Edgar Filing: IVANHOE ENERGY INC

Form 10-K

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

For the fiscal year ended December 31, 2008


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

For the transition period from to

Commission file number: 000-30586

IVANHOE ENERGY INC.

(Exact name of registrant as specified in its charter)


Yukon, Canada		98-0372413
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

654-999 Canada Place Vancouver, British Columbia, Canada		V6C 3E1
(Address of principal executive offices)		(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 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	Non-accelerated filer o
		(Do not check if a smaller reporting company)

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, 2008, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $680,645,631 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, 2009

Common Shares, no par value		279,381,187 shares

DOCUMENTS INCORPORATED BY REFERENCE
None

TABLE OF CONTENTS


	Page
PART I

Items 1 and 2 Business and Properties

General		4

Corporate Strategy		5

Integrated Oil and Gas Properties		7

Conventional Oil and Gas Properties		8

Business and Technology Development		11

Certain Factors Affecting the Business		13

Employees		14

Production, Wells and Related Information		14

Item 1A Risk Factors		16

Item 1B Unresolved Staff Comments		22

Item 3 Legal Proceedings		22

Item 4 Submission of Matters to a Vote of Security Holders		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		46

Item 8 Financial Statements and Supplementary Data		49

Item 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		94

Item 9A Controls and Procedures		95

Item 9B Other Information		96

PART III

Item 10 Directors, Executive Officers and Corporate Governance		97

Item 11 Executive Compensation		99

Item 12 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		113

Item 13 Certain Relationships and Related Transactions, and Director Independence		114

Item 14 Principal Accountant’s Fees and Services		115

PART IV

Item 15 Exhibits, Financial Statement Schedules		116

Exhibit 10.24
Exhibit 10.25
Exhibit 21.1
Exhibit 23.1
Exhibit 23.2
Exhibit 23.3
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

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:


	2008		2007		2006		2005		2004
Closing	$	0.82	$	1.01	$	0.86	$	0.86	$	0.83
Low	$	0.77	$	0.84	$	0.85	$	0.79	$	0.72
High	$	1.01	$	1.09	$	0.91	$	0.87	$	0.85
Average Noon	$	0.94	$	0.94	$	0.88	$	0.83	$	0.77

The average noon rate of exchange reported by the Bank of Canada (the Federal Reserve Bank of New York ceased posting noon exchange rates as of December 31, 2008) for conversion of U.S. dollars into Canadian dollars on March 10, 2009 was $0.78 ($1.00 = Cdn.$1.28).

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:


Boe		= barrel of oil equivalent
Bbl		= barrel
MBbl		= thousand barrels
MMBbl		= million barrels
Mboe		= thousands of barrels of oil equivalent
Bopd		= barrels of oil per day
Bbls/d		= barrels per day
Boe/d		= barrels of oil equivalent per day
Mboe/d		= thousands of barrels of oil equivalent per day
MBbls/d		= thousand barrels per day
MMBls/d		= million barrels per day
MMBtu		= million British thermal units
Mcf		= thousand cubic feet
MMcf		= million cubic feet
Mcf/d		= thousand cubic feet per day
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 the U.S., China and Ecuador; our limited cash resources and consequent need for additional financing; our ability to raise additional financing. The availability of financing is dependent in part on the return of the credit and equity markets to normalized conditions. During the fourth quarter of 2008, as a result of the global economic crisis, the terms and availability of equity and debt capital have been materially restricted and financing may not be available when it is required or on acceptable terms. In addition to the above financing risks, uncertainties, risk and other factors also include uncertainties regarding the potential success of heavy-to-light oil upgrading and gas-to-liquids technologies; uncertainties regarding the potential success of our oil and gas exploration and development properties in the U.S. and China; 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 mid-2008, the Company acquired two leases located in the heart of the Athabasca oil sands region in Alberta, Canada and recently signed a contract in Ecuador for the appraisal and development of a heavy oil lease in Ecuador. It is anticipated that these sites will provide for the first commercial applications of the Company’s HTL™ Technology in major, integrated heavy oil projects (see Implementation Strategy below). In addition, the Company seeks to selectively expand its reserve base and production through conventional exploration and production of oil and gas.

Core operations are in Canada, the United States, China and Ecuador, with business development opportunities worldwide.

The Company has established a number of geographically focused entities. The parent company, Ivanhoe Energy Inc., will pursue HTL^TMopportunities in the Athabasca oil sands of Western Canada and will hold and manage the core HTL^TM Technology. A new subsidiary for Latin America recently signed a contract for the appraisal and development of a heavy oil lease in Ecuador. In addition, a subsidiary has been established to undertake activities in the Middle East and North Africa. These companies complement Sunwing Energy Ltd., the Company’s existing, wholly-owned company established for activities in China. 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.

We believe this structure will allow the development and financing of multiple HTL^TM projects around the world, while minimizing dilution of the Company’s existing shareholders. In addition, the alignment with principal energy-producing regions will help to facilitate financing from region-specific strategic investors, some of which already have been identified, and also will enhance flexibility in accessing global capital markets.

The Company’s four reportable business segments are: Oil and Gas — Integrated, Oil and Gas - Conventional, Business and Technology Development and Corporate. These segments are different than those reported in the Company’s previous Form 10-Ks. Due to newly established geographically focused entities and the initiation of two new integrated projects, new segments are being reported to reflect how management now analyzes and manages the Company.

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

The Company explores for, develops and produces crude oil and natural gas in China and in the U.S. 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 the U.S., the Company’s exploration, development and production activities are primarily conducted in California and Texas.

Business and Technology Development

The Company incurs various costs in the pursuit of HTL^TM and GTL 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 projects products, the Company assesses whether the feasibility and related costs incurred have potential future value, are probable of leading 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 and GTL technologies it owns or licenses. 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. Although there has been a great deal of volatility in the price of oil and significant recent price declines, 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, the 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 seen in the first part of this past year, 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 wide 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.

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

The business opportunities available to the Company correspond to the challenges each potential heavy oil project faces. In Canada, Ecuador, California, Iraq and Oman, all four of the HTL^TM advantages identified above come into play. In others, including certain identified opportunities in Colombia and Libya, the heavy oil naturally flows to the surface, but transport is the key problem.

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 in Bakersfield and Calgary, 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:

Build a portfolio of major HTL^TM 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 HTL^TM Technology.

Advance the technology. Additional development work will continue to advance the technology through the first commercial application and beyond.

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.

Build internal capabilities. During 2008, significant progress has been made in building execution teams in preparation for the Company’s first HTL^TM projects. The upstream teams consist of a number of experienced heavy oil petroleum engineers and geologists complemented by a core team of geotechnical experts. In addition, the Company’s Houston-based HTL^TM technology team has been strengthened with the addition of 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 in its execution mode.

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 at least 30,000 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. The integrated HTL^TM and SAGD project is expected to produce 20,000 BOPD of bitumen as a first stage and sell a sour synthetic bottomless product, most likely into the US mid-west market.

Ecuador Project

In October 2008, Ivanhoe Energy Ecuador Inc., an indirect wholly owned subsidiary, signed a contract with 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 oil-field 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 for light 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 capability 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 will be in the approval phase during the first part of 2009 which includes obtaining environmental licenses. If the Company succeeds in getting the necessary approvals it will enter into the appraisal phase which would include obtaining permits to drill, undertaking seismic activity and drilling selected locations. Our analysis of old drilling core data from the Pungarayacu field suggests 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 approximately 25 years ago, geologists on site reported that the oil in the drilling cores fluoresced a bright color 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 program planned for later this year.

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 products and upstream oil and gas equipment.

CONVENTIONAL OIL AND GAS PROPERTIES

Our principal oil and gas properties are located in California’s San Joaquin Basin and Sacramento Basin, the Permian Basin in Texas and 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			12/31/2008		Percentage of
		2008		of Total			Proved		Total Estimated
		Production		2008			Reserves		Proved
Property	Location	(in MBoe)		Production			(in MBoe)		Reserves
South Midway	Kern County, California		189		27	%		675		38	%
West Texas	Midland County, Texas		13		2	%		94		5	%
Other	California		2		0	%		—		0	%

Total U.S.			204		29	%		769		43	%

Dagang	Hebei Province, China		472		68	%		960		53	%
Other	China		18		3	%		72		4	%

Total China			490		71	%		1,032		57	%

Total			694		100	%		1,801		100	%

Note: See the “Supplementary Disclosures About Oil and Gas Production Activities (Unaudited)”, which follow the notes to our consolidated financial statements set forth in Item 8 in this Annual Report on Form 10-K, for certain details regarding the Company’s oil and gas proved reserves, the estimation process and production by country. Estimates for our U.S. and China operations were prepared by independent petroleum consultants Netherland, Sewell & Associates Inc. and GLJ Petroleum Consultants Ltd., respectively. We have not filed with nor included in reports to any other U.S. federal authority or agency, any estimates of total proved crude oil or natural gas reserves since the beginning of the last fiscal year.

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 a constant price basis using the standards contained in SEC Regulation S-X and 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 year-end constant prices and 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 proved and proved developed reserves by country only whereas NI 51-101 requires disclosure of more reserve categories and product types;

•

the SEC does not require separate disclosure of proved undeveloped reserves or related future development costs whereas NI 51-101 requires disclosure of more information regarding proved undeveloped reserves, related development plans and future development costs; 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 and to file their reports.

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.

United States

•

Production and Development

South Midway

We currently have 66 producing wells in South Midway of which we are the operator with a working interest of 100% and a 93% net revenue interest. In 2008, we drilled eight new wells on the South Midway properties compared to 2007 when we drilled none. Six of these new wells were in a new pool discovery. As well as being successful wells, these new wells have proved up additional locations. These new wells have initial production rates after steam stimulations of 15-50 Boe/d.

West Texas

In 2000, we farmed-in to the Spraberry property, which is a producing property located on 2,500 gross acres in the Spraberry Trend of the Permian Basin in West Texas. We retain working interests ranging from 31% to 48% in 23 wells, which are currently producing approximately 28 net Boe/d compared to 40 net Boe/d at December 31, 2007. The future decline of the oil and gas production rates are expected to be moderate and should lead to consistent performance and long life reserves.

Other

In mid-2004, we farmed-in to the McCloud River prospect near the Cymric field in the San Joaquin Basin. After the initial well resulted in a dry hole, a second prospect, North Salt Creek was identified. Due to the prior completion of three producers with attractive pay columns which resulted in oil production with repeated cyclic steam stimulations, three more oil wells were drilled and completed in 2008. Two of the wells are located in the Miocene Antelope Section and the third in a Pliocene sand. One of the wells is expected to produce gas and the other two are oil wells currently awaiting steam stimulation.

In addition to the new producers at Salt Creek, a new water disposal well and facilities have been constructed.

The Company has a 24% working interest in this 1,120 gross-acre prospect.

•

Exploration

The Company is focusing its exploration efforts on the lower risk opportunities noted below.

Knights Landing

In 2004, we farmed-in to the Knights Landing project, which is a 15,700 gross-acre block located in the Sacramento Gas Basin in northern California. We drilled nine new exploratory wells which resulted in three successful completions and six dry holes. Subsequent to this drilling program we increased our working interests in the project and 11 existing producing natural gas wells. By the end of 2005, production from the Knights Landing wells had been fully depleted in all but one well, which was producing at minimal levels. This well was full depleted by the end of 2006.

In late 2005, we acquired a 3-D seismic data program over 25 square miles covering our Knights Landing acreage block. We completed our seismic acquisition program in December 2005 and completed processing and interpretation of the seismic data in 2006. The primary objective of this development and exploration program is the Starkey Sand formation, which is an established producing reservoir in the region that lies between depths of 2,000 to 3,500 feet. Negotiations for farm-outs and other financing opportunities in order to drill this play have been unsuccessful to date.

The Company plans to continue to explore its options with regard to the Knights Landing property to seek either a farm out or possible drilling program.

Aera Exploration Agreement

The exploration agreement with Aera Energy LLC (“Aera”), a company owned by affiliates of ExxonMobil and Shell, originally covering an area of more than 250,000 acres in the San Joaquin Basin, gave us access to all of Aera’s exploration, seismic and technical data in the region for the purpose of identifying drillable exploration prospects. We identified 13 prospects within 11 areas of mutual interest (“AMI”) covering approximately 46,800 gross acres owned by Aera and an additional 24,200 acres of leased mineral rights. Of the 13 prospects submitted, Aera has elected to take a working interest in 10 prospects, resulting in our retention of working interests ranging from 12.5% to 50%. We have a 100% working interest in three prospects in which Aera elected not to participate — South Midway, Citrus and North Yowlumne. We will continue to hold exploration rights to the lands within each previously designated and accepted prospect until an exploration well is drilled on that prospect. There is no time deadline for drilling to occur if Aera elects to participate in the drilling of a prospect. If Aera elects not to participate we have an additional two years to drill the prospect on our own or with other parties. This two-year period will be extended as long as we continue to drill or have established production. The majority of these San Joaquin prospects are fee property with no rental payments to maintain the Company’s leases. The timing of drilling on these prospects is dependent on other working interest owners.

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 fund 100% of the development costs to earn 82% of the net revenue from oil production until cost recovery, at which time our entitlement reverts to 49%. 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.

During 2001, we completed the pilot phase and in 2002 submitted the final draft of our Overall Development Plan (“ODP”) to the Chinese regulatory authorities for approval. Final government approval was obtained in April 2003, after which the development phase commenced in late 2003. We suspended drilling in late 2005 to allow for detailed evaluation of well productivity and production decline performance. By the end of 2006, we had drilled a total of 39 development wells, as compared to the estimated 115 wells set out in the approved ODP, and in the fourth quarter of 2006, we reached agreement with CNPC to reduce the overall scope of the ODP to approximately 44 wells through a modified ODP. This program included a further five development wells to be drilled in 2007. This program has been finalized and all five wells have been completed and placed on production. Further to the previous relinquishment of three of the six blocks that were part of the ODP, an additional 2,759 acres of undeveloped land was relinquished in one of the remaining blocks in 2008. Commercial production commenced on January 1, 2009 as agreed by the parties following conversion of two wells to water injection for pressure maintenance. At such time the Company, pursuant to the terms of the agreement, will be able to recover from CNPC its share of operating costs, currently 18% then 51% after cost recovery.

No new development wells were drilled in 2008 as compared to 5 in 2007. In 2008, we did, however, fracture stimulate 12 wells and perforate additional sands in 8 other wells. Only a third of the net pay in each of the new five wells was completed and fracture stimulated in 2007. The year-end 2008 gross production rate was 1,700 Bopd (277 Bopd resulting from the five 2007 wells) compared to 1,900 Bopd at the end of 2007 and 1,877 Bopd at the end of 2006. 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 is currently discussing additional farm-out interest opportunities with Mitsubishi and other international oil companies.

The Company now has completed the first phase under the Zitong Contract (“Phase 1”). 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 2”). By electing to participate in Phase 2 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 1 shortfall), with total gross remaining estimated minimum expenditures for this program of $27.4 million. The Phase 2 seismic line acquisition commitment was fulfilled in the Phase 1 exploration program. The Zitong Partners plan to acquire additional seismic data in Phase 2. The partners have requested that CNPC allow the offset of this additional seismic line acquisition against the drilling commitment, reducing the required Phase 2 drilling footage requirement, but no agreement has been reached at this time. The Zitong Partners have relinquished 15% of the Block acreage and will relinquish an additional 10% to complete 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 the first Phase II drilling location. Drilling is to commence in late 2009 with expected completed drilling, completion and evaluation of the prospect 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 2, the Zitong Partners must relinquish all of the remaining property except any areas identified for development and production. In the event of a discovery, the Zitong Partners believe it would be possible to negotiate to enter a Phase III and reduce the amount of land relinquishment to allow further exploration activities.

BUSINESS AND TECHNOLOGY DEVELOPMENT

Heavy to Light Oil Upgrading

•

RTP^TM License and Patents

In April 2005, we 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. In January 2007, the Company received a Notice of Allowance from the U.S. Patent Office for the first of a family of additional petroleum upgrading patent applications. Since Ivanhoe acquired the patented heavy oil upgrading technology it has been working to expand patent coverage to protect innovations to the HTL^TM Technology as they are developed. This allowance is the first patent protection that has been granted directly to Ivanhoe Energy, and significantly broadens the Company’s portfolio of HTL^TM intellectual property for petroleum upgrading and opens up additional HTL^TM patenting opportunities for Ivanhoe Energy. In addition, Ivanhoe Energy currently has several additional HTL^TM patents in various stages of prosecution.

•

Feedstock Test Facility

The Company initiated the construction of the Feedstock Test Facility (“FTF”) during 2007. 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 Commercial Demonstration Facility (“CDF”) (see described below). 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.

This facility, costing approximately $8.8 million, is expected to be commissioned during the first quarter of 2009. The FTF is located in San Antonio, Texas.

•

Commercial Demonstration Facility

In 2004, Ensyn constructed a 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.

The Company plans to have the CDF available through the end of 2009 for potential investor crude evaluations as well as investor due diligence exercises.

Business Development

We are pursuing HTL^TM business development opportunities around the world, primarily Western Canada, Latin America and the Middle East/North Africa region. Integrated HTL^TM/SAGD financial models for Athabasca have been updated and refined, incorporating newly revised capital costs from AMEC, and revised price assumptions and currency exchange rate changes. These updated models show that HTL^TM integration represents robust value-add for thermal bitumen projects in Western Canada.

We also made significant progress in developing an execution plan with AMEC, our Tier One engineering contractor, for the design and construction of full-scale commercial HTL^TM facilities. The Company is proceeding with preliminary, non site-specific engineering related to the first fully commercial HTL^TM facility, supported by the recent successful CDF runs.

In October 2004, we signed a MOU with the Ministry of Oil of Iraq to study and evaluate the shallow Qaiyarah oil field in Iraq. The field’s reservoirs contain a large proven accumulation of 17.1 degree API heavy oil at a depth of about 1,000 feet. We have completed the reservoir assessment and have evaluated various recovery methods. Facility design work as well as an economic evaluation are both complete. Based on this evaluation we submitted a technical proposal to the Iraq Ministry of Oil who have accepted and approved the study and its conclusions.

In the first half of 2007, the Company and INPEX Corporation (“INPEX”), Japan’s largest oil and gas exploration and production company, signed an agreement to jointly pursue the opportunity to develop the above noted heavy oil field in Iraq. During the second quarter of 2007, INPEX paid $9.0 million to the Company as a contribution towards the Company’s historical costs related to the project and certain costs related to the development of its HTL^TM upgrading technology.

The agreement provides INPEX with a significant minority interest in the venture, with Ivanhoe Energy retaining a majority interest. Both parties will participate in the pursuit of the opportunity but Ivanhoe will lead the discussions with the Iraqi Ministry of Oil. Should the Company and INPEX proceed with the development and deploy Ivanhoe Energy’s HTL^TM Technology, certain technology fees would be payable to the Company by INPEX.

In September 2007, the Ministry of Oil requested that we submit a commercial proposal for a 30,000 Bopd Pilot Project to test the reservoir response to thermal recovery methods, optimize the development plan and build/operate the first HTL^TM unit for the field. Commercial proposals for a 10,000 Bopd “Quick Start” Project and a 30,000 Bopd “Pilot” Project were both submitted to the Ministry in the latter part of 2008. A meeting took place with the Iraqi Ministry of Oil during November 2008. Negotiations are currently underway on the 10,000 BPD proposal.

During the fourth quarter of 2007 we signed a MOU with Libya to perform an evaluation of the Haram Field and submit a proposal if warranted. A commercial proposal was submitted in September 2008 to the Libya National Oil Corporation (“LNOC”). We expect to be meeting with the LNOC in early 2009 to discuss this proposal.

Gas-to-Liquids Technology

•

Syntroleum License

We own a 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. Syntroleum’s proprietary GTL process is designed to catalytically convert natural gas into synthetic liquid hydrocarbons. This patented process uses compressed air, steam and natural gas as initial components to the catalyst process. As a result, this process (the “Syntroleum Process^TM”) substantially reduces the capital and operating costs and the minimum economic size of a GTL plant as compared to the other oxygen-based GTL technologies. Competitor GTL processes use either steam reforming or a combination of steam reforming and partial oxidation with pure oxygen. A steam reformer and an air separation plant necessary for oxidation are expensive and considered hazardous and increase operating costs.

The attraction of the GTL Technology lies in the commercialization of stranded natural gas. Such gas exists in discovered and known reservoirs, but is considered to be stranded based on the relative size of the fields and their remoteness from comparable sized markets. We have performed detailed project feasibility studies for the construction, operation and cost of plants from 47,000 to 185,000 Bbls/d. Additionally, we have conducted marketing and transportation feasibility studies for both European and Asia Pacific regions in which we identified potential markets and estimated premiums for GTL diesel and GTL naphtha.

•

GTL Project

At the present time, the only GTL project we are pursuing is in Egypt. In 2005, we signed a memorandum of understanding with Egyptian Natural Gas Holding Company (“EGAS”), the state organization responsible for managing Egypt’s natural gas resources, to prepare a feasibility study to construct and operate a GTL plant in Egypt that would convert natural gas to ultra-clean liquid fuels. We completed an engineering design of a GTL plant to incorporate the latest advances in Syntroleum GTL technology and have completed market and pricing analysis for GTL products to reflect changes since the original evaluation was completed several years ago. Plant capacity options of 47,000 and 94,000 Bbls/d were evaluated and in May 2006, we presented the feasibility study report to EGAS along with three commercial proposals. Based on EGAS’ review, and response to the proposals, we submitted a revised proposal in October 2006. In November 2006, the Company signed a Participation Agreement with H.K. Renewable Energy Ltd. (“HKRE”). In August 2007, we signed a Term Sheet with EGAS (a 24% project participant) and HKRE (a 15% project participant) which set out the commercial terms for a 47,000 Bbls/d project to be run on a tolling basis. EGAS agreed to commit, at no cost to the project, up to 4.2 trillion cubic feet of natural gas, or approximately 600 MMcf/d for the anticipated 20-year operating life of the project, subject to satisfactory conclusion of pre-front end engineering and design to confirm commercial viability and financing ability, the negotiation and signature of a definitive agreement and approval by the Company’s Board of Directors and the appropriate authorities in Egypt.

Because the Company has been working on this project in Egypt for an extended period of time and has not been able to obtain a definitive agreement or appropriate project financing, the Company has impaired the carrying value of the costs associated with GTL. This impairment does not affect the Company’s intention to continue to pursue this project.

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.

In the U.S., environmental laws and regulations, implemented principally by the Environmental Protection Agency, Department of Transportation and the Department of the Interior and comparable state agencies, govern the management of hazardous waste, the discharge of pollutants into the air and into surface and underground waters and the construction of new discharge sources, the manufacture, sale and disposal of chemical substances, and surface and underground mining. These laws and regulations generally provide for civil and criminal penalties and fines, as well as injunctive and remedial relief.

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.

Operations in Canada are still in the preliminary stages but the Company plans to observe all Canadian standards related to environmental management practices.

Environmental Provisions

As at December 31, 2008, a $1.8 million provision has been made for future site restoration and plugging and abandonment of wells in the U.S. and $1.9 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 $4.3 million and $2.0 million for the U.S. wells 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. During 2008, our provision for future site restoration and plugging and abandonment of U.S. wells increased by $0.2 million and we increased our provision for the CDF by $1.1 million.

Government Regulations

Our business is subject to certain federal, state 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. 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, 2008, we had 165 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 and Production tax) only and exclude depletion and depreciation, income taxes, interest, selling and administrative expenses.


	Average Sales Price						Average Operating Costs
	2008		2007		2006		2008		2007		2006
Crude Oil and Natural Gas ($/Boe)
U.S.	$	88.67	$	61.71	$	54.86	$	25.14	$	21.72	$	19.54
China	$	98.73	$	64.86	$	62.04	$	43.92	$	26.88	$	20.58

The following table sets forth the number of commercially productive wells (both producing wells and wells 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.


	2008								2007								2006
	Oil Wells				Gas Wells				Oil Wells				Gas Wells				Oil Wells					Gas Wells
	Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net			Gross		Net
U.S.		100		82.9		2		0.5		92		74.9		1		0.2		89		73.5			2		1.0
China		44		36.1		—		—		44		36.1		—		—		42		34.4	(1)		—		—


(1)		After giving effect to the 40% farm-in/out of Richfirst to the Dagang field.

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
	2008				2007				2006				2008				2007				2006
	Oil		Gas		Oil		Gas		Oil		Gas		Oil		Gas		Oil		Gas		Oil			Gas
U.S.		—		—		—		—		—		—		—		—		—		—		0.6	(1)		—
China		—		—		—		—		—		—		—		—		—		0.9		—			—

Total		—		—		—		—		—		—		—		—		—		0.9		0.6			—


(1)		Includes 0.6 (1 gross) net exploratory wells drilled during 2005 which were determined to be dry in 2006.

Development


	Productive Wells													Dry Wells
	2008					2007				2006				2008				2007				2006
	Oil			Gas		Oil		Gas		Oil		Gas		Oil		Gas		Oil		Gas		Oil		Gas
U.S.		8.7	(1)		0.2		1.2		—		9.0		—		—		—		—		—		—		—
China		—			—		4.1		—		—		—		—		—		—		—		—		—

Total		8.7			0.2		5.3		—		9.0		—		—		—		—		—		—		—


(1)		Includes 0.5 (2 gross) net development wells not included in the commercially productive wells table above as these wells are waiting to be steamed.

Wells in Progress

At the end of 2008, 2007 and 2006 we had 4.8 (7 gross), 4.3 (5 gross) and 5.3 (6 gross) net wells, respectively, 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, 2008. Gross acres include the interest of others and net acres exclude the interests of others:


	Developed Acres				Undeveloped Acres
	Gross		Net		Gross		Net
U.S.		6,011		3,440		69,003		16,452
China (1)		1,490		1,222		752,697		676,928


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

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^TM project development initiatives in Canada and Ecuador will require significant investments in development activities. Since our revenues from existing operations are insufficient to fund the capital expenditures that will be required to implement our HTL^TM project development initiatives, we will need to rely on external sources of financing to meet our capital requirements. We have, in the past, relied upon equity capital as our principal source of funding. We may seek to obtain the future funding we will need through debt and equity markets, through project participation arrangements with third parties or from the sale of existing assets. The availability of financing is dependent in part on the return of the credit and equity markets to normalized conditions. During the fourth quarter of 2008, as a result of the global economic crisis, the terms and availability of equity and debt capital have been materially restricted and financing may not be available when it required or on commercially acceptable terms. 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.

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 subordinate security over certain of our present and after acquired property. In the case of such default, Talisman Energy could foreclose on the secured assets, including the leases.

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

The HTL™ projects we plan to establish on our Athabasca heavy oil leases in Canada and our Block 20 project in Ecuador are currently at a very early stage of development and no detailed feasibility or engineering studies have been produced. There can be no assurances that such 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 developing such projects. In our efforts to develop 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.

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^TM 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^TM 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^TM plants, and we may not be successful in doing so.

Our efforts to commercialize our HTL^TM Technology may give rise to claims of infringement upon the patents or proprietary rights of others.

We own a license to use the HTL^TM 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^TM 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^TM 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^TM Technology facilities to become uncompetitive.

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

Lower oil prices could negatively impact our ability to borrow.

The amount of borrowings available to us under our bank credit facilities are determined by reference to borrowing bases. The amounts of our borrowing bases are established by our lenders and are primarily functions of the quantity and value of our reserves. Our borrowing bases are re-determined at least twice a year to take into account changes in our reserve base and prevailing commodity prices. Commodity prices can affect both the value as well as the quantity of our reserves for borrowing base purposes as certain reserves may not be economic at lower price levels. Consequently, the amounts of borrowings available to us under our bank credit facilities could be adversely affected by extended periods of low commodity prices.

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 sell 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^TM business, which may involve the sale of some or all of our exploration, development and production assets in China and the U.S. There can be no assurance that we will sell any such assets nor that any such sale, if and when made, will generate sufficient capital for the ongoing development of our core HTL^TM 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^TM 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^TM 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^TM projects.

Our HTL^TM 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.

Canada is a signatory to the United Nations Framework Convention on Climate Change and has ratified the Kyoto Protocol, which requires signatory nations to reduce their nation-wide emissions of carbon dioxide and other greenhouse gases. Any significant extraction or upgrading operations we may undertake in respect of our HTL^TM project in Canada are likely to produce certain greenhouse gases. The details of the implementation of a federal greenhouse gas reduction program in Canada have not been finalized and it is premature to predict what impact changes to Canadian federal or provincial regulations will have on the Canadian oil and natural gas industry, but if, and when we develop and operate our HTL^TM project in Canada, we expect that we will face increased capital and operating costs in order to comply with greenhouse gas emissions targets and/or reductions, which may be material. There is no assurance that any mandatory emission intensity reductions to which we may become subject will be technically and economically feasible to implement. Failure to meet any such requirements or successfully engage alternative compliance mechanisms (such as emissions credits) could materially adversely affect our ability to develop and operate the project.

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 18% 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 U.S. District Court for the District 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. The plaintiff’s claim is for unspecified damages or ownership of the Company’s interest in the Pungarayacu field. The action is at an early stage and the parties are preparing their defense. All defendants have filed motions to dismiss the lawsuit for lack of jurisdiction. While the Company intends to rigorously defend the interest of the Company and its shareholders, the likelihood of any ultimate loss or gain, if any, is not determinable at this time.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

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.$)


	2008								2007
	4th Qtr		3rd Qtr		2nd Qtr		1st Qtr		4th Qtr		3rd Qtr		2nd Qtr		1st Qtr
High		1.43		3.51		3.77		1.97		2.45		2.25		2.65		2.16
Low		0.35		1.21		1.79		1.24		1.43		1.77		1.67		1.19

TSX (IE)
(CDN$)


	2008								2007
	4th Qtr		3rd Qtr		2nd Qtr		1st Qtr		4th Qtr		3rd Qtr		2nd Qtr		1st Qtr
High		1.53		3.37		3.85		1.99		2.33		2.36		2.99		2.53
Low		0.43		1.28		1.82		1.27		1.43		1.88		1.84		1.40

On December 31, 2008, the closing prices for our common shares were $0.49 on the NASDAQ Capital Market and Cdn. $0.58 on the TSX.

Exemptions from Certain NASDAQ Marketplace Rules

NASDAQ’s Marketplace Rules permit foreign private issuers to follow home country practices in lieu of the requirements of certain Marketplace Rules, including the requirement that an issuer’s independent directors hold regularly scheduled meetings at which only independent directors are present.

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 and our executive offices are located in British Columbia, 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, 2008, a total of 279,381,187 of our common shares were issued and outstanding and held by 241 holders of record with an estimated 21,000 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 entity that is not a “Canadian”, as defined, unless after review, the minister responsible for the Investment Act is satisfied that the investment is likely to be of net benefit to Canada. An investment in our common shares by a non-Canadian who is not a “WTO investor” (which includes governments of, or individuals who are nationals of, member states of the World Trade Organization and corporations and other entities which are controlled by them), at a time when we were not already controlled by a WTO investor, would be reviewable under the Investment Act under two circumstances. First, if it was an investment to acquire control (within the meaning of the Investment Act) and the value of our assets, as determined under Investment Act regulations, was Cdn.$5 million or more. Second, the investment would also be reviewable if an order for review was made by the federal cabinet of the Canadian government on the grounds that the investment related to Canada’s cultural heritage or national identity (as prescribed under the Investment Act), regardless of asset value. 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 2009 is expected to be Cdn.$312 million. The Investment Act provides detailed rules to determine if there has been an acquisition of control. For example, a non-Canadian would acquire control of us for the purposes of the Investment Act if the non-Canadian acquired a majority of our outstanding common shares. The acquisition of less than a majority, but one-third or more, of our common shares would be presumed to be an acquisition of control of us unless it could be established that, on the acquisition, we were not controlled in fact by the acquirer. 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 proposed amendments (the “Amendments”) to the Investment Act. If adopted as law, the Amendments would generally raise the thresholds that trigger governmental review. Specifically, with respect to investors based in WTO member nations, the Amendments would see the thresholds for the review of direct acquisitions of control increase from the current Cdn.$312 million (based on book value) to Cdn.$600 million (to be based on the “enterprise value” of the Canadian business) for the two years after the Amendments becomes law, 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 exact specifications of the Amendments still require additional definition and details of how they will be implemented. The Amendments, however, represent a significant change to Canada’s regulation of foreign investment.

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 is generally 15%. However, if the beneficial owner of such dividends is a U.S. resident corporation, which 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 year ended December 31, 2008, which were not registered under the Act, have been detailed in previously filed Form 10-Qs.

During the year ended December 31, 2007, we issued securities, which were not registered under the Securities Act of 1933 (the “Act”), 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.

During the year ended December 31, 2006, we issued securities, which were not registered under the Act, as follows:

•

in February 2006, we issued 8,591,434 common shares under Rule 903 of the Act to CITIC in exchange for an additional 40% working interest in the Dagang field.

•

in March 2006, we issued 100 common shares under Rule 903 of the Act at a price of U.S.$3.20 to an institutional investor pursuant to the exercise of previously issued share purchase warrants.

•

in April 2006, we issued 11,400,000 special warrants under Rule 903 of the Act at U.S.$2.23 per special warrant to institutional and individual investors. Each special warrant was exercised to acquire, for no additional consideration, one common share and one share purchase warrant following the issuance of a receipt for a prospectus by applicable Canadian securities regulatory authorities, which occurred in May 2006. Originally, one common share purchase warrant would entitle the holder to purchase one common share at a price of U.S.$2.63 exercisable until the fifth anniversary date of the special warrant date of issue. In September 2006 these warrants were listed on the TSX and the exercise price was changed to Cdn.$2.93.

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 19 to our financial statements in this Annual Report on Form 10-K for 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
	2008			2007			2006			2005			2004
	(stated in thousands of US dollars, except per share amounts)
Results of Operations
Revenues		69,166			33,517			48,100			29,939			17,997
Net loss		(34,193	)(1)		(39,207	)(1)		(25,492	)(1)		(13,512	)(1)		(20,725	)(1)
Net loss per share — basic and diluted		(0.13	)		(0.16	)		(0.11	)		(0.07	)		(0.12	)

Financial Position
Total assets		317,275			236,916			248,544			240,877			118,486
Long-term debt		37,855			9,812			4,237			4,972			2,639
Shareholders’ equity		257,427			197,287			228,386			204,767			103,586

Common shares outstanding (in thousands)		279,381			244,873			241,216			220,779			169,665

Cash Flow
Cash provided by operating activities		17,053			5,489			14,352			9,870			4,032
Capital investments		(25,606	)		(31,638	)		(17,842	)		(43,282	)		(46,454	)


(1)		Includes asset write-downs and provisions for impairment of $17.7 million, $6.1 million, $5.4 million, $5.6 million and $16.6 million for 2008, 2007, 2006, 2005 and 2004, respectively. See Note 4 to our financial statements under Item 8 in this Annual Report on Form 10-K.

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 19 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
	2008			2007			2006			2005			2004
	(stated in thousands of US dollars, except per share amounts)

Results of Operations
Net loss		(63,051	) (1)		(27,392	) (1)		(42,421	) (1)		(12,106	) (1)		(19,696	) (1)
Net loss per share — basic and diluted		(0.24	)		(0.11	)		(0.18	)		(0.06	)		(0.12	)

Financial Position
Total assets		263,247			216,656			216,365			224,935			105,791
Long-term debt		40,392			10,412			4,237			4,972			2,639
Shareholders’ equity		199,741			170,545			189,829			188,745			90,892

Cash Flow
Cash provided by operating activities		16,639			11,501			13,340			5,042			2,222
Capital investments		(25,192	)		(31,371	)		(16,830	)		(38,454	)		(44,644	)


(1)		Includes asset write-downs and provisions for impairment of $54.9 million, $5.9 million, $23.5 million, $4.5 million and $15.0 million for 2008, 2007, 2006, 2005 and 2004, respectively. See Note 19 to our financial statements under Item 8 in this Annual Report on Form 10-K.


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

TABLE OF CONTENTS


	Page
Ivanhoe Energy’s Business		28

Executive Overview of 2008 Results		28

Financial Results — Year to Year Change in Net Loss		30

Revenues and Operating Costs		31

General and Administrative		34

Business and Technology Development		35

Net Interest		36

Unrealized Gain (Loss) on Derivative Instruments		36

Depletion and Depreciation		36

Provision for Impairment of GTL Intangible Assets and Development Costs		38

Write-off of Deferred Financing Costs		38

Provision for Impairment of Oil and Gas Properties		38

Financial Condition, Liquidity and Capital Resources		38

Sources and Uses of Cash		38

Outlook for 2009		40

Contractual Obligations and Commitments		41

Critical Accounting Principles and Estimates		41

2008 Accounting Changes		44

Impact of New and Pending Canadian GAAP Accounting Standards		44

Convergence of Canadian GAAP with International Financial Reporting Standards		45

Impact of New and Pending U.S. GAAP Accounting Standards		45

Off Balance Sheet Arrangements		46

Related Party Transactions		46

THE FOLLOWING SHOULD BE READ IN CONJUNCTION WITH THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED DECEMBER 31, 2008. 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 19 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, the United States, Canada and Ecuador, with business development opportunities worldwide. In mid-2008, the Company acquired two leases located in the heart of the Athabasca oil sands region in Alberta, Canada and recently signed a contract in Ecuador for the appraisal and development of a heavy oil lease in Ecuador. It is anticipated that these sites will provide for the first commercial applications of the Company’s HTL™ Technology in major, integrated heavy oil projects.

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 2008 Results

During the year, the value attributed to our reserves of oil and gas based on a standardized measure of discounted future cash flows decreased by 82% to $75.8 million of which $35.5 million is in China and $40.3 million in the U.S. These values decreased principally as a result of significant year-over-year decreases in oil prices as at the end of the year of 50%. Total revenues increased as a result of price increases during a portion of the year and a $12.6 million increase in gains on derivative instruments that were required by the Company’s bank loan agreements. General and administrative costs increased as the Company continued to invest significant resources in the development and commercial deployment of its patented HTL™ heavy oil upgrading technology. In addition, in 2008 the Company made a $15.1 million provision for impairment of its GTL intangible assets and development costs.

In the second and third quarters of 2008, the Company completed three key transactions: 1) the acquisition of what we believe to be high quality oil sand assets in the Athabasca region of Canada (our “Tamarack” project), 2) an agreement with the Government of Ecuador on the development of a major heavy oil block in Ecuador (“Pungarayacu”), and 3) a Cdn.$88 million equity financing. With these transactions, the Company has taken significant steps towards its transition to a heavy oil exploration, production and upgrading company.

The remainder of 2008 was dedicated primarily to formulating the development plans for the Tamarack project in Alberta and for Pungarayacu in Ecuador, including advancing the permitting processes. In addition, the Company commissioned and began operating the HTL Feedstock Test Facility in San Antonio, and continues with HTL engineering of commercial scale HTL facilities consistent with the development plans for Tamarack and Pungarayacu.

The Company’s four reportable business segments are: Oil and Gas — Integrated, Oil and Gas - Conventional, Business and Technology Development and Corporate. These segments are different than those reported in the Company’s previous financial statements included in its Form 10-Ks and as such the presentation has been changed to conform to the new segments. Due to newly established geographically focused entities and the initiation of two new integrated projects, new segments are being reported to reflect how management now analyzes and manages the Company.

Oil and Gas

Integrated

Projects in this segment will 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. The integrated segments were established in 2008 and therefore there is no comparative information for 2007 and 2006.

Conventional

Business and Technology Development

Additionally, the Company incurs costs to develop, enhance and identify improvements in the application of the HTL^TM and GTL technologies it owns or licenses. 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.

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


	Year ended December 31,
	2008			2007			2006
Oil and gas revenue	$	66,490		$	43,635		$	47,748

Net loss	$	(34,193	)	$	(39,207	)	$	(25,492	)
Net loss per share — basic and diluted	$	(0.13	)	$	(0.16	)	$	(0.11	)

Average production (Boe/d)		1,897			1,870			2,178

Net operating revenue per Boe	$	57.38		$	38.56		$	39.77

Cash flow provided by operating activities	$	17,053		$	5,489		$	14,352

Capital investments	$	(25,606	)	$	(31,638	)	$	(17,842	)

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, 2008 and a summary of year-over-year variances for the year ended December 31, 2008 compared to 2007 and for the year ended December 31, 2007 compared to 2006:



				*Favorable*						*Favorable*
				*(Unfavorable)*							*(Unfavorable)*
	2008			*Variances*			2007				*Variances*			2006

Summary of Net Loss by Significant Components:
Oil and Gas Revenues:	$	66,490					$	43,635						$	47,748
Production volumes				$	717						$	(6,732	)
Oil and gas prices					22,138							2,619
Realized gain (loss) on derivative instruments		(9,625	)		(7,977	)		(1,648	)			(1,717	)		69
Operating costs		(26,652	)		(9,333	)		(17,319	)			(1,186	)		(16,133	)

General and administrative, less stock based compensation		(15,202	)		(5,830	)		(9,372	)			(1,724	)		(7,648	)
Business and technology development, less stock based compensation		(5,885	)		2,715			(8,600	)			(1,379	)		(7,221	)
Net interest		(815	)		(503	)		(312	)			(283	)		(29	)
Current income tax provision		(656	)		(656	)		—				—			—

Unrealized gain (loss) on derivative instruments		11,591			20,530			(8,939	)			(8,446	)		(493	)
Depletion and depreciation		(31,904	)		(5,380	)		(26,524	)			6,026			(32,550	)
Stock based compensation		(3,554	)		175			(3,729	)			(808	)		(2,921	)
Provision for impairment of GTL intangible assets and development costs		(15,054	)		(15,054	)		—				—			—
Impairment of oil and gas properties		—			6,130			(6,130	)			(710	)		(5,420	)
Write off of deferred financing costs		(2,621	)		(2,621	)		—				—			—
Acquisition costs		—			—			—				736			(736	)
Other		(306	)		(37	)		(269	)			(111	)		(158	)


Net Loss	$	(34,193	)	$	5,014		$	(39,207	)		$	(13,715	)	$	(25,492	)

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 $14.9 million in combined oil and gas revenues and realized gain on derivative instruments. These were offset by increases in operating costs of $9.3 million, a $3.1 million increase in general and administrative and business and technology development expenses excluding stock based compensation and a $5.4 million increase in depletion and depreciation. In addition, there was a $20.5 million increase in income as a result of unrealized gain on derivative instruments offset by a combined $11.5 million expense increase arising from the impairment of assets.

Our net loss for 2007 was $39.2 million ($0.16 per share) compared to our net loss in 2006 of $25.5 million ($0.11 per share). The increase in our net loss from 2006 to 2007 of $13.7 million was due to decrease of $5.8 million in combined oil and gas revenues and realized loss on derivative instruments, an increase in operating costs of $1.2 million, a $3.1 million increase in general and administrative and business and technology development expenses excluding stock based compensation and an $8.4 million increase in unrealized loss on derivative instruments. These increases were partially offset by a $6.0 million decrease for depletion and depreciation.

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

Revenues and Operating Costs

The following is a comparison of changes in production volumes for the year ended December 31, 2008 when compared to the same period in 2007 and for the year ended December 31, 2007 when compared to the same period for 2006:


	Years ended December 31,							Years ended December 31,
	Net Boe’s				Percentage			Net Boe’s				Percentage
	2008		2007		Change			2007		2006		Change
China:
Dagang		471,817		464,206		2	%		464,206		554,185		-16	%
Daqing		18,096		19,379		-7	%		19,379		20,946		-7	%

		489,913		483,585		1	%		483,585		575,131		-16	%

U.S.:
South Midway		188,911		177,745		6	%		177,745		188,379		-6	%
Spraberry		13,484		19,587		-31	%		19,587		23,242		-16	%
Others		1,960		1,512		30	%		1,512		8,309		-82	%

		204,355		198,844		3	%		198,844		219,930		-10	%


		694,268		682,429		2	%		682,429		795,061		-14	%

Net production volumes in 2008 increased 2% from 2007 due to a 1% increase in production volumes in our China properties and a 3% increase in our U.S. properties, resulting in increased revenues of $0.7 million.

Net production volumes in 2007 decreased 14% from 2006 due to a 16% decrease in production volumes in our China properties and a 10% decrease in our U.S. properties, resulting in decreased revenues of $6.7 million.

Oil and gas prices increased 50% per Boe in 2008 contributing to a $22.1 million increase in revenue as compared to 2007. We realized an average of $98.73 per Boe from operations in China during 2008, which was an increase of $33.87 per Boe from 2007 prices and accounted for $16.6 million of our increase in revenues. From the U.S. operations, we realized an average of $88.97 per Boe during 2008, which was an increase of $26.96 per Boe and accounted for $5.5 million of our increased revenues. We expect crude oil prices and natural gas prices to remain volatile in 2009.

Oil and gas prices increased 6% per Boe in 2007 generating $2.6 million in additional revenue as compared to 2006. We realized an average of $64.86 per Boe from operations in China during 2007, which was an increase of $2.82 per Boe from 2006 prices and accounted for $1.3 million of our increase in revenues. From the U.S. operations, we realized an average of $61.71 per Boe during 2007, which was an increase of $6.85 per Boe and accounted for $1.3 million of our increased revenues.

The increased revenues from higher oil and gas price in 2008 and 2007 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 $9.6 million, $5.2 million of which was from the U.S. segment, the balance from the China segment. This compares to a realized net loss in 2007 of $1.6 million and a $0.1 million realized gain in 2006. 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,
	2008			*Variances*			2007			*Variances*			2006

China	$	(4,430	)	$	(4,096	)	$	(334	)	$	(334	)	$	—
U.S.		(5,195	)		(3,881	)	$	(1,314	)		(1,383	)		69

	$	(9,625	)	$	(7,977	)	$	(1,648	)	$	(1,717	)	$	69

Operating costs, including Windfall Levy (the “Windfall Levy”) and production taxes and engineering and support costs, for 2008 increased $13.01, or 51%, per Boe for 2008 when compared to 2007. These costs increased $5.09, or 25%, per Boe for 2007 when compared to 2006. Of the total $9.3 million increase in these costs for 2008 compared to 2007, $6.7 million were a result of the change in Windfall Levy which is explained in more detail below under the China — Operating Costs section.

China

•

Production Volumes 2008 vs. 2007

Net production volumes during 2008 increased by 6,327 Boe when compared to 2007. 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. The expected production rates for 2009 will be similar to those averaged in 2008, but may be lower than the exit rate at December 31, 2008. At the end of 2008, there were 43 producing wells at the Dagang field and 42 producing wells at the end of 2007.

•

Production Volumes 2007 vs. 2006

The December 31, 2007 exit production rate at Dagang was 1,900 Gross Bopd, compared to 1,877 Gross Bopd at the end of 2006. Normal field decline was offset by the production of 290 Gross Bopd from five new development wells completed and put on production in the second half of 2007. Overall, net production volumes decreased 16% at the Dagang field for 2007 as in addition to normal declines within the field; we incurred abnormal downtimes due to problems encountered with sub-surface equipment. These equipment issues were resolved with a change in equipment suppliers.

•

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.

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 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. Consequently, 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.

We expect operating costs in 2009 to decrease on a per barrel basis as compared to 2008. The most significant component of the expected decrease in operating expenses will be related to the Windfall Levy, as oil prices are not expected to reach the same levels in 2009 as 2008. In addition, there will be a decrease in operating costs due to the ability to charge CNPC for its share of operating costs, as “commercial production” status, currently 18% then 51% after cost recovery, will commence on January 1, 2009. These increases will be somewhat offset by an increase in office costs allocated to operations as we continue to reduce the number of capital projects.

•

Operating Costs 2007 vs. 2006

Operating costs in China, including engineering and support costs and Windfall Levy, increased 31% or $6.30 per Boe for 2007 when compared to 2006. Field operating costs increased $4.01 per Boe. In addition to the excessive down hole maintenance problems mentioned above, which resulted in increased workover and maintenance costs, increased power costs, additional operator salaries and higher supervision charges in relation to reduced volumes contributed to the increase. The Windfall Levy resulted in a $1.94 per Boe increase for 2007 partially as a result of the 2007 being the first full year of the Levy and partially due to higher oil prices. Engineering and support costs for 2007 increased by $0.35 per Boe or 46% as we reduced the number of capital projects.

U.S.

•

Production Volumes 2008 vs. 2007

There was a 3% increase in U.S. production volume for 2008 as compared to 2007. 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 2008 first quarter drilling program at South Midway is expected to offset natural declines within this field and to provide additional future drilling locations. Increases at South Midway were offset by smaller decreases in our Spraberry field in West Texas where there was a significant downtime related to down hole leak problems. As at December 31, 2008, we were producing 560 gross Boe/d (520 net Boe/d) at South Midway compared to 517gross Boe/d (496 net Boe/d) as at December 31, 2007. In 2009, we expect production volumes at South Midway will decline as there are no plans to drill new wells in this property. We also expect that production volumes at West Texas will continue decline modestly.

•

Production Volumes 2007 vs. 2006

As at December 31, 2007, we were producing 517 gross Boe/d (496 net Boe/d) at South Midway compared to 590 gross Boe/d (543 net Boe/d) as at December 31, 2006. U.S. production volumes decreased 10% in 2007 when compared to 2006 mainly due to a decline in production at South Midway resulting from steam generator downtime during the second and third quarters, along with certain wells taken offline to be soaked and steamed once that steaming operation came back on line. The purchase of a second steam generator and the retrofit of an existing generator allowed for a full steaming program in 2008. In addition to the natural declines in production within our Spraberry field in West Texas, production was also hampered by a key producer being down for repairs in the third quarter.

•

Operating Costs 2008 vs. 2007

Operating costs in the U.S., including engineering and support costs and production taxes, increased 16% per Boe for 2008 when compared to 2007. Field operating costs increased $4.21 per Boe 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. Additional maintenance costs and workovers at the Spraberry field in West Texas in 2008 added to the overall increase in costs. In addition, oil field expenses in general increased due to the demand both in California and nationwide during 2008. Typically as oil prices rise so does drilling activity. The Company anticipates the costs associated with the oil service industry to decrease in 2009 as demand has decreased. The expectation for overall operating expense in 2009 is otherwise unknown as natural gas prices are expected to remain volatile and the Company can not predict the number or extent of workover projects.

•

Operating Costs 2007 vs. 2006

Operating costs in the U.S., including engineering and support costs and production taxes, increased 11% or $2.18 per Boe for 2007 when compared to 2006. Field operating costs increased $0.97 per Boe due to increases to maintenance costs and workovers at Spraberry and steaming projects in the diatomite formation at North Salt Creek. These increases were somewhat offset due to a reduction in our South Midway steaming operations as we were in the process of replacing a steam generator, including purchasing and subsequent retro fit, which was completed and put on line in the third quarter. We also had our other steam generator down for repairs during the second quarter. In addition to this overall increase, engineering and support costs for 2007 increased by $1.11 per Boe mainly due to a higher allocation of support to production as capital activity decreased.

* * *

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,
	2008						2007						2006
	China		U.S.		Total		China		U.S.		Total		China		U.S.		Total

Net Production:
Boe		489,913		204,355		694,268		483,585		198,844		682,429		575,131		219,930		795,061
Boe/day for the period		1,339		558		1,897		1,325		545		1,870		1,576		603		2,178


	Per Boe						Per Boe							Per Boe
Oil and gas revenue	$	98.73	$	88.67	$	95.77	$	64.86		$	61.71	$	63.94	$	62.04	$	54.86	$	60.06

Field operating costs		21.70		19.62		21.09		18.08			15.41		17.30		14.07		14.44		14.17
Windfall Levy (China) and Production tax (U.S.)		21.14		1.31		15.30		7.68			1.25		5.81		5.74		1.15		4.47
Engineering and support costs		1.08		4.21		2.00		1.12			5.06		2.27		0.77		3.95		1.65

		43.92		25.14		38.39		26.88			21.72		25.38		20.58		19.54		20.29

Net operating revenue		54.81		63.53		57.38		37.98			39.99		38.56		41.46		35.32		39.77
Depletion		47.22		29.88		42.12		39.73			29.38		36.71		40.57		24.23		36.05

Net revenue (loss) from operations	$	7.59	$	33.65	$	15.26	$	(1.75	)	$	10.61	$	1.85	$	0.89	$	11.09	$	3.72

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, 2008 when compared to the same period for 2007 and for the year ended December 31, 2007 when compared to the same period for 2006 were as follows:


	2008 vs.			2007 vs.
	2007			2006
Favorable (unfavorable) variances:
Oil and Gas Activities:
Canada	$	(1,653	)	$	—
Ecuador		(658	)		—
China		(204	)		(705	)
U.S.		(393	)		(342	)
Corporate		(3,206	)		(849	)

		(6,114	)		(1,896	)
Less: stock based compensation		284			172

	$	(5,830	)	$	(1,724	)

•

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.

China

General and administrative expenses related to the China operations increased $0.2 million for 2008 as compared to 2007 mainly resulting from increases in consulting and audit fees, rent and facility costs and unrealized foreign exchange loss.

U.S.

General and administrative expenses related to the U.S. operations increased $0.4 million for 2008 as compared to 2007 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.

Corporate

General and administrative costs related to Corporate activities increased $3.2 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 and foreign exchange losses of $1.1 million.

•

General and Administrative 2007 vs. 2006

China

General and administrative expenses related to the China operations increased $0.7 million for 2007 mainly due to a decrease in allocations to capital investments as a result of fewer capital projects in 2007 when compared to 2006.

U.S.

General and administrative expenses related to U.S. operations increased $0.3 million in 2007. Allocations to capital investments and operations decreased $0.9 million as a result of less capital activity for 2007 when compared to 2006 and discretionary bonuses paid in 2007. This increase in expense was offset by a decrease of $0.5 million for salaries and benefits, which was a result of reallocation of resources to HTL^TM activities beginning in the second half of 2006 and continuing through all of 2007.

Corporate

General and administrative costs related to Corporate activities increased $0.8 million for 2007 when compared to 2006. The increase for 2007 was due to a $1.4 million increase in salaries and benefits partially resulting from discretionary bonuses paid in 2007, the addition of new executives mid way through 2006, and other key personnel added in 2007. This increase was offset by a decrease in outside legal costs of $0.2 million, a decrease in professional fees incurred to comply with the provisions of Section 404 of the Sarbanes-Oxley Act of 2002 (“SOX”) in the amount of $0.1 million and a $0.3 million decrease for a one-time charge in 2006 for the write off of the deferred loan costs on the convertible loan that was paid by way of the issuance of common shares in the April 2006 private placement.

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, 2008 when compared to 2007 and for the year ended December 31, 2007 when compared to 2006 were as follows:

•

Business and Technology Development 2008 vs. 2007

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^TMtechnology team.

•

Business and Technology Development 2007 vs. 2006

Business and technology development expenses increased $2.0 million in 2007 compared to 2006 as we focused on business and technology development activities related to HTL^TM opportunities. The overall increase in HTL^TM related to salaries and benefits was $1.4 million. In addition to a reallocation of resources (see G&A explanations above) to HTL^TM, and 2007 discretionary bonuses, key personnel were added to this segment throughout 2007 as the Company developed its commercialization program for its technology. This increase was partially offset by an increased $0.5 million allocation to capital investments. This segment also increased as a result of $0.3 million higher operating costs at the CDF. Operating expenses of the CDF to develop and identify improvements in the application of the HTL^TM Technology are a part of our business and technology development activities. This increase was in part the result of several heavy oil upgrading runs in the first and second quarters of 2007, including a key Athabasca bitumen test run. The Company used the information derived from the Athabasca bitumen test run for the design and development of full-scale commercial projects. In addition, the HTL^TM segment increased $0.4 million as a result of higher outside engineering fees and legal fees related to patents and $0.6 million due to a shift in resources from GTL. The remainder of the increase is related to consulting fees and travel costs to develop opportunities for our HTL^TM Technology.

Net Interest

•

Net Interest 2008 vs. 2007

Interest expense increased $0.8 million for 2008 when compared to 2007 partially due to an additional draw on our U.S. loan, 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.

•

Net Interest 2007 vs. 2006

Interest expense was higher in 2007 when compared to 2006 partially due to an additional draw down on our U.S. loan and the funding of a new loan for China. These higher amounts were offset by a decrease related to the early pay off of the term note (see 2006 vs. 2005 analysis below). In addition, interest income decreased by $0.3 million as average cash balances were lower throughout 2007 when compared to 2006.

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. Also as a result of a requirement of 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 has 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.

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 $11.6 million unrealized gains in these derivative transactions. This compares to an unrealized net loss in 2007 of $8.9 million and $0.5 million in 2006. 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,
	2008		*Variances*		2007			*Variances*			2006

China	$	6,117	$	10,776	$	(4,659	)	$	(4,659	)	$	—
U.S.		5,474		9,754		(4,280	)		(3,787	)		(493	)

	$	11,591	$	20,530	$	(8,939	)	$	(8,446	)	$	(493	)

Depletion and Depreciation

The primary expense in this classification is depletion of the carrying values of our oil and gas properties in our U.S. and 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.

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Depletion and Depreciation 2008 vs. 2007

Depletion and depreciation increased $5.4 million for 2008 as compared to 2007. This is partially due to a $1.2 million increase in depreciation of the CDF, increases in depletion rates for China and in the U.S.

China

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.

U.S.

The U.S. depletion rate for 2008 was $29.88 per Boe compared to $29.38 per Boe for 2007, an increase of $0.50 per Boe resulting in a $0.2 million increase in depletion expense.

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.

•

Depletion and Depreciation 2007 vs. 2006

Depletion and depreciation decreased $6.0 million in 2007, partially due to reduced depletion of $3.6 million. The overall reduction in depletion was mainly the result of lower production rates which resulted in a decrease in depletion of $4.2 million for 2007. This decrease was somewhat offset by a higher depletion rate of $36.71 per Boe which resulted in additional depletion expense of $0.6 million. Reduced depreciation of the CDF as a result of a longer depreciation period also contributed to the overall decrease in depletion and depreciation in the amount of $2.4 million for 2007.

China

Decreases in production volumes in China resulted in a decrease in depletion expense of $3.7 million for 2007 when compared to 2006.

China’s depletion rate decreased $0.86 per Boe to $39.73 for 2007 when compared to 2006, resulting in a $0.4 million decrease in depletion expense. The decrease in the rates from year to year was mainly due to a $5.4 million ceiling test write down in the fourth quarter of 2006. This decrease was somewhat offset by an increase to the depletable pool in the fourth quarter of 2007 for the impairment of the drilling costs associated with the second exploration well in the Zitong Block.

U.S.

The U.S. depletion rate for 2007 was $29.38 per Boe compared to $24.23 per Boe for 2006, an increase of $5.15 per Boe resulting in a $1.0 million increase in depletion expense. This increase was mainly due to the 2006 fourth quarter impairment of certain properties, including North Yowlumne, LAK Ranch and Catfish Creek, resulting in $4.8 million of those costs being included with our proved properties and therefore subject to depletion. In addition, the capital spending we incurred in 2007 was related to facilities, versus drilling, and therefore did not correspondingly increase our reserve base.

Additionally, decreases in production volumes in the U.S. accounted for $0.5 million of the decrease in depletion expense for 2007.

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. The end term of this agreement was extended in August 2006 from December 31, 2006 to December 31, 2008 and the useful life was extended to coincide with the new term of the agreement. In addition to the change in life, depreciation expense also decreased as a result of a reduction in the depreciable base during the second quarter of 2007 due to a portion of the payment from INPEX being applied against those costs.

Provision for Impairment of GTL Intangible Assets and Development Costs

The Company has been pursuing a GTL project for an extended period of time and has not been able to obtain a definitive agreement or appropriate financing. As a result the Company has 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 and 2006, we had no write downs of our GTL assets.

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.

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Impairment of Oil and Gas Properties 2008 vs. 2007

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

•

Impairment of Oil and Gas Properties 2007 vs. 2006

We impaired our China oil and gas properties by $6.1 million in 2007, compared to $5.4 million in 2006. The 2007 impairment was mainly the result of impairing our costs incurred in the Zitong block due to an unsuccessful second exploration well resulting in those costs of $17.6 million being included with the carrying value of proved properties for the ceiling test calculation. The 2006 impairment was a result increased operating costs of the Dagang field, including cost of the Windfall Levy established in March 2006.

Financial Condition, Liquidity and Capital Resources

Sources and Uses of Cash

Net cash and cash equivalents increased by $27.9 million for the year ended December 31, 2008 compared to a decrease of $2.5 million for 2007 and a decrease of $7.2 million for 2006.

•

Operating Activities

Our operating activities provided $17.1 million in cash for the year ended December 31, 2008 compared to $5.5 million and $14.4 million for the same periods in 2007 and 2006. 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. The decrease in cash from operating activities for the year ended December 31, 2007 was mainly due to a decrease in net production volumes of 14% offset by an increase in oil and gas prices of 6%, net of realized loss on derivative instruments associated with oil and gas operations. In addition, increases to operating costs, general and administrative and business and technology development expenses also reduced operating cash flows.

•

Investing Activities

Our investing activities used $49.3 million in cash for the year ended December 31, 2008 compared to $22.3 million for the same period in 2007 and $25.6 million for 2006. 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 $10.0 million in proceeds from the sale of assets and a recovery of development costs in 2007, compared to nil in 2008 and $6.0 million in proceeds from asset sales in 2006. There was also a decrease in capital asset expenditures of $6.0 million for 2008 as compared to 2007 and increase of $13.8 million for 2007 when compared to 2006.

Changes in capital investments by segment are detailed below:


	For the Year Ended							For the Year Ended
	December 31,							December 31,
					(Increase)							(Increase)
	2008		2007		Decrease			2007		2006		Decrease
Oil and Gas Activities:
Canada	$	6,484	$	—	$	(6,484	)	$	—	$	—	$	—
Ecuador		1,369		—		(1,369	)		—		—		—
China		8,378		23,488		15,110			23,488		9,086		(14,402	)
U.S.		4,542		3,052		(1,490	)		3,052		5,550		2,498
Business and Technology Development		4,833		5,098		265			5,098		3,206		(1,892	)

	$	25,606	$	31,638	$	6,032		$	31,638	$	17,842	$	(13,796	)

Canada

As noted above, two leases located in Canada were acquired in the third quarter of 2008. Capital investments this quarter consisted of capitalized interest, seismic/ERT and environmental work. In 2008, the overall focus has been on delineation activities, engineering and pre-filing regulatory requirements.

Ecuador

The increase in 2008 of $1.4 million of investment activities is due to a new project’s activities related to the signing of a contract to explore and develop Ecuador’s Pungarayacu heavy-oil field using our HTL^TM upgrading technology.

China

The decrease in investment in China in 2008 compared to 2007 was the result of a $9.6 million decrease in capital spending at Zitong and a $5.5 million decrease in capital spending at Dagang. Spending at Zitong during 2008 was limited to expenditures relating to the commencement of the second phase of the exploration program which were relatively minor compared to the drilling and completion costs incurred during 2007 for completing the first phase of the program which was concluded in December 2007. At Dagang, we spud five new development wells in 2007 compared to 2008 where we only completed a series of fracture stimulation projects. The increase from 2006 to 2007 was the result of a $9.1 million increase at our Zitong project and $5.3 million increase for the five new wells in 2007 at our Dagang project.

U.S.

The $1.5 million increase in U.S. capital spending in 2008 compared to 2007 was mainly due to the eight well drilling program at South Midway in 2008 compared to the cost of a new steam generator in 2007. This amount was offset by a decrease in cash inflows from asset sales of $1.0 million in the U.S. in 2007, compared to $6.0 million for the same period in 2006 when we had a ten well drilling program at South Midway.

Business and Technology Development

The decrease in capital spending during 2008 when compared to 2007 was due to the timing of costs relating to the construction and delivery of the Feedstock Test Facility (“FTF”). The increase of $1.9 million, when comparing 2007 to 2006, resulted from expenditures for the FTF increasing by $3.9 million which were offset by decreased expenditures of $1.2 million for the CDF and $0.4 million for GTL and $0.4 million for other capitalized development costs.

•

Financing Activities

Financing activities for the year ended December 31, 2008 consisted mainly of an equity private placement in the third quarter of 2008. In July 2008, the Company completed a Cdn.$88.0 million private placement consisting of 29,334,000 special warrants (“Special Warrants”) at Cdn.$3.00 per Special Warrant (the “Offering”). Each Special Warrant entitled the holder to one common share of the Company upon exercise of the Special Warrant. In August 2008, all of the Special Warrants were exercised for 29,334,000 common shares. The net proceeds from the Offering of the Special Warrants was approximately Cdn.$83.4 million.

In addition, in April 2008, the Company obtained a loan from a third party finance company in the amount of Cdn.$5.0 million bearing interest at 8% per annum. At the lender’s option the principal and accrued and unpaid interest was converted in August 2008 into the Company’s common shares at a conversion price of Cdn.$2.24 per share.

These cash inflows were offset by $2.6 million in professional fees and expenses associated with the pursuit of corporate financing initiatives by the Company’s Chinese subsidiary, Sunwing Energy and the payment at maturity on December 31, 2008 of a promissory note to Talisman in the principal amount of Cdn.$12.5 million plus accrued interest.

Financing activities for the year ended December 31, 2007 consisted of three draws totaling $13.0 million ($12.4 million net of financing costs) on two separate loan facilities. This increase in borrowings was offset by scheduled debt payments of $2.5 million. In 2006, we repaid notes in the amount of $5.5 million prior to maturity, made scheduled repayments of long-term debt of $3.2 million offset by an initial draw on a bank loan facility of $1.5 million ($1.3 million net of financing costs). Financing activities in 2007 also consisted of $4.0 million received from the exercise of warrants compared to 2006 when there were no warrants exercised but there was a $25.3 million private placement of common shares.

In April 2006, the Company closed a private placement of 11.4 million special warrants at $2.23 per special warrant for a total of $25.4 million. Each special warrant entitled the holder to receive, at no additional cost, one common share and one common share purchase warrant. All of the special warrants were subsequently exercised for common shares and common share purchase warrants. Each common share purchase warrant originally entitled the holder to purchase one common share at a price of $2.63 per share until the fifth anniversary date of the closing. In September 2007, these warrants were listed on the TSX and the exercise price was changed to Cdn.$2.93.

Outlook for 2009

Our 2009 capital program budget ranges from approximately $15 million to $20 million and will encompass the following: a) continuing development of our existing producing oil and gas properties to maximize near-term cash flow, b) the preparation of Tamarack and Pungarayacu for development, and c) engineering and development costs related to the preparation of our proprietary HTL^TM oil upgrading technology for full scale deployment in Canada and Ecuador. Management’s plans for financing its 2009 requirements and beyond include the potential for alliances or other arrangements with strategic partners as well as traditional project financing, debt and mezzanine financing or the sale of equity securities.

Discussions with potential strategic partners are focused primarily on national oil companies and other sovereign or government entities from Asian and Middle Eastern countries that have approached the Company and expressed interest in participating in the Company’s heavy oil activities in Ecuador, Canada and around the world.

The Company intends to utilize revenue from existing operations to fund the continuing transition of the Company to a heavy oil exploration, production and upgrading company and non-heavy oil related investments in our portfolio will be leveraged or monetized to capture value and provide maximum return for the Company. No assurances can be given that we will be able to enter into one or more alternative business alliances with other parties or raise additional capital. If we are unable to enter into such business alliances or obtain adequate additional financing, we will be required to curtail our operations, which may include the sale of assets.

In addition to Tamarack and Pungarayacu, the Company will continue to pursue ongoing discussions related to other HTL heavy oil opportunities in Canada, Latin America, the Middle East and North Africa.

Contractual Obligations and Commitments

The table below summarizes the contractual obligations that are reflected in our 2008 consolidated balance sheets and/or disclosed in the accompanying Notes:


	Payments Due by Year
	(stated in thousands of U.S. dollars)
	Total		2009		2010		2011		2012		After 2012
Consolidated Balance Sheets:
Note payable — current portion	$	5,612	$	5,612	$	—	$	—	$	—	$	—
Long term debt		37,855		—		6,549		31,306		—		—
Asset retirement obligation		3,738		15		1,928		—		—		1,795
Long term obligation		1,900		—		—		—		1,900		—
Other Commitments:
Interest payable		8,238		3,165		2,884		2,189		—		—
Lease commitments		3,337		1,191		1,009		680		331		126
Zitong exploration commitment		24,694		13,123		11,571		—		—		—

Total	$	85,374	$	23,106	$	23,941	$	34,175	$	2,231	$	1,921

We have excluded our normal purchase arrangements as they are discretionary and/or being performed under contracts which are cancelable immediately or with a 30-day notification period.

Critical Accounting Principles and Estimates

Our accounting principles are described in Note 2 to Notes to the Consolidated Financial Statements. We prepare our Consolidated Financial Statements in conformity with GAAP in Canada, which conform in all material respects to U.S. GAAP except for those items disclosed in Note 19 to the Consolidated Financial Statements. For U.S. readers, we have detailed the differences and have also provided a reconciliation of the differences between Canadian and U.S. GAAP in Note 19 to the Consolidated Financial Statements.

The preparation of our financial statements requires us to make estimates and judgments that affect our reported amounts of assets, liabilities, revenue and expenses. On an ongoing basis we evaluate our estimates, including those related to asset impairment, revenue recognition, fair market value of derivatives, allowance for doubtful accounts and contingencies and litigation. These estimates are based on information that is currently available to us and on various other assumptions that we believe to be reasonable under the circumstances. Actual results could vary from those estimates under different assumptions and conditions.

We have identified the following critical accounting policies that affect the more significant judgments and estimates used in preparation of our consolidated financial statements.

Full Cost Accounting — We follow Accounting Guideline 16 “Oil and Gas Accounting — Full Cost” (“AcG 16”) in accounting for our oil and gas properties. Under the full cost method of accounting, all exploration and development costs associated with lease and royalty interest acquisition, geological and geophysical activities, carrying charges for unproved properties, drilling both successful and unsuccessful wells, gathering and production facilities and equipment, financing, administrative costs directly related to capital projects and asset retirement costs are capitalized on a country-by-country cost center basis. As at December 31, 2008, the carrying values of our Canada, Ecuador, China and the U.S. cost centers were $81.1 million, $1.5 million, $48.1 million and $32.6 million, respectively.

The other generally accepted method of accounting for costs incurred for oil and gas properties is the successful efforts method. Under this method, costs associated with land acquisition and geological and geophysical activities are expensed in the year incurred and the costs of drilling unsuccessful wells are expensed upon abandonment.

As a consequence of following the full cost method of accounting, we may be more exposed to potential impairments if the carrying value of a cost center’s oil and gas properties exceeds its estimated future net cash flows than if we followed the successful efforts method of accounting. Impairment may occur if a cost center’s recoverable reserve estimates decrease, oil and natural gas prices decline or capital, operating and income taxes increase to levels that would significantly affect its estimated future net cash flows. See “Impairment of Proved Oil and Gas Properties” below.

Oil and Gas Reserves — The process of estimating quantities of reserves is inherently uncertain and complex. It requires significant judgments and decisions based on available geological, geophysical, engineering and economic data. These estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change. Our reserve estimates are based on current production forecasts, prices and economic conditions. Reserve numbers and values are only estimates and you should not assume that the present value of our future net cash flows from these estimates is the current market value of our estimated proved oil and gas reserves.

Reserve estimates are critical to many accounting estimates and financial decisions including:

•

determining whether or not an exploratory well has found economically recoverable reserves. Such determinations involve the commitment of additional capital to develop the field based on current estimates of production forecasts, prices and other economic conditions.

•

calculating our unit-of-production depletion rates. Proved reserves are used to determine rates that are applied to each unit-of-production in calculating our depletion expense. In 2008, oil and gas depletion of $29.2 million was recorded in depletion and depreciation expense. If our reserve estimates changed by 10%, our depletion and depreciation expense for 2008 would have changed by approximately $2.3 million assuming no other changes to our reserve profile. See “Depletion” below.

•

assessing our proved oil and gas properties for impairment on a quarterly basis. Estimated future net cash flows used to assess impairment of our oil and gas properties are determined using proved and probable reserves⁽¹⁾. See “Impairment of Proved Oil and Gas Properties” below.

Management is responsible for estimating the quantities of proved oil and natural gas reserves and preparing related disclosures. Estimates and related disclosures are prepared 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 COGE Handbook modified to reflect SEC requirements.

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 engineers who are familiar with the property and by our operational management. Our CEO and CFO meet with our operational personnel to review the current reserve estimates and related disclosures and upon their review and approval present the independent qualified reserves evaluators’ reserve reports to our Board of Directors with a recommendation for approval. Our Board of Directors has approved the reserve estimates and related disclosures.

The estimated discounted future net cash flows from estimated proved reserves included in the Supplementary Financial Information are based on prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower. Actual future net cash flows will also be affected by factors such as actual production levels and timing, and changes in governmental regulation or taxation, and may differ materially from estimated cash flows.


(1)		“Proved” oil and gas reserves are the estimated quantities of natural gas, crude oil, condensate and natural gas liquids that geological and engineering data demonstrate with reasonable certainty can be recoverable in future years from known reservoirs under existing economic and operating conditions. Reservoirs are considered proved if economic recoverability is supported by either actual production or a conclusive formation test. “Probable” reserves are those additional reserves that are less likely to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of estimated proved plus probable reserves.

Depletion —As indicated previously, our estimate of proved reserves are critical to calculating our unit-of-production depletion rates.

Another critical factor affecting our depletion rate is our determination that an impairment of unproved oil and gas properties has occurred. Costs incurred on an unproved oil and gas property are excluded from the depletion rate calculation until it is determined whether proved reserves are attributable to an unproved oil and gas property or upon determination that an unproved oil and gas property has been impaired. An unproved oil and gas property would likely be impaired if, for example, a dry hole has been drilled and there are no firm plans to continue drilling on the property. Also, the likelihood of partial or total impairment of a property increases as the expiration of the lease term approaches and there are no plans to drill on the property or to extend the term of the lease. We assess each of our unproved oil and gas properties for impairment on a quarterly basis. If we determine that an unproved oil and gas property has been totally or partially impaired we include all or a portion of the accumulated costs incurred for that unproved oil and gas property in the calculation of our unit-of-production depletion rate. As at December 31, 2008, we had $81.1 million, $1.5 million, $5.2 million and $4.2 million of costs incurred on unproved oil and gas properties in Canada, Ecuador, China and the U.S., respectively.

Our depletion rate is also affected by our estimates of future costs to develop the proved reserves. We estimate future development costs using quoted prices, historical costs and trends. It is difficult to predict prices for materials and services required to develop a field particularly over a period of years with rising oil and gas prices during which there is generally increased competition for a limited number of suppliers. We update our estimates of future costs to develop our proved reserves on a quarterly basis.

Impairment of Proved Oil and Gas Properties — We evaluate each of our cost centers’ proved oil and gas properties for impairment on a quarterly basis. The basis for calculating the amount of impairment is different for Canadian and U.S. GAAP purposes.

For Canadian GAAP, AcG 16 requires recognition and measurement processes to assess impairment of oil and gas properties (“ceiling test”). In the recognition of an impairment, the carrying value⁽¹⁾ of a cost center is compared to the undiscounted future net cash flows of that cost center’s proved reserves using estimates of future oil and gas prices and costs plus the cost of unproved properties that have been excluded from the depletion calculation. If the carrying value is greater than the value of the undiscounted future net cash flows of the proved reserves plus the cost of unproved properties excluded from the depletion calculation, then the amount of the cost center’s potential impairment must be measured. A cost center’s impairment loss is measured by the amount its carrying value exceeds the discounted future net cash flows of its proved and probable reserves using estimates of future oil and gas prices and costs plus the cost of unproved properties that have been excluded from the depletion calculation and which contain no probable reserves. The net cash flows of a cost center’s proved and probable reserves are discounted using a risk-free interest rate adjusted for political and economic risk on a country-by-country basis. The amount of the impairment loss is recognized as a charge to the results of operations and a reduction in the net carrying amount of a cost center’s oil and gas properties. We provided for nil, $6.1 million and $5.4 million in a ceiling test impairment for our China cost center for the years ended December 31, 2008, 2007 and 2006, respectively.

For U.S. GAAP, we follow the requirements of the SEC’s Regulation S-X Article 4-10(c)4 for determining the limitation of capitalized costs. Accordingly, the carrying value⁽¹⁾ of a cost center’s oil and gas properties cannot exceed the future net cash flows, discounted at 10%, of its proved reserves using period-end oil and gas prices and costs plus (i) the cost of properties that have been excluded from the depletion calculation and (ii) the lower of cost or estimated fair value of unproved properties included in the depletion calculation less (iii) income tax effects related to differences between the book and tax basis of the properties. The amount of the impairment loss is recognized as a charge to the results of operations and a reduction in the net carrying amount of a cost center’s oil and gas properties. We provided for $20.3 million, nil and $7.6 million in ceiling test impairments for our U.S. cost center for the years ended December 31, 2008, 2007 and 2006, respectively, and $21.6 million, $5.9 million and $15.9 million for the years ended December 31, 2008, 2007 and 2006 for our China cost center.


(1)		For Canadian GAAP, the carrying value includes all capitalized costs for each cost center, including costs associated with asset retirement net of estimated salvage values, unproved properties and major development projects, less accumulated depletion and ceiling test impairments. This is essentially the same definition according to U.S. GAAP, under Regulation S-X, except that the carrying value of assets should be net of deferred income taxes and costs of major development projects are to be considered separately for purposes of the ceiling test calculation.

Asset Retirement Obligations — For Canadian GAAP, we follow Canadian Institute of Chartered Accountants (“CICA”) Section 3110, “Asset Retirement Obligations” which requires asset retirement costs and liabilities associated with site restoration and abandonment of tangible long-lived assets be initially measured at a fair value which approximates the cost a third party would incur in performing the tasks necessary to retire such assets. The fair value is recognized in the financial statements at the present value of expected future cash outflows to satisfy the obligation. Subsequent to the initial measurement, the effect of the passage of time on the liability for the asset retirement obligation (accretion expense) and the amortization of the asset retirement cost are recognized in the results of operations. We measure the expected costs required to retire our producing U.S. oil and gas properties at a fair value, which approximates the cost a third party would incur in performing the tasks necessary to abandon the field and restore the site. We do not make such a provision for our oil and gas 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. Asset retirement costs are depleted using the unit of production method based on estimated proved reserves and are included with depletion and depreciation expense. The accretion of the liability for the asset retirement obligation is included with interest expense.

For U.S. GAAP, we follow SFAS No. 143, “Accounting for Asset Retirement Obligations” which conforms in all material respects with Canadian GAAP.

Research and Development — We incur various expenses in the pursuit of HTL^TM and GTL projects, including HTL^TM Technology for heavy oil processing, throughout the world. For Canadian GAAP, such expenses incurred prior to signing a MOU, or similar agreements, are considered to be business and technology development expenses and are charged to the results of operations as incurred. Upon executing a MOU to determine the technical and commercial feasibility of a project, including studies for the marketability of the projects’ products, we assess that the feasibility and related costs incurred have potential future value, are probable of leading to a definitive agreement for the exploitation of proved reserves and should be capitalized. If no definitive agreement is reached, then the capitalized costs, which are deemed to have no future value, are written down to our results of operations with a corresponding reduction in our investments in HTL^TM or GTL assets. For the years ended December 31, 2008, 2007 and 2006, we wrote down $5.1 million, nil and nil, respectively, of capitalized negotiation and feasibility costs associated with our GTL projects which did not result in definitive agreements with no write downs in those same periods related to our HTL^TM projects.

Additionally, we incur costs to develop, enhance and identify improvements in the application of the HTL^TM and GTL technologies we license or own. We follow CICA Section 3450 “Research and Development Costs” in accounting for the development costs of equipment and facilities acquired or constructed for such purposes. Development costs are capitalized 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. We review the recoverability of such capitalized development costs annually, or as changes in circumstances indicate the development costs might be impaired, through an evaluation of the expected future discounted cash flows from the associated projects. If the carrying value of such capitalized development costs exceeds the expected future discounted cash flows, the excess is written down to the results of operations with a corresponding reduction in the investments in HTL^TM and GTL assets.

Costs incurred in the operation of equipment and facilities used to develop or enhance HTL^TM and GTL technologies prior to commencing commercial operations are business and technology development expenses and are charged to the results of operations in the period incurred.

For U.S. GAAP, we follow SFAS No. 2, “Research and Development”. As with Canadian GAAP, costs of equipment or facilities that are acquired or constructed for research and development activities are capitalized as tangible assets 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. However, for U.S. GAAP such facilities must have alternative future uses to be capitalized. As with Canadian GAAP, expenses incurred in the operation of research and development equipment or facilities prior to commencing commercial operations are business and technology development expenses and are charged to the results of operations in the period incurred. The major difference for U.S. GAAP purposes is that feasibility, marketing and related costs incurred prior to executing a definitive agreement are considered to be research and development costs and are expensed as incurred. For the years ended December 31, 2008, 2007 and 2006, we expensed $0.4 million, $0.3 million and $1.0 million, respectively, of feasibility, marketing and related costs incurred prior to executing definitive agreements.

Intangible Assets — Our intangible assets consists of the underlying value of an exclusive, irrevocable license to deploy, worldwide, the RTP^TMProcess for petroleum applications (HTL^TM Technology) as well as the exclusive right to deploy the RTP^TMProcess in all applications other than biomass and a master license from Syntroleum permitting us to use the Syntroleum Process in an unlimited number of projects around the world. For Canadian GAAP, we follow CICA Section 3062 “Goodwill and Other Intangible Assets” whereby intangible assets, acquired individually or with a group of other assets, are initially recognized and measured at cost. Intangible assets with finite lives are amortized over their useful lives whereas intangible assets with indefinite useful lives are not amortized unless it is subsequently determined to have a finite useful life. Intangible assets are reviewed annually for impairment, or when events or changes in circumstances indicate that the carrying value of an intangible asset may not be recoverable. If the carrying value of an intangible asset exceeds its fair value or expected future discounted cash flows, the excess is written down to the results of operations with a corresponding reduction in the carrying value of the intangible asset. The HTL^TM Technology and the Syntroleum GTL master license have finite lives, which correlate with the useful lives of the facilities we expect to develop that will use the technologies. The amount of the carrying value of the technologies we assign to each facility will be amortized to earnings on a basis related to the operations of the facility from the date on which the facility is placed into service. We evaluate the carrying values of the HTL^TM Technology and the Syntroleum GTL master license annually, or as changes in circumstances indicate the intangible assets might be impaired, based on an assessment of its fair market value.

For U.S. GAAP, we follow SFAS No. 142, “Goodwill and Other Intangible Assets” which conforms in all material respects with Canadian GAAP.

2008 Accounting Changes

On January 1, 2008, the Company adopted three new accounting standards that were issued by the Canadian Institute of Chartered Accountants (“CICA”): Handbook Section 1535 “Capital Disclosures” (“S.1535”), Handbook Section 3862 “Financial Instruments — Disclosures” (“S.3862”), and Handbook Section 3863 “Financial Instruments — Presentation” (“S.3863”). S.1535 establishes standards for disclosing information about an entity’s capital and how it is managed. The objective of S.3862 is to require entities to provide disclosures in their financial statements that enable users to evaluate both the significance of financial instruments for the entity’s financial position and performance; and the nature and extent of risks arising from financial instruments to which the entity is exposed during the period and at the balance sheet date, and how the entity manages those risks. The purpose of S.3863 is to enhance financial statement users’ understanding of the significance of financial instruments to an entity’s financial position, performance and cash flows. The latter two replaced Handbook Section.3861 “Financial Instruments — Disclosure and Presentation”. The Company adopted the new standards on January 1, 2008 with additional disclosures included in these consolidated financial statements. There was no transitional adjustment to the consolidated financial statements as a result of having adopted these standards.

Impact of New and Pending Canadian GAAP Accounting Standards

In February 2008, the CICA issued Handbook Section 3064, “Goodwill and Intangible assets,” (“S.3064”) replacing Handbook Section 3062, “Goodwill and Other Intangible Assets” (“S.3062”) and Handbook Section 3450, “Research and Development Costs”. S.3064 will be applicable to financial statements relating to fiscal years beginning on or after October 1, 2008. Accordingly, the Company will adopt the new standards for its fiscal year beginning January 1, 2009. The new section establishes standards for the recognition, measurement, presentation and disclosure of goodwill subsequent to its initial recognition and of intangible assets by profit-oriented enterprises. Standards concerning goodwill are unchanged from the standards included in the previous S.3062. Management has concluded that the requirements of this new Section as they relate to goodwill will not have a material impact on its consolidated financial statements.

Also in February 2008, the CICA amended portions of Handbook Section 1000, “Financial Statement Concepts”, which the CICA concluded permitted deferral of costs that did not meet the definition of an asset. The amendments apply to annual and interim financial statements relating to fiscal years beginning on or after October 1, 2008. Upon adoption of S.3064 and the amendments to Section 1000 on January 1, 2009, capitalized amounts that no longer meet the definition of an asset will be expensed retrospectively. Management has concluded that the requirements of this new Section will not have a material impact on its consolidated financial statements.

Effective January 1, 2008, the Company implemented amendments to CICA Handbook Section 1400 “General Standards of Financial Statement Presentation” that incorporates going concern guidance. These changes require management to make an assessment of an entity’s ability to continue as a going concern when preparing financial statements. Financial statements shall be prepared on a going concern basis unless management either intends to liquidate the entity or to cease trading, or has no realistic alternative but to do so. When management is aware, in making its assessment, of material uncertainties related to events or conditions that may cast significant doubt upon the entity’s ability to continue as a going concern, those uncertainties shall be disclosed. The new requirements are applicable to all entities and are effective for annual financial statements relating to fiscal years beginning on or after January 1, 2008. There was no material impact on the Company’s consolidated financial statements as the Company already going concern disclosure in its consolidated financial statements.

Convergence of Canadian GAAP with International Financial Reporting Standards

In April 2008, the CICA published the exposure draft “Adopting IFRSs in Canada”. The exposure draft proposes to incorporate International Financial Reporting Standards (“IFRS”) into the CICA Accounting Handbook effective for interim and annual financial statements relating to fiscal years beginning on or after January 1, 2011. At this date, publicly accountable enterprises will be required to prepare financial statements in accordance with IFRS.

Under IFRS, the primary audience is capital markets and, as a result, there is significantly more disclosure required, specifically for quarterly reporting. Further, while IFRS uses a conceptual framework similar to Canadian GAAP, there are significant differences in accounting policy which must be addressed. The Company has not completed development of its IFRS changeover plan, which will include project structure and governance, deployment of resources and training, analysis of key GAAP differences and a phased plan to assess accounting policies under IFRS as well as potential IFRS 1 exemptions. The Company hopes to complete its project scoping, which will include a timetable for assessing the impact on data systems, internal controls over financial reporting, and business activities, such as financing and compensation arrangements, once the exemptions as described below relating to full cost oil and gas companies have been determined.

The International Accounting Standards Board (“IASB”) has stated that it plans to issue an exposure draft relating to certain amendments to IFRS 1 in order to make it more useful to Canadian entities adopting IFRS for the first time. One such exemption relating to full cost oil and gas accounting is expected to result in a reduced administrative transition from the current Canadian AcG-16 to IFRS. It is anticipated that this exposure draft will not result in an amended IFRS 1 standard until late in 2009. The amendment will potentially permit the Company to apply IFRS prospectively to its full cost pool, rather than the retrospective assessment of capitalized exploration and development expenses, with the proviso that a ceiling test, under IFRS standards, be conducted at the transition date.

Impact of New and Pending U.S. GAAP Accounting Standards

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities” (“SFAS No. 161”). The new standard is intended to improve financial reporting about derivative instruments and hedging activities by requiring enhanced disclosures to enable investors to better understand their effects on an entity’s financial position, financial performance, and cash flows. It is effective beginning January 1, 2009. Management has concluded that the requirements of this recent statement will not have a material impact on its financial statements.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”). This statement defines fair value, establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. The Company adopted the provisions of SFAS No. 157 effective January 1, 2008. The implementation of this standard did not have a material impact on the consolidated financial statements as the current policy on accounting for fair value measurements is consistent with this guidance. The Company has, however, provided additional prescribed disclosures not required under Canadian GAAP.

In December 2008, the SEC released Final Rule, Modernization of Oil and Gas Reporting to revise the existing Regulation S-K and Regulation S-X reporting requirements to align with current industry practices and technological advances. The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. In addition, the new disclosure requirements require a company to (a) disclose its internal control over reserves estimation and report the independence and qualification of its reserves preparer or auditor, (b) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserve audit and (c) report oil and gas reserves using an average price based upon the prior 12-month period rather than period-end prices. The provisions of this final ruling will become effective for disclosures in our Annual Report on Form 10-K for the year ended December 31, 2009. Management is currently evaluating the impact of these changes on its financial statements.

Off Balance Sheet Arrangements

At December 31, 2008 and 2007, we did not have any relationships with unconsolidated entities or financial partnerships, such as structured finance or special purpose entities, which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. In addition, we do not engage in trading activities involving non-exchange traded contracts. As such, we are not materially exposed to any financing, liquidity, market or credit risk that could arise if we had engaged in such relationships. We do not have relationships and transactions with persons or entities that derive benefits from their non-independent relationship with us, or our related parties, except as disclosed herein.

Related Party Transactions

The Company has entered into agreements with a number of entities which are related through common directors or shareholders. These entities provide access to an aircraft, the services of administrative and technical personnel and office space or facilities in Vancouver, London and Singapore. The Company is billed on a cost recovery basis. For the year ended December 31, 2008 the costs incurred in the normal course of business with respect to the above arrangements amounted to $3.0 million ($3.3 million for 2007 and $3.0 million for 2006), and are recorded in general and administrative expense in the statement of operations. As at December 31, 2008 amounts included in accounts payable and accrued liabilities on the balance sheet under these arrangements were $0.1 million ($0.2 million at December 31, 2007).

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to normal market risks inherent in the oil and gas business, including equity market risk, commodity price risk, foreign-currency rate risk, interest rate risk and credit risk. We recognize these risks and manage our operations to minimize our exposures to the extent practicable.

NON-TRADING

Equity Market Risks

We currently have limited production in the U.S. and China, which have not generated sufficient cash from operations to fund our exploration and development activities. Historically, we have relied on the equity markets as the primary source of capital to fund our expansion and growth opportunities. Based on our current plans, we estimate that we will need approximately $15 to $20 million to fund our capital investment programs for 2009.

We can give no assurance that we will be successful in obtaining financing as and when needed. Factors beyond our control, such as the recent credit crisis, may make it difficult or impossible for us to obtain financing on favorable terms or at all. Failure to obtain any required financing on a timely basis may cause us to postpone our development plans, forfeit rights in some or all of our projects or reduce or terminate some or all of our operations.

Commodity Price Risk

Commodity price risk related to crude oil prices is one of our most significant market risk exposures. Crude oil prices and quality differentials are influenced by worldwide factors such as the recent credit crisis, OPEC actions, political events and supply and demand fundamentals. To a lesser extent we are also exposed to natural gas price movements. Natural gas prices are generally influenced by oil prices, North American supply and demand and local market conditions. Using the Company’s 2008 actual worldwide crude oil production levels as an estimate for 2009 production, a $1.00/Bbl change in the realized price of oil, would increase or decrease net income and cash from operations for 2009 by $0.7 million. Using the Company’s 2008 actual natural gas production levels as an estimate for 2009 production, a $1.00/Mcf change in the realized price of natural gas would increase or decrease net income and cash from operations for 2009 by less than $0.1 million.

We periodically engage in the use of derivatives to minimize variability in our cash flow from operations and currently have costless collar contracts put in place as part of our bank loan facilities. 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 had 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 also 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 WTI as the index traded on the NYMEX. See Note 12 to the Consolidated Financial Statements.

On December 31, 2008, the Company’s open positions on the derivatives mentioned above had a fair value of $2.2 million. A 10% increase in oil prices would reduce the fair value by approximately $1.1 million, while a 10% decrease in prices would increase the fair value by approximately $1.1 million. The fair value change assumes volatility based on prevailing market parameters at December 31, 2008.

Decreases in oil and natural gas prices would negatively impact our results of operations as a direct result of a reduction in revenues but may also do so in the ceiling test calculation for the impairment of our oil and gas properties. On a quarterly basis, we compare the value of our proved and probable reserves, using estimated future oil and gas prices⁽¹⁾, to the carrying value of our oil and gas properties. The ceiling test calculation is sensitive to oil and gas prices and in a period of declining prices could result in a charge to our results of operations as we experienced in 2001 when we recorded a $14.0 million provision for impairment for Canadian GAAP and an additional $10.0 million for U.S. GAAP mainly due to a decline in oil and gas prices. Decreases in oil and gas prices from those used in our ceiling test calculation as at December 31, 2008 as discussed above in “Critical Accounting Principles and Estimates — Impairment of Proved Oil and Gas Properties” may result in additional impairment provisions of our oil and gas properties.


(1)		The recoverable value of probable reserves is included only for the measurement of the impairment of the carrying value of oil and gas properties as required under Canadian GAAP but not for U.S. GAAP. Additionally, U.S. GAAP requires the use of period end oil and gas prices to measure the amount of the impairment rather than estimated future oil and gas prices as required by Canadian GAAP. See ‘Critical Accounting Principles and Estimates’ for the difference between Canadian and U.S. GAAP in calculating the impairment provision for oil and gas properties.

Foreign Currency Rate Risk

Foreign currency risk refers to the risk that the value of a financial commitment, recognized asset or liability will fluctuate due to changes in foreign currency rates. The main underlying economic currency of the Company’s cash flows is the U.S. dollar. This is because the Company’s major product, crude oil, is priced internationally in U.S. dollars. Accordingly, the Company does not expect to face foreign exchange risks associated with its production revenues. However, some of the Company’s cash flow stream relating to certain international operations is based on the U.S. dollar equivalent of cash flows measured in foreign currencies. The majority of the operating costs incurred in the Chinese operations are paid in Chinese renminbi. The majority of costs incurred in the administrative offices in Vancouver and Calgary, as well as some business development costs, are paid in Canadian dollars. In addition, with the recent property acquisition in Alberta (see Note 18) the Company’s Canadian dollar expenditures have increased during the last half of 2008 along with an increase in cash and debt balances denominated in Canadian dollars. Disbursement transactions denominated in Chinese renminbi and Canadian dollars are converted to U.S. dollar equivalents based on the exchange rate as of the transaction date. Foreign currency gains and losses also come about when monetary assets and liabilities, mainly short term payables and receivables, denominated in foreign currencies are translated at the end of each month. The estimated impact of a 10% strengthening or weakening of the Chinese renminbi, and Canadian dollar, as of December 31, 2008 on net loss and accumulated deficit for the year ended December 31, 2008 is a $3.6 million increase, and a $3.7 million decrease, respectively. To help reduce the Company’s exposure to foreign currency risk it seeks to maximize the expenditures and contracts denominated in U.S. dollars and minimize those denominated in other currencies, except for its Canadian activities where it attempts to hold cash denominated in Canadian dollars in order to manage its currency risk related to outstanding debt and current liabilities denominated in Canadian dollars.

Interest Rate Risk

Interest rate risk refers to the risk that the value of a financial instrument or cash flows associated with the instrument will fluctuate due to the changes in market interest rates. Interest rate risk arises from interest-bearing borrowings which have a variable interest rate. The Company currently has two separate bank loan facilities, a promissory note and a convertible note with fluctuating interest rates. The Company estimates that its net loss and accumulated deficit for the year ended December 31, 2008 would have changed $0.2 million for every 1% change in interest rates as of December 31, 2008. The Company is not currently actively attempting to mitigate this interest rate risk given the limited amount and term of its borrowings and the current global interest rate environment.

Credit Risk

The Company is exposed to credit risk with respect to its cash held with financial institutions, accounts receivable and advance balances. The Company believes its exposure to credit risk related to cash held with financial institutions is minimal due to the quality of the institutions where the cash is held and the nature of the deposit instruments. Most of the Company’s accounts receivable balances relate to oil and natural gas sales and are exposed to typical industry credit risks. In addition, accounts receivable balances consist of costs billed to joint venture partners where the Company is the operator and advances to partners for joint operations where the Company is not the operator. The advance balance relates to an arrangement whereby scheduled advances were made to a third party contractor associated with negotiating an HTL^TM and/or GTL project for the Company. The Company manages its credit risk by entering into sales contracts only with established entities and reviewing its exposure to individual entities on a regular basis. Of the $4.9 million trade receivables balance as at December 31, 2008, $3.1 million is due from a single customer and $0.4 million is due from another single customer. There are no other customers who represent more than 5% of the total balance of trade receivables. Included in the Company’s trade receivable balance are debtors with a carrying amount of $0.4 million as of the year ended December 31, 2008 which are past due at the reporting date for which the Company has not provided an allowance, as there has not been a significant change in credit quality and the amounts are still considered recoverable. During the quarter ended September 30, 2008 the Company recorded an allowance associated with the advance balance for the entire outstanding amount of $0.7 million. The provision was recorded in General and Administrative expense in the accompanying Statement of Operations and Comprehensive Loss. There were no other changes to the allowance for credit losses account during the three-month period ended December 31, 2008 and no other losses associated with credit risk were recorded during this same period.

Liquidity Risk

Liquidity risk is the risk that suitable sources of funding for the Company’s business activities may not be available, which means it may be forced to sell financial assets or non-financial assets, refinance existing debt, raise new debt or issue equity. The Company’s present plans to generate sufficient resources to assure continuation of its operations and achieve its capital investment objectives include alliances or other arrangements with entities with the resources to support the Company’s projects as well as project financing, debt financing or the sale of equity securities. The availability of financing is dependent in part on the return of the credit and equity markets to normalized conditions. During the fourth quarter of 2008, as a result of the global economic crisis, the terms and availability of equity and debt capital have been materially restricted and financing may not be available when it required or on commercially acceptable terms.

TRADING

We do not enter into contracts for trading or speculative purposes. As such, we are not materially exposed to any financing, liquidity, market or credit risk that could arise if we had entered into such contracts.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Financial Statements and Related Information


	Page

Report of Independent Registered Chartered Accountants		50

Consolidated Financial Statements

Consolidated Balance Sheets		51

Consolidated Statements of Operations and Comprehensive Loss		52

Consolidated Statements of Shareholders’ Equity		53

Consolidated Statements of Cash Flows		54

Notes to the Consolidated Financial Statements		55

Quarterly Financial Data in Accordance with Canadian and U.S. GAAP (Unaudited)		90

Supplementary Disclosures About Oil and Gas Production Activities (Unaudited)		90

REPORT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS

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

We have audited the accompanying consolidated balance sheets of Ivanhoe Energy Inc. and subsidiaries (the “Company”) as at December 31, 2008 and 2007, and the related consolidated statements of operations and comprehensive loss, shareholders’ equity and cash flows for each of the three years in the period ended December 31, 2008. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). These standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Ivanhoe Energy Inc. and subsidiaries as at December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 in conformity with accounting principles generally accepted in Canada.

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the consolidated financial statements, the Company’s recurring losses from operations and accumulated deficit raise substantial doubt about its ability to continue as a going concern. Management’s plans concerning these matters are also discussed in Note 2 to the consolidated financial statements. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2008, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 26, 2009 expressed an unqualified opinion on the Company’s internal control over financial reporting.

(signed) “Deloitte & Touche LLP”

Independent Registered Chartered Accountants
Calgary, Canada
February 26, 2009

IVANHOE ENERGY INC.

Consolidated Balance Sheets

(stated in thousands of U.S. Dollars, except share amounts)


	As at December 31,
	2008			2007

Assets
Current Assets:
Cash and cash equivalents (Note 12)	$	39,265		$	11,356
Accounts receivable (Note 12)		4,870			9,376
Advance (Note 12)		—			825
Prepaid and other current assets		1,658			602
Derivative instruments (Note 12)		2,159			—

		47,952			22,159

Oil and gas properties and development costs, net (Note 3)		176,550			111,853
Intangible assets — technology (Note 4)		92,153			102,153
Long term assets		620			751

	$	317,275		$	236,916


Liabilities and Shareholders’ Equity
Current Liabilities:
Accounts payable and accrued liabilities (Note 12)	$	10,093		$	9,538
Income tax payable (Note 12)		650			—
Debt — current portion (Note 5 and 12)		5,612			6,729
Derivative instruments (Note 12)		—			9,432

		16,355			25,699

Long term debt (Note 5 and 12)		37,855			9,812
Asset retirement obligations (Note 6)		3,738			2,218
Long term obligation (Note 7)		1,900			1,900

		59,848			39,629

Commitments and contingencies (Note 7)

Going concern and basis of presentation (Note 2)

Shareholders’ Equity:
Share capital, issued 279,381,187 common shares;
December 31, 2007 244,873,349 common shares		413,857			324,262
Purchase warrants (Note 8)		18,805			23,078
Contributed surplus		16,862			9,937
Convertible note (Note 8)		2,086			—
Accumulated deficit		(194,183	)		(159,990	)

		257,427			197,287

	$	317,275		$	236,916

(See accompanying Notes to the Consolidated Financial Statements)

Approved by the Board:


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

IVANHOE ENERGY INC.

Consolidated Statements of Operations and Comprehensive Loss
(stated in thousands of U.S. Dollars, except share amounts)


	Year Ended December 31,
	2008			2007			2006

Revenue
Oil and gas revenue (Note 12)	$	66,490		$	43,635		$	47,748
Gain (loss) on derivative instruments (Note 12)		1,966			(10,587	)		(424	)
Interest income		710			469			776

		69,166			33,517			48,100


Expenses
Operating costs		26,652			17,319			16,133
General and administrative		18,190			12,076			10,180
Business and technology development		6,453			9,625			7,610
Depletion and depreciation		31,904			26,524			32,550
Interest expense and financing costs		1,829			1,050			963
Provision for impairment of GTL intangible asset and development costs (Notes 3 and 4)		15,054			—			—
Write off of deferred financing costs (Note 13)		2,621			—			—
Provision for impairment of oil and gas properties (Note 3)		—			6,130			5,420
Write off of deferred acquisition costs		—			—			736

		102,703			72,724			73,592


Loss before Income Taxes		(33,537	)		(39,207	)		(25,492	)

Current provision for income taxes (Note 14)		(656	)		—			—


Net Loss and Comprehensive Loss	$	(34,193	)	$	(39,207	)	$	(25,492	)


Net Loss per share — Basic and Diluted	$	(0.13	)	$	(0.16	)	$	(0.11	)


Weighted Average Number of Shares (in thousands)
Basic and Diluted *(Note 15)*		258,815			242,362			235,640

(See accompanying Notes to the Consolidated Financial Statements)

IVANHOE ENERGY INC.

Consolidated Statements of Shareholders’ Equity
(stated in thousands of U.S. Dollars, except share amounts)


	Share Capital				Purchase			Contributed			Convertible		Accumulated
	Shares		Amount		Warrants			Surplus			Note		Deficit			Total
	(thousands)
Balance December 31, 2005		220,779	$	291,088	$	5,150		$	3,820		$	—	$	(95,291	)	$	204,767
Net loss and comprehensive loss		—		—		—			—			—		(25,492	)		(25,492	)
Shares and purchase warrants issued for:
Acquisition of oil and gas assets (Note 18)		8,591		20,000		—			—			—		—			20,000
Private placements, net of share issue costs (Note 8)		11,400		6,493		18,805			—			—		—			25,298
Exercise of options (Note 9)		297		743		—			(252	)		—		—			491
Employee bonuses		149		401		—			—			—		—			401
Compensation calculated for stock option grants (Note 9)		—		—		—			2,921			—		—			2,921

Balance December 31, 2006		241,216		318,725		23,955			6,489			—		(120,783	)		228,386
Net loss and comprehensive loss		—		—		—			—			—		(39,207	)		(39,207	)
Shares issued for:
Exercise of purchase warrants (Note 8)		2,000		4,313		(313	)		—			—		—			4,000
Exercise of options (Note 9)		1,231		431		—			(52	)		—		—			379
Employee bonuses		427		793		—			—			—		—			793
Expiry of purchase warrants (Note 8)		—		—		(564	)		564			—		—			—
Compensation calculated for stock option grants (Note 9)		—		—		—			2,936			—		—			2,936

Balance December 31, 2007		244,874		324,262		23,078			9,937			—		(159,990	)		197,287
Net loss and comprehensive loss		—		—		—			—			—		(34,193	)		(34,193	)
Shares issued for:
Private placements, net of share issue costs (Note 8)		29,334		82,451		—			—			—		—			82,451
Exercise of convertible debt (Note 8)		2,291		4,862		—			—			—		—			4,862
Exercise of options (Note 9)		2,666		1,792		—			(587	)		—		—			1,205
Employee bonuses		216		490		—			—			—		—			490
Convertible note issued (Note 8)		—		—		—			—			2,086		—			2,086
Expiry of purchase warrants (Note 8)		—		—		(4,273	)		4,273			—		—			—
Compensation calculated for stock option grants (Note 9)		—		—		—			3,239			—		—			3,239

Balance December 31, 2008		279,381	$	413,857	$	18,805		$	16,862		$	2,086	$	(194,183	)	$	257,427

(See accompanying Notes to the Consolidated Financial Statements)

IVANHOE ENERGY INC.

Consolidated Statements of Cash Flows
(stated in thousands of U.S. Dollars)


	Year Ended December 31,
	2008			2007			2006

Operating Activities
Net loss and comprehensive loss	$	(34,193	)	$	(39,207	)	$	(25,492	)
Items not requiring use of cash:
Depletion and depreciation		31,904			26,524			32,550
Write-downs and provision for impairment (Note 3 and 4)		15,054			6,130			5,420
Stock based compensation (Note 9)		3,554			3,729			2,921
Unrealized (gain) loss on derivative instruments (Note 12)		(11,591	)		8,939			493
Write off of deferred financing costs (Note 13)		2,621			—			—
Unrealized foreign exchange loss		1,762			—			—
Provision for uncollectible accounts (Note 12)		1,016			—			—
Write off of deferred acquisition costs		—			—			736
Other		783			649			600
Abandonment costs settled (Note 6)		—			(792	)		—
Changes in non-cash working capital items (Note 16)		6,143			(483	)		(2,876	)

		17,053			5,489			14,352

Investing Activities
Capital investments		(25,606	)		(31,638	)		(17,842	)
Acquisition of oil and gas assets (Note 18)		(22,308	)		—			—
Proceeds from sale of assets (Note 3)		100			1,000			5,950
Recovery of development costs (Note 3)		—			9,000			—
Advance repayments (payments)		200			500			(125	)
Merger and acquisition related costs		—			—			(736	)
Other		(777	)		28			(116	)
Changes in non-cash working capital items (Note 16)		(930	)		(1,177	)		(12,708	)

		(49,321	)		(22,287	)		(25,577	)

Financing Activities
Shares issued on private placements, net of share issue costs (Note 8)		82,451			—			25,298
Proceeds from exercise of options and warrants (Notes 8 and 9)		1,205			4,379			491
Proceeds from debt obligations, net of financing costs (Note 5)		5,490			12,356			1,280
Payments of debt obligations (Note 5)		(15,750	)		(2,460	)		(8,689	)
Payments of deferred financing costs (Note 13)		(2,621	)		—			—
Other		(50	)		—			—
Changes in non-cash working capital items (Note 16)		26			—			—

		70,751			14,275			18,380


Foreign Exchange Loss on Cash and Cash Equivalents Held in a Foreign Currency		(10,574	)		—			—


Increase (decrease) in Cash and Cash Equivalents, for the year		27,909			(2,523	)		7,155
Cash and cash equivalents, beginning of year		11,356			13,879			6,724

Cash and Cash Equivalents, end of year	$	39,265		$	11,356		$	13,879

(See accompanying Notes to the Consolidated Financial Statements)

IVANHOE ENERGY INC.

Notes to the Consolidated Financial Statements
(all tabular amounts are expressed in thousands of U.S. Dollars, except share and per share amounts)

1. NATURE OF OPERATIONS

Ivanhoe Energy Inc. (the “Company” or “Ivanhoe Energy”), a Canadian company, is an independent international heavy oil development and production company focused on pursuing long-term growth in its reserves and production. Ivanhoe Energy plans to utilize technologically innovative methods designed to significantly improve recovery of heavy oil resources, including the anticipated commercial application of the patented rapid thermal processing process (“RTP^TMProcess”) for heavy oil upgrading (“HTL^TM Technology” or “HTL^TM") and enhanced oil recovery (“EOR”) techniques. In addition, the Company seeks to expand its reserve base and production through conventional exploration and production (“E&P”) of oil and gas. Our core operations are currently carried out in China, the United States, Canada and Ecuador.

2. SIGNIFICANT ACCOUNTING POLICIES

These consolidated financial statements have been prepared in accordance with generally accepted accounting principles (“GAAP”) in Canada. The impact of material differences between Canadian and U.S. GAAP on the consolidated financial statements is disclosed in Note 19.

The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts and other disclosures in these consolidated financial statements. Actual results may differ from those estimates.

In particular, the amounts recorded for depletion and depreciation of the oil and gas properties and accretion for asset retirement obligations are based on estimates of reserves and future costs. By their nature, these estimates, and those related to future cash flows used to assess impairment of oil and gas properties and development costs as well as intangible assets, are subject to measurement uncertainty and the impact on the financial statements of future periods could be material.

Going Concern and Basis of Presentation

The Company’s financial statements as at and for the year ended December 31, 2008 have been prepared in accordance with Canadian generally accepted accounting principles applicable to a going concern, which assumes that the Company will continue in operation for the foreseeable future and will be able to realize its assets and discharge its liabilities in the normal course of operations. The Company incurred a net loss of $34.2 million for the year ended December 31, 2008, and as at December 31, 2008, had an accumulated deficit of $194.2 million and positive working capital of $31.6 million. The Company currently anticipates incurring substantial expenditures to further its capital development programs, particularly those related to the development of two recently acquired oil sands leases in Alberta and the development of a heavy oil field in Ecuador. The Company’s cash flow from operating activities will not be sufficient to both satisfy its current obligations and meet the requirements of these capital investment programs. The continued existence of the Company is dependent upon its ability to obtain capital to fund further development and to meet obligations to preserve its interests in these properties and to meet the obligations associated with other potential HTL™ projects. The Company intends to finance the future payments required for its capital projects from a combination of strategic investors and/or traditional debt and equity markets, either at a parent company level or at the project level. Traditional debt and equity markets may not be accessible at the current time and as such the outcome of these matters cannot be predicted with certainty at this time and therefore the Company may not be able to continue as a going concern. These consolidated financial statements do not include any adjustments to the amounts and classification of assets and liabilities that may be necessary should the Company be unable to continue as a going concern.

Principles of Consolidation

These consolidated financial statements include the accounts of Ivanhoe Energy and its subsidiaries, all of which are wholly owned.

The Company conducts a portion of its exploration, development and production activities in its oil and gas business jointly with others. The Company’s accounts reflect only its proportionate interest in the assets and liabilities of these joint ventures.

All inter-company transactions and balances have been eliminated for the purposes of these consolidated financial statements.

Foreign Currency Translation

The functional currency of the Company is the U.S. Dollar since it is the currency in which the worldwide petroleum business is denominated and the majority of our transactions occur in this currency. Monetary assets and liabilities denominated in foreign currencies are converted to the U.S. Dollar at the exchange rate in effect at the balance sheet date and non-monetary assets and liabilities at the exchange rates in effect at the time of acquisition or issue. Revenues and expenses are converted to the U.S. Dollar at rates approximating exchange rates in effect at the time of the transactions. Exchange gains or losses resulting from the period-end translation of monetary assets and liabilities denominated in foreign currencies are reflected in the results of operations.

Cash and Cash Equivalents

Cash and cash equivalents include short-term money market instruments with terms to maturity, at the date of issue, not exceeding 90 days.

Oil and Gas Properties

Full Cost Accounting

The Company follows the full cost method of accounting for oil and gas operations whereby all exploration and development expenditures are capitalized on a country-by-country (cost center) basis. Such expenditures include lease and royalty interest acquisition costs, geological and geophysical expenses, carrying charges for unproved properties, costs of drilling both successful and unsuccessful wells, gathering and production facilities and equipment, financing, administrative costs related to capital projects and asset retirement costs. Proceeds from sales of oil and gas properties are recorded as reductions in the carrying value of proved oil and gas properties, unless such amounts would significantly alter the rate of depreciation and depletion, whereupon gains or losses would be recognized in income. Maintenance and repair costs are expensed as incurred, while improvements and major renovations are capitalized. The amount of interest costs capitalized for qualifying assets is intended to be that portion of the interest cost incurred during the assets’ acquisition periods that theoretically could have been avoided if expenditures for the assets had not been made. Unusually significant investments in unproved properties and major development projects that are not being currently depreciated, depleted, or amortized and on which exploration or development activities are in progress are assets qualifying for capitalization of interest cost. Similarly, in a cost center with no production, significant properties and projects on which exploration or development activities are in progress are assets qualifying for capitalization of interest costs.

Depletion

The Company’s share of costs for proved oil and gas properties accumulated within each cost center, including a provision for future development costs, are depleted using the unit-of-production method over the life of the Company’s share of estimated remaining proved oil and gas reserves net of royalties. Costs incurred on an unproved oil and gas property are excluded from the depletion rate calculation until it is determined whether proved reserves are attributable to an unproved oil and gas property or upon determination that an unproved oil and gas property has been impaired. Natural gas reserves and production are converted to a barrels of oil equivalent using a generally recognized industry standard in which six thousand cubic feet of gas is equal to one barrel of oil. 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.

Impairment of Proved Oil and Gas Properties

In the recognition of an impairment, the carrying value of a cost center is compared to the undiscounted future net cash flows of that cost center’s proved reserves using estimates of future oil and gas prices and costs plus the cost of unproved properties that have been excluded from the depletion calculation. If the carrying value is greater than the value of the undiscounted future net cash flows of the proved reserves plus the cost of unproved properties excluded from the depletion calculation, then the amount of the cost center’s potential impairment must be measured. A cost center’s impairment loss is measured by the amount its carrying value exceeds the discounted future net cash flows of its proved and probable reserves using estimates of future oil and gas prices and costs plus the cost of unproved properties that have been excluded from the depletion calculation and which contain no probable reserves. The net cash flows of a cost center’s proved and probable reserves are discounted using a risk-free interest rate adjusted for political and economic risk on a country-by-country basis. The amount of the impairment loss is recognized as a charge to the results of operations and a reduction in the net carrying amount of a cost center’s oil and gas properties. Unproved properties and major development projects are assessed on a quarterly basis for possible impairments or reductions in value. If a reduction in value has occurred, the impairment is transferred to the carrying value of proved oil and gas properties.

Asset Retirement Costs

The Company measures the expected costs required to abandon its producing U.S. oil and gas properties and HTL^TM facilities at a fair value which approximates the cost a third party would incur in performing the tasks necessary to abandon the field and restore the site. The fair value is recognized in the financial statements at the present value of expected future cash outflows to satisfy the obligation as a liability with a corresponding increase in the related asset. Subsequent to the initial measurement, the effect of the passage of time on the liability for the asset retirement obligation (accretion expense) is recognized in the results of operations and included with interest expense. Actual costs incurred upon settlement of the obligation are charged against the obligation to the extent of the liability recorded. Any difference between the actual costs incurred upon settlement of the obligation and the recorded liability is recognized as a gain or loss in the carrying balance of the related capital asset in the period in which the settlement occurs.

Asset retirement costs associated with the producing U.S. oil and gas properties are being depleted using the unit of production method based on estimated proved reserves and are included with depletion and depreciation expense. Asset retirement costs associated with the CDF are depreciated over the life of the CDF which commenced when the facility was placed into service.

The Company does not make such a provision for its oil and gas operations in China as there is no obligation on the Company’s part to contribute to the future cost to abandon the field and restore the site.

Development Costs

The Company incurs various costs in the pursuit of HTL^TM and GTL projects throughout the world. Such costs incurred prior to signing a memorandum of understanding (“MOU”), or similar agreements, 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 projects products, the Company assesses that the feasibility and related costs incurred have potential future value, are probable of leading to a definitive agreement for the exploitation of proved reserves and should be capitalized. If no definitive agreement is reached, then the project’s capitalized costs, which are deemed to have no future value, are written down in the results of operations with a corresponding reduction in the carrying balance of the HTL^TM and GTL development costs.

Additionally, the Company incurs costs to develop, enhance and identify improvements in the application of the HTL^TM and GTL technologies it owns or licenses. The cost of equipment and facilities acquired, such as the HTL^TM commercial demonstration facility (“CDF”), 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. The CDF will be used to develop and identify improvements in the application of the HTL^TM Technology by processing and testing heavy crude feedstock of prospective partners until such time as the CDF is sold, dismantled or redeployed.

The Company reviews the recoverability of such capitalized development costs annually, or as changes in circumstances indicate the development costs might be impaired, through an evaluation of the expected future discounted cash flows from the associated projects. If the carrying value of such capitalized development costs exceeds the expected future discounted cash flows, the excess is written down in the results of operations with a corresponding reduction in the carrying balance of the HTL^TM and GTL development costs.

Furniture and Equipment

Furniture and fixtures are stated at cost. Depreciation is provided on a straight-line basis over the estimated useful life of the respective assets, at rates ranging from three to five years.

Intangible Assets

Intangible assets are initially recognized and measured at cost. Intangible assets with finite lives are amortized over their estimated useful lives. Intangible assets are reviewed at least annually for impairment, or when events or changes in circumstances indicate that the carrying value of an intangible asset may not be recoverable. If the carrying value of an intangible asset exceeds its fair value or expected future discounted cash flows, the excess is written down to the results of operations with a corresponding reduction in the carrying value of the intangible asset.

The Company owns intangible assets in the form of an exclusive, irrevocable license to employ the RTP^TM Process for all applications other than biomass and a GTL master license from Syntroleum. The Company will assign the carrying value of the HTL^TMTechnology and the Syntroleum GTL master license to the number of facilities it expects to develop that will use the HTL^TM Technology and the Syntroleum GTL process respectively. The amount of the carrying value of the technologies assigned to each HTL^TM or GTLfacilitywill be amortized to earnings on a basis related to the operations of the HTL^TM or GTL facility from the date on which the facility is placed into service. The carrying value of the HTL^TM Technology and the Syntroleum GTL master license are evaluated for impairment annually, or as changes in circumstances indicate the intangible assets might be impaired, based on an assessment of their fair market values.

Oil and Gas Revenue

Sales of crude oil and natural gas are recognized in the period in which the product is delivered to the customer. Oil and gas revenue represents the Company’s share and is recorded net of royalty payments to governments and other mineral interest owners.

In China, the Company conducts operations jointly with the government of China in accordance with a production-sharing contract. Under this contract, the Company pays both its share and the government’s share of operating and capital costs. The Company recovers the government’s share of these costs from future revenues or production over the life of the production-sharing contract. The government’s share of operating costs is recorded in operating expense when incurred and capital costs are recorded in oil and gas properties when incurred and expensed to depletion and depreciation in the year recovered.

Earnings or Loss Per Share

Basic earnings or loss per share is calculated by dividing the net earnings or loss to common shareholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share reflects the potential dilution that would occur if stock options, convertible debentures and purchase warrants were exercised. The “if converted” method is used in calculating diluted earnings per share for the convertible debentures. The treasury stock method is used in calculating diluted earnings per share, which assumes that any proceeds received from the exercise of in-the-money stock options and purchase warrants would be used to purchase common shares at the average market price for the period. The Company does not report diluted loss per share amounts, as the effect would be anti-dilutive to the common shareholders.

Income Taxes

The Company follows the liability method of accounting for future income taxes. Under the liability method, future income taxes are recognized to reflect the expected future tax consequences arising from tax loss carry-forwards and temporary differences between the carrying value and the tax basis of the Company’s assets and liabilities. A valuation allowance is recorded against any future income tax asset if the Company is not “more likely than not” to be able to utilize the tax deductions associated with the future income tax asset. The effect of a change in income tax rates on future tax liabilities and assets is recognized in income in the period in which the change occurs, provided that the income tax rates are substantively enacted.

Stock Based Compensation

The Company has an Employees’ and Directors’ Equity Incentive Plan consisting of a stock option plan, a bonus plan and an employee share purchase plan. Compensation costs are recognized in the results of operations over the periods in which the stock options vest for all stock options granted based on the fair value of the stock options at the date granted. The Company uses the Black-Scholes option-pricing model for determining the fair value of stock options issued at grant date. As of the date stock options are granted, the Company estimates a percentage of stock options issued to employees and directors it expects to be forfeited. Compensation costs are not recognized for stock option awards forfeited due to a failure to satisfy the service requirement for vesting. Compensation costs are adjusted for the actual amount of forfeitures in the period in which the stock options expire.

Upon the exercise of stock options, share capital is credited for the fair value of the stock options at the date granted with a charge to contributed surplus. Consideration paid upon the exercise of the stock options is also credited to share capital.

Compensation expenses are recognized when shares are issued from the stock bonus plan. The employee share purchase portion of the plan has not yet been activated.

Financial Assets and Liabilities

Financial assets

The Company’s financial assets are comprised of cash and cash equivalents, accounts receivable, advances and derivative instruments. These financial assets are classified as loans and receivables or held for trading financial assets as appropriate. The classification of financial assets is determined at initial recognition. When financial assets are recognized initially, they are measured at fair value, normally being the transaction price. Transaction costs for all financial assets are expensed as incurred.

Financial assets are classified as held for trading if they are acquired for sale in the short term. Cash and cash equivalents and derivatives in a positive fair value position are also classified as held for trading. Held for trading assets are carried on the balance sheet at fair value with gains or losses recognized in the consolidated statement of operations. The estimated fair value of held for trading assets is determined by reference to quoted market prices and, if not available, on estimates from third-party brokers or dealers.

Loans and receivables are non-derivative financial assets with fixed or determinable payments. Accounts receivable and advances have been classified as loans and receivables. Such assets are carried at amortized cost, as the time value of money is not significant. Gains and losses are recognized in income when the loans and receivables are derecognized or impaired.

The Company assesses at each balance sheet date whether a financial asset carried at cost is impaired. If there is objective evidence that an impairment loss exists, the amount of the loss is measured as the difference between the carrying amount of the asset and its fair value. The carrying amount of the asset is reduced with the amount of the loss recognized in earnings.

Financial liabilities

Financial liabilities are classified as held for trading financial liabilities or other financial liabilities as appropriate. Financial liabilities include accounts payable and accrued liabilities, derivative financial instruments, credit facilities, long term obligation and long term debt. The classification of financial liabilities is determined at initial recognition.

Held for trading financial liabilities represent financial contracts that were acquired for sale in the short term or derivatives that are in a negative fair market value position.

The estimated fair value of held for trading liabilities is determined by reference to quoted market prices and, if not available, on estimates from third-party brokers or dealers.

Other financial liabilities are non-derivative financial liabilities with fixed or determinable payments.

Short term other financial liabilities are carried at cost as the time value of money is not significant. Accounts payable and accrued liabilities and credit facilities have been classified as short term other financial liabilities. Gains and losses are recognized in income when the short term other financial liability is derecognized. Transaction costs for short term other financial liabilities are expensed as incurred.

Long term other financial liabilities are measured at amortized cost. Long-term debt and long term obligation have been classified as long term other financial liabilities. Transaction costs for long term other financial liabilities are deducted from the related liability and accounted for using the effective interest rate method.

Derivative Financial Instruments

The Company may periodically use different types of derivative instruments to manage its exposure to price volatility, thus mitigating fluctuations in commodity-related cash flows. The Company currently uses costless collar derivative instruments to manage this exposure.

Derivative financial instruments are classified as held for trading and recorded on the consolidated balance sheet at fair value, either as an asset or as a liability under current assets or current liabilities, respectively. Changes in the fair value of these financial instruments, or unrealized gains and losses, are recognized in the statement of operations as revenues in the period in which they occur.

Gains and losses related to the settlement of derivative contracts, or realized gains and losses, are recognized as revenues in the statement of operations.

Contracts to buy or sell non-financial items that are not in accordance with the Company’s expected purchase, sale or usage requirements are accounted for as derivative financial instruments.

2008 Accounting Changes

Impact of New and Pending Canadian GAAP Accounting Standards

In February 2008, the CICA issued Handbook Section 3064, “Goodwill and Intangible assets,” (“S.3064”) replacing Handbook Section 3062, “Goodwill and Other Intangible Assets” (“S.3062”) and Handbook Section 3450, “Research and Development Costs”. S.3064 will be applicable to financial statements relating to fiscal years beginning on or after October 1, 2008. Accordingly, the Company will adopt the new standards for its fiscal year beginning January 1, 2009. The new section establishes standards for the recognition, measurement, presentation and disclosure of goodwill subsequent to its initial recognition and of intangible assets by profit-oriented enterprises. Standards concerning goodwill are unchanged from the standards included in the previous S.3062. Management has concluded that the requirements of this new Section will not have a material impact on its consolidated financial statements.

Convergence of Canadian GAAP with International Financial Reporting Standards

3. OIL AND GAS PROPERTIES AND DEVELOPMENT COSTS

The Company has four reportable business segments: Oil and Gas — Integrated, Oil and Gas — Conventional, Business and Technology Development and Corporate as further described in Note 11. These segments are different than those reported in the Company’s previous financial statements included in its Form 10-Ks and as such the presentation has been changed to conform to the new segments. Capital assets categorized by segment are as follows:


	As at December 31, 2008
	Oil and Gas											Business and
	Integrated					Conventional						Technology
	Canada			Ecuador		China			U.S.			Development			Total
Oil and Gas Properties:
Proved	$	—		$	—	$	141,089		$	113,002		$	—		$	254,091
Unproved		81,090			1,454		5,233			3,067			—			90,844

		81,090			1,454		146,322			116,069			—			344,935
Accumulated depletion		—			—		(81,717	)		(33,197	)		—			(114,914	)
Accumulated provision for impairment		—			—		(16,550	)		(50,350	)		—			(66,900	)

		81,090			1,454		48,055			32,522			—			163,121

Development Costs:
Feasibility studies and other deferred costs:
HTL^TM		—			—		—			—			801			801
GTL		—			—		—			—			5,054			5,054
Accumulated provision for impairment		—			—		—			—			(5,054	)		(5,054	)
Feedstock test facility		—			—		—			—			8,770			8,770
Commercial demonstration facility		—			—		—			—			11,036			11,036
Accumulated depreciation		—			—		—			—			(7,713	)		(7,713	)

		—			—		—			—			12,894			12,894

Furniture and equipment		20			90		120			538			406			1,174
Accumulated depreciation		(6	)		—		(80	)		(476	)		(77	)		(639	)

		14			90		40			62			329			535

	$	81,104		$	1,544	$	48,095		$	32,584		$	13,223		$	176,550


	As at December 31, 2007
	Oil and Gas						Business and
	Conventional						Technology
	China			U.S.			Development			Total
Oil and Gas Properties:
Proved	$	134,648		$	107,040		$	—		$	241,688
Unproved		3,297			4,373			—			7,670

		137,945			111,413			—			249,358
Accumulated depletion		(58,583	)		(27,091	)		—			(85,674	)
Accumulated provision for impairment		(16,550	)		(50,350	)		—			(66,900	)

		62,812			33,972			—			96,784

Development Costs:
Feasibility studies and other deferred costs:
HTL^TM		—			—			389			389
GTL		—			—			5,054			5,054
Feedstock test facility		—			—			4,724			4,724
Commercial demonstration facility		—			—			9,903			9,903
Accumulated depreciation		—			—			(5,159	)		(5,159	)

		—			—			14,911			14,911

Furniture and equipment		119			529			107			755
Accumulated depreciation		(77	)		(449	)		(71	)		(597	)

		42			80			36			158

	$	62,854		$	34,052		$	14,947		$	111,853

Oil and Gas Properties

In 2008, the Company disposed of U.S. Oil and Gas Properties interests with proceeds totaling $0.1 million ($1.0 million in 2007 and $6.0 in 2006). The sale proceeds were credited to the carrying value of its U.S. oil and gas properties as the sales did not significantly alter the depletion rate for the U.S. cost center.

Costs as at December 31, 2008 of $90.8 million ($7.7 million at December 31, 2007), related to unproved oil and gas properties have been excluded from costs subject to depletion and depreciation. Included in that same depletion calculation were $6.7 million for future development costs associated with proven undeveloped reserves as at December 31, 2008 ($8.9 million at December 31, 2007). The oil and gas properties in Canada and Ecuador have not had any oil and gas production and have been excluded from the ceiling test as undeveloped land.

The Company performed a ceiling test calculation at December 31, 2008, 2007 and 2006 to assess the recoverable value of its U.S. Oil and Gas Properties. Based on this calculation, the present value of future net revenue from the Company’s proved plus probable reserves exceeded the carrying value of the Company’s U.S. Oil and Gas Properties in each of those years. The Company performed this same calculation for its China Oil and Gas Properties at December 31, 2008, 2007 and 2006 resulting in no impairment in 2008 and an impairment of $6.1 million and $5.4 million in 2007 and 2006 respectively.

Prices used in calculating the expected future cash flows were based on the following benchmark prices adjusted for gravity, transportation and other factors as required by sales agreements:


	As at December 31, 2008				As at December 31, 2007				As at December 31, 2006
	West Texas		Henry		West Texas		Henry		West Texas		Henry
	Intermediate		Hub		Intermediate		Hub		Intermediate		Hub
	(per Bbl)		(per Mcf)		(per Bbl)		(per Mcf)		(per Bbl)		(per Mcf)
2007		NA		NA		NA		NA	$	62.00	$	7.25
2008		NA		NA	$	92.00	$	7.50	$	60.00	$	7.50
2009	$	57.50	$	7.00	$	88.00	$	8.25	$	58.00	$	7.50
2010	$	68.00	$	7.50	$	84.00	$	8.25	$	57.00	$	7.50
2011	$	74.00	$	8.00	$	82.00	$	8.25	$	57.00	$	7.50
2012	$	85.00	$	8.75	$	82.00	$	8.25	$	57.50	$	7.75
2013	$	92.01	$	9.20	$	82.00	$	8.25	$	58.50	$	7.90
2014	$	93.85	$	9.38	$	82.00	$	8.45	$	59.75	$	8.05
2015	$	95.73	$	9.57	$	82.00	$	8.62	$	61.00	$	8.20
2016	$	97.64	$	9.76	$	82.02	$	8.79	$	62.25	$	8.40
2017	$	99.59	$	9.96	$	83.66	$	8.96	$	63.50	$	8.55
2018	$	101.59	$	10.16		2% per year	$	9.14		2% per year		2% per year
Thereafter		2% per year		2% per year		2% per year		2% per year		2% per year		2% per year

Development Costs

In late 2004, the Company signed a memorandum of understanding with the Iraqi Ministry of Oil to evaluate a specific, large heavy oil field and its commercial development potential using Ivanhoe Energy’s HTL^TM Technology. Since that time, the Company has carried out a detailed analysis and has generated data regarding the applicability of its HTL^TM Technology for the development of the field.

In the first half of 2007, the Company and INPEX Corporation (“INPEX”), a Japanese oil and gas exploration and production company, signed an agreement to jointly pursue the opportunity to develop the above noted heavy oil field in Iraq. During the second quarter of 2007, INPEX paid $9.0 million to the Company as a contribution towards the Company’s past costs related to the project and certain costs related to the development of its HTL^TM Technology. The payment was credited to the carrying value of its Iraq and CDF HTL^TM Development Costs related to this project.

The agreement provides INPEX with a minority interest in the venture, with Ivanhoe Energy retaining a majority interest. Both parties will participate in the pursuit of the opportunity but Ivanhoe will lead the discussions with the Iraqi Ministry of Oil. Should the Company and INPEX proceed with the development and deploy Ivanhoe Energy’s HTL^TM Technology, certain technology fees would be payable to the Company by INPEX.

At December 31, 2007 the CDF had one year remaining in its useful life. This useful life was extended to December 31, 2009 concurrent with the extension of the existing term of an agreement with a third party oil and gas producer to use its property for the CDF site location. The Feedstock Test Facility (“FTF”) was entering into the commissioning phase at December 31, 2008 and, as such, was not depreciated, nor impaired for the year ended December 31, 2008.

For the year ended December 31, 2008, the Company had no impairments (nil in 2007 and 2006) related to its HTL^TM Development Costs.

Gas-to-Liquids

The Company is exploring an opportunity in Egypt to monetize stranded gas reserves through the application of the conversion of natural gas-to-liquids using a technology (“GTL Technology” or "GTL”) licensed from Syntroleum Corporation (“Syntroleum”). Because the Company has been pursuing this project for an extended period of time and has not been able to obtain a definitive agreement or appropriate project financing, the Company has impaired the 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 assets of $10.0 million (see Note 4), were 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 this project.

4. INTANGIBLE ASSETS — TECHNOLOGY

The Company’s intangible assets consist of the following:

HTL^TM Technology

In the 2005 merger with the Ensyn Group, Inc. (“Ensyn”), the Company acquired an exclusive, irrevocable license to deploy, worldwide, the RTP^TM Process for petroleum applications as well as the exclusive right to deploy the RTP^TM Process in all applications other than biomass. The Company’s carrying value of the HTL^TM Technology as at December 31, 2008 and 2007 was $92.2 million. Since the company acquired the 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 Company’s portfolio of HTL^TM intellectual property. The Company is the assignee of three granted patents and currently has five patent applications pending in the U.S. The Company also has multiple patents pending in numerous other countries. This intangible asset was not amortized and its carrying value was not impaired for the years ended December 31, 2008, 2007 and 2006.

Syntroleum GTL Master License

The Company owns a master license from Syntroleum permitting the Company to use Syntroleum’s proprietary GTL process in an unlimited number of projects around the world. 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. Both companies have the right to pursue GTL projects independently, but the Company would be required to pay the normal license fees and royalties in such projects. The Company’s carrying value of the Syntroleum GTL master license as at December 31, 2008 and 2007 was nil and $10.0 million.

Recovery of capitalized costs related to potential HTL^TM and GTL projects is dependent upon finalizing definitive agreements for, and successful completion of, the various projects. As described in Note 3 to these financial statements the GTL intangible asset balance of $10 million was impaired and charged to the results of operations with a corresponding reduction in intangible GTL assets (see Note 3). These intangible assets were not amortized and their carrying values were not impaired for the years ended December 31, 2007 and 2006.

5. LONG TERM DEBT

Notes payable consisted of the following as at:


	December 31,			December 31,
	2008			2007
Variable rate bank note, (5.46% at December 31, 2008), due April 2009	$	5,200		$	4,500
Variable rate bank note (5.33% at December 31, 2008) due September 2010		7,000			10,000
Non-interest bearing promissory note, due April 2009		416			2,876
Convertible note (5.50% at December 31, 2008) due July 2011		32,787			—

		45,403			17,376

Less:
Unamortized discount		(4	)		(139	)
Unamortized deferred financing costs		(1,932	)		(696	)
Current maturities		(5,612	)		(6,729	)

		(7,548	)		(7,564	)

	$	37,855		$	9,812

Bank Loan

In October 2006, the Company arranged a Senior Secured Revolving/Term Credit Facility of up to $15 million with an initial borrowing base of $8 million. In October 2008, the original due date of the revolving facility of October 2008 was extended to April 2009 and $5.2 million was outstanding at December 31, 2008. Depending on the drawn amount, interest, at the Company’s option, will be either at 1.75% to 2.25%, above the bank’s base rate or 2.75% to 3.25% over the London Inter-Bank Offered Rate (“LIBOR”). The loan terms include the requirement for the Company to enter into two-year commodity derivative contracts (See Note 12) covering up to 14,700 Bbls per month of the Company’s production from its South Midway Property in California and Spraberry Property in West Texas. As part of reestablishing the borrowing base amount, the Company was required to enter into an additional commodity derivative contract (see Note 12). The facility is secured by a mortgage on both of these properties. The Company made an initial $1.5 million draw of this facility in October 2006, a subsequent draw of $3.0 million in September 2007 and a final draw of $0.7 million in April 2008.

In September 2007 the Company obtained a bank loan for a $30 million Revolving/Term Credit Facility with an initial borrowing base of $10 million. The facility is a revolving facility with a three-year term with interest payable only during the term. Interest will be three-month LIBOR plus 3.75%. The loan terms include the requirement for the Company to enter into three-year commodity derivative contracts (See Note 12) covering up to 18,000 Bbls per month of the Company’s production from its Dagang field in China. The facility is secured by a pledge of collections from the Company’s monthly oil sales in China and by a pledge of shares of the Company’s Chinese subsidiaries. The Company made an initial $7.0 million draw of this facility in September 2007 and a subsequent draw of $3.0 million in December of 2007. In December 2008 $3.0 million of this loan was repaid.

Promissory Notes

In connection with the acquisition in July 2008 described in Note 18, the Company issued a promissory note (the “2008 Note”) to Talisman Energy Canada (“Talisman”) in the principal amount of Cdn.$12.5 million bearing interest at a rate per year equal to the prime rate plus 2%, calculated daily and not compounded. The 2008 Note matured and the principal and related interest was paid on December 31, 2008.

In February 2006, the Company re-acquired the 40% working interest in the Dagang oil project not already owned by the Company. Part of the consideration was the issuance by the Company of a non-interest bearing, unsecured promissory note in the principal amount of approximately $7.4 million ($6.5 million after being discounted to net present value). The note is payable in 36 equal monthly installments commencing March 31, 2006 (See Note 18).

Convertible Note

Also in connection with the acquisition in July 2008 described in Note 18, the Company issued a convertible promissory note (the “Convertible Note”) to Talisman in the principal amount of Cdn.$40.0 million bearing interest at a rate per year equal to the prime rate plus 2%, calculated daily and not compounded, payable semi-annually and maturing in July 2011. The Convertible Note is convertible (as to the outstanding principal amount), at Talisman’s option, into a maximum of 12,779,552 common shares of the Company at Cdn.$3.13 per common share. There were no conversions of this note as of December 31, 2008.

Under Canadian GAAP, the Convertible Note is assessed based on the substance of the contractual arrangement in determining whether it exhibits the fundamental characteristic of a financial liability or equity. Management has concluded that this debt instrument mainly exhibits characteristics that are liability in nature, however, the embedded conversion feature is equity in nature and is required to be bifurcated and disclosed separately within shareholders’ equity. Management has applied a residual basis method and has valued the liability component first and assigned the residual value to the equity component. Management has fair valued the liability component by discounting the expected interest and principal payments using an interest rate of 8.75% being management’s estimate of the expected interest payments for a similar instrument without the conversion feature. The liability component was valued at Cdn.$37.9 million and the remaining balance of Cdn.$2.1 million was allocated to the equity component. The liability component will be accreted over the three-year maturity period to bring the liability back to Cdn.$40.0 million using the effective interest method.

The Company’s obligations under the Convertible Note and the Contingent Payment (see Note 18) are secured by a first fixed charge and security interest in favor of Talisman against the acquired Talisman leases and the related assets acquired by the Company pursuant to the Talisman lease acquisition, and a subordinate security interest in and to all other present and after-acquired property of the Company other than the shares of any subsidiary of Ivanhoe Energy. The Talisman security interest also does not extend to any assets of any subsidiary of Ivanhoe Energy.

Revolving Line of Credit

The Company has a revolving credit facility for up to $1.25 million from a related party, repayable with interest at U.S. prime plus 3%. The Company did not draw down any funds from this credit facility for the years ended December 31, 2008, 2007 and 2006.

The scheduled maturities of the Company’s long term debt, excluding unamortized discount and unamortized deferred financing costs, as at December 31, 2008 were as follows:


2009	$	5,616
2010		7,000
2011		32,787

	$	45,403

Interest expense included in Interest Expense and Financing Costs in the statement of operations was $1.7 million for the year ended December 31, 2008 ($0.9 million for 2007 and $0.9 million for 2006). For the year ended December 2008, $1.7 million (nil in 2007 and 2006) in interest was capitalized to oil and gas properties and development costs in the balance sheet.

6. ASSET RETIREMENT OBLIGATIONS

The Company provides for the expected costs required to abandon its producing U.S. oil and gas properties and the CDF. The undiscounted amount of expected future cash flows required to settle the Company’s asset retirement obligations for these assets as at December 31, 2008 was estimated at $6.3 million. These payments are expected to be made over the next 30 years; with over half of the payments during 2010 to 2025. To calculate the present value of these obligations, the Company used an inflation rate of 3% and the expected future cash flows have been discounted using a credit-adjusted risk-free rate of 6%. The changes in the Company’s liability for the two-year period ended December 31, 2008 were as follows:


	As at		As at
	December, 31		December, 31
	2008		2007
Carrying balance, beginning of year	$	2,218	$	1,953
Liabilities incurred		236		20
Liabilities settled		—		(792	)
Accretion expense		171		119
Revisions in estimated cash flows		1,113		918

Carrying balance, end of period	$	3,738	$	2,218

7. COMMITMENTS AND CONTINGENCIES

Zitong Block Exploration Commitment

At December 31, 2005, the Company held a 100% working interest in a thirty-year production-sharing contract with China National Petroleum Corporation (“CNPC”) in a contract area, known as the Zitong Block located in the northwestern portion of the Sichuan Basin. In January 2006, the Company farmed-out 10% of its working interest in the Zitong block to Mitsubishi Gas Chemical Company Inc. of Japan (“Mitsubishi”) for $4.0 million.

Under this production-sharing contract, the Company was obligated to conduct a minimum exploration program during the first three years ending December 1, 2005 (“Phase 1”). The Company completed Phase 1 with a drilling shortfall of approximately 700 feet. In December 2007, the Company and Mitsubishi (the “Zitong Partners") made a decision to enter into the next three-year exploration phase (“Phase 2”). The shortfall in Phase I drilling will be carried over into Phase 2.

By electing to participate in Phase 2 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 1 shortfall), with total gross remaining estimated minimum expenditures for this program of $27.4 million. The Phase 2 seismic line acquisition commitment was fulfilled in the Phase 1 exploration program. The Zitong Partners plan to acquire additional seismic data in Phase 2. The partners have requested that CNPC allow the offset of this additional seismic against the drilling commitment, reducing the required Phase 2 drilling footage requirement, but no agreement has been reached at this time. The Zitong Partners have relinquished 15% of the Block acreage and will relinquish an additional 10% to complete 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 the first Phase II drilling location. Drilling is planned to commence in late 2009 with expected completed drilling, completion and evaluation of this prospect finalized in 2010. The Zitong Partners must complete the minimum work program by the end of the Phase 2 period, December 31, 2010, 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 2, the Zitong Partners must relinquish all of the remaining property except any areas identified for development and production.

Long Term Obligation

As part of its 2005 merger with Ensyn Group, Inc., the Company assumed an obligation to pay $1.9 million in the event, and at such time that, the sale of units incorporating the HTL^TM Technology for petroleum applications reach a total of $100.0 million. This obligation was recorded in the Company’s consolidated balance sheet.

Income Taxes

The Company’s income tax filings are subject to audit by taxation authorities, which may result in the payment of income taxes and/or a decrease its net operating losses available for carry-forward in the various jurisdictions in which the Company operates. While the Company believes its tax filings do not include uncertain tax positions, except as noted below, the results of potential audits or the effect of changes in tax law cannot be ascertained at this time.

The Company has an uncertain tax position in China related to when its entitlement to take tax deductions associated with development costs commenced. In March 2007, the Company received a preliminary indication from local Chinese tax authorities as to a potential change in the rule under which development costs are deducted from taxable income effective for the 2006 tax year. The Company discussed this matter with Chinese tax authorities and subsequently filed its 2006 tax return for Sunwing’s wholly-owned subsidiary Pan-China Resources Ltd. (“Pan-China”) taking a new filing position in which development costs are capitalized and amortized on a straight line basis over six years starting in the year the development costs are incurred rather than deducted in their entirety in the year incurred. This change resulted in a $50.3 million reduction in tax loss carry-forwards in 2007 with an equivalent increase in the tax basis of development costs available for application against future Chinese income. The Company has received no formal notification of this rule change; however it will continue to file tax returns under this new approach. To the extent that there is a different interpretation in the timing of the deductibility of development costs this could potentially result in an increase in the current tax provision of $2.0 million.

The Company has an uncertain tax position related to the calculation of a gain on the consideration received from two farm-out transactions (Richfirst January 2004 — see Note 5 and Mitsubishi January 2006 — see under Zitong Block Exploration Commitment in this Note 7) and the designation of whether the taxable gains may be subject to a withholding tax of 10% pursuant to Chinese tax law for income derived by a foreign entity. The Company is waiting for the Chinese tax authorities to reply to its request to validate in writing that its current treatment of such tax position is appropriate. To the extent that the calculation of a gain is interpreted differently and the amounts are subject to withholding tax there would be an additional current tax provision of approximately $0.7 million.

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

Other Commitments

From time to time the Company enters into consulting agreements whereby a success fee may be payable if and when either a definitive agreement is signed or certain other contractual milestones are met. Under the agreements, the consultant may receive cash, Company shares, stock options or some combination thereof. These fees are not considered to be material in relation to the overall capital costs and funding requirements of the individual projects.

See Note 18 for a commitments related to acquisition of properties in Alberta.

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

Lease Commitments

For the year ended December 31, 2008 the Company expended $1.2 million ($1.1 million in 2007 and $0.8 million in 2006) on operating leases relating to the rental of office space, which expire between July 2010 and March 2012. Such leases frequently provide for renewal options and require the Company to pay for utilities, taxes, insurance and maintenance expenses.

As at December 31, 2008, future net minimum payments for operating leases (excluding oil and gas and other mineral leases) were the following:


2009	$	1,191
2010		1,009
2011		680
2012		331
2013		126

	$	3,337

8. SHARE CAPITAL AND WARRANTS

The authorized capital of the Company consists of an unlimited number of common shares without par value and an unlimited number of preferred shares without par value.

Special Warrants Offering

A special warrant is a security sold for cash which may be exercised to acquire, for no additional consideration, a common share or, in certain circumstances, a common share and a common share purchase warrant.

In July 2008, the Company completed a Cdn.$88.0 million private placement consisting of 29,334,000 special warrants at Cdn.$3.00 per special warrant (the “Offering”). Each of these special warrants entitled the holder to one common share of the Company upon exercise of the special warrant. In August 2008, all of these special warrants were exercised for 29,334,000 common shares. The net proceeds from the Offering was approximately Cdn.$83.4 million after deducting the agents’ commission of Cdn.$4.0 million and the expenses of the Offering of Cdn.$0.6 million. The Company used Cdn.$22.5 million of the net proceeds of the Offering to complete the cash component of the Talisman lease acquisition described in Note 18.

On April 7, 2006, the Company closed a special warrant financing by way of private placement for $25.3 million. The financing consisted of 11,400,000 special warrants issued for cash at $2.23 per special warrant. Each special warrant entitled the holder to receive, at no additional cost, one common share and one common share purchase warrant. All of the special warrants were subsequently exercised for common shares and common share purchase warrants. Each common share purchase warrant originally entitled the holder to purchase one common share at a price of $2.63 per share until the fifth anniversary date of the closing. In September 2007, these warrants were listed on the Toronto Stock Exchange and the exercise price was changed to Cdn.$2.93.

Convertible Notes

As described in Note 5, in connection with the acquisition in July 2008, the Company issued the Convertible Note to Talisman in the principal amount of Cdn.$40.0 million bearing interest at a rate per year equal to the prime rate plus 2%, calculated daily and not compounded, and payable semi-annually, maturing in July 2011 and convertible (as to the outstanding principal amount), at Talisman’s option, into a maximum of 12,779,552 common shares of the Company at Cdn.$3.13 per common share. Also described in Note 5, management accounted for this convertible note by assigning a portion of the value, Cdn.$2.1 million, of the instrument to equity.

In April 2008, the Company obtained a loan from a third party finance company in the amount of Cdn.$5.0 million bearing interest at 8% per annum. The principal and accrued and unpaid interest matured and was repayable in August 2008. In August 2008, the lender exercised its option to convert the entire outstanding balance into the Company’s common shares at the conversion price of Cdn.$2.24 per share.

Purchase Warrants

The following reflects the changes in the Company’s purchase warrants and common shares issuable upon the exercise of the purchase warrants for the three-year period ended December 31, 2008:


	Purchase			Shares
	Warrants			Issuable
	(thousands)
Balance December 31, 2005		25,469			21,883
Purchase warrants expired		(7,173	)		(3,587	)
Private placements		11,400			11,400

Balance December 31, 2006		29,696			29,696
Purchase warrants exercised		(2,000	)		(2,000	)
Purchase warrants expired		(1,200	)		(1,200	)

Balance December 31, 2007		26,496			26,496
Purchase warrants expired		(15,096	)		(15,096	)
Private placements		29,334			29,334
Purchase warrants exercised		(29,334	)		(29,334	)

Balance December 31, 2008		11,400			11,400

For the year ended December 31, 2008, 29.3 million purchase warrants (2,000,000 in 2007 and nil in 2006) were exercised for the purchase of common shares — please refer to details under “Special Warrants Offering” (2,000,000 in 2007 at an average exercise price of U.S. $2.00 per share for 2007 for a total of $4.0 million).

The expiration of 15.1 million (1.2 million in 2007) purchase warrants in 2008 resulted in the carrying value of $4.3 million ($0.6 million in 2007) associated with these warrants being reclassified from Purchase Warrants to Contributed Surplus at the time of expiration.

As at December 31, 2008, the following purchase warrants were exercisable to purchase common shares of the Company until the expiry date at the price per share as indicated below:

Number of

Purchase Warrants

Price per

Common

Exercise

Cash

Year of

Special

Shares

Price per

Value on

Issue

Warrant

Issued

Exercisable

Issuable

Value

Expiry Date

Share

Exercise

(thousands)

($U.S. 000)

2006

U.S.$2.23

11,400

18,805

May 2011

Cdn. $2.93

(1)

27,379


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

The weighted average exercise price of the exercisable purchase warrants as at December 31, 2008 was U.S. $2.40 per share.

The Company calculated a value of $18.8 million for the purchase warrants issued in 2006. This value was calculated in accordance with the Black-Scholes (“B-S”) pricing model using a weighted average risk-free interest rate of 4.4%, a dividend yield of 0.0%, a weighted average volatility factor of 75.3% and an expected life of 5 years.

9. STOCK BASED COMPENSATION

The Company has an Employees’ and Directors’ Equity Incentive Plan under which it can grant stock options to directors and eligible employees to purchase common shares, issue common shares to directors and eligible employees for bonus awards and issue shares under a share purchase plan for eligible employees. The total number of common shares that may be issued under this plan cannot exceed 29.3 million.

Stock options are issued at not less than the fair market value on the date of the grant and are conditional on continuing employment. Expiration and vesting periods are set at the discretion of the Board of Directors. Stock options granted prior to March 1, 1999 vested over a two-year period and expire ten years from date of issue. Stock options granted after March 1, 1999 generally vest over three to four years and expire five to ten years from the date of issue. Additionally, in 2007, the Company granted share option awards whose vesting is contingent upon meeting various departmental and company-wide goals.

The fair value of each option award is estimated on the date of grant using the B-S option-pricing formula with service condition options amortized on a straight-line attribution approach and performance condition options amortized over the service period both with the following weighted-average assumptions for the years presented:


	2008			2007			2006
Expected term (in years)		4.0			3.7			5.5
Volatility		63.6	%		73.5	%		82.5	%
Dividend Yield		0.0	%		0.0	%		0.0	%
Risk-free rate		3.1	%		4.1	%		4.4	%

The Company’s expected term represents the period that the Company’s stock-based awards are expected to be outstanding and was determined based on historical experience of similar awards, giving consideration to the contractual terms of the stock-based awards, vesting schedules and expectations of future employee behavior as influenced by changes to the terms of its stock-based awards. The fair values of stock-based payments were valued using the B-S valuation method with an expected volatility factor based on the Company’s historical stock prices. The B-S valuation model calls for a single expected dividend yield as an input. The Company has not paid and does not anticipate paying any dividends in the near future. The Company bases the risk-free interest rate used in the B-S valuation method on the implied yield currently available on Canadian zero-coupon issue bonds with an equivalent remaining term. When estimating forfeitures, the Company considers historical voluntary termination behavior as well as future expectations of workforce reductions. The estimated forfeiture rate as at December 31, 2008 is 25.9% (23.1% at December 31, 2007 and 23.0% at December 31, 2006). The Company recognizes compensation costs only for those equity awards expected to vest.

The weighted average grant-date fair value of stock options granted during 2008 was Cdn.$0.90 (Cdn.$1.09 in 2007 and Cdn$1.92 in 2006).

For the years ended December 31, 2008 the Company’s stock based compensation related to option awards was $3.1 million ($2.9 million in 2007 and $2.9 million in 2006). The Company’s stock based compensation related to share bonus awards was $0.5 million for the year ended December 31, 2008 ($0.8 million in 2007). Stock based compensation was recorded as general and administrative and business and technology development expense in the statement of operations. In addition, $0.2 million of the Company’s stock based compensation related to option awards was capitalized to oil and gas properties and development costs in the balance sheet during December 31, 2008.

The following table summarizes changes in the Company’s outstanding stock options:


	December 31, 2008					December 31, 2007					December 31, 2006
				Weighted-					Weighted-					Weighted-
	Number			Average		Number			Average		Number			Average
	of Stock			Exercise		of Stock			Exercise		of Stock			Exercise
	Options			Price		Options			Price		Options			Price
	(thousands)			(Cdn.$)		(thousands)			(Cdn.$)		(thousands)			(Cdn.$)
Outstanding at beginning of year		12,945		$	2.37		12,370		$	2.34		10,278		$	2.21
Granted		3,832		$	1.79		3,843		$	1.05		3,419		$	3.02
Exercised		(3,067	)	$	0.90		(1,477	)	$	0.62		(297	)	$	2.05
Expired		(580	)	$	5.78		(1,017	)	$	3.12		(448	)	$	3.62
Forfeited		(1,217	)	$	3.05		(774	)	$	2.69		(582	)	$	3.22

Outstanding at end of year		11,913		$	2.32		12,945		$	2.37		12,370		$	2.34


Options exercisable at end of year		5,062		$	2.61		6,932		$	2.24		7,720		$	1.92

The aggregate intrinsic value of total options outstanding as well as options exercisable as at December 31, 2008 was nil as there were no options in the money. The total intrinsic value of options exercised during the year ended December 31, 2008 was $5.4 million ($2.1 million in 2007 and $0.2 million in 2006), and the cash received from exercise of options during the year ended December 31, 2008 was $1.2 million ($0.4 million in 2007 and $0.5 million in 2006).

The following table summarizes information respecting stock options outstanding and exercisable as at December 31, 2008:


	Stock Options Outstanding						Stock Options Exercisable
			Weighted-Average						Weighted-Average
Range of	Number		Remaining		Weighted-Average		Number		Remaining		Weighted-Average
Exercise Prices	Outstanding		Contractual Life		Exercise Price		Exercisable		Contractual Life		Exercise Price
(Cdn.$)	(thousands)		(Years)		(Cdn.$)		(thousands)		(Years)		(Cdn.$)
$1.52 to $2.25		6,097		3.8	$	1.80		1,432		3.6	$	1.83
$2.29 to $3.44		5,504		2.3	$	2.84		3,432		2.0	$	2.87
$3.53 to $3.62		312		1.9	$	3.55		198		1.8	$	3.56

$1.52 to $3.62		11,913		3.1	$	2.32		5,062		2.4	$	2.61

A summary of the Company’s unvested options as at December 31, 2008, and changes during the year then ended, is presented below:


				Weighted-
	Number			Average
	of Stock			Grant Date
	Options			Fair Value
	(thousands)			(Cdn.$)
Outstanding at December 31, 2007		6,013		$	1.12
Granted		3,831		$	0.90
Vested		(2,692	)	$	0.68
Cancelled/forfeited		(301	)	$	0.03

Outstanding at December 31, 2008		6,851		$	0.98


Unvested options outstanding at December 31, 2008 by type:

Based on fulfulling service conditions		5,412
Based on fulfulling performance conditions		1,439

		6,851

As at December 31, 2008, there was $2.9 million of total unrecognized compensation costs related to unvested share-based compensation arrangements granted by the Company. That cost is expected to be recognized over a weighted-average period of 1.7 years. The total fair value of shares vested during the year ended December 31, 2008 was $3.0 million ($2.9 million in 2007 and $3.1 million in 2006).

10. RETIREMENT PLAN

In 2001, the Company adopted a defined contribution retirement or thrift plan (“401(k) Plan”) to assist U.S. employees in providing for retirement or other future financial needs. Employees’ contributions (up to the maximum allowed by U.S. tax laws) were matched 100% by the Company in 2008. For the year ended December 31, 2008 the Company’s matching contributions to the 401(k) Plan was $0.5 million ($0.5 million in 2007 and $0.4 million in 2006).

11. SEGMENT INFORMATION

The Company has four reportable business segments: Oil and Gas — Integrated, Oil and Gas — Conventional, Business and Technology Development and Corporate. These segments are different than those reported in the Company’s previous financial statements included in its Form 10-Ks and as such the presentation has been changed to conform to the new segments. Due to newly established geographically focused entities and the initiation of two new integrated projects, new segments are being reported to reflect how management now analyzes and manages the Company.

Oil and Gas

Integrated

Projects in this segment will 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 (see Note 18) and a heavy oil property in Ecuador (see Note 18). The integrated segments were established in 2008 and therefore there is no comparative information for 2007 and 2006.

Conventional

Business and Technology Development

Additionally, the Company incurs costs to develop, enhance and identify improvements in the application of the HTL^TM and GTL technologies it owns or licenses. 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.

The following tables present the Company’s segment information for the three years ended December 31, 2008.


	Year Ended December 31, 2008
	Oil and Gas												Business and
	Integrated						Conventional						Technology
	Canada			Ecuador			China			U.S.			Development			Corporate			Total
Revenue
Oil and gas revenue	$	—		$	—		$	48,370		$	18,120		$	—		$	—		$	66,490
Gain on derivative instruments		—			—			1,688			278			—			—			1,966
Interest income		—			—			50			98			—			562			710

		—			—			50,108			18,496			—			562			69,166


Expenses
Operating costs		—			—			21,515			5,137			—			—			26,652
General and administrative		1,653			658			2,245			2,411			—			11,223			18,190
Business and technology development		189			—			—			—			6,264			—			6,453
Depletion and depreciation		3			—			23,135			6,143			2,618			5			31,904
Interest expense and financing costs		—			—			821			520			76			412			1,829
Provion for impairment of GTL intangible assets and development costs		—			—			—			—			15,054			—			15,054
Write off of deferred financing costs		—			—			2,621			—			—			—			2,621

		1,845			658			50,337			14,211			24,012			11,640			102,703


Income (Loss) before Income Taxes		(1,845	)		(658	)		(229	)		4,285			(24,012	)		(11,078	)		(33,537	)


Provision for income taxes
Current		—			—			(650	)		(4	)		(2	)		—			(656	)


Net Income (Loss) and Comprehensive Income (Loss)	$	(1,845	)	$	(658	)	$	(879	)	$	4,281		$	(24,014	)	$	(11,078	)	$	(34,193	)


Capital Investments	$	6,484		$	1,369		$	8,378		$	4,542		$	4,833		$	—		$	25,606


Identifiable Assets:
As at December 31, 2008	$	81,126		$	1,766		$	64,901		$	37,480		$	105,587		$	26,415		$	317,275


	Year Ended December 31, 2007
	Oil and Gas						Business and
	Conventional						Technology
	China			U.S.			Development			Corporate			Total
Revenue
Oil and gas revenue	$	31,365		$	12,270		$	—		$	—		$	43,635
Loss on derivative instruments		(4,993	)		(5,594	)		—			—			(10,587	)
Interest income		58			152			—			259			469

		26,430			6,828			—			259			33,517


Expenses
Operating costs		13,000			4,319			—			—			17,319
General and administrative		2,042			2,018			—			8,016			12,076
Business and technology development		—			—			9,625			—			9,625
Depletion and depreciation		19,222			5,884			1,412			6			26,524
Interest expense and financing costs		281			427			29			313			1,050
Provision for impairment of oil and gas properties		6,130			—			—			—			6,130

		40,675			12,648			11,066			8,335			72,724


Net Loss and Comprehensive Loss	$	(14,245	)	$	(5,820	)	$	(11,066	)	$	(8,076	)	$	(39,207	)


Capital Investments	$	23,488		$	3,052		$	5,098		$	—		$	31,638


Identifiable Assets:
As at December 31, 2007	$	73,298		$	40,726		$	117,529		$	5,363		$	236,916


	Year Ended December 31, 2006
	Oil and Gas						Business and
	Conventional						Technology
	China			U.S.			Development			Corporate			Total
Revenue
Oil and gas revenue	$	35,683		$	12,065		$	—		$	—		$	47,748
Loss on derivative instruments		—			(424	)		—			—			(424	)
Interest income		63			139			—			574			776

		35,746			11,780			—			574			48,100


Expenses
Operating costs		11,834			4,299			—			—			16,133
General and administrative		1,337			1,676			—			7,167			10,180
Business and technology development		—			—			7,610			—			7,610
Depletion and depreciation		23,345			5,378			3,822			5			32,550
Interest expense and financing costs		156			290			10			507			963
Write off of deferred acquisition costs		736			—			—			—			736
Provision for impairment of oil and gas properties		5,420			—			—			—			5,420

		42,828			11,643			11,442			7,679			73,592


Net Income (Loss) and Comprehensive Income (Loss)	$	(7,082	)	$	137		$	(11,442	)	$	(7,105	)	$	(25,492	)


Capital Investments	$	9,086		$	5,550		$	3,206		$	—		$	17,842

12. FINANCIAL INSTRUMENTS AND FINANCIAL RISK FACTORS

The accounting classification of each category of financial instruments, and their carrying amounts (which approximate fair value), are set out below.


	As at December 31, 2008
							Financial
			Available-for-				liabilities
	Loans and		sale financial		Held-for-		measured at			Total carrying
	receivables		assets		trading		amortized cost			amount
Financial Assets:
Cash and cash equivalents	$	—	$	—	$	39,265	$	—		$	39,265
Accounts receivable		4,870		—		—		—			4,870
Derivative instruments		—		—		2,159		—			2,159

Financial Liabilities:
Accounts payable and accrued liabilities		—		—		—		(10,093	)		(10,093	)
Long term obligation		—		—		—		(1,900	)		(1,900	)
Long term debt		—		—		—		(43,467	)		(43,467	)

	$	4,870	$	—	$	41,424	$	(55,460	)	$	(9,166	)


	As at December 31, 2007
								Financial
			Available-for-					liabilities
	Loans and		sale financial		Held-for-			measured at			Total carrying
	receivables		assets		trading			amortized cost			amount
Financial Assets:
Cash and cash equivalents	$	—	$	—	$	11,356		$	—		$	11,356
Accounts receivable		9,376		—		—			—			9,376
Advance		825		—		—			—			825

Financial Liabilities:
Accounts payable and accrued liabilities		—		—		—			(9,538	)		(9,538	)
Derivative instruments		—		—		(9,432	)		—			(9,432	)
Long term obligation		—		—		—			(1,900	)		(1,900	)
Long term debt		—		—		—			(16,541	)		(16,541	)

	$	10,201	$	—	$	1,924		$	(27,979	)	$	(15,854	)

Financial Risk Factors

The Company is exposed to a number of different financial risks arising from typical business exposures as well as its use of financial instruments including market risk relating to commodity prices, foreign currency exchange rates and interest rates, credit risk and liquidity risk. There have been no significant changes to the Company’s exposure to risks nor to management’s objectives, policies and processes to manage risks from the previous year except discussed below under “Liquidity Risk”. The risks associated with our financial instruments and our policies for minimizing these risks are detailed below.

Market Risk

Market risk is the risk that the fair value or future cash flows of our financial instruments will fluctuate because of changes in market prices. Components of market risk to which we are exposed are discussed below.

Commodity Price Risks

Commodity price risk refers to the risk that the value of a financial instrument or cash flows associated with the instrument will fluctuate due to the changes in market commodity prices. Crude oil prices and quality differentials are influenced by worldwide factors such as OPEC actions, political events and supply and demand fundamentals. The Company may periodically use different types of derivative instruments to manage its exposure to price volatility as well as being a requirement of the Company’s lenders.

The Company entered into costless collar derivatives to minimize variability in its cash flow from the sale of up to 14,700 Bbls per month of the Company’s 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 had 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 also entered into a costless collar derivative to minimize variability in its cash flow from the sale of up to 18,000 Bbls per month of the Company’s 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. All of the above contacts were put in place as part of the Company’s bank loan facilities.

Results of these derivative transactions for the three years ended December 31, 2008:


	Year Ended December 31,
	2008			2007			2006
Realized gains (losses) on derivative transactions	$	(9,625	)	$	(1,648	)	$	69
Unrealized gains (losses) on derivative transactions		11,591			(8,939	)		(493	)

	$	1,966		$	(10,587	)	$	(424	)

Both realized and unrealized gains and losses on derivatives have been recognized in the results of operations.

On December 31, 2008, the Company’s open positions on the derivative assets referred to above had a fair value of $2.2 million. A 10% increase in oil prices would reduce the fair value, and consequently increase the net loss, by approximately $1.1 million, while a 10% decrease in prices would increase the fair value, and consequently reduce the net loss, by approximately $1.1 million. The fair value change assumes volatility based on prevailing market parameters at December 31, 2008.

Foreign Currency Exchange Rate Risk

Interest Rate Risk

Interest rate risk refers to the risk that the value of a financial instrument or cash flows associated with the instrument will fluctuate due to the changes in market interest rates. Interest rate risk arises from interest-bearing borrowings which have a variable interest rate. The Company currently has two separate bank loan facilities and a convertible note with fluctuating interest rates. The Company estimates that its net loss and accumulated deficit for the year ended December 31, 2008 would have changed $0.2 million for every 1% change in interest rates as of December 31, 2008. The Company is not currently actively attempting to mitigate this interest rate risk given the limited amount and term of its borrowings and the current global interest rate environment.

Credit Risk

The Company is exposed to credit risk with respect to its cash held with financial institutions, accounts receivable, derivative contracts and advance balances. The Company believes its exposure to credit risk related to cash held with financial institutions is minimal due to the quality of the institutions where the cash is held and the nature of the deposit instruments. Most of the Company’s accounts receivable balances relate to oil and natural gas sales to pipelines, refineries, major oil companies and foreign national petroleum companies and are exposed to typical industry credit risks. In addition, accounts receivable balances consist of costs billed to joint venture partners where the Company is the operator and advances to partners for joint operations where the Company is not the operator. The advance balance relates to an arrangement whereby scheduled advances were made to a third party contractor associated with negotiating an HTL^TM and/or GTL project for the Company. The Company manages its credit risk by entering into sales contracts only with established entities and reviewing its exposure to individual entities on a regular basis.

The following summarizes the accounts receivable balances and revenues from significant customers:


	Accounts Receivable as				Oil and Gas Revenue for the Year
	at December 31,				Ended December 31,
	2008		2007		2008		2007		2006
U.S. Customers
A	$	436	$	1,138	$	16,679	$	10,903	$	10,351
B		50		207		1,011		1,011		1,094
C		57		72		267		271		277
D		—		—		92		74		236
All others		18		27		72		11		107

		561		1,444		18,121		12,270		12,065

China Customer
A		3,057		6,564		48,369		31,365		35,683

		3,618		8,008		66,490		43,635		47,748

Receivables from partners		613		815		—		—		—

Other receivables		639		553		—		—		—

	$	4,870	$	9,376	$	66,490	$	43,635	$	47,748

As noted below, included in the Company’s trade receivable balance are debtors with a carrying amount of $0.4 million as of the year ended December 31, 2008 which are past due at the reporting date for which the Company has not provided an allowance, as there has not been a significant change in credit quality and the amounts are still considered recoverable. The Company defines “past due” by the specific contract terms associated with each transaction (e.g. oil sales generally have a one — two month lag, joint venture billings generally are between 15 — 45 days). During the quarter ended September 30, 2008 the Company recorded an allowance associated with the advance balance for the entire outstanding amount of $0.7 million. In addition, the Company recorded an allowance for the entire outstanding amount of $0.4 million related to an amount owed to the Company by a joint interest partner in the fourth quarter of 2008. These provisions were recorded in General and Administrative expense in the accompanying Statement of Operations and Comprehensive Loss. There were no other changes to the allowance for credit losses account during the three-month period ended December 31, 2008 and no other losses associated with credit risk were recorded during this same period.


	December 31,		December 31,
	2008		2007
Accounts Receivable:
Neither impaired nor past due	$	4,509	$	8,259
Impaired (net of valuation allowance)		—		—
Not impaired and past due in the following periods:
within 30 days		108		347
31 to 60 days		46		—
61 to 90 days		72		4
over 90 days		135		766

		4,870		9,376

Advance
Not impaired and past due over 90 days		—		825

	$	4,870	$	10,201

Our maximum exposure to credit risk is based on the recorded amounts of the financial assets above.

Liquidity Risk

Liquidity risk is the risk that suitable sources of funding for the Company’s business activities may not be available, which means it may be forced to sell financial assets or non-financial assets, refinance existing debt, raise new debt or issue equity. The Company’s present plans to generate sufficient resources to assure continuation of its operations and achieve its capital investment objectives include alliances or other arrangements with entities with the resources to support the Company’s projects as well as project financing, debt financing or the sale of equity securities. However, the availability of financing, in particular project funding, is dependent in part on the return of the credit and equity markets to normalized conditions. During the fourth quarter of 2008, as a result of the global economic crisis, the terms and availability of equity and debt capital have been materially restricted and financing may not be available when it required or on commercially acceptable terms.

The contractual maturity of the fixed and floating rate financial liabilities and derivatives are shown in the table below. The amounts presented represent the future undiscounted principal and interest cash flows and therefore do not equate to the values presented in the balance sheet.


	As at December 31, 2008								As at December 31, 2007
	Contractual Maturity								Contractual Maturity
	(Nominal Cash Flows)								(Nominal Cash Flows)
	Less than		1 to 2		2 to 5		Over 5		Less than		1 to 2		2 to 5		Over 5
	1 year		years		years		years		1 year		years		years		years
Derivative financial liabilities:
Costless Collars — oil price commodity	$	—	$	—	$	—	$	—	$	7,156	$	2,276	$	—	$	—

Non derivative financial liabilities:
Trade accounts payable	$	4,835	$	—	$	—	$	—	$	6,897	$	—	$	—	$	—
Accruals	$	5,258	$	—	$	—	$	—	$	2,641	$	—	$	—	$	—
Long term debt and interest	$	8,777	$	9,432	$	33,495	$	—	$	8,240	$	1,541	$	10,277	$	—

13. CAPITAL MANAGEMENT

The Company manages its capital so that the Company and its subsidiaries will be able to continue as a going concern and to create shareholder value through exploring, appraising and developing its assets including the major initiative of implementing multiple, full-scale, commercial HTL™ heavy oil projects in Canada and internationally. There have been no significant changes in management’s objectives, policies and processes to manage capital or the components of capital from the previous year. However, the availability of financing, in particular project funding, is dependent in part on the return of the credit and equity markets to normalized conditions. During the fourth quarter of 2008, as a result of the global economic crisis, the terms and availability of equity and debt capital have been materially restricted and financing may not be available when it required or on commercially acceptable terms.

The Company defines capital as total equity or deficiency plus cash and cash equivalents and long term debt. Total equity is comprised of share capital, purchase warrants, convertible note, contributed surplus, shares to be issued and accumulated deficit as disclosed in Note 8. Cash and cash equivalents consist of $39.3 million and $11.4 million at December 31, 2008 and December 31, 2007 and are composed entirely of bank balances in checking accounts with excess cash in money market accounts which invest primarily in government securities with less than 90 day maturities... Long term debt is disclosed in Note 5.

The Company’s management reviews the capital structure on a regular basis to maintain the most optimal debt to equity balance. In order to maintain or adjust its capital structure, the Company may refinance its existing debt, raise new debt, seek cost sharing arrangements with partners or issue new shares.

In 2008, the Company expensed $2.6 million of deferred financing costs that were directly attributable to a proposed offering of securities for its wholly-owned Chinese subsidiary.

The Company’s U.S. and Chinese oil and gas subsidiaries are subject to financial covenants, such as interest coverage ratios, under each of their revolving/term credit facilities which are measured on a quarterly or semi-annual basis. The Company is in compliance with all financial covenants for the year ended December 31, 2008.

14. INCOME TAXES

The Company and its subsidiaries are required to individually file tax returns in each of the jurisdictions in which they operate. The provision for income taxes differs from the amount computed by applying the statutory income tax rate to the net losses before income taxes. The combined Canadian federal and provincial statutory rates as at December 31, 2008, 2007 and 2006 were 29.5%, 32.12% and 32.12%, respectively. The sources and tax effects for the differences were as follows:


	Year ended December 31,
	2008			2007			2006
Tax benefit computed at the combined Canadian federal and provincial statutory income tax rates	$	(9,893	)	$	(12,593	)	$	(8,188	)
Foreign net losses affected at lower income tax rates		5,084			905			113
Effect of change in foreign exchange rates		3,006			(2,879	)		(14	)
Expiry of tax loss carry-forwards		2,875			2,440			1,583
Stock-based compensation not deductible		905			1,001			1,031
Financing costs not deductible		695			—			—
Net currency exchange losses not deductible		402			—			—
Change in prior year estimate of tax loss carry-forwards		(430	)		(483	)		503
Realized derivative (gains)/losses not taxable/deductible		(422	)		1,248			—
Effect of change in effective income tax rates on future tax assets		(331	)		6,109			870
Other permanent differences		(58	)		778			95
Tax credit carry-forward		—			607			(428	)

		1,833			(2,867	)		(4,435	)
Valuation allowance		(1,833	)		2,867			4,435

	$	—		$	—		$	—

Significant components of the Company’s future net income tax assets and liabilities were as follows:


	As at December 31,
	2008						2007
	Future Income Tax						Future Income Tax
	Assets			Liabilities			Assets			Liabilities
Oil and gas properties and investments	$	—		$	(1,972	)	$	—		$	(3,330	)
Intangibles		—			(37,089	)		—			(36,976	)
Derivative contracts		—			(292	)		1,989			—
Tax loss carry-forwards		60,355			—			61,152			—
Tax credit carry-forward		1,278			—			1,278			—
Valuation allowance		(22,280	)		—			(24,113	)		—

	$	39,353		$	(39,353	)	$	40,306		$	(40,306	)

Due to the uncertainty of utilizing these net income tax assets, the Company has made a valuation allowance of an equal amount against the net potential recoverable amounts.

The tax loss carry-forwards in Canada are Cdn.$45.4 million, in China $35.5 million and in the U.S. $101.2 million. Tax loss carry-forwards in Ecuador are nominal. The tax loss carry-forwards in Canada expire between 2009 and 2028 and in the U.S. between 2016 and 2028. In China, the tax loss carry-forwards have no expiration period. A loss of approximately Cdn.$55.3 million from the disposition of Russian operations in 2000, being the aggregate investment, not including accounting write-downs, less proceeds received on settlement is a capital loss for Canadian income tax purposes, available for carry-forward against future Canadian capital gains indefinitely and is not included in the future income tax assets above.

The amount of current income tax payable at December 31, 2008 associated with income taxes for China equaled $0.7 million.

15. NET LOSS PER SHARE

Had the Company generated net earnings during the years presented, the earnings per share calculations for the years presented would have included the following weighted average items:


	Year ended December 31,
	2008		2007		2006
	(thousands of shares)
Stock options		1,374		2,433		3,292
Richfirst conversion rights		—		—		1,104
Purchase warrants		—		—		121
Convertible debt		6,943		—		—

		8,317		2,433		4,517

Additionally, the earnings per share calculations would have included the following weighted average items had the exercise prices exceeded the average market prices of the common shares:


	Year ended December 31,
	2008		2007		2006
	(thousands of shares)
Stock options		9,944		8,616		7,022
Purchase warrants		16,399		28,898		25,184

		26,343		37,514		32,206

16. SUPPLEMENTAL CASH FLOW INFORMATION

Supplemental cash flow information for each of the years ended December 31 was as follows:


	Year Ended December 31,
	2008			2007			2006
Cash paid during the period for
Income taxes	$	6		$	6		$	5

Interest	$	1,431		$	479		$	430


Investing and Financing activities, non-cash
Acquisition of oil and gas assets
Debt issued	$	52,052		$	—		$	6,547
Shares issued		—			—			20,000
Receivable applied to acquisition		—			—			1,746

	$	52,052		$	—		$	28,293


Conversion of debt to shares
Extinguishment of debt	$	4,737		$	—		$	—
Extinguishment of interest		125			—			—

	$	4,862		$	—		$	—


Shares issued for bonuses	$	490		$	793		$	401


Stock based compensation capitalized	$	175		$	—		$	—


Changes in non-cash working capital items
Operating Activities
Accounts receivable	$	4,159		$	(1,734	)	$	(1,375	)
Prepaid and other current assets		(136	)		85			(434	)
Accounts payable and accrued liabilities		1,470			1,166			(1,067	)
Income tax payable		650			—			—

		6,143			(483	)		(2,876	)


Investing Activities
Accounts receivable		(44	)		(207	)		2,188
Prepaid and other current assets		(70	)		86			(1	)
Accounts payable and accrued liabilities		(816	)		(1,056	)		(14,895	)

		(930	)		(1,177	)		(12,708	)


Financing Activities
Accounts payable and accrued liabilities		26			—			—

	$	5,239		$	(1,660	)	$	(15,584	)

Cash and cash equivalents at December 31, 2008, and 2007, are composed entirely of bank balances in checking accounts with excess cash in money market accounts which invest primarily in government securities with less than 90 day maturities.

17. RELATED PARTY TRANSACTIONS

The Company has entered into agreements with a number of entities which are related or controlled through common directors or shareholders. These entities provide access to an aircraft, the services of administrative and technical personnel, and office space or facilities in Vancouver, London and Singapore. The Company is billed on a cost recovery basis. For the year ended December 31, 2008 the costs incurred in the normal course of business with respect to the above arrangements amounted to $3.0 million ($3.3 million for 2007 and $3.0 million for 2006), and are recorded in general and administrative expense in the statement of operations. As at December 31, 2008 amounts included in accounts payable and accrued liabilities on the balance sheet under these arrangements were $0.1 million ($0.2 million at December 31, 2007).

18. ACQUISTION AND PROJECT RELATED AGREEMENTS

Canada

In July 2008, the Company completed the acquisition of Talisman Energy Canada’s (“Talisman”) 100% working interests in two leases located in the Athabasca oil sands region in the Province of Alberta, Canada. The total purchase price was Cdn.$90.0 million, of which an initial payment of Cdn.$22.5 million was made on closing. In addition to this initial payment the Company issued a promissory note to Talisman in the principal amount of Cdn.$12.5 million bearing interest at a rate per year equal to the prime rate plus 2% which matured and was paid on December 31, 2008 and a second promissory note to Talisman in the principal amount of Cdn.$40.0 million bearing interest at a rate per annum equal to the prime rate plus 2%, maturing in July 2011 and convertible (as to the outstanding principal amount), at Talisman’s option, into a maximum of 12,779,552 common shares of the Company at Cdn.$3.13 per common share.

The Company may also be required to make a cash payment to Talisman of Cdn.$15 million if the requisite government and other approvals necessary to develop the northern border of one of the leases (the “Contingent Payment”) are obtained. No amount is recorded in the financial statements for this payment as at December 31, 2008 as the chance of occurrence can not be determined at this time.

Talisman retains a back-in right (the “Back-in Right”), exercisable once per lease until July 11, 2011, to re-acquire up to a 20% undivided interest in each lease. The purchase price payable by Talisman were it to exercise the Back-in Right in respect of a particular lease would be an amount equal to 20% of:

(a)

100% of the Company’s acquisition cost and certain expenses in respect of the relevant lease if the Back-in Right is exercised on or before July 11, 2009;

(b)

150% of the Company’s acquisition cost and certain expenses in respect of the relevant lease if the Back-in Right is exercised after July 11, 2009 but on or before July 11, 2010; or

(c)

200% of the Company’s acquisition cost and certain expenses in respect of the relevant lease if the Back-in Right is exercised after July 11, 2010 but on or before July 11, 2011.

Until July 11, 2011, Talisman has the right of first offer to acquire any interests in heavy oil projects in the Province of Alberta that the Company or any of its subsidiaries wishes to sell, excluding the acquired leases.

Ecuador

In October 2008, Ivanhoe Energy Ecuador Inc. (“IE Ecuador”) entered into a contract with Empresa Estatal de Petroleos del Ecuador, Petroecuador (“Petroecuador”), the state oil company of Ecuador, and its affiliate, Empresa Estatal de Exploracion y Produccion de Petroleos del Ecuador, Petroproduccion (“Petroproduccion”) to explore and develop an oil field in Ecuador that includes the Pungarayacu heavy-oil field, utilizing the Company’s HTL^TM technology. IE Ecuador is a wholly-owned subsidiary of Ivanhoe Energy Latin America Inc. (“IE Latin America”), a wholly-owned subsidiary of the Company.

IE Ecuador will lead the development of the project. The contract is guaranteed by its parent company IE Latin America, which will obtain or provide funding and financing for IE Ecuador’s operations under the contract. The contract’s 30-year term may be extended by mutual agreement. To recover its investments, costs and expenses, and to provide for a profit, IE 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 US Government-published producer price indices relating to steel products, refinery products and upstream oil and gas equipment.

China

The Company currently holds a production-sharing contract with CNPC to develop existing oil properties in the Dagang region. In January 2004, the Company signed farm-out and joint operating agreements with Richfirst Holdings Limited (“Richfirst”), to acquire a 40% working interest in the Dagang field for payment of $20.0 million. In February 2006, the Company re-acquired Richfirst’s 40% working interest for total consideration of $28.3 million consisting of $20.0 million paid by way of the issuance to Richfirst of 8,591,434 common shares of the Company, a non-interest bearing, unsecured promissory note in the principal amount approximately $7.4 million ($6.5 million after being discounted to net present value) and the forgiveness of $1.8 million of unpaid joint venture receivables. The promissory note is repayable in 36 equal monthly installments commencing March 31, 2006. The Company has the right, during the three-year loan repayment period, to require Richfirst to convert the remaining unpaid balance of the promissory note into common shares of Sunwing Energy Ltd (“Sunwing"), the Company’s wholly-owned subsidiary, or another company owning all of the outstanding shares of Sunwing, subject to Sunwing or the other company having obtained a listing of its common shares on a prescribed stock exchange. The number of shares issued would be determined by dividing the then outstanding principal balance under the promissory note by the issue price of shares of the newly listed company issued in the transaction that results in the listing, less a 10% discount.

19.

ADDITIONAL DISCLOSURES REQUIRED UNDER U.S. GENERALLY ACCEPTED ACCOUNTING PRINCIPLES

The Company’s consolidated financial statements have been prepared in accordance with GAAP as applied in Canada. In the case of the Company, Canadian GAAP conforms in all material respects with U.S. GAAP except for certain matters, the details of which are as follows:

Consolidated Balance Sheets

The application of U.S. GAAP has the following effects on consolidated balance sheet items as reported under Canadian GAAP:


	As at December 31, 2008											As at December 31, 2007
	Canadian			Increase					U.S.			Canadian			Increase					U.S.
	GAAP			(Decrease)			Notes		GAAP			GAAP			(Decrease)			Notes		GAAP

Assets
Current Assets:
Cash and cash equivalents	$	39,265							$	39,265		$	11,356							$	11,356
Accounts receivable		4,870								4,870			9,376								9,376
Advance		—								—			825								825
Prepaid and other current assets		1,658								1,658			602			96			(xi)		698
Derivative instruments		2,159								2,159			—								—

Total Current Assets		47,952			—					47,952			22,159			96					22,255

Oil and gas properties and development costs, net		176,550			1,358			(iv)		122,071			111,853			1,358			(iv)		90,897
					(67,850	)		(v)								(25,990	)		(v)
					13,031			(vi)								9,334			(vi)
					(1,018	)		(vii)								(5,658	)		(vii)
Intangible assets — technology		92,153								92,153			102,153			—					102,153
Long term assets		620			451			(xi)		1,071			751			600			(xi)		1,351

Total Assets	$	317,275		$	(54,028	)			$	263,247		$	236,916		$	(20,260	)			$	216,656

Liabilities and Shareholders’ Equity
Current Liabilities:
Accounts payable and accrued liabilities	$	10,093							$	10,093		$	9,538		$	—				$	9,538
Income tax payable		650								650			—			—					—
Debt — current portion		5,612								5,612			6,729			96			(xi)		6,825
Derivative instruments		—			1,121			(iii)		1,121			9,432			5,786			(iii)		15,218

Total Current Liabilities		16,355			1,121					17,476			25,699			5,882					31,581

Long term debt		37,855			451			(xi)		40,392			9,812			600			(xi)		10,412
					2,086			(viii)

Asset retirement obligations		3,738								3,738			2,218			—					2,218
Long term obligation		1,900								1,900			1,900			—					1,900

Total Liabilities		59,848			3,658					63,506			39,629			6,482					46,111


Shareholders’ Equity:
Share capital		413,857			74,455			(i)		502,372			324,262			74,455			(i)		412,879
					(498	)		(ii)								(396	)		(ii)
					1,358			(iv)								1,358			(iv)
					13,200			(iii)								13,200			(iii)
Purchase warrants		18,805			(18,805	)		(iii)		—			23,078			(21,218	)		(iii)		1,860
Contributed surplus		16,862			(3,250	)		(ii)		10,665			9,937			(3,352	)		(ii)		6,051
					(2,947	)		(iii)								(534	)		(iii)
Convertible note		2,086			(2,086	)		(viii)		—			—			—					—
Accumulated deficit		(194,183	)		(119,113	)				(313,296	)		(159,990	)		(90,255	)				(250,245	)

Total Shareholders’ Equity		257,427			(57,686	)				199,741			197,287			(26,742	)				170,545

Total Liabilities and Shareholders’ Equity	$	317,275		$	(54,028	)			$	263,247		$	236,916		$	(20,260	)			$	216,656

Shareholders’ Equity

(i) In June 1999, the shareholders approved a reduction of stated capital in respect of the common shares by an amount of $74.5 million being equal to the accumulated deficit as at December 31, 1998. Under U.S. GAAP, a reduction of the accumulated deficit such as this is not recognized except in the case of a quasi reorganization.

(ii) Under Canadian GAAP, the Company accounts for all stock options granted to employees and directors since January 1, 2002 using the fair value based method of accounting. Under this method, compensation costs are recognized in the financial statements over the stock options’ vesting period using an option-pricing model for determining the fair value of the stock options at the grant date. For U.S. GAAP, prior to January 1, 2006 the Company applied APB Opinion No. 25, as interpreted by FASB Interpretation No. 44, in accounting for its stock option plan and did not recognize compensation costs in its financial statements for stock options issued to employees and directors.

In December 2004, the Financial Accounting Standards Board (“FASB”) issued a revision to Statement of Financial Accounting Standards (“SFAS”) No. 123, “Accounting for Stock Based Compensation” which supersedes APB No. 25, “Accounting for Stock Issued to Employees”. This statement (“SFAS No. 123(R)”) requires measurement of the cost of employee services received in exchange for an award of equity instruments based on the fair value of the award on the date of the grant and recognition of the cost in the results of operations over the period during which an employee is required to provide service in exchange for the award. No compensation cost is recognized for equity instruments for which employees do not render the requisite service. The Company elected to implement this statement on a modified prospective basis starting in the first quarter of 2006. Under the modified prospective basis the Company began recognizing stock based compensation in its U.S. GAAP results of operations for the unvested portion of awards outstanding as at January 1, 2006 and for all awards granted after January 1, 2006.

(iii) The Company accounts for purchase warrants as equity under Canadian GAAP. The accounting treatment of warrants under U.S. GAAP reflects the application of SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”). Under SFAS No. 133, share purchase warrants with an exercise price denominated in a currency other than a company’s functional currency are accounted for as derivative liabilities. Changes in the fair value of the warrants are required to be recognized in the statement of operations each reporting period for U.S. GAAP purposes. At the time that the Company’s share purchase warrants are exercised, the value of the warrants will be reclassified to shareholders’ equity for U.S. GAAP purposes. Under Canadian GAAP, the fair value of the warrants on the issue date is recorded as a reduction to the proceeds from the issuance of common shares, with the offset to the warrant component of equity. The warrants are not revalued to fair value under Canadian GAAP.

Oil and Gas Properties and Development Costs

(iv) Under U.S. GAAP, the aggregate value attributed to the acquisition of U.S. royalty rights during 1999 and 2000 was $1.4 million higher, due to the difference between Canadian and U.S. GAAP in the value ascribed to the shares issued, primarily resulting from differences in the recognition of effective dates of the transactions.

(v) There are certain differences between the full cost method of accounting for oil and gas properties as applied in Canada and as applied in the U.S. The principal difference is in the method of performing ceiling test evaluations under the full cost method of accounting rules. In the ceiling test evaluation for U.S. GAAP purposes, the Company limits, on a country-by-country basis, the capitalized costs of oil and gas properties, net of accumulated DD&A and deferred income taxes, to (a) the estimated future net cash flows from proved oil and gas reserves using period-end, non-escalated prices and costs, discounted to present value at 10% per annum, plus (b) the cost of properties not being amortized (e.g. major development projects) and (c) the lower of cost or fair value of unproved properties included in the costs being amortized less (d) income tax effects related to difference between the book and tax basis of the properties referred to in (b) and (c) above. If capitalized costs exceed this limit, the excess is charged as a provision for impairment. Unproved properties and major development projects are assessed on a quarterly basis for possible impairments or reductions in value. If a reduction in value has occurred, the impairment is transferred to the carrying value of proved oil and gas properties. The differences in the ceiling test impairments by period for the U.S. and China Oil and Gas Properties between U.S. and Canadian GAAP as at December 31, 2008 are as follows:


	Ceiling Test Impairments				(Increase)
	U.S. GAAP		Canadian GAAP		Decrease
U.S. Properties
Prior to 2004	$	34,000	$	34,000	$	—
2004		15,000		16,350		1,350
2005		2,800		—		(2,800	)
2006		7,600		—		(7,600	)
2007		—		—		—
2008		20,300		—		(20,300	)

		79,700		50,350		(29,350	)

China Properties
Prior to 2004		10,000		—		(10,000	)
2004		—		—		—
2005		1,700		5,000		3,300
2006		15,940		5,420		(10,520	)
2007		5,850		6,130		280
2008		21,560		—		(21,560	)

		55,050		16,550		(38,500	)

	$	134,750	$	66,900	$	(67,850	)

(vi) The cumulative differences in the amount of impairment provisions between U.S. and Canadian GAAP resulted in reductions in accumulated depletion.

(vii) As more fully described under “Development Costs” in Note 2, under Canadian GAAP, the Company capitalizes certain development costs incurred for HTL^TM and GTL projects subsequent to executing a MOU to determine the technical and commercial feasibility of a project, including studies for the marketability for the project’s products. If no definitive agreement is reached, then the project’s capitalized costs, which are deemed to have no future value, are written down and charged to the results of operations with a corresponding reduction in HTL^TM and GTL development costs. Under U.S. GAAP, feasibility, marketing and related costs incurred prior to executing an HTL^TM or GTL definitive agreement are considered to be research and development and are expensed as incurred.

(viii) As described in Note 5, under Canadian GAAP the Company was required to bifurcate the value of the Convertible Debt, allocating a portion to long term debt and a portion to equity. Under U.S. GAAP, the convertible debt securities in their entirety are classified as debt. This resulted in an increase in long term debt and a decrease in equity of $2.1 million for U.S. GAAP when compared to Canadian GAAP as at December 31, 2008. Under Canadian GAAP, the liability component will be accreted over the three-year maturity period to bring the liability back to Cdn.$40.0 million using the effective interest method.

Deferred Financing Costs

(xi) As more fully described under “Financial Assets and Liabilities” in Note 2, for Canadian GAAP the Company accounts for deferred financing costs, or transaction costs, as a reduction from the related liability and accounted for using the effective interest method. For U.S. GAAP purposes, these costs are classified as other assets and amortized over the expected term of the financial liability.

Consolidated Statements of Operations

The application of U.S. GAAP had the following effects on net loss and net loss per share as reported under Canadian GAAP:


	Year Ended December 31, 2008
	Canadian			Increase				U.S.
	GAAP			(Decrease)			Notes	GAAP
Revenue
Oil and gas revenue	$	66,490						$	66,490
Gain on derivative instruments		1,966			4,665		(iii)		6,631
Interest income		710							710

Total Revenue		69,166			4,665				73,831


Expenses
Operating costs		26,652							26,652
General and administrative		18,190							18,190
Business and technology development		6,453							6,453
Depletion and depreciation		31,904			(3,697	)	(ix)		28,207
Interest expense and financing costs		1,829							1,829
Provision for impairment of HTL^TM and GTL intangible assets and development costs		15,054			(4,640	)	(x)		10,414
Write off of deferred financing costs		2,621							2,621
Provision for impairment of oil and gas properties		—			41,860		(ix)		41,860

Total Expenses		102,703			33,523				136,226


Loss before Income Taxes		(33,537	)		(28,858	)			(62,395	)

Current provision for income taxes		(656	)		—				(656	)


Net Loss and Comprehensive Loss		(34,193	)		(28,858	)			(63,051	)
Accumulated Deficit, beginning of year		(159,990	)		(90,255	)			(250,245	)

Accumulated Deficit, end of year	$	(194,183	)	$	(119,113	)		$	(313,296	)


Net Loss per share — Basic and Diluted	$	(0.13	)	$	(0.11	)		$	(0.24	)


Weighted Average Number of Shares (in thousands)
Basic and Diluted		258,815							258,815


	Year Ended December 31, 2007
	Canadian			Increase				U.S.
	GAAP			(Decrease)			Notes	GAAP
Revenue
Oil and gas revenue	$	43,635		$	—			$	43,635
Loss on derivative instruments		(10,587	)		592		(iii)		(9,995	)
Interest income		469			—				469

Total Revenue		33,517			592				34,109


Expenses
Operating costs		17,319			—				17,319
General and administrative		12,076			—				12,076
Business and technology development		9,625			—				9,625
Depletion and depreciation		26,524			(4,932	)	(ix)		21,592
Interest expense and financing costs		1,050			—				1,050
Provision for impairment of HTL^TM and GTL intangible assets and development costs		—			(6,011	)	(x)		(6,011	)
Provision for impairment of oil and gas properties		6,130			(280	)	(ix)		5,850

Total Expenses		72,724			(11,223	)			61,501


Net Loss and Comprehensive Loss		(39,207	)		11,815				(27,392	)
Accumulated Deficit, beginning of year		(120,783	)		(102,070	)			(222,853	)

Accumulated Deficit, end of year	$	(159,990	)	$	(90,255	)		$	(250,245	)


Net Loss per share — Basic and Diluted	$	(0.16	)	$	0.05			$	(0.11	)


Weighted Average Number of Shares (in thousands)
Basic and Diluted		242,362							242,362


	Year Ended December 31, 2006
	Canadian			Increase				U.S.
	GAAP			(Decrease)			Notes	GAAP
Revenue
Oil and gas revenue	$	47,748		$	—			$	47,748
Loss on derivative instruments		(424	)		(691	)	(iii)		(1,115	)
Interest income		776			—				776

Total Revenue		48,100			(691	)			47,409


Expenses
Operating costs		16,133			—				16,133
General and administrative		10,180			—				10,180
Business and technology development		7,610			—				7,610
Depletion and depreciation		32,550			(2,840	)	(ix)		29,710
Interest expense and financing costs		963			—				963
Provision for impairment of HTL^TM and GTL intangible assets and development costs		—			958		(x)		958
Provision for impairment of oil and gas properties		5,420			18,120		(ix)		23,540
Write off of deferred acquisition costs		736			—				736

Total Expenses		73,592			16,238				89,830


Net Loss and Comprehensive Loss		(25,492	)		(16,929	)			(42,421	)
Accumulated Deficit, beginning of year		(95,291	)		(85,141	)			(180,432	)

Accumulated Deficit, end of year	$	(120,783	)	$	(102,070	)		$	(222,853	)


Net Loss per share — Basic and Diluted	$	(0.11	)	$	(0.07	)		$	(0.18	)


Weighted Average Number of Shares (in thousands)
Basic and Diluted		235,640							235,640

(ix) As discussed under “Oil and Gas Properties and Development Costs” in this note, there is a difference between U.S. and Canadian GAAP in performing the ceiling test evaluation under the full cost method of accounting rules. Application of the ceiling test evaluation under U.S. GAAP has resulted in an accumulated net increase in impairment provisions on the Company’s U.S. and China oil and gas properties. This net increase in U.S. GAAP impairment provisions has resulted in lower depletion rates for U.S. GAAP purposes and a reduction in the net losses for the years ended December 31, 2008, 2007 and 2006.

(x) As more fully described under “Oil and Gas Properties and Development Costs” in this note, for Canadian GAAP, feasibility, marketing and related costs incurred prior to executing a HTL^TM or GTL definitive agreement are capitalized and are subsequently written down upon determination that a project’s future value has been impaired. For U.S. GAAP, such costs are considered to be research and development and are expensed as incurred.

As more fully described under Note 3, the Company and INPEX have signed an agreement to jointly pursue the opportunity to develop a heavy oil field in Iraq that Ivanhoe believes is a suitable candidate for its patented HTL^TM heavy oil upgrading technology. In the second quarter of 2007, the Company received a $9.0 million payment related to this agreement which was credited to the carrying value of its Iraq and CDF HTL^TM Investments related to this project for Canadian GAAP purposes. The prior costs for Iraq projects had previously been expensed for U.S. GAAP purposes therefore that portion of the proceeds, $6.3 million, was credited to the statement of operations for U.S. GAAP purposes. For the year ended December 31, 2008 the Company recorded nil ($6.3 million in 2007 and nil in 2006) as a reduction to net loss for U.S. GAAP when compared to Canadian GAAP due to the recovery of prior costs expensed for U.S. GAAP and capitalized for Canadian GAAP.

As more fully described under Note 3, the Company wrote off $5.1 million in GTL development costs under Canadian GAAP. These costs had already been expensed under U.S. GAAP in previous periods and therefore this transaction reduced the net loss for U.S. GAAP purposes in 2008.

Pro Forma Effect of Merger and Acquisition

Had the acquisition of Richfirst’s 40% working interest in the Dagang field been completed January 1, 2006, the U.S. GAAP pro forma revenue, net loss and net loss per share of the consolidated operations for the year ended December 31, 2006 would have been as follows:


	Year ended December 31, 2006
			(unaudited)
			Net			Net Loss
	Revenue		Loss			Per Share
As reported	$	47,409	$	(42,421	)	$	(0.18	)
Pro forma adjustments		1,051		809			—

	$	48,460	$	(41,612	)	$	(0.18	)


Pro Forma Weighted Average Number of Shares (in thousands)							236,840

Income Taxes

On January 1, 2007, the Company adopted the provisions of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”), an interpretation of FASB Statement No. 109, “Accounting for Income Taxes.” FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The interpretation requires that the Company recognize the impact of a tax position in the financial statements if that position is more likely than not of being sustained on audit, based on the technical merits of the position. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods and disclosure. In accordance with the provisions of FIN 48, any cumulative effect resulting from the change in accounting principle is to be recorded as an adjustment to the opening balance of deficit.

The implementation of FIN 48 did not result in any adjustment to the Company’s beginning tax positions. The Company continues to fully recognize its tax benefits, which are offset by a valuation allowance to the extent that it is more likely than not that the deferred tax assets will not be realized. As at December 31, 2008 and December 31, 2007, the Company did not have any unrecognized tax benefits.

The Company files federal and provincial income tax returns in Canada. The Company’s U.S. and China subsidiaries file federal, state and local income tax returns in the U.S and China, as applicable. The Company may be subject to a reassessment of federal and provincial income taxes by Canadian tax authorities for a period of four years from the date of mailing of the original Notice of Assessment in respect of any particular taxation year. The U.S. federal statute of limitations for assessment of income tax is generally closed for the Company’s tax years ending on or prior to 2003. In certain circumstances, the U.S. federal statute of limitations can reach beyond the standard three year period. U.S. state statutes of limitations for income tax assessment vary from state to state. There is no statute of limitations for audit of tax years in China. Tax authorities have not audited any of the Company’s, or its subsidiaries’, income tax returns or issued Notices of Assessment for any tax years.

The Company recognizes any interest accrued related to unrecognized tax benefits in interest expense and penalties in interest expense and financing costs. During the years ended December 31, 2008, 2007 and 2006, there were no charges for interest or penalties.

Consolidated Statements of Cash Flows

As a result of the expensing of HTL^TM and GTL development costs as required under U.S. GAAP and the recovery of such costs, the statement of cash flows as reported would result in cash surplus from operating activities of $16.6 million, $11.5 million and $13.3 million for the years ended December 31, 2008, 2007 and 2006. Additionally, capital investments reported under investing activities would be $25.2 million, $31.4 million and $16.8 million for the years ended December 31, 2008, 2007 and 2006, respectively.

Additional U.S. GAAP Disclosures

Oil and Gas Properties and Development Costs

The categories of costs included in “Oil and Gas Properties and Development Costs”, including the U.S. GAAP adjustments discussed in this note were as follows:


	As at December 31, 2008
												Business and
												Technology
	Canada			Ecuador		China			U.S.			Development			Total
Property acquisition costs	$	75,732		$	863	$	31,137		$	22,672		$	—		$	130,404
Royalty rights acquired		—			—		—			10,582			—			10,582
Capitalized Interest		1,672			—		—			—			—			1,672
Exploration costs		3,686			591		31,578			42,759			—			78,614
Development costs		—			—		83,315			41,413			—			124,728
HTL^TM facilities		—			—		—			—			19,590			19,590
Support equipment and general property		20			90		412			538			406			1,466

		81,110			1,544		146,442			117,964			19,996			367,056
Accumulated depletion and depreciation		(6	)		—		(72,030	)		(30,571	)		(7,628	)		(110,235	)
Provision for impairment		—			—		(55,050	)		(79,700	)		—			(134,750	)

	$	81,104		$	1,544	$	19,362		$	7,693		$	12,368		$	122,071


	As at December 31, 2007
							Business and
							Technology
	China			U.S.			Development			Total
Property acquisition costs	$	31,137		$	22,196		$	—		$	53,333
Royalty rights acquired		—			10,582			—			10,582
Capitalized Interest		—			—			—			—
Exploration costs		29,621			42,721			—			72,342
Development costs		76,895			37,272			—			114,167
HTL^TM facilities		—			—			14,412			14,412
Support equipment and general property		410			529			108			1,047

		138,063			113,300			14,520			265,883
Accumulated depletion and depreciation		(51,643	)		(25,315	)		(5,138	)		(82,096	)
Provision for impairment		(33,490	)		(59,400	)		—			(92,890	)

	$	52,930		$	28,585		$	9,382		$	90,897

As at December 31, 2008, the costs of unproved properties included in oil and gas properties, which have been excluded from the depletion and ceiling test calculations, were as follows:


			Incurred in
									Prior to
	Total		2008		2007		2006		2006

Property Acquisition	$	77,901	$	77,209	$	33	$	24	$	635
Royalty rights		659		—		—		—		659
Exploration		12,315		7,290		258		212		4,555

	$	90,875	$	84,499	$	291	$	236	$	5,849

The following is a summary of unproved oil and gas properties by prospect as at December 31, 2008:


			Incurred in
									Prior to
	Total		2008		2007		2006		2006
Canada
Tamarack	$	81,090	$	81,090	$	—	$	—	$	—


Ecuador
Block 20		1,454		1,454		—		—		—


China
Zitong Block		5,233		1,935		258		57		2,983


U.S.
Knights Landing		1,000		—		—		144		856
San Joaquin Basin prospects — other		2,098		20		33		35		2,010

		3,098		20		33		179		2,866

	$	90,875	$	84,499	$	291	$	236	$	5,849

With regard to the Tamarack Project in Canada, the Company plans to continue on the path for submitting a regulatory application, for the first phase of development, in the 3rd quarter of 2010.

With regard to Block 20 in Ecuador, the Company will be in the approval phase during the first part of 2009 which includes obtaining environmental licenses. If the Company succeeds in getting the necessary approvals it will enter into the appraisal phase which would include obtaining permits to drill, undertaking seismic activity and drilling selected locations.

With regards to the Zitong Block prospect, the Company plans to complete its review of the seismic data acquired to date on the block to select the first Phase II drilling location in the first part of 2009, commence drilling in late 2009 and complete drilling, completion and conclude final evaluation in late 2010.

The Company plans to continue to explore its options with regard to the Knight’s Landing property to seek either a farm out or possible drilling program. The majority of the San Joaquin prospects are fee property with no rental payments to maintain the Company’s leases. The timing of drilling on these prospects is dependent on other working interest owners.

Accounts Payable and Accrued Liabilities

The following was the breakdown of accounts payable and accrued liabilities:


	As at December 31,
	2008		2007
Trade payables	$	4,835	$	6,896
Accrued general and administrative expenses		1,130		722
Accrued operating expenses		558		561
Accrued capital expenditures		2,163		620
Accrued salaries and related expenses		328		82
Accrued interest		1,027		65
Other accruals		52		592

	$	10,093	$	9,538

SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The three levels of the fair value hierarchy are described below:

Level 1: Values based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical assets or liabilities.

Level 2: Values based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability.

Level 3: Values based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement.

As required by SFAS No. 157 when the inputs used to measure fair value fall within different levels of the hierarchy, the level within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measure in its entirety.

The following table presents the company’s fair value hierarchy for those assets and liabilities measured at fair value on a recurring basis as of December 31, 2008.


	As at December 31, 2008
	Level 1		Level 2		Level 3		Total

Derivative instruments assets	$	—	$	2,159	$	—	$	2,159

Derivative instruments liabilities	$	1,121	$	—	$	—	$	1,121

The fair value measurement of derivative instruments assets related to the Company’s costless collars are considered Level 2 and the fair value measurement of derivative instruments liabilities related to its purchase warrants denominated in Cdn.$ are considered Level 1.

Impact of New and Pending U.S. GAAP Accounting Standards

In December 2008, the SEC released Final Rule, Modernization of Oil and Gas Reporting to revise the existing Regulation S-K and Regulation S-X reporting requirements to align with current industry practices and technological advances. The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. In addition, the new disclosure requirements require a company to (a) disclose its internal control over reserves estimation and report the independence and qualification of its reserves preparer or auditor, (b) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserve audit and (c) report oil and gas reserves using an average price based upon the prior 12-month period rather than period-end prices. The provisions of this final ruling will become effective for disclosures in our Annual Report on Form 10-K for the year ended December 31, 2009. Management is still evaluating the impact of these changes on its financial statements.

QUARTERLY FINANCIAL DATA IN ACCORDANCE WITH CANADIAN AND U.S. GAAP (UNAUDITED)


	QUARTER ENDED
	2008											2007
	4th Qtr			3rd Qtr		2nd Qtr			1st Qtr			4th Qtr			3rd Qtr			2nd Qtr			1st Qtr
Total revenue:
Canadian GAAP	$	25,143		$	35,626	$	(2,772	)	$	11,169		$	5,848		$	8,823		$	9,589		$	9,257
U.S. GAAP	$	30,538		$	50,267	$	(14,975	)	$	8,001		$	6,966		$	12,393		$	7,685		$	7,065
Net income (loss):
Canadian GAAP	$	(13,980	)	$	10,062	$	(21,731	)	$	(8,544	)	$	(18,849	)	$	(7,232	)	$	(6,579	)	$	(6,547	)
U.S. GAAP	$	(45,399	)	$	25,824	$	(32,981	)	$	(10,495	)	$	(16,094	)	$	(2,551	)	$	(1,211	)	$	(7,536	)
Net income (loss) per share:
Canadian GAAP	$	(0.05	)	$	0.04	$	(0.09	)	$	(0.03	)	$	(0.07	)	$	(0.03	)	$	(0.03	)	$	(0.03	)
U.S. GAAP	$	(0.17	)	$	0.10	$	(0.13	)	$	(0.04	)	$	(0.07	)	$	(0.01	)	$	—		$	(0.03	)

The differences in the net loss and net loss per share for the second quarter of 2007 were due mainly to the treatment of the payment by INPEX for past costs paid by the Company related to its Iraq project and HTL^TM Technology development costs. Approximately $6.3 million of this payment was applied to capital balances for Canadian GAAP purposes and as reduction to net loss for U.S. GAAP purposes. The differences in the net loss and net loss per share for the third quarter of 2007 were mainly due to an additional $3.6 million fair value adjustment of derivative instruments for U.S. GAAP. The differences in the net loss and net loss per share for the second quarter of 2008 were mainly due to an additional negative $12.2 million fair value adjustment of derivative instruments for U.S. GAAP. The differences in the net income and net income per share for the third quarter of 2008 were mainly due to an additional $14.6 million positive fair value adjustment of derivative instruments for U.S. GAAP. The differences in the net loss and net loss per share for the fourth quarter of 2008 were mainly due to the additional ceiling test write downs for U.S. GAAP.

SUPPLEMENTARY DISCLOSURES ABOUT OIL AND GAS PRODUCTION ACTIVITIES (UNAUDITED)
(all tabular amounts are expressed in thousands of U.S. Dollars, except reserves and depletion rate amounts)

The following information about the Company’s oil and gas producing activities is presented in accordance with U.S. SFAS No. 69, “Disclosures About Oil and Gas Producing Activities”.

Oil and Gas Reserves

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic conditions.

Proved developed oil and gas reserves are reserves, which can be expected to be recovered from existing wells with existing equipment and operating methods.

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

Reserves presented in this section represent the Company’s share of reserves, excluding royalty interests of others. The reserves were based on the estimates by the independent petroleum engineering firms of GLJ Petroleum Consultants Ltd. and Netherland, Sewell & Associates, Inc. for the China and U.S. reserves, respectively.

The changes in the Company’s net proved oil and gas reserves for the three-year period ended December 31, 2008 were as follows:


	Oil (MBbl)									Gas (MMcf)
	U.S.			China			Total			U.S.
Net proved reserves, December 31, 2005		1,272			1,300			2,572			1,685
Revisions of previous estimates		54			179	(1)		233			(214	)
Extensions and discoveries		189	(2)		—			189			—
Purchases of reserves in place		—			881	(3)		881			—
Production		(208	)		(575	)		(783	)		(66	)
Sale of reserves in place		(87	)		—			(87	)		(988	)

Net proved reserves, December 31, 2006		1,220			1,785			3,005			417
Revisions of previous estimates		84			(22	)		62			(52	)
Extensions and discoveries		23			—			23			—
Production		(192	)		(483	)		(675	)		(31	)

Net proved reserves, December 31, 2007		1,135			1,280			2,415			334
Revisions of previous estimates		(294	)(4)		242	(5)		(52	)		(168	)(6)
Extensions and discoveries		103	(7)		—			103			—
Production		(199	)		(490	)		(689	)		(22	)

Net proved reserves, December 31, 2008		745			1,032			1,777			144


(1)		These technical revisions were due to production performance, plus ongoing production optimizations.

(2)		This adjustment was related to a new pool discovery in the Company’s South Midway prospect.

(3)		In February of 2006 the Company re-acquired its 40% working interest in the Dagang field.

(4)		The oil reserve revision decrease is due to the low year end oil prices and its resulting affect on the economic limit for the Midway Sunset and West Texas properties.

(5)		The oil reserve revision is due to better performance of the Dagang property in relation to the 2007 Reserve Report.

(6)		The gas reserve revision decrease is due to the underperformance of the West Texas properties in relation to the 2007 Reserve Report.

(7)		The oil reserve additions are new locations in an area of the Midway Sunset Field prove up by the drilling program in the Spring of 2008.

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

The following standardized measure of discounted future net cash flows from proved oil and gas reserves was computed using period end statutory tax rates, costs and prices of $37.49, $89.18 and $55.33 per barrel of oil in 2008, 2007 and 2006, respectively, and $7.2, $8.54 and $5.64 per Mcf of gas in 2008, 2007 and 2006, respectively. A discount rate of 10% was applied in determining the standardized measure of discounted future net cash flows.

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

	•		future production from proved reserves will differ from estimated production;

	•		future production will also include production from probable and potential reserves;

	•		future, rather than year end, prices and costs will apply; and

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

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


	2008
	U.S.		China		Total
Future cash inflows	$	24,742	$	42,906	$	67,648
Future development and restoration costs		2,790		3,310		6,100
Future production costs		18,046		22,934		40,980

Future net cash flows		3,906		16,662		20,568
10% annual discount		940		2,576		3,516

Standardized measure	$	2,966	$	14,086	$	17,052


	2007
	U.S.		China		Total
Future cash inflows	$	99,301	$	118,911	$	218,212
Future development and restoration costs		3,490		5,190		8,680
Future production costs		38,935		52,446		91,381
Future income taxes		—		1,010		1,010

Future net cash flows		56,876		60,265		117,141
10% annual discount		13,616		10,674		24,290

Standardized measure	$	43,260	$	49,591	$	92,851


	2006
	U.S.		China		Total
Future cash inflows	$	65,101	$	103,526	$	168,627
Future development and restoration costs		2,990		11,660		14,650
Future production costs		31,691		38,369		70,060

Future net cash flows		30,420		53,497		83,917
10% annual discount		7,332		10,705		18,037

Standardized measure	$	23,088	$	42,792	$	65,880

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


	2008
	U.S.			China			Total
Sale of oil and gas, net of production costs	$	(12,984	)	$	(26,855	)	$	(39,839	)
Net changes in prices and production costs		(26,330	)		(21,620	)		(47,950	)
Extensions and discoveries, net of future production and development costs		768			—			768
Net change in future development costs		(1,701	)		(2,708	)		(4,409	)
Development costs incurred during the period that reduced future development costs		2,559			4,720			7,279
Revisions of previous quantity estimates		(1,762	)		3,739			1,977
Accretion of discount		4,326			4,959			9,285
Net change in income taxes		—			925			925
Changes in production rates (timing) and other		(5,170	)		1,335			(3,835	)

Decrease		(40,294	)		(35,505	)		(75,799	)
Standardized measure, beginning of year		43,260			49,591			92,851

Standardized measure, end of year	$	2,966		$	14,086		$	17,052


	2007
	U.S.			China			Total
Sale of oil and gas, net of production costs	$	(7,951	)	$	(18,365	)	$	(26,316	)
Net changes in prices and production costs		22,823			16,322			39,145
Extensions and discoveries, net of future production and development costs		465			—			465
Net change in future development costs		—			(3,545	)		(3,545	)
Development costs incurred during the period that reduced future development costs		—			10,188			10,188
Revisions of previous quantity estimates		2,900			(898	)		2,002
Accretion of discount		2,309			4,279			6,588
Net change in income taxes		—			(925	)		(925	)
Changes in production rates (timing) and other		(374	)		(257	)		(631	)

Increase		20,172			6,799			26,971
Standardized measure, beginning of year		23,088			42,792			65,880

Standardized measure, end of year	$	43,260		$	49,591		$	92,851


	2006
	U.S.			China			Total
Sale of oil and gas, net of production costs	$	(7,766	)	$	(23,849	)	$	(31,615	)
Net changes in prices and production costs		(4,851	)		(12,907	)		(17,758	)
Extensions and discoveries, net of future production and development costs		1,355			—			1,355
Net change in future development costs		(682	)		(7,800	)		(8,482	)
Development costs incurred during the period that reduced future development costs		2,572			4,686			7,258
Revisions of previous quantity estimates		319			5,187			5,506
Accretion of discount		3,217			4,664			7,881
Net change in income taxes		—			815			815
Purchases of reserves in place		—			25,645			25,645
Sale of reserves in place		(4,405	)		—			(4,405	)
Changes in production rates (timing) and other		1,155			3,052			4,207

Decrease		(9,086	)		(507	)		(9,593	)
Standardized measure, beginning of year		32,174			43,299			75,473

Standardized measure, end of year	$	23,088		$	42,792		$	65,880

Costs incurred in oil and gas property acquisition, exploration, and development activities for the Company’s U.S. and China Oil and Gas Properties were as follows:


	For the year ended December 31,
	2008		2007		2006
Canada
Property acquisition
Unproved	$	75,732	$	—	$	—
Exploration		5,357		—		—

		81,089		—		—


Ecuador
Property acquisition
Unproved		863		—		—
Exploration		591		—		—

		1,454		—		—


China
Property acquisition
Proved		—		—		28,719
Exploration		1,956		11,611		2,485
Development		6,420		11,881		6,153

		8,376		23,492		37,357


U.S.
Property acquisition
Unproved		477		702		881
Exploration		37		202		1,230
Development		5,354		3,087		3,465

		5,868		3,991		5,576

Total	$	96,787	$	27,483	$	42,933

The U.S. GAAP depletion rates, calculated on a per Boe of net production basis, were as follows:


U.S.
Year ended December 31, 2008	$	25.60
Year ended December 31, 2007	$	22.05
Year ended December 31, 2006	$	22.11

China
Year ended December 31, 2008	$	41.61
Year ended December 31, 2007	$	32.73
Year ended December 31, 2006	$	36.46

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


	2008									2007							2006
	U.S.			China			Total			U.S.		China			Total		U.S.			China			Total
Oil and gas revenue	$	18,120		$	48,370		$	66,490		$	12,270	$	31,365		$	43,635	$	12,065		$	35,683		$	47,748
Operating costs		5,137			21,515			26,652			4,319		13,000			17,319		4,299			11,834			16,133
Depletion		5,229			20,385			25,614			4,381		15,832			20,213		4,858			20,966			25,824
Provision for impairment		20,300			21,560			41,860			—		5,850			5,850		7,600			15,940			23,540

Results of operations from producing activities	$	(12,546	)	$	(15,090	)	$	(27,636	)	$	3,570	$	(3,317	)	$	253	$	(4,692	)	$	(13,057	)	$	(17,749	)

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

The Company’s management, including our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of December 31, 2008. Based upon this evaluation, management concluded that these controls and procedures were (1) designed to ensure that information required to be disclosed in the Company’s reports under the Exchange Act is accumulated and communicated to the Company’s Chief Executive Officer and Chief Financial Officer to allow timely decisions regarding required disclosure and (2) effective in accomplishing those objectives, in that they provide reasonable assurance that information required to be disclosed by the Company in the reports that it files or submits under the Securities Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives.

MANAGEMENT REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

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

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

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

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

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2008. In making this assessment, the Company’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on our assessment, management has concluded that, as of December 31, 2008, the Company’s internal control over financial reporting was effective based on those criteria. Management has reviewed the results of its assessment with the Audit Committee of the Board of Directors. The Company’s independent registered Chartered Accountants, Deloitte & Touche LLP, has audited the effectiveness of the Company’s internal control over financial reporting as of December 31, 2008, as stated in their report which immediately follows.


/s/ Robert M. Friedland		/s/ W. Gordon Lancaster

Robert M. Friedland		W. Gordon Lancaster
Chief Executive Officer		Chief Financial Officer

February 26, 2009

REPORT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS

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

We have audited the internal control over financial reporting of Ivanhoe Energy Inc. and subsidiaries (the “Company”) as of December 31, 2008, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

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

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

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

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements of the Company as of and for the year ended December 31, 2008 and our report dated February 26, 2009 expressed an unqualified opinion on those financial statements and included an explanatory paragraph regarding conditions and events that cast substantial doubt on the Company’s ability to continue as a going concern.

(signed) “Deloitte & Touche LLP”

Independent Registered Chartered Accountants
Calgary, Canada
February 26, 2009

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

There were no changes in the Company’s internal control over financial reporting that occurred during the three months ended December 31, 2008 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The following table provides the names of all of our directors and executive officers, their positions, terms of office and their principal occupations during the past five years. Each director is elected for a one-year term or until his successor has been duly elected or appointed. Officers serve at the pleasure of the Board of Directors.


Name, Age and	Position with	Present Occupation and
Municipality of Residence	the Registrant	Principal Occupation for the Past Five Years
A. ROBERT ABBOUD, age 79 Barrington Hills, IL	Co-Chairman and Independent Lead Director (since May 2006)	President, A. Robert Abboud and Company, a private investment company (1984 — present)

ROBERT M. FRIEDLAND, age 58 Singapore	Executive Co-Chairman, President & Chief Executive Officer (since May 2008) Director (since February 1995)	Executive Co-Chairman, President & Chief Executive Officer, Ivanhoe Energy Inc. (May 2008 — present); Deputy Chairman, Ivanhoe Energy Inc. (June, 1999 - May, 2008); Executive Chairman, Ivanhoe Mines Ltd. (March 1994 — present); Chairman, Ivanhoe Capital Corporation (January 1991 — present); President, Ivanhoe Capital Corporation (July 1988 — present)

HOWARD R. BALLOCH, age 57 Beijing, China	Director (since January 2002)	President, The Balloch Group (July 2001 — present); President, Canada China Business Council (July 2001 — 2006); Canadian Ambassador to China, Mongolia and Democratic Republic of Korea (April 1996 — July 2001)

ROBERT G. GRAHAM, age 55 Ottawa, Ontario	Director (since April 2005)	Chairman of Board of Directors and Chief Executive Officer, Ensyn Corporation (July 2008 — Present); Chairman of the Board of Directors, Ensyn Corporation (June 2007 — July 2008); President and CEO, Ensyn Corporation (April 2005 — June 2007); Chairman and CEO, Ensyn Group (October 1984— April 2005)

ROBERT A. PIRRAGLIA, age 59 Boca Raton, Florida	Director (since April 2005)	Executive Vice President, Ensyn Corporation (October 2007 — Present); Chief Operating Officer and Vice President, Ensyn Corporation (April 2005 — October 2007); Chief Operating Officer and Vice President, Ensyn Group, Inc. (September 1998 — April 2005)

BRIAN F. DOWNEY, C.M.A. age 67 Lake in the Hills, Illinois	Director (since July 2005)	President, Downey & Associates Management Inc. (July 1986 — present); Financial Advisor, Lending Solutions, Inc. (January 2002 — present) Partner/Owner, Lending Solutions, Inc. (November 1995 — January 2002)

PETER G. MEREDITH C.A., age 66 Vancouver, British Columbia	Director (since December 2007)	Deputy Chairman, Ivanhoe Mines Ltd. (May 2006 - present): Chief Financial Officer, Ivanhoe Capital Corporation (1996 — March 2009); Chief Executive Officer, SouthGobi Energy Resources (June 2007 - present), Chief Financial Officer, Ivanhoe Mines Ltd. (June 1999 — November 2001)

W. GORDON LANCASTER, C.A., age 65 Vancouver, British Columbia	Chief Financial Officer (since January 2004)	Chief Financial Officer, Ivanhoe Energy Inc. (January 2004 — present); Vice President Finance and Chief Financial Officer, Xantrex Technology Inc. (July 2003 — December 2003); Vice President Finance and Chief Financial Officer, Power Measurement, Inc. (August 2000 — June 2003)

MICHAEL A. SILVERMAN, age 56 Houston, Texas	Executive Vice President, Technology and Chief Technology Officer (since September 2007)	Executive Vice President, Technology and Chief Technology Officer, Ivanhoe Energy Inc. (September 2007 — present); Vice President, Technology, Ivanhoe Energy Inc. (May 2007 — September 2007); Vice President Technology, KBR, Inc. (May 2004 — May 2007); Director Technology Center, KBR, Inc. (May 2000 — May 2004)

EDWIN J. VEITH, age 50 Frazier Park, California	Executive Vice President, Upstream (since September 2007)	Executive Vice President, Upstream, Ivanhoe Energy Inc. (September 2007 — present); Vice President, HTL Technology, Ivanhoe Energy (USA) Inc. (November 2005 - present); Chief Reservoir Engineer, Ivanhoe Energy (USA) Inc. (June 2001 — November 2005)

K. C. PATRICK CHUA, age 53 Hong Kong, China	Executive Vice-President (since June 1999)	Executive Vice-President, Ivanhoe Energy Inc. (June 1999 — present); Chairman, Sunwing Energy Ltd. (Bermuda) (April 2004 — present); President, Sunwing Energy Ltd. (Bermuda) (March 2000 — April 2004)

GERALD G. MOENCH, age 60 Lethbridge, Alberta	Executive Vice-President (since June 1999)	Executive Vice-President, Ivanhoe Energy Inc. (June 1999 — present); President, Sunwing Energy Ltd. (Bermuda) (April 2004 — present)

All of our directors were elected at our last annual general meeting of shareholders (“AGM”) held on May 29, 2008. The term of office of each director concludes at our next AGM, unless the director’s office is earlier vacated in accordance with our by-laws. There are no family relationships among any of our directors, officers or key employees.

Under the terms of our acquisition of Ensyn, we granted to Ensyn the right to designate two individuals for appointment to our Board of Directors and agreed to use reasonable best efforts to nominate Ensyn’s designees for re-election to our Board of Directors annually for at least five years. Ensyn’s designees, Dr. Robert G. Graham and Mr. Robert A. Pirraglia, were originally appointed to the Board of Directors on April 15, 2005.

Effective May 29, 2008, our Board of Directors appointed Robert M. Friedland as Executive Chairman, President and Chief Executive Officer.

As required under the Business Corporations Act (Yukon), our Board of Directors has an Audit Committee. We also have a Compensation Committee, and a Nominating and Corporate Governance Committee and an Executive Committee. The members of the Audit Committee are Messrs. Brian F. Downey, Howard R. Balloch and A. Robert Abboud. Mr. Downey, one of our current independent directors, has been determined by the Board of Directors to be an Audit Committee financial expert. We believe that Mr. Downey’s prior experience working as a Certified Management Accountant and significant financial and business experience at the executive levels of management qualifies him to be an Audit Committee financial expert. The current members of the Compensation Committee are Messrs. Howard R. Balloch (Chair), Robert A. Pirraglia and Brian F. Downey. The current members of the Nominating and Corporate Governance Committee are Messrs. Howard R. Balloch (Chair), Robert A. Pirraglia and A. Robert Abboud. The current members of the Executive Committee are Messrs. Robert M. Friedland, A. Robert Abboud, Howard R. Balloch and Peter G. Meredith.

Management is responsible for our financial reporting process including our system of internal controls over financial reporting and for the preparation of consolidated financial statements in accordance with generally accepted accounting principles in Canada. Our independent registered chartered accountants are responsible for auditing those financial statements. The members of the Audit Committee are not our employees, and are not professional accountants or auditors. The Audit Committee’s primary purpose is to assist the Board of Directors in fulfilling its oversight responsibilities by reviewing the financial information provided to shareholders and others, and the systems of internal controls which management has established to preserve our assets and the audit process. It is not the Audit Committee’s duty or responsibility to conduct auditing or accounting reviews or procedures or to determine that our financial statements are complete and accurate and in accordance with generally accepted accounting principles in Canada. In giving its recommendation to the Board of Directors, the Audit Committee has relied on management’s representations that the financial statements have been prepared with integrity and objectivity and in conformity with generally accepted accounting principles in Canada and on the opinion of the independent registered chartered accountants included in their report on our financial statements.

Other Directorships

Messrs. Howard R. Balloch, Peter G. Meredith and Robert M. Friedland are all directors of Ivanhoe Mines Ltd. Mr. Balloch is also a director of Methanex Corporation and Tiens Biotech Group USA Inc. Messrs. Friedland and Meredith are both directors of Ivanhoe Australia Limited. Mr. Meredith is also a director of Entrée Gold Inc., SouthGobi Energy Resources Ltd. and Great Canadian Gaming Corporation.

Code of Business Conduct and Ethics

We have a Code of Business Conduct and Ethics applicable to all employees, consultants, officers and directors regardless of their position in our organization, at all times and everywhere we do business. The Code of Business Conduct and Ethics provides that our employees, consultants, officers and directors will uphold our commitment to a culture of honesty, integrity and accountability and that we require the highest standards of professional and ethical conduct from our employees, consultants, officers and directors. A copy of our Code of Business Conduct and Ethics, as amended, may be obtained, without charge, by request to Ivanhoe Energy Inc., Suite 654-999 Canada Place, Vancouver, British Columbia, Canada V6C 3E1, Attention: Corporate Secretary or by phone to 604-688-8323.

ITEM 11. EXECUTIVE COMPENSATION

In accordance with the requirements of applicable securities legislation in Canada, the following executive compensation disclosure is provided in respect of each person who served as the Company’s Chief Executive Officer or Chief Financial Officer during the 2008 fiscal year, and each of the Company’s three most highly compensated executive officers whose annual aggregate compensation for the 2008 fiscal year exceeded Cdn.$150,000 (collectively, the “Named Executive Officers”).

Compensation Discussion and Analysis

Compensation and Benefits Committee, Philosophy and Goals

The Company’s executive compensation program is administered by the Compensation and Benefits Committee (the “Compensation Committee”). The members of the Compensation Committee are all independent, non-management directors. Following review and approval by the Compensation Committee, decisions relating to executive compensation are reported to, and approved by, the full Board of Directors.

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

•

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

•

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

•

to enable us to attract, retain and motivate executive officers of the highest caliber in light of the strong competition in the Company’s industry for qualified personnel;

•

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

•

to provide fair, transparent, and defensible compensation

In applying these principles during a transitional period of the Company’s development and while the Company has been undergoing a management restructuring which included a change in the office of President and Chief Executive Officer, the Compensation Committee, and the Board, have sought to maintain a significant degree of flexibility and subjectivity in making compensation decisions.

Recent Developments Relating to Executive Compensation

In 2007, the Company adopted a compensation program based on a series of quantitative and qualitative compensation parameters for the Company’s executive officers and the Company’s non-executive management personnel. This program was based on a report prepared by an external consultant in 2005 and an internal review of the Company’s compensation policies and practices. The compensation program was designed to provide incentives to work for, and stay with, the Company, to drive strong Company performance, and to differentially reward skills more critical to the Company’s business plans. Under this compensation program, the Company has sought to pay near term compensation, using a pay grade system consistent with industry practice, which is competitive with industry while providing incentive compensation that is designed to outperform other options that employees and prospective employees might find in the marketplace.

As part of a management restructuring in May 2008, Joseph Gasca left the Company and Robert Friedland was appointed Executive Co-Chairman, President and Chief Executive Officer of the Company. Mr. Friedland does not accept a salary from the Company for acting in these capacities.

In making compensation decisions during, and in respect, of the 2008 fiscal year, the Compensation Committee applied aspects of the existing 2007 compensation plan for purposes of establishing base salary. Incentive bonuses in respect of the 2007 fiscal year were awarded during 2008 based largely on the compensation plan with certain discretionary variations; however long-term compensation arrangements as originally contemplated by the 2007 plan were not implemented in light of recent global market conditions. Special bonuses were awarded to certain executives during 2008 in connection with the successful completion of the Company’s transaction with Talisman Energy Canada, which bonuses were to be considered part of such executive’s overall 2008 bonus, to the extent further bonuses were awarded in respect of the 2008 fiscal year. In light of the management reorganization and the substantial market turbulence, no specific update of the compensation program has been considered for 2008 and the Compensation Committee determined to defer all further short-term bonus awards in respect of the 2008 fiscal year.

The Company hired a new Vice President, Human Resources in October 2008 and the Company is in the process of undertaking a review of its compensation practices with a view to developing a more structured compensation plan with updated benchmarking to a comparator group and appropriate compensation and incentive mechanisms for its executives given the Company’s stage of development and market conditions.

How We Make Compensation Decisions

The Compensation Committee oversees and sets the general guidelines and principles for the implementation of the Company’s executive compensation policies, assesses the individual performance of the Company’s executive officers and makes recommendations to the Board of Directors. Based on these recommendations, the Board of Directors makes decisions concerning the nature and scope of the compensation to be paid to the Company’s executive officers. The Compensation Committee bases its recommendations to the Board on its compensation philosophy and on individual and corporate performance. The Compensation Committee may seek compensation advice where appropriate from consultants, although the Compensation Committee did not engage outside consultants for 2008.

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

Decisions for base salary adjustments are usually put into effect on June 1 of each year. Targets for performance bonuses for the next fiscal year are usually set prior to the beginning of the next fiscal year, and decisions on actual bonuses, are made at some point during the six month period following the end of the fiscal year. Incentive awards may be made at any time during the year, but are ordinarily made during the first six months following the end of the fiscal year. In the ordinary course, management presents its compensation recommendations for consideration by the Compensation Committee.

Elements of Total Compensation

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

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

•

Base salary — paid in cash as a fixed amount of compensation for performing day-to-day responsibilities.

•

Performance Bonus — Annual bonus awards, paid in common shares or cash, or both, earned for achieving strategic corporate, business unit or individual goals.

•

Incentive Awards — Equity incentives, in the form of stock options granted to align compensation with achievement of the Company’s goals, creation of shareholder value, and retention of executives over a longer period.

In making compensation decisions in respect of these elements, the Compensation Committee considers both the cumulative compensation being granted to executives as well as internal comparisons amongst the Company’s executives.

Peer Comparator Group

The original salary ranges for the Company were established in 2005 with reference to a number of Canadian and United States based oil and gas companies with international operations and similar market capitalizations; North America based energy focused technology companies with somewhat comparable market capitalizations, and United States based junior oil and gas companies. This comparator group has not been recently updated and is now not directly relevant to current compensation, although it formed an initial basis from which variations to salaries have been made to reflect market conditions, retention requirements and recruitment needs. The Company also considers current comparable information on a less formalized basis. The Company expects that the establishment of a formalized and updated peer comparator group will form part of a new compensation policy currently under development.

100

Base Salary

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

Under the Company’s compensation program, salary levels are assessed using a pay grade system that is consistent with industry practice. Each of the Company’s employees, including the Company’s executive officers, is placed in a pay grade based upon his or her knowledge, skills and relevant experience and credentials. Annual salary increases are made based on performance and relative position within a pay grade. Performance will be assessed and rated based on agreed objectives and behaviors. A simple three-tiered rating system is used for salaries, with top performers rewarded the highest, regular performers rewarded consistent with average industry trends and bottom performers receiving little or no salary increases. The Compensation Committee also considers retention risks, succession requirements and compensation changes in the market in determining salaries.

Annual Bonus

The intent of the Company’s annual bonus program is to provide competitive near-term compensation. The Company uses the same pay grade system used for base salary for determining the target and maximum bonus that is achievable by an employee.

Bonus award levels for executive officers and senior non-executive management personnel are based on a targeted percentage of base salary and are determined based on job specific criteria in addition to overall performance rating. Performance is assessed relative to new project development and the achievement of business plan and technology development goals, as well as other goals in respect of production targets, investor and corporate communications, staffing and business development. An individual executive’s bonus is assessed by allocating a lesser or greater percentage of the executive’s target bonus to business targets within his or her sphere of influence.

The composition of annual bonus awards is usually a combination of the Company’s common shares and cash. In order to preserve cash, bonus awards consist predominantly of common shares with a significantly smaller cash component to facilitate the recipient’s ability to pay applicable income taxes.

Under the existing compensation program, for executive officers, potential bonus amounts were expected to range from 40% of salary (target) and 60% of salary (maximum) for the Company’s Chief Financial Officer and 25%-30% of salary (target) and 37.5%-45% of salary (maximum) for other executive officers. 75% of the targeted bonus amount is earned through the achievement of measurable defined corporate objectives, including share price, net income, net operating cash flow and net production, as well as other specific corporate and individual goals, and 25% of the targeted bonus is based on discretionary factors. While Joe Gasca was in office as the President and Chief Executive Officer, potential bonus amounts for that position were expected to range from 50% of salary (target) and 70% of salary (maximum).

Incentive Compensation

The relationship of corporate performance to executive compensation under the Company’s executive compensation program is created, in part, through equity compensation mechanisms. Incentive stock options, which vest and become exercisable through the passage of time, link the bulk of the Company’s equity-based executive compensation to shareholder return, measured by increases in the market price of the Company’s common shares. All outstanding stock options that have been granted under the Company’s Equity Incentive Plan were granted at prices not less than 100% of the fair market value of the Company’s common shares on the dates such options were granted.

The Company continues to believe that stock-based incentives encourage and reward effective management that results in long-term corporate financial success, as measured by stock appreciation. Stock-based incentives awarded to the Company’s executive officers have been traditionally based upon the Compensation Committee’s subjective evaluation of each executive officer’s ability to influence the Company’s long-term growth and to reward outstanding individual performance and contributions to the Company’s business. Other factors influencing the Company’s recommendations respecting the nature and scope of the equity compensation and equity incentives to be awarded to the Company’s executive officers in a given year have included: awards made in previous years and, particularly in the case of equity incentives, the number of incentive stock options that remain outstanding and exercisable from grants in previous years and the exercise price and the remaining exercise term of those outstanding stock options.

101

The intent of the Company’s incentive compensation under the compensation program has been to provide retention incentives to employees and prospective employees that are superior to incentive compensation offered by our competition. Under the program, the Company has used the same pay grade system for outlining the target and maximum incentive compensation that is achievable for an executive or employee. For executives and higher pay grade employees, annual incentive compensation awards will be provided based on specific performance criteria, value to the Company in terms of skills, knowledge and experience, completion of specific projects as well as subjective criteria. Incentive compensation awards for executives and upper pay grade employees are expected to include stock options and may in the future include other securities such as restricted shares.

Option exercise periods and vesting schedules for options granted to executive officers are determined, on a case by case basis, by the Compensation Committee and the Board. Although the Company has traditionally taken an approach to vesting that is based on the passage of time, the Company has, in appropriate circumstances, granted options with vesting schedules based on the achievement of specified corporate objectives.

2008 Executive Compensation Decisions

Salary Compensation

The base salary of the Company’s former Chief Executive Officer, Joseph Gasca, was originally set by the terms of his employment contract, which are described under “Termination and Change of Control Benefits” and was based on competitive market factors, level of experience and scope of responsibility. As part of the management restructuring arrangements in 2008, Robert Friedland assumed the position of Executive Co-Chairman, President and Chief Executive Officer in May, 2008. Mr. Friedland has voluntarily waived a cash salary from the Company. Certain salary adjustments were made as of June 1, 2008 for the Company’s other named Executive Officers. Mr. Lancaster’s base salary was increased from Cdn$262,330 to Cdn$288,563 (US$247,272 to US$271,999 based on the August 15, 2008 US Federal Reserve noon conversion rate of 0.9426); Mr. Silverman’s base salary was increased from US$247,000 to US$272,250; Mr. Veith’s base salary was increased from US$220,000 to US$253,000; and, Mr. Chua’s base salary was increased from US$180,000 to US$198,000.

Bonus Compensation

In July 2008, the Compensation Committee recommended payment of individual bonuses for the 2007 fiscal year to certain of its executive officers, following a review and comparison of the defined performance targets against actual results. These bonuses included a cash portion, and the issuance of common shares at a fair market value of US$2.26 on the grant date.

Mr. Gasca received a bonus of U.S.$78,509, of which U.S.$28,468 was paid in cash and the balance of U.S.$50,041 was satisfied by the issue of 22,142 common shares. Mr. Lancaster received a bonus of U.S.$52,461, of which U.S.$22,496 was paid in cash and the balance of U.S.$29,965 was satisfied by the issue of 13,259 common shares. Mr. Silverman received a bonus of U.S.$53,831, of which U.S.$23,866 was paid in cash and the balance of $29,965 was satisfied by the issue of 13,259 common shares. Mr. Veith received a bonus of U.S.$53,831, of which U.S.$23,866 was paid in cash and the balance of U.S.$29,965 was satisfied by the issue of 13,259 common shares. Mr. Chua received a bonus of U.S.$41,169, of which U.S.$22,969 was paid in cash and the balance of U.S.$18,200 was satisfied by the issue of 8,053 common shares.

The chart on page 106 of this Form 10-K sets forth the targeted and maximum bonuses for the NEOs for these 2007 awards, the corporate goals or goal categories for which bonuses were established, the percentage bonus allocations to each NEO related to such corporate goal or goal categories, the resulting percentage achievement for each such category of goals or goal categories, resulting in a notional bonus goal for such NEOs. In the case of Mr. Gasca, the bonus was awarded as provided for in his termination agreement. In the case of Mr. Lancaster, Mr. Silverman and Mr. Veith, in light of the management restructuring then ongoing, and for internal adjustments, the bonuses of these executives and one other officer were averaged. In the case of Mr. Chua, the bonus was adjusted upwards in light of discretionary performance factors and for retention purposes.

In recognition of the concerted efforts of Messrs. Lancaster, Silverman and Veith with respect to the negotiation and conclusion of the transaction with Talisman Energy Canada, Mr. Lancaster received a bonus of Cdn$50,000 (US$47,130 based on an August 15, 2008 conversion rate of the US Federal Reserve of 0.9426) and each of Messrs Silverman and Veith received a bonus of US$50,000, which bonuses were to be taken into account when the Company finalized its bonus awards, if any, following the 2008 year end. However, having regard to the management reorganization and the substantial market turbulence in equity and credit markets, the Compensation Committee determined to defer consideration of any further short-term bonus awards in respect of the 2008 fiscal year until the return of market stability and in light of the relatively limited cash position of the Company. Bonus targets that will apply for 2009 are expected to be determined by July, 2009 as part of the ongoing compensation review process, consideration of the Company’s cash resources and further internal restructuring of the Company.

102

Incentive Compensation

As part of a management restructuring, in May, 2008, Robert Friedland was appointed Executive Co-Chairman, President and Chief Executive Officer of the Company. In connection with his appointment, and as incentive compensation in respect of the efforts Mr. Friedland is making on behalf of the Company in that capacity, Mr. Friedland was granted stock options to purchase 2,500,000 Common Shares exercisable for a term of five years.

In respect of the 2008 year, awards of stock options to certain executive officers were made on a subjective discretionary basis, taking into account performance and internal comparisons of executive officer’s stock option positions, and for retention considerations. In March 2008 Mr. Lancaster was issued options to purchase 50,000 common shares at Cdn $1.68, and Mr. Chua was issued options to purchase 60,000 common shares at US $1.70. Each of such options has a term of five years and vested as to 20% on March 11, 2008, with 20% to vest on each of the four anniversaries thereafter until fully vested.

Other Compensation

The Company does not provide its executive officers with a pension plan and the share purchase plan of the Company has not been activated. In 2008, the Company paid Mr. Gasca US$20,400, Mr. Veith US$19,958 and Mr. Silverman US$20,496, in each case for the purpose of contributing to the 401(k) retirement plan of the recipient. In 2008 the Company paid life insurance premiums and long term disability premiums on behalf of each Named Executive Officer except for Mr. Friedland. The aggregate “other compensation” received by each Named Executive Officer is disclosed in the Summary Compensation Table.

103

2007 INCENTIVE BONUS CHART
AWARDED IN JULY 2008


				Gasca – CEO						Lancaster – CFO						Silverman – CTO						Veith – EVP⁽¹⁾						Chua – EVP
				Bonus Target: 50%⁽²⁾						Bonus Target: 40%⁽²⁾						Bonus Target: 40%⁽²⁾						Bonus Target: 35%⁽²⁾						Bonus Target: 30%⁽²⁾
				Bonus Maximum: 70%						Bonus Maximum: 60%						Bonus Maximum: 60%						Bonus Maximum: 52.5%						Bonus Maximum: 45%
	Achievement			% Total						% Total						% Total						% Total						% Total
Company Goals that are	of Company			Bonus			% Base			Bonus			% Base			Bonus			% Base			Bonus			% Base			Bonus			% Base
linked to Executive Bonus	Goals in			Attributed to			Salary			Attributed to			Salary			Attributed to			Salary			Attributed to			Salary			Attributed to			Salary
Compensation⁽⁶⁾	2007⁽³⁾			Goal⁽⁴⁾			Earned⁽⁵⁾			Goal⁽⁴⁾			Earned			Goal⁽⁴⁾			Earned			Goal⁽⁴⁾			Earned			Goal⁽⁴⁾			Earned
Performance Rating		100	%		N/A			N/A			20	%		8	%		25	%		10	%		25	%		9	%		30	%		9	%
Share Price/Market Cap Target		0	%		10	%		0	%		10	%		0	%		10	%		0	%		10	%		0	%		10	%		0	%
Investor/Corp Communications		85	%		15	%		6	%		5	%		2	%		5	%		2	%		5	%		1	%		0	%		0	%
Governance/Corporate Reporting		100	%		15	%		8	%		25	%		10	%		5	%		2	%		5	%		2	%		10	%		3	%
Human Resource Mgmt.		40	%		10	%		2	%		10	%		2	%		10	%		2	%		10	%		1	%		5	%		1	%
Financial Mgmt (incl. raising capital)		100	%		10	%		5	%		15	%		6	%		0	%		0	%		0	%		0	%					0	%
Net Income Target		0	%		5	%		0	%		5	%		0	%		5	%		0	%		5	%		0	%		5	%		0	%
Net Operating Cash Flow Target		0	%		5	%		0	%		0	%		0	%		5	%		0	%		5	%		0	%		5	%		0	%
Capex Management Target		100	%		5	%		3	%		5	%		2	%		5	%		2	%		5	%		2	%		5	%		2	%
Safety, Health and Environmental Targets		100	%		5	%		3	%		0	%		0	%		5	%		2	%		5	%		2	%		5	%		2	%
Net Production Target		0	%		0	%		0	%		0	%		0	%		0	%		0	%		0	%		0	%		10	%		0	%
Opex/Bbl Target		0	%		0	%		0	%		5	%		0	%		0	%		0	%		0	%		0	%		5	%		0	%
Business Development Target		15	%		10	%		1	%		0	%		0	%		5	%		0	%		15	%		1	%		10	%		0	%
Technology Targets		70	%		10	%		4	%		0	%		0	%		20	%		6	%		10	%		2	%		0	%		0	%
Individual Percentage Attained								30.13	%					29.30	%					25.20	%					20.13	%					16.05	%

Current Salary				US $315,500.00						Cdn $262,330.00						US $247,500.00						US $220,000.00						US $180,000.00

Notional Bonus Allocation				US $94,893.75						Cdn $78,862.69						US $62,370.00						US $44,275.00						US $28,890.00

Total Amount of Bonus Awarded⁽⁷⁾				US$78,509						US$52,461						US$53,831						US$53,381						US$41,169

104

NOTES:


1.		Represents Bonus Target and Bonus Maximum for a partial year.

2.		Bonus Target and Bonus Maximum represent the potential range of a bonus that may be awarded as a percentage of an executive’s base salary. The Bonus Target and Bonus Maximum are determined by the executive’s pay grade, and whether or not the executive was employed by the Company for the full financial year. For the financial year 2007, executive bonuses were calculated at the Bonus Target percentage.

3.		The Company’s Compensation Committee evaluated whether or not the Company achieved the goals that were linked to executive compensation in 2007, and reported the percentage achievement of each goal. This percentage achievement is used to determine the Bonus Compensation received by executives.

4.		Each executive’s bonus is linked to a distinct subset of the Company’s goals based on the executive’s duties and responsibilities. The percentage of an executive’s bonus that is linked to each of the Company’s goals is set out in this column.

5.		The percent of the base salary earned is calculated by multiplying the percentage of achievement of a Company goal by the percent of the executive’s bonus attributed to such Company goal, and then multiplying the resulting product by the percentage Bonus Target of the executive.

6.		The Company’s goals used to evaluate executive performance and calculate executive bonuses for 2007 are as follows:

Performance Rating: Determined by the Compensation Committee based on internal assessment of executives and specific achievement of an executive’s individual performance goals for 2007.

Share Price/Market Cap Target: Target Bonus share price in 2007 was US$4, Bonus Maximum share price was US $7.

Investor/Corp Communications: Achievement of certain objectives including improvement of communications with investors, including assessment of investor opinion and production of investor communications media.

Governance/Corporate Reporting: Achievement of certain objectives including continued improvement of corporate governance procedures, compliance with laws, completion of internal and external auditing.

Human Resource Mgmt.: Achievement of certain objectives including continued recruitment of excellent talent, ensuring efficient and fulsome training, monitoring and improving internal performance evaluations.

Financial Mgmt (incl. raising capital): Target Bonus influx of cash beyond core operations was US $20 million, Bonus Maximum influx of cash beyond core operations was US $50 million.

Net Income Target: Target Bonus net income was US $20 million. No Bonus Maximum determined for net income in 2007.

Net Operating Cash Flow Target: Target Bonus net operating cash flow target was US $0, Bonus Maximum net operating cash flow target was US $4 million.

Capex Management Target: Target Bonus capex management target was US $32 million, Bonus Maximum capex management target was US $30 million.

Safety, Health and Environmental Targets: Achievement of standards and development of policy.

Net Production Target: Target Bonus net production target, excluding China, was 532,800 BOE, Maximum Bonus net production target, excluding China, was 600,000 BOE.

Opex/Bbl Target: Target Bonus Opex/Bbl was US $20/boe, Maximum Bonus Opex/Bbl was US $17.50/boe.

Business Development Target: Achievement of certain objectives including completion of transactions, progression of projects and development of new opportunities.

Technology Targets: Achievement of certain objectives including implementation of intellectual property policy, completion of mechanical and construction goals at properties.


7.		Based on discretionary factors, the actual bonuses awarded varied somewhat from notional bonuses determined in accordance with the foregoing chart.

105

Performance Graph

The following graph and table compares the cumulative shareholder return on a Cdn.$100 investment in our common shares to a similar investment in companies comprising the S&P/TSX Composite Index, including dividend reinvestment, for the period from December 31, 2003 to December 31, 2008.


	As at December 31,
	(Cdn.$)
	2003		2004		2005		2006		2007		2008

Ivanhoe Energy Inc.	$	100	$	63	$	25	$	32	$	32	$	12
S&P/TSX Composite Index	$	100	$	114	$	142	$	167	$	183	$	123

The information provided in this Performance Graph shall not be deemed “soliciting material” or “filed” with the Securities and Exchange Commission or subject to Regulation 14A or 14C under the Securities Exchange Act of 1934 (“Exchange Act”), other than as provided in Item 201 to Regulation S-K under the Exchange Act, or subject to the liabilities of Section 18 of the Exchange Act and shall not be deemed incorporated by reference into any filing under the Securities Act of 1933 or the Exchange Act except to the extent the Company specifically requests that it be treated as soliciting material or specifically incorporates it by reference.

The trend in overall compensation paid to the Company’s executive officers over the past five years has not tracked the performance of the market price of the Company’s common shares, or the S&P/TSX Composite Index, particularly since 2007. Market price targets of the Company’s common shares have, however, been included as a component of the Company’s annual bonus incentives.

Option-Based Awards

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

In 2008 the Company issued option-based awards under its Equity Incentive Plan to executive officers as described under the heading “2008 Executive Compensation Decisions”. The Company also issued four option-based awards outside of the Equity Incentive Plan to four employees, none of whom are executive officers of the Company. One of the four option-based awards has been terminated. The ratification by shareholders of two of the option grants is required by the TSX prior to the exercise of any of the options and will be put to Shareholders at the Meeting. Please see “Particulars of Matters to Be Acted Upon – Ratification of Stock Option Grants” for more information.

106

Summary Compensation Table

Summary Compensation Table (U.S.$)


								Non-equity incentive plan
								compensation ($)
								Annual			Long-term
				Share-based		Option-based		incentive			incentive		Pension		All other			Total
Name and principal position	Salary ($)			awards ($)⁽⁷⁾		awards ($)⁽⁵⁾		plans			plans⁽²⁾		value ($)		compensation ($)			compensation ($)

Friedland, Robert Executive Co-Chairman, President & CEO		—			—		1,950,236		—			—		—		—			1,950,236	⁽¹⁾

Gasca, Joseph President & CEO		131,250	⁽⁸⁾		50,041		—		28,468			—		—		340,827	⁽³⁾		550,586

Lancaster, Gordon CFO		259,552	⁽⁴⁾		29,965		50,550		69,626	^{(4) (11)}		—		—		1,972	⁽⁴⁾		411,665

Silverman, Michael Executive Vice President		261,938			29,965		—		73,866	⁽¹¹⁾		—		—		32,945	⁽⁶⁾		398,714

Veith, Edwin Executive Vice President		239,250			29,965		—		73,866	⁽¹¹⁾		—		—		39,549	⁽⁹⁾		382,630

Chua, Patrick Executive Vice President		228,600			18,200		60,660		22,969			—		—		3,801	⁽¹⁰⁾		334,230

NOTES:


(1)		Mr. Friedland is also a director of the Company. Pursuant to the Company’s policies regarding management directors, Mr. Friedland does not receive compensation from the Company for acting as a director, and no portion of the Total Compensation disclosed in the summary compensation table was received by Mr. Friedland as compensation for acting as a director.

(2)		The Company does not presently have a long-term incentive plan for any of its executive officers, including its Named Executive Officers.

(3)		Includes: $131,250 payable in 2009 to Mr. Gasca pursuant to the terms of his termination agreement; $20,400 paid as a contribution to Mr. Gasca’s 401(k) retirement plan; $184,100 paid to Mr. Gasca in 2008 pursuant to the terms of his termination agreement; and, $5,077 paid for life insurance and long term disability premiums. For further information, please see: Termination and Change of Control Benefits.

(4)		Amounts were paid to Mr. Lancaster in Canadian currency. Salary has been converted to US currency based on the noon buying price for Canadian currency of the Federal Reserve Bank of New York on the date of each pay period during 2008. Annual Incentive Plan amounts were converted at the US Federal Reserve noon rate on August 15, 2008: 0.9426.

(5)		The Company used the Black-Scholes option-pricing model for determining the fair value of stock options issued at the grant date. The practice of the Company is to grant all option based awards in Canadian currency, then convert the grant date fair value amount to U.S. currency for reporting the value of the grants in the Company’s financial statements. The conversion rate is the noon buying price for Canadian currency of the Federal Reserve Bank of New York on the date the grant is made which was 0.9897 for the options granted to Mr. Friedland, and 0.9871 for the options granted to each of Messrs. Lancaster and Chua.

(6)		Includes: $20,496 paid as a contribution to Mr. Silverman’s 401(k) retirement plan; and, $12,449 paid for life insurance and long term disability premiums.

(7)		The grant date fair value is determined by the closing trading price of the Company’s common shares on the day the Company delivered a treasury order for the share based award to the Company’s transfer agent. The share based awards granted to the Named Executive Officers and listed in the Summary Compensation Table were based on the closing price of the Company’s common shares on August 5, 2008. The grant date fair value was US$2.26.

(8)		Includes compensation paid until Mr. Gasca’s employment ended in May 2008.

(9)		Includes: $19,958 paid as a contribution to Mr. Veith’s 401(k) retirement plan; and, $19,591 paid for life insurance and long term disability premiums.

(10)		Includes $3,801 paid for life insurance and long term disability premiums.

(11)		Includes US$50,000 for each of Messrs. Silverman and Veith, and Cdn$50,000 for Mr. Lancaster (converted to US$47,130 at the US Federal Reserve noon rate on August 15, 2008: 0.9426), that was paid on August 15, 2008, as an advance on bonuses payable for the year ending 2008, which are normally determined and paid in mid-2009.

107

Incentive Plan Awards

Outstanding share-based awards and option-based awards

Option-based Awards

Share-based Awards

Market or

Number of

payout value

securities

Value of

Number of

of share-based

underlying

unexercised in-

shares or units

awards that

unexercised

Option

the-money

of shares that

have not

options

exercise price

Option

options

have not vested

vested

Name

(#)

($)

expiration date

(US$)⁽¹⁾

(#)

(US$)

Friedland, Robert
Executive Co-Chairman,
President & CEO

2,500,000

⁽²⁾

Cdn$

1.61

March 5, 2013

Gasca, Joseph
President & CEO

—

Lancaster, Gordon
CFO

50,000

⁽³⁾

Cdn$

1.68

March 11, 2013

Silverman, Michael

270,000

⁽⁴⁾

US$

1.92

Oct. 4, 2012

Executive Vice President

150,000

⁽⁵⁾

US$

1.92

Sept. 19, 2012

80,000

⁽⁶⁾

US$

2.06

May 28, 2012

Veith, Edwin

158,000

⁽⁴⁾

US$

1.92

Oct. 4, 2012

Executive Vice President

250,000

⁽⁷⁾

US$

2.70

June 2, 2011

70,734

⁽⁸⁾

US$

2.57

April 18, 2011

22,000

⁽⁹⁾

US$

3.06

March 8, 2011

Chua, Patrick

60,000

⁽³⁾

US$

1.70

March 11, 2013

Executive Vice President

40,000

⁽⁶⁾

US$

2.06

May 3, 2012

NOTES:


(1)		The “Value of unexercised in-the-money options” is calculated on the basis of the difference between the closing price of the common shares on the TSX on December 31, 2008 and the Exercise Price of the options.

(2)		This option grant vests 20% on March 5, 2008, and 20% on each of the four anniversaries thereafter, and will be fully vested on March 3, 2012.

(3)		This option grant vests 20% on March 11, 2008, and 20% on each of the four anniversaries thereafter, and will be fully vested on March 11, 2012.

(4)		This option grant vested 20% on October 4, 2007, and will continue to vest over the four years following October 4, 2007, upon the achievement of performance milestones.

(5)		This option grant vests 20% on September 19, 2007, and 20% on each of the four anniversaries thereafter, and will be fully vested on September 19, 2011.

(6)		This option grant vests 25% on May 3, 2008, and 25% on each of the three anniversaries thereafter, and will be fully vested on May 3, 2011.

(7)		This option grant vests 20% on June 2, 2006, and 20% on each of the four anniversaries thereafter, and will be fully vested on June 2, 2010.

(8)		This option grant vests 20% on April 18, 2006, and 20% on each of the four anniversaries thereafter, and will be fully vested on April 18, 2010.

(9)		This option grant vests 20% on March 8, 2006, and 20% on each of the four anniversaries thereafter, and will be fully vested on March 8, 2010.

108

Incentive Plan Awards — value vested or earned during 2008


						Non-equity incentive plan
	Option-based awards — Value			Share-based awards — Value		compensation — Value earned
	vested during the year			vested during the year		during the year
Name	(U.S.$)⁽³⁾			(U.S.$)		(U.S.$)
Friedland, Robert Executive Co-Chairman, President & CEO	Nil.				—		—
Gasca, Joseph President & CEO	Nil.				50,041		28,468
Lancaster, Gordon CFO	$	1,792	⁽²⁾		29,965		69,626	⁽⁴⁾⁽¹⁾
Silverman, Michael Executive Vice President	Nil.				29,965		73,866	⁽⁴⁾
Veith, Edwin Executive Vice President	$	646			29,965		73,866	⁽⁴⁾
Chua, Patrick Executive Vice President	$	3,080			18,200		22,969

NOTES:


(1)		Amounts were paid to Mr. Lancaster in Canadian currency and have been converted to US currency based on the noon buying price for Canadian currency of the Federal Reserve Bank of New York on the date the award was paid.

(2)		The value vested during the year of options held by Mr. Lancaster was converted from Canadian currency to US currency based on the noon buying rate of 0.9953 on March 11, 2008, the date Mr. Lancaster’s in the money options vested.

(3)		A Nil amount indicates that no options held by the Named Executive Officer vested during 2008 at an in the money amount when the exercise price was compared to the closing price of the Company’s common shares on the TSX on the date of vesting.

(4)		Includes US$50,000 for each of Messrs. Silverman and Veith, and Cdn$50,000 for Mr. Lancaster (converted to US currency at the US Federal Reserve rate on August 15, 2008: 0.9426), that was paid in 2008 as an advance on bonuses for 2008, which are normally determined and paid in mid-2009.

109

Pension Plan Benefits

The Company does not have any pension, retirement or deferred compensation plans, including defined contribution plans.

Termination and Change of Control Benefits

The Company has written contracts of employment with Messrs. Silverman, Lancaster and Veith, and had a written contract of employment with Mr. Gasca during his term of employment as Chief Executive Officer of the Company.

Mr. Gasca’s employment contract was terminated by agreement, effective May 15, 2008. The Company will continue to pay Mr. Gasca his base salary (US$310,000) under his employment contract during the twelve (12) month period from May, 2008 to April, 2009. The Company awarded Mr. Gasca an annual bonus for 2007 consistent with the awards made to other executive officers in accordance with the Company’s normal practice. This bonus is reported in the summary compensation table for Named Executive Officers. The Company accelerated the vesting of Mr. Gasca’s options such that 750,000 options were available for exercise on May 15, 2008. No options were exercised by Mr. Gasca, and all of Mr. Gasca’s options were terminated on November 15, 2008.

Mr. Silverman’s employment contract provides that: (a) in the case of termination for cause the Company must pay wages earned to the date of termination, vested options shall remain exercisable for one month after termination, and unvested options shall immediately terminate; (b) in the case of termination without cause or termination upon disability the Company must pay twelve (12) months wages in a lump sum, cause all of the unvested options that would vest in the succeeding twelve (12) months to vest immediately and remain exercisable for six months, and continue the medical, dental, life, disability and related insurance benefits for twelve (12) months; (c) in the case of termination of the employment agreement by the Company within twelve (12) months of a change of control the Company must pay twelve (12) months wages in a lump sum and cause all of the unvested options that would vest in the succeeding twelve (12) months to vest immediately and remain exercisable for six months; (d) in the case of voluntary resignation by Mr. Silverman the Company must pay wages to date and for an additional three month working notice period (during which time Mr. Silverman continues to work for the Company), and vested options shall remain exercisable for a period of three months following the last day of the notice period; (e) Mr. Silverman is bound by a non-competition clause effective until the later of 6 months after the termination of active employment or the date he no longer receives compensation of any kind under the employment contract; (f) Mr. Silverman is bound by a non-solicitation clause effective for twelve (12) months after the termination of active employment; and, (g) Mr. Silverman is bound by a confidentiality clause that is effective for three (3) years after the termination of active employment.

The following is an estimate of payments to Mr. Silverman in the above scenarios (a) — (d), based on his annual salary as at December 31, 2008, and the value of his options as at December 31, 2008: (a) no further wages, and no vested in the money options, for a total of $0; (b) a lump sum of US$272,250, no vested in the money options or in the money accelerated options, and benefits of US$12,449, for a total of US$284,699; (c) a lump sum of US$272,250, no vested in the money options or in the money accelerated options, and benefits of US$12,449, for a total of US$284,699; and, (d) wages for a three month working notice period of US$68,063, and no vested in the money options, for a total of US$68,063.

Mr. Lancaster’s employment contract provides that: (a) in the case of termination for cause the Company must pay wages earned to the date of termination; (b) in the case of termination without cause the Company must pay six (6) months wages in a lump sum and continue the medical, dental, life, disability and related insurance benefits for six (6) months; (c) in the case of voluntary resignation by Mr. Lancaster the Company must pay wages to date and for an additional two month working notice period (during which time Mr. Lancaster continues to work for the Company); (d) Mr. Lancaster is bound by a non-competition clause effective until the later of twelve (12) months after the termination of active employment or the date he no longer receives compensation of any kind under the employment contract; (e) Mr. Lancaster is bound by a non-solicitation clause effective until the later of twelve (12) months after the termination of active employment or the date he no longer receives compensation of any kind under the employment contract; and, (f) Mr. Lancaster is bound by a confidentiality obligation that is effective for five (5) years after the termination of active employment.

The following is an estimate of payments to Mr. Lancaster in the above scenarios (a) — (c), based on his annual salary as at December 31, 2008, and the value of his options as at December 31, 2008: (a) no further wages, for a total of US$0; (b) a lump sum of US$136,202 and benefits of US$986; and, (c) a lump sum of US$45,401 and benefits of US$329, for a total of US$45,730.

Mr. Veith’s employment contract does not include terms with respect to termination, resignation, retirement, change of control, non-competition, non-solicitation and confidentiality.

110

Director Compensation

Director Compensation Table
(U.S.$)


								Non-equity
				Share-based		Option-based		incentive plan		Pension		All other
	Fees Earned			awards		awards		compensation		value		compensation		Total
Name	(US$)			(US $)		(US $)		(US $)		(US $)		(US $)		(US $)
Abboud, A. Robert		92,500	⁽¹⁾		0		66,725		0		0		0		159,225
Balloch, Howard		53,000			0		66,725		0		0		0		119,725
Downey, Brian		49,500			0		66,725		0		0		0		116,225
Graham, Robert	Nil		⁽²⁾		0		66,725		0		0		0		66,725
Meredith, Peter		39,000			0		167,824		0		0		0		206,824
Pirraglia, Robert		42,500			0		66,725		0		0		0		109,225

NOTES:


(1)		Mr. Abboud was paid an all-inclusive annual fee of US$250,000 which provided for and included director fees, Lead director fees and meeting fees customarily payable for the attendance of Board or Committee meetings up until May 29, 2008, after which time he earned the regular retainer of $24,000 per year plus individual meeting fees.

(2)		Mr. Graham did not receive any fees for acting as a director. A Company owned by Mr. Graham received fees for consulting services rendered to the Company during 2008. See Item 13 “Certain Relationships and Related Transactions, and Director Independence”.

Share-based awards, option-based awards and non-equity incentive plan compensation

Outstanding share-based awards and option-based awards

Option-based Awards

Share-based Awards

Market or

Number of

payout value

securities

Value of

Number of

of share-based

underlying

unexercised in-

shares or units

awards that

unexercised

Option

the-money

of shares that

have not

options

exercise price

Option

options

have not vested

vested

Name

(#)

($)

expiration date

(US$)

(#)

(US$)

Abboud, A. Robert

50,000

US$

2.69

May 29, 2013

480,000

US$

2.85

May 15, 2011

Balloch, Howard

50,000

Cdn$

2.66

May 29, 2013

50,000

Cdn$

2.30

May 3, 2012

50,000

Cdn$

3.12

May 4, 2011

50,000

Cdn$

3.01

May 5, 2010

Downey, Brian

50,000

US$

2.69

May 29, 2013

50,000

US$

2.06

May 3, 2012

50,000

US$

2.80

May 4, 2011

150,000

US$

2.32

July 22, 2010

111

Option-based Awards

Share-based Awards

Market or

Number of

payout value

securities

Value of

Number of

of share-based

underlying

unexercised in-

shares or units

awards that

unexercised

Option

the-money

of shares that

have not

options

exercise price

Option

options

have not vested

vested

Name

(#)

($)

expiration date

(US$)

(#)

(US$)

Graham, Robert

50,000

Cdn$

2.66

May 29, 2013

200,000

Cdn$

2.29

March 8, 2012

50,000

Cdn$

3.12

May 4, 2011

150,000

Cdn$

3.01

May 4, 2010

Meredith, Peter

50,000

Cdn$

2.66

May 29, 2013

100,000

Cdn$

1.68

March 11, 2013

150,000

Cdn$

1.52

Dec. 19, 2012

Pirraglia, Robert

50,000

US$

2.69

May 29, 2013

50,000

US$

2.06

May 3, 2012

50,000

US$

2.80

May 4, 2011

200,000

US$

2.42

May 5, 2010

Incentive Plan Awards — value vested or earned during 2008

Non-equity incentive plan

Option-based awards— Value

Share-based awards— Value

compensation— Value earned

vested during the year

during the year

Name

(US$)

Abboud, A. Robert

Nil.

Balloch, Howard

Nil.

Downey, Brian

US$5,800

Graham, Robert

Nil.

Meredith, Peter G.

Nil.

Pirraglia, Robert

Nil.

112


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

Except as set forth below, no person or group is known to beneficially own 5% or more of our issued and outstanding common shares. Based on information known to us, the following table sets forth the beneficial ownership of each such person or group in our common shares as at February 27, 2009.

Name and Address of

Number of Shares

Percentage

Title of Class

Beneficial Owner

Beneficially Owned (1)

of Class

Common Shares

Robert M. Friedland

52,411,725

(2)

18.44

150 Beach Road

#25-03 The Gateway West

Singapore 189720

Common Shares

Directors and Executive Officers as a Group (12 persons)

59,934,095

(3)

21.08

Common Shares

Caisse de depot et placement du Québec

17,022,822

6.09

Common Shares

TD Asset Management Inc.

14,700,801

5.27

(4)


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

(2)		50,994,620 common shares are held indirectly through Newstar Securities SRL, Premier Mines SRL and Evershine SRL, companies controlled by Mr. Friedland.

(3)		Includes 2,711,787 unissued common shares issuable to directors and senior officers upon exercise of incentive stock options.

(4)		Based on 279,381,187 shares of common stock outstanding as of February 27, 2009, TD Asset Management Inc.’s percentage of share ownership is 5.27%.

Security Ownership of Management

The following table sets forth the beneficial ownership as at February 27, 2009 of our common shares by each of our directors, our executive officers and by all of our directors and executive officers as a group:


		Amount
		and Nature
		of Beneficial		Percentage		Incentive Stock
		Ownership (1)		of Class		Options Included in
Title of Class	Name of Beneficial Owner	(a)		(b)		(a) (c)
Common Shares	A. Robert Abboud		748,000		.26		248,000
Common Shares	Robert M. Friedland (2)		52,411,725		18.44		1,000,000
Common Shares	Howard R. Balloch		170,000		.06		120,000
Common Shares	Robert G. Graham		4,855,112		1.71		310,000
Common Shares	Robert A. Pirraglia		473,396		.17		240,000
Common Shares	Brian F. Downey		250,000		.09		150,000
Common Shares	Peter G. Meredith		148,000		.05		100,000
Common Shares	W. Gordon Lancaster		84,710		.03		20,000
Common Shares	Michael A. Silverman		147,259		.05		134,000
Common Shares	Edwin J. Veith		305,424		.11		255,787
Common Shares	Patrick Chua		128,318		.04		34,000
Common Shares	Gerald Moench		212,151		.07		100,000

Common Shares	All directors and executive officers as a group (12 persons)		59,934,095		21.08		2,711,787


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

(2)		50,994,620 common shares are held indirectly through Newstar Securities SRL, Premier Mines SRL and Evershine SRL, companies controlled by Mr. Friedland.

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Securities Authorized for Issuance under Equity Compensation Plans

Other than four specific grants made in 2008, which are further described below, all of the incentive stock options and equity compensation awards the Company granted in 2008 were made under our Plan, the material terms of which are described in Item 11 “Executive Compensation”. The Plan is the only equity compensation plan the Company has in effect and is intended to further align the interests of the Company’s directors and management with the Company’s long-term performance and the long-term interests of the Company’s shareholders. The Company’s shareholders have approved the Plan and all amendments thereto. The following information is as at December 31, 2008:

Equity Compensation Plan Information


					Number of securities remaining
	Number of securities to be issued		Weighted-average exercise		available for future issuance under
	upon exercise of outstanding options,		price of outstanding options,		equity compensation plans (excluding
	warrants and rights		warrants and rights (Cdn.$)		securities reflected in column (a))
Plan category	(a)		(b)		(c)
Equity compensation plans approved by Security holders		11,628,303	$	2.33		5,369,834
Equity compensation plans not approved by Security holders (1)		285,000	$	2.13		—

Total		11,913,303	$	2.32		5,369,834


(1)		The following stock options were not granted under the Company’s Equity Incentive Plan previously approved by shareholders and the common shares reserved for issuance upon the exercise of the following stock options are not included in the total number of common shares reserved for issuance under the Equity Incentive Plan:

50,000 incentive stock options granted to Mr. Jim Pelham on April 17, 2008, as an inducement to accepting employment with the Company. Under the rules and policies of the TSX, stock options under security based compensation arrangements that do no exceed prescribed thresholds may be offered to prospective officers as an inducement to employment without shareholder approval.

50,000 stock options granted to Ms. Mariola Lepak on April 17, 2008; 35,000 stock options granted to Mr. Mark Savage on April 17, 2008; and, 150,000 stock options granted to Mr. Brian Wilson on April 28, 2008. The stock options issued to Ms. Mariola Lepak have been terminated. Under the rules and policies of the TSX, the grants to Messrs. Savage and Wilson require shareholder ratification prior to the exercise of any of the options.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Transactions with Management and Others

In 2003, we borrowed $1.25 million from Ivanhoe Capital Finance Ltd.; a company wholly owned by Mr. Robert M. Friedland our Executive Co-Chairman, President and Chief Executive Officer. The unsecured loan was repaid with accrued interest, at U.S. prime plus 3%, in September 2003. We negotiated a revolving credit facility of $1.25 million to re-establish or extend that loan in the future as needs arise.

Certain Business Relationships

We are party to cost sharing agreements with other companies wholly or partially owned by Mr. Robert M. Friedland. Through these agreements, we share office space, furnishings, equipment, air travel and communications facilities in Vancouver, Beijing and Singapore. We also share the costs of employing administrative and non-executive management personnel at these offices. For the year ended December 31, 2008, our share of costs for the Vancouver and Singapore offices was $851,099. Effective as of March 1, 2008, we agreed, as part of our cost sharing arrangements and in connection with Mr. Friedland’s appointment as President and Chief Executive Officer, to share the costs of operating an aircraft owned by a private company of which Mr. Friedland is the sole shareholder. For the year ended December 31, 2008, our share of these aircraft costs was $1.0 million.

During the year ended December 31, 2008, we paid $223,508 for technical services provided to us to a wholly owned subsidiary of Ensyn Corporation, an unaffiliated company that was spun off from Ensyn Group, Inc. as a result of our acquisition of Ensyn Group, Inc. on April 15, 2005. One of our directors, Dr. Robert Graham, held the positions of Chairman of the Board of Directors and Chief Executive Officer of Ensyn Corporation from July 2008 to present, Chairman of the Board of Directors of Ensyn Corporation from June 2007 to July 2008 and was Chief Executive Officer and President of Ensyn Corporation from April 2005 to June 2007. Mr. Graham owns an approximate 20% equity interest in Ensyn Corporation. In addition, the Company paid Dr. Graham’s private consulting company $101,224 for consulting services.

During the year ended December 31, 2008, a company controlled by Mr. Shun-ichi Shimizu, one of our former directors, received $708,847 for consulting services and out of pocket expenses.

A list of our directors is contained in Item 10 “Directors, Executive Officers and Corporate Governance.”

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ITEM 14. PRINCIPAL ACCOUNTANT’S FEES AND SERVICES

The following table summarizes the aggregate fees billed by Deloitte & Touche LLP:


	Year ended December 31,
	2008					2007
			% of fees					% of fees
			approved by					approved by
	Cdn.($000)		Audit Committee			Cdn.($000)		Audit Committee
Audit fees (a)	$	1,901		100	%	$	702		100	%
Tax fees (b)		98		100	%		80		100	%
All other fees (c)		15		100	%		—		—

	$	2,014				$	782


(a)		Fees for audit services billed in 2008 and 2007 consisted of:

	•		Audit of our annual financial statements

	•		Reviews of our quarterly financial statements

	•		Audit of our internal control over financial reporting in compliance with the requirements of the Sarbanes Oxley Act of 2002.

	•		Comfort letters, statutory and regulatory audits, consents and other services related to Canadian and U.S. securities regulatory matters

	•		Activities related to the audit of our Chinese subsidiary in contemplation of an initial public offering totaling Cdn.$970,000 in 2008


(b)		Fees for tax services billed in 2008 and 2007 consisted of tax compliance and tax planning and advice:

•

Fees for tax compliance services totaled Cdn.$87,000 and Cdn.$62,000 in 2008 and 2007, respectively. Tax compliance services are services rendered based upon facts already in existence or transactions that have already occurred to document, compute, and obtain government approval for amounts to be included in tax filings and consisted of:

	i.		Federal, state and local income tax return assistance

	ii.		Preparation of expatriate tax returns

	iii.		Assistance with tax return filings in certain foreign jurisdictions

•

Fees for tax planning and advice services totaled Cdn.$11,000 and Cdn.$18,000 in 2008 and 2007, respectively. Tax planning and advice are services rendered with respect to proposed transactions or that alter a transaction to obtain a particular tax result. Such services consisted of tax advice related to structuring certain proposed mergers, acquisitions and disposals.


(c)		“All other fees” includes fees for services billed in 2008 and 2007 other than the services reported as “Audit fees” or “Tax fees” and include such items as the CPAB billing, a subscription to an accounting research tool and human capital salary information.

In considering the nature of the services provided by Deloitte & Touche LLP, the Audit Committee determined that such services are compatible with the provision of independent audit services. The Audit Committee discussed these services with Deloitte & Touche LLP and our management to determine that they are permitted under the rules and regulations concerning auditor independence promulgated by the SEC to implement the Sarbanes-Oxley Act of 2002, as well as the American Institute of Certified Public Accountants.

Audit Committee Pre-Approval Policy

Before Deloitte & Touche LLP is engaged by us or our subsidiaries to render audit or non-audit services, the engagement is approved by our Audit Committee.

The Audit Committee has adopted a pre-approval policy for audit or non-audit service engagements. This policy describes the permitted audit, audit related, tax, and other services (collectively, the “Disclosure Categories”) that Deloitte & Touche LLP may perform. The policy requires that, prior to the beginning of each fiscal year, a description of the services (the “Service List”) expected to be performed by Deloitte & Touche LLP in each of the Disclosure Categories in the following fiscal year be presented to the Audit Committee for approval. Services provided by Deloitte & Touche LLP during the following year that are included in the Service List are pre-approved following the policies and procedures of the Audit Committee.

Any requests for audit, audit related, tax, and other services not contemplated on the Service List must be submitted to the Audit Committee for specific pre-approval and cannot commence until such approval has been granted. Normally, pre-approval is provided at regularly scheduled meetings. However, the authority to grant a specific pre-approval between meetings, as necessary, has been delegated to the Chairman of the Audit Committee. The Chairman must update the Audit Committee at the next regularly scheduled meeting of any services that were granted specific pre-approval.

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In addition, although not required by the rules and regulations of the SEC, the Audit Committee generally requests a range of fees associated with each proposed service on the Service List and any services that were not originally included on the Service List. Providing a range of fees for a service incorporates appropriate oversight and control of the independent auditor relationship, while permitting us to receive immediate assistance from the independent auditor when time is of the essence. On a quarterly basis, the Audit Committee reviews the status of services and fees incurred year-to-date against the original Service List and the forecast of remaining services and fees for the fiscal year.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

We refer you to the Financial Statements and Supplementary Data in Item 8 of this report where these documents are listed. The following exhibits are filed as part of this Annual Report on Form 10-K:


Exhibits
	3.1	Articles of Ivanhoe Energy Inc. as amended May 3, 2007 (Incorporated by reference to Exhibit 3.1 of Form 10-K filed with the Securities and Exchange Commission on March 17, 2008)

	3.2	Bylaws of Ivanhoe Energy Inc. as amended May 15, 2001 and further amended March 8, 2007 (Incorporated by reference to Exhibit 3.2 of Form 10-K filed with the Securities and Exchange Commission on March 17, 2008)

	10.1	Petroleum Contract for Kongnan Block, Dagang Oilfield of the People’s Republic of China dated September 8, 1997 between China National Petroleum Corporation and Pan-China Resources Ltd., as amended June 11, 1999 (Incorporated by reference to Exhibit 3.15 of Form 20-F filed with the Securities and Exchange Commission on February 28, 2000)

	10.2	Master License Agreement Amendment No. 1 dated October 11, 2000 between Syntroleum Corporation and Ivanhoe Energy Inc. (Incorporated by reference to Exhibit 10.18 of Form 10-K filed with the Securities and Exchange Commission on March 16, 2001)

	10.3	Petroleum Contract dated September 19, 2002 between China National Petroleum Corporation and Pan-China Resources Ltd. for Zitong Block, Sichuan Basin of the People’s Republic of China (Incorporated by reference to Exhibit 10.12 of Form 10-K filed with the Securities and Exchange Commission on March 19, 2003)

	10.4	Strategic Development Alliance Letter Agreement dated September 26, 2002 between Ivanhoe Energy Inc. and CITIC Energy Ltd. (Incorporated by reference to Exhibit 10.13 of Form 10-K filed with the Securities and Exchange Commission on March 19, 2003)

	10.5	Employees’ and Directors’ Equity Incentive Plan as amended May 3, 2007 (Incorporated by reference to Exhibit 10.5 of Form 10-K filed with the Securities and Exchange Commission on March 17, 2008)

	10.6	Amendment No. 2 to Master License Agreement between Syntroleum Corporation and the Company dated June 1, 2002 (Incorporated by reference to Exhibit 10.6 of Form 10-K filed with the Securities and Exchange Commission on March 15, 2006)

	10.7	Amendment No. 3 to Master License Agreement between Syntroleum Corporation and the Company dated July 1, 2003 (Incorporated by reference to Exhibit 10.17 of Form 10-K filed with the Securities and Exchange Commission on March 15, 2004)

	10.8	Terms of Agreement — Conversion of Participating Interest by Richfirst dated February 18, 2006 among Richfirst Holdings Limited, Pan-China Resources Limited, Sunwing Energy Ltd. and the Company (Incorporated by reference to Exhibit 10.2 of Form 8-K filed with the Securities and Exchange Commission on February 24, 2006)

	10.9	Amended and Restated License Agreement dated December 8, 1997 between Ensyn Technologies Inc. and Ensyn Group, Inc. and as amended on February 12, 1999 (Incorporated by reference to Exhibit 10.12 of Form 10-K filed with the Securities and Exchange Commission on March 15, 2006)

116


Exhibits
	10.10	Employment Agreement dated November 25, 2003 between Ivanhoe Energy Inc. and W. Gordon Lancaster (Incorporated by reference to Exhibit 10.22 of Form 10-K filed with the Securities and Exchange Commission on March 10, 2005)

	10.11	Employment Agreement, dated May 15, 2006 between Ivanhoe Energy Inc. and Joseph I. Gasca (Incorporated by reference to Exhibit 10.1 of Form 8-K filed with the Securities and Exchange Commission on May 26, 2006)

	10.12	Stock Purchase Agreement, dated May 12, 2006 between Ivanhoe Energy Inc., Sunwing Holding Corporation, Sunwing Energy Ltd and China Mineral Acquisition Corporation (Incorporated by reference to Exhibit 10.1 of Form 8-K filed with the Securities and Exchange Commission on May 17, 2006)

	10.13	Termination of Stock Purchase Agreement, dated August 31, 2006, between Ivanhoe Energy Inc., Sunwing Holding Corporation, Sunwing Energy Ltd. and China Mineral Acquisition Corporation (Incorporated by reference to Exhibit 99.1 of Form 8-K filed with the Securities and Exchange Commission on September 1, 2006)

	10.14	Facility Agreement, dated September 14, 2007 between Pan-China Resources Ltd., Sunwing Energy Ltd., Sunwing Holding Corporation, Sunwing Zitong Energy Ltd., Standard Bank PLC and Standard Bank Asia Limited (Incorporated by reference to Exhibit 10.15 of Form 10-Q filed with the Securities and Exchange Commission on November 8, 2007)

	10.15	Credit Agreement, dated October 30, 2006 between Ivanhoe Energy (USA) Inc. and LaSalle Bank N.A . (Incorporated by reference to Exhibit 10.15 of Form 10-K filed with the Securities and Exchange Commission on March 17, 2008)

	10.16	Indemnification Agreements entered into during the first quarter of 2008 between Ivanhoe Energy Inc. and its executive officers and directors (Incorporated by reference to Exhibit 10.16 of Form 10-K filed with the Securities and Exchange Commission on March 17, 2008)

	10.17	Employment Agreement dated May 2, 2007 between Ivanhoe Energy Inc. and Michael Silverman (Incorporated by reference to Exhibit 10.17 of Form 10-K filed with the Securities and Exchange Commission on March 17, 2008)

	10.18	Asset Transfer Agreement dated July 11, 2008 between Ivanhoe Energy Inc. and Talisman Energy Canada (Incorporated by reference to Exhibit 10.1 of Form 10-Q filed with the Securities and Exchange Commission on August 11, 2008)

	10.19	Back-In Agreement dated July 11, 2008 between Ivanhoe Energy Inc. and Talisman Energy Canada (Incorporated by reference to Exhibit 10.2 of Form 10-Q filed with the Securities and Exchange Commission on August 11, 2008)

	10.20	Cdn. $12.5 million Promissory Note in favour of Talisman Energy Canada due 31, 2008 (Incorporated by reference to Exhibit 10.1 of Form 10-Q filed with the Securities and Exchange Commission on November 11, 2008)

	10.21	Cdn. $40 million Promissory Note in favour of Talisman Energy Canada due July 11, 2011 and convertible at the option of Talisman Energy Canada into 12,779,552 common shares at Cdn. $3.13 per share (Incorporated by reference to Exhibit 10.2 of Form 10-Q filed with the Securities and Exchange Commission on November 11, 2008)

	10.22	Fixed and Floating Charge Debenture of Ivanhoe Energy Inc. in favour of Talisman Energy Canada dated July 11, 2008 in the principal sum of Cdn. $67.5 million (Incorporated by reference to Exhibit 10.3 of Form 10-Q filed with the Securities and Exchange Commission on November 11, 2008)

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Exhibits
	10.23	Pledge Agreement dated July 11, 2008 between Ivanhoe Energy Inc. and Talisman Energy Canada (Incorporated by reference to Exhibit 10.4 of Form 10-Q filed with the Securities and Exchange Commission on November 11, 2008)

	10.24	English translation of Specific Services Contract dated October 8, 2008 between Ivanhoe Energy Ecuador Inc., Empresa Estatal de Petroleos del Ecuador, Petroecuador and Empresa Estatal de Exploracion y Produccion de Petroleos del Ecuador, Petroproduccion

	10.25	English translation of Contract Modification to the Specific Services Contract dated February 13, 2009 between Ivanhoe Energy Ecuador Inc., Empresa Estatal de Petroleos del Ecuador, Petroecuador and Empresa Estatal de Exploracion y Produccion de Petroleos del Ecuador, Petroproduccion

	14.1	Code of Business Conduct and Ethics as amended November 2, 2007 (Incorporated by reference to Exhibit 14.1 of Form 10-K filed with the Securities and Exchange Commission on March 17, 2008)

	21.1	Subsidiaries of Ivanhoe Energy Inc.

	23.1	Consent of GLJ Petroleum Consultants Ltd., Petroleum Engineers

	23.2	Consent of Netherland, Sewell & Associates, Inc.

	23.3	Consent of Deloitte & Touche LLP

	31.1	Certification by the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

	31.2	Certification by the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

	32.1	Certification by the Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

	32.2	Certification by the Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


IVANHOE ENERGY INC.
By:	/s/ Robert M. Friedland
	Name:	Robert M. Friedland
	Title: Dated:	Chief Executive Officer March 16, 2009

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.


Signature	Title	Date

/s/ ROBERT M. FRIEDLAND Robert M. Friedland	Executive Co-Chairman, President and Chief Executive Officer (Principal Executive Officer)	March 16, 2009

/s/ W. GORDON LANCASTER	Chief Financial Officer	March 16, 2009
W. Gordon Lancaster	(Principal Financial and Accounting Officer)

/s/ A. ROBERT ABBOUD	Independent Co-Chairman and Lead Director	March 16, 2009
A. Robert Abboud

/s/ HOWARD R. BALLOCH	Director	March 16, 2009
Howard Balloch

/s/ ROBERT G. GRAHAM	Director	March 16, 2009
Robert G. Graham

/s/ ROBERT A. PIRRAGLIA	Director	March 16, 2009
Robert A. Pirraglia

/s/ BRIAN F. DOWNEY	Director	March 16, 2009
Brian F. Downey

/s/ PETER G. MEREDITH	Director	March 16, 2009
Peter G. Meredith

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EXHIBIT INDEX


Exhibit No.		Description
	3.1	Articles of Ivanhoe Energy Inc. as amended to May 3, 2007 (Incorporated by reference to Exhibit 3.1 of Form 10-K filed with the Securities and Exchange Commission on March 17, 2008)

	3.2	Bylaws of Ivanhoe Energy Inc. as amended May 15, 2001 and further amended March 8, 2007 (Incorporated by reference to Exhibit 3.2 of Form 10-K filed with the Securities and Exchange Commission on March 17, 2008)

	10.1	Petroleum Contract for Kongnan Block, Dagang Oilfield of the People’s Republic of China dated September 8, 1997 between China National Petroleum Corporation and Pan-China Resources Ltd., as amended June 11, 1999 (Incorporated by reference to Exhibit 3.15 of Form 20-F filed with the Securities and Exchange Commission on February 28, 2000)

	10.2	Master License Agreement Amendment No. 1 dated October 11, 2000 between Syntroleum Corporation and Ivanhoe Energy Inc. (Incorporated by reference to Exhibit 10.18 of Form 10-K filed with the Securities and Exchange Commission on March 16, 2001)

	10.3	Petroleum Contract dated September 19, 2002 between China National Petroleum Corporation and Pan-China Resources Ltd. for Zitong Block, Sichuan Basin of the People’s Republic of China (Incorporated by reference to Exhibit 10.12 of Form 10-K filed with the Securities and Exchange Commission on March 19, 2003)

	10.4	Strategic Development Alliance Letter Agreement dated September 26, 2002 between Ivanhoe Energy Inc. and CITIC Energy Ltd. (Incorporated by reference to Exhibit 10.13 of Form 10-K filed with the Securities and Exchange Commission on March 19, 2003)

	10.5	Employees’ and Directors’ Equity Incentive Plan as amended May 3, 2007 (Incorporated by reference to Exhibit 10.5 of Form 10-K filed with the Securities and Exchange Commission on March 17, 2008)

	10.6	Amendment No. 2 to Master License Agreement between Syntroleum Corporation and the Company dated June 1, 2002 (Incorporated by reference to Exhibit 10.6 of Form 10-K filed with the Securities and Exchange Commission on March 15, 2006)

	10.7	Amendment No. 3 to Master License Agreement between Syntroleum Corporation and the Company dated July 1, 2003 (Incorporated by reference to Exhibit 10.17 of Form 10-K filed with the Securities and Exchange Commission on March 15, 2004)

	10.8	Terms of Agreement — Conversion of Participating Interest by Richfirst dated February 18, 2006 among Richfirst Holdings Limited, Pan-China Resources Limited, Sunwing Energy Ltd. and the Company (Incorporated by reference to Exhibit 10.2 of Form 8-K filed with the Securities and Exchange Commission on February 24, 2006)

	10.9	Amended and Restated License Agreement dated December 8, 1997 between Ensyn Technologies Inc. and Ensyn Group, Inc. and as amended on February 12, 1999 (Incorporated by reference to Exhibit 10.12 of Form 10-K filed with the Securities and Exchange Commission on March 15, 2006)

	10.10	Employment Agreement dated November 25, 2003 between Ivanhoe Energy Inc. and W. Gordon Lancaster (Incorporated by reference to Exhibit 10.22 of Form 10-K filed with the Securities and Exchange Commission on March 10, 2005)

	10.11	Employment Agreement, dated May 15, 2006 between Ivanhoe Energy Inc. and Joseph I. Gasca (Incorporated by reference to Exhibit 10.1 of Form 8-K filed with the Securities and Exchange Commission on May 26, 2006)

	10.12	Stock Purchase Agreement, dated May 12, 2006 between Ivanhoe Energy Inc., Sunwing Holding Corporation, Sunwing Energy Ltd and China Mineral Acquisition Corporation (Incorporated by reference to Exhibit 10.1 of Form 8-K filed with the Securities and Exchange Commission on May 17, 2006)

	10.13	Termination of Stock Purchase Agreement, dated August 31, 2006, between Ivanhoe Energy Inc., Sunwing Holding Corporation, Sunwing Energy Ltd. and China Mineral Acquisition Corporation (Incorporated by reference to Exhibit 99.1 of Form 8-K filed with the Securities and Exchange Commission on September 1, 2006)

	10.14	Facility Agreement, dated September 14, 2007 between Pan-China Resources Ltd., Sunwing Energy Ltd., Sunwing Holding Corporation, Sunwing Zitong Energy Ltd., Standard Bank PLC and Standard Bank Asia Limited (Incorporated by reference to Exhibit 10.15 of Form 10-Q filed with the Securities and Exchange Commission on November 8, 2007)

	10.15	Credit Agreement, dated October 30, 2006 between Ivanhoe Energy (USA) Inc. and LaSalle Bank N.A. (Incorporated by reference to Exhibit 10.15 of Form 10-K filed with the Securities and Exchange Commission on March 17, 2008)

120


Exhibit No.		Description
	10.16	Indemnification Agreements entered into during the first quarter of 2008 between Ivanhoe Energy Inc. and its executive officers and directors (Incorporated by reference to Exhibit 10.16 of Form 10-K filed with the Securities and Exchange Commission on March 17, 2008)

	10.17	Employment Agreement, dated May 2, 2007 between Ivanhoe Energy Inc. and Michael Silverman (Incorporated by reference to Exhibit 10.17 of Form 10-K filed with the Securities and Exchange Commission on March 17, 2008)

	10.18	Asset Transfer Agreement dated July 11, 2008 between Ivanhoe Energy Inc. and Talisman Energy Canada (Incorporated by reference to Exhibit 10.1 of Form 10-Q filed with the Securities and Exchange Commission on August 11, 2008)

	10.19	Back-In Agreement dated July 11, 2008 between Ivanhoe Energy Inc. and Talisman Energy Canada (Incorporated by reference to Exhibit 10.2 of Form 10-Q filed with the Securities and Exchange Commission on August 11, 2008)

	10.20	Cdn. $12.5 million Promissory Note in favour of Talisman Energy Canada due 31, 2008 (Incorporated by reference to Exhibit 10.1 of Form 10-Q filed with the Securities and Exchange Commission on November 11, 2008)

	10.21	Cdn. $40 million Promissory Note in favour of Talisman Energy Canada due July 11, 2011 and convertible at the option of Talisman Energy Canada into 12,779,552 common shares at Cdn. $3.13 per share (Incorporated by reference to Exhibit 10.2 of Form 10-Q filed with the Securities and Exchange Commission on November 11, 2008)

	10.22	Fixed and Floating Charge Debenture of Ivanhoe Energy Inc. in favour of Talisman Energy Canada dated July 11, 2008 in the principal sum of Cdn. $67.5 million (Incorporated by reference to Exhibit 10.3 of Form 10-Q filed with the Securities and Exchange Commission on November 11, 2008)

	10.23	Pledge Agreement dated July 11, 2008 between Ivanhoe Energy Inc. and Talisman Energy Canada (Incorporated by reference to Exhibit 10.4 of Form 10-Q filed with the Securities and Exchange Commission on November 11, 2008)

	10.24	English translation of Specific Services Contract dated October 8, 2008 between Ivanhoe Energy Ecuador Inc., Empresa Estatal de Petroleos del Ecuador, Petroecuador and Empresa Estatal de Exploracion y Produccion de Petroleos del Ecuador, Petroproduccion

	10.25	English translation of Contract Modification to the Specific Services Contract dated February 13, 2009 between Ivanhoe Energy Ecuador Inc., Empresa Estatal de Petroleos del Ecuador, Petroecuador and Empresa Estatal de Exploracion y Produccion de Petroleos del Ecuador, Petroproduccion

	14.1	Code of Business Conduct and Ethics amended November 2, 2007 (Incorporated by reference to Exhibit 14.1 of Form 10-K filed with the Securities and Exchange Commission on March 17, 2008)

	21.1	Subsidiaries of Ivanhoe Energy Inc.

	23.1	Consent of GLJ Petroleum Consultants Ltd., Petroleum Engineers

	23.2	Consent of Netherland, Sewell & Associates, Inc.

	23.3	Consent of Deloitte & Touche LLP

	31.1	Certification by the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

	31.2	Certification by the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

	32.1	Certification by the Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

	32.2	Certification by the Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

121