UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-K

For the fiscal year ended December 31, 2010
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: None
Securities registered pursuant to Section 12(g) 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

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, 2010, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $530,616,815, based on the Toronto Stock Exchange closing price on that date. At March 4, 2011, the registrant had 343,931,658 common shares outstanding.

 

 

TABLE OF CONTENTS

PART I ITEMS 1 AND 2: Business and Properties			4
ITEM 1A: Risk Factors			13
ITEM 1B: Unresolved Staff Comments			19
ITEM 3: Legal Proceedings			19
PART II ITEM 5: Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			20
ITEM 6: Selected Financial Data			22
ITEM 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations			23
ITEM 7A: Quantitative and Qualitative Disclosures About Market Risk			34
ITEM 8: Financial Statements and Supplementary Data			36
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			82
ITEM 12: Security and Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			92
ITEM 13: Certain Relationships and Related Transactions, and Director Independence			94
ITEM 14: Principal Accounting Fees and Services			94
PART IV ITEM 15: Exhibits and Financial Statement Schedules			96
Exhibit 10.18
Exhibit 10.19
Exhibit 10.20
Exhibit 10.21
Exhibit 21.1
Exhibit 23.1
Exhibit 23.2
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2
Exhibit 99.1

ABBREVIATIONS

As generally used in the oil and gas industry and in this Annual Report on Form 10-K (“Annual Report”), the following terms have the following meanings:

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

Oil equivalents compare quantities of oil with quantities of gas or express these different commodities in a common unit. 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$)		2010				2009				2008				2007				2006
Closing			1.01				0.96				0.82				1.01				0.86
High			1.01				0.97				1.03				1.09				0.91
Low			0.93				0.77				0.77				0.84				0.85
Average Noon			0.93				0.88				0.94				0.93				0.88

On March 4, 2011, the noon-day exchange rate was US$0.97 for Cdn$1.00.

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements 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”), constitute “forward-looking statements” within the meaning of the United States Private Securities Litigation Reform Act of 1995, Section 21E of the United States Securities Exchange Act of 1934, as amended (the “Exchange Act”), and Section 27A of the United States Securities Act of 1933, as amended (the “Act”). Such forward-looking statements involve known and unknown risks, uncertainties and other factors which may cause our actual results, performance or achievements, or other future events, to be materially different from any future results, performance or achievements or other events expressly or implicitly predicted by such forward-looking statements. Such risks, uncertainties and other factors include:

•

our short history of limited revenue, losses and negative cash flow from our current exploration and development activities in Canada, Ecuador, China and Mongolia;

•

our limited cash resources and consequent need for additional financing;

•

our ability to raise additional financing when it is required or on acceptable terms;

•

the potential success of our Heavy-to-Light or HTLTM technology;

•

the potential success of our oil and gas exploration and development properties in Canada, Ecuador, China and Mongolia;

•

oil price volatility;

•

oil and gas industry operational hazards and environmental concerns;

•

government regulation and requirements for permits and licenses, particularly in the foreign jurisdictions in which we carry on business;

•

title matters;

•

risks associated with carrying on business in foreign jurisdictions;

•

conflicts of interests;

•

competition for oil and gas exploration properties from larger, better financed oil and gas companies; and

•

other statements contained herein regarding matters that are not historical facts.

Forward-looking statements can often be identified by the use of forward-looking terminology such as “may”, “expect”, “intend”, “estimate”, “anticipate”, “believe” or “continue” or the negative thereof or variations thereon or similar terminology. We believe that any forward-looking statements made are reasonable based on information available to us on the date such statements were made. However, no assurance can be given as to future results, levels of activity and achievements. Except as required by law, we undertake no obligation to update publicly or revise any forward-looking statements contained in this report. All subsequent forward-looking statements, whether written or oral, attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by these cautionary statements.

AVAILABLE INFORMATION

The principal executive offices of Ivanhoe Energy Inc. (“Ivanhoe,” the “Company,” “we,” “our,” or “us”) are located at Suite 654-999 Canada Place, 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.

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. The information on our website is not, and shall not be, deemed to be part of this Annual Report.

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. Ivanhoe is the listed parent company and is responsible for Canadian operations. Operations in Latin American are conducted through Ivanhoe Energy Latin America Inc., while activities in China and Southeast Asia are operated by Sunwing Energy Ltd. (“Sunwing”).

We were 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, we changed our name to Black Sea Energy Ltd. On June 24, 1999, Black Sea Energy Ltd. merged with Sunwing, and we changed our name to Ivanhoe.

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 oil sand assets in the Athabasca region of Canada. Later in 2008, we 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 all our oil and gas exploration and production operations in the United States (“US”). We also acquired a production-sharing contract for the Nyalga Block XVI in Mongolia in 2009, through a merger with 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 HTLTM 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.

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 fueled 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.

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 broken down into three geographic areas: Canada, Ecuador and Asia. The Business and Technology Development area captures costs incurred in the pursuit of projects throughout the world as well as expenses 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 11 to the consolidated financial statements and in the MD&A in this Annual Report.

Integrated Oil and Gas Properties

Canada

Tamarack, acquired in 2008, is a 6,880 acre block located approximately 10 miles northeast of Fort McMurray, Alberta, Canada. Ivanhoe holds a 100% working interest in the property, subject only to a 20% back-in right held by Talisman Energy Canada (“Talisman”), which expires in mid-2011.

Our independent reserve evaluator, GLJ Petroleum Consultants Ltd. (“GLJ”), has assigned total 3P reserves of 220 mmbbls of bitumen to Tamarack. It is anticipated that the resources will be developed utilizing steam assisted gravity drainage (“SAGD”) technology. The Company expects that 12 well pads and approximately 160 SAGD well pairs will be required to fully develop and produce the targeted resource base.

In March 2010, a 28 well winter delineation program was completed, which provided information necessary for regulatory filings. In November 2010, Ivanhoe filed a comprehensive Environmental Impact Assessment with the Government of Alberta. In support of the application, Basic Engineering and Design and Front End Engineering and Design were completed to generate a Class III (+25/-20%) capital cost estimate. Subject to regulatory approvals from the Alberta Energy Resources Conservation Board and Alberta Environment, construction at Tamarack could commence in mid-2012, with commissioning and start-up of the production facilities expected in the fourth quarter of 2013.

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 us 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. We anticipate 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 use any light oil discoveries to blend with the heavy oil for delivery to Petroproduccion.

In 2010, the 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. The Company’s IP-15 well, drilled in 2010, encountered certain cementing and completion problems during steam injection operations and testing at the well was suspended without recovering oil. Ivanhoe sees significant variability between the two well locations, supporting the view that geological faulting is prevalent in Block 20 due to the close proximity of the Andes, directly to the west of the block. We plan to commence a seismic program following testing operations at IP-5b to increase understanding of the geological faulting and to help determine locations for our next appraisal wells.

Conventional Oil and Gas Properties

Asia

China

Zitong

In November 2002, we entered into a 30 year production sharing contract with China National Petroleum Corporation (“CNPC”) for the Zitong block, which covers an area of approximately 658,000 gross acres after contractual relinquishments in the Sichuan basin. The parties will jointly participate in the development and production of any commercially viable deposits, with production rights limited to the later of 2032 or 20 years of continuous production. In 2006, we farmed out 10% of our working interest in the Zitong block to Mitsubishi Gas Chemical Company Inc. of Japan 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, two wells were drilled in 2010 at the Zitong block, both resulting in gas discoveries. The Yixin-2 well was tested in December 2010 with gas flowing from the Xu-4 Formation. Following initial flow and pressure tests, the well was shut-in for pressure build-up. The Zitong-1 well reached total depth in December 2010 and was tested in January 2011, with gas flowing from the Xu-4 Formation. The well was subsequently shut-in to record reservoir pressure build-up and allow testing of the shallower, Xu-5 formation.

Following the drilling of the Zitong-1 and Yixin-2 wells, areas excluding those identified for development and future production were to be relinquished. In January 2011, Ivanhoe received notice that the exploration period has been extended for an additional six months.

Dagang

Ivanhoe’s oil production originates in the Kongnan oilfield in Dagang, Hebei Province, China (the “Dagang field”). We have a 30 year production sharing contract with CNPC, covering an area of 10,255 gross acres. From 2001 to 2007, we drilled 44 wells and commercial production commenced on January 1, 2009. The project reached cost recovery in 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 2010, quotas restricted production to 70,000 gross tonnes or 1,400 bbls/d gross. Actual production in 2010 averaged 750 bbls/d net. Production quotas in 2011 are set at 80,000 gross tonnes or approximately 1,600 bbls/d gross.

Mongolia

Through a merger with PanAsian Petroleum Inc. in November 2009, we acquired a production sharing contract 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 has adjusted the dates in 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. In 2010, preparations commenced for a five well drilling program and a seismic acquisition program. The first exploratory location has been identified and we expect to initiate drilling operations in Mongolia in the first half of 2011.

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, 2010:

Summary of Oil and Gas Reserves Using Average 2010 Prices⁽¹⁾

		Canada				China
(mbbl)		Tamarack				Dagang				Other				Total
Proved
Developed			—				1,186				79				1,265
Undeveloped			—				473				—				473
Total proved			—				1,659				79				1,738
Probable
Developed			—				322				—				322
Undeveloped			175,684				470				—				176,154
Possible
Developed			—				—				—				—
Undeveloped			43,809				—				—				43,809

(1)		Reserves are the Company’s total gross reserves before royalty deductions.

Canada

Probable and Possible Reserves

In 2010, probable and possible reserves increased from nil in 2009 to 219,493 mbbls as a result of completing a 28 well delineation drilling program on the Tamarack lands, further technical evaluation and the submission of Ivanhoe’s regulatory application to the Government of Alberta in November 2010. Further reserve development is subject to regulatory approval and availability of financing.

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

Probable and possible reserves will be developed using a SAGD thermal recovery process, which has been successfully demonstrated in similar projects in the Athabasca Oil Sands region. Recovery estimates for Tamarack are based on applying appropriate recovery factors to original oil-in-place estimates developed through detailed reservoir characterization. The reservoir characterization is based on information gathered during historical field delineation programs. Recovery factors applied to the oil-in-place estimates are the result of simulation and analytical models, incorporating the actual performance of existing analog projects.

China

Proved Reserves

Proved reserves at December 31, 2010, were 1,738 mbbls compared to 1,101 mbbls at December 31, 2009, an increase of 58% after 2010 production. Proved reserves increased due to in-field performance improvements from continued water injections, a partial natural water drive and our ongoing hydraulic fracture stimulation program in the Dagang field. Drilling activity in late December 2010 was successful and, in combination with geological review and reservoir mapping, supported additional future drilling locations. Proved reserves also benefitted from a pool extension due to the addition of re-activated wells in the periphery of the reservoir.

The transfer of reserves from proved undeveloped to the proved category was immaterial in 2010.

Probable Reserves

At December 31, 2010, probable reserves in China were 792 mbbls, an increase of 137% over the 334 mbbls reported at December 31, 2009. 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.

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 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 modified to reflect SEC requirements. Our reserve estimates and disclosures may differ from other Canadian issuers who follow National Instrument 51-101, “Standards of Disclosure for Oil and Gas Activities” (“NI 51-101”). Significant differences between SEC and Canadian reserve estimates and disclosures are described in the Special Note to Canadian Investors on page 10.

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, with over 25 years of experience in the oil industry focused on heavy oil recovery techniques. His past experience includes international positions responsible for thermal horizontal and vertical well development projects using state-of-the-art reservoir management techniques and advanced 3D reservoir visualization methods to integrate complex data sets. He has experience supervising project expansions and investigating new development scenarios using reservoir simulation and advanced economic modeling.

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, certain Canadian securities regulatory authorities adopted NI 51-101 which prescribes standards that Canadian companies are required to follow in the preparation and disclosure of reserves and related information.

In 2010, we re-applied for, and received, exemptions from certain NI 51-101 requirements. These exemptions permit us to substitute disclosures based on SEC requirements for much of the annual disclosure required by NI 51-101 and to prepare our reserves 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 Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”) modified to reflect SEC requirements.

The reserve quantities disclosed in this Annual Report represent net reserves calculated on an average, first-day-of-the-month price during the 12 month period preceding the end of the year for 2010, 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;

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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;

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

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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.

Production, Sales Prices and Production Costs

		2010				2009				2008
Oil production (bbls/d)			788				1,276				1,339
Average sales price ($/bbl)			75.52				53.60				98.73
Average operating costs (1) ($/bbl)			33.05				21.88				43.92

(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 is above $40.00/bbl. Excludes 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 national petroleum company.

Producing Oil Wells

The company does not have any producing gas wells. Producing oil wells are reported below.

		2010								2009								2008
		Gross(1)				Net(2)				Gross(1)				Net(2)				Gross(1)				Net(2)
Asia			44.0				21.6				44.0				21.6	(3)			44.0				36.1

(1)		Gross wells are the total number of wells in which a working interest is owned.
(2)		Net wells are the sum of fractional working interests owned in gross wells.
(3)		Our working interest in net wells was reduced from 82% to 49% as stipulated by the governing production sharing contracts upon the Company completing the recovery of its development investments in September 2009.

Drilling Activity

At December 31, 2010, we were actively drilling the Zitong-1 and Yixin-2 wells in our Zitong project and one well in our Dagang field. No wells were completed in 2010. The Company did not drill any exploration or development wells in 2009 or 2008.

Acreage

		Developed Acres								Undeveloped Acres(1)
		Gross				Net				Gross				Net
Canada			—				—				7,520				7,520
Ecuador			—				—				272,639				272,639
Asia — China(2)			1,525				747				664,314				595,338
Asia — Mongolia			—				—				3,107,907				3,107,907

(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. Although production activities from the Tamarack lease is anticipated to commence in 2013, we plan to apply for a continuation of the lease prior to its expiration if the project is delayed.

We signed a specific services contract with affiliated entities of the State 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.

Acreage in the Dagang field will return to CNPC in 2027. Following the completion of Phase II of the Zitong Contract, the remaining acreage must be relinquished to CNPC except for areas identified for development and future production, which will be relinquished upon termination of the production sharing contract in 2032.

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.

BUSINESS AND TECHNOLOGY DEVELOPMENT

The Company’s Business and Technology Development segment captures HTL™ activities as well as costs associated with the pursuit of new business development opportunities.

Technology Development

In April 2005, Ivanhoe acquired Ensyn and thereby obtained an exclusive, irrevocable license to the HTL™ process for all applications other than biomass. We have 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 three granted US patents and currently has three US patent applications pending. In other countries, 47 patents are pending. In addition, Ivanhoe owns exclusive, irrevocable licenses to 21 global patents as well as proprietary technological knowledge for the rapid thermal processing process of petroleum.

Ivanhoe operates 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 was used to support basic and front-end engineering for a commercial-scale HTL™ plant for the Tamarack project in Canada. Also, the unit was used to support conceptual design for several projects, including Pungarayacu in Ecuador. As we continue to advance our technology, the FTF will serve an integral role in supporting the Company’s commercial operations.

The FTF replaced the Commercial Demonstration Facility (“CDF”), constructed in 2004. The CDF was decommissioned in 2010 and all future testing will be conducted at the FTF.

Business Development

The Company pursues HTL™ business development opportunities globally, with an emphasis on creating value from stranded resources or resource accumulations considered too small to be economically viable using other technologies. In 2010, HTL^TM heavy oil and selected conventional oil opportunities were pursued in North and South America, the Middle East and North Africa.

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 absorb the burden of any changes in laws and regulations in the jurisdictions in which we do business more easily, 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, to evaluate and select suitable properties, implement advanced technologies, and to 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 conventional oil and gas and HTL™ operations are subject to various levels of government laws and regulations 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 regulations are imposed on 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 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 18 to 24 months. 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.

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 statement prepared for individual projects.

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 government regulates various aspects of foreign company operations in China. Such laws and regulations have generally become more stringent in recent years in the US, Canada, Ecuador and China, 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, 2010, we had 211 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 others 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” set out on page 3 of this Annual Report.

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. Continuation of the Company 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 on favorable terms, if at all, 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 financing, we may not 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 on favorable terms, if at all, 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.

We have fixed and contingent payment obligations to Talisman

As a result of acquiring our Athabasca heavy oil leases from Talisman in 2008, we have fixed and contingent payment obligations to Talisman. These obligations include a Cdn$40.0 million convertible promissory note (the “Convertible Note”) that, unless converted into Ivanhoe common shares, is due in July 2011, and a contingent payment of up to Cdn$15.0 million that will become due and payable if and when the requisite government and other approvals to develop the northern border of one of the Athabasca heavy oil leases are obtained. We intend to finance such future payments through debt and equity markets, arrangements with third parties, either at the Ivanhoe parent company level or at the subsidiary or project level or from the sale of existing assets. There is no assurance that we will be able to obtain such financing on favorable terms, if at all, 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. Failure to obtain such additional financing could put us in default of our obligations to Talisman, which are secured by a first fixed charge and security interest in favor of Talisman over the Athabasca heavy oil leases and a general security interest in all of our present and after acquired property other than the common shares we own in our subsidiaries. In the case of such default, Talisman could foreclose on the secured assets, including the leases.

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 efforts 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 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.

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 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 18 to 24 months; however, there is no assurance that the process will be completed on a timely basis and construction of the Tamarack Project could be significantly delayed. 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 time frame or within the parameters of any determined 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

We have not obtained title opinions in respect of the Athabasca heavy oil leases we acquired from Talisman and 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 a claim filed against the Government of Canada, the Province of Alberta, certain governmental entities and the regional municipality of Wood Buffalo (which includes the City of Fort McMurray, Alberta) claiming, among other things, aboriginal title to large areas of lands surrounding Fort McMurray where most of the oil sands operations in Alberta are located. Such claims, if successful, could affect the title to our heavy oil leases 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 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 15.22% 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 certain 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.

ITEM 3:		LEGAL PROCEEDINGS

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

On October 16, 2009, the plaintiffs filed a motion requesting that the Court vacate its judgment and allow discovery on jurisdictional issues on the grounds that plaintiffs had discovered new evidence. On July 15, 2010, the Court denied the plaintiffs’ motion to vacate the judgment. The request for attorneys’ fees remains pending before the Court. On August 13, 2010, the plaintiffs filed a notice of appeal challenging the district court’s judgment and some of its orders. The appeal is currently pending in the United States Court of Appeals for the Tenth Circuit. Briefing on the appeal is complete; the plaintiffs have filed an opening and reply brief and the Company and related defendants have filed a response brief. The Court has not announced whether it will hold oral argument on the appeal before it is decided. 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. The demand alleges breach of contract, fraud and other misconduct arising from a consulting agreement and various collateral agreements between GAR Energy and the Company relating to the Pungarayacu heavy oil field. The claimants seek actual damages of $250,000, a portion of the Company’s interest in the Pungarayacu field and other miscellaneous relief. The dispute is still in its early stages and arbitration proceedings, including discovery, have not yet commenced. 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
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 31, 2010, the closing prices of our common shares were Cdn$2.72 on the TSX and $2.72 on NASDAQ.

As at December 31, 2010, a total of 334,365,482 of our common shares were issued and outstanding and held by 203 holders of record with an estimated 22,700 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.

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 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 2011 is Cdn$312 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 brought forth certain 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$312 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, 2010 and 2009, which were not registered under the Act, have been detailed in previously filed Form 10-Qs and Form 8-Ks.

ITEM 6.		SELECTED FINANCIAL DATA

FIVE YEAR SUMMARY OF SELECTED FINANCIAL DATA

The financial data presented below has been revised to account for the sale of all of the Company’s US oil and gas exploration and production operations in 2009 as discontinued operations on a retroactive basis in accordance with generally accepted accounting principles (“GAAP”) in Canada. See Note 18 to the consolidated financial statements under Item 8 in this Annual Report.

($000s, except per share amounts)		2010				2009				2008				2007				2006
Results of Operations
Revenues			21,928				23,658				50,670				26,689				36,320
Net loss from continuing operations			(29,110	)			(37,731	)			(38,476	)			(33,433	)			(25,677	)
Net loss from continuing operations per share — basic and diluted			(0.09	)			(0.13	)			(0.15	)			(0.14	)			(0.11	)
Financial Position
Total assets			409,585				281,763				346,875				266,516				278,144
Debt			39,832				—				—				—				—
Long term debt			—				36,934				37,855				9,812				2,737
Asset retirement obligations			744				195				1,928				739				484
Long term obligation			1,900				1,900				1,900				1,900				1,900

RECONCILIATION TO US GAAP

Our consolidated financial statements have been prepared in accordance with GAAP in Canada, which differ in certain respects from those principles that we would have followed had our consolidated financial statements been prepared in accordance with GAAP in the US. The differences between Canadian and US GAAP, which affect our consolidated financial statements, are described in detail in Note 20 to our consolidated financial statements in this Annual Report. Had we followed US GAAP, certain selected financial information would have been reported as follows:

($000s, except per share amounts)		2010				2009				2008				2007				2006
Results of Operations
Revenues			36,945				17,152				55,335				27,281				35,628
Net loss from continuing operations			(10,271	)			(32,679	)			(47,911	)			(23,080	)			(35,477	)
Net loss from continuing operations per share — basic and diluted			(0.03	)			(0.12	)			(0.19	)			(0.10	)			(0.15	)
Financial Position
Total assets			393,675				262,717				292,847				251,627				252,893
Debt			40,217				—				—				—				—
Long term debt			—				38,005				40,392				10,412				2,737
Asset retirement obligations			744				195				1,928				739				484
Long term obligation			1,900				1,900				1,900				1,900				1,900

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

Executive Overview of 2010 Results			23
Highlights			24
Change in Net Loss			24
Results of Operations
Revenue			25
Netbacks			25
Operating Costs			26
General and Administrative			26
Business and Technology Development			26
Depletion and Depreciation			27
Foreign Exchange			27
Interest			27
Impairment			27
Derivatives			27
Income Taxes			28
Discontinued Operations			28
Liquidity and Capital Resources			28
Critical Accounting Principles and Estimates			30
New Accounting Pronouncements			32

The following MD&A should be read in conjunction with the consolidated financial statements for the year ended December 31, 2010. The consolidated financial statements have been prepared in accordance with GAAP in Canada. The impact of significant differences between Canadian and US GAAP on the consolidated financial statements is disclosed in Note 20 to the consolidated financial statements. The date of this discussion is March 4, 2010. Unless otherwise noted, tabular amounts are in thousands of US dollars. Oil and gas volumes and reserves and related measures are presented on a working interest, before royalties basis.

EXECUTIVE OVERVIEW OF 2010 RESULTS

Production decreased in 2010 compared to 2009 as Ivanhoe’s working interest at Dagang, China was reduced to 49% upon the Company recovering its development costs in 2009. Although realized prices in 2010 were higher than in the past year, overall oil revenue declined due to lower production volumes. Lower revenue in combination with higher general and administrative costs resulted in additional cash flow used in operating activities in 2010 compared to 2009.

The net loss from continuing operations in 2010 improved over the prior year as the result of non-cash items. Lower depletion expense and an unrealized foreign exchange gain compensated for the decrease in revenue, the elimination of a future income tax recovery and higher stock-based compensation costs.

Capital expenditures totaled $86.3 million in 2010. A 28 well winter delineation program was completed in March 2010 at Tamarack. With the information gathered from the drilling program, Ivanhoe filed a comprehensive Environmental Impact Assessment with the Government of Alberta in November 2010. In support of the application, Basic Engineering and Design and Front End Engineering and Design were completed to generate a Class III (+25/-20%) capital cost estimate.

Two wells were drilled in the Pungarayacu field on Block 20 in Ecuador. The IP-5b well was drilled, perforated in the Hollin oil sands and steam was successfully injected into the reservoir resulting in production of heated heavy oil. The Company’s initial well, IP-15, encountered cementing and completion problems during steam injection operations and testing at the well was suspended without recovering oil.

Gas was discovered at the Zitong-1 and Yixin-2 wells drilled in the Zitong Block in China. Following initial flow and pressure tests, both wells have been shut-in for pressure build-up. In Dagang, one well was drilling at year end and five fracture stimulations were performed during 2010. In the Nyalga basin of Mongolia, additional 2D seismic was acquired and preparations were made for a further 2D seismic program and a drilling program.

HIGHLIGHTS

($000, except as stated)		2010				2009				2008
Average production (bbls/d)			788				1,276				1,339
Realized oil prices ($/bbl)			75.52				53.60				98.73
Oil revenue			21,720				24,968				48,370
Cash flow provided by (used in) operating activities			(17,764	)			(12,290	)			17,053
Net loss (continuing operations(1))			(29,110	)			(37,731	)			(38,476	)
Net loss per share — basic and diluted (continuing operations(1))			(0.09	)			(0.13	)			(0.15	)
Working capital (continuing operations(1))			16,485				18,317				31,597
Capital expenditures (continuing operations(1))			86,285				26,373				21,063

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

CHANGE IN NET LOSS

The following quantifies year-over-year changes in the components of net loss realized in the years ended December 31, 2010, 2009 and 2008.

		2010				Change				2009				Change				2008
Cash items
Oil revenues			21,720								24,968								48,370
Production volumes							(9,515	)							(2,384	)
Oil prices							6,267								(21,018	)
Operating costs			(9,503	)			688				(10,191	)			11,324				(21,515	)
General and administrative, less stock-based compensation			(20,565	)			(2,563	)			(18,002	)			(6,198	)			(11,804	)
Business and technology development, less stock-based compensation			(10,215	)			(872	)			(9,343	)			(3,458	)			(5,885	)
Realized foreign exchange gain (loss)			(198	)			(87	)			(111	)			(346	)			235
Realized gain (loss) on derivatives			—				(124	)			124				4,554				(4,430	)
Net interest			184				485				(301	)			283				(584	)
Current income tax expense			(126	)			1,631				(1,757	)			(1,103	)			(654	)
Total cash changes			(18,703	)			(4,090	)			(14,613	)			(18,346	)			3,733
Non-cash items
Unrealized gain (loss) on derivatives			—				1,459				(1,459	)			(7,577	)			6,118
Unrealized foreign exchange gain (loss)			3,523				8,632				(5,109	)			(3,347	)			(1,762	)
Depletion and depreciation			(8,960	)			10,908				(19,868	)			5,893				(25,761	)
Stock-based compensation			(6,095	)			(2,246	)			(3,849	)			(833	)			(3,016	)
Provision for impairment of intangible asset and development costs			—				1,903				(1,903	)			13,151				(15,054	)
Write off of deferred financing costs			—				—				—				2,621				(2,621	)
Future income tax recovery			1,125				(8,475	)			9,600				9,600				—
Discontinued operations (net of tax)			—				23,921				(23,921	)			(28,204	)			4,283
Other			—				530				(530	)			(417	)			(113	)
Total non-cash changes			(10,407	)			36,632				(47,039	)			(9,113	)			(37,926	)
Net loss			(29,110	)			32,542				(61,652	)			(27,459	)			(34,193	)

RESULTS OF OPERATIONS

Revenue

		2010				2009				2008
Production
Asia (net bbls)
Dagang			273,868				452,573				471,817
Daqing			13,751				13,231				18,096
Total production			287,619				465,804				489,913
Average daily production (bbls/d)			788				1,276				1,339
Pricing
Average realized oil price ($/bbl)			75.52				53.60				98.73
West Texas Intermediate (WTI) ($/bbl)			79.39				61.80				99.65

2010 vs 2009

Oil revenue in 2010 was lower than in 2009 as a result of lower production volumes, despite higher realized prices in the current year. Production in 2010 decreased primarily as a result of Ivanhoe’s working interest in the Dagang field decreasing to 49% in September 2009. The Company received a 2010 production quota of 70,000 gross tonnes or approximately 680 bbls/d net. The Company took advantage of this quota situation and performed certain maintenance workovers that normally would have been delayed. Production quotas in 2011 are set at 80,000 gross tonnes or approximately 1,600 bbls/d gross.

Dagang production is sold at the three month rolling average price of Cinta crude, which historically averages $3.00/bbl less than West Texas Intermediate (“WTI”). Following the increase in Cinta crude prices in 2010, our realized oil prices rose compared to 2009.

2009 vs 2008

Due to the combination of lower production and realized prices, oil revenue was lower in 2009 than in 2008. Production in 2009 decreased from 2008 due to normal field declines which were partially offset by productivity increases from adding new perforations, fracture stimulations and water flood response. In addition, Ivanhoe’s working interest in the Dagang field decreased from 82% to 49% in September 2009 upon the Company recovering its development investments.

Realized oil prices decreased 46% per barrel in 2009 compared to the prior year, consistent with the decline in Cinta crude.

Netbacks

($/bbl)		2010				2009				2008
Oil revenue(1)			75.52				53.60				98.73
Less operating costs
Field operating			(19.96	)			(17.13	)			(21.70	)
Windfall Levy			(11.59	)			(4.00	)			(21.14	)
Engineering and support costs			(1.50	)			(0.75	)			(1.08	)
Net operating revenue(1)			42.47				31.72				54.81
Depletion			(29.87	)			(38.70	)			(47.22	)
Net revenue (loss) from operations(1)			12.60				(6.98	)			7.59

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

Operating Costs

2010 vs 2009

Operating costs on a per barrel basis rose in 2010, primarily as the result of an increase in the Windfall Levy administered in China due to higher realized oil prices in 2010 than in 2009. The Windfall Levy is imposed at progressive rates from 20% to 40% on the portion of the monthly weighted average sales price exceeding $40.00/bbl.

Higher field costs in 2010 also contributed to the increase in operating costs per barrel. Additional electrical and instrumentation costs were incurred in Dagang as we installed variable frequency drives on certain producing wells to assist in reducing future maintenance and power costs. Additional transportation, oil treatment and processing expenses were also incurred, as well as higher local office costs due to increased field activity.

2009 vs 2008

Operating costs on a per barrel basis, as well as in total, decreased in 2009 from the prior year due to lower field costs as well as a reduction in the Windfall Levy. Field operating costs in 2009 declined from 2008 as the result of decreased road and lease maintenance and workover costs, offset by higher oil treatment costs. Once key milestones in the Production Sharing Contract with CNPC were reached in September 2009, we incurred a smaller proportionate share of costs in 2009 and a decline in overall working interest. Had the Company paid a smaller proportionate share of costs in 2008 and the overall working interest had also been lower, field operating costs would have been $0.68/bbl lower in 2008. The Windfall Levy expense decreased in 2009 from the prior year since oil prices realized by the Company were lower in 2009.

General and Administrative

2010 vs 2009

General and administrative expenses (“G&A”) rose in 2010, primarily as a result of higher staff and office costs incurred with the Company’s growing commitments to its projects around the world. Staff and office costs increased $5.0 million in 2010 across all operating segments and corporate costs, such as stock exchange filing fees and non-cash stock-based compensation, increased by $1.8 million, which were offset by a decrease of $2.1 million in contract labour.

2009 vs 2008

In 2009, G&A rose in comparison to the prior period primarily as the result of higher costs in the corporate area and Ecuador. Corporate G&A rose $5.5 million in 2009 over 2008 due to incurring additional legal fees (see Item 3 to Part I of this Annual Report), corporate aircraft costs and personnel costs previously allocated to our US segment. These increases were partially offset by lower salary and benefit costs in 2009 due to the resignation of an executive in 2008, severance paid in 2008 and reallocating certain executive salaries to the Business and Technology Development segment. G&A for Ecuador were $1.6 million higher in 2009 as costs incurred prior to signing the contract to explore and develop Block 20 were minimal. G&A in China increased $0.8 million for 2009 over 2008 since a lower amount of G&A was allocated to capital projects in 2009. These increases were offset by a $0.5 million decrease in G&A incurred in Canada due to capitalizing costs related to the Tamarack property.

Business and Technology Development

2010 vs 2009

Business and technology development costs were higher in 2010 than in 2009. In 2010, the FTF was used to support basic and front-end engineering for a commercial-scale HTL™ plant for the Tamarack project in Canada and to support conceptual design for several projects, including Pungarayacu in Ecuador. Costs were also incurred in 2010 in connection with pursuing HTL^TM heavy oil and selected conventional oil opportunities in North and South America, the Middle East and North Africa.

2009 vs 2008

Business and technology development expenses increased in 2009 over 2008, as a result of the startup of the FTF, opening an office in Houston, the pursuit of financing initiatives in 2009, as well as the reallocation of certain executive salaries to the Business and Technology Development segment in late 2008.

Depletion and Depreciation

2010 vs 2009

Depletion and depreciation expense decreased in 2010 compared to 2009 due to lower depletion in Asia and reduced depreciation in the Business and Technology Development segment. Depletion in Asia was lower due to the combination of reduced production and higher proved reserves in China. We stopped depreciating the CDF at the end of 2009 when it was retired, lowering our depreciation expense in 2010.

2009 vs 2008

Ivanhoe’s depletion and depreciation expense in 2009 was lower than in 2008. Depletion in Asia decreased in 2009 as a result of an increase in proved reserves at our Dagang project in China as well as lower production in the current year. Additionally, our depreciation expense in the Business and Technology Development segment decreased in 2009 in comparison to the prior year as the depreciation expense associated with the FTF was lower than the depreciation expense incurred on the CDF.

Foreign Exchange

2010 vs 2009

The Company incurred a net foreign exchange gain in 2010 in comparison to a net foreign exchange loss in the prior year. In 2010, the Canadian dollar continued to strengthen relative to the US dollar resulting in a foreign exchange gain on the Cdn$150.0 million proceeds raised in our private placement in the first quarter of 2010, partially offset by a foreign exchange loss on our Canadian dollar debt.

2009 vs 2008

We incurred a foreign exchange loss primarily due to the translation of our Canadian dollar debt in 2009 and 2008. The loss was greater in 2009 than in 2008 due to the Canadian dollar strengthening relative to the US dollar.

Interest

2010 vs 2009

In the first quarter of 2010, the Company raised Cdn$150.0 million through a private placement. The short term investment of these funds earned interest income. Interest expense in 2010 was lower than in 2009 from the repayment of loan obligations associated with the Company’s China and US operations during the course of 2009.

2009 vs 2008

Interest expense in 2009 was lower in comparison to 2008 due to the repayment of debt. In 2008, we repaid a Cdn$12.5 million promissory note and $3.0 million against our bank loan for Asian operations.

Impairment

When the FTF was completed in 2009, we commenced the abandonment process for the CDF. The $0.9 million net asset value of the CDF was impaired. Additionally, $0.8 million of development costs related to the pursuit of projects in the Middle East were impaired in 2009.

In 2008, we impaired costs associated with our GTL project due to the lack of a definitive agreement and appropriate financing. Development costs of $5.1 million and intangible license costs of $10.0 million were written off.

The Company incurred costs associated with the pursuit of corporate financing initiatives by Sunwing. In the fourth quarter of 2008, this financing initiative was postponed indefinitely and therefore the associated costs were written down to nil.

Derivatives

In 2007, we entered into a costless collar derivative as required by the Company’s lenders to minimize variability in our cash flow. This derivative had a ceiling of $84.50/bbl and a floor of $55.00/bbl using the WTI as the index traded on the NYMEX. In December 2009, the Company repaid the outstanding loan balance and this derivative was subsequently cancelled.

The derivative instrument resulted in a loss to the Company in 2009, compared to a gain in 2008, due to movements in WTI. WTI reached record highs at the beginning of the third quarter of 2008 before steadily declining at the end of the fourth quarter to a level that was the lowest dating back several years. The low benchmark prices continued into the first half of 2009, recovering in the last half of the year.

Income Taxes

The Company’s income tax recovery was lower in 2010 than in 2009 due to a decrease in future taxes in the current year. Future taxes were significantly higher in 2009 due to the sale of the Company’s US oil and gas operations.

In 2009, current income taxes included a provision for taxes in Asia and a net adjustment of $1.0 million related to 2008 from changes in the minimum depreciation and amortization periods for oil and gas companies by the Chinese State Tax Administration Bureau. The future tax recovery in 2009 was driven by the sale of our US operating segment.

In 2008, current taxes were payable on Asian operations.

Discontinued Operations

In 2009, Ivanhoe sold its wholly owned subsidiary, Ivanhoe Energy (USA) Inc., disposing of all our oil and gas exploration and production operations in the US. The US operations have been accounted for as discontinued operations on a retroactive basis in accordance with Canadian GAAP and the results for 2009 and 2008 have been amended accordingly.

The operating results for the discontinued operations were as follows:

		2009				2008
Revenue
Oil and gas			5,455				18,120
Gain on derivative instruments			189				278
Interest			8				98
			5,652				18,496
Expenses
Operating			2,132				5,137
General and administrative			139				2,413
Depletion and depreciation			3,772				6,143
Interest and financing			173				520
			6,216				14,213
Income (loss) before disposition			(564	)			4,283
Loss on disposition (net of tax of $29.6 million for 2009, nil for 2008)			(23,357	)			—
Net income (loss) from discontinued operations			(23,921	)			4,283

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. Previous exploration commitments in Zitong and Nyalga have been fulfilled and therefore are not included below.

		Total				2011				2012				2013				2014				After 2014
Debt			39,832				39,832				—				—				—
Interest			2,042				2,042				—				—				—				—
Asset retirement obligations(1)			1,939				—				332				—								1,607
Long term obligation			1,900				—				—				—				—				1,900
Leases			2,989				1,769				885				335				—				—
Total			48,702				43,643				1,217				335				—				3,507

(1)		Represents undiscounted asset retirement obligations after inflation. The discounted value ($0.7 million) of these estimated obligations is provided for in the consolidated financial statements.

Debt

As described in Note 5 to the consolidated financial statements, the Company issued a Cdn$40.0 million convertible promissory note maturing in July 2011. The outstanding principal amount is convertible, at Talisman’s option, into a maximum of 12,779,552 Ivanhoe common shares at Cdn$3.13 per common share. Interest at the prime rate plus 2% is calculated daily and payable semi-annually. The estimated interest payments on the convertible promissory note are included in the above table.

Asset Retirement Obligations

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, 2010, we estimated the total undiscounted, inflated cost to settle our asset retirement obligations in Canada, Ecuador and the FTF in the US was $1.9 million. These costs are expected to be incurred between 2013 and 2038. Ivanhoe does not make such a provision for asset retirement costs in connection with its oil and gas operations in China as dry holes are abandoned as occurred and the Company is under no obligation to contribute to the future costs to restore well sites or abandon the field.

Long Term Obligation

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

Operating Leases

We have long term operating leases for office space, which expire between January 2011 and September 2013.

Other

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

The Company may provide indemnities to third parties, in the ordinary course of business, that are customary in certain commercial transactions, such as purchase and sale agreements. The terms of these indemnities will vary based upon the contract, the nature of which prevents Ivanhoe from making a reasonable estimate of the maximum potential amounts that may be required to be paid. The Company’s management is of the opinion that any resulting settlements relating to indemnities are immaterial.

In the normal course of business, we are subject to legal proceedings being brought against us. While the final outcome of these proceedings is uncertain, we believe that these proceedings, in the aggregate, are not reasonably likely to have a material effect on our financial position or results of operations.

Sources and Uses of Cash

The following table sets forth a summary of our cash flows from operating, investing and financing activities, as reported in the consolidated statements of cash flows.

		2010				2009				2008
Net cash provided by (used in) operating activities			(17,764	)			(12,290	)			17,053
Net cash provided by (used in) investing activities			(79,860	)			6,396				(49,321	)
Net cash provided by (used in) financing activities			138,286				(11,875	)			70,751

Operating Activities

2010 vs 2009

Operating activities in 2010 used more cash than in 2009 primarily as a result of lower oil revenue and higher G&A costs, partially offset by current tax savings. 2009 operating activities benefitted from net cash from discontinued operations. An increase in accounts payable, partially offset by changes in accounts receivable and income taxes, represented working capital cash in flows from operating activities in 2010 compared to an overall working capital outflow in 2009.

2009 vs 2008

Operating activities in 2009 resulted in a use of cash due to significantly lower revenue in 2009, in contrast to 2008 activities which generated cash inflows.

Investing Activities

2010 vs 2009

Net cash used for investing activities was higher in 2010 than in 2009 due to a more extensive capital program. Payables related to capital expenditures were higher at December 31, 2010, than the prior year, creating a source of working capital. In 2009, $35.3 million cash was generated from the sale of our US operating segment.

2009 vs 2008

In 2009, investing activities resulted in a net cash inflow due to the sale of the US operating segment. In comparison, $22.3 million was paid to acquire the Tamarack leases in 2008, and when combined with other capital expenditures, created a net cash outflow in 2008.

Financing Activities

2010 vs 2009

In 2010, financing activities raised $135.7 million of cash with the private placement of 50 million special warrants in February and March 2010 at a price of Cdn$3.00 per special warrant. Additional cash was raised through the exercise of stock options. The repayment of debt in 2009 resulted in a net cash outflow from financing activities.

2009 vs 2008

Financing activities in 2009 resulted in a net cash outflow due to the final debt repayment of long term notes and the repayment of a note associated with discontinued operations. In 2008, financing activities resulted in a net cash inflow due to a private placement in the third quarter and the receipt of cash from a Cdn$5.0 million loan.

Capital Structure

As at December 31,		2010				2009
Cash and cash equivalents			67,817				21,512
Debt			39,832				—
Long term debt			—				36,934
Shareholders’ equity			324,109				208,029

Ivanhoe intends to use its cash and cash equivalent balance to fulfill its commitments and partially fund operations in 2011. Cash flow from operating activities may be insufficient to meet operating requirements in the next 12 months and additional sources of funding, either at a parent company level or at a project level, will be required to grow the Company’s major projects and fully develop its oil and gas properties. Historically, Ivanhoe has used external sources of funding, such as public and private equity and debt markets. There is no assurance that we will be able to obtain additional financing on favorable terms, if at all, and any future equity issuances may be dilutive to our current investors. If we cannot secure additional financing, we may have to delay our capital programs and forfeit or dilute our rights in existing oil and gas property interests.

CRITICAL ACCOUNTING PRINCIPLES AND ESTIMATES

Our significant accounting policies may be found in Note 2 to the consolidated financial statements. Some of these policies involve critical accounting estimates because they require us 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 our critical accounting estimates and assumptions and how they affect the amounts reported in our consolidated financial statements.

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. 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 the results of operations.

Total proved reserves estimates are used to determine rates that are applied to each barrel of production in calculating our depletion expense. In 2010, depletion expense of $9.0 million was recorded. If our proved reserves estimates changed by 10%, our depletion and depreciation expense would have changed by approximately $0.6 million, assuming all other variables remained constant.

Impairment

Oil and Gas Properties and Development Costs

We periodically evaluate our oil and gas properties and development costs for impairment. Among other things, an impairment of these assets may be triggered by falling oil and gas prices, a significant negative revision to our reserve estimates, the inability to use our HTL™ technology in certain projects, changes in capital costs or the inability to raise sufficient financial resources to further develop the property. If one of these occurs, we assess if the undiscounted future net cash flows from proved reserves at future commodity prices plus the cost of undeveloped properties is less than the carrying value of the capitalized costs. If an impairment is found to exist, the impaired properties are written down to their fair value. The fair value of the assets is calculated based on future net cash flows from proved plus probable reserves, discounted at a risk-free interest rate using future commodity prices, plus the cost of undeveloped properties.

Cash flow estimates for our impairment assessments require assumptions about future prices and costs, reserves, discount rates and potential benefits from the application of our HTL™ technology. Given the significant assumptions required and the likelihood that actual conditions will differ, we consider the assessment of impairment to be a critical accounting estimate.

It is difficult to determine and assess how a decrease in proved reserves could impact our impairment tests. The relationship between our reserve estimates and the estimated undiscounted cash flows and the nature of the property-by-property impairment test is complex. As a result, we are unable to provide a reasonable sensitivity analysis of the impact that a reserve estimate decrease would have on our assessment of impairment.

Intangible Assets

Intangible assets consist of an exclusive, irrevocable license to deploy HTL™ technology our proprietary, patented heavy oil upgrading process. We periodically review the intangible 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. To determine if the intangible assets are impaired, we assess if the undiscounted future cash flows are in excess of the carrying value. If not, the assets are reduced to their fair value based on expected discounted future cash flows.

We believe that the intangible asset impairment is a critical accounting estimate because it requires management to make assumptions about competitive technological developments, the successful commercialization of our HTL™ technology and future cash flows from the HTL™ technology. We cannot predict if an event that triggers impairment will occur, when it will occur or how it will affect the asset amounts we have reported. Although we believe our estimates are reasonable and consistent with current conditions, internal planning and expected future operations, such estimates are subject to significant uncertainties and judgments.

Future Income Taxes

We operate in a specialized industry and in several tax jurisdictions. As a result, our 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 we 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 our tax assets and tax liabilities.

We estimate future income taxes based upon temporary differences between the assets and liabilities that we report in our consolidated financial statements and the tax basis of our assets and liabilities as determined under applicable tax laws. We record a valuation allowance against our future income tax assets when we believe, based on all available evidence, that it is not “more likely than not” that all of our future income tax assets recognized will be realized. The amount of the future income tax asset recognized and considered realizable could, however, be reduced if projected income is not achieved.

Convertible note liability

In connection with the acquisition of the Tamarack leases in July 2008 from Talisman, we issued a Convertible Note. The Convertible Note is a compound financial instrument, containing a debt instrument as well as an embedded conversion feature classified as equity. The residual basis method was used to value the instrument which means the fair value of the liability component was calculated and the remaining value was assigned to the equity component.

Management estimated the value of the liability component to be Cdn$37.9 million by discounting the expected interest and principal payments. The remaining value of Cdn$2.1 million was allocated to the equity component. If the interest rate used to discount the liability decreased by 1%, the amount of the Convertible Note originally recorded as a liability would increase by $1.0 million and the equity component would have been $1.0 million lower. Since the accretion of the liability component over the three year maturity period is capitalized on the balance sheet, there would not have been an impact on our operating results. Increasing the interest rate by 1% would have had the opposite, but equal, impact on our consolidated financial statements.

NEW ACCOUNTING PRONOUNCEMENTS

Transition to International Financial Reporting Standards

Effective January 1, 2011, we adopted International Financial Reporting Standards (“IFRS”) as our 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 balance sheet. 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.

As a foreign private issuer in the US, we will be permitted to file with the SEC consolidated financial statements prepared under IFRS without a reconciliation to US GAAP. The impact of this change is that we will no longer prepare a reconciliation of our results to US GAAP. It is possible that some of our accounting policies under IFRS could be different from US GAAP.

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 balance sheet 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 balance sheet 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 our 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 has elected to utilize this exemption such that transactions entered into prior to the transition date will not be restated.

Expected Areas of Significance

IFRS will have 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 exploration and evaluation (“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 income statement. Costs incurred in connection with our projects in Canada, Ecuador, Mongolia and exploration projects in China will be reclassified as E&E assets, while producing assets in China will continue to be classified as oil and gas properties and development costs on the consolidated balance sheet.
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 prohibits 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 were capitalized as oil and gas properties and development costs under Cdn GAAP. The threshold to capitalize G&A is higher under IFRS; therefore, we expect to capitalize less G&A in the future and G&A on the consolidated income statement 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 income statement. 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 Canadian 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 income statement in comparison to Cdn GAAP.

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.

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 we receive for our 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 our estimated 2011 production, a US$1.00/bbl change in the price of oil would increase or decrease net income and cash flows from operations for 2011 by US$0.82/bbl. In the past, we have used derivatives to minimize variability in our cash flow from operations when required to do so by loan covenants. However, no hedging contracts were in place in 2010 nor do we anticipate using hedging contracts in 2011 to manage our 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 2010 common share issuance in Cdn dollars. The Company did not enter into any foreign currency derivatives in 2010, nor do we anticipate using foreign currency derivatives in 2011. 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, assuming reasonably possible changes in the relevant foreign currency. This analysis assumes all other variables remain constant.

		10% Increase				10% Decrease
(Increase) Decrease in Net Loss and Comprehensive Loss		or Weakening				or Strengthening
Chinese renminbi			1,438				(1,758	)
Canadian dollar			(2,089	)			167

CREDIT RISK

Ivanhoe is exposed to credit risk with respect to its cash and cash equivalents, accounts receivable, note receivable, restricted cash and long term receivables. The Company’s maximum exposure to credit risk at December 31, 2010, 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, 85% of the outstanding accounts receivable balance at December 31, 2010 (December 31, 2009 — 94%) is due from a national oil corporation. Long term value-added tax receivable from Ecuador 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.

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 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 on favorable terms, if at all.

NON-GAAP FINANCIAL MEASURES

Oil revenue per barrel is calculated by dividing oil revenue by the Company’s total production for the respective periods presented. Net operating revenue per barrel is calculated by dividing oil revenue less operating costs by total production for the respective periods presented. Net revenue (loss) from operations per barrel is calculated by subtracting depletion from net operating revenue and dividing by total production for the respective periods presented. The Company believes oil revenue per barrel, net operating revenue per barrel and net revenue (loss) from operations per barrel are important to investors to evaluate operating results and the Company’s ability to generate cash. Each of the components used in these calculations can be reconciled directly to the 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			37
Consolidated Financial Statements
Consolidated Balance Sheets			38
Consolidated Statements of Loss and Comprehensive Loss			39
Consolidated Statements of Shareholders’ Equity			40
Consolidated Statements of Cash Flows			41
Notes to the Consolidated Financial Statements			42
Supplementary Disclosures About Oil and Gas Production Activities (Unaudited)			71

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, which comprise the consolidated balance sheets as at December 31, 2010 and 2009, and the consolidated statements of loss and comprehensive loss, shareholders’ equity and cash flows for each of the years in the three-year period ended 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 Canadian generally accepted accounting principles, 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, 2010 and 2009 and the results of their operations and cash flows for each of the years in the three-year period ended December 31, 2010 in accordance with Canadian generally accepted accounting principles.

Emphasis of Matter

Without qualifying our opinion, we draw attention to Note 2 in the financial statements which indicates that the Company had an accumulated deficit of $284.9 million and working capital of $16.5 million at December 31, 2010 and cash flow used in operating activities of $17.8 million and a net loss of $29.1 million during the year ended December 31, 2010. These conditions, along with other matters as set forth in Note 2, indicate the existence of a material uncertainty that may cast significant 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, 2010, 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 4, 2011 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ Deloitte & Touche LLP   Deloitte & Touche LLP
Independent Registered Chartered Accountants
Calgary, Canada
March 4, 2011

IVANHOE ENERGY INC.

Consolidated Balance Sheets
December 31, 2010 and 2009

(US$000s, except share amounts)		2010				2009
Assets
Current Assets
Cash and cash equivalents (Note 15)			67,817				21,512
Accounts receivable			6,359				5,021
Note receivable			264				225
Prepaid and other current assets			2,859				771
Restricted cash (Note 18)			500				2,850
			77,799				30,379
Oil and gas properties and development costs, net (Note 3)			237,200				158,392
Intangible assets (Note 4)			92,153				92,153
Long term receivables (Note 12)			2,433				839
			409,585				281,763
Liabilities and Shareholders’ Equity
Current Liabilities
Accounts payable and accrued liabilities (Note 12)			21,482				10,779
Debt (Note 5)			39,832				—
Income tax payable (Note 14)			—				530
Asset retirement obligations (Note 6)			—				753
			61,314				12,062
Long term debt (Note 5)			—				36,934
Asset retirement obligations (Note 6)			744				195
Long term obligation (Note 7)			1,900				1,900
Future income tax liability (Note 14)			21,518				22,643
			85,476				73,734
Commitments and contingencies (Note 7)
Going concern and basis of presentation (Note 2)
Shareholders’ Equity
Share capital, issued 334,365,482 common shares			550,562				422,322
December 31, 2009 282,558,593 common shares
Purchase warrants (Note 8)			33,423				19,427
Contributed surplus			22,983				20,029
Convertible note (Note 5)			2,086				2,086
Accumulated deficit			(284,945	)			(255,835	)
			324,109				208,029
			409,585				281,763

(See accompanying Notes to the Consolidated Financial Statements)

Approved on behalf of the Board:

(signed) “Robert M. Friedland” Director		(signed) “Brian F. Downey” Director

IVANHOE ENERGY INC.

Consolidated Statements of Loss and Comprehensive Loss
Three Years Ended December 31, 2010

(US$000s, except per share amounts)		2010				2009				2008
Revenue
Oil			21,720				24,968				48,370
Gain (loss) on derivative instruments			—				(1,335	)			1,688
Interest			208				25				612
			21,928				23,658				50,670
Expenses
Operating			9,503				10,191				21,515
General and administrative			26,260				21,693				14,252
Business and technology development			10,615				9,501				6,453
Depletion and depreciation			8,960				19,868				25,761
Foreign exchange (gain) loss			(3,325	)			5,220				1,527
Interest and financing			24				856				1,309
Impairment of intangible asset and development costs (Note 3)			—				1,903				15,054
Impairment of deferred financing costs (Note 13)			—				—				2,621
			52,037				69,232				88,492
Loss from continuing operations before income taxes			(30,109	)			(45,574	)			(37,822	)
(Provision for) recovery of income taxes (Note 14)
Current			(126	)			(1,757	)			(654	)
Future			1,125				9,600				—
			999				7,843				(654	)
Net loss — continuing operations			(29,110	)			(37,731	)			(38,476	)
Net (loss) income — discontinued operations (net of tax of $29.6 million for 2009, nil for 2008) (Note 18)			—				(23,921	)			4,283
Net loss and comprehensive loss			(29,110	)			(61,652	)			(34,193	)
Net loss per common share
Net loss — continuing operations, basic and diluted			(0.09	)			(0.13	)			(0.15	)
Net (loss) income — discontinued operations, basic and diluted			—				(0.09	)			0.02
Net loss per common share, basic and diluted			(0.09	)			(0.22	)			(0.13	)
Weighted average number of common shares
Basic and diluted (000s)			327,442				279,722				258,815

(See accompanying Notes to the Consolidated Financial Statements)

IVANHOE ENERGY INC.

Consolidated Statements of Shareholders’ Equity
Three Years Ended December 31, 2010

(US$000s)		2010				2009				2008
Common shares, beginning of year			422,322				413,857				324,262
Shares issued for cash, net of share issue costs (Note 8)			121,697				—				82,451
Shares issued for services			799				207				—
Shares issued for acquisition of a business, net of share issue costs (Note 17)			—				6,874				—
Exercise of stock options			5,735				1,384				1,792
Exercise of purchase warrants			9				—				—
Exercise of convertible debt			—				—				4,862
Shares issued for employee bonuses			—				—				490
End of year			550,562				422,322				413,857
Purchase warrants, beginning of year (Note 8)			19,427				18,805				23,078
Issuance of special warrants on private placement			13,999				—				—
Warrants issued for acquisition of a business			—				622				—
Exercise of purchase warrants			(3	)			—				—
Expiry of purchase warrants			—				—				(4,273	)
End of year			33,423				19,427				18,805
Contributed surplus, beginning of year			20,029				16,862				9,937
Stock-based compensation expense			6,894				3,659				3,239
Exercise of stock options			(3,940	)			(492	)			(587	)
Expiry of purchase warrants			—				—				4,273
End of year			22,983				20,029				16,862
Convertible note, beginning of year			2,086				2,086				—
Issuance of convertible note			—				—				2,086
End of year			2,086				2,086				2,086
Accumulated deficit, beginning of year			(255,835	)			(194,183	)			(159,990	)
Net loss and comprehensive loss			(29,110	)			(61,652	)			(34,193	)
End of year			(284,945	)			(255,835	)			(194,183	)