.14	Indemnification Agreement dated May 18, 2010 between Ivanhoe Energy Inc. and Carlos A. Cabrera	10-K	March 16, 2011	10.20

10.15	Indemnification Agreement dated May 18, 2010 between Ivanhoe Energy Inc. and Alexander A. Molyneux	10-K	March 16, 2011	10.21

10.16	Amended and Restated Employees’ and Directors’ Equity Incentive Plan dated April 28, 2010	10-K	March 15, 2012	10.16

10.17	Warrant Indenture Amendment Agreement dated January 26, 2011, among Ivanhoe Energy Inc. and TD Securities Inc., Macquarie Capital Markets Canada Ltd., RBC Dominion Securities Inc., UBS Securities Canada Inc., CIBC World Markets Inc. and Byron Capital Markets Ltd.	10-Q	May 10, 2011	10.1

10.18	Warrant Indenture Amendment Agreement dated January 26, 2011, among Ivanhoe Energy Inc. and TD Securities Inc., Macquarie Capital Markets Canada Ltd., RBC Dominion Securities Inc., UBS Securities Canada Inc., CIBC World Markets Inc. and Byron Capital Markets Ltd.	10-Q	May 10, 2011	10.2

10.19	Underwriting Agreement, dated May 18, 2011, among Ivanhoe Energy Inc. and TD Securities Inc., Macquarie Capital Markets Canada Ltd., RBC Dominion Securities Inc., UBS Securities Canada Inc., CIBC World Markets Inc. and Byron Capital Markets Ltd.	10-Q	August 9, 2011	1.1

10.20	Debenture Indenture dated June 9, 2011 between Ivanhoe Energy Inc. and BNY Trust Company of Canada	10-Q	August 9, 2011	4.1

10.21	Restricted Share Unit Plan	10-Q	August 9, 2011	10.1

10.22	Employment Agreement dated December 12, 2011 between Ivanhoe Energy Inc. and Carlos A. Cabrera	8-K	December 16, 2011	10.1

10.23	Supplementary Agreement dated December 30, 2011, for the Petroleum Contract for Zitong Block, Sichuan Oilfield of the People’s Republic of China, with China National Petroleum Corporation and Mitsubishi Gas Chemical Company, Inc.	10-K	March 15, 2012	10.23

10.24	Memorandum of Understanding dated January 12, 2012 with Shell China Exploration and Production Company Limited	10-K	March 15, 2012	10.24

21.1	Subsidiaries of Ivanhoe Energy Inc.	10-K	March 15, 2012	21.1

23.1	Consent of GLJ Petroleum Consultants Ltd., Petroleum Engineers

23.2	Consent of Deloitte LLP

31.1	Certification by the Executive Chairman 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 Executive Chairman 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

99.1	GLJ Petroleum Consultants Ltd., Report on Reserves Data by Independent Qualified Reserves Evaluator or Auditor as of December 31, 2011

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on March 27, 2013.

IVANHOE ENERGY INC.

By: /s/ Carlos A. Cabrera

Carlos A. Cabrera

Executive Chairman

(Principal Executive Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on March 27, 2013.

/s/ Carlos A. Cabrera		/s/ Robert M. Friedland
Carlos A. Cabrera		Robert M. Friedland
Executive Chairman		Founder and Executive Co-Chairman
(Principal Executive Officer)
		/s/ A. Robert Abboud
/s/ Gerald D. Schiefelbein		A. Robert Abboud
Gerald D. Schiefelbein		Independent Lead Director
Chief Financial Officer
(Principal Financial and Accounting Officer)		/s/ Howard R. Balloch
		Howard R. Balloch, Director

		/s/ Brian F. Downey
		Brian F. Downey, Director

		/s/ Robert G. Graham
		Robert G. Graham, Director

		/s/ Peter G. Meredith
		Peter G. Meredith, Director

		/s/ Alexander A. Molyneux
		Alexander A. Molyneux, Director

		/s/ Robert A. Pirraglia
		Robert A. Pirraglia, Director

104