UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number: 000-30586

IVANHOE ENERGY INC.

(Exact name of registrant as specified in its charter)

Yukon, Canada (State or other jurisdiction of incorporation or organization)		98-0372413 (I.R.S. Employer Identification No.)
654-999 Canada Place Vancouver, British Columbia, Canada (Address of principal executive offices)		V6C 3E1 (Zip Code)

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

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 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. o Yes þ 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. (Check one):

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

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

As of June 30, 2009, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $346,054,578 based on the average bid and asked price as reported on the National Association of Securities Dealers Automated Quotation System National Market System.

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

Class		Outstanding at March 10, 2010
Common Shares, no par value		324,928,513 shares

DOCUMENTS INCORPORATED BY REFERENCE
None

 

 

TABLE OF CONTENTS

		Page
PART I
Items 1 and 2 Business and Properties			4
General			4
Corporate Strategy			6
Integrated Oil and Gas Properties			8
Conventional Oil and Gas Properties			8
Business and Technology Development			11
Certain Factors Affecting the Business			12
Employees			14
Production, Wells and Related Information			14
Item 1A Risk Factors			15
Item 1B Unresolved Staff Comments			22
Item 3 Legal Proceedings			22
Item 4 Reserved			22
PART II
Item 5 Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			23
Item 6 Selected Financial Data			25
Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations			27
Item 7A Quantitative and Qualitative Disclosures About Market Risk			52
Item 8 Financial Statements and Supplementary Data			55
Item 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			106
Item 9A Controls and Procedures			106
Item 9B Other Information			108
PART III
Item 10 Directors, Executive Officers and Corporate Governance			109
Item 11 Executive Compensation			113
Item 12 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			127
Item 13 Certain Relationships and Related Transactions, and Director Independence			128
Item 14 Principal Accounting Fees and Services			129
PART IV
Item 15 Exhibits, Financial Statement Schedules			130
Exhibit 10.4
Exhibit 10.20
Exhibit 21.1
Exhibit 23.1
Exhibit 23.2
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2
Exhibit 99.1

CURRENCY AND EXCHANGE RATES

Unless otherwise specified, all reference to “dollars” or to “$” are to U.S. dollars and all references to “Cdn.$” are to Canadian dollars. The closing, low, high and average noon buying rates in New York for cable transfers for the conversion of Canadian dollars into U.S. dollars for each of the five years ended December 31 as reported by the Federal Reserve Bank of New York were as follows:

		2009				2008				2007				2006				2005
Closing		$	0.96			$	0.82			$	1.01			$	0.86			$	0.86
Low		$	0.77			$	0.77			$	0.84			$	0.85			$	0.79
High		$	0.97			$	1.01			$	1.09			$	0.91			$	0.87
Average Noon		$	0.88			$	0.94			$	0.94			$	0.88			$	0.83

The average noon rate of exchange reported by the Bank of Canada for conversion of U.S. dollars into Canadian dollars on March 10, 2010 was $.98 ($1.00 = Cdn.$1.02 ).

ABBREVIATIONS

As generally used in the oil and gas business and in this Annual Report on Form 10-K, the following terms have the following meanings:

Bbl		= barrel
Bbls/d		= barrels per day
Bopd		= barrels of oil per day
Boe		= barrel of oil equivalent
Boe/d		= barrels of oil equivalent per day
MBbl		= thousand barrels
MBbls/d		= thousand barrels per day
Mboe		= thousands of barrels of oil equivalent
Mboe/d		= thousands of barrels of oil equivalent per day
MMBbl		= million barrels
MMBls/d		= million barrels per day
Mcf		= thousand cubic feet
Mcf/d		= thousand cubic feet per day
MMBtu		= million British thermal units
MMcf		= million cubic feet
MMcf/d		= million cubic feet per day

When we refer to oil in “equivalents”, we are doing so to compare quantities of oil with quantities of gas or express these different commodities in a common unit. In calculating Bbl equivalents (Boe), we use a generally recognized industry standard in which one Bbl is equal to six Mcf. Boes may be misleading, particularly if used in isolation. The conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

SELECT DEFINED TERMS

Ivanhoe Energy Inc. – “Ivanhoe Energy” or “Ivanhoe” or “the Company”

The Company’s proprietary, patented rapid thermal processing process (“RTP^TM Process”) for heavy oil upgrading (“HTL^TM Technology” or “HTL^TM”)

Syntroleum Corporation’s (“Syntroleum”) proprietary technology (“GTL Technology” or “GTL”) to convert natural gas into ultra clean transportation fuels and other synthetic petroleum products

United States Securities and Exchange Commission – “SEC”

Canadian Securities Administrators – “CSA”

The Securities Act of 1933 (the “Act”)

Enhanced oil recovery – “EOR”

Steam Assisted Gravity Drainage – “SAGD”

Memorandum of Understanding – “MOU”

Toronto Stock Exchange – “TSX”

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements in this document are “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, and Section 27A of the United States Securities Act of 1933, as amended. 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 oil upgrading 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 a limited number of what appear to be promising oil and gas exploration properties from larger, more well-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

Electronic copies of the Company’s filings with the SEC and the CSA are available, free of charge, through its web site (www.ivanhoeenergy.com) or, upon request, by contacting its investor relations department at (604) 688-8323. Alternatively, the SEC and the CSA each maintains a website (www.sec.gov and www.sedar.com) that contains the Company’s periodic reports and other public filings 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 on Form 10-K.

ITEMS 1 AND 2 BUSINESS AND PROPERTIES

GENERAL

Ivanhoe Energy 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^TM Technology. In addition, the Company also seeks to selectively expand its conventional oil and gas reserves base and production through conventional exploration and production activities, primarily in the Asia region. In the fourth quarter of 2009 the Company acquired a large, conventional oil exploration block in Mongolia’s Nyalga basin to complement the heavy oil properties acquired in 2008.

Core operations now include Canada, China, Mongolia and Ecuador, with continued business development opportunities worldwide.

Consistent with the Company’s intent to organize around geographically based subsidiaries, 2009 saw the addition of senior management talent allowing Canadian activities to organize as a separate subsidiary. The group structure now includes three subsidiaries with active field operations and one dedicated to business development activities. The subsidiaries with active field operations include the Asian subsidiary, Sunwing, with conventional oil production and conventional oil and gas exploration; the new Canadian subsidiary focusing on the Tamarack project and potential step-out opportunities in the Athabasca region; and the Latin American subsidiary focusing on the Pungarayacu field and other business development opportunities throughout Mexico, Central and South America. The Middle East remains an active area for the Company’s business development activities. Ivanhoe Energy Inc. owns 100% of each of these subsidiaries, although the percentages are expected to decline as they develop their respective businesses and raise capital independently.

The Company’s HTL^TM Technology Group operates a state-of-the-art HTL^TM testing facility in the Southwest Research Institute in San Antonio, Texas. The research facility and technology group hold dual roles in the Company. They pursue advancements in the HTL^TM technology, building and protecting the Company’s patent base, and support business development and project execution by upgrading sample heavy oils to lighter crudes to demonstrate the results available to projects employing the HTL^TM technology.

This organizational structure has allowed the Company to engage potential strategic investors in targeted discussions about specific assets and regional alliances. Discussions are ongoing.

The Company’s four reportable business segments are: Oil and Gas – Integrated, Oil and Gas – Conventional, Business and Technology Development and Corporate. Revenues, net income, capital expenditures and identifiable assets for these segments appear in Note 11 to the Consolidated Financial Statements.

On December 31, 2008, the SEC issued final rules relating to reserve definitions and related disclosure requirements. The rules are effective for estimates and disclosures made in annual reports on Form 10-K for fiscal years ended on or after December 31, 2009, including those in this report. The impact of the new rules on our reserves estimates also require us to modify our reserves disclosures this year to transition our reserves estimates from the old rules to the new rules. We have chosen to report our transition to the new rules in a manner that we believe best illustrates the impact of the changes on our reserves estimates and allows us to clearly present how our reserves estimates changed during 2009 as a result of our operational activities separate from the adoption of the new rules.

Oil and Gas

Integrated

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

Conventional

Post the sale of the Company’s U.S. operations it now explores for, develops and produces conventional crude oil and natural gas in China and Mongolia. The Company’s development and production activities are conducted at the Dagang oil field located in China’s Hebei Province and its exploration activities are conducted on the Zitong block located in Sichuan Province. In Mongolia the company is in the early exploration phase on Block XVI in the Nyalga basin, southeast of the capital Ulaanbaatar.

Business and Technology Development

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

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

Corporate

The Company’s corporate segment consists of costs associated with the board of directors, executive officers, corporate debt, financings and other corporate activities.

Our authorized capital consists of an unlimited number of common shares without par value and an unlimited number of preferred shares without par value.

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., and on June 24, 1999, we changed our name to Ivanhoe Energy Inc.

Our principal executive office is 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.

CORPORATE STRATEGY

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 replacement low cost reserves. This has resulted in volatility in oil markets and marked shifts in the demand and supply landscape. We believe 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 play an important role in Ivanhoe Energy’s 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 been increasingly more common. Refineries, on the other hand, have not been able to keep up with the need for deep conversion capacity, and heavy versus light oil price differentials have widened significantly.

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, although for profitable exploitation, key challenges remain, with varied weightings, project by project: 1) the requirement for steam and electricity to help extract heavy oil, 2) the need for diluent to move the oil once it is at the surface, 3) the heavy versus light oil price differentials that the producer is faced with when the product gets to market, and 4) conventional upgrading technologies 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

The Company’s application of the HTL^TM Technology seeks to address the four key heavy oil development challenges outlined above, and can do so at a relatively small minimum economic scale.

Ivanhoe Energy’s HTL™ upgrading is a partial upgrading process that is designed to operate in facilities as small as 10,000 to 30,000 barrels per day produced. 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 barrels per day produced. The Company’s HTL™ Technology 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, as processing times are 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. The Company’s HTL™ Technology has the added advantage of converting the byproducts 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:

	1.		Virtual elimination of external energy requirements for steam generation and/or power for upstream operations.
	2.		Elimination of the need for diluent or blend oils for transport.
	3.		Capture of the majority of the heavy versus light oil value differential.
	4.		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^TM 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 the Company will have to establish the Ivanhoe Energy value proposition.

Implementation Strategy

We are an oil and gas company with a unique technology which addresses several major problems confronting the oil and gas industry today and we believe that we have a competitive advantage because of our patented technology. In addition, because we have experienced thermal recovery teams, we are in a position to add value and leverage our technology advantage by working with partners on stranded heavy oil resources around the world.

The Company’s continuing strategy is as follows:

	1.		Build a portfolio of major HTLTM projects. Continue to deploy the personnel and the financial resources in support of our goal to capture additional opportunities for development projects utilizing the Company’s HTLTM Technology.
	2.		Advance the technology. Additional development work will continue to advance the technology through the first commercial application and beyond.
	3.		Enhance the Company’s financial position in anticipation of major projects. Implementation of large projects requires significant capital outlays. The Company is working on various financing plans and establishing the relationships required for the development activities of the future.
	4.		Build internal capabilities. During 2009, the Company added two key executives; one to take up the role of President and CEO of its Canadian subsidiary and one to fill the Corporate CFO role, vacated through retirement. In addition, the Company continued to build its internal technical capabilities through the addition of senior subsurface engineering talent as well as senior environmental leadership. These new staff will join existing execution teams as they advance the Company’s first HTLTM projects. The existing upstream teams consist of a number of experienced heavy oil petroleum engineers and geologists complemented by a core team of geotechnical experts. The Houston-based HTLTM technology team is built on a number of engineers that have an extensive background in chemical and petroleum refining, project engineering and the development and management of intellectual property. The Company expects to continue filling key positions as its projects advance.
	5.		Build the relationships needed for the future. Commercialization of the Company’s technologies demands close alignment with partners, suppliers, host governments and financiers.

INTEGRATED OIL AND GAS PROPERTIES

Tamarack Project

In July 2008, the Company announced the completion of the acquisition of Talisman Energy Canada’s (“Talisman”) 100% working interests in two leases (Leases 10 and 6) located in the heart of the Athabasca oil sands region in the Province of Alberta, Canada. Lease 10 is a 6,880-acre contiguous block located approximately ten miles (16 km) northeast of Fort McMurray. Lease 6 is a small, un-delineated, 680-acre block, one mile (1.6 km) south of Lease 10. Once the acquisition was complete the development of Lease 10 became known as the “Tamarack Project” or “Tamarack”.

The Tamarack Project will provide the site for the application of Ivanhoe Energy’s proprietary, HTL™ heavy oil upgrading technology in a major, integrated heavy oil project. Tamarack has a relatively high level of delineation (four wells per section). We believe that a high-quality reservoir is present and is an excellent candidate for thermal recovery utilizing the SAGD process. The high quality of the asset is expected to provide for favorable projected operating costs, including attractive steam-oil ratios (“SOR”) using SAGD development techniques.

The Company’s HTL^TM plants at Tamarack are projected ultimately to be capable of operating at production rates of approximately 50,000 barrels per day for approximately 25 years. The Company intends to integrate established SAGD thermal recovery techniques with its patented HTL upgrading process, producing and marketing a light, synthetic sour crude.

The Company has commenced planning its Project Tamarack development program in preparation for the submission of permits for an integrated HTL^TM project. In general, thermal oil sands projects, including SAGD projects, require a period of initial development, including delineation, permitting and field development, which is followed by relatively stable operations for many years.

Ecuador Project

In October 2008, Ivanhoe Energy Ecuador Inc., an indirect wholly owned subsidiary, signed a contract with the Ecuador state oil companies Petroecuador and Petroproduccion to explore and develop Ecuador’s Pungarayacu heavy oil field which is part of Block 20. Block 20 is an area of approximately 426 square miles, approximately 125 miles southeast of Quito, Ecuador’s capital.

Under this contract Ivanhoe Energy Ecuador will use the Company’s unique and patented HTL^TM Technology, as well as provide advanced oilfield technology, expertise and capital to develop, produce and upgrade heavy crude oil from the Pungarayacu field. In addition, Ivanhoe Energy Ecuador has the right to conduct exploration and appraisal for lighter oil in the contract area and to use any light oil that it discovers to blend with the heavy oil for delivery to Petroproduccion.

The contract has an initial term of 30 years and has three phases. The first two phases include the evaluation of the field’s production potential and the crude oil characteristics, as well as construction of the first HTL^TM plant. The third phase involves full field development and will include drilling additional exploration and development wells. Additional HTL^TM capacity will be added as necessary for expected production.

The Company was in the approval phase during the first half of 2009 which included obtaining environmental licenses. The Company succeeded in getting the necessary approvals and subsequently entered into the appraisal phase which would include obtaining permits to drill, undertaking seismic activity and drilling selected locations. Our analyses of old drilling core data from the Pungarayacu field suggest that there may be oil in the field that is lighter than the bitumen oil seeps that occur at the surface. During the drilling campaign undertaken more than 25 years ago, geologists on site reported that the oil in the drilling cores fluoresced colors indicative of lighter oil which would be inconsistent with bitumen. This coloration in other oil fields around the world is usually a sign of lighter oil. We will not be able to confirm this until we have results from our drilling and testing program currently underway.

To recover its investments, costs and expenses, and to provide for a profit, Ivanhoe Energy Ecuador will receive from Petroproduccion a payment of US$37.00 per barrel of oil produced and delivered to Petroproduccion. The payment will be indexed (adjusted) quarterly for inflation, starting from the contract date, using the weighted average of a basket of three U.S. Government-published producer price indices relating to steel products, refinery equipment and upstream oil and gas equipment.

CONVENTIONAL OIL AND GAS PROPERTIES

Following the disposition of our U.S. oil and gas assets, in California and Texas, (see Note 19 to the financial statements included in Item 8 in this Form 10-K), the Company’s principal oil and gas properties are located in the Hebei and Sichuan Provinces in China. Set forth below is a description of these properties.

The following table sets forth the estimated quantities of proved reserves and production attributable to our properties:

								Percentage				12/31/2009				Percentage of
				2009				of Total				Proved				Total Estimated
				Production				2009				Reserves				Proved
Property		Location		(in MBoe)				Production				(in MBoe)				Reserves
Dagang		Hebei Province, China			453				97	%			1,032				94	%
Other		China			13				3	%			69				6	%
Total					466				100	%			1,101				100	%

Internal Control over Reserve Reporting

Independent qualified reserves evaluators prepare reserve estimates for each property at least annually and issue a report thereon. The reserve estimates are reviewed by our in-house Senior Engineering Advisor (“SEA”) who is familiar with the property. Our SEA has over 30 years of experience working as a Reservoir Engineering Specialist/Advisor for various international oil companies. His primary responsibilities in these positions included evaluating and recommending well configuration and steaming strategy, conducting reservoir enhancement opportunity assessments and evaluation, simulation of reservoir, reservoir management, development and implementation of depletion strategies, evaluation gas reserves, formulating and implementing reservoir technology development programs, evaluating gas cycling recovery performance and developing surveillance tools and reservoir management programs. He holds a Bachelor’s Degree in Engineering Physics, University of Saskatchewan, Canada. He is a member of the Association of Professional Engineers, Geologists and Geophysicists of Alberta, the Society of Petroleum Engineers and Canadian Institute of Mining, Metallurgy and Petroleum. Our Board of Directors reviews the current reserve estimates and related disclosures as presented by the independent qualified reserves evaluators’ in their reserve reports with a recommendation for approval. 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 securities regulatory disclosures are prepared based on SEC disclosure requirements. In 2003, certain Canadian securities regulatory authorities adopted National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) which prescribes certain standards that Canadian companies are required to follow in the preparation and disclosure of reserves and related information. We applied for, and received, exemptions from certain NI 51-101 disclosure requirements based on our adherence to SEC disclosure requirements, which differ in certain respects from the prescribed disclosure standards of NI 51-101.

In 2008, as a result of the enactment of amendments to NI 51-101, we were required to re-apply for, and received, exemptions from certain of the amended 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 U.S. 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 reserves quantities disclosed in this Annual Report on Form 10-K represent net proved reserves calculated on an average, first-day-of-the-month price during the 12-month period preceding the end of the year for 2009, and year-end constant price basis for 2008 and 2007 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:

•

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

	•		the SEC mandates disclosure of proved reserves calculated using an average, first-day-of-the-month price during the 12-month period preceding and existing costs only; whereas NI 51-101 requires disclosure of reserves and related future net revenues using forecasted prices, with additional constant pricing disclosure being optional;
	•		the SEC mandates disclosure of reserves by geographic area only whereas NI 51-101 requires disclosure of more reserve categories and product types; and
	•		the SEC leaves the engagement of independent qualified reserves evaluators to the discretion of a company’s board of directors whereas NI 51-101 requires issuers to engage such evaluators.

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

China

•

Production and Development

Our producing property in China is a 30-year production-sharing contract with China National Petroleum Corporation (“CNPC”), covering an area of 10,255 gross acres divided into three blocks in the Kongnan oilfield in Dagang, Hebei Province, China (the “Dagang field”). Under the contract, as operator, we funded 100% of the development costs to earn 82% of the net revenue from oil production until cost recovery. Effective September 1, 2009 the project reached cost recovery and the working interests changed to 51% CNPC and 49% for the Company. Our entire interest in the Dagang field will revert to CNPC at the end of the 20-year production phase of the contract or if we abandon the field earlier.

In January 2004, we negotiated farm-out and joint operating agreements with Richfirst Holdings Limited (“Richfirst”) a subsidiary of China International Trust and Investment Corporation (“CITIC”) whereby Richfirst paid $20.0 million to acquire a 40% working interest in the field after Chinese regulatory approvals, which were obtained in June 2004. The farm-out agreement provided Richfirst with the right to convert its working interest in the Dagang field into common shares in the Company at any time prior to eighteen months after closing the farm-out agreement. Richfirst elected to convert its 40% working interest in the Dagang field and in February 2006 we re-acquired Richfirst’s 40% working interest.

From 2001 to the fourth quarter 2006 under the Petroleum Sharing Contract, we completed the pilot phase and entered the development phase and reached agreement with CNPC on a modified Overall Development Plan to reduce the scope of the development from 115 wells to 44 wells. The last 5 wells were drilled and placed on production in 2007. To date there has been 4,366 gross acres of a total of 12,097 acres relinquished through the terms of the contract. Commercial production commenced on January 1, 2009 as agreed by the parties following conversion of two wells to water injection for pressure maintenance purposes. Pursuant to the terms of the agreement, to the Company can recover from CNPC their share of operating costs, which is currently a 51% working interest.

No new development wells were drilled in 2009 or 2008. In 2009, we fracture stimulated 6 wells compared to 12 fracture stimulations in 2008. The year-end 2009 gross production rate was 1,660 Bopd compared to 1,700 Bopd at the end of 2008 and 1,900 Bopd at the end of 2007. We currently sell our crude oil at a three-month rolling average price of Cinta crude which historically averages approximately $3.00 per barrel less than West Texas Intermediate (“WTI”) price.

•

Exploration

In November 2002, we received final Chinese regulatory approval for a 30-year production-sharing contract (the “Zitong Contract”), with CNPC for the Zitong block, which covers an area of approximately 900,000 acres in the Sichuan basin. Under the Zitong Contract, we agreed to conduct an exploration program on the Zitong block consisting of two phases, each three years in length. The first three-year period was ultimately extended to December 31, 2007. The parties will jointly participate in the development and production of any commercially viable deposits, with production rights limited to a maximum of the lesser of 30 years following the date of the Zitong Contract 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 (“Mitsubishi”) for $4.0 million. The Company completed the first phase under the Zitong Contract (“Phase I”). This included reprocessing approximately 1,649 miles of existing 2D seismic data and acquiring approximately 705 miles of new 2D seismic data, and interpreting this data. This was followed by drilling two wells, totaling an aggregate of 22,293 feet. Both wells encountered expected reservoirs and gas was tested on the second well, but neither well demonstrated commercially viable flow rates and both have been suspended. The Company may elect to reenter these wells to stimulate or drill directionally in the future.

In December 2007, the Company and Mitsubishi (the “Zitong Partners”) made a decision to enter into the next three-year exploration phase (“Phase II”). By electing to participate in Phase II the Zitong Partners must relinquish 30%, plus or minus 5%, of the Zitong block acreage and complete a minimum work program involving the acquisition of approximately 200 miles of new seismic lines and approximately 23,700 feet of drilling (including the Phase I shortfall), with total gross remaining estimated minimum expenditures for this program of $23.1 million. The Phase II seismic line acquisition commitment was fulfilled in the Phase I exploration program. The Zitong Partners have no plans to acquire additional seismic data in Phase II. The Zitong Partners relinquished 15% of the Block acreage in 2008 and a further 10% was relinquished in 2009 to complete the end of the Phase I relinquishment requirement. The Zitong Partners contracted Sichuan Geophysical Company to conduct a complete review of the seismic data acquired to date on the block to select two Phase II drilling locations. Drilling is to commence in the second quarter of 2010 with expected completed drilling, completion and evaluation of the prospects finalized in late 2010. The Zitong Partners must complete the minimum work program or will be obligated to pay to CNPC the cash equivalent of the deficiency in the work program for that exploration phase. Following the completion of Phase II, the Zitong Partners must relinquish all of the remaining property except areas identified for development and future production. In the event of a discovery, the Zitong Partners believe it could be possible to negotiate to enter into a defined Phase III exploration commitment and ongoing development phase and reduce the amount of land relinquishment at this time.

Mongolia

•

Exploration

In November 2009, through a merger with PanAsian Petroleum Inc., a privately-owned corporation, the company acquired a Production-Sharing Contract (the “Nyalga contract”) for the Nyalga Block XVI in Mongolia. The block covers an area of approximately 4.2 million acres in the Khenti and Tov provinces and provides the Company with the exclusive rights to explore, develop and produce oil or gas within the block.

The exploration period is for five years in duration and consists of three phases of two years, one year and two years respectively, with the ability to nominate a two year extension following Phase I or Phase II. The minimum work obligations consist of $2.7 million for phase I, $1.0 million for phase II and $2.5 million for phase III. If in one year more than the minimum is expended, the excess can be applied to reduce the minimum expenditure in the next year of that phase. During the initial seismic a portion of the block, representing approximately 16% of the total, was declared by the Mongolian government to be a historical site and operations on that portion, being the Delgerkhaan area, were suspended. The Company received a letter from the Mineral Resources and Petroleum Authority of Mongolia (the “MRPAM”) in May 2008 which stated that the obligations under year one of phase one would be extended for one year from the time the Company is allowed access to the suspended area. To date access has not been allowed and discussions with MRPAM are ongoing. Seismic previously acquired has more than fulfilled the year obligation. The Company’s plans are to perform additional 2D seismic in the first quarter 2010, process and interpret the results and to spud an initial exploration well in the last quarter 2010.

BUSINESS AND TECHNOLOGY DEVELOPMENT

Heavy to Light Oil Upgrading

•

RTPTM License and Patents

In April 2005, the Company acquired all the issued and outstanding common shares of Ensyn Group, Inc. (“Ensyn”) whereby we acquired an exclusive, irrevocable license to Ensyn’s RTP^TM Process for all applications other than biomass. Since Ivanhoe acquired the HTL^TM technology, it has continued to expand its patent coverage to protect innovations to the HTL^TM Technology as they are developed and to significantly extend the Ivanhoe’s portfolio of HTL^TM intellectual property. In the United States, Ivanhoe is the assignee of three granted U.S. patents and currently has three U.S. patent applications pending. Ivanhoe also has multiple patent applications pending in numerous other countries. In addition, Ivanhoe owns exclusive, irrevocable licenses to patents, patent applications, and technology for the rapid thermal processing process of petroleum.

•

Commercial Demonstration Facility

In 2004, Ensyn constructed a Commercial Demonstration Facility (“CDF”) to confirm earlier pilot test results on a larger scale and to test certain processing options. This facility, acquired by the Company as part of the Ensyn merger, was built in the Belridge field, a large heavy oil field owned by Aera. In March 2005, initial performance testing of the CDF was completed successfully and the results of the test were verified by two large independent consulting firms. The CDF demonstrated an overall processing capacity of approximately 1,000 Bbls/d based on whole oil from the Belridge California heavy oil fields and a hot reaction section capacity of approximately 300 Bbls/d.

During 2007, technical developments were led by two important test runs at the CDF: a High Quality configuration was demonstrated on Belridge whole oil vacuum tower bottoms (“VTBs”) and a key test was successfully completed processing Athabasca bitumen pursuant to a longstanding technology development agreement with ConocoPhillips Canada Resources Corp. These two key tests were the capstones of the CDF test program and we have now fulfilled the primary technical objectives of the CDF. The goals of the test program were: (1) to confirm in a substantially large facility the key results generated in the early Ensyn pilot plant runs of heavy oil and bitumen which formed the basis of the HTL^TM intellectual property, and (2) to provide sufficient data for the design and construction of commercial HTL^TM plants.

The Athabasca bitumen CDF test provided important technical information related to the design of full-scale HTL^TM facilities. This test coupled with other test run data, correlated the performance of the CDF with earlier runs on the smaller scale pilot facility and validated the assumptions in Ivanhoe Energy’s economic models.

Ivanhoe Energy is currently decommissioning of this plant and completion is planned for end of second quarter 2010. All future test work will be carried out in the FTF.

•

Feedstock Test Facility

The Company initiated the construction of the Feedstock Test Facility (“FTF”) during 2008 and the unit was successfully commissioned in March 2009. The state-of-the-art HTL^TM testing facility is being used by Ivanhoe to support detailed engineering and design of commercial-scale HTL^TM plants for Ivanhoe’s Tamarack Project in Alberta, Canada, and Pungarayacu Project in Ecuador, and to test crudes associated with additional potential HTL^TM projects. The FTF was installed at Southwest Research Institute (“SwRI”) in San Antonio, Texas. SwRI is a world-class technology center that operates testing facilities for numerous leading oil companies, as well as other technology-intensive organizations such as NASA, the Department of Energy and the Department of Defense. The FTF is a small 10-15 Bbls/d, highly flexible state-of-the-art HTL^TM facility which will permit screening of global crude oil for current and potential partners in smaller volumes and at lower costs than required at the CDF. As we continue to advance our technology, this unit will form an integral part of the ongoing post-commercialization optimization of our products and processes. The FTF will provide additional data and will support the detailed engineering process once the first commercial target location and crude has been established. The FTF will also serve an integral part in supporting all of the Company’s commercial operations.

Business Development

The Company pursues HTL^TM 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. As part of this strategy to focus on stranded resources the Company has in the past pursued projects incorporating its non-exclusive master license entitling us to use Syntroleum’s proprietary GTL Technology to convert natural gas into ultra clean transportation fuels and other synthetic petroleum products in an unlimited number of projects with no limit on production volume. The Company’s master license expires on the later of April 2015 or five years from the effective date of the last site license issued to the Company by Syntroleum. No such site licenses have been issued to date. These two technologies have formed the basis for the Company’s business development activities in the Middle East. While discussions with various governments have at times reached advanced states, no definitive agreements have ever been signed. The Company continues to actively pursue business opportunities in the Middle East.

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 natural gas companies and other individual producers and operators, many of which have substantially greater financial and human resources and more developed and extensive infrastructure than we do. Our larger competitors, by reason of their size and relative financial strength, can more easily access capital markets than we can 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 than we can, adversely affecting our competitive position. Our competitors may be able to pay more for producing oil and natural gas properties and may be able to define, evaluate, bid for, and purchase a greater number of properties and prospects than we can. Further, these companies may enjoy technological advantages and may be able to implement new technologies more rapidly than we can. 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^TM 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. The Company is in the process of preparing a detailed regulatory application and Environmental Impact Assessment for submission to the Alberta Energy Resources Conservation Board and Alberta Environment. 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.

In April 2007, the Government of Canada announced its intent to introduce a set of regulations to limit emissions of greenhouse gas and air pollutants from major industrial facilities in Canada, although the details of the regulations have not been finalized. In the fall of 2009, the Government further expressed its intent that Canadian policy in this area be aligned with that of the U.S., which also remains under development. Consequently, attempts to assess the impact on our company are premature. We will continue to monitor the development of legal requirements in this area.

In the Province of Alberta, regulations governing greenhouse gas emissions from large industrial facilities came into effect July 1, 2007. These regulations cover industrial facilities emitting more than 100,000 tonnes (carbon dioxide equivalent) of greenhouse gas emissions annually and require a reduction by 12 percent in the greenhouse gas emissions per unit of production from each facility’s average annual intensity over the period 2003 through 2005. Allowed compliance measures include participation in an Alberta emission-trading system or payment (at a rate of $15 per excess tonne of emissions) to Alberta’s Climate Change and Emissions Management Fund. Impact on the overall operations of the company has not been material.

China 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.

Environmental Provisions

As at December 31, 2009, a $0.2 million provision for the removal of the FTF and $0.8 million for the removal of the CDF and restoration of the Aera site occupied by the CDF. The future cost of these obligations is estimated at $0.5 million and $0.8 million for the FTF and CDF, respectively. We do not make such a provision for our oil and gas production operations in China as there is no obligation on our part to contribute to the future cost to abandon the field and restore the site.

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 natural 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 both in the U.S., 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, 2009, we had 169 employees and consultants actively engaged in the business. None of our employees are unionized.

PRODUCTION, WELLS AND RELATED INFORMATION

See the “Supplementary Disclosures About Oil and Gas Production Activities (Unaudited)”, which follows the notes to our consolidated financial statements set forth in Item 8 in this Annual Report on Form 10-K, for information with respect to our oil and gas producing activities.

The following tables set forth, for each of the last three fiscal years, our average sales prices and average operating costs per unit of production based on our net interest after royalties. Average operating costs are for lifting costs (which include Windfall Levy) only and exclude depletion and depreciation, income taxes, interest, selling and administrative expenses.

		Average Sales Price												Average Operating Costs
		2009				2008				2007				2009				2008				2007
Crude Oil ($/Boe)
China		$	53.60			$	98.73			$	64.86			$	21.88			$	43.92			$	26.88

The following table sets forth the number of productive wells (both producing wells and wells mechanically capable of production) in which we held a working interest at the end of each of the last three fiscal years. Gross wells are the total number of wells in which a working interest is owned and net wells are the sum of fractional working interests owned in gross wells. All of our wells have multiple completions in different zones, but all completions for a well are in the same well bore hole.

		2009																2008																2007
		Oil Wells								Gas Wells								Oil Wells								Gas Wells								Oil Wells								Gas Wells
		Gross				Net				Gross				Net				Gross				Net				Gross				Net				Gross				Net				Gross				Net
China			44				21.6	(1)			—				—				44				36.1				—				—				44				36.1				—				—

The following two tables set forth, for each of the last three fiscal years, our participation in the completed drilling of net oil and gas wells:

Exploratory

		Productive Wells																								Dry Wells
		2009								2008								2007								2009								2008								2007
		Oil				Gas				Oil				Gas				Oil				Gas				Oil				Gas				Oil				Gas				Oil				Gas
China			—				—				—				—				—				—				—				—				—				—				—				0.9

Development

		Productive Wells																								Dry Wells
		2009								2008								2007								2009								2008								2007
		Oil				Gas				Oil				Gas				Oil				Gas				Oil				Gas				Oil				Gas				Oil				Gas
China			—				—				—				—				4.1				—				—				—				—				—				—				—

Wells in Progress

For our China operations, we had 2.0 net (4 gross) wells as at December 31, 2009, (3.3 net, 4 gross - 2008 and 3.3 net, 4 gross — 2007) which were either in the process of drilling or suspended.

Acreage

The following table sets forth our holdings of developed and undeveloped oil and gas acreage as at December 31, 2009. Gross acres include the interest of others and net acres exclude the interests of others:

		Developed Acres								Undeveloped Acres
		Gross				Net				Gross				Net
Canada			—				—				7,520				7,520
Ecuador			—				—				272,639				272,639
China (1)			1,490				730				664,348				595,355
Mongolia			—				—				4,161,422				4,161,422

Notes:

The Tamarack lease in Canada will expire in October 2016, but Ivanhoe has sufficient drill density to be granted a continuation by Alberta Department of Energy one year prior to the expiry or upon first production, whichever comes first. Although we expect to be on production in 2013, in the event the project is delayed we plan to apply for a continuation prior to the lease expiring.

Our contract in Ecuador to develop Block 20 is divided into three phases, appraisal, pilot and exploitation. Under the terms of the contract, at the end of the appraisal phase we are required to declare that (i) we believe that the portion of the block appraised can be commercial and (ii) we commit to move into the pilot phase. The commitment then is for the pilot phase which consists of an HTL plant and reaching a production capacity of a plateau production of +/-30,000 BOPD. If at the end of the pilot phase we elect to enter into the full field development, we will declare commerciality for the whole field and present our full field development plan. We have the right to only develop that portion of the field associated with the pilot and relinquish the balance of the block.

Our two production sharing agreements in China expire in 2027 and 2032. Also see Note 7 to the accompanying financial statements in Item 8 in this Form 10-K.

Our exploration production sharing contract in Mongolia has a term of five years of which we are still in the first year.

ITEM 1A. RISK FACTORS

We are subject to a number of risks due to the nature of the industry in which we operate, our reliance on strategies which include technologies that have not been proved on a commercial scale, the present state of development of our business and the foreign jurisdictions in which we carry on business. Some of the following statements are forward-looking and involve risks and uncertainties. Please refer to the “Special Note Regarding Forward-Looking Statements” set forth on page 4 of this Form 10-K. Our actual results may differ materially from the results anticipated in these forward-looking statements.

We may not be able to meet our substantial capital requirements

Our business is capital intensive and the advancement of our HTL™ project development initiatives in Canada and Ecuador will require significant investments in development activities. Our exploration projects in China and Mongolia will also require significant investments in order to progress as planned. Since our revenues from existing operations are insufficient to fund the capital expenditures that will be required to implement our HTL™ project development initiatives and carry out our planned exploration activities in China and Mongolia, we will need to rely on external sources of financing to meet our capital requirements. We have, historically, relied upon equity capital as our principal source of funding and we completed a significant equity financing transaction in the first quarter of 2010. It is likely that, in the future, we will need to obtain additional financing from external sources. Principal factors that could affect our ability to obtain financing from external sources include 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 the funding that we need when it is required, we may have to forego or delay 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. Our limited operating history may make it difficult to obtain future financing.

Our ability to continue as a going concern in the future may be adversely affected by a lack of access to adequate funding sources

Our financial statements have been prepared in accordance with Canadian generally accepted accounting principles applicable to a going concern, which assumes that we will continue in operation for the foreseeable future and will be able to realize our assets and discharge our liabilities in the normal course of operations. We have a history of operating losses and we currently anticipate incurring substantial expenditures to further our capital development programs. Our cash flow from operating activities will not be sufficient to both satisfy our current obligations and meet the requirements of our capital investment programs. Our continued existence is dependent upon our ability to obtain capital to meet our obligations, to preserve our interests in current projects and to meet the obligations associated with future projects. We intend to finance the future payments required for our capital projects 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. Public and private debt and equity markets may not be accessible now or in the foreseeable future and, as such, our ability to obtain financing cannot be predicted with certainty at this time. Without access to financing, we may not be able to continue as a going concern.

We have fixed and contingent payment obligations to Talisman Energy

We have certain future fixed and contingent payment obligations to Talisman Energy that arose as a result of our acquisition from Talisman Energy of our Athabasca heavy oil leases in 2008. These obligations include a Cdn.$40,000,000 convertible promissory note that, unless converted into Ivanhoe common shares, is due in July, 2011 and a contingent payment of up to Cdn.$15,000,000 that will become due and payable if and when the requisite governmental and other approvals to develop the northern border of one of the Athabasca heavy oil leases are obtained. As with the funds we require for our planned capital expenditures, 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 or at all and any future equity issuances may be dilutive to investors. Failure to obtain such additional financing could put us in default of our obligations to Talisman Energy, 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 shares we own in our subsidiaries. In the case of such default, Talisman Energy could foreclose on the secured assets, including the leases.

Our HTL™ projects in Canada and Ecuador are at a very early stage of development

Our HTL™ projects in Canada and Ecuador are at varying stages of development. Although we have completed a significant amount of engineering work for the HTL™ project, we plan to establish on our Athabasca heavy oil leases in Canada and, additional engineering work will be required before we can initiate the process of applying for the regulatory approvals required in order to advance to the next stage of the development process. Our Block 20 project in Ecuador is currently at a very early stage of development and no detailed feasibility or engineering studies have yet been produced. There can be no assurances that either or both of 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.

Heavy oil exploration and development involves increased operational risks

Oil sands and heavy oil exploration and development are very competitive and involve many risks that even a combination of experience, knowledge and careful evaluation may not be able to overcome. As with any petroleum property, there can be no assurance that commercial quantities of economically marketable oil will be produced. The viability and marketability of any production from the properties may be affected by factors and circumstances beyond our control, fluctuations in the market price of oil, proximity and capacity of pipelines and processing equipment, electricity transmission and distribution systems, transportation arrangements, equipment availability and government regulations (including regulations relating to prices, taxes, royalties, land tenure, allowable production, importing and exporting of oil and gas and environmental protection). The extent to which some or all of these factors will affect our business cannot be accurately predicted. If our proposed HTL™ projects in Canada and Ecuador are developed and become operational, there is no assurance that they will attain production in any specific quantities or within any defined cost framework, or that they will not cease producing entirely in certain circumstances. Because operating costs for production from oil sands and heavy oil fields may be substantially higher than operating costs to produce conventional crude oil, an increase in such costs may render the development and operation of these projects uneconomical. It is possible that other developments, such as increasingly strict environmental and safety laws and regulations and enforcement policies thereunder and claims for damages to property or persons resulting from the operations, could result in substantial costs and liabilities, delays or an inability to complete the proposed project or the abandonment of the proposed project.

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

Current SAGD technologies for in-situ recovery of heavy oil and bitumen are energy intensive, requiring significant consumption of natural gas and other fuels in the production of steam which is 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 this 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 might not successfully commercialize our technology, and commercial-scale HTL^TM plants based on our technology may never be successfully constructed or operated

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. No commercial-scale HTL™ plant based on our technology has been constructed to date and we may never succeed in doing so. Other developers of competing heavy oil upgrading technologies may have significantly more financial resources than we do and may be able to use this to obtain a competitive advantage. Success in commercializing our HTL™ technology depends on our ability to economically design, construct and operate commercial-scale plants and a variety of factors, many of which are outside our control. We currently have insufficient resources to manage the financing, design, construction or operation of commercial-scale HTL™ plants, and we may not be successful in doing so.

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

We regularly enter into confidentiality agreements with third parties in order to facilitate discussions respecting potential business relationships through the exchange of confidential information. A breach by a third party of an obligation of confidentiality could put us at competitive risk and may cause significant damage to our business if confidential operating information or proprietary intellectual property is improperly disclosed. The harm to our business that improper disclosure of confidential operating information or proprietary intellectual property may cause cannot presently be quantified but may be significant and may not be compensable in damages. There is no assurance that, in the event of a breach of a confidentiality obligation, we will be able to obtain equitable remedies, such as injunctive relief, from a court of competent jurisdiction in a timely manner or at all in order to prevent or mitigate any damage to our business that such a breach of confidentiality might cause.

Our efforts to commercialize our HTL™ Technology may give rise to claims of infringement upon the patents or 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 rights of others in this technology until after we have made a substantial investment in the development and commercialization of projects utilizing it. Third parties may claim that the technology infringes upon past, present or future patented technologies. Legal actions could be brought against the licensor and us 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.

Technological advances could significantly decrease the cost of upgrading heavy oil and, if we are unable to adopt or incorporate technological advances into our operations, our HTL^TM Technology could become uncompetitive or 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 occur. It is possible that those advances could make the processes and procedures, which are integral to the HTL™ Technology that we are seeking to commercialize, less efficient or cause the upgraded product being produced to be of a lesser quality. These advances could also allow competitors to produce upgraded products at a lower cost than that at which our HTL™ Technology is able to produce such products. If we are unable to adopt or incorporate technological advances, our production methods and processes could be less efficient than those of our competitors, which could cause our HTL™ Technology facilities to become uncompetitive.

The development of alternate sources of energy could lower the demand for our HTL™ Technology

Alternative sources of energy are continually under development and those that can reduce reliance on oil and bitumen may be developed, which may decrease the demand for our HTL™ Technology upgraded product. It is also possible that technological advances in engine design and performance could reduce the use of oil and bitumen derived products, which would lower the demand for our HTL™ Technology upgraded product.

The volatility of oil prices may affect our financial results

Our revenues, operating results, profitability and future rate of growth are highly dependent on the price of, and demand for, 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.

The price of oil may fluctuate widely in response to relatively minor changes in the supply of and demand for oil, 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 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, 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. Declines in oil prices would not only reduce our revenues, but could reduce the amount of oil we can economically produce. This may result in our having to make substantial downward adjustments to our estimated proved reserves and could have a material adverse effect on our financial condition and results of operations. In addition, a substantial long-term decline in oil prices would severely impact our ability to execute a heavy oil development program.

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

Under generally accepted accounting principles in Canada and the U.S. 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 of Proved Oil and Gas Properties” in Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report.

Our ability to monetize non-core assets and replace revenues generated from any sale of our existing properties depends upon market conditions and numerous uncertainties

We continue to explore opportunities to generate capital for the ongoing development of our core HTL™ business, which may involve efforts to monetize non-core assets used in other areas of our business, including our exploration, development and production assets in China. There can be no assurance that we will sell or otherwise monetize any such assets nor that any such sale or monetization initiative, if and when made, will generate sufficient capital for the ongoing development of our core HTL™ business. Our operating revenues and cash flows would likely decrease significantly following the sale of any material portion of our existing producing assets and would likely remain at lower levels until we were able to replace the lost production with production from new properties.

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 Energy 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 or at all.

Aboriginal peoples have claimed aboriginal title and rights to large areas of land in western Canada where crude oil and natural 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 significant 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 to the Block 20 agreement comply with the dispute resolution provisions of the Block 20 agreement or otherwise voluntarily submit to arbitration.

Government policy in Ecuador may change to discourage foreign investment or requirements not currently 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.

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. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment and the assumptions used regarding prices for oil and natural gas, production volumes, required levels of operating and capital expenditures, and quantities of recoverable oil reserves. Oil prices have fluctuated widely in recent years. Volatility is expected to continue and price fluctuations directly affect estimated quantities of proved reserves and future net revenues. Actual prices, production, development expenditures, operating expenses and quantities of recoverable oil reserves will vary from those assumed in our estimates, and these variances may be significant. Also, we make certain assumptions regarding future oil prices, production levels, and operating and development costs that may prove incorrect. 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 natural gas and oil prices after the date of the estimate may result in revisions to our reserve estimates. Revisions to prior estimates may be material.

No reserves have yet been established in respect of our HTL™ projects in Canada and Ecuador

No reserves have yet been established in respect of our Athabasca heavy oil project in Canada or our Block 20 project in Ecuador. There are numerous uncertainties inherent in estimating reserves, including many factors beyond our control and no assurance can be given that any level of reserves or recovery thereof will be realized. In general, estimates of reserves are based upon a number of assumptions made as of the date on which the estimates were determined, many of which are subject to change and are beyond our control.

Information in this document 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 availability and cost of capital; receipt of 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 and personnel; success or failure of activities in similar areas; changes in estimates of project completion costs; our ability to attract other industry partners to acquire a portion of the working interest to reduce costs and exposure to risks and decisions of our joint working interest owners.

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. You should understand that our plans regarding our projects might change.

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.

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 economic return. We may misinterpret geologic or engineering data, which may result in significant losses on 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 costs of production or otherwise adversely affect our ability to realize an acceptable level of economic return on a particular project in a timely manner or at all.

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

There are hazards and risks inherent in drilling for, producing and transporting oil and gas. These hazards and risks may result in loss of hydrocarbons, environmental pollution, personal injury claims, and other damage to our properties and third parties and include 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.

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.

Changes to laws, regulations and government policies in Canada or Ecuador could adversely affect our ability to develop our HTL™ projects

Our HTL™ projects in Canada and Ecuador are subject to substantial regulation relating to the exploration for, and the development, production, upgrading, marketing, pricing, taxation, and transportation of bitumen and heavy oil and related products and other matters, including environmental protection.

Legislation and regulations may be changed from time to time in response to economic or political conditions. The exercise of discretion by governmental authorities under existing legislation and regulations, the implementation of new legislation or regulations or the amending of existing legislation and regulations affecting the crude oil and natural gas industry generally could materially increase the costs of developing these projects and could have a material adverse impact on our business. There can be no assurance that laws, regulations and government policies relevant to these 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 the projects and increased 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 governmental 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 stopped. There is no assurance 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 the projects.

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

Our operations are governed by numerous laws and regulations at various levels of government in the countries in which we operate. Oil sands and heavy oil extraction, upgrading and transportation operations are subject to extensive regulation and 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 on 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.

Under these 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 on properties, if environmental damage occurs.

The costs of complying with environmental laws and regulations in the future may harm our business. Furthermore, future changes in environmental laws and regulations could occur that 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 on our ability to develop or operate our projects in a manner consistent with our current expectations.

During 2007 and 2008, the federal government of Canada proposed a regulatory framework and plan for the reduction of Canada’s total greenhouse gas emissions from 2006 levels by 20% by 2020 and by 60% to 70% by 2050. Other approaches to reducing greenhouse gases, including a North America-wide cap and trade system have also been proposed. The potential extent and magnitude of any adverse impacts of these proposals cannot be reliably or accurately estimated at this time because specific legislative and regulatory requirements have not been implemented and uncertainty exists with respect to which, if any, of the proposals being considered will ultimately be implemented. In the Province of Alberta, where our Tamarack project is located, the Climate Change and Emissions Management Act has a targeted specified gas emission target relative to Alberta’s gross domestic product to an amount that is equal to or less than 50% of 1990 levels.

The future federal industrial air pollutant and greenhouse gas emission reduction targets, together with provincial emission reduction requirements in Alberta’s Climate Change and Emissions Management Act, or emission reduction requirements in future regulatory approvals, may not be technically or economically feasible to implement and the failure to meet such emission intensity reduction requirements or other compliance mechanisms may materially adversely affect our ability to develop and operate the Tamarack project and result in fines, penalties and the suspension of operations. As well, equipment from suppliers which can meet future emission standards may not be available on an economic basis and other compliance methods of reducing emission intensity to required levels in the future may significantly increase our capital and operating costs or reduce output of the project. We may not be able for technical or economic reasons to take advantage of incentives to implement certain capture and storage. Emission reduction or off-set credits may not be available for acquisition by the Tamarack project or may not be available on an economic basis. There is also the risk that governments could impose additional emission or emission intensity reduction requirements or pass legislation which would tax such emissions.

No assurance can be given that environmental laws will not result in a curtailment of project development or a material increase in the costs of production, development or exploration activities or otherwise adversely affect our financial condition, results of operations or prospects.

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

We operate in a highly competitive environment in which we compete with other exploration and development companies to acquire a limited number of prospective oil and gas properties. Many of our competitors are much larger than we are and, as a result, may enjoy a competitive advantage in accessing financial, technical and human resources. They may be able to pay more for productive oil and gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial, technical and human resources permit.

Our principal shareholder may significantly influence our business

As at the date of this Annual Report, our largest shareholder, Robert M. Friedland, owned approximately 15.9% 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 you that these individuals will remain with us in the future. An unexpected partial or total loss of their services would harm our business.

Development of our heavy oil projects in Canada and Ecuador will require the recruitment and retention of experienced employees. We compete with other companies to recruit and retain the limited number of individuals who possess the requisite skills and experience in the particular areas of expertise 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 all of the employees with the necessary abilities and expertise we require will be available.

ITEM 1B. UNRESOLVED STAFF COMMENTS

We have no unresolved staff comments from the SEC staff regarding our periodic or current reports filed under the Act.

ITEM 3. LEGAL PROCEEDINGS

The Company is a defendant in a lawsuit filed November 20, 2008 in the United States District Court of Colorado by Jack J. Grynberg and three affiliated companies that alleges bribery and other misconduct and challenges 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. Plaintiffs’ claims are for unspecified damages or ownership of Ivanhoe Energy Ecuador Inc.’s interest in the Pungarayacu field.

All defendants filed motions to dismiss the lawsuit for lack of personal jurisdiction. The Court granted the motions, noted its view that plaintiffs’ claims are not likely to have merit, and dismissed the case without prejudice. The Court granted the request of defendant Robert M. Friedland to sanction the plaintiffs and the plaintiffs’ counsel for their conduct related to bringing the suit by awarding Mr. Friedland fees and costs. The defendants comprising the Company and its subsidiaries were awarded their costs in defending the suit. All defendants are now in the process of seeking an award of their attorney fees and costs.

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. The defendants have filed their opposition and the plaintiffs have filed their reply, and the motion is now ready for decision by the Court. The Court has not yet announced a hearing date or indicated when the motion will be resolved. The likelihood of loss or gain resulting from the lawsuit, and the estimated amount of ultimate loss or gain, are not determinable or reasonably estimable at this time.

ITEM 4. RESERVED

PART II

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

Market Information

Our common shares trade on the NASDAQ Capital Market and the TSX. The high and low sale prices of our common shares as reported on the NASDAQ and TSX for each quarter during the past two years are as follows:

NASDAQ CAPITAL MARKET (IVAN)
(U.S.$)

		2009																2008
		4th Qtr				3rd Qtr				2nd Qtr				1st Qtr				4th Qtr				3rd Qtr				2nd Qtr				1st Qtr
High			3.12				2.81				1.85				1.22				1.43				3.51				3.77				1.97
Low			2.02				1.13				1.10				0.45				0.35				1.21				1.79				1.24

TSX (IE)
(CDN$)

		2009																2008
		4th Qtr				3rd Qtr				2nd Qtr				1st Qtr				4th Qtr				3rd Qtr				2nd Qtr				1st Qtr
High			3.25				2.98				2.16				1.53				1.53				3.37				3.85				1.99
Low			2.20				1.31				1.38				0.57				0.43				1.28				1.82				1.27

On December 31, 2009, the closing prices for our common shares were $2.86 on the NASDAQ Capital Market and Cdn. $2.96 on the TSX.

Exemptions from Certain NASDAQ Marketplace Rules

As a Canadian issuer listed on the NASDAQ Stock Market (“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 Securities Exchange Act of 1934; and (iv) we must provide a brief description of any significant differences between our corporate governance practices and those followed by U.S. 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 non-management directors hold meetings from time to time as and when considered necessary or desirable by the independent lead 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 on Form 10-K reside outside the U.S. and a substantial portion of their assets and our assets are located outside the U.S. As a result, it may be difficult for you to effect service of process within the U.S. upon the directors, controlling shareholders, officers and representatives of experts who are not residents of the U.S. or to enforce against them judgments obtained in the courts of the U.S. based upon the civil liability provisions of the federal securities laws or other laws of the U.S. 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 U.S., in original actions or in actions for enforcement of judgments of U.S. courts, of liabilities based solely upon civil liability provisions of the U.S. 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 on Form 10-K.

Holders of Common Shares

As at December 31, 2009, a total of 282,558,593 of our common shares were issued and outstanding and held by 233 holders of record with an estimated 29,328 additional shareholders whose 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.

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) (a “Cultural Business”) 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. 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 2010 is Cdn.$299 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 recently 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.$299 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 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 you as dividends in respect of the common shares you hold at a time when you are 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-U.S. 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 U.S. resident that is entitled to the benefits of the Convention is generally 15%. However, if the beneficial owner of such dividends is a U.S. 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 U.S. 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 on Form 10-K.

Performance Graph

See table under “Executive Compensation” set forth in Item 11 in this Annual Report on Form 10-K.

Sales of Unregistered Securities

All securities we issued during the years ended December 31, 2009 and 2008, which were not registered under the Act, have been detailed in previously filed Form 10-Qs and Form 8-Ks.

During the year ended December 31, 2007, we issued securities, which were not registered under the Act of, as follows:

•

in November 2007, we issued 2,000,000 common shares under Rule 903 of the Act at a price of U.S.$2.00 to an institutional investor pursuant to the exercise of previously issued share purchase warrants.

ITEM 6. SELECTED FINANCIAL DATA

The selected financial data set forth below are derived from the accompanying financial statements, which form part of this Annual Report on Form 10-K. The financial statements have been prepared in accordance with generally accepted accounting principles (“GAAP”) applicable in Canada. See Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 21 to our financial statements in this Annual Report on Form 10-K for a detailed description of the differences between GAAP applicable in Canada and GAAP applicable in the U.S. as it relates to the Company.

The following table shows selected financial information for the years indicated:

		December 31
		2009				2008				2007				2006				2005
		(stated in thousands of US dollars, except per share amounts)
Results of Operations
Revenues			23,658				50,670				26,689				36,320				15,965
Net loss from continuing operations			(37,731	)			(38,476	)			(33,433	)			(25,677	)			(15,983	)
Net loss from continuing operations
per share — basic and diluted			(0.13	)			(0.15	)			(0.14	)			(0.11	)			(0.08	)
Financial Position
Total assets			281,763				346,875				266,516				278,144				270,477
Long-term debt			36,934				37,855				9,812				2,737				4,000
Asset retirement obligations — long term			195				1,928				739				484				100
Long term obligation			1,900				1,900				1,900				1,900				1,900
Shareholders’ equity			208,029				257,427				197,287				228,386				204,767
Common shares outstanding (in thousands)			282,559				279,381				244,874				241,216				220,779
Cash Flow
Cash flow provided by (used in) operating activities			(12,290	)			17,053				5,489				14,352				9,870
Capital investments (continuing operations)			(26,373	)			(21,063	)			(28,585	)			(12,296	)			(36,741	)

Reconciliation to U.S. GAAP

Our financial statements have been prepared in accordance with GAAP applicable in Canada, which differ in certain respects from those principles that we would have followed had our financial statements been prepared in accordance with GAAP in the U.S. The differences between Canadian and U.S. GAAP, which affect our financial statements, are described in detail in Note 21 to our financial statements in this Annual Report on Form 10-K.

Had we followed U.S. GAAP certain selected financial information reported above, in accordance with Canadian GAAP, would have been reported as follows:

		December 31
		2009				2008				2007				2006				2005
		(stated in thousands of US dollars, except per share amounts)
Results of Operations
Revenues			17,152				55,335				27,281				35,628				18,831
Net loss from continuing operations			(32,679	)			(47,911	)			(23,080	)			(35,477	)			(13,773	)
Net loss from continuing operations
per share — basic and diluted			(0.12	)			(0.19	)			(0.10	)			(0.15	)			(0.07	)
Financial Position
Total assets			262,717				292,847				251,627				252,893				254,335
Long-term debt			38,005				40,392				10,412				2,737				4,000
Asset retirement obligations — long term			195				1,928				739				484				100
Long term obligation			1,900				1,900				1,900				1,900				1,900
Shareholders’ equity			179,663				199,741				170,545				189,829				188,745
Cash Flow
Cash flow provided by (used in) operating activities			(12,441	)			16,639				11,501				13,340				5,042
Capital investments (continuing operations)			(26,223	)			(20,649	)			(28,319	)			(11,280	)			(31,913	)

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

TABLE OF CONTENTS

		Page
Ivanhoe Energy’s Business			27
Executive Overview of 2009 Results			28
Financial Results – Year to Year Change in Net Loss			30
Revenues and Operating Costs			31
General and Administrative			33
Business and Technology Development			34
Foreign Exchange			34
Net Interest			34
Unrealized Gain (Loss) on Derivative Instruments			34
Depletion and Depreciation			35
Provision for Impairment of Intangible Assets and Development Costs			35
Write-off of Deferred Financing Costs			36
Provision for Impairment of Oil and Gas Properties			36
Net income (loss) from Discontinued Operations			36
Financial Condition, Liquidity and Capital Resources			38
Sources and Uses of Cash			38
Outlook for 2010			41
Contractual Obligations and Commitments			41
Critical Accounting Principles and Estimates			41
2009 Accounting Changes			44
Impact of New and Pending Canadian GAAP Accounting Standards			45
Convergence of Canadian GAAP with International Financial Reporting Standards			46
Impact of New and Pending U.S. GAAP Accounting Standards			49
Off Balance Sheet Arrangements			51
Related Party Transactions			52

THE FOLLOWING SHOULD BE READ IN CONJUNCTION WITH THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED DECEMBER 31, 2009. THE CONSOLIDATED FINANCIAL STATEMENTS HAVE BEEN PREPARED IN ACCORDANCE WITH GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (“GAAP”) IN CANADA. THE IMPACT OF SIGNIFICANT DIFFERENCES BETWEEN CANADIAN AND U.S. GAAP ON THE FINANCIAL STATEMENTS IS DISCLOSED IN NOTE 21 TO THE CONSOLIDATED FINANCIAL STATEMENTS.

OUR DISCUSSION AND ANALYSIS OF OUR OIL AND GAS ACTIVITIES WITH RESPECT TO OIL AND GAS VOLUMES, RESERVES AND RELATED PERFORMANCE MEASURES IS PRESENTED ON OUR WORKING INTEREST BASIS AFTER ROYALTIES. ALL TABULAR AMOUNTS ARE EXPRESSED IN THOUSANDS OF U.S. DOLLARS, EXCEPT PER SHARE AND PRODUCTION DATA INCLUDING REVENUES AND COSTS PER BOE.

IVANHOE ENERGY’S BUSINESS

Ivanhoe Energy is an independent international heavy oil development and production company focused on pursuing long term growth in its reserve base and production. Ivanhoe Energy plans to utilize technologically innovative methods designed to significantly improve recovery of heavy oil resources, including the application of HTL^TM Technology and EOR techniques. In addition, the Company seeks to expand its reserve base and production through conventional exploration and production of oil and gas. Our core operations are currently carried out in China, Mongolia, Canada and Ecuador, with business development opportunities worldwide. In late 2009, the Company, through a wholly owned subsidiary, acquired PanAsian Petroleum Inc., and acquired a production–sharing contract covering the 16,839 square kilometer Block XVI exploration area in the Nyalga basin Mongolia.

Ivanhoe Energy’s proprietary, patented heavy oil upgrading technology upgrades the quality of heavy oil and bitumen by producing lighter, more valuable crude oil, along with by-product energy which can be used to generate steam or electricity. The HTL^TM Technology has the potential to substantially improve the economics and transportation of heavy oil. There are significant quantities of heavy oil throughout the world that have not been developed, much of it stranded due to the lack of on-site energy, transportation issues, or poor heavy-light price differentials. In remote parts of the world, the considerable reduction in viscosity of the heavy oil through the HTL^TM process will allow the oil to be transported economically by pipelines. In addition to a dramatic improvement in oil quality, an HTL^TM facility can yield large amounts of surplus energy for production of the steam and electricity used in heavy oil production. The thermal energy from the HTL^TM process would provide heavy oil producers with an alternative to increasingly volatile prices for natural gas that now is widely used to generate steam. Yields of the low-viscosity, upgraded product can be greater than 85% by volume, and high conversion of the heavy residual fraction is achieved. In addition to the liquid upgraded oil product, a small amount of valuable by-product gas is produced, and usable excess heat is generated from the by-product coke.

HTL^TM can virtually eliminate cost exposure to natural gas and diluent, solve the transport challenge, and capture a substantial portion of the heavy to light oil price differential for oil producers. HTL^TM accomplishes this at a much smaller scale and at lower per barrel capital costs compared with established competing technologies, using readily available plant and process components. As HTL^TM facilities are designed for installation near the wellhead, they eliminate the need for diluent and make large, dedicated upgrading facilities unnecessary.

EXECUTIVE OVERVIEW OF 2009 RESULTS

In July 2009 the Company disposed of its U.S. operations and used the proceeds for its ongoing projects. To properly reflect this sale in the Company’s 2009 financial statements the results of the U.S. operations have been segregated from ongoing operations and separately disclosed as “Discontinued Operations.”

In 2009 the Company’s oil revenues from continuing operations decreased from $48.4 million in 2008 to $25.0 million in 2009 due primarily to the decline in oil prices between the two years. These results relate specifically to China producing properties which also experienced a decrease in operating costs from $21.5 million to $10.2 million between 2008 and 2009. This decrease in costs relates to a reduction in the Windfall Levy (a windfall profits tax as defined below), and is also driven by the decline in oil prices between 2008 and 2009. General and Administrative costs increased significantly due to several factors including the Company adding key personnel to advance its first HTL^TM projects and bolster our executive leadership, the redeployment of many of the U.S. staff from their previous duties at our U.S. operations to focus on advancing our heavy oil business development strategy and one-time legal and related fees (see Item 3 to Part I of this Form 10K).

The 2009 results for discontinued operations was a loss of $23.9 million, including the write-off of a $29.6 million future income tax asset that could no longer be utilized.

In the first half of 2009, in response to the deteriorating global economy and restricted capital markets, the Company focused on husbanding capital while continuing to selectively advance its heavy oil projects in Canada and Ecuador and develop its HTL^TM technology. As a result both Tamarack and Pungarayacu development activities continued to advance, albeit at a more deliberate pace, and the Technology Group created a major technical breakthrough in the HTL^TM process, reducing the amount of oil recycled through a plant by up to 80 percent.

In the second half of the year, as economic conditions moderated somewhat, the Company completed two key transactions: 1) the acquisition of what we believe to be a high quality exploration block in Mongolia’s Nyalga basin, and 2) a divestiture of our U.S. operations. These transactions continued to build the Company in line with our stated strategies as we redeployed capital from our U.S. conventional operations into our heavy oil projects and built our conventional asset base in our Asian operations.

Oil and Gas

Integrated

Projects in this segment will have two primary components. The first consists of conventional exploration and production activities together with enhanced oil recovery techniques such as steam assisted gravity drainage. The second component consists of the deployment of the HTL^TM Technology which will be used to upgrade heavy oil at facilities located in the field to produce lighter, more valuable crude. The Company’s two flagship projects currently report in this segment - a heavy oil project in Alberta (Tamarack) and a heavy oil property in Ecuador (Pungarayacu).

Conventional

The Company explores for, develops and produces conventional crude oil and natural gas in China and Mongolia, having divested its U.S. operations. In China, the Company’s development and production activities are conducted at the Dagang oil field located in Hebei Province and its exploration activities are conducted on the Zitong block located in Sichuan Province. In Mongolia the Company is conducting early phase exploration activities in the Nyalga basin, southeast of the capital Ulaanbaatar. The Company’s California and Texas exploration, development and production activities were sold to Seneca South Midway LLC.

Business and Technology Development

The Company’s technology development activities made major strides in 2009. The Feed Stock Test Facility in San Antonio, Texas was commissioned in the first quarter and immediately took up its dual roles of supporting business development and continuing to advance the technology. This facility was a key part of the major technical advancement that eliminated the need to recycle oil through HTL^TM facilities, greatly reducing capital costs per barrel of throughput. In addition, the facility also began processing test runs for various heavy oils to support business plans and development opportunities.

Business development successes include the disposition of the Company’s U.S. operations, facilitating capital redeployment from the strategically non-core, conventional U.S. arena into our core heavy-oil and conventional Asian operations. The PanAsian merger was also a large advance for our conventional oil and gas strategy, accessing significant exploration opportunities in the Asian arena. Additional opportunities in the Middle East, North and South America are currently being pursued.

Corporate

The Company’s corporate segment consists of costs associated with the board of directors, executive officers, corporate debt, financings and other corporate activities.

Summary table of financial data

The following table sets forth certain selected consolidated data for the past three years:

		Year ended December 31,
		2009				2008				2007
Oil revenues		$	24,968			$	48,370			$	31,365
Net loss from continuing operations		$	(37,731	)		$	(38,476	)		$	(33,433	)
Net loss from continuing operations per share — basic and diluted		$	(0.13	)		$	(0.15	)		$	(0.14	)
Net loss and comprehensive loss		$	(61,652	)		$	(34,193	)		$	(39,207	)
Net loss per share — basic and diluted		$	(0.22	)		$	(0.13	)		$	(0.16	)
Average production (Boe/d)			1,276				1,339				1,325
Net revenue (loss) from operations per Boe		$	(6.98	)		$	7.59			$	(1.75	)
Cash flow provided by (used in) operating activities from continuing operations		$	(14,993	)		$	10,780			$	1,168
Cash flow provided by (used in) operating activities		$	(12,290	)		$	17,053			$	5,489
Capital investments (continuing operations)		$	(26,373	)		$	(21,063	)		$	(28,585	)

FINANCIAL RESULTS – YEAR TO YEAR CHANGE IN NET LOSS

The following provides a summary analysis of our net loss for each of the three years ended December 31, 2009 and a summary of year-over-year variances for the year ended December 31, 2009 compared to 2008 and for the year ended December 31, 2008 compared to 2007:

						Favorable								Favorable
						(Unfavorable)								(Unfavorable)
		2009				Variances				2008				Variances				2007
Summary of Net Loss by Significant Components:
Oil Revenues:		$	24,968							$	48,370							$	31,365
Production volumes						$	(2,384	)						$	398
Oil prices							(21,018	)							16,607
Realized gain (loss) on derivative instruments			124				4,554				(4,430	)			(4,096	)			(334	)
Operating costs			(10,191	)			11,324				(21,515	)			(8,515	)			(13,000	)
General and administrative, less stock based compensation			(18,002	)			(6,198	)			(11,804	)			(4,127	)			(7,677	)
Business and technology development, less stock based compensation			(9,343	)			(3,458	)			(5,885	)			2,715				(8,600	)
Net interest			(301	)			283				(584	)			(548	)			(36	)
Current income tax provision			(1,757	)			(1,103	)			(654	)			(654	)			—
Unrealized gain (loss) on derivative instruments			(1,459	)			(7,577	)			6,118				10,777				(4,659	)
Foreign Exchange Loss			(5,220	)			(3,693	)			(1,527	)			(1,226	)			(301	)
Depletion and depreciation			(19,868	)			5,893				(25,761	)			(5,121	)			(20,640	)
Stock based compensation			(3,849	)			(833	)			(3,016	)			135				(3,151	)
Provision for impairment of intangible asset and development costs			(1,903	)			13,151				(15,054	)			(15,054	)			—
Impairment of oil and gas properties			—				—				—				6,130				(6,130	)
Write off of deferred financing costs			—				2,621				(2,621	)			(2,621	)			—
Future income tax recovery			9,600				9,600				—				—				—
Discontinued operations (net of tax)			(23,921	)			(28,204	)			4,283				10,057				(5,774	)
Other			(530	)			(417	)			(113	)			157				(270	)
Net Loss		$	(61,652	)		$	(27,459	)		$	(34,193	)		$	5,014			$	(39,207	)

Our net loss for 2009 was $61.7 million ($0.22 per share) compared to our net loss in 2008 of $34.2 million ($0.13 per share). The decrease in our net loss from 2008 to 2009 of $27.5 million was due to a decrease of $18.8 million in combined oil and gas revenues and realized gain on derivative instruments, a $9.7 million increase in general and administrative and business and technology development expenses excluding stock based compensation and a $28.2 million increase in loss from discontinued operations. These were offset by decreases in operating costs of $11.3 million, a $13.2 million expense decrease arising from the impairment of assets and a $9.6 million increase in future income tax recovery.

Our net loss for 2008 was $34.2 million ($0.13 per share) compared to our net loss in 2007 of $39.2 million ($0.16 per share). The decrease in our net loss from 2007 to 2008 of $5.0 million was due to an increase of $12.9 million in combined oil and gas revenues and realized loss on derivative instruments, a $10.8 million increase in unrealized gain on derivative instruments and a $10.1 million increase in gain from discontinued operations. These were offset by an increase in operating costs of $8.5 million, a $1.4 million increase in general and administrative and business and technology development expenses excluding stock based compensation and a $8.9 million expense increase arising from the impairment of assets.

Significant variances in our net losses are explained in the sections that follow.

Revenues and Operating Costs

			Asia
	•		Oil Prices 2009 vs. 2008

Oil and gas prices decreased 46% per Boe in 2009 contributing to a $21.0 million decrease in revenue as compared to 2008. We realized an average of $53.60 per Boe during 2009, which was a decrease of $45.13 per Boe from 2008 prices. We expect crude oil prices and natural gas prices to remain volatile in 2010.

•

Oil Prices 2008 vs. 2007

Oil and gas prices increased 52% per Boe in 2008 contributing to a $16.6 million increase in revenue as compared to 2007. We realized an average of $98.73 per Boe during 2008, which was an increase of $33.87 per Boe from 2007 prices.

•

Realized Gain (Loss) on Derivatives

The increased revenues from higher oil and gas price in 2008 were offset by the realized loss on derivatives resulting from settlements from our costless collar derivative instruments. As benchmark prices rise above the ceiling price established in the contract the Company is required to settle monthly (see further details on these contracts below under “Unrealized Gain (Loss) on Derivative Instruments”). Changes in these realized settlement gains (losses) by segment are detailed below:

	Year Ended		Favorable				Year Ended				Favorable				Year Ended
	December 31,		(Unfavorable)				December 31,				(Unfavorable)				December 31,
2009			Variances				2008				Variances				2007
$	124		$	4,554			$	(4,430	)		$	(4,096	)		$	(334	)

•

Production Volumes

The following is a comparison of changes in production volumes for the year ended December 31, 2009 when compared to the same period in 2008 and for the year ended December 31, 2008 when compared to the same period for 2007:

		Years Ended December 31,												Years Ended December 31,
		Net Boe’s								Percentage				Net Boe’s								Percentage
		2009				2008				Change				2008				2007				Change
China:
Dagang			452,573				471,817				-4	%			471,817				464,206				2	%
Daqing			13,231				18,096				-27	%			18,096				19,379				-7	%
			465,804				489,913				-5	%			489,913				483,585				1	%

•

Production Volumes 2009 vs. 2008

Net production volumes during 2009 decreased by 5%, or 24 Mboe, when compared to 2008, resulting in decreased revenues of $2.4 million. The reduction was attributed to the normal field decline partially offset by the productivity increases from adding new perforations, fracture stimulations and water flood response. In addition, the Dagang project reached cost recovery effective September 1, 2009, at which time the Company’s working interest changed from 82% to 49%. It is anticipated that the gross production rates for 2010 will be similar to those averaged in 2009. In Dagang, at the end of 2009, there were 38 wells producing at a rate of 1,660 Bopd, compared to 43 producing wells at the end of 2008 at 1,700 Bopd.

•

Production Volumes 2008 vs. 2007

Net production volumes during 2008 increased by 1%, or 6 Mboe, when compared to 2007, resulting in increased revenues of $0.4 million. The normal field decline was offset by the production from five new development wells that were completed and put on production in the second half of 2007, as well as productivity increases from adding new perforations, fracture stimulations and water flood response.

•

Operating Costs 2009 vs. 2008

Operating costs in China, including engineering support costs and Windfall Levy, decreased 50% or $22.05 per Boe for 2009 when compared to 2008. The majority of the decrease relates to an 81% per Boe drop in the Windfall Levy as oil prices decreased substantially from 2008. Field operating costs decreased $4.58 per Boe. Effective January 1, 2009 the Dagang field reached “Commercial Production” status as defined by the Production Sharing Contract with China National Petroleum Company. The effect of this change is that the Company no longer pays 100% of operating costs but now pays only its proportionate interest. In addition, cost recovery was reached in Dagang effective September 1, 2009. During 2009 the effect of these two changes resulted in the Company paying 82% of operating costs for the first eight months, representing its share based on the commercial production declaration and 49% for the final four months, representing the post cost recovery share. Had the Company paid these lower proportionate shares in 2008, field operating costs would have decreased $0.68 per Boe or 4%, from 2008 levels. Road and lease maintenance costs, which are weather related, and decreased well workover costs were the main contributing factors to the decrease. These were offset by increases in oil treatment costs as total fluid volumes increased in 2009.

In March 2006, the Ministry of Finance of the Peoples Republic of China (“PRC”) issued the “Administrative Measures on Collection of Windfall Gain Levy on Oil Exploitation Business” (the “Windfall Levy Measures”). According to the Windfall Levy Measures, effective as of March 26, 2006, enterprises exploiting and selling crude oil in the PRC are subject to a windfall gain levy (the “Windfall Levy”) if the monthly weighted average price of crude oil is above $40 per barrel. The Windfall Levy is imposed at progressive rates from 20% to 40% on the portion of the weighted average sales price exceeding $40 per barrel. The cost associated with Windfall Levy has been included in operating costs in our financial statements. With oil prices decreasing in 2009, the Windfall Levy decreased $17.14 per Boe when compared to 2008.

During 2010 the Company has been placed on a production quota at our Dagang project. We therefore expect operating costs in 2010 to increase on a per barrel basis as compared to 2009. The general overall increase is anticipated to be slightly offset with improved maintenance methods currently being implemented in the field.

•

Operating Costs 2008 vs. 2007

Operating costs in China, including engineering and support costs and Windfall Levy, increased 63% or $17.03 per Boe for 2008 when compared to 2007. Field operating costs increased $3.62 per Boe mainly as a result of a higher percentage of field office costs allocated to operations versus capital as capital activity has decreased. In addition there were more service rig days worked and higher power costs resulting from greater water injection in 2008 when compared to 2007. These increases were offset by decreases resulting from road access costs, insurance coverage and lower project management salaries. As oil prices have increased, the amount of the Windfall Levy also increased significantly, resulting in $13.46 per Boe increase in 2008 when compared to 2007.

* * *

Production and operating information including oil and gas revenue, operating costs and depletion, on a per Boe basis, are detailed below:

		Year ended December 31,
		2009				2008				2007
Net Production:
Boe			465,804				489,913				483,585
Boe/day for the period			1,276				1,339				1,325

		Per Boe
Oil and gas revenue		$	53.60			$	98.73			$	64.86
Field operating costs			17.02				21.70				18.08
Windfall Levy			4.00				21.14				7.68
Engineering and support costs			0.86				1.08				1.12
			21.88				43.92				26.88
Net operating revenue			31.72				54.81				37.98
Depletion			38.70				47.22				39.73
Net revenue (loss) from operations		$	(6.98	)		$	7.59			$	(1.75	)

General and Administrative

Changes in general and administrative expenses, before and after considering increases in non-cash stock based compensation, by segment for the year ended December 31, 2009 when compared to the same period for 2008 and for the year ended December 31, 2008 when compared to the same period for 2007 were as follows:

		2009 vs.				2008 vs.
		2008				2007
Favorable (unfavorable) variances:
Oil Activities:
Canada		$	498			$	(1,627	)
Ecuador			(1,611	)			(658	)
Asia			(810	)			(141	)
Corporate			(5,518	)			(2,023	)
			(7,441	)			(4,449	)
Less: stock based compensation			1,243				322
		$	(6,198	)		$	(4,127	)

	•		General and Administrative 2009 vs. 2008
			Canada

The Company acquired working interests in two leases located in Alberta, Canada in July 2008. Certain general and administrative costs, including salaries and benefits, related to Canada are now being capitalized.

Ecuador

In the fourth quarter of 2008, the Company signed a contract to explore and develop Block 20. General and administrative costs incurred prior to signing this contract were minimal, costs incurred subsequent to signing this contract include setting up an office in Ecuador including local staff as well as redeploying personnel and office costs who previously worked on the business segment in our discontinued operations.

Asia

General and administrative expenses related to the China operations increased $0.8 million for 2009 as compared to 2008. The increase mainly results from a lower amount of general and administrative expenses allocated to capital projects in 2009.

Corporate

General and administrative costs related to Corporate activities increased: $4.5 million for legal and related fees (see Item 3 to Part III of this Form 10K), corporate aircraft costs, and a reallocation of personnel to Corporate previously allocated to our U.S. business segment. These increases were offset by decreases related to salary and benefit related items such as a one-time severance charge in 2008, reallocation of certain executive salaries to business development activities at the beginning of the third quarter 2008, a reduction in salary for an executive that resigned in the second quarter of 2008.

	•		General and Administrative 2008 vs. 2007
			Canada

As noted elsewhere in this Annual Report, the Company acquired working interests in two leases located in Alberta, Canada in July 2008. General and administrative costs related to Canada in 2008 consist of hiring key staff, reallocation of existing resources and some initial office setup costs. In prior periods, some of these costs were recorded in the Business and Technology Development segment.

Ecuador

As noted elsewhere in this Annual Report, in the fourth quarter of 2008 the Company signed a contract to explore and develop Block 20. General and administrative costs related to Ecuador in 2008 consist of travel costs, contract services, hiring key staff, reallocation of existing resources and some initial office setup costs.

Asia

General and administrative expenses related to the China operations increased $0.1 million for 2008 as compared to 2007 mainly resulting from increases in consulting and audit fees, rent and facility costs.

Corporate

General and administrative costs related to Corporate activities increased $2.0 million for 2008 when compared to 2007. The overall increase was mainly due to the following increases; $0.6 million provision for uncollectible accounts, corporate aircraft costs of $1.0 million, and increases in third party recruiting fees of $0.5 million.

Business and Technology Development

Changes in business and technology development costs, before and after considering increases in non-cash stock based compensation, for the year ended December 31, 2009 when compared to 2008 and for the year ended December 31, 2008 when compared to 2007 were as follows:

•

Business and Technology Development 2009 vs. 2008

Business and technology development expenses increased $3.0 million (including changes in stock based compensation) in 2009 when compared to 2008, mainly as a result of a reallocation of certain executive salaries to business development activities at the beginning of the third quarter 2008, the start up of the FTF, the establishment of an office in Houston in 2008 and several project financing initiatives in the first quarter of 2009.

•

Business and Technology Development 2007 vs. 2006

Business and technology development expenses decreased $3.2 million (including changes in stock based compensation) in 2008 when compared to 2007, mainly as a result of a decrease in CDF operating costs due to several heavy oil upgrading runs in the first and second quarters of 2007. These decreases were offset by increases in compensation costs as the Company assembled a core HTL^TM technology team.

Foreign Exchange Loss

The increase in foreign exchange loss period over period is mainly a result of the unrealized loss on Canadian dollar denominated long-term debt.

Net Interest

•

Net Interest 2009 vs. 2008

Interest expense decreased $0.5 million for 2009 when compared to 2008 mainly due to a decrease in our long term debt resulting from a $3.0 million repayment on our loan for our China operations in the fourth quarter of 2008 and pay off of a short term Corporate note payable in the third quarter of 2008.

•

Net Interest 2008 vs. 2007

Interest expense increased $0.7 million for 2008 when compared to 2007 partially due to borrowings under a new loan for our China operations in the fourth quarter of 2007 and a short term loan that was outstanding from May 2008 to August 2008. Interest income also increased slightly in 2008 when compared to 2007 due to cash deposits from the July 2008 private placement.

Unrealized Gain (Loss) on Derivative Instruments

As required by the Company’s lenders, the Company entered into a costless collar derivative to minimize variability in its cash flow from the sale of approximately 50% of the Company’s estimated production from its Dagang field in China over a three-year period starting September 2007. This derivative had a ceiling price of $84.50 per barrel and a floor price of $55.00 per barrel using the WTI as the index traded on the NYMEX. In December the Company paid off the lender’s outstanding loan balance and this derivative was subsequently cancelled.

The Company is required to account for these contracts using mark-to-market accounting. As forecasted benchmark prices exceed the ceiling prices set in the contract, the contracts have negative value or a liability. These benchmark prices 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 and recovered in the last half of the year. Changes in these unrealized settlement (losses) and gains by segment are detailed below:

Year Ended			Favorable				Year Ended				Favorable				Year Ended
December 31,			(Unfavorable)				December 31,				(Unfavorable)				December 31,
2009			Variances				2008				Variances				2007
$	(1,459	)	$	(7,577	)		$	6,118			$	10,777			$	(4,659	)

Depletion and Depreciation

The primary expense in this classification is depletion of the carrying values of our oil and gas properties in our China cost centers over the life of their proved oil and gas reserves as determined by independent reserve evaluators. For more information on how we calculate depletion and determine our proved reserves see “Critical Accounting Principles and Estimates – Oil and Gas Reserves and Depletion” in this Item 7.

	•		Depletion and Depreciation 2009 vs. 2008
			Asia

China’s depletion rate decreased $8.52 per Boe for 2009 when compared to 2008, resulting in a $5.1 million decrease in depletion expense for 2009. The decrease in the rates from year to year was mainly due to an increase in total estimated proved reserves at our Dagang project due to reduced decline rates and improved recovery rates. A decrease of $1.1 million in depletion expense from year to year was related to decreased production.

Business and Technology Development

Depreciation in this segment decreased by $1.0 million in 2009 when compared to 2008 due to the Company the CDF only being depreciated for the first two quarters in 2009, offset by the commencement of depreciation on the FTF carrying balance.

	•		Depletion and Depreciation 2008 vs. 2007
			Asia

China’s depletion rate increased $7.50 per Boe for 2008 when compared to 2007, resulting in a $3.7 million increase in depletion expense for 2008. The increase in the rates from year to year was mainly due to an impairment of the drilling and completion costs associated with the second Zitong exploration well in the fourth quarter of 2007. The remaining increase of $0.2 million was related to increased production.

Business and Technology Development

Depreciation of the CDF is calculated using the straight-line method over its current useful life which is based on the existing term of the agreement with Aera Energy LLC to use their property to test the CDF. A formal study was conducted in 2008 whereby the estimated salvage value of the property was decreased and the asset retirement obligation was increased resulting in an increased depreciable base.

Provision for Impairment of Intangible Asset and Development Costs

During the third quarter of 2009, the Company determined that the completion and subsequent improvements to its technology showpiece the FTF in San Antonio diminished the business purpose of the CDF to nil. Consequently, the abandonment process commenced and the Company has impaired the net carrying value of the costs associated with the CDF as at September 30, 2009. The carrying value, net of depreciation, for the CDF, of $0.9 million, was reduced to nil with a corresponding reduction in our results of operations. In addition, the Company had $1.0 million in deferred costs on its balance sheet related to the pursuit of projects in the Middle East. In the fourth quarter of 2009, the entire carrying value of these costs were reduced to nil with a corresponding reduction in our results of operations.

The Company has been pursuing a GTL project for an extended period of time and had not been able to obtain a definitive agreement or appropriate financing. As a result the Company impaired the entire carrying value of the costs associated with GTL as at December 31, 2008. The carrying value for GTL development costs of $5.1 million and intangible GTL license costs of $10.0 million have been reduced to nil with a corresponding reduction in our results of operations. This impairment does not affect the Company’s intention to continue to pursue the current GTL project in Egypt.

In 2007, we had no write downs of our intangible assets or development costs.

Write-off of Deferred Financing Costs

The Company incurred professional fees and expenses associated with the pursuit of corporate financing initiatives by the Company’s Chinese subsidiary, Sunwing Energy. In the fourth quarter of 2008 this financing initiative was postponed indefinitely and therefore the associated costs were written down to nil with a corresponding reduction in our results of operations.

Provision for Impairment of Oil and Gas Properties

As discussed below in this Item 7 in “Critical Accounting Principles and Estimates — Impairment of Proved Oil and Gas Properties”, we evaluate each of our cost center’s proved oil and gas properties for impairment on a quarterly basis. If as a result of this evaluation, a cost center’s carrying value exceeds its expected future net cash flows from its proved and probable reserves then a provision for impairment must be recognized in the results of operations.

•

Impairment of Oil and Gas Properties 2008 vs. 2007

We did not impair our oil and gas properties in 2009 or 2008, compared to $6.1 million impairment of our China oil and gas properties in 2007.

Provision for/Recovery of Income Taxes

Asia

There was a $1.4 million current tax provision for the year ended December 31, 2009 comprised of $0.4 million for the tax year 2009 and a net adjustment of $1.0 million for 2008, as compared to a $0.6 million provision for the same period in 2008. In April 2009, the Chinese State Tax Administration Bureau issued changes to the minimum depreciation and amortization periods for oil and gas companies. The minimum period changed form 6 to 8 years and was effective January 1, 2008. Consequently, when submitting the final 2008 tax return in the second quarter 2009 an additional $1.0 million tax payable was calculated.

Business and Technology Development

Prior to the Company selling its U.S. operating segment in July 2009, as further described in Note 14 to the accompany financial statements, the Company had future tax assets arising from net operating losses carry-forwards generated by this business segment. These future income tax assets were partially offset by certain future income tax liabilities in the U.S. and by a valuation allowance. As at June 30, 2009, as a result of the pending sale of the business segment, the Company was no longer able to offset these tax assets and liabilities but was required to present these future income tax assets as “assets from discontinued operations” and a future income tax liability both in the amount of $29.6 million in the June 30, 2009 balance sheet. The future income tax assets classified as “Assets from discontinued operations” were ultimately included in the $23.4 million loss on disposition as described in Note 19. Revisions were made to the future income tax liability during the third quarter of 2009 based on revised projections of taxable income and utilization of net operating loss carryforwards. As at December 31, 2009, the Company’s future income tax liability is $20.0 million in the accompanying balance sheet.

Net Income (Loss) from Discontinued Operations

The following applies to the U.S operations only. The sale of the U.S. operations closed July 17, 2009. The U.S. operations have been accounted for as discontinued operations in accordance with Canadian GAAP on a retroactive basis and the results as at December 31, 2008 and for the three years ended December 31, 2008 have been amended accordingly.

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

		Year Ended December 31,
		2009				2008				2007
Revenue
Oil and gas revenue		$	5,455			$	18,120			$	12,270
Gain (loss) on derivative instruments			189				278				(5,594	)
Interest income			8				98				152
			5,652				18,496				6,828
Expenses
Operating costs			2,132				5,137				4,319
General and administrative			139				2,413				1,972
Depletion and depreciation			3,772				6,143				5,884
Interest expense and financing costs			173				520				427
			6,216				14,213				12,602
Income (Loss) before disposition			(564	)			4,283				(5,774	)
Loss on disposition (net of tax of $29.6 million for 2009, nil for 2008 and 2007)			(23,357	)			—				—
Net Income (Loss) from discontinued operations		$	(23,921	)		$	4,283			$	(5,774	)

	•		Revenues and Operating Costs
			Prices and gain/loss on derivatives

From the U.S. operations, we realized an average of $44.03 per Boe during 2009, which was a decrease of $44.64 per Boe and accounted for $5.5 million of our decreased revenues, and we realized an average of $88.67 per Boe during 2008, which was an increase of $26.96 per Boe and accounted for $5.5 million of our increased revenues.

The increased revenues from higher oil and gas prices in 2008 were offset by the realized loss on derivatives resulting from settlements from our costless collar derivative instruments. As benchmark prices rise above the ceiling price established in the contract the Company is required to settle monthly (see further details on these contracts below under “Unrealized Gain (Loss) on Derivative Instruments”). The Company realized a net loss on these settlements in 2008 of $5.2 million, which compares to a realized net loss in 2007 of $1.3 million.

Production Volumes

From the U.S. Operations we produced 124 Mboe compared to 204 Mboe produced in 2008. This decrease was due to the sale of these U.S. operations midway through 2009. There was a 3% increase in U.S. production volume for 2008 as compared to 2007 and accounted for $0.3 million of our increased revenues. The overall changes to the U.S. production volumes were mainly due to the 2008 first quarter drilling program at South Midway. In addition, an increase in production in 2008 was due to increased steaming in the first two months of 2008 and abnormal downtimes in the steaming operations in 2007 due the absence of our two steam generators for extended period of time. The purchase of a second steam generator and the retrofit of an existing generator allowed for a full steaming program in 2008.

Operating Costs

Field operating costs decreased $7.92 per Boe in 2009 mainly due management redeploying technical personnel assigned to this segment to other segments in anticipation of the sale of these operations.

Field operating costs increased $4.21 per Boe in 2008 mainly due to an increase in steaming operations at South Midway. Both steam generators were down in the latter part of the first quarter and through the second quarter of 2007. In addition, the price of natural gas has been significantly higher in 2008 when compared to 2007.

•

General and Administrative Expenses

General and administrative expenses decreased significantly in 2009 when compared to 2008, in part because these U.S. Operations were sold midway through 2009 and in part due to non-field assets and personnel being transferred to the parent company.

General and administrative expenses increased $0.4 million in 2008 as compared to 2007. The increase in 2008 was mainly resulting from a lower allocation to capital and operations, provision for uncollectible accounts related to certain joint interest billings, offset by reallocation of staff to business and technology development.

•

Net Interest

Interest expense increased for 2008 and 2007 when compared to prior years due to additional draws on our loan facility.

•

Unrealized Gain (Loss) on Derivative Instruments

As required by the Company’s lenders, the Company entered into costless collar derivatives to minimize variability in its cash flow from the sale of approximately 75% of the Company’s estimated production from its South Midway Property in California and Spraberry Property in West Texas over a two-year period starting November 2006 and a six-month period starting November 2008. The derivatives have a ceiling price of $65.20, and $70.08, per barrel and a floor price of $63.20, and $65.00, per barrel, respectively, using WTI as the index traded on the NYMEX.

The Company is required to account for these contracts using mark-to-market accounting. As forecasted benchmark prices exceed the ceiling prices set in the contract, the contracts have negative value or a liability. These benchmark prices 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 is the lowest dating back several years. For the year ended December 31, 2008, the Company had $5.5 million unrealized gains in these derivative transactions. This compares to an unrealized net loss in 2007 of $4.3 million.

•

Depletion and Depreciation

The depletion rates for 2009, 2008 and 2007 were all within $1.00 of each other. Any fluctuation between years was due to production variances.

Financial Condition, Liquidity and Capital Resources

Sources and Uses of Cash

The following table sets forth a summary of our cash flows from continuing and discontinued operations for the periods indicated:

		Year ended December 31,
		2009				2008				2007
Net cash provided by (used in) operating activities		$	(12,290	)		$	17,053			$	5,489
Net cash provided by (used in) investing activities		$	6,396			$	(49,321	)		$	(22,287	)
Net cash provided by (used in) financing activities		$	(11,875	)		$	70,751			$	14,275
Net increase in cash and cash equivalents		$	(17,753	)		$	27,909			$	(2,523	)

As reflected in the accompanying unaudited consolidated financial statements, we have losses from operations, negative cash flows from operations and have a substantial accumulated deficit. Historically, we have principally used external sources to fund operations, to fund acquisitions of oil and gas properties and projects, to service long-term liabilities and to develop our technology and major projects. The main source of funds historically has been public and private equity and debt markets. The Company’s cash flow from operating activities will not be sufficient to meet its operating and capital obligations, and as such, the Company intends to finance its operating and capital projects from a combination of strategic investors in its projects and/or public and private debt and equity markets, either at a parent company level or at a project level.

Principal factors that could affect our ability to obtain funds from external sources include:

	•		Inability to attract strategic investors to our projects,
	•		Volatility in the public debt and private and equity markets,
	•		Increases in interest rates or credit spreads, as well as limitations on the availability of credit, that affect our ability to borrow under future potential credit facilities on a secured or unsecured basis, and
	•		A decrease in the market price for our common stock.
	•		Operating Activities

Our operating activities used $12.3 million in cash for the year ended December 31, 2009 compared to $17.1 million and $5.5 million provided in the same periods in 2008 and 2007. The decrease in cash from operating activities for the year ended December 31, 2009 was mainly due to the significant decrease in oil and gas production prices offset by an increase in expenses. The increase in cash from operating activities for the year ended December 31, 2008 was mainly due to a 50% increase in oil and gas production prices offset by an increase in expenses, as well as an increase in changes in non-cash working capital when compared to 2007.

•

Investing Activities

Our investing activities used $6.4 million in cash for the year ended December 31, 2009 compared to $49.3 million for the same period in 2008 and $22.3 million for 2007. For 2009, the main reason for the differences is $35.3 million cash provided by discontinued operations which is mainly the proceeds from the sale of these operations. For 2008, the main reason for the differences is the $22.3 million paid as part of the cost of the acquisition of the100% working interests in two leases located in the Athabasca oil sands region in the Province of Alberta, Canada (see Note 18 in the accompanying financial statements for more details). In addition the Company received $9.0 million in proceeds from a recovery of development costs in 2007, compared to nil in 2008 and 2009. There was also an increase in capital asset expenditures of $5.3 million for 2009 as compared to 2008 and a decrease of $7.5 million for 2008 when compared to 2007.

Changes in capital investments by segment are detailed below:

		For the Year Ended												For the Year Ended
		December 31,												December 31,
										(Increase)												(Increase)
		2009				2008				Decrease				2008				2007				Decrease
Oil and Gas Activities:
Canada		$	12,756			$	6,484			$	(6,272	)		$	6,484			$	—			$	(6,484	)
Ecuador			5,380				1,369				(4,011	)			1,369				—				(1,369	)
Asia			6,049				8,378				2,329				8,378				23,488				15,110
Business and Technology Development			2,093				4,832				2,739				4,832				5,097				265
Corporate			95				—				(95	)			—				—				—
		$	26,373			$	21,063			$	(5,310	)		$	21,063			$	28,585			$	7,522