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

OR

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

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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”

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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^TM opportunities 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.

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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.

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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.

4. 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.

6

The Company’s continuing strategy is as follows:

1. 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.

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

3. Enhance the Company’s financial position in anticipation of major projects. Implementation of large projects requires significant capital outlays. The Company is working on various financing plans and establishing the relationships required for the development activities of the future.

4. Build internal capabilities. During 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.

5. Build the relationships needed for the future. Commercialization of the Company’s technologies demands close alignment with partners, suppliers, host governments and financiers.

INTEGRATED OIL AND GAS PROPERTIES

Tamarack Project

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

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

The Company’s HTL^TM plants at Tamarack are projected ultimately to be capable of operating at production rates of 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.

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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.

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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.

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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.

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• 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.

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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.

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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.

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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

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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.

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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.

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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.

17

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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

25

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.

26

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.

27

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.

28

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

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.

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	)

29

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.

30

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.

31

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.

32

• 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.

* * *

33

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.

34

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^TM technology team.

35

• 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.

37

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.

• 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.

38

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.

39

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.

40

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.

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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.

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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.

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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^TM Process for petroleum applications (HTL^TM Technology) as well as the exclusive right to deploy the RTP^TM Process 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.

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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.

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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.

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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.

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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.

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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

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REPORT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS

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

We have audited the accompanying consolidated 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

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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

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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)

52

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)

53

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)

54

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^TM Process”) 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.

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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.

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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.

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.

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^TM Technology 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 GTL facility will 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.

57

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.

58

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.

59

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 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.

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.

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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:
HTLTM		—			—		—			—			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:
HTLTM		—			—			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

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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.

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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.

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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.

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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

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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.

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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.

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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

Common

Exercise

Cash

Year of

Special

Shares

Shares

Price per

Value on

Issue

Warrant

Issued

Issued

Exercisable

Issuable

Value

Expiry Date

Share

Exercise

(thousands)

($U.S. 000)

($U.S. 000)

2006

U.S.$2.23

11,400

11,400

11,400

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.

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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.

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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).

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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

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.

71

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

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	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

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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.

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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

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 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.

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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.

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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.

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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

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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).

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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.

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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

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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.

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(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.

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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 HTLTM 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

84

	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 HTLTM 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 HTLTM 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

85

(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.

86

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
HTLTM 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
HTLTM 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

87

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

88

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.

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 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 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.

89

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.

90

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

91

	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

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	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

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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.

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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.

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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.

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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)

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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.

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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.

99

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.

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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.

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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.

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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			0		0		0
Gasca, Joseph President & CEO		—			—		—		0		0		0
Lancaster, Gordon CFO		50,000	(3)	Cdn$	1.68	March 11, 2013			0		0		0
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			0		0		0
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			0		0		0
Chua, Patrick		60,000	(3)	US$	1.70	March 11, 2013
Executive Vice President		40,000	(6)	US$	2.06	May 3, 2012			0		0		0

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.

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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		0		0		0
		480,000	US$	2.85	May 15, 2011
Balloch, Howard		50,000	Cdn$	2.66	May 29, 2013		0		0		0
		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		0		0		0
		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		0		0		0
		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		0		0		0
		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		0		0		0
		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	vested during the year		during the year
Name	(US$)	(US$)		(US$)
Abboud, A. Robert	Nil.		0		0
Balloch, Howard	Nil.		0		0
Downey, Brian	US$5,800		0		0
Graham, Robert	Nil.		0		0
Meredith, Peter G.	Nil.		0		0
Pirraglia, Robert	Nil.		0		0

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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.

113

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:

a. 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.

b. 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.”

114

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.

115

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)

117

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

118

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

119

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

EX-10.24

Exhibit 10.24

ENGLISH TRANSLATION OF CONTRACT AS SIGNED
OCTOBER 8, 2008

SPECIFIC SERVICES CONTRACT FOR DEVELOMENT, PRODUCTION AND
UPGRADING OF CRUDE OIL
IN BLOCK 20, INCLUDING THE PUNGARAYACU OIL FIELD IN THE
ECUADORIAN AMAZON REGION

ENTERED INTO BY AND BETWEEN

EMPRESA ESTATAL DE PETRÓLEOS DEL ECUADOR, PETROECUADOR AND
ITS AFFILIATE EMPRESA ESTATAL DE EXPLORACION Y PRODUCCIÓN DE
PETRÓLEOS DEL ECUADOR, PETROPRODUCCION, AND IVANHOE ENERGY
ECUADOR INC.
UNDETERMINED AMOUNT

CLAUSE 1: PARTIES TO THIS CONTRACT

This Contract is entered into by and between Empresa Estatal de Petróleos del Ecuador, PETROECUADOR and its Affiliate Company Empresa Estatal de Exploración y Producción de Petróleos del Ecuador, PETROPRODUCCION, represented by the Rear-Admiral Luis Aurelio Jaramillo Arias and Captain Camilo Delgado in their capacity as Executive President and Vice-President, respectively, who have been duly authorized by the Contracting Committee of PETROPRODUCCION, as appears in the documents attached hereto, hereinafter referred to as PETROECUADOR and PETROPRODUCCION, on the one hand, and on the other, IVANHOE ENERGY ECUADOR INC., represented by its General Agent and Legal Representative in Ecuador, Mr. Carlos Espinoza, who has been duly authorized by its Parent Company, as appears in the documents attached hereto, hereinafter referred to as the CONTRACTOR.

CLAUSE 2: BACKGROUND

Description and Basic Principles - On December 6, 2007, IVANHOE ENERGY ECUADOR INC. submitted its offer and proposal for the development and production of Crude Oil in the Contract Area, consisting of an Appraisal Stage, a Pilot Stage and the subsequent Exploitation Stage (that includes the development and production periods). All Contract Stages will be implemented in a period of 30 years, with the exploitation stage extendable by mutual agreement of the parties.

2.1. STAGES:

APPRAISAL STAGE - The Appraisal Stage will have a duration of up to 3 years and will begin as of the date CONTRACTOR obtains the environmental permit. During the Appraisal Stage, CONTRACTOR will undertake bi-dimensional seismic surveys over the southern portion of the Pungarayacu Field believed to contain mobile oil. Depending on the results of the seismic surveys, CONTRACTOR will perform drilling and testing of appraisal wells. CONTRACTOR will also use steam generators to test the heavy oil formations for production.

In the event that the technical data indicates that it is favorable to drill a well to the pre-cretaceous formation, the work schedule submitted by CONTRACTOR may be amended for the period it will take to appraise such well.

PILOT STAGE- The Pilot Stage will commence when CONTRACTOR notifies PETROPRODUCCION of its intention to enter such Stage. The Pilot Stage shall have a duration of up to three (3) years. Among other works, in the Pilot Area selected, CONTRACTOR will perform bi-dimensional and three-dimensional seismic studies and will drill wells. Construction of the first HTL™ Plant to process heavy oil, will commence at the beginning of the Pilot Stage and will end when the HTL™ Plant begins processing and upgrading Available Crude Oil.

EXPLOITATION STAGE- (Includes the Development and Production Stages). The results obtained during the Pilot Stage will determine whether CONTRACTOR will proceed into the Exploitation Stage to develop and produce Crude Oil in the Pungarayacu Field and other commercially exploitable and economically profitable Crude Oil reservoirs selected by CONTRACTOR in the Contract Area. CONTRACTOR will notify PETROPRODUCCION when the results obtained warrant proceeding with the Exploitation Stage.

EARLY PRODUCTION or TEST PRODUCTION- Are the activities of development and production of Available Crude Oil that the CONTRACTOR may perform during the Appraisal Stage and/or the Pilot Stage. Said production will be ascribed to the permitted production rates as established in the Regulations of Hydrocarbon Operations, which volumes of production will be recommended in accordance with the provisions of Clause 8.1.,and for which the CONTRACTOR will receive payment in accordance with the provisions of Clause 9.2.12.

2.2 ANTECEDENTS. By Memorandum No. 3164 VPR-LEG-2007, of 22 August 2007, PETROPRODUCCION requested the President and Members of the Council of Administration of PETROECUADOR to deliver the technical information requested by IVANHOE ENERGY INC.

The company IVANHOE ENERGY INC, presented 6 December 2007 its offer and proposal for the development and production of the Area of the Pungarayacu Field, consisting of an Evaluation Phase, a Pilot Phase and the subsequent Exploitation Phase (that includes the Development and Production phases). All of the Phases of the Contract would be developed in a period of 30 years, extendable by mutual agreement of the parties, for two additional periods of five years each, depending on the interests of the State, in conformity with the Hydrocarbons Law and this Contract.

By communication dated 10 December 2007, the company IVANHOE ENERGY ECUADOR INC reconfirmed the designation of its representatives to prepare the proposal directed to the President of the Republic and the power to initiate the work immediately, also reiterated its commitment to assume all the risk of the investments of the project and all the existing legal requirements in Ecuador.

By order NO. 7617 PPR-VPR-2007 of 13 December 2007, PETROPRODUCCION designated the members of the commission to travel to Bakersfield, California, United States of America, to visit the installations of IVANHOE ENERGY, that was done between 16 and 19 of December of the same year.

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On 27 December 2007 IVANHOE ENERGY INC.,sent to PETROPRODUCCION the documentation necessary to satisfy the legal, technical and financial aspects to corroborate the information contained in the proposal referred to and requested the designation of the personnel that for purposes of confidentiality would have knowledge of the same.

The Executive President of PETROECUADOR by order NO.508-PEP-2007 reported that after the visit to the installations of the company in Bakersfield, California, United States of America, the technicians of the sate company made an analysis of the information provided and considering that the reserves of crude of the country are in large part heavy crude, considering that it would be important to rely on the technical experience and financial capacity of IVANHOE ENERGY INC., to optimize the Pungarayacu Field for the requirements of PETROPRODUCCION.

By ResolutionNo.794-CEL 2008 of 1 February 2008, it was resolved without effect of Resolution No. 663-CEL-2003 of 13 August 2003, to authorize the start of the prebidding of Blocks 20 and 29 of the Amazon Region and for the record it states that it corresponds to the Executive President of PETROECUADOR and VICEPRESIDENTS of its Affiliates to deliver the available information of the Areas / Blocks or petroleum fields to the interested companies.

By Order No. 176-SJ461/DM 2008, of 11 April 2008 the Minister of Mines and Petroleum communicated to the Executive President of PETROECUADOR that the legal basis that supported the signature of the Contract with the company for the Development and Exploitation of the Heavy crudes of the PUNGARYACU Field of the Ecuadorian Amazon Region is the Contract of Work, Goods and Specific Services as contemplated in Art. 17 of the Hydrocarbons Law and in the Regulation of Contracting of Works, Goods and Services of PETROECUADOR and its Affiliates issued by Executive Decree No. 652 and published in the Official Register 194 of 19 October 2007 conforming to Order 630-DM-0707632 of 26 December 2007 and 051 DM-2008 of 17 January 2008 and Memorandum N-261-SJ-2008 of 19 March2008, granting to PETROECUADOR the process and description of the respective Contract.

By Resolution No. 44-DIR-2008 of 19 May 2008 adopted by the Board of PETROECUADOR, resolved (point 3) THE PUNGARAYACUFIELD,- THAT IN CONSIDERATION AND THAT UNTIL MARCH 2008, THERE MUST BE SIGNED THE CONTRACT OF SPECIFIC SERVICES WITH THE COMPANY IVANHOE, FOR THE DEVELOPMENT AND PRODUCTION OF HEAVY CRUDE OIL OF THE PUNGARAYACU FIELD, UTILIZING THE PATENTED TECHNOLOGY OF THIS COMPANY, AND TAKING INTO ACCOUNT THAT THE CONTRACTORS MUST HAVE A PRICE PER PRODUCED BARRELTHAT INCLUDES ALL THE COSTS, INVESTMENTS AND REASONABLE PROFIT AND RESOLVED TO REQUEST THE COMPANY IVANHOE TO PRESENT ITS OFFER ON THESE TERMS WITHIN A PERIOD OF 30 DAYS AND IF NOT PRESENTED IN THIS PERIOD, THAT PETROPRODUCCION WILL PREPARE THE BASES FOR BIDDING BY PUBLIC AND PRIVATE COMPANIES.

By public letter of 15 May 2008 delivered before Notary 17, IVANHOE ENERGY INC.proved that it is the sole provider and owner of the patents of the HTL technology.

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By letter S/N of 30 May 2008, the company IVANHOE ENERGY ECUADOR INC.presented for consideration of the Executive President of PETROECUADOR its Proposal for the Integral Economic Development of Block 20 in the sense that the services will be paid for by a fixed amount per barrel of production.

Under date of 10 June 2008 the Commission designated to Review the economic terms of the company IVANHOE ENERGY INC.. issued a conclusive Acta on the proposal presented by the company for the development and production of Block 20, the Pungarayacu Field.

By Report No. 2465-VPR-2008, of 16 June 2008, the Vicepresident of PETROPRODUCCION made available to the Contracting Committee of PETROPRODUCCION the documentation relating to the development and production of the PUNGARAYACU field, of the offer presented and negotiated by the company IVANHOE ENERGY ECUADOR INC.

By Resolution 2008325 VPR-PPR-2008 of 17 June 2008, the Vicepresident of PETROPRODUCCION RESOLVED to qualify the company IVANHOE ENERGY ECUADOR INCL. as the unique provider for the utilization of the patented technology HEAVY TO LIGHT (HTL) for the upgrading of heavy crude, ordered the publicity of the resolution and designated the Head of that Unit to coordinate the Contracts for the execution of such resolution.

The Contracting Committee of PETROPRODUCCION resolved pending a detailed report of the Vicepresident of PETROPRODUCCION through the Negotiation Commission containing an analysis of the economic aspects of the negotiation.

By Order No. 3051 VPR-ACUM-2008, of 22 July 2008, the Vicepresident of PETROPRODUCCION presented the report of the Negotiation Commission with the recommendation for the Contracting Committee of PETROPRODUCCION.

By Resolution No. 024-CC-PPR-2008-07-29, of 29 July 2008 the Contracting Committee of PETROPRODUCCION resolved to award and authorized the signing of he contract with the company IVANHOE ENERGY ECUADOR INC. the purpose of which is the provision of specific services, for the development, production of the crude oil in the Pungarayacu Field in Block 20, providing the technology, capital, equipment, machinery and other goods and services necessary for the compliance with the obligations, utilizing the HTL™ Technology (Heavy to Light) patented as its property, for the upgrading of the quality of the crude oil, confirmation of reserves and complementary exploration in the precretaceous under its responsibility and risk, and for a period of thirty years.

CLAUSE 3: INTERPRETATION OF THIS CONTRACT

3.1 Interpretation: The Parties hereby agree to interpret this Contract in accordance with the provisions of the Preliminary Section and Section XIII, Book IV, of the Codified Civil Code of Ecuador. The titles and order of all paragraphs and subparagraphs used herein are for identification and reference purposes only. Definitions shall apply equally to both the singular and plural forms of the terms defined herein. Whenever the context may require, all pronouns shall include the corresponding masculine, feminine and neuter forms. The words “include,” “includes” and “including” shall not be limiting and will be deemed as if they were followed by the phrase “without limitation.”, unless the context requires otherwise. Any agreements, documents, instruments or laws defined or referred to in this Contract shall be deemed to include all agreements, documents, instruments or laws amended, modified or supplemented from time to time, including any agreements, documents or instruments by waiver or consent. All references in this Contract to any particular Law shall be deemed to include any rules and regulations passed under that Law. References to particular persons shall also refer to their authorized predecessors, successors and authorized transferees.

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3.1.1	Any tolerance by the Parties involving timely compliance of any obligations under this Contract shall not imply in any event a change or amendment to its provisions, and such failure to comply will not be a precedent for the interpretation of this Contract, and shall not give rights to a Party in default of compliance of its obligations under this Contract.
3.1.2	The provisions of this Contract shall prevail, in the event of discrepancies between any laws entering into force after execution of this Contract or those contained in complementary agreements and amendments, and any additional agreements executed between the Parties and other documents that due to their legal, technical or economic nature are deemed subordinate.
3.1.3	The provisions of the Contract herein specify and clarify the scope of such provisions and shall prevail over them.
3.2	Language: This Contract has been written in Spanish and the Spanish version shall be the only one valid for all purposes. Any correspondence between the Parties hereto shall also be in Spanish, except technical reports that due to their nature need to be submitted in another language, in which case, and if required by PETROPRODUCCION, such reports will include a Spanish translation.
	The parties hereby agree that the specific services rendered under this Contract do not imply a transfer of technology — know how — nor the total or partial assignment of rights that are inherent to invention patents of the HTL™ process. Such patents are the exclusive property of IVANHOE ENERGY ECUADOR INC. and its Related Companies. Therefore, the Ecuadorian Government hereby agrees to honor such property rights, including all those arising from International and Regional Agreements and local legislation on Intellectual Property Rights.
3.3	Definitions: For the purposes of this Contract, the terms below shall have the following meanings, unless the context of this Contract requires otherwise.
3.3.1	Fixed Asset: is any non-fungible movable or immovable asset, acquired, constructed or supplied by CONTRACTOR for the activities foreseen under this Contract, which have a useful life that exceeds one year.

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3.3.2	Fiscal Year: Means the period from January 1 until December 31 of each year, both dates inclusive.
3.3.3	Contract Area - Means Block 20 (that includes the Pungarayacu Field) in which CONTRACTOR is authorized by virtue of this Contract to carry out activities to confirm reserves, develop and produce hydrocarbons and related exploration, at its own responsibility and risk, whose boundaries are clearly and duly defined in Annex 1 to this Contract which is an integral part hereof.
3.3.4	Fiscalization. Means the technical-financial activities that PETROPRODUCCION and the “Dirección Nacional de Hidrocarburos” will carry out to determine volumes of Available Crude Oil and/or RTP™ Product (“Fiscalizable Production”) sent to a Fiscalization and Delivery Center. Among other things, it will serve to determine: (i) the Contractual Payment as established in Clause 9; and, (ii) in the event that CONTRACTOR receives payment in kind, it shall mean the Fiscalized Production to which CONTRACTOR is entitled to, before the HTL™ Plant begins production, and thereafter, for operational reasons, the Fiscalizable Production may consist of only Available Crude Oil or pure RTP™ Product or a blend of both.
3.3.5	Fiscalized Production is the Available Crude Oil and/or RTP™ Product that has been Fiscalized in a Fiscalization and Delivery Center.
3.3.6	Fiscalization and Delivery Centers: Are the sites agreed between PETROPRODUCCION and CONTRACTOR, where the CONTRACTOR delivers to, and PETROPRODUCCION receives from, and the “Dirección Nacional de Hidrocarburos” Fiscalizes, the Fiscalizable Product (as defined in Clause 3.3.4). The Fiscalization and Delivery Centers will require approval from the Ministry of Energy. CONTRACTOR shall have the right to request from time to time an alternate Fiscalization and Delivery Center for technical or operational reasons.
3.3.6.1	Measuring Devices: The Parties shall agree on the type of measuring devices they will use to measure the Fiscalized Production at the Fiscalization and Delivery Centers. Such devices, hereinafter referred to as “Fiscalization Meters”, shall be inspected and calibrated regularly by independent inspectors mutually agreed by the Parties. The measurements of Fiscalized Production with the Fiscalization Meters shall be conclusive and will serve as basis to determine the volumes of Fiscalized Production for purposes of the Contractual Payment that will be paid to CONTRACTOR, as established in Clause 9 of this Contract.
3.3.6.2	Except for the Fiscalized Production taken by CONTRACTOR as payment, CONTRACTOR will not bear any transportation costs from a Fiscalization and Delivery Center after Fiscalization.
3.3.7	Executive Committee: Is a supporting body, comprised of three officials from PETROPRODUCCION and three high level officials of CONTRACTOR, that has for its purpose, to supervise, coordinate and recommend timely actions, as the case may be, in order to optimize performance of this Contract, as established in Annex III to this Contract, which contains the details of the functions and duties of the Executive Committee.

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3.3.8	Related Companies: a) Parent Company is a Company that directly or indirectly controls an Affiliate or Subsidiary, or any of the companies that are shareholders of CONTRACTOR, in this case IVANHOE ENERGY LATIN AMERICA INC, a Canadian company duly organized in the Province of British Columbia, Canada. b) Affiliate — is a company directly controlled by an Affiliate and indirectly controlled by the Parent Company.; c) Subsidiary — is a company directly controlled by its Parent Company. The term control, as used in this sub-clause, shall be interpreted within the context of a Parent Company-Affiliate relationship, where the Parent Company owns more than 50% of the Affiliate’s capital. As regards to the Affiliate-Subsidiary relationship, this percentage shall be 100%.
3.3.9	Appearing Parties PETROECUADOR, PETROPRODUCCION and CONTRACTOR.
3.3.10	Consultants. Are the natural persons or legal entities independent and in good standing , national or foreign, who provide services on the issues requiring consultation.
3.3.11	CONTRACTOR: IVANHOE ENERGY ECUADOR INC, a company duly incorporated in the Province of British Columbia, Canada, registered and qualified in Ecuador. CONTRACTOR also means and includes any other Persons proposed by IVANHOE ENERGY ECUADOR INC., and approved by PETROECUADOR and PETROPRODUCCION to participate as members of the CONTRACTOR’s Group, as established in IVANHOE ENERGY ECUADOR INC’s bylaws which were registered at the “Superintendencia de Compañías” through Resolution No 0698 dated March 4, 2008, and registered at the Quito Register of Commercial Concerns on March 11, 2008, and at the “Dirección Nacional de Hidrocarburos” on March 14, 2008 with Records 0000488 to 0000584, establishing that CONTRACTOR may perform hydrocarbon exploration, exploitation, transportation, storage, industrialization and commercialization activities, as well as provide oil industry integrated services in Ecuador or abroad, through partnerships or third party agreements.
3.3.12	Contract: Means this instrument, including its enabling documents and annexes, referred to as “Specific Services Contract for Development, Production and Upgrading of Crude Oil in Block 20” whose object is to develop, produce and upgrade heavy crude oil, confirm reserves and perform complementary exploration activities in Block 20, at the expense and risk of CONTRACTOR, and by virtue of which CONTRACTOR is entitled to receive the Contractual Payment set forth in the provisions of Clause 9.

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3.3.13	Dollar: Means the currency of the United States of America and the legal tender in the Republic of Ecuador.
3.3.14	Environmental Studies: Consist of forecasts or current identification of potential environmental damages or changes, in order to establish preventive measures, mitigation activities and rehabilitation measures of the environmental impact that may occur due to performance of this Contract. These include Environmental Impact Studies, Environmental Diagnoses, Environmental Management Plans and Environmental Audits.
3.3.15	Appraisal Stage. Is the Project Stage set forth in sub-clause 2.1 of this Contract.
3.3.16	Pilot Stage. Is the Project Stage described in sub-clause 2.1 of this Contract.
3.3.17	Exploitation Stage. Means the Project Stage set forth in sub-clause 2.1 of this Contract.
3.3.18	Effective Date: Is the date on which this Contract is registered in the Hydrocarbons Records of the Dirección Nacional de Hidrocarburos, from which date the terms of this Contract shall be effective.
3.3.19	Start-Up Date: Is the date on which the CONTRACTOR begins its operations, within one hundred and eighty (180) days from the date of execution of this Contract. Operations for this purpose shall include any arrangements to develop the Environmental Studies and Environmental Management Plans. The above-mentioned term will only be extended for duly justified reasons.
3.3.20	Force Majeure or acts of God: Means unforeseen circumstances beyond control by the Parties, as provided in Article 30 of the Ecuadorian Civil Code. This includes, but is not limited to earthquakes, seaquakes, flooding, landslides, storms, fires, explosions, strikes, walkouts, social unrest, acts of war (declared or not), sabotage or terrorist acts, acts or omissions of government authorities or state entities, or any other events not mentioned in this sub-clause which are beyond reasonable control by the Party affected, thus hindering or delaying performance of one or several obligations under this Contract, including delays in obtaining approval of environmental studies. However, Force Majeure shall not include operational or administrative events imputable to CONTRACTOR and its subcontractors. It is hereby intended and agreed that PETROPRODUCCION may allege as Force Majeure any act or omission by other entities or authorities of the Ecuadorian Government when said acts or omissions are due to facts that represent Force Majeure or Act of God. The term Fortuitous Circumstances shall have the same meaning as Force Majeure.

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3.3.21	Associated Gas: Mixture of hydrocarbons produced from the Crude Oil Reservoirs, which become gas at surface pressure and surface temperature.
3.3.22	Gas Condensate: Mixture of hydrocarbons produced from a reservoir that under surface pressure and temperature, become liquid.
3.3.23	Natural Gas: Mixture of hydrocarbons produced from Gas Reservoirs, which remain as gas at surface pressure and temperature.
3.3.24	Heavy to Light (HTL™) Technology means the patented RTPTM process of Ivanhoe Energy Inc. and its Related Companies, which rapidly heats carbonaceous materials, at temperatures above 400 degrees Centigrade per second, until reaching a minimum temperature of 350 degrees Centigrade, but holds carbonaceous materials together with the products originally decomposed by heat into a pyrolysis reactor, at a minimum temperature of 450 degrees Centigrade during less than 5 seconds. Among other applications, this process produces upgraded fuels arising from carbonaceous materials, including heavy oil and bituminous raw materials. The HTL™ Plant is a technical construction that uses the HTL™ Technology to process Available Crude Oil and create produces the RTP™ Product. The RTP™ Product is the product that results from processing the Available Crude Oil in an HTL™ Plant, which upgrades the quantity and quality of the Available Crude Oil.
3.3.25	Appraisal Investments. Are all those costs, expenses, and investments incurred directly by CONTRACTOR or indirectly through its Related Companies, during the Appraisal Stage, as well as any additional expenditures made during the Pilot Stage and Exploitation Stage, to evaluate the commerciality of hydrocarbon reservoirs in the Contract Area, duly approved by the Executive Committee.
3.3.26	Development Investments. Are those expenditures, including costs, expenses and payments, incurred directly by CONTRACTOR or indirectly through its Related Companies, to develop and put into production the Crude Oil reservoirs in the Contract Area during the Pilot Stage and Exploitation Stage, in accordance with the respective Development Plan.
3.3.27	Production Investments. Expenditures, including costs, expenses and payments directly incurred by CONTRACTOR, or indirectly through its Related Companies, during the term of this Contract to produce Crude Oil in the Contract Area, and to maintain and increase such production, thus incrementing the non-amortizable value of the Fixed Assets, used for the performance of this Contract.

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3.3.28 Domestic Market: Means the Crude Oil volumes used to cover local Ecuador needs, and includes:

(a)	Refining and industrialization in plants installed in Ecuador where the production is used for local consumption;
(b)	Refining abroad to obtain by-products used for local consumption; and
(c)	Countertrade or compensation to obtain by-products used for local consumption

	PETROPRODUCCION shall deliver to CONTRACTOR all the information it may request involving prices, quality and sales volumes, as well as the terms and conditions of external sales for the oil and RTP™ Products produced in the Contract Area. CONTRACTOR shall keep confidential all the information supplied by PETROPRODUCCION.
3.3.29	Ministry: Means the Ministry of Mines and Petroleum of Ecuador.
3.3.30	Main Pipelines: Means the Pipelines, other lines and facilities required to move the Fiscalizable Production to the Fiscalization and Delivery Center or to the export terminals or industrial centers in Ecuador, as the case may be, which according to Law are operated by PETROPRODUCCION and will be available to CONTRACTOR,.
3.3.31	Secondary Pipelines: Pipelines needed to move Fiscalizable Production from the Fiscalization and Delivery Centers to the Main Pipelines.
3.3.32	Development Plan: Is the set of minimum or maximum activities and estimated investments that CONTRACTOR intends to implement during the Exploitation Stage to put into production the Crude Oil reservoirs in the Contract Area, approved by the Executive Committee, PETROPRODUCCION and the Ministry of Energy. This Development Plan must be based on all commerciality parameters, as well as on any other factors that could affect the economic and technical feasibility to develop the Commercially Exploitable Crude Oil reservoirs during the Exploitation Stage.
3.3.33	Crude Oil: is the mixture of hydrocarbons that exist in liquid form in the natural reservoir, which remain liquid at atmospheric conditions of pressure and temperature. a) Available Crude Oil is the Crude Oil produced after deducting quantities used in operations or unavoidably lost.
3.3.34	RTP™ Product. Is the product that results from upgrading Available Crude Oil in an HTL™ Plant, with a higher API grade, reduced levels of viscosity, metals and sulphur, by using the HTL™ Technology.

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3.3.35	International Market Price. Is the last weighted average price received by PETROPRODUCCION in a calendar month, per volume of Available Crude Oil external cash sales (including “spot” or long term sales), to independent buyers, on competitive terms, but excluding volumes for countertrade or barter or compensation and adjusted by quality; equivalent to the Available Crude Oil and Crude Oil used for payments in kind, according to international petroleum practices. These prices shall be FOB Ecuadorian port (main export terminal) and in Dollars per Barrel.
3.3.36	In the event that external sales have payment terms exceeding 30 days, the cash price will be adjusted to that term by applying the legal interest rate established by the Central Bank of Ecuador for the corresponding month.
3.3.37	PETROECUADOR, through PETROPRODUCCION, will promptly deliver to CONTRACTOR all the information required by CONTRACTOR regarding prices, quality and sale volumes, as well as terms and conditions of payment, in order that CONTRACTOR is able to verify all data concerning the external sales from the Contract Area.
3.3.38	CONTRACTOR shall keep confidential all the information supplied to it concerning the Contract Area under this Contract, and, in turn, PETROPRODUCCION will not reveal any technological issues involving the Plant and the HTL™ process.
3.3.39	If the International Market Price cannot be determined because PETROPRODUCCION has had no external sales during the past 60 days, the Parties will select a basket of Crude Oils produced in the Oriente Basin to establish such price. If the Parties do not reach an agreement regarding the above-mentioned basket, the Parties may submit the issue to a Consultant for the determination.
3.3.40	Legal Interest Rate: Is the annual interest rate in decimal fraction, established by the Central Bank of Ecuador and applicable to each month during the corresponding Fiscal Year.
3.3.41	Reference Price. Is the last weighted average price of Crude Oil external sales made in cash by PETROECUADOR during the past month, (including “spot” or long-term sales), to independent buyers, under competitive terms, excluding volumes for trade, consignment or compensation, in conformity with Article 71 of the Hydrocarbons Law and the provisions of Clause 9.3 of this Contract. These prices shall be FOB in a main Ecuadorian port (export terminal) and in Dollars per Barrel.
3.3.42	Annual Work Plans and Annual Investment Budgets. Means all the activities and estimated investments that CONTRACTOR plans to perform in a Fiscal Year.

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3.3.43	Early Production. Are the activities of development and production of Available Crude Oil that the CONTRACTOR may perform during the Appraisal Stage and/or the Pilot Stage. Said production will be ascribed to the permitted production rates as established in the Regulations of Hydrocarbon Operations, which volumes of production will be recommended in accordance with the provisions of Clause 8.1.,and for which the CONTRACTOR will receive payment in accordance with the provisions of Clause 9.2.12.
3.3.44	Emergency Situations. Are those circumstances that occur or may occur in Ecuador or abroad, which require immediate action to avoid actual or potential damages to CONTRACTOR’s operations under his Contract or to the employees/property of any of the Parties hereto, or to the individuals that provide goods or services to any Party or to the persons/property of third parties, without prejudice to the provisions of the Hydrocarbons Law and the National Security Act.
3.3.45	Maximum Allowed Production Rate. Means the Crude Oil produced per time unit/well/reservoir/field, as dictated by the Ministry of Mines and Petroleum through the “Dirección Nacional de Hidrocarburos”. Such rate is based on technical and financial criteria, and shall follow the procedures set forth in Clause 8 of this Contract, and in the document “Technical Criteria to Calculate Production Rates”, developed by the “Dirección Nacional de Hidrocarburos” on November 20, 1995, included herein as Annex 4.
3.3.46	Quarter: Is a three-month period beginning on January 1, April 1, July 1 and October 1 of each Fiscal Year, as established in Clause 9.1.1 of this Contract. Reference Quarter and Payment Quarter are the quarters defined in sub-clause 9.1.2.1 of this Contract.
3.3.47	Production Unit or Barrel: Is the volume unit of Crude Oil, equivalent to 42 United States gallons, measured at a temperature of 60-degrees Fahrenheit, and at a pressure of 14,7959 pounds per square inch.
3.3.48	Commercially Exploitable Crude Oil Reservoirs. Are those reservoirs that, according to technical and economic studies, production rates and recoverable reserves, CONTRACTOR deems adequate due to the technical and financial parameters and reports, and which the Parties consider as commercially exploitable.
3.3.49	Gas Condensate Reservoirs: Are those Gas Reservoirs that, if exploited, would produce gas and liquids in a ratio not exceeding 100.000 standard cubic feet of gas per Barrel of liquid hydrocarbons, measured at surface level under standard conditions of pressure and temperature.
3.3.50	Gas Reservoirs: Are the Hydrocarbon reservoirs that at reservoir pressure and temperature contain hydrocarbons in gaseous state only.

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3.3.51	Crude Oil Reservoirs: Are those reservoirs containing hydrocarbons, in liquid state, at reservoir conditions.
3.3.52	Reference Quarter is the Calendar Quarter immediately preceding the Quarter in which the Effective Date of this Contract occur.
3.4	Other definitions: The terms below, shall be interpreted as follows:
3.4.1	When this Contract refers to “Crude Oil Producers in Ecuador” or if similar phrases are used, for legal and contractual purposes it shall mean that PETROPRODUCCION is included as such a producer.
3.4.2	When this Contract refers to periods (plazos), they are calculated on a continuous and calendar basis; while when the reference is to terms (terminos) , calculation will be only in working or business days. In all events, when periods expire on a non-working day, they shall be extended to the next working or business day.
3.4.3	When in this Contract the word “Clause” begins with capital letter, it shall refer to the entire Clause; otherwise, its scope shall be limited to the corresponding sub-clause.
3.4.4	As regards to definitions not included in this Contract, the Parties shall interpret them, in accordance with the generally accepted practices of the international Petroleum industry and those established in the Hydrocarbon Operation Regulations.

CLAUSE 4: CONTRACT PURPOSE

4.1	The purpose of this Contract is the provision of specific services by the CONTRACTOR for the development, production of crude oil in the Contract Area, utilizing the HTL™ Technology (Heavy to Light), patented and owned by Ivanhoe Energy and its Related Companies, to upgrade the quality of the Crude Oil of the Pungarayacu Field confirm reserves, and implement complementary exploration activities, at the CONTRACTOR’s own risk and expense. CONTRACTOR undertakes to implement activities to confirm reserves, develop and produce Crude Oil in Block 20, supplying the necessary technology, capital and equipment or other goods and services necessary for the compliance with the obligations established in this Contract. PETROPROPRUDUCCION will pay CONTRACTOR a price per barrel produced and fiscalized, in accordance with the provisions of Clause 9 of this Contract.
	If upon completing the activities to confirm reserves, CONTRACTOR finds Commercially Exploitable Light Crude Oil, it shall be its obligation to exploit it, in which event the Parties hereto will mutually agree on the terms and conditions to develop and exploit such crude oil, as well as fix the price to be paid, aspects that will be established in a written document.
4.1.1	The above-mentioned obligations shall be fulfilled by CONTRACTOR in Block 20 (which includes the Pungarayacu Field), whose boundaries are listed in Annex 1 to this Contract. CONTRACTOR may carry out exploration activities within the boundaries of Block 20, as well as develop studies and interpretation of surveys involving such seismic lines and other work, and will deliver such results to PETROPRODUCCION. Administrative and technical services may be rendered in Ecuador or abroad, to support the activities performed in the Contract Area.

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CLAUSE 5: OBLIGATIONS AND RIGHTS OF THE PARTIES

5.1	CONTRACTOR OBLIGATIONS: Without prejudice of any other obligations under this Contract, CONTRACTOR undertakes to:
5.1.1	Comply with the purpose of this Contract, for which the development and production will be its exclusive responsibility.
5.1.2	Register this Contract in the Hydrocarbons Registry within 30 days from its signature.
5.1.3	Deliver at the Fiscalization and Delivery Center Fiscalized Production from the Contract Area that will always be crude that is transportable by oil pipeline.
5.1.4	Make the investments and expenditures required to perform this Contract, as established in Annex 5. In addition, CONTRACTOR shall build all civil works and oil facilities; acquire and install, at its expense, the necessary equipment ( Fiscalization Meters) referred to in sub-clause 3.3.6.1, needed perform this Contract, in order to determine volumes, temperature adjustments, water and sediments content and other measures required to establish the Fiscalized Production.
5.1.5	Carry out all technical and administrative activities required in the evaluation, development, production and upgrading operations of Commercially Exploitable Crude Oil reservoirs, observing the provisions of sub-clauses 5.1.14, 5.1.15 and 5.1.16 of this sub-clause 5.1.
5.1.6	All rights, titles or interests involving confidential and proprietary information, including the HTL™ Technology, inventions, improvements, tests, processes, discoveries, commercial secrets or intellectual property developed or having relationship with confidential and proprietary information, will remain the property of CONTRACTOR, and this Contract does not grant any interest, license or right over such confidential information, neither implicitly or in any other manner.
5.1.7	Implement the Work Plans and the Annual Investment Budgets approved in accordance with the legal provisions and regulations in force, and meet the chronogram established by the Executive Committee in accordance to Clause 15.5.3.
5.1.8	Employ qualified personnel and use equipment, machinery, materials and technology in accordance with the generally accepted standards and practices of the national and international petroleum industry.

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5.1.9	Keep PETROPRODUCCION informed, through the Executive Committee, regarding development of all activities carried out during the life of this Contract, as established in the Rules and Regulations for Hydrocarbon Operations.
5.1.10	Deliver to PETROPRODUCCION the originals of all technical, environmental and research data, with copy to the Ministry, on the activities performed by CONTRACTOR under this Contract, in accordance with the legal provisions and regulations in force. In addition, upon termination of this Contract, CONTRACTOR shall deliver to PETROPRODUCCION any documents that are pending submittal.
5.1.11	Deliver to PETROPRODUCCION the Environmental Studies, together with the supporting documents, as set forth in sub-clause 5.1.23.3 and the supporting documents.
5.1.12	Keep accounting records of all activities performed under this Contract, accurately showing all investments, income, costs and expenses. For such purpose, CONTRACTOR shall follow the generally accepted accounting principles and procedures of the international petroleum industry, as well as the accounting regulations contained in 6, which is an integral part of this Contract.
5.1.13	Take all reasonable measures to ensure that its employees, Related Companies, subcontractors and its employees do not disclose to third parties, without PETROPRODUCCION’s prior written consent, any information generated or obtained by CONTRACTOR involving this Contract, as set forth in the provisions of Clause 16.
5.1.14	Provide to the officials authorized by the Ministry, PETROPRODUCCION, and the Armed Forces having to do with security issues and to other public officials authorized by the Ministry, the information they may need to fulfill their duties concerning this Contract.
5.1.15	CONTRACTOR may at its discretion, provide the officials mentioned in clause 5.1.14. from time to time and on a temporary and occasional basis, as required, camp facilities, transportation, food and lodging services, similar to those it provides to CONTRACTOR’s personnel, without CONTRACTOR assuming liability for any injuries or damages that such officials may suffer when using the above-mentioned facilities.
5.1.16	Save and hold harmless PETROPRODUCCION from damages, legal actions, indemnifications, costs and expenses of any nature whatsoever, it may suffer or may be required to pay, as a result of any actions or omissions imputable to the subcontractors or Related Companies of CONTRACTOR, qualified as such by final award of the Ecuadorian courts. CONTRACTOR shall notify PETROPRODUCCION regarding any legal action arising out of this Contract, where CONTRACTOR intervenes or may have to intervene, in order that PETROPRODUCCION takes the necessary measures to protect its interests. The amounts payable for any award or final administrative award of competent authority, or settlement and any other expenses arising out from such award or administrative award shall be at the CONTRACTOR’s expense.

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5.1.17	Engage, renew and keep in force the required guarantees, and obtain all insurances established by Law, the Regulations and this Contract.
5.1.18	Deliver to PETROPRODUCCION copies of all insurance policies obtained in Ecuador. In the event of insurance policies obtained abroad, CONTRACTOR shall deliver to PETROPRODUCCION the coverage certificates duly issued and executed by the insurance companies of all insurance policies where CONTRACTOR is the co-assured, duly authenticated by the corresponding Consulate of Ecuador or annotated as established by the Hague Convention.
5.1.19	Pay all taxes, fees and duties as required by the Ecuadorian legislation and regulations effective on the date this Contract is executed, or any taxes, fees and duties that may be increased in the future. CONTRACTOR shall comply with all legal requirements, especially as regards to submittal of tax returns, tax withholding, and bookkeeping.
	Notwithstanding the above, and in accordance with Article 87 of the Hydrocarbons Law, CONTRACTOR shall enjoy the rights and exemptions established in the above-mentioned regulations and the Customs Law (Ley Orgánica de Aduanas).
5.1.20	Take all necessary measures in order that subcontractors engaged by CONTRACTOR, comply with all laws, rules, regulations and provisions applicable to this Contract in the Republic of Ecuador.
5.1.21	Submit for approval of the Executive Committee the Work Plans and Annual Investment Budgets, as required by the Hydrocarbons Law and Annex 3 to this Contract. In addition, CONTRACTOR will comply with the requirements of the Dirección Nacional de Hidrocarburos and the Ministry in accordance with the Ecuadorian law.
5.1.22	CONTRACTOR shall conduct its operations in accordance with the environmental protection laws and regulations and the international agreements ratified by Ecuador. The remedial and mitigation obligations undertaken by CONTRACTOR, are defined in the Environmental Studies and the Environmental Management Plans, upon prior approval of the “Subsecretaría de Protección Ambiental” of the Ministry of Mines and Petroleum.
5.1.23	Use technologies internationally accepted in the oil industry, which are compatible with the environmental requirements of the Ecuadorian Amazon Region, both for its operations, studies, reports and putting into practice any recommendations.
5.1.23.1	Comply with the legal and regulatory provisions applicable to relationships between CONTRACTOR and the neighboring communities.
5.1.23.2	Prior to the operations start-up, PETROPRODUCCION shall carry out the Social-Environmental Audit of the Field and will submit it for review by the Ministry’s “Subsecretaría de Protección Ambiental”, establishing the current conditions in which CONTRACTOR receives the Contract Area. If the environmental audit reveals that there are environmental damages requiring remediation, it will be liable to take the corrective actions needed in coordination with the CONTRACTOR.

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5.1.23.3	CONTRACTOR undertakes to carry out the Environmental Studies and to obtain the Environmental Permits from the Ministry’s “Subsecretaría de Protección Ambiental” for all the stages included in the Development Plan, in accordance with the Substitute Regulations to the “Reglamento Ambiental para las Operaciones Hidrocarburíferas en el Ecuador” and related legislation in force. If applicable, CONTRACTOR will develop a plan for delivery and/or abandonment of the area.
5.1.23.4	The CONTRACTOR shall be liable to engage Environmental Audits for the Contract Area, as established in the Substitute Regulations to the “Reglamento Ambiental para las Operaciones Hidrocarburíferas en el Ecuador”. Prior to termination of the Contract herein, the CONTRACTOR shall engage an Integral Environmental Audit for the Contract Area, which shall conclude no later than six months prior to termination of this Contract. The cost of these audits shall be borne by CONTRACTOR. These audits are aimed at establishing whether the environmental management plans approved by the Ministry’s “Subsecretaría de Protección Ambiental” were met, and its recommendations will be binding.
5.1.23.5	Employ skilled personnel and use adequate equipment, machinery, materials, operational procedures and technologies that meet environmental protection standards and practices of the international hydrocarbons industry, without prejudice of its liability to comply with the Ecuadorian rules and regulations currently in force.
5.1.23.6	CONTRACTOR undertakes to comply with the Environmental Management Plans and to keep the oil field in the best social-environmental conditions, as set forth in the Substitute Regulations to the “Reglamento Ambiental para las Operaciones Hidrocarburíferas en el Ecuador”. In the event of Final Abandonment, the CONTRACTOR will recover and rehabilitate the area in which it operated, by remedying the environmental damages caused by its operation of the Field.
5.1.23.7	Cooperate with Government Entities in charge of sustainable development for the area in which CONTRACTOR operates, as required by Law. However, CONTRACTOR shall not be liable for environmental damages caused to the oil fields by area inhabitants, settlers or third parties.
5.1.24	Deliver to PETROPRODUCCION at the date of termination of this Contract, at no charge and in good conditions, except the normal wear, all wells, goods, facilities, equipment and infrastructure works that exist in the Contract Area. It is hereby agreed that the specific services rendered under this Contract do not imply any transfer of technology — know how - nor the total or partial assignment of the rights inherent to invention patents of the HTL™ process, which are exclusively owned by IVANHOE ENERGY ECUADOR INC and its Related Companies. Therefore, the Ecuadorian Government hereby agrees to abide by such rights, including all those of the International and Regional Agreements and the local legislation on intellectual property rights.
	As of the date in which the delivery referred to in this clause takes place, PETROPRODUCCION will assume full and total responsibilities over said wells, goods, facilities, equipment and infrastructure.

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5.1.25	Comply with the Work Plans and Annual Investment Budgets.
5.1.26	Give priority to the procurement of goods and services to those produced in Ecuador or which are supplied by Ecuadorians, provided that such goods and services have equivalent quality, price and availability, at the time and in the quantities required.
5.1.27	Maintain the roads used by CONTRACTOR to reach the Contract Area during the life of this Contract. PETROPRODUCCION will reimburse the maximum amount for such purpose. Delivery of this amount will take place, provided that there are works that need to be performed as set forth in this sub-clause, in which case the amount will not exceed $200,000 Dollars per year.
5.1.28	Receive up to five (5) outstanding students or graduates from hydrocarbon industry-related technical schools, for two months per year in the Contract Area in the offices of the CONTRACTOR in Ecuador, and will assume the risks and costs for transportation, food and lodging, and minor health and emergency medical care of such students. For such purpose, the Internships Act (Ley de Pasantías) will apply. Transportation, food and lodging, and the medical care previously mentioned shall be provided in equal conditions to those of the CONTRACTOR’s personnel in Ecuador. The Executive Committee will determine the duration of said practices and studies and the number of students, in such way as not to interfere with the activities performed by CONTRACTOR. It is hereby agreed that there will be no labor relationship between CONTRACTOR or PETROPRODUCCION and the students; however, students shall comply with all rules and regulations applicable in the Contract Area, especially as regards to industrial safety. CONTRACTOR shall not be liable for the students’ risks, but will provide accident insurance during the practices, with similar coverage as that of its regular workers performing similar tasks. In addition, CONTRACTOR will provide students with a monthly financial aid, in an amount equivalent to the salaries of its regular workers doing similar jobs. PETROPRODUCCION may not nominate or propose any candidates for the internships and is expressly prohibited to nominate any relatives of its officials up to second degree by marriage and fourth degree by blood relation.
5.1.29	Deliver all original documents or certified copies of all information arising from performance of this Contract, including the geological, geophysical, petrophysical and engineering data, well completion records and reports and any other data created and compiled by CONTRACTOR during the life of this Contract.
5.1.30	During Stage 3 of the Project, CONTRACTOR to deliver crude oil that exceeds 21° API with viscosity below 200 cts at 60° C, if supported by technical and financial results from oil and reservoir evaluation studies performed in Stages 1 and 2. In the event the resulting crude oil quality is lower than 21°API the Executive Committee will define the production conditions most beneficial for the interests of the Parties, based on prevailing technical and financial conditions.

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5.2	PETROPRODUCCION OBLIGATIONS: In addition to the obligations set forth in this Contract, PETROPRODUCCION undertakes to:
5.2.1	Pay CONTRACTOR for the services rendered, in the amounts set forth in Clause 9 of this Contract.
5.2.2	Satisfy promptly, through the Executive Committee, any requests or requirements of CONTRACTOR, and, if applicable, issue the corresponding observations and approvals as established in this Contract, in order that CONTRACTOR may comply within its terms and conditions. PETROPRODUCCION shall answer all requests, proposals or requirements within the terms or periods established for each case under this Contract, or within 15 days, in the event that a term is not specified herein.
5.2.3	Process or approve permits, in order that CONTRACTOR obtains the required approvals from the Ministry, as required by the Executive Committee, in order to comply with the Purpose of this Contract.
5.2.4	Give prior clearance in order that the Ministry of Finance and Public Credit levies from customs duties and other taxes the import of goods needed to perform this Contract.
5.2.5	Provide CONTRACTOR with the information and technical data, as well as with any other information required by CONTRACTOR, which may serve to support the operations in the Contract Area. The costs incurred to reproduce such materials will be borne by CONTRACTOR.
5.2.6	Notify CONTRACTOR as soon as it receives any claim or legal action that may affect CONTRACTOR, in order that CONTRACTOR may take measures to protect its interests.
5.2.7	Cooperate and coordinate with CONTRACTOR reasonable safety measures to carry out the operations under this Contract.
5.2.8	Provide information, approvals or documentation required for issuance of visas, resident permits and work permits to foreign personnel of CONTRACTOR and its subcontractors to carry out activities directly related with the performance of this Contract in Ecuador. However, CONTRACTOR shall be responsible for the corresponding administrative formalities.
5.2.9	Request and obtain from the Ministry, upon prior declaration of public use, the expropriation of land or real property, or the rights-of-way in benefit of PETROPRODUCCION, required by CONTRACTOR to perform this Contract.
5.2.10	Obtain from public entities assistance and support, required by CONTRACTOR to promptly processing any licenses and permits, especially those involving land surface rights, as set forth in Article 91 of the Hydrocarbons Law for the performance of this Contract.

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5.2.11	Receive the Fiscalized Production.
5.2.12	If necessary, and upon request by CONTRACTOR, PETROPRODUCCION, through the Police Force, will provide reasonable safety conditions to perform the operations under this Contract, for a reasonable compensation that will be agreed between the Parties. PETROPRODUCCION will include in the Contractual Payment the costs incurred by CONTRACTOR. This compensation will be made in accordance with the accounting procedures in force. However, PETROPRODUCCION will not be liable if despite these safety conditions there are losses and damages to the goods or individuals involved in this Contract.
5.2.13	The CONTRACTOR shall take the necessary actions for the prompt construction a secondary pipeline for the timely removal the upgraded petroleum to the Fiscalization and Delivery Center, the cost of such secondary pipeline line will be the exclusive responsibility of the CONTRACTOR, within the scope of the Contractual Payment.
5.2.14	If the capacity of the Main Pipeline is adequate to transport the Crude Oil produced in the Contract Area, then the Crude Oil shall have access to the Main Pipeline. However, if the capacity of the Main Pipeline is insufficient, PETROPRODUCCION will ensure a share in the capacity of said Main Pipeline to move the Crude Oil from the Contract Area, equivalent to the percentage between the Production of Available Crude Oil and the total production of all areas served by this Main Pipeline.
5.2.15	In the event that there is a secondary pipeline with adequate capacity to transport the Fiscalizable Production, without need to build a new Main Pipeline, PETROPRODUCCION shall take the necessary actions, in order that the Fiscalizable Crude Oil has timely access to the secondary pipeline, upon prior agreement between the interested parties.
5.3	CONTRACTOR’S RIGHTS: CONTRACTOR shall have the following rights:
5.3.1	CONTRACTOR shall have the exclusive right to implement and conduct activities, for the purpose of this Contract in the Contract Area, with the guarantees granted by the Republic of Ecuador, including the right to do exploration in Block 20.
5.3.2	Receive the Contractual Payment, as set forth in Clause 9.
5.3.3	Use and have access to all geological, geophysical, drilling and production data, as well as any other information kept by PETROPRODUCCION involving Block 20, upon prior payment of the corresponding costs to reproduce such materials.
5.3.4	Use the existing roads, communications and transportation means or those built in the future, as well as use the water and construction materials required by its operations, as set forth by Law and by the provisions of this Contract.

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5.3.5	Use, at no charge, the Crude Oil and Natural Gas produced in the Contract Area required for its operations.
5.3.6	Arrange, together with PETROPRODUCCION the timely inclusion into national production of the crude oil produced in the Contract Area.
5.3.7	Precretaceous: This Contract does not grant CONTRACTOR any rights over the soil, subsurface or natural resources existing in the Contract Area, nor on the areas expropriated in benefit of PETROPRODUCCION under this Contract, or on the facilities constructed in the Contract Area. However, CONTRACTOR will have the right to conduct exploration drilling in the Precretaceous, and if the results are positive, the Parties will execute an agreement establishing the production conditions and payment terms.
5.3.8	The CONTRACTOR has the right to receive the monthly Contractual Payment with petroleum owned by PETROECUADOR as compensation for the amount to which it has the right to payment in money.
5.3.9	During the life of the Contract, and with the purpose of increasing crude oil production for the State, the CONTRACTOR may blend the oil produced from the Contract Area with other Available Crude Oil from the same Area, notwithstanding the API gravity.
5.4	PETROPRODUCCION’S RIGHTS: For supervision and monitoring purposes, PETROPRODUCCION shall have the following rights:
5.4.1	Review and monitor performance of technical, financial and contractual activities undertaken by CONTRACTOR, in accordance with the timetables and procedures mutually agreed by the Parties, as set forth in sub-clauses 15.2 and 19.2.
5.4.2	Request CONTRACTOR, at any time, the information and reports it may consider appropriate, for the performance of this Contract, in accordance with the applicable laws and regulations in force.
5.5	JOINT OBLIGATIONS OF THE PARTIES: The Parties hereto shall have the following joint obligations:
5.5.1	Interpret and perform this Specific Services Contract in good faith.
5.5.2	Both Parties shall meet their contractual obligations and comply with the provisions of the Hydrocarbons Law; the Special Law of “Empresa Estatal de Petróleos del Ecuador”, PETROECUADOR and its Affiliate companies; Procurement Rules for Works, Specific Goods and Services of PETROECUADOR and its Affiliate Companies; Substitute Regulations to the “Reglamento Ambiental para las Operaciones Hidrocarburíferas en el Ecuador”, and the provisions of the Contract herein.
5.5.3	Subject to the provisions set forth in subparagraphs 5.3.8 and 9.2.7 of this Contract, PETROECUADOR shall execute with CONTRACTOR or its Related Companies the corresponding Oil Purchase/Sale agreement, as applicable. The price paid by CONTRACTOR or its Related Companies shall be the Reference Price, as defined under sub-clause 3.3.41. of this Contract.

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5.6	Representations and Guarantees
5.6.1	The Parties represent and warrant that:

a)	Execution and performance of this Contract is subject to the provisions of the Hydrocarbons Law, the Special Law for PETROECUADOR and its regulations, related laws, verdict, court order or award. Therefore, their assets or any other rights derived from other contracts executed by the Parties will not be affected.
b)	Neither Party shall be liable to the other Party for administrative or judicial claims arising out from actions or omissions incurred prior to execution of this Contract.

5.7	LIABILITIES
5.7.1	Liability from the representations and guarantees delivered by the Parties for any claims shall remain and continue in force during 5 years for all claims filed within such period and notified in writing to the other Party, even if said claims have grounds for contingent damages and at such time no administrative, judicial or arbitration process was filed. In addition, the Parties shall be liable for the obligations undertaken in this Contract. CONTRACTOR shall also be liable for the obligations of its Subcontractors and Related Companies involved in activities performed under this Contract.
5.7.2	CONTRACTOR shall be liable for all operations derived from the purpose of this Contract. In addition, CONTRACTOR shall be liable to deliver production at the Fiscalization and Delivery Center, in accordance with the terms of this Contract.
5.7.3	PETROPRODUCCION shall be liable for the Fiscalized Production upon delivery by CONTRACTOR at a Fiscalization and Delivery Center, in accordance with the terms of this Contract.
5.7.4	FORCE MAJEURE OR ACTS OF GOD. Neither Party shall be liable to the other for noncompliance, interruption or delayed performance of its obligations under this Contract if such failure to comply or delay is due to duly proven Force Majeure or Acts of God. In such events, the Party affected by Force Majeure shall notify the other Party within 15 days of such occurrence
5.7.4.1	Upon notification by either Party of an event of Force Majeure or Acts of God, the other Party may accept or object it, and will observe the procedure established by the Executive Committee. The Party giving notice of Force Majeure or Acts of God may refute such objection, using the resources established in this Contract or the Law. The objection of Force Majeure will not interfere with the development of the Contract activities.
5.7.4.2	The Party alleging Force Majeure or Acts of God shall prove the occurrence of such events. If PETROPRODUCCION alleges Force Majeure, such Force Majeure must have the approval of its Vice-President.

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5.7.4.3	If during an event of Force Majeure or Acts of God there is any remaining Fiscalized Production, CONTRACTOR shall be entitled to receive the Contractual Payment for the activities already performed, as set forth in Clause 9. The obligations set forth in Clause 9 shall not expire due to occurrence of Force Majeure or Acts of God.
5.7.4.4	The occurrence of Force Majeure or Acts of God may require review of the work schedule proposed by CONTRACTOR according to Annex 5, notwithstanding its right to resume performance of its obligations as soon as reasonably feasible. The obligations not affected by Force Majeure or Acts of God shall be fulfilled in accordance with the provisions of this Contract.
5.7.4.5	In the event of Force Majeure or Acts of God, CONTRACTOR shall notify PETROPRODUCCION within 15 days of such occurrence and will make every effort to resume operations as soon as feasible.
5.7.4.6	Upon overcoming the Force Majeure or Acts of God, CONTRACTOR shall justify within 15 days to PETROPRODUCCION the number of days during which activities were interrupted due to such events.
5.7.4.7	If CONTRACTOR deems that the Force Majeure or Acts of God need immediate action, CONTRACTOR will take all necessary measures and incur in all the expenses required to protect its interests and those of PETROPRODUCCION and their respective workers, even if such expenditures were not included in the Annual Program and Budget for the corresponding Fiscal Year. The actions taken shall be reported to PETROPRODUCCION for its information within 10 days.
	The unforeseen expenses referred to in the preceding paragraph shall be deemed as costs and expenses, as the case may be, as established in the accounting procedures. Such expenses will be included in the Contractual Payment and will require approval by the Executive Committee.
5.7.4.8	The time of interrupted activities due to Force Majeure or Acts of God shall be excluded from the term to comply with the Work Plans and Annual Investment Budgets. Consequently, the timetables established in this Contract shall be extended in a period equal to the duration of such Force Majeure or Acts of God.
	If appropriate and at the request of CONTRACTOR, Police support may be requested to safeguard the personnel that is working at the facilities, as well as the property and goods of the Affiliate Company and CONTRACTOR, in which case. PETROPRODUCCION will provide the necessary assistance.

CLAUSE 6: CONTRACT TERM

6.1 This Contract will enter into force on the Effective Date established in sub-clause 3.3.19 and will have a duration of 30 years. This term may be extended for two additional periods of five years each, by mutual agreement of the Parties. In the event of unilateral early termination, CONTRACTOR shall have the right to obtain reimbursement of all the investments, costs and expenses, and to receive payment for the services actually performed that are pending payment.

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CLAUSE 7: PLANS, WORK PROGRAMS AND ANNUAL INVESTMENT BUDGETS

7.1	Work Programs and Annual Investment Budgets. CONTRACTOR will submit for PETROPRODUCCION,s approval, through the Executive Committee, the committed Work Programs and their respective Annual Investment Budgets, which will include quarterly breakdown estimates for reference purposes.
7.1.1	Contractor will submit to the Executive Committee the Work Programs and Annual Investment Budgets referred to in the preceding paragraph by September 30 of the Fiscal Year prior to which the Work Programs and Annual Investment Budgets will be implemented. In addition, within the first 30 days of the following Fiscal Year, CONTRACTOR will submit to the Executive Committee a report on the activities performed during the previous Fiscal Year and the corresponding budget implementation.
7.1.2	As regards to the first year of this Contract, the Work Program and Annual Investment Budget shall be submitted to the Executive Committee for the time that remains until the end of that Fiscal Year and, if execution of this Contract takes place after October 31, the Work Plan and Annual Investment Budget shall be added to the next Fiscal Year.
7.1.3	CONTRACTOR may amend the current Work Plans and Annual Investment Budgets upon prior approval of the Executive Committee.

CLAUSE 8: PRODUCTION RATE

8.1

Prior to the date an oil reservoir begins production, CONTRACTOR shall submit the proposed Production Rate to PETROPRODUCCION, through the Executive Committee, in order that PETROPRODUCCION submits it to the Ministry of Energy and Mines for its approval. The Production Rate shall use as basis conventional studies or oil reservoir simulations, in accordance with the provisions of Executive Decree 543, published in Official Register 135 dated March 1, 1985, including the Technical Criteria to Calculate Production Rates, as established by the “Dirección Nacional de Hidrocarburos” and the Rules and Regulations for Hydrocarbon Operations.

8.2

Early Production. Early production of Crude Oil that CONTRACTOR may produce and PETROPRODUCCION will accept and deem as test production to determine the reservoir features and production rates. PETROPRODUCCION agrees to take the full volume of such Available Crude Oil under the terms of this Contract. PETROPRODUCCION will accept the income obtained from the sale of such production to pay CONTRACTOR the Contractual Payment, as set forth in Clause 9 of this Contract. The early production of Crude Oil shall be valued at the Reference Price.

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8.3

Maximum Production Rate Allowed. In accordance with the provisions of Executive Decree 543 and the Technical Criteria to Calculate Maximum Production Rates, the Ministry shall establish the Maximum Production Rate Allowed. This rate may be reviewed every Fiscal Year, by following the above-mentioned procedure. Until the Ministry establishes the Maximum Production Rate Allowed, CONTRACTOR will use the rate proposed by it, in accordance with the provisions of Article 2 of Executive Decree 543. The cost and difficulties of developing and producing heavy oil, as well as installation and utilization of the HTL™ Technology to upgrade the volume and quality of heavy Crude Oil require that the production of Crude Oil reservoirs be at the Maximum Efficient Rate, in order for the project to be profitable and obtain optimum benefits from the unique HTL™ Technology.

8.4

CONTRACTOR may propose, at any time, to PETROPRODUCCION, through the Executive Committee, to review the Maximum Allowable Production Rate for each well, reservoir or oil field, due to unexpected changes in production or reserve updates, based on conventional studies or reservoir simulation studies. In turn, PETROPRODUCCION will request the Ministry to review the proposal, in accordance with the procedure set forth in sub-clause 8.1.

CLAUSE 9: CONTRACTUAL PAYMENT AND PAYMENTS TO CONTRACTOR

9.1	During the life of this Contract, CONTRACTOR will receive payment every month (Contractual Payment). Such payment will be calculated taking into account the number of Fiscalized Production barrels produced in Block 20 during that month. The Contractual Payment includes Investments, Costs, Expenses and CONTRACTOR Profits.
9.1.2	During the life of this Contract, the Contractual Price will be calculated by multiplying the number of Fiscalized Production barrels for the corresponding month (the Month of Payment) for an amount per barrel of thirty-seven United States dollars (US$37.00) (the Contractual Price). Such amount will be adjusted quarterly as of the effective date of this Contract. The formula to adjust the Contractual Payment is detailed in Clause 9.1.2.1 and is based on the quarterly weighted average changes in a basket of Producers Price Index (PPI), published by the US Department of Labor, the Labor Statistics Unit, and the Indexes (Adjustment Indexes) for the calendar quarter immediately preceding the Quarter in which the Effective Date occurred (Reference Quarter), and the calendar quarter immediately before the month of payment (Payment Quarter) to be invoiced.
9.1.2.1	Payment Formula — Contractual Payment Formula

Definitions:

Reference Quarter: Calendar quarter immediately before the month in which the Effective Date of this Contract occurred

Payment Quarter: Calendar quarter immediately before the month for which CONTRACTOR will invoice for the Fiscalized Production

Payment Month: The calendar month for which the Contractual Payment amount is established

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CPP: Contractual Payment agreed under this Contract

CPPc: Actual Contractual Payment applicable to the Fiscalized Production invoiced for the corresponding month

AI: Adjusting Index — Actual escalation adjustment of the CPP that will make it applicable for the Payment Month, AI x CPP = CPPc, and to be multiplied by the amount of Fiscalized Production to be invoiced in that month. The Adjusting Index is equal to the weighted sum of the Delta PPIs for three commodities.

PPI: Producers Price Index for commodities, US Department of Labor, Bureau of Labor

PPI_s = Metals & Metal Products, Steel Mill Products
PPI_m = Field Machinery & Equipment for the Oil and Gas Industry
PPI_r = Petroleum Refineries

WF_s = Weighting Factor for the PPI_s
WF_m= Weighting Factor for the PPI_m
WF_r = Weighting Factor for the PPI_r

Where: WFs = 0.45; WF_M = 0.35; WF_R = 0.20

Delta PPI I for any of the three commodities ,is the change in PPIs calculated as the ratio of the current average PPI’s for the weighted Quarter prior to the month of the corresponding Fiscalized Production (Payment Quarter), divided by the average PPI’s for the Quarter preceding the month in which the Contract’s Effective Date (Reference Quarter). The PPI indexes for any Quarter will be the weighter arithmetic average of the PPI’s for the three months in that quarter. A Quarter means a calendar quarter, i.e., January, February & March (first Quarter), April, May and June (second Quarter), etc.

Application of Payment Formula to Determine the Contractual Price for the Month of Payment:

IA = [(WF_s) x (Delta PPI_s)] + [(WF_m) x (Delta PPI_m)] + [(WF_r) x (Delta PPI_r)]

ACTUAL CONTRACTUAL PAYMENT FORMULA

CPPc = CPP (IA)

Upon completing the construction of the last HTL plant, and after the CONTRACTOR has recovered its investment, the adjustment formula will include only the following indices:

WFs = Weighted Factor for the PPIs
WF_M = Weighted Factor for the PPI_M

Where: WFs = 0.50; WF_M = 0.50

Application of the payment formula to determine the Contractual Payment for the Month of Payment:

IA = [(WF_s) x ( Delta PPIs) + [(WF_M) x ( Delta PPI_M)]

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CONTRACTUAL PAYMENT FORMULA

CPPc = CPP {IA}

9.1.2.2	The Contractual Price will also be adjusted as established in Clauses 9.2.10 and 9.3.11, and other provisions of the Contract herein.
9.1.3	If during the life of this Contract any of the indexes mentioned in the preceding clause are no longer published by the United States Department of Labor, the index/indexes no longer published will be replaced with similar indexes published by the Government of the United States of America or any renowned organizations of the industry, as references for cost variations in the United States of America, or which are used by the industry as equivalents of such.
9.1.4	In accordance with the provisions of Article 17, Hydrocarbons Law, PETROPRODUCCION and the CONTRACTOR agree that the form of payment, will be in money. Nevertheless, the payment obligation may be satisfied through compensation of the value of the payment in petroleum.

PAYMENT PROCEDURE

9.2	Trust Fund: PETROECUADOR shall create a Trust Fund to pay CONTRACTOR, equivalent to not less than 35% or a sufficient amount to pay the CONTRACTOR, from the monthly income arising from sales of crude oil produced in the Contract Area. The Payment to which CONTRACTOR is entitled under the terms of this clause will be paid with funds from this Trust Fund, in accordance with the payment schedule established in this clause.
9.2.1	If payment takes place with Crude Oil, as set forth in the previous paragraphs the value of the amount of the corresponding crude oil will be deducted from the Trust Fund.
9.2.2	The Trust Fund shall be created through the Central Bank of Ecuador, between PETROECUADOR and the Ministry of Economy and Finance. Its purpose will be to ensure payment to CONTRACTOR of all obligations derived from this Contract.
9.2.3	Payment to CONTRACTOR from the Trust Fund Account shall take place monthly, upon submittal of the invoice for the quantity of Fiscalized Production during the applicable month. Invoices shall be submitted together with the details of the Fiscalized Production, and shall be paid upon verifying that all data is correct. Invoices will be submitted within the first ten calendar days of each month for the preceding month. Invoices will be paid within 30 calendar days following its submittal, and payment will be made through bank transfer to the account notified by CONTRACTOR, using funds from the Trust Fund created for such purpose. Failure to pay the invoices within 30 days from their submittal will accrue interests, as fixed by the Central Bank of Ecuador, until payment is made.

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9.2.4	If in any month during the life of this Contract, the Contractual Payment exceeds the amount allocated to CONTRACTOR through the Trust Fund for Contractual Payments during that month, PETROPRODUCCION and/or PETROECUADOR will pay CONTRACTOR the surplus amount with public funds, in the subsequent month or months, until the full amount is paid.
9.2.5	In the event that CONTRACTOR is unable to collect payment for the services rendered under this Contract, CONTRACTOR will not lose its rights to recovery and may exercise its rights to claim such payments, even if the Contract herein is terminated for any reason whatsoever.
9.2.6	If PETROECUADOR allocates the Production to the domestic market, sales will be valued at the International Market Price, FOB Balao main port.
9.2.7	In case that the value corresponding to the Contractual Payment established in this Contract, is compensated in crude oil, this will correspond to the sales price that PETROECUADOR applies to the crude oil of similar characteristics and shall be the Reference Price FOB port of Balao.
	In addition, CONTRACTOR shall have the option to buy RTP product, available crude from the Contract Area and other Crude Oil on equal conditions to those used by PETROECUADOR for sales to other companies, complying with the then existing legal norms and procedures.
9.2.8	All crude oil received by CONTRACTOR as the contractual payment will be valued based on quality, volume and selling terms, to ensure that CONTRACTOR receives the value it would have received had the invoices been paid with cash. Payment of interests may also apply in the event of delivery delays by PETROPRODUCCION, as set forth in Clause 9.2.11.
9.2.9	Lifting procedures will include, among other issues, volumes, quantities, crude oil lifting schedules (including timely notices, tolerance levels for operational reasons and other delivery conditions, categories, loading hour free of charge, penalties for delayed lifting and other charges attributable to PETROPRODUCCION).
9.2.10	Adjustment: The Contractual Payment to which CONTRACTOR is entitled to will be adjusted using as basis the adjustment factors set forth in sub-clause 9.1.2.1. Likewise, CONTRACTOR shall be entitled to adjustments of the Contractual Price in any of the following events: (i) Tax system changes or modifications, including the VAT, which may have an impact on CONTRACTOR; (ii) modifications in the labor share effective at the time this Contract is signed; (iii) modification of the currency system changes, as described in sub-clause 13.4; (iv) Changes/restrictions established by the National Hydrocarbons Administration in the production rate, negatively affecting the economics of this Contract; (v) Changes in the amortization formula established in the Accounting Procedures, in which case any adjustments will be proportionate to the impact of such events over the economy of this Contract.

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9.2.11	Interests: After 45 days following the date in which payment is due to CONTRACTOR, PETROPRODUCCION will pay CONTRACTOR interest for the period of delay, calculated at the Legal Interest Rate effective in Ecuador on the date of payment. If the Contractual Payment will be compensated with Crude Oil, interest will accrue from the scheduled lifting date and in accordance with the lifting agreement, until the date in which the Fiscalized Production received by PETROPRODUCCION is available to CONTRACTOR, for lifting. Delayed payments will accrue interests as of the 46th day (inclusive) from submittal of the corresponding invoice and supporting documents. Interests will not be paid during any periods of Force Majeure or Acts of God that hinder PETROPRODUCCION from making the payments agreed under this Contract.
	If the delayed payment is due to Force Majeure or Acts of God, PETROPRODUCCION shall not be liable to pay interest for delayed payment.
9.2.12	During the life of this Contract, not withstanding the payment of the contractual service, and the international market price for the crude oil , the State will not receive less than 20% of the gross income generated from the sale of this crude oil.:
	If the international market conditions improve in the future, the CONTRACTOR will be entitled to recover the difference of the agreed price for the contracted services, except for the early production crude which the CONTRACTOR shall not recover the difference in the contractual payment.
9.2.13	Economic Equilibrium PETROPRODUCCION or the CONTRACTOR shall have the right to propose to the other Party adjustments necessary when due to special circumstances in the international market, or the prices of goods and services having relationship with the hydrocarbons industry and emergency situations unforeseen under this Contract, negatively affect the economic equilibrium of this Contract, for which effect, after reaching an agreement must sign the corresponding document, with agreed economic adjustments.

INVOICING

9.3	Payment Procedure: CONTRACTOR will submit monthly one or more invoices for the Contractual Payment applicable to the previous month, in accordance with the procedure established in this clause.
9.3.1	Issuance of Invoices: All invoices shall be issued to EMPRESA ESTATAL DE EXPLORACION Y PRODUCCION DE PETROLEOS DEL ECUADOR, PETROPRODUCCION, as established in Annex 2 to this Contract
9.3.2	Payment Objections: PETROPRODUCCION may object an invoice, only for calculation errors.
9.3.3	CONTRACTOR will cancel the invoice objected to and will immediately issue a new invoice.
9.3.4	Objections by PETROPRODUCCION to any invoice shall not prevent CONTRACTOR from submitting other invoices and receive Contractual Payments to which it is entitled on the terms established under this Clause.

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9.3.5	PETROPRODUCCION shall pay the full amount of the corresponding invoice within a period of up to 45 days from its submittal.
9.3.6	EMPRESA ESTATAL PETROLEOS DEL ECUADOR, PETROECUADOR, shall be jointly liable with PETROPRODUCCION for all payments to CONTRACTOR.
9.3.7	In the event that an invoice is not paid within the established periods, the provisions of Clause 9.2.11 shall apply.
9.3.8	The interest of the compensation, when this option has been agreed upon as a payment option, will be paid in accordance to Clause 9.2.11.
9.3.9	Gross Income of CONTRACTOR: The revenues obtained by CONTRACTOR through the Contractual Payment shall represent the gross income of CONTRACTOR. If payment by PETROPRODUCCION is in kind (with crude oil), the CONTRACTOR will register the invoice amount in its accounting records and such amount will be the gross income of CONTRACTOR, regardless of the final value of the goods actually received.
	For tax payment purposes, reimbursements of costs, expenses and investments will be deducted from each invoice, in order that the tax base reflects the CONTRACTOR’s profit.
	Costs, expenses, payments and investments included in the Contractual Payment shall not be subject to payment of income tax and may be deducted as provided in Ecuadorian legislation.
9.3.10	Reference Price: The reference price shall be the one defined in sub-clause 3.3.41. In the event that PETROECUADOR did not make external sales during the previous calendar month, the Reference Price will be established using as basis a basket of international crude oil with similar features, as agreed by the Parties, and prices will be obtained from renowned and specialized publications, such as PLATTS or similar publications. The Reference Price will be FOB Balao Ecuadorian Port (export terminal), in Dollars per Barrel.
	Procedure: Prices of the crude basket components and the average freight price, when expressed in FOB terms, Ecuadorian Port, shall be obtained from specialized and renowned publications, such as PLATTS or similar publications, within two days from its publication prior to the date of Crude Oil sales, and two days after the date of the Crude Oil sales. If the sale is on a Sunday or Monday (where there are no publications), the publication to be used will be that of the two days immediately before and three days after the date on which the Crude Oil was sold. If the Crude Oil sale takes place on a Saturday or on a day when there are no publications (except Sunday or Monday), the publications to use will be those of three days before, and two days after the date of the Crude Oil sale.
9.3.11	As established in Article 5 of the “Reglamento Sustitutivo del Reglamento Ambiental para las Operaciones Hidrocarburíferas en el Ecuador”, if there are ecologically sensitive or culturally vulnerable areas that vary the technical and financial conditions of hydrocarbon operations, PETROPRODUCCION and CONTRACTOR shall explore ways to solve the situation and reestablish the original terms of this Contract or shall amend it by mutual agreement. In the event that PETROPRODUCCION and CONTRACTOR are unable to find a solution acceptable to both parties, the conflict will be solved in accordance with the procedures set forth in this Contract.

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PENALTIES

9.4	Delayed compliance or breach of any provisions in this Contract will give PETROPRODUCCION the right to charge CONTRACTOR a penalty equivalent to 0.01% over the portion not performed in the development plan approved for the corresponding fiscal year.
9.4.1	Prior to applying a penalty for noncompliance ANY OBLIGATIONS under this Contract, the corresponding Department will notify CONTRACTOR in writing and will attach the “Fines Form”, within 5 calendar days from having knowledge of such noncompliance.
9.4.2	Upon receipt of notice, CONTRACTOR will have 15 Business Days to justify the noncompliance, and after that period, the Contract Administrator will apply or cancel the penalty, notifying the CONTRACTOR in writing within the next 5 days upon completion of the period granted to justify such noncompliance.
9.4.3	However, CONTRACTOR may submit the issue within 15 calendar days to the Executive Committee, which will take a decision in a period of five calendar days. After completing this procedure, CONTRACTOR may submit the issue within five calendar days to the Vice-President of PETROPRODUCCION, who will take a decision in 10 calendar days.
9.4.4	Penalties will not apply to events of Force Majeure or Acts of God, or in the event that PETROPRODUCCION experiences delays in fulfilling its obligations under this Contract and those foreseen in Ecuadorian Legislation, duly approved by CONTRACTOR and accepted by PETROPRODUCCION.
9.4.5	PETROPRODUCCION may collect the penalties imposed on CONTRACTOR either from: (i) the invoices payable to CONTRACTOR; (ii) the Performance Bond, in the portion proportional to the penalties.
9.4.6	In the event that the penalties imposed to CONTRACTOR reach 20% of the total value of the Contract, PETROPRODUCCION will have the right to unilaterally terminate this Contract.
	The total value of this Contract amount represents the sum of the financial commitments undertaken and estimated for all stages under this Contract.

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CLAUSE 10: GUARANTEES AND INSURANCE

10.1	Guarantees: CONTRACTOR shall deliver to PETROPRODUCCION the following guarantees:
10.1.1	Joint Guarantee: Prior to execution of this Contract, CONTRACTOR shall submit a joint guarantee issued by its Parent Company for the activities and investments that CONTRACTOR undertakes to perform during each Stage. The text of such guarantee will be an integral part of this Contract and is included herein as Annex 7.
10.2	Insurance: From the Effective Date of this Contract, CONTRACTOR will be solely liable to maintain all the necessary national and international insurance policies. These insurance policies will abide by Ecuadorian Law and will be based on generally accepted practices in the international petroleum industry. Assets located within the country shall be insured in the Ecuadorian Insurance market, except where coverage for specific risks is not offered locally, in which case insurance may be arranged abroad. PETROECUADOR may assign the coverage of its current insurance policies by transferring the proportional cost of the applicable insurance premiums. The CONTRACTOR may accept, at its discretion, all or part of the insurance coverage offered by PETROECUADOR.
10.2.1	CONTRACTOR shall either arrange for PETROPRODUCCION to be an additional insured party or endorse the insurance policies established by law and this Contract to PETROPRODUCCION.
10.2.2	The property and Fixed Assets referred to in this Contract shall be insured until such property and Fixed Assets are delivered to PETROPRODUCCION.
10.2.3	CONTRACTOR agrees to arrange and maintain insurance policies with public liability coverage for any direct or indirect material damages to third parties, which may arise from performance of this Contract. The CONTRACTOR undertakes to save and hold harmless PETROPRODUCCION from any claim involving loss or damage to third parties by CONTRACTOR, during the performance of this Contract.
10.2.4	In the event of loss or damage, the indemnifications paid by the insurance companies shall be paid to CONTRACTOR and will serve to immediately replace the damaged, destroyed or stolen property or facilities, as well as to cover any underinsurance, if any.
10.2.5	CONTRACTOR shall require all its insurers to include a specific clause in all policies, waiving their right of subrogation against PETROPRODUCCION.
10.2.6	CONTRACTOR shall provide PETROPRODUCCION sufficient proof that the national and international insurance companies are duly covered by the required reinsurance.
10.2.7	CONTRACTOR shall maintain current all the insurance policies, at commercial value updated annually.
10.2.8	Indemnifications and replacement of underinsured property due to damages shall be the exclusive responsibility of CONTRACTOR, and will be covered as soon as possible by CONTRACTOR.

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10.2.9 CONTRACTOR is required to obtain and maintain valid at least the following insurance policies:

• FULL OIL INDUSTRY RISK COVERAGE FOR CONTRACT ACTIVITIES

• PUBLIC LIABILITY INSURANCE

• FIRE INSURANCE

• ELECTRONIC EQUIPMENT INSURANCE

• PERSONAL INJURY AND LIFE INSURANCE

	CONTRACTOR is required to obtain “Blow Out Insurance, cratering, Well Cost Control and Drilling Expenses.
10.2.10	Environmental Pollution and Damage Insurance: CONTRACTOR shall obtain, at PETROPRODUCCION’s satisfaction, the Environmental Damage and Pollution Insurances, in accordance with International petroleum Industry practices, which are included in the public liability insurance policy of CONTRACTOR.
10.2.11	The Parties may agree, in the future, to obtain additional insurance coverage for other risks involving the execution of this Contract.
10.2.12	CONTRACTOR may, at its discretion, obtain the additional insurance coverage it may deem necessary for its activities
10.2.13	Performance Bond - CONTRACTOR will deliver in favor of PETROPRODUCCION for each year of the first five years of the Contract term, a performance bond for the faithful performance of the investment commitments for the respective fiscal year, which will be inconditional, irrevocable and for immediate collection. The performance bond will be issued by a financial entity established in Ecuador, in an amount equivalent to 5% of the planned investments for the corresponding fiscal year. The performance bond will be returned to CONTRACTOR upon completing its obligations for the Fiscal Year, and CONTRACTOR will deliver a new performance bond for each of the of the subsequent years. This procedure is used in view that the Contract herein is for an undetermined amount.

CLAUSE 11: CONTRACT AMENDMENTS

11.1

This Contract may only be amended by mutual agreement of the Parties, and upon prior approval of the Contracting Committee. In the event of changes in the applicable legislation, which may impact the financial terms of this Contract, and without limiting the provisions of the following bodies of law: “Ley Orgánica de Equidad Financiera” and its Regulations, Tax Code, Social Security Law, Municipal System Law, Labor Code, the Parties agree to reflect such deviations as correction factors, or through an amendment to this Contract.

11.2

In case of increases in the costs, expenses and investments the economic model of the CONTRACTOR (Annex 5), such costs, expenses and investments shall be recovered by the CONTRACTOR through the signature of a complementary contract.

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CLAUSE 12: TAXES, LIENS, LABOR SHARE AND CONTRIBUTIONS

12.1	Tax System and Labor Share. CONTRACTOR shall pay income taxes, in accordance with the provisions of the “Ley Orgánica de Régimen Tributario Interno” and other applicable rules. CONTRACTOR may deduct its investments, costs and expenses by following the legal framework that is currently in force in Ecuador. Therefore, said items will not be subject to payment of income taxes, in the event that after execution of this Contract, changes occur in the Tax System whereby the investments, costs and expenses of CONTRACTOR are deductible. CONTRACTOR will have the right as of that date to automatically include a correction factor in the payment term, in order to offset the impact of the changes made in the tax regulations.
	CONTRACTOR shall pay its workers all contributions and the labor share established in the Codified Labor Code, which is currently equivalent to fifteen (15%) per cent.
12.2	The CONTRACTOR will comply with the current rules and regulations for issuance of sales receipts and tax withholding, as established by the Internal Revenue Service.
12.3	Tax on Total Assets: CONTRACTOR shall pay, as applicable, the Municipal tax equivalent to 1.5 per thousand on total assets, as set forth in Item III of the “Ley de Control Tributario y Financiero”.
12.4	Contribution to the “Superintendencia de Compañías” (Companies Examiner Office). CONTRACTOR shall pay, as applicable, the annual contribution of one per thousand on total assets, as set forth in Article 455 of the Codified Corporations Law in accordance with the procedure established by the “Superintendente de Compañías”.
12.5	CONTRACTOR shall pay, if applicable, the tax set forth in Law 122, its interpretative law and amendments.
12.6	Notary costs shall be borne by CONTRACTOR, as well as the cost of obtaining 10 certified copies of this Contract for delivery to PETROPRODUCCION.
12.7	Under this Contract, the Income Tax applicable to CONTRACTOR shall be 25% over the disposable base, with no additional charges.
	In addition, CONTRACTOR may resort to all tax benefits with financial-economic effect established in the tax laws and its current or future regulations, including the income tax reduction due to reinvestment of profits.
12.8	CONTRACTOR will issue invoices to PETROPRODUCCION as established in Clause 9, adding the VAT rate to each invoice.
	In view that CONTRACTOR sales will be to the public sector and in the name of PETROPRODUCCION and that CONTRACTOR will not be able to compensate the Value Added Tax paid in all its purchases or the tax withholdings made, CONTRACTOR shall have the right to obtain from the Internal Revenue Service reimbursement of the tax credit through the corresponding credit note, check or payment with other obligations of the State.

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12.9

Tax System Changes. If the tax system is amended, including the VAT, and changes cannot be deemed as a tax credit or credit for profit sharing on the date this Contract is executed or its interpretation, and which affect the economics of this Contract, the Party affected shall have the right to include, by mutual agreement, a correction factor or an adjustment to the Contractual Payment, in order to absorb the increase/decrease of the tax/labor burden.

12.10

Payment in Kind. When the payment is in a value other than money or legal currency, the CONTRACTOR, that is to say is paid debt of PETROPRODUCCION the value of such invoice will be the only amount registered in the accounts of CONTRACTOR, regardless of the value these payments may reach.

CLAUSE 13: FOREIGN EXCHANGE CONTROL

13.1	Foreign currency will be subject to the provisions of the Political Charter, the Monetary Law and the regulations issued by the Central Bank of Ecuador, by virtue of which CONTRACTOR will have the right to freely dispose of the foreign currency resulting from the Contract Payment.
13.2	Likewise, CONTRACTOR will have the right to maintain, control and operate bank accounts in any currency within the country or abroad, have control and use said accounts; and maintain and use the funds of such accounts abroad, without any limitation whatsoever, in view that all transactions under this Contract will be in Dollars of the United States of America.
13.3	Notwithstanding the above, CONTRACTOR will have the right to freely dispose of, distribute, send or maintain abroad, with no restriction whatsoever, any and all amounts received by CONTRACTOR under this Contract, including its annual net profits, after all legal and tax deductions established in the laws of Ecuador.
13.4	The Bank Board regulations of the Central Bank of Ecuador or other government entities may not alter the obligations and rights of the Parties derived from this Contract. If new regulations are issued that affect the CONTRACTOR’S rights or obligations, impose exchange quotas or otherwise, provided in this Clause, which have an impact on the Contractual Payment, a correction factor will be included in order to offset the economic or financial burden to the CONTRACTOR.

CLAUSE 14: ACCOUNTING

14.1 The CONTRACTOR must keep accounting records for this Contract, subject to the hierarchy and priority of the following legal instruments: “Ley Orgánica de Equidad Tributaria” and its regulations; this Contract; and the generally accepted accounting practices of the international petroleum industry; and the Accounting Rules issued by PETROECUADOR and the Dirección Nacional de Hidrocarburos For all legal, accounting, tax and financing effects, the CONTRACTOR shall register in its accounts as a credit in the amount of the payment, only when it is made in a cash payment.

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14.2 The CONTRACTOR will use in its accounting records account codes, systems and accounting procedures generally accepted in the oil industry. Double entry bookkeeping principles will be used, based on earnings. The bookkeeping will be in US Dollars. The accounting procedures are attached to this Contract as Annex VI.

CLAUSE 15: OPERATIONS

15.1	The Parties designate the CONTRACTOR, IVANHOE ENERGY ECUADOR INC. as the party responsible to perform all the operations, directly or indirectly, relating the the operations of development, production and upgrading, in the Contract Area, which includes the Pungarayacu Field, from the date this Contract is signed and from the Effective Date, as well as during the life of this Contract.
15.2	CONTRACTOR will perform the stipulated work under its responsibility, in a diligent and timely manner, and in accordance with the standards and practices accepted in the international petroleum industry, using sound engineering principles of the international petroleum industry, and in strict compliance with the terms of this Contract. PETROPRODUCCION, through its delegates in the Executive Committee, will have the right to make recommendations to CONTRACTOR regarding the method used to obtain the desired results, but it is intended that CONTRACTOR will have exclusive and full control and management over ts operations. CONTRACTOR will take all technical-operational decisions to comply with and execute the operations approved in the Annual Work Program Plan, without prejudice of the right it has to make the necessary consultations with the Vice President of PETROPRODUCCION and with the Executive Committee.
15.3	Executive Committee: The Executive Committee will consist of three (3) representatives of each Party. Each Party will also designate two alternate representatives who will replace any of the main representatives appointed by the respective Party, in the absence or incapacity of the main representative. The Executive Committee Coordinator will be appointed by CONTRACTOR from one of its representatives. The Committee will meet monthly or hold extraordinary meetings, as requested by any of its members.
15.3.1	Notices for Executive Committee meetings, will include the date, hour, place, agenda and supporting documentation for the issues to be discussed. As regards regular meetings, the representatives of the Parties will be notified three (3) business days in advance. As regards to extraordinary meetings, notices will be given at least five (5) business days in advance.

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15.3.2	The Executive Committee Secretary will be a representative of CONTRACTOR, who will keep the Minutes with the resolutions adopted during the meetings, which must be discussed, approved and signed by the representatives of the Parties and certified by the Secretary. The Secretary will be responsible as the custodian to keep all Executive Committee documents and records, which will be filed at the facilities of CONTRACTOR, and will deliver PETROPRODUCCION certified copies of said documentation.
15.3.3	Decisions of the Executive Committee will be taken by simple majority vote. However, on technical issues, especially those involving the HTL™ Technology or an HTL™ Plant, the CONTRACTOR’s position will prevail. In case the members of the Executive Committee do not reach agreement, the matters in dispute shall be submitted for consideration to the legal representatives of the Parties for their resolution but if the discrepancy continues, the matter will be referred to mediation or arbitration, as established in this Contract.
15.3.4	Each Party may consult with the advisors it deems convenient, who may attend the Committee meetings. A maximum of two advisors per Party and per issue may attend the committee meetings while the issue in question is been discussed. The advisors shall only have the right to express their views, without having the right to vote.
15.3.5	Duties of the Executive Committee. In addition to the duties listed in Annex 3, the Executive Committee will: (a) approve Annual Work Programs and Annual Investment Budgets, requests to drill and recondition wells and any other activities contemplated in the Regulations of Hydrocarbon Operations. (b) review and approve modifications, changes and/or alternatives submitted by CONTRACTOR regarding Annual Work Programs and Annual Investment Budgets, (c) review and recommend the maximum allowable production rates for the Pungarayacu Field before PETROPRODUCCION submits them for Ministry approval. The Executive Committee shall decide on all requests, proposals or requirements within term of five (5) days from the date a regular or extraordinary meeting was held to discuss the issues.

CLAUSE 16: CONFIDENTIAL INFORMATION

16.1 All data, whether interpreted or not, including but not limited to samples, electric logs, cores, reports or files, obtained by any Party during the life of this Contract, involving the operations and reservoirs will be kept strictly confidential, unless the Executive Committee approves in writing the total or partial disclosure of such data. This excludes data that any Party will provide without written consent to: a) the executives and employees of the Parties, provided that they keep the confidentiality established in this Contract. b) independent consultants, mediators and arbitrators who prior to disclosure of the information have agreed, in writing, to keep it confidential. c) government entities. including the regulation of national or public securities, having jurisdiction on any of the Parties hereto for disclosure of such information.

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CLAUSE 17: INSPECTIONS, CONTROLS AND AUDITS

17.1	Inspections: During the life of this Contract, PETROPRODUCCION shall have the right to inspect the operations of the CONTRACTOR and those of the Subcontractors directly related to this Contract, in order to ensure compliance with CONTRACTOR’s obligations.
	Notice of at least fifteen days in advance of the inspections must be given, in order to make the necessary arrangements for the delegates or inspectors. They shall not interrupt operations, and the inspection notices shall delimit the areas, issues and other purposes of such inspections.
17.2	PETROPRODUCCION, through officials designated by the Vice- President of this Affiliate, will have access no more than once a year to the accounting records, documents and technical records maintained by CONTRACTOR and its Subcontractors (to the extent the Subcontracts allow it), directly related to this Contract; and upon prior written notice, delivered to CONTRACTOR or its Subcontractors at least fifteen days in advance, PETROPRODUCCION or the Subcontractors, as the case may be, may also inspect the operations performed under this Contract.
17.3	The authorized representatives of PETROPRODUCCION shall have the right to request the information mentioned in the preceding paragraph during office hours, provided that prior written notice is given to CONTRACTOR at least 15 days in advance, indicating the name of such individuals.
17.4	Fiscalization and Audits: The performance of operations under this Contract will be subject to technical and financial auditing by the Dirección Nacional de Hidrocarburos, (National Hydrocarbons Bureau), as well as to the control of the Undersecretary for Environmental Protection of the Ministry of Environment, as regards to social and environmental management. These tasks will be performed directly or by hiring auditors and independent experts with proven skills, in accordance with the provisions of Articles 11 and 56 of the Hydrocarbons Law and Executive Decree 1215, published in Official Register 265 of February 13, 2002, respectively.

CLAUSE 18: ASSIGNMENT OF RIGHTS

18 CONTRACTOR may assign or transfer its rights and liabilities under this Contract upon prior approval by PETROPRODUCCION. Failure to comply with this requirement, any such assignment shall be null, and CONTRACTOR will be liable for any resulting damages or injuries . CONTRACTOR, at its own risk and expense, may assign rights to receive amounts payable to CONTRACTOR under this Contract, to entities that provide financing for operations under this CONTRACT.

CLAUSE 19: SUBCONTRACTS

19.1 CONTRACTOR may subcontract, at its own responsibility and risk, the works or services required for the performance of this Contract. Said works and services will be performed on behalf of CONTRACTOR, who will remain directly liable for all obligations under this Contract and those resulting from it, and of which CONTRACTOR is not be exonerated by reason of subcontracting. PETROPRODUCCION will assume no liability for this concept, not even in terms of solidarity.

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19.2	CONTRACTOR undertakes to select its subcontractors among suitable companies, giving preference to Ecuadorian companies, in order to promote the services of national companies, provided that such services are equivalent in quality, price and availability and technical capability.
19.3	Selection of subcontractors, negotiation of subcontract terms and conditions and the awarding thereof shall be the exclusive responsibility of CONTRACTOR, without prejudice to the provisions of the National Security Act.
19.4	CONTRACTOR must stipulate in its subcontracts that the subcontractor be required to abide by all the current legal provisions and those applicable under this Contract.
19.5	Subcontractors in Ecuador will be subject to the laws, judges, courts and administrative and legal procedures currently in force in Ecuador, especially as to labor relations, social security, taxation, foreign currency payments and environmental protection, where applicable.
19.6	The value of goods, works or services rendered by subcontractors will be in accordance with current market conditions for such goods and services.
19.7	Upon request by PETROPRODUCCION, CONTRACTOR may implement works or provide additional services in areas located in or outside the Contract Area, under the same conditions and terms of this Contract. For items where no unit prices are available, the Parties will establish the value for the additional goods or services. The additional works or services will be considered as costs and expenses of CONTACTOR in the Contractual Payment.

CLAUSE 20: GOODS, IMPORTS, DELIVERIES AND DELIVERY/RECEIPT RECORDS

20.1

Goods: Supply of materials, equipment and additional goods required for the performance of this Contract, as established in the approved Plans, Programs and Annual Budgets will be the responsibility of CONTRACTOR.

20.2

Imports: Imports of any goods required to perform this Contract will be made in accordance with the Hydrocarbons Law, the Customs Law, its Regulations and other applicable legal provisions. Imports made by CONTRACTOR will be on behalf of PETROPRODUCCION and IVANHOE ENERGY ECUADOR INC, in view that CONTRACTOR will carry out complementary exploration and exploitation activities. Therefore, the Parties hereby acknowledge the exemptions of Article 87, Hydrocarbons Law, concurrent with Article 27 of the Customs Law as regards to the goods CONTRACTOR will import, provided that such goods are not available in Ecuador.

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20.3	Any goods to be used temporarily in the performance of this Contract, which belong to CONTRACTOR or its Subcontractors, may enter and leave Ecuador in compliance with the temporary import regime or the commercial or industrial deposit regime contemplated in the Hydrocarbons Law, the Customs Law and its Regulations. CONTRACTOR will make any temporary imports in the name of PETROPRODUCCION.
20.3.1	The CONTRACTOR shall determine which goods the CONTRACTOR or Subcontractors will bring into Ecuador under the Temporary Import Regime to perform this Contract and will notify PETROPRODUCCION in advance. The CONTRACTOR or Subcontractor will be responsible for the paperwork, which will be subject to the Customs Law provisions.
20.3.2	The goods brought into Ecuador by CONTRACTOR or Subcontractors under the Temporary Import Regime will not be subject to the provisions of the last sub-clause of Article 29 of the Hydrocarbons Law, and may be either re-exported or nationalized upon prior notice to PETROPRODUCCION, subject to the provisions of the Customs Law, the Hydrocarbons Law, the Internal Tax System Law and other applicable laws and regulations.
20.4	As set forth in sub-clause 5.2.4, and after receiving a favorable report from PETROPRODUCCION, the Ministry of Economy and Finance, shall grant the corresponding customs duty exemption for the imported assets required to perform this Contract, in accordance with the provisions of Article 87 of the Hydrocarbons Law.
20.5	Notwithstanding the provisions of this Contract, CONTRACTOR will not transfer, encumber or remove, during the term of this Contract, any equipment, tools, machinery, facilities, or other movable or immovable assets acquired to perform this Contract, without the prior approval of PETROPRODUCCION, except for the financial or business operations that the CONTRACTOR is required to perform.
20.6	Upon termination of this Contract, due to expiration of its term or any other cause set forth in this Contract, CONTRACTOR shall deliver to PETROPRODUCCION, free of charge and in good conditions, except for normal wear and tear, the wells currently in production. In addition, it will deliver to PETROPRODUCCION in good conditions, except for normal wear and tear, all equipment, tools, machinery, facilities, and other movable or immovable assets acquired to perform this Contract, which are located in the Contract Area, with the exception of the the CONTRACTOR’s patented systems.
20.6.1	A committee made up of delegates from PETROPRODUCCION and representatives from the CONTRACTOR shall be created 180 days prior to termination of this Contract, to deliver/receive the assets referred to in sub-clause 20.6, of this Contract, in accordance with the corresponding legal provisions and regulations, and to verify compliance of the contractual obligations. The Committee will execute the delivery/receipt record, on the date this Contract terminates. If the inspection reveals deficiencies that are duly proven following the due process and are imputable to CONTRACTOR, such deficiencies will be recorded in the delivery/receipt record, and reception will be delayed for the period granted by PETROPRODUCCION, who will give CONTRACTOR all the instructions to solve the observed deficiencies.

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20.7 As regards to the goods mentioned in this Clause, and if said goods are vital to keep operational the Contract Area, (PETROPRODUCCION) may exercise the purchase option in purchase or leasing agreements celebrated by the CONTRACTOR during the last (5) five years prior to termination of this Contract. The purchase option shall be duly approved by the Executive Committee.

CLAUSE 21: PERSONNEL

21.1	CONTRACTOR will hire the personnel necessary for the performance of this Contract, in accordance with the applicable legal provisions, taking into account the provisions of the first sub-clause, item a), Article 31 of the Hydrocarbons Law.
21.1.1	CONTRACTOR undertakes to maximize the use of available Ecuadorian personnel to perform the activities under this Contract.
21.1.2	For national security reasons, CONTRACTOR and its Subcontractors shall submit to the Joint Command of the Armed Forces, via PETROPRODUCCION, the data cards of all national and foreign employees.
21.1.3	The CONTRACTOR and its Subcontractors may not employ persons objected to by the Joint Command of the Armed Forces for national security reasons. Such objections may also occur for the employees already hired, in which case the objected employee will be dismissed, and such fact will not represent an omission or liability imputable to CONTRACTOR.
21.1.4	The CONTRACTOR and its Subcontractors will assume separately the employer’s liability for their workers, as established by Law. PETROPRODUCCION will not be deemed an employer, not even in terms of solidarity. The CONTRACTOR will not be deemed an employer for the workers of its subcontractors, not even in terms of solidarity.
21.2	Training. CONTRACTOR will train its Ecuadorian employees, in accordance with the Work Programs and Annual Investment Budgets. The CONTRACTOR’S foreign technical and management staff will train the CONTRACTOR’S Ecuadorian employees.
	The staffing program will be the exclusive responsibility of CONTRACTOR in accordance with Art. 31 of the Hydrocarbons Law.

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CLAUSE 22: SOLUTION OF DISPUTES

In the event of controversies arising from performance of this Contract, the Parties hereto will make every effort to settle such controversies by mutual agreement, within 30 days from occurrence.

22.1	Industrial property, technical or financial disputes not solved by mutual agreement will be submitted to an arbitration process in the Court of Arbitration of the International Chamber of Commerce in Paris (ICC), in accordance with the procedures established in the operating rules of the above-mentioned arbitration center.
	In cases involving other issues, the Parties agree that controversies will be solved by a Court of arbitration and mediation of the Chamber of Commerce of Quito, in accordance with the Ecuadorian Arbitration Law and the Rules of that Center, as established in Article 50 of the Procurement Regulations for Specific Works, Goods and Services of Empresa Estatal de Petróleos del Ecuador, PETROECUADOR and its Affiliate Companies.
22.2	For the events mentioned in the first and second paragraphs of sub-clause 22.1, the Parties hereby specify that their domicile for all arbitration summons and notices will be the city of Paris, France, or Quito, Ecuador, as the case may be; and their addresses shall be those recorded in sub-clause 24.4.2.
	To appoint the arbitrators and follow the arbitral procedure before the Chambers of Commerce of Paris or Quito, as the case may be, the Parties will observe the following:
22.3	The Parties may only make counterclaims in relation to the same issue.
22.4	The arbitration will be in accordance with legal principles, as set forth in the provisions of Article 11 of the Attorney General’s Office Organic Law and governed by the provisions in this Contract, the documents involving the issue submitted to arbitration, and the Ecuadorian laws currently in force.
22.5	Arbitrators shall have the authority to order preventive measures, and request assistance from public officials for its enforcement.
22.6	Filing, notification, summons, and arbitral pleas, preventive measures, changes in the claim or plea, as well as the call for hearing will be in accordance with the Arbitration Regulations of the International Chamber of Commerce headquartered in Paris.
22.7	If an agreement is not reached during the mediation stage, the Parties shall designate arbitrators, in accordance with the following procedure.
22.8	The Court of Arbitration will consist of three arbitrators.
22.9	Within twenty days from receipt of the plea, or of the reply to the counterclaim, or due to contempt of one of the Parties, if applicable, whichever occurs last , each Party shall appoint one arbitrator from the list of qualified arbitrators provided by the International Chamber of Commerce in Paris (ICC), notifying the Chamber, in writing, of such appointments. If one of the Parties fails to appoint its arbitrator within said term, the other Party may request the Director of the Arbitration Center of the International Chamber of Commerce in Paris, to appoint an arbitrator from the list of arbitrators of the above-mentioned Chamber.

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22.10	The two arbitrators will designate a third arbitrator, who will chair the Court of Arbitration. If within ten days these two arbitrators do not reach an agreement regarding the third arbitrator, either Party may request to the Director of the Arbitration Center of the International Chamber of Commerce in Paris appointment of the third arbitrator. The Party requesting the Director General to appoint the third arbitrator shall attach to its request the names of two candidates. The other Party will be notified of the issue, and in turn will suggest two candidates within five days from the date of notice. If the party fails to suggest candidates within the established term, the Director of the Arbitration Center will appoint a third arbitrator from the list submitted by the other Party, within five days from the date the foregoing procedures were fulfilled.
22.11	The arbitrators appointed will accept or refuse the nomination within three days after receiving notice. If no reply is received, it will be understood that they refused the nomination, and a new designation will be requested from the Party that nominated the arbitrator, in order to appoint a replacement, or, in the case of the third arbitrator, he/she will be elected in accordance with the procedures of sub-clause 22.10. When designation has been accepted, the arbitrators will be summoned by the Director of the ICC and will designate the Chair of the Court of Arbitration, which will be recorded in the corresponding minutes.
22.12	The Designated Chair of the Court shall lead the arbitration process and the Secretary of the Court will be appointed from the list of Secretaries of the Arbitration Center.
22.13	The Arbitration will be held in the city of Paris, France, and its venue will be the Paris Chamber of Commerce without prejudice that the Court of Arbitration may move to any place it may require to perform its work.
22.14	The Parties shall provide the Court of Arbitration with all information and facilities, as well as allow them access to the work sites, books and technical and accounting records, as may be needed to solve the controversy at issue. Likewise, the arbitrators will use procedures that allow the Parties to submit all the evidences deemed convenient before taking a decision.
22.15	Arbitration procedures will not interrupt the activities nor the terms foreseen in this Contract, and Contract performance shall continue as usual, unless such terms are significantly affected by the matter under dispute or by the arbitration results, which will be determined by the Court of Arbitration itself, together with the period of interruption.
22.16	The arbitral award will be executed in accordance with the Arbitration Rules of the International Chamber of Commerce, headquartered in Paris. If necessary, the Court of Arbitration will specify in its award, the measures to be taken for adequate compliance of the arbitral award.
22.17	If during the arbitration process one of the arbitrators resigns or is unable to continue in it, the Party that appointed said arbitrator will have the right to designate his/her replacement. If the person resigning or unable to continue is the Chair of the Court of Arbitration, the procedure set forth in sub-clause 22.10 shall apply.

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22.18	All decisions taken by the Court of Arbitration will be by majority of votes.
22.19	The Party filing the claim will cover the arbitrator fees and operational costs involving the issue in question, while the costs of experts consulted will be borne by the requesting Party. Arbitrator fees will be settled in accordance with the tariffs established by the Arbitration and Mediation Center.
22.20	Upon completion of the arbitration process, the Court of Arbitration will notify its decision at an open hearing, after which the Court will provide the Parties with a copy of the award. The award shall include detailed explanations regarding the conclusions and other technical measures involving the arbitral award, as may be necessary.
22.21	Any arbitral award requiring payment in cash will be paid in Dollars of the United States of America. In addition, on any award requiring any of the Parties to make a cash settlement, the Party shall pay the interests established in the arbitral award, which shall be calculated from the date of noncompliance or breach of this Contract, and if established by the arbitral award, interests will accrue until the full amount is settled.
22.22	The award will not be subject to appeal, but the Parties may request further details or clarifications within three days from receipt of notice; or if applicable, an action to declare void may be presented. The Court will reply to such requests within ten days from receipt of the request.
22.23	If the Parties reach a partial or total agreement during the arbitration process, they will abide by the provisions of the Arbitration Rules of the ICC or the Chamber of Commerce of Quito, as the case may be.

CLAUSE 23: TERMINATION OF CONTRACT

23.1 This Contract will terminate in the following events:

a)	Upon full completion of the Contract term;
b)	By court decision declaring nullity or termination of this Contract;
c)	By mutual agreement of the Parties prior to performance of this Contract;
d)	By legally declared bankruptcy of CONTRACTOR;
e)	By dissolution of CONTRACTOR as a legal entity;
f)	By unilateral decision of PETROPRODUCCION due to one of the grounds set forth in Article 43 of the Procurement Regulations for Specific Works, Goods and Services of Empresa Estatal de Petróleos del Ecuador, PETROECUADOR and its Affiliate Companies.

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23.2 The grounds for unilateral termination of this Contract are:

1)	Noncompliance by CONTRACTOR;
2)	Legally declared bankruptcy of CONTRACTOR;

3)	Interruption of works, not caused by Force Majeure or Acts of God proven by CONTRACTOR and accepted by PETROPRODUCCION and PETROECUADOR;
4)	Executing this Contract with fraud and violating the express legal prohibitions or the Procurement Regulations for Specific Works, Goods and Services of PETROECUADOR;
5)	Summons to lawsuit against the legal representative of CONTRACTOR for criminal offenses having relationship with the performance of this Contract;
6)	If the penalties exceed the established minimum percentage of the Contract amount; and
7)	Any other events stipulated in this Contract, according to their nature.

23.3 Procedure for unilateral termination - Unilateral termination, as established in items 1, 3, 5, 7 will be in accordance with the provisions of Article 44 of the Regulations for Specific Works, Goods and Services of Empresa Estatal Petróleos del Ecuador and its Affiliate Companies.

i)	Prior to the unilateral termination PETROPRODUCCION will notify CONTRACTOR, in writing, its decision to unilaterally terminate this Contract, and will attach to such notice the technical and financial reports involving the breach of Contract. The above-mentioned notice shall specify the noncompliance incurred by Contractor, noting that if such noncompliance is not remedied or justified in a term of 15 days from receipt of notice, this Contract will be terminated.
	If CONTRACTOR fails to justify or remedy the noncompliance within the established term granted, PETROPRODUCCION will terminate this Contract by resolution of its highest authority.
ii)	Unilateral termination may be grounds foe collection of the performance bond submitted under this Contract.
iii)	The financial and accounting settlement will establish the amounts payable by each Party, and the issue will be recorded in the register of defaulted contractors kept by the State Comptroller’s Office.
iv)	Early or unilateral termination of this Contract by PETROPRODUCCION will not be allowed if PETROPRODUCCION failed to fulfill its obligations with CONTRACTOR.

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23.4

Early Termination for Technical or Economic Reasons If upon completion of the Evaluation and/or Pilot Stages (Stages 1 and/or 2), the CONTRACTOR advises PETROPRODUCCION that technically or economically feasible to fully develop the Contract Areas is not technically or financially feasible, the Parties will make a settlement reflecting the investments, costs and expenses incurred by CONTRACTOR in the Contract Area during the period that CONTRACTOR operated . CONTRACTOR will not be entitled to any reimbursement, for which the termination by mutual agreements that will be carried out in a Agreement, said Agreement, and prior to its signature, it must obtain the decree of the Attorney General of the Country, as stipulated in the Ley Orgánica de la Procuraduría General del Estado (The Attorney General Office Organic Law) The total cost of the work included under the proposal until this time will be the exclusive responsibility of the CONTRACTOR and as such will not be included in the settlement.

Termination by mutual agreement may also take place during the Exploitation Stage, subject to the provisions of Article 42 of the Regulations for Specific Works, Goods and Services of Empresa Estatal Petróleos del Ecuador, PETROECUADOR and its Affiliate Companies. The above-mentioned Article states that “If due to unforeseen technical or financial conditions or Force Majeure or Acts of God, it is not convenient for the State to fully or partially execute the contract, the parties may agree to terminate all or some of the contractual obligations in whatever state they are at the moment, in which event the corresponding settlement will be made”.

CLAUSE 24: APPLICABLE LAW, DOMICILE, JURISDICTION AND PROCEEDINGS

24.1	Applicable legislation: This Contract is exclusively governed by Ecuadorian laws and it is hereby understood that the laws in force at the time of executing this Contract are included.
24.1.1	The CONTRACTOR expressly declares that it is fully aware of Ecuadorian Legislation.
24.2	Legal Framework: The legal framework applicable to this Contract includes but is not limited to the following instruments: One- Hydrocarbons Law, published in Official Register No. 711, of November 15, 1978 and its amendments. Two- The Special Law of Empresa Estatal Petróleos del Ecuador (PETROECUADOR) and its Affiliate Companies, published in Official Register No. 283, dated September 26, 1989 including its amendments and relevant regulations. Three- “Ley Orgánica de Equidad Tributaria”, published in Official Register 242, dated November 29, 2007. Four- Law No. 122, which creates the Development Fund for the Amazon Region Provinces, published in Official Register 676 of May 3, 1991, including its amendments and interpretative law. Five- Arbitration and Mediation Law, published in Official Register No. 145 of September 4, 1997, including its amendments. Six — General Insurance Law and its amendments. Seven- Customs Law and its regulations. Eight— Substitute Regulations for Hydrocarbon Operations. Nine- Substitute Regulations to the “Reglamento Ambiental para las Operaciones Hidrocaruburíferas en el Ecuador” published in Official Register No. 265, dated February 13, 2001. Ten — Regulations for Procurement of Goods, Works and Services for PETROECUADOR and other laws in force at the time of execution of this contract, and which are applicable to hydrocarbon activities. In the event of controversy between the above-mentioned instruments, the priority will be as follows: this Contract, the Laws, and the Regulations.

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24.3	Domicile, Jurisdiction and Competence: The Parties waive domicile and submit themselves to Ecuadorian law and expressively agree that all controversies will be settled as set forth in Clause 22 of this Contract, except as established for International Arbitration.
24.4	Communications and Notices.-
24.4.1	Any documents submitted by CONTRACTOR by virtue of this Contract to PETROPRODUCCION or the Ministry under this Contract will be subject to the provisions of Article 82 of the Hydrocarbons Law.
24.4.2	All notices exchanged between the Parties will be in writing, in Spanish and will be delivered at the following addresses:

PETROPRODUCCION, Avenida de los Shyris No. 34-382 y Portugal, telephone number 2465758, fax: 2449000, Quito, Ecuador.

CONTRACTOR: IVANHOE ENERGY ECUADOR INC., Calle del Establo, Lote No. 50, Santa Lucía Alta, Edificio SITE CENTER, Torre 3, Cumbayá Ecuador, Telephone 09-978-1532.

24.4.3 The Parties may designate new addresses, by timely notifying in writing the other Party of such change.

CLAUSE 25: REGISTRATION AND VALUE OF CONTRACT

25.1	CONTRACTOR undertakes to register this Contract in the Hydrocarbons Registry of the National Hydrocarbons Bureau, within 30 days from signature of this instrument.
25.2	Undetermined Amount of Contract: Given the nature of this Contract, its value is not quantifiable on the date of its execution. Therefore, the public record in which it is recorded, will establish it of undetermined amount.

CLAUSE 26: TECHNOLOGY TRANSFER, TRAINING AND EDUCATION

CONTRACTOR undertakes to implement a technology transfer program, based on the following:

26.1	Technology Transfer Programs: The CONTRACTOR undertakes to implement a technology transfer program and will contribute 1% of total investments to research and development of heavy crude oil, to be managed by the Parties.
26.2	Training: CONTRACTOR will give seminars/courses on technology improvements to exploit heavy crude oils. The costs of the instructors, educational materials, facilities, travel expenses, lodging, etc. required to implement such courses will be at the expense of CONTRACTOR, upon prior agreement with PETROPRODUCCION, in an amount not exceeding US$25,000 per year.

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26.3	Lab Facilities. Install a research lab for upgrading and transforming heavy crude oils, with participation of “Universidad Central del Ecuador”, for an amount up to $100,000.
26.4	Technical Students. Receive from the beginning of the Exploitation Stage, two (2) students or graduates of technology institutes or universities, with specialization in the Ecuadorian hydrocarbon industry, per year, to study in the United States or Canada for two years. PETROPRODUCCION and CONTRACTOR will select the educational institutions by mutual agreement. Transportation, lodging, food, and medical care will be borne by CONTRACTOR. The CONTRACTOR will not be liable for the student’s safety, but will obtain for them an accident insurance policy. The CONTRACTOR shall give the students a monthly financial aid in a reasonable amount with a value of up to $100,000 per year.
26.5	Internships. Implement an annual internship program for two PETROPRODUCCION professionals per year in the fields operated by CONTRACTOR, its Affiliates or Subsidiaries in the country or abroad, during the first five years after the HTL™ Plant begins to operate. The names of the candidates will be notified in advance to CONTRACTOR, and CONTRACTOR will have the right to veto the nominees.
26.6	Training and Educational Support: Contribute to the training and research centers of the Ministry of Mining and Petroleum and PETROECUADOR with an annual amount of up to $20,000 from the beginning of the Development Stage.
26.7	Training in Canada and USA. Coordinate training programs with Canadian and United States universities in order that PETROECUADOR workers or students from Ecuadorian Universities participate.
26.8	Heavy Crude Oil Training. Train CONTRACTOR’s Ecuadorian personnel in the use of new heavy crude oil technologies.

CLAUSE 27: CONTRACT DOCUMENTS

27.1

Qualifying Documents: This Contract includes the following qualifying documents, which have been formally recorded: a) certified copies of the appointment and taking-office minutes of the President of PETROECUADOR and Vice President of PETROPRODUCCION. b) Documents issued by the “Superintendencia de Compañías”, and the Registry of Commercial Concerns, certifying the legal status of CONTRACTOR, its legal representative and domiciliation in Ecuador. c) PETROECUADOR’s Procurement Committee Resolution, authorizing the Executive President of PETROECUADOR and the Vice President of PETROPRODUCCION to award and execute this Contract.

27.2

Annexes. The following annexes are an integral part of the Contract herein Annex: Annex One.- Delimitation of Block 20 and the Pungarayacu Field. Annex Two- Form of Payment Chart .- Annex Three Executive Committee Manual; Annex Four- Technical Criteria to Calculate Maximum Allowable Production Rates; Annex Five.- Detailed Investments Committed; Annex Six.- Accounting Rules and Regulations; Annex Seven.- Parent Company’s Joint Guaranty; Annex Eight.- Regulations for the Operation of the International Chamber of Commerce, headquartered in Paris; Annex Nine: Report of the State Attorney General: Annex Ten- Report of the State Controller; Annex Eleven-  Clarification of the Report of the State Controller; Annex Twelve- Cronogram of the Development Plan.

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ANEXO 1

BLOCK 20 COORDINATES
INCLUDING PUNGARAYACU FIELD

Coordinates for Block 20
Pungarayacu Field
Napo Department, Ecuador

	East		North		Longitude								Latitude
Point	UTM				degrees		minutes		seconds		direction		degrees		minutes		seconds		direction
1		180.225,856		9'912.499,598		77		52		21.65		w		00		47		26.28		s
2		188.532,316		9'922.418,184		77		47		53.03		w		00		42		03.08		s
3		200.225,856		9'923.049,024		77		41		35.13		w		00		41		43.50		s
4		200.225.856		9'870.436,882		77		41		36.43		w		01		10		15.17		s
5		180.225,856		9'870.436,882		77		52		22.82		w		01		10		14.52		s
6		180.225,856		9'880.436,882		77		52		22.50		w		01		04		49.24		s
7		170.225,856		9'880.436,882		77		57		45.65		w		01		04		48.92		s
8		170.225,856		9'890.436,882		77		57		45.35		w		00		59		23.56		s
9		180.225,856		9'890.436,882		77		52		22.21		w		00		59		23.95		s

Point	LONG		LAT
1		-77.872681		-0.790633
2		-77.798064		-0.700856
3		-77.693092		-0.695417
4		-77.693453		-1.170881
5		-77.873006		-1.170700
6		-77.872917		-1.080344
7		-77.962681		-1.080256
8		-77.962597		-0.989878
9		-77.872836		-0.989986

ANNEX 1

BLOQUE	PUNTO		EASTING		NORTING		AREA (Has)
20		P20-1		180225,8		9914643,8		113538,585
		P20-2		200225,8		9924442,8
		P20-3		200225,8		9870436,8
		P20-4		180225,8		9870436,8
		P20-5		180225,8		9880436,8
		P20-6		170225,8		9880436,8
		P20-7		170225,8		9890436,8
		P20-8		180225,8		9890436,8

ANNEX 1 MAP
(Map of Coordinates for Block 20)

ANNEX 2
PAYMENT FORMULA
CALCULATION TABLE
PUNGARAYACU OIL FIELD
(February 2007 – Example of Contractual Payment)

1. Production during the month of February 2007
Total fiscalized production in the Contract Area (BBL)	x.xxx.xxx,xx
2. Contractual Payment (Payment Formula):
Definitions,
Reference Quarter: Calendar quarter immediately before the month on which the Effective Date of this Contract occurred.
Payment Month: The calendar month for which the Contractual Payment amount is established.
Payment Quarter Calendar quarter immediately before the month on which CONTRACTOR estimates the amount that will be invoiced as the Contractual Payment.
CPP = Contractual Payment agreed under this contract.
CPPc = Actual Contractual Payment applicable to the Fiscalized Production invoiced for the corresponding month.
IA = Adjusting Indexes – Actual escalated adjustment of the CPP that will be adjusted to the amount of Fiscalized Production to be invoiced in that month.
PPI = Producers Price Index, US Department of Labor, Bureau of Labor Statistics:
PPIs = Metals & Metal Products, Steel Mill Products
PPIm = Field Machinery & Equipment for the Oil and Gas Industry
PPIr = Petroleum Refineries
Weighting Factors: Used to calculate each adjusting index. The weighting factors have relationship with capital expenditures.
• WFs = 0.45 Weighting Factor for the PPIs
• WFm= 0.35 Weighting Factor for the PPIm
• WFr = 0.20 Weighting Factor for the PPIr

Delta PPI is the change in PPIs calculated as the ratio of the current average PPI’s for the weighted Quarter prior to the month of the corresponding Fiscalized Production (Payment Quarter), divided by the average PPI’s for the Quarter of the Contract’s Effective Date (Reference Quarter. The PPI indexes for any Quarter will be the weighted arithmetic average of the PPI’s for the three months in that quarter. A Quarter means a calendar quarter, i.e., January, February & March (first Quarter), April, May and June (second Quarter), etc.
Where,
IA = [(WFs) x (Delta PPIs)] + [(WFm) x (Delta PPIm)] + [(WFr) x (Delta PPIr)]
Then,
CPPc = (CPP) X (IA)
Where,
CPP in US $/fiscalized barrel =		37,00
3. Contractual Payment if Contractual Payment is higher than the fiscalized oil price:
Payment month =	February 2007
Effective date of Contract =	January 2006
Reference Quarter =	First Quarter 2006
Payment Quarter =	First Quarter 2007
CPP = US $  per barrel of fiscalized oil		37,00
PPIs and CPIs average for the Reference Quarter (January, February and March 2006):
From the US Bureau of Labor Statistics Web site.
Average PPIsrq = [(xxx.x + xxx.x + xxx.x) / 3] = xxx.x
Average PPImrq = [(xxx.x + xxx.x + xxx.x) / 3] = xxx.x
Average PPIrrq = [(xxx.x + xxx.x + xxx.x) / 3] = xxx.x

PPI average for the Payment Quarter (January, February and March 2007):
From the US Bureau of Labor Statistics Web site.
Average PPIspq = [(xxx.x + xxx.x + xxx.x) / 3] = xxx.x
Average PPImpq = [(xxx.x + xxx.x + xxx.x) / 3] = xxx.x
Average PPIrpq = [(xxx.x + xxx.x + xxx.x) / 3] = xxx.x
Delta PPIs and CPI,
Delta PPIs = [(PPIspq) / (PPIsrq)] =[xxx.x / xxx.x] = x.xx
Delta PPIm = [(PPImpq ) / (PPImrq)] =[xxx.x / xxx.x] = x.xx
Delta PPIr = [(PPIrpq) / (PPIrrq)] =[xxx.x / xxx.x] = x.xx
Then,
IA = [(0.45) x (x.xxPPIs)] + [(0.35) x (x.xxPPIm)] + [(0.20) x (x.xxPPIr)] = x.xxIA (index with two decimal digits = Adjusting Index)
CPPc = (37.00) x (x.xxIA) = (Adjusting Index) =
Contractual Payment (US $) = US.$.xx.xx/oil barrel multiplied by xx.xxx.xxx,xx oil barrels = (including the IA)
Less,	37,00*x,xx(IA)
Costs, Expenses and Planned Investments =
Total amount to be paid – basis of liabilities =	xx.xxx.xxx,xx
And,
4.5% for the Amazon Region Provinces Development Fund (Fondo de Desarrollo de las Provincias de la Amazonía) =	(x.xxx.xxx,xx)
TOTAL AMOUNT PAYABLE TO CONTRACTOR =	x.xxx.xxx,xx
	(x.xxx.xxx,xx)
	x,xxx.xxx,xx

4. Income sharing if Contractual Payment is equal or lower than the fiscalized oil price:
Gross income from sale of fiscalized oil = number of fiscalized oil barrels for the sale price per barrel
Number of Fiscalized Barrels in February 2007 (BBL)=	x.xxx.xxx,xx
Weighted price for the Payment Month (US $/BBL)=	xx.xx
Gross Income to be Shared (US $)=	xx.xxx.xxx,xx
Income will be divided as follows:
Petroproducción = (20% of income) =	x.xxx.xxx,xx
Contractor = (80% of income) =	x.xxx.xxx,xx
For Contractor, Less,
Costs, Expenses and Planned Investments =	(x.xxx.xxx,xx)
Total to be paid – basis of liabilities =	x,xxx.xxx,xx
And,
4.5% for the Amazon Region Provinces Development Fund (Fondo de Desarrollo de las Provincias de la Amazonía) =	(x.xxx.xxx,xx)
TOTAL AMOUNT PAYABLE TO CONTRACTOR =	x.xxx.xxx,xx

ANNEX 3

JOINT WORK PROCEDURE DURING PROJECT EXECUTION
BETWEEN PETROPRODUCCION AND THE CONTRACTOR

This is a Specific Services Rendering Contract for the production of Heavy Crude Oil in the Area of the Contract. The contractor commits itself, at its own risk and responsibility, with PETROPRODUCCION, to confirm reserves and complementary exploration, while providing the necessary technology, capital, and equipment or machinery for the fulfillment of the obligations established in this contract.

Meaning the organizational structure should allow for widespread technological transference on site and a capacity building training program for field personnel and office staff.

The joint administration of the project will be regulated under the following policy:

All of the staff from Petroproducción, involved in the project, will be subject to the established Norms and Regulations. The Contractors personnel will be subject to the norms established by it, according to pertaining clauses of the present written document.

The following are the definitions and functions of the Operations Committee, which shall be in accordance with the contract subscribed between the parties.

REGARDING THE OPERATIONS COMMITTEE:

The Operations Committee will be composed by three (3) members from PETROPRODUCCION and three (3) members from the Contractors side. These shall be independently nominated and their functions shall last three years, and may be re elected. The members of the Committee shall come from the following areas: Operations, Exploration and Development, Finance and Legal.

The functions of the Operations Committee are:

a) Asses and recommend the Plans, Activity Programs and Annual Investment Budgets and drilling proposals, well reconditioning and any other activity contemplated in the Hydrocarbon Operations Regulation.

b) To learn of and act on modifications, changes and/or alternatives presented by the CONTRACTOR regarding Plans, Activity Programs and Annual Investment Budgets.

c) To learn of and recommend the Maximum Allowable Production Rates for Pungarayacu Field before PETROPRODUCCION submits these to the approval of the corresponding Ministry.

d) Asses general project advancement, control the fulfillment of contracts, and establish the general policies for the fulfillment of project objectives, resolve controversies and solve operational, financial, administrative, legal and contractual problems, which may have not been resolved by lower instances.

e) Specific technical, economic, administrative or legal issues regarding projects, may be advised by specialists on the matter and may recommend appropriate measures.

In general, it shall be responsible for directing, administrating, appraising, and adopting all measures necessary for the correct operation and execution of the project.

ANNEX 4

Technical Criteria to Calculate Maximum Permitted Production Rates

To be provided by the National Hydrocarbon Directorate

ANNEX 5

Provisional First Five Years of Capital Expenditures
Pungarayacu Field
2008

Year 1A – US$ 3 million	Approvals Period
Year 1B – US$ 14 million	Appraisal Period (1st Year) Subject to the successful outcome of the Approvals Period
Year 2 – US$87 million	Appraisal Period (2nd Year) Subject to the successful outcome of the previous periods
Year 3 – US$273 million	Pilot Period (1st Year) Subject to the successful outcome of the previous period
Year 4 – US$462 million	Pilot Period (2nd Year) Subject to the successful outcome of the previous period
Year 5 – US 22 million	Pilot Period (3rd Year) Subject to the successful outcome of the previous period

NOTES:

1.	The five-year capital expenditure schedule will be subject to updating every year depending on the technical results of the previous periods. The technical results and analysis for updating the subsequent years of capital expenditures will coincide with the proposed work plan and budget for the subsequent years as stated in the Contract as per clause 7.1.1 and 7.1.3.
2.	Year 2 includes costs for Front End Engineering and Design (FEED) for both the field facilities and the first HTLTM plant. The execution of this work will be subject to technical results from the previous periods.

These are approximate investments. They will only be finalized when they are approved by the Executive Committee

ANEXO 5
MODELO ECONOMICO

UNESCALATED CAPITAL COSTS

			Approval										FEED		Well
			Period		2-D		3-D		Appraisal		Steam		&		Capex &		Pipeline		HTL		Facility		Total
			Costs		Seismic		Seismic		Wells		Pilots		Engineering		Steam Pilots		Capex		Capex		Capex		Capex		Sub-Totals
PERIOD	Year		M$		M$		M$		M$		M$		M$		M$		M$		M$		M$		M$		M$
APPRAISAL		1		5,100		10,000		—		5,000		—		—		8,000		—		—		—		28,100
		2		—		—		15,000		5,000		—				20,000		—		—		—		40,000
		3		—		—		—		—		—				12,000		30,000						42,000		110,100
PILOT		4		—		—		—		—		—		40,000		33,550								73,550
		5		—		—		—		—		—		—		51,350		—		138,105		54,230		243,685
		6		—		—		—		—		—		—		61,000		—		271,755		106,500		439,255		756,490
EXPLOITATION (SECOND HTL PLANT)		7		—		—		—		—		—		—		122,152		—						122,152
		8		—		—		—		—		—		—		116,750		—						116,750
		9		—		—		—		—		—		—		88,750		—		222,750		87,295		398,795
		10		—		—		—		—		—		—		85,700		—		222,750		87,295		395,745		1,033,443
EXPLOITATION (THIRD HTL PLANT)		11		—		—		—		—		—		—		141,050		—						141,050
		12		—		—		—		—		—		—		145,700		—						145,700
		13		—		—		—		—		—		—		91,500		—		222,750		87,295		401,545
		14		—		—		—		—		—		—		79,300		—		222,750		87,295		389,345		1,077,641
		15		—		—		—		—		—		—		82,350		—		—		—		82,350
		16		—		—		—		—		—		—		73,200		—		—		—		73,200
		17		—		—		—		—		—		—		73,200		—		—		—		73,200
		18		—		—		—		—		—		—		73,200		—		—		—		73,200
		19		—		—		—		—		—		—		73,200		—		—		—		73,200
		20		—		—		—		—		—		—		73,200		—		—		—		73,200
		21		—		—		—		—		—		—		88,450		—		—		—		88,450
		22		—		—		—		—		—		—		88,450		—		—		—		88,450
		23		—		—		—		—		—		—		82,350		—		—		—		82,350
		24		—		—		—		—		—		—		85,400		—		—		—		85,400
		25		—		—		—		—		—		—		79,300		—		—		—		79,300
		26		—		—		—		—		—		—		82,350		—		—		—		82,350
		27		—		—		—		—		—		—		82,350		—		—		—		82,350
		28		—		—		—		—		—		—		82,350		—		—		—		82,350
		29		—		—		—		—		—		—		76,250		—		—		—		76,250
		30		—		—		—		—		—		—		73,200		—		—		—		73,200		1,268,800
				5,100		10,000		15,000		10,000		—		40,000		2,325,602		30,000		1,300,860		509,912		4,246,474		4,246,474

ANNEX 6

APPLICABLE NORMS OF ACCOUNTING FOR SPECIFIC SERVICES
CONTRACT IN CRUDE OIL PRODUCTION FOR THE AREA OF THE
CONTRACT

These Norms of Accounting are prepared in conformity with Clause 9 of this contract, which are developed according to the generally applied accounting principles for the hydrocarbon industry internationally.

The CONTRACTOR will, in addition, to able to receive all incentives and tributary benefits with economic – financial effect established by the tributary laws and its regulations, present or future, including the reduction of the income tax due to the reinvestment of the profits.

The expenses made by the CONTRACTOR shall be grouped under the following categories:

Geosciences
Development and Production Investments
Depreciations and amortizations
Costs and Expenses
Warehouse Stocks

A. GEOSCIENCE

Includes the following entries:

A.1. SERVICE TARIFFS for topography, aerophotogrametry, geology, seismics, magnetometry, gravimetry, processing, reprocessing and any other geological and geophysical research method including technical services, materials and personnel that correspond to this entry.

A.2. PERSONNEL EXPENSES for direction, supervision and support lent to the Geosciences unit, including services, supplies, and general expenses related to this entry.

A. 3. TECHNICAL INSURANCE AND GUARANTEES.- Insurance Policy costs, contracted to cover installations, equipment, vehicles and technical personnel.

A.4. MAIN OFFICE SERVICES.- Direct or indirect services for the Head Office and related companies, corresponding to Geoscience activities, including specific service rendering and general support.

A.5. QUITO OFFICE SUPPORT.- Technical and administrative expenses related to the functional operation of the CONTRACTOR’S main office in Ecuador, applicable to geosciences activities, including among others, staff expenses, office rent, utilities (telephone, electric, water, postal services) supplies, professional wages, hired services, general insurances and other specific and general expenses corresponding to this entry.

A.6. OTHER UNFORESEEN EXPENSES.- These correspond to other unforeseen expenses not mentioned in the previous entries, including expenses for environmental impact assessments, indemnifications for communities, etc.

B. DEVELOPMENT AND PRODUCTION INVESTMENTS

Includes the following entries:

B.1. DEVELOPMENT WELL DRILLING.- Which include the following subentries:

B.1.1. Access Roads; expenses corresponding to road construction, including technical services, staff and materials inherent to this subentry.

B.1.2. Construction site preparation entails all expenses related to well pad site preparation including technical services, staff and materials inherent to this subentry.

B.1.3. Well drilling, which include among others, mobilization, assembly, rental, disassembly and relocation of drilling equipment, pipelines, and all other related materials and services, as well as staffing expenses inherent to this subentry.

B.1.4. Well Completion.- Which correspond among others: completion equipment rental costs, services and associated materials, (Down Hole Equipment), bottom hole sensor gages and registries, well tests, laboratory services, etc.: including, technical services, pipes, materials and staff inherent to this subentry.

B.1.5. Dry wells.- the cost derived from dry wells drilled will not be capitalized and the corresponding value will be directly assigned to production expenses during that time period.

B.2. SURVEY STUDIES, INSTALLATIONS AND EQUIPMENT.- Which will include the following subentries:

B.2.1. Land survey studies for civil works execution, which correspond to the technical studies necessary for the execution of Development and Production activities.

B.2.2. Well surface equipment corresponds to surface equipment installation (artificial lift equipment), including technical services, staff and materials inherent to this subentry.

B.2.3. Christmas Tree Assembly equipment.- These expenses correspond to flow line assembly installation, manifold, scraper unit, and flow meters, including casing and pipelines, associated materials, technical services and staff inherent to this subentry.

B.2.4. Separation Equipment.- corresponding to atmospheric separators, cleanout tanks, transference pumps, including materials, technical services and staff inherent to this subentry.

B.2.5. Storage (Tank Farm), which corresponds to crude storage and other consumable fuel tanks, including materials, technical services and staff inherent to this subentry.

B.2.6. Production Facilities, which correspond to the acquisition of office equipment and furniture necessary for the fulfillment of production and development activities. This subentry shall include all assets with a cost over five hundred dollars and a life cycle of over one year.

B.2.7. Crude Upgrading Cost.

B.2.7.1. Engineering, Design, Construction & Installation of Upgrade Facility.

B.2.7.2. Facility Operation & Maintenance.

B.2.7.3. Facility Parts Importation.

B.2.7.4. Administrative, Management & Labor Costs.

B.2.7.5. Spare Parts & Repairs.

B.3. OTHER INVESTMENTS IN PROPERTY, FACILITIES & EQUIPMENT.- which will include the following subentries:

B.3.1. Furniture and equipment.- include the acquisition of furniture and office equipment necessary for the fulfillment of Development and Production activities. This subentry shall include all assets with a cost over five hundred dollars and a life cycle of over one year.

B.3.2. Vehicles.- includes the acquisition of necessary vehicles to be used during Development Investment.

B.4. TRANSPORTATION.- Air, land and river transportation costs for personnel, materials and equipment necessary for the execution of the Development and Production activities.

B.5. ROAD, EQUIPMENT AND FIELD MAINTENANCE.- These would include the maintenance costs for roads, facilities, equipment and fields, (except Base Camp) during the execution of Development and Production Investments, including technical services, staff, materials and spare parts corresponding to this entry.

B.6. BASE CAMP SERVICES.- Base Camp services and maintenance costs, including technical services, medical services, communication, staffing and materials necessary for its operation during the execution of Developing and Production Investments.

B.7. TECHNICAL INSURANCES AND GUARANTEES.- Insurance Policy costs, contracted to cover installations, equipment, vehicles and technical personnel, during Development and Production Investments, as well as the contractual warrantee costs corresponding to that investment period.

B.8. MAIN OFFICE SERVICES.- Direct and indirect services for the Main Office and related companies, corresponding to Development and Production Investment activities, including specific services and general support.

B.9. QUITO OFFICE SUPPORT.- Technical and administrative expenses related to the functional operation of the CONTRACTOR’S main office in Ecuador, applicable to Development and Production Investment activities, including among others, staff expenses, office rent, utilities (telephone, electric, water, postal services) supplies, professional wages, hired services, general insurances and other specific and general expenses corresponding to this entry.

B.10. SECONDARY RECOVERY.- Secondary recovery installation costs, including technical services, materials and staff corresponding to this entry.

B.11. FACILITY AND EQUIPMENT RESTITUTION.- Restitution costs that increase the value of facilities and equipment.

B.12. OTHER UNFORESEEN EXPENSES.- These correspond to other unforeseen expenses not mentioned in the previous entries, necessary during the execution of Development and Production Investment including expenses for environmental impact assessments, indemnifications for communities, etc.

C. DEPRECIATIONS AND AMORTIZATIONS

C.1. DEPRECIATION

The Support and Facilities equipment depreciation property of the CONTRACTOR will be calculated according to -Servicio de Rentas Internas- Internal Revenue Service standards, except for the last fiscal year of the contract when the total value of the CONTRACTOR’S assets must be amortized before they are reverted to the State.

C.2. AMORTIZATION

The CONTRACTOR’S amortization of the investment will take place in five years, taxable in equal percentages, considering that they are development investments, whereas for the maintenance investments its amortization will be by production units, that is up to twenty years, or for the life of the contrac6. As it is stated in the investment flows where it was determined the sole payment for the CONTRACTOR by Petroproduccion.

D. COSTS AND EXPENSES

All expenses made by the Contractor beginning the effective date shall be considered as Costs and Expenses.

D.1. ADMINISTRATIVE COSTS.- Which will include the following subentries:

D.1.1. General Expenses.- Correspond to the general functional expenses of the Contractor’s Main Office, directly related to this contract, including among those, office rent, utilities (telephone, electricity, water, postal services) supplies, general contracted services, general insurance, food services and other specific and general expenses inherent to this entry.

D.1.2. Costs related to Administrative Staff and their benefits.

D.1.3. Contributions to the Superintendence of Companies and other government and professional organisms.

D.1.4. Administrative insurance expenses corresponding to personnel and administrative assets insurance premium.

D.1.5. Administrative personnel transportation expenses, including foreign personnel and shipping and moving costs.

D.1.6. Main Office Administrative Services, correspond to direct and indirect services for the Main Office and related companies in Costs and Expenses administrative activities, including rendering of specific services and general support.

D.1.7. Professional Fees that correspond to expenses for professional service fees hired by the Contractor.

D.2. OPERATIONAL COSTS.- Which will include the following subentries:

D.2.1. Operational staff costs that correspond to technical personnel expenses linked to reservoir maintenance and production operations, including field superintendent, production manager, reservoir engineers, operators, mechanical, electrical, instrumentation, and materials maintenance personnel, and technical equipment for personal use, personnel and material transportation, etc, inherent to this entry, except senior staff and support personnel from the Operator’s main office, mentioned in D.3.1.

D.2.2. Consumable materials and transportation, corresponding to materials and supply expenses used in crude oil exploitation, its transportation to the operations area including, chemicals, fuels, lubricants and spare parts inherent to this subentry.

D.2.3. Production technical services correspond to contracted technical service costs inherent to reservoir exploitation, including wire lines, chemical treatments, stimulation, coiled tubing unit and other surface and corrosion treatments.

D.2.4. Maintenance, that corresponds to access road, facility, equipment, vehicle, and camp maintenance, including technical services tools, materials, staff and transportation inherent to this subentry.

D.2.5. Indemnities, costs corresponding to third party indemnity payments.

D.3. OTHER EXPENSES.- Which will include other non specified expenses from prior entries, necessary for the activities and which will be classified in the following subentries:

D.3.1. Personnel costs, corresponding to Senior Staff and Technical Support personnel from the Contractor’s Main Office’s expenses, including obligations with the state.

D.3.2. Technical insurance, related to exploitation activities, corresponding to reservoir, facilities, equipment and non-administrative staff technical insurance premiums.

D.3.3. Training Program, corresponds to Contractor’s staff training expenses.

D.3.4. Environmental protection, corresponds to environmental assessment studies and other tasks related to environmental protection, including technical services, materials and supplies for personnel expenses for those involved in the activities of this subentry.

D.3.5. Main Office technical services, correspond to direct and indirect services for the main office and related companies in cost and expense technical activities, including the rendering of specific services and general support.

D.3.6. OTHER EXPENSES.- Which will include other non specified expenses from prior entries, such as financial expenses necessary for contract development activities.

E. GENERAL MANDATORY REGULATIONS

The CONTRACTOR, to carry out its sales to the public sector and in Petroproduccion’s name with 0% tariff in the Value Added Tax (IVA), without it being able to be compensated in all its acquisitions, purchases or withholdings that take place, has the right that this un-used tax credit, it be returned or reimbursed through the respective credit note, check, or other form of payment, by the internal revenue service (SRI) or compensate with other obligations with the state.

The CONTRACTOR will be able to import under Petroproduccion’s name the goods that it may need for the fulfillment of the contract, in conformity with art. 109 of the Reformed Law of Tributary Equity in Ecuador, since said goods will be the property of the state.

E.1. OTHER TAXES LEVIES OR PAYMENTS

All the unforeseen factors that the CONTRACTOR may face in order to meet the object of this contract, and that are not specified, since they have not been considered in the economic part of the contract, in which a return to the investment was assured using the internal rate of return, with its only fee or payment, the CONTRACTOR will be able to request the reintegration or compensation to cover said taxes, levies, payments or unforeseen withdrawals to Petroproduccion.

ANNEX 7

HEAD OFFICE WARRANTY

IVANHOE ENERGY LATIN AMERICA INC., (Ivanhoe) a duly constituted and established company, under the laws of the Province of British Columbia, Canada, whose Main Office is located at Suite 654 — 999 Canada Place, Vancouver, British Columbia, V6C3E1, Canada, a company which from hereon forth shall be simply denominated as MAIN OFFICE, through this written document confirms to warrant due and integral compliance of all the obligations established in the Contract and shall provide all the technical, economic assistance and support necessary to its subsidiary IVANHOE ENERGY ECUADOR Inc, Ecuador Branch Office, a duly constituted and established branch office, under the laws of the Republic of Ecuador, as evidenced by Public Dead celebrated before the Notary Public, Dr. Remigio Poveda Vargas, Chief Officer of the Notary Number Seventeen, on February 18, 2008 and inscribed in the Mercantile Registry on March 11, 2008 and in the National Hydrocarbon Directorate on March 14, 2008, so that said branch office may fulfill all the investment obligations it acquires as a result of subscribing the SPECIFIC SERVICES CONTRACT FOR THE DEVELOPMENT AND PRODUCTION OF CRUDE OIL IN THE AREA OF THE CONTRACT, to be celebrated with, EMPRESA ESTATAL PETROLEOS DEL ECUADOR, PETROECUADOR AND ITS AFFILIATE, LA EMPRESA ESTATAL DE EXPLORACION Y PRODUCCION DE PETROLEOS DEL ECUADOR, PETROPRODUCCION.

The present warrantee shall be interpreted as such and in due compliance with Canadian law, excluding any other rule of law from any other jurisdiction, to which the present warrantee is subject to.

The MAIN OFFICE irrevocably commits to submit to the exclusive jurisdiction and competence of the judges and courts of the province of British Columbia — Canada, to resolve any controversy or claim associated or related to the present written document, including but not limited to the validity and compliance of the same.

Submitted to the exclusive competence and jurisdiction of the judges and courts of the Province of British Columbia — Canada, does in no way constitute a limitation to the right of the parties to initiate legal action whatsoever for the execution and fulfillment of any ruling or decision of said judges or courts.

IVANHOE ENERGY LATIN AMERICA INC.
Suite 654 – 999 Canada Place,
Vancouver, British Columbia,
V6C3E1, Canada

ANNEX 8

Rules of Arbitration of the International Chamber of Commerce (1998)

INTRODUCTORY PROVISIONS

Article 1

International Court of Arbitration

1. The International Court of Arbitration (the “Court”) of the International Chamber of Commerce (the “ICC”) is the arbitration body attached to the ICC. The statutes of the Court are set forth in Appendix I. Members of the Court are appointed by the World Council of the ICC. The function of the Court is to provide for the settlement by arbitration of business disputes of an international character in accordance with the Rules of Arbitration of the International Chamber of Commerce (the “Rules”).

If so empowered by an arbitration agreement, the Court shall also provide for the settlement by arbitration in accordance with these Rules of business disputes not of an international character.

2. The Court does not itself settle disputes. It has the function of ensuring the application of these Rules. It draws up its own Internal Rules (Appendix II).

3. The Chairman of the Court or, in the Chairman’s absence or otherwise at his request, one of its Vice-Chairmen shall have the power to take urgent decisions on behalf of the Court, provided that any such decision is reported to the Court at its next session.

4. As provided for in its Internal Rules, the Court may delegate to one or more committees composed of its members the power to take certain decisions, provided that any such decision is reported to the Court at its next session.

5. The Secretariat of the Court (the “Secretariat”) under the direction of its Secretary General (the “Secretary General”) shall have its seat at the headquarters of the ICC.

Article 2

Definitions

In these Rules:

(i) “Arbitral Tribunal” includes one or more arbitrators.

(ii) “Claimant” includes one or more claimants and “Respondent” includes one or more respondents.

(iii) “Award” includes, inter alia, an interim, partial or final Award.

Article 3

Written Notifications or Communications; Time Limits

1. All pleadings and other written communications submitted by any party, as well as all documents annexed thereto, shall be supplied in a number of copies sufficient to provide one copy for each party, plus one for each arbitrator, and one for the Secretariat. A copy of any communication from the Arbitral Tribunal to the parties shall be sent to the Secretariat.

2. All notifications or communications from the Secretariat and the Arbitral Tribunal shall be made to the last address of the party or its representative for whom the same are intended, as notified either by the party in question or by the other party. Such notification or communication may be made by delivery against receipt, registered post, courier, facsimile transmission, telex, telegram or any other means of telecommunication that provides a record of the sending thereof.

3. A notification or communication shall be deemed to have been made on the day it was received by the party itself or by its representative, or would have been received if made in accordance with the preceding paragraph.

4. Periods of time specified in or fixed under the present Rules shall start to run on the day following the date a notification or communication is deemed to have been made in accordance with the preceding paragraph. When the day next following such date is an official holiday, or a non-business day in the country where the notification or communication is deemed to have been made, the period of time shall commence on the first following business day. Official holidays and non-business days are included in the calculation of the period of time. If the last day of the relevant period of time granted is an official holiday or a non-business day in the country where the notification or communication is deemed to have been made, the period of time shall expire at the end of the first following business day.

COMMENCING THE ARBITRATION

Article 4

Request for Arbitration

1. A party wishing to have recourse to arbitration under these Rules shall submit its Request for Arbitration (the “Request”) to the Secretariat, which shall notify the Claimant and Respondent of the receipt of the Request and the date of such receipt.

2. The date on which the Request is received by the Secretariat shall, for all purposes, be deemed to be the date of the commencement of the arbitral proceedings.

3. The Request shall, inter alia, contain the following information:

a) the name in full, description and address of each of the parties;

b) a description of the nature and circumstances of the dispute giving rise to the claim(s);

c) a statement of the relief sought, including, to the extent possible, an indication of any amount(s) claimed;

d) the relevant agreements and, in particular, the arbitration agreement;

e) all relevant particulars concerning the number of arbitrators and their choice in accordance with the provisions of Articles 8, 9 and 10, and any nomination of an arbitrator required thereby; and f) any comments as to the place of arbitration, the applicable rules of law and the language of the arbitration.

4. Together with the Request, the Claimant shall submit the number of copies thereof required by Article 3(1) and shall make the advance payment on administrative expenses required by Appendix III (“Arbitration Costs and Fees”) in force on the date the Request is submitted. In the event that the Claimant fails to comply with either of these requirements, the Secretariat may fix a time limit within which the Claimant must comply, failing which the file shall be closed without prejudice to the right of the Claimant to submit the same claims at a later date in another Request.

5. The Secretariat shall send a copy of the Request and the documents annexed thereto to the Respondent for its Answer to the Request once the Secretariat has sufficient copies of the Request and the required advance payment.

6. When a party submits a Request in connection with a legal relationship in respect of which arbitration proceedings between the same parties are already pending under these Rules, the Court may, at the request of a party, decide to include the claims contained in the Request in the pending proceedings provided that the Terms of Reference have not been signed or approved by the Court. Once the Terms of Reference have been signed or approved by the Court, claims may only be included in the pending proceedings subject to the provisions of Article 19.

Article 5

Answer to the Request; Counterclaims

1. Within 30 days from the receipt of the Request from the Secretariat, the Respondent shall file an Answer (the “Answer”) which shall, inter alia, contain the following information:

a) its name in full, description and address;

b) its comments as to the nature and circumstances of the dispute giving rise to the claim(s);

c) its response to the relief sought;

d) any comments concerning the number of arbitrators and their choice in light of the Claimant’s proposals and in accordance with the provisions of Articles 8, 9 and 10, and any nomination of an arbitrator required thereby; and

e) any comments as to the place of arbitration, the applicable rules of law and the language of the arbitration.

2. The Secretariat may grant the Respondent an extension of the time for filing the Answer, provided the application for such an extension contains the Respondent’s comments concerning the number of arbitrators and their choice and, where required by Articles 8, 9 and 10, the nomination of an arbitrator. If the Respondent fails to do so, the Court shall proceed in accordance with these Rules.

3. The Answer shall be supplied to the Secretariat in the number of copies specified by Article 3(1).

4. A copy of the Answer and the documents annexed thereto shall be communicated by the Secretariat to the Claimant.

5. Any counterclaim(s) made by the Respondent shall be filed with its Answer and shall provide:

a) a description of the nature and circumstances of the dispute giving rise to the counterclaim(s); and

b) a statement of the relief sought, including, to the extent possible, an indication of any amount(s) counterclaimed.

6. The Claimant shall file a Reply to any counterclaim within 30 days from the date of receipt of the counterclaim(s) communicated by the Secretariat. The Secretariat may grant the Claimant an extension of time for filing the Reply.

Article 6

Effect of the Arbitration Agreement

1. Where the parties have agreed to submit to arbitration under the Rules, they shall be deemed to have submitted ipso facto to the Rules in effect on the date of commencement of the arbitration proceedings, unless they have agreed to submit to the Rules in effect on the date of their arbitration agreement.

2. If the Respondent does not file an Answer, as provided by Article 5, or if any party raises one or more pleas concerning the existence, validity or scope of the arbitration agreement, the Court may decide, without prejudice to the admissibility or merits of the plea or pleas, that the arbitration shall proceed if it is prima facie satisfied that an arbitration agreement under the Rules may exist. In such a case, any decision as to the jurisdiction of the Arbitral Tribunal shall be taken by the Arbitral Tribunal itself. If the Court is not so satisfied, the parties shall be notified that the arbitration cannot proceed. In such a case, any party retains the right to ask any court having jurisdiction whether or not there is a binding arbitration agreement.

3. If any of the parties refuses or fails to take part in the arbitration or any stage thereof, the arbitration shall proceed notwithstanding such refusal or failure.

4. Unless otherwise agreed, the Arbitral Tribunal shall not cease to have jurisdiction by reason of any claim that the contract is null and void or allegation that it is non-existent, provided that the Arbitral Tribunal upholds the validity of the arbitration agreement. The Arbitral Tribunal shall continue to have jurisdiction to determine the respective rights of the parties and to adjudicate their claims and pleas even though the contract itself may be non-existent or null and void.

THE ARBITRAL TRIBUNAL

Article 7

General Provisions

1. Every arbitrator must be and remain independent of the parties involved in the arbitration.

2. Before appointment or confirmation, a prospective arbitrator shall sign a statement of independence and disclose in writing to the Secretariat any facts or circumstances which might be of such a nature as to call into question the arbitrator’s independence in the eyes of the parties. The Secretariat shall provide such information to the parties in writing and fix a time limit for any comments from them.

3. An arbitrator shall immediately disclose in writing to the Secretariat and to the parties any facts or circumstances of a similar nature which may arise during the arbitration.

4. The decisions of the Court as to the appointment, confirmation, challenge or replacement of an arbitrator shall be final and the reasons for such decisions shall not be communicated.

5. By accepting to serve, every arbitrator undertakes to carry out his responsibilities in accordance with these Rules.

6. Insofar as the parties have not provided otherwise, the Arbitral Tribunal shall be constituted in accordance with the provisions of Articles 8, 9 and 10.

Article 8

Number of Arbitrators

1. The disputes shall be decided by a sole arbitrator or by three arbitrators.

2. Where the parties have not agreed upon the number of arbitrators, the Court shall appoint a sole arbitrator, save where it appears to the Court that the dispute is such as to warrant the appointment of three arbitrators. In such case, the Claimant shall nominate an arbitrator within a period of 15 days from the receipt of the notification of the decision of the Court, and the Respondent shall nominate an arbitrator within a period of 15 days from the receipt of the notification of the nomination made by the Claimant.

3. Where the parties have agreed that the dispute shall be settled by a sole arbitrator, they may, by agreement, nominate the sole arbitrator for confirmation. If the parties fail to nominate a sole arbitrator within 30 days from the date when the Claimant’s Request for Arbitration has been received by the other party, or within such additional time as may be allowed by the Secretariat, the sole arbitrator shall be appointed by the Court.

4. Where the dispute is to be referred to three arbitrators, each party shall nominate in the Request and the Answer, respectively, one arbitrator for confirmation. If a party fails to nominate an arbitrator, the appointment shall be made by the Court. The third arbitrator, who will act as chairman of the Arbitral Tribunal, shall be appointed by the Court, unless the parties have agreed upon another procedure for such appointment, in which case the nomination will be subject to confirmation pursuant to Article 9. Should such procedure not result in a nomination within the time limit fixed by the parties or the Court, the third arbitrator shall be appointed by the Court.

Article 9

Appointment and Confirmation of the Arbitrators

1. In confirming or appointing arbitrators, the Court shall consider the prospective arbitrator’s nationality, residence and other relationships with the countries of which the parties or the other arbitrators are nationals and the prospective arbitrator’s availability and ability to conduct the arbitration in accordance with these Rules. The same shall apply where the Secretary General confirms arbitrators pursuant to Article 9(2).

2. The Secretary General may confirm as co-arbitrators, sole arbitrators and chairmen of Arbitral Tribunals persons nominated by the parties or pursuant to their particular agreements, provided they have filed a statement of independence without qualification or a qualified statement of independence has not given rise to objections. Such confirmation shall be reported to the Court at its next session. If the Secretary General considers that a co-arbitrator, sole arbitrator or chairman of an Arbitral Tribunal should not be confirmed, the matter shall be submitted to the Court.

3. Where the Court is to appoint a sole arbitrator or the chairman of an Arbitral Tribunal, it shall make the appointment upon a proposal of a National Committee of the ICC that it considers to be appropriate. If the Court does not accept the proposal made, or if the National Committee fails to make the proposal requested within the time limit fixed by the Court, the Court may repeat its request or may request a proposal from another National Committee that it considers to be appropriate.

4. Where the Court considers that the circumstances so demand, it may choose the sole arbitrator or the chairman of the Arbitral Tribunal from a country where there is no National Committee, provided that neither of the parties objects within the time limit fixed by the Court.

5. The sole arbitrator or the chairman of the Arbitral Tribunal shall be of a nationality other than those of the parties.

However, in suitable circumstances and provided that neither of the parties objects within the time limit fixed by the Court, the sole arbitrator or the chairman of the Arbitral Tribunal may be chosen from a country of which any of the parties is a national.

6. Where the Court is to appoint an arbitrator on behalf of a party which has failed to nominate one, it shall make the appointment upon a proposal of the National Committee of the country of which that party is a national. If the Court does not accept the proposal made, or if the National Committee fails to make the proposal requested within the time limit fixed by the Court, or if the country of which the said party is a national has no National Committee, the Court shall be at liberty to choose any person whom it regards as suitable. The Secretariat shall inform the National Committee, if one exists, of the country of which such person is a national.

Article 10

Multiple Parties

1. Where there are multiple parties, whether as Claimant or as Respondent, and where the dispute is to be referred to three arbitrators, the multiple Claimants, jointly, and the multiple Respondents, jointly, shall nominate an arbitrator for confirmation pursuant to Article 9.

2. In the absence of such a joint nomination and where all parties are unable to agree to a method for the constitution of the Arbitral Tribunal, the Court may appoint each member of the Arbitral Tribunal and shall designate one of them to act as chairman. In such case, the Court shall be at liberty to choose any person it regards as suitable to act as arbitrator, applying Article 9 when it considers this appropriate.

Article 11

Challenge of Arbitrators

1. A challenge of an arbitrator, whether for an alleged lack of independence or otherwise, shall be made by the submission to the Secretariat of a written statement specifying the facts and circumstances on which the challenge is based.

2. For a challenge to be admissible, it must be sent by a party either within 30 days from receipt by that party of the notification of the appointment or confirmation of the arbitrator, or within 30 days from the date when the party making the challenge was informed of the facts and circumstances on which the challenge is based if such date is subsequent to the receipt of such notification.

3. The Court shall decide on the admissibility and, at the same time, if necessary, on the merits of a challenge after the Secretariat has afforded an opportunity for the arbitrator concerned, the other party or parties and any other members of the Arbitral Tribunal to comment in writing within a suitable period of time. Such comments shall be communicated to the parties and to the arbitrators.

Article 12

Replacement of Arbitrators

1. An arbitrator shall be replaced upon his death, upon the acceptance by the Court of the arbitrator’s resignation, upon acceptance by the Court of a challenge, or upon the request of all the parties.

2. An arbitrator shall also be replaced on the Court’s own initiative when it decides that he is prevented de jure or de facto from fulfilling his functions, or that he is not fulfilling his functions in accordance with the Rules or within the prescribed time limits.

3. When, on the basis of information that has come to its attention, the Court considers applying Article 12(2), it shall decide on the matter after the arbitrator concerned, the parties and any other members of the Arbitral Tribunal have had an opportunity to comment in writing within a suitable period of time. Such comments shall be communicated to the parties and to the arbitrators.

4. When an arbitrator is to be replaced, the Court has discretion to decide whether or not to follow the original nominating process. Once reconstituted, and after having invited the parties to comment, the Arbitral Tribunal shall determine if and to what extent prior proceedings shall be repeated before the reconstituted Arbitral Tribunal.

5. Subsequent to the closing of the proceedings, instead of replacing an arbitrator who has died or been removed by the Court pursuant to Articles 12(1) and 12(2), the Court may decide, when it considers it appropriate, that the remaining arbitrators shall continue the arbitration. In making such determination, the Court shall take into account the views of the remaining arbitrators and of the parties and such other matters that it considers appropriate in the circumstances.

THE ARBITRAL PROCEEDINGS

Article 13

Transmission of the File to the Arbitral Tribunal

The Secretariat shall transmit the file to the Arbitral Tribunal as soon as it has been constituted, provided the advance on costs requested by the Secretariat at this stage has been paid.

Article 14

Place of the Arbitration

1. The place of the arbitration shall be fixed by the Court unless agreed upon by the parties.

2. The Arbitral Tribunal may, after consultation with the parties, conduct hearings and meetings at any location it considers appropriate unless otherwise agreed by the parties.

3. The Arbitral Tribunal may deliberate at any location it considers appropriate.

Article 15

Rules Governing the Proceedings

1. The proceedings before the Arbitral Tribunal shall be governed by these Rules and, where these Rules are silent, by any rules which the parties or, failing them, the Arbitral Tribunal may settle on, whether or not reference is thereby made to the rules of procedure of a national law to be applied to the arbitration.

2. In all cases, the Arbitral Tribunal shall act fairly and impartially and ensure that each party has a reasonable opportunity to present its case.

Article 16

Language of the Arbitration

In the absence of an agreement by the parties, the Arbitral Tribunal shall determine the language or languages of the arbitration, due regard being given to all relevant circumstances, including the language of the contract.

Article 17

Applicable Rules of Law

1. The parties shall be free to agree upon the rules of law to be applied by the Arbitral Tribunal to the merits of the dispute. In the absence of any such agreement, the Arbitral Tribunal shall apply the rules of law which it determines to be appropriate.

2. In all cases the Arbitral Tribunal shall take account of the provisions of the contract and the relevant trade usages.

3. The Arbitral Tribunal shall assume the powers of an amiable compositeur or decide ex aequo et bono only if the parties have agreed to give it such powers.

Article 18

Terms of Reference; Procedural Timetable

1. As soon as it has received the file from the Secretariat, the Arbitral Tribunal shall draw up, on the basis of documents or in the presence of the parties and in the light of their most recent submissions, a document defining its Terms of Reference. This document shall include the following particulars:

a) the full names and descriptions of the parties;

b) the addresses of the parties to which notifications and communications arising in the course of the arbitration may be made;

c) a summary of the parties’ respective claims and of the relief sought by each party, with an indication to the extent possible of the amounts claimed or counterclaimed;

d) unless the Arbitral Tribunal considers it inappropriate, a list of issues to be determined;

e) the full names, descriptions and addresses of the arbitrators;

f) the place of the arbitration; and

g) particulars of the applicable procedural rules and, if such is the case, reference to the power conferred upon the Arbitral Tribunal to act as amiable compositeur or to decide ex aequo et bono.

2. The Terms of Reference shall be signed by the parties and the Arbitral Tribunal. Within two months of the date on which the file has been transmitted to it, the Arbitral Tribunal shall transmit to the Court the Terms of Reference signed by it and by the parties. The Court may extend this time limit pursuant to a reasoned request from the Arbitral Tribunal or on its own initiative if it decides it is necessary to do so.

3. If any of the parties refuses to take part in the drawing up of the Terms of Reference or to sign the same, they shall be submitted to the Court for approval. When the Terms of Reference have been signed in accordance with Article 18(2) or approved by the Court, the arbitration shall proceed.

4. When drawing up the Terms of Reference, or as soon as possible thereafter, the Arbitral Tribunal, after having consulted the parties, shall establish in a separate document a provisional timetable that it intends to follow for the conduct of the arbitration and shall communicate it to the Court and the parties. Any subsequent modifications of the provisional timetable shall be communicated to the Court and the parties.

Article 19

New Claims

After the Terms of Reference have been signed or approved by the Court, no party shall make new claims or counterclaims which fall outside the limits of the Terms of Reference unless it has been authorized to do so by the Arbitral Tribunal, which shall consider the nature of such new claims or counterclaims, the stage of the arbitration and other relevant circumstances.

Article 20

Establishing the Facts of the Case

1. The Arbitral Tribunal shall proceed within as short a time as possible to establish the facts of the case by all appropriate means.

2. After studying the written submissions of the parties and all documents relied upon, the Arbitral Tribunal shall hear the parties together in person if any of them so requests or, failing such a request, it may of its own motion decide to hear them.

3. The Arbitral Tribunal may decide to hear witnesses, experts appointed by the parties or any other person, in the presence of the parties, or in their absence provided they have been duly summoned.

4. The Arbitral Tribunal, after having consulted the parties, may appoint one or more experts, define their terms of reference and receive their reports. At the request of a party, the parties shall be given the opportunity to question at a hearing any such expert appointed by the Tribunal.

5. At any time during the proceedings, the Arbitral Tribunal may summon any party to provide additional evidence.

6. The Arbitral Tribunal may decide the case solely on the documents submitted by the parties unless any of the parties requests a hearing.

7. The Arbitral Tribunal may take measures for protecting trade secrets and confidential information.

Article 21

Hearings

1. When a hearing is to be held, the Arbitral Tribunal, giving reasonable notice, shall summon the parties to appear before it on the day and at the place fixed by it.

2. If any of the parties, although duly summoned, fails to appear without valid excuse, the Arbitral Tribunal shall have the power to proceed with the hearing.

3. The Arbitral Tribunal shall be in full charge of the hearings, at which all the parties shall be entitled to be present. Save with the approval of the Arbitral Tribunal and the parties, persons not involved in the proceedings shall not be admitted.

4. The parties may appear in person or through duly authorized representatives. In addition, they may be assisted by advisers.

Article 22

Closing of the Proceedings

1. When it is satisfied that the parties have had a reasonable opportunity to present their cases, the Arbitral Tribunal shall declare the proceedings closed. Thereafter, no further submission or argument may be made, or evidence produced, unless requested or authorized by the Arbitral Tribunal.

2. When the Arbitral Tribunal has declared the proceedings closed, it shall indicate to the Secretariat an approximate date by which the draft Award will be submitted to the Court for approval pursuant to Article 27. Any postponement of that date shall be communicated to the Secretariat by the Arbitral Tribunal.

Article 23

Conservatory and Interim Measures

1. Unless the parties have otherwise agreed, as soon as the file has been transmitted to it, the Arbitral Tribunal may, at the request of a party, order any interim or conservatory measure it deems appropriate. The Arbitral Tribunal may make the granting of any such measure subject to appropriate security being furnished by the requesting party. Any such measure shall take the form of an order, giving reasons, or of an Award, as the Arbitral Tribunal considers appropriate.

2. Before the file is transmitted to the Arbitral Tribunal, and in appropriate circumstances even thereafter, the parties may apply to any competent judicial authority for interim or conservatory measures. The application of a party to a judicial authority for such measures or for the implementation of any such measures ordered by an Arbitral Tribunal shall not be deemed to be an infringement or a waiver of the arbitration agreement and shall not affect the relevant powers reserved to the Arbitral Tribunal. Any such application and any measures taken by the judicial authority must be notified without delay to the Secretariat. The Secretariat shall inform the Arbitral Tribunal thereof.

AWARDS

Article 24

Time Limit for the Award

1. The time limit within which the Arbitral Tribunal must render its final Award is six months. Such time limit shall start to run from the date of the last signature by the Arbitral Tribunal or by the parties of the Terms of Reference or, in the case of application of Article 18(3), the date of the notification to the Arbitral Tribunal by the Secretariat of the approval of the Terms of Reference by the Court.

2. The Court may extend this time limit pursuant to a reasoned request from the Arbitral Tribunal or on its own initiative if it decides it is necessary to do so.

Article 25

Making of the Award

1. When the Arbitral Tribunal is composed of more than one arbitrator, an Award is given by a majority decision. If there be no majority, the Award shall be made by the chairman of the Arbitral Tribunal alone.

2. The Award shall state the reasons upon which it is based.

3. The Award shall be deemed to be made at the place of the arbitration and on the date stated therein.

Article 26

Award by Consent

If the parties reach a settlement after the file has been transmitted to the Arbitral Tribunal in accordance with Article 13, the settlement shall be recorded in the form of an Award made by consent of the parties if so requested by the parties and if the Arbitral Tribunal agrees to do so.

Article 27

Scrutiny of the Award by the Court

Before signing any Award, the Arbitral Tribunal shall submit it in draft form to the Court. The Court may lay down modifications as to the form of the Award and, without affecting the Arbitral Tribunal’s liberty of decision, may also draw its attention to points of substance. No Award shall be rendered by the Arbitral Tribunal until it has been approved by the Court as to its form.

Article 28

Notification, Deposit and Enforceability of the Award

1. Once an Award has been made, the Secretariat shall notify to the parties the text signed by the Arbitral Tribunal, provided always that the costs of the arbitration have been fully paid to the ICC by the parties or by one of them.

2. Additional copies certified true by the Secretary General shall be made available on request and at any time to the parties, but to no one else.

3. By virtue of the notification made in accordance with Paragraph 1 of this Article, the parties waive any other form of notification or deposit on the part of the Arbitral Tribunal.

4. An original of each Award made in accordance with the present Rules shall be deposited with the Secretariat.

5. The Arbitral Tribunal and the Secretariat shall assist the parties in complying with whatever further formalities may be necessary.

6. Every Award shall be binding on the parties. By submitting the dispute to arbitration under these Rules, the parties undertake to carry out any Award without delay and shall be deemed to have waived their right to any form of recourse insofar as such waiver can validly be made.

Article 29

Correction and Interpretation of the Award

1. On its own initiative, the Arbitral Tribunal may correct a clerical, computational or typographical error, or any errors of similar nature contained in an Award, provided such correction is submitted for approval to the Court within 30 days of the date of such Award.

2. Any application of a party for the correction of an error of the kind referred to in Article 29(1), or for the interpretation of an Award, must be made to the Secretariat within 30 days of the receipt of the Award by such party, in a number of copies as stated in Article 3(1).

After transmittal of the application to the Arbitral Tribunal, the latter shall grant the other party a short time limit, normally not exceeding 30 days, from the receipt of the application by that party, to submit any comments thereon. If the Arbitral Tribunal decides to correct or interpret the Award, it shall submit its decision in draft form to the Court not later than 30 days following the expiration of the time limit for the receipt of any comments from the other party or within such other period as the Court may decide.

3. The decision to correct or to interpret the Award shall take the form of an addendum and shall constitute part of the Award. The provisions of Articles 25, 27 and 28 shall apply mutatis mutandis.

COSTS

Article 30

Advance to Cover the Costs of the Arbitration

1. After receipt of the Request, the Secretary General may request the Claimant to pay a provisional advance in an amount intended to cover the costs of arbitration until the Terms of Reference have been drawn up.

2. As soon as practicable, the Court shall fix the advance on costs in an amount likely to cover the fees and expenses of the arbitrators and the ICC administrative costs for the claims and counterclaims which have been referred to it by the parties. This amount may be subject to readjustment at any time during the arbitration. Where, apart from the claims, counterclaims are submitted, the Court may fix separate advances on costs for the claims and the counterclaims.

3. The advance on costs fixed by the Court shall be payable in equal shares by the Claimant and the Respondent. Any provisional advance paid on the basis of Article 30(1) will be considered as a partial payment thereof. However, any party shall be free to pay the whole of the advance on costs in respect of the principal claim or the counterclaim should the other party fail to pay its share. When the Court has set separate advances on costs in accordance with Article 30(2), each of the parties shall pay the advance on costs corresponding to its claims.

4. When a request for an advance on costs has not been complied with, and after consultation with the Arbitral Tribunal, the Secretary General may direct the Arbitral Tribunal to suspend its work and set a time limit, which must be not less than 15 days, on the expiry of which the relevant claims, or counterclaims, shall be considered as withdrawn. Should the party in question wish to object to this measure, it must make a request within the aforementioned period for the matter to be decided by the Court. Such party shall not be prevented, on the ground of such withdrawal, from reintroducing the same claims or counterclaims at a later date in another proceeding.

5. If one of the parties claims a right to a set-off with regard to either claims or counterclaims, such set-off shall be taken into account in determining the advance to cover the costs of arbitration in the same way as a separate claim insofar as it may require the Arbitral Tribunal to consider additional matters.

Article 31

Decision as to the Costs of the Arbitration

1. The costs of the arbitration shall include the fees and expenses of the arbitrators and the ICC administrative expenses fixed by the Court, in accordance with the scale in force at the time of the commencement of the arbitral proceedings, as well as the fees and expenses of any experts appointed by the Arbitral Tribunal and the reasonable legal and other costs incurred by the parties for the arbitration.

2. The Court may fix the fees of the arbitrators at a figure higher or lower than that which would result from the application of the relevant scale should this be deemed necessary due to the exceptional circumstances of the case. Decisions on costs other than those fixed by the Court may be taken by the Arbitral Tribunal at any time during the proceedings.

3. The final Award shall fix the costs of the arbitration and decide which of the parties shall bear them or in what proportion they shall be borne by the parties.

MISCELLANEOUS

Article 32

Modified Time Limits

1. The parties may agree to shorten the various time limits set out in these Rules. Any such agreement entered into subsequent to the constitution of an Arbitral Tribunal shall become effective only upon the approval of the Arbitral Tribunal.

2. The Court, on its own initiative, may extend any time limit which has been modified pursuant to Article 32(1) if it decides that it is necessary to do so in order that the Arbitral Tribunal or the Court may fulfil their responsibilities in accordance with these Rules.

Article 33

Waiver

A party which proceeds with the arbitration without raising its objection to a failure to comply with any provision of these Rules, or of any other rules applicable to the proceedings, any direction given by the Arbitral Tribunal, or any requirement under the arbitration agreement relating to the constitution of the Arbitral Tribunal, or to the conduct of the proceedings, shall be deemed to have waived its right to object.

Article 34

Exclusion of Liability

Neither the arbitrators, nor the Court and its members, nor the ICC and its employees, nor the ICC National Committees shall be liable to any person for any act or omission in connection with the arbitration.

Article 35

General Rule

In all matters not expressly provided for in these Rules, the Court and the Arbitral Tribunal shall act in the spirit of these Rules and shall make every effort to make sure that the Award is enforceable at law.

ARBITRATION COSTS AND FEES

Article 1

Advance on Costs

1. Each request to commence an arbitration pursuant to the Rules must be accompanied by an advance payment of US$ 2,500 on the administrative expenses. Such payment is non-refundable, and shall be credited to the Claimant’s portion of the advance on costs.

2. The provisional advance fixed by the Secretary General according to Article 30(1) of the Rules shall normally not exceed the amount obtained by adding together the administrative expenses, the minimum of the fees (as set out in the scale hereinafter) based upon the amount of the claim and the expected reimbursable expenses of the Arbitral Tribunal incurred with respect to the drafting of the Terms of Reference. If such amount is not quantified, the provisional advance shall be fixed at the discretion of the Secretary General. Payment by the Claimant shall be credited to its share of the advance on costs fixed by the Court.

3. In general, after the Terms of Reference have been signed or approved by the Court and the provisional timetable has been established, the Arbitral Tribunal shall, in accordance with Article 30(4) of the Rules, proceed only with respect to those claims or counterclaims in regard to which the whole of the advance on costs has been paid.

4. The advance on costs fixed by the Court according to Article 30(2) of the Rules comprises the fees of the arbitrator or arbitrators (hereinafter referred to as “arbitrator”), any arbitration-related expenses of the arbitrator and the administrative expenses.

5. Each party shall pay in cash its share of the total advance on costs. However, if its share exceeds an amount fixed from time to time by the Court, a party may post a bank guarantee for this additional amount.

6. A party that has already paid in full its share of the advance on costs fixed by the Court may, in accordance with Article 30(3) of the Rules, pay the unpaid portion of the advance owed by the defaulting party by posting a bank guarantee.

7. When the Court has fixed separate advances on costs pursuant to Article 30(2) of the Rules, the Secretariat shall invite each party to pay the amount of the advance corresponding to its respective claim(s).

8. When, as a result of the fixing of separate advances on costs, the separate advance fixed for the claim of either party exceeds one half of such global advance as was previously fixed (in respect of the same claims and counterclaims that are the subject of separate advances), a bank guarantee may be posted to cover any such excess amount. In the event that the amount of the separate advance is subsequently increased, at least one half of the increase shall be paid in cash.

9. The Secretariat shall establish the terms governing all bank guarantees which the parties may post pursuant to the above provisions.

10. As provided in Article 30(2) of the Rules, the advance on costs may be subject to readjustment at any time during the arbitration, in particular to take into account fluctuations in the amount in dispute, changes in the amount of the estimated expenses of the arbitrator, or the evolving difficulty or complexity of arbitration proceedings.

11. Before any expertise ordered by the Arbitral Tribunal can be commenced, the parties, or one of them, shall pay an advance on costs fixed by the Arbitral Tribunal sufficient to cover the expected fees and expenses of the expert as determined by the Arbitral Tribunal. The Arbitral Tribunal shall be responsible for ensuring the payment by the parties of such fees and expenses.

Article 2

Costs and Fees

1. Subject to Article 31(2) of the Rules, the Court shall fix the fees of the arbitrator in accordance with the scale hereinafter set out or, where the sum in dispute is not stated, at its discretion.

2. In setting the arbitrator’s fees, the Court shall take into consideration the diligence of the arbitrator, the time spent, the rapidity of the proceedings, and the complexity of the dispute, so as to arrive at a figure within the limits specified or, in exceptional circumstances (Article 31(2) of the Rules), at a figure higher or lower than those limits.

3. When a case is submitted to more than one arbitrator, the Court, at its discretion, shall have the right to increase the total fees up to a maximum which shall normally not exceed three times the fees of one arbitrator.

4. The arbitrator’s fees and expenses shall be fixed exclusively by the Court as required by the Rules. Separate fee arrangements between the parties and the arbitrator are contrary to the Rules.

5. The Court shall fix the administrative expenses of each arbitration in accordance with the scale hereinafter set out or, where the sum in dispute is not stated, at its discretion. In exceptional circumstances, the Court may fix the administrative expenses at a lower or higher figure than that which would result from the application of such scale, provided that such expenses shall normally not exceed the maximum amount of the scale. Further, the Court may require the payment of administrative expenses in addition to those provided in the scale of administrative expenses as a condition to holding an arbitration in abeyance at the request of the parties or of one of them with the acquiescence of the other.

6. If an arbitration terminates before the rendering of a final Award, the Court shall fix the costs of the arbitration at its discretion, taking into account the stage attained by the arbitral proceedings and any other relevant circumstances.

7. In the case of an application under Article 29(2) of the Rules, the Court may fix an advance to cover additional fees and expenses of the Arbitral Tribunal and may make the transmission of such application to the Arbitral Tribunal subject to the prior cash payment in full to the ICC of such advance. The Court shall fix at its discretion any possible fees of the arbitrator when approving the decision of the Arbitral Tribunal.

8. When an arbitration is preceded by an attempt at amicable resolution pursuant to the ICC ADR Rules, one half of the administrative expenses paid for such ADR proceedings shall be credited to the administrative expenses of the arbitration.

9. Amounts paid to the arbitrator do not include any possible value added taxes (VAT) or other taxes or charges and imposts applicable to the arbitrator’s fees. Parties have a duty to pay any such taxes or charges; however, the recovery of any such charges or taxes is a matter solely between the arbitrator and the parties.

Article 3

Appointments of Arbitrators

1. A registration fee normally not exceeding US$ 2,500 is payable by the requesting party in respect of each request made to the ICC to appoint an arbitrator for any arbitration not conducted under the Rules. No request for appointment of an arbitrator will be considered unless accompanied by the said fee, which is not recoverable and becomes the property of the ICC.

2. The said fee shall cover any additional services rendered by the ICC regarding the appointment, such as decisions on a challenge of an arbitrator and the appointment of a substitute arbitrator.

Article 4

Scales of Administrative Expenses and Arbitrator’s Fees

1. The Scales of Administrative Expenses and Arbitrator’s Fees set forth below shall be effective as of 1 January 1998 in respect of all arbitrations commenced on or after such date, irrespective of the version of the Rules applying to such arbitrations.

2. To calculate the administrative expenses and the arbitrator’s fees, the amounts calculated for each successive slice of the sum in dispute must be added together, except that where the sum in dispute is over US$ 80 million, a flat amount of US$ 75,800 shall constitute the entirety of the administrative expenses.

A. ADMINISTRATIVE EXPENSES

Sum in dispute (in US Dollars)				Administrative expenses (*)
up to	50 000			$	2 500
from	50 001	to	100 000		3.50	%
from	100 001	to	500 000		1.70	%
from	500 001	to	1 000 000		1.15	%
from	1 000 001	to	2 000 000		0.60	%
from	2 000 001	to	5 000 000		0.20	%
from	5 000 001	to	10 000 000		0.10	%
from	10 000 001	to	50 000 000		0.06	%
from	50 000 001	to	80 000 000		0.06	%
over	80 000 000			$	75 800

(*) For illustrative purposes only, the table on the following page indicates the resulting administrative expenses in US$ when the proper calculations have been made.

B. ARBITRATOR’S FEES

Sum in dispute (in US Dollars)				Fees (**)
				minimum			maximum
up to	50 000			$	2500			17.00	%
from	50 001	to	100 000		2.00	%		11.00	%
from	100 001	to	500 000		1.00	%		5.50	%
from	500 001	to	1 000 000		0.75	%		3.50	%
from	1 000 001	to	2 000 000		0.50	%		2.50	%
from	2 000 001	to	5 000 000		0.25	%		1.00	%
from	5 000 001	to	10 000 000		0.10	%		0.55	%
from	10 000 001	to	50 000 000		0.05	%		0.17	%
from	50 000 001	to	80 000 000		0.03	%		0.12	%
from	80 000 000	to	100 000 000		0.02	%		0.10	%
over	100 000 000				0.01	%		0.05	%

(**) For illustrative purposes only, the table on the following page indicates the resulting range of fees when the proper calculations have been made.

				DISPUTE A. ADMINISTRATIVE
SUM IN DISPUTE (in US Dollars)				EXPENSES (in US Dollars) (*)
up to	50 000			2 500
from	50 001	to	100 000	2 500 + 3.50% of amt. over 50 000
from	100 001	to	500 000	4 250 + 1.70% of amt. over 100 000
from	500 001	to	1 000 000	11 050 + 1.15% of amt. over 500 000
from	1 000 001	to	2 000 000	16 800 + 0.60% of amt. over 1 000 000
from	2 000 001	to	5 000 000	22 800 + 0.20% of amt. over 2 000 000
from	5 000 001	to	10 000 000	28 800 + 0.10% of amt. over 5 000 000
from	10 000 001	to	50 000 000	33 800 + 0.06% of amt. over 10 000 000
from	50 000 001	to	80 000 000	57 800 + 0.06% of amt. over 50 000 000
from	80 000 000	to	100 000 000	75 800
over	100 000 000			75 800

(*) See above

ANNEX 9

(Translation of the State Attorney General’s Official Letter)

Official Letter No. 03161

Quito, September 9, 2008

Captain Camilo Delgado Montenegro
VICE-PRESIDENT
PETROPRODUCCION
Quito

Dear Sir:

This is with reference to your letter 7120-PPR-LEG-2008 of August 21, 2008, received in this Control Entity with record No 08566. The above-referenced letter requests a legal opinion on the draft contract for specific services to develop and produce crude oil in the Pungarayacu Field, in Block 20. The contractor IVANHOE ENERGY ECUADOR INC will contribute with technology, capital, equipment and other goods and services required to fulfill its contractual obligations using the HTL technology owned by IVANHOE ENERGY ECUADOR INC, to improve crude quality, confirm reserves and perform complementary drilling activities in the pre-cretaceous of the Pungarayacu field, in a term of 30 years.

BACKGROUND

The Contracting Committee, through Resolution 794-CEL-2008 dated February 1, 2008, “RESOLVED TO CANCEL RESOLUTION CEL No 653-CEL-2003 of August 3, 2003, WHICH AUTHORIZED INITIATION OF THE COMPETITIVE BIDDING PROCESSES FOR BLOCKS 20 AND 29 IN THE AMAZON REGION”.

Through Official Letter 176-SJ461/DM-2006 dated April 11, 2008, the temporary Minister of Mines and Petroleum, informed the Executive President of PETROECUADOR: “... that the legal basis that would apply in celebrating the contract with IVANHOE to Develop and Exploit Heavy Oil in the Pungarayacu Field of the Ecuadorian Amazon Region will be that of a Contract for Specific Works, Goods and Services, established in Article 17, Hydrocarbons Law, and in the Contracting Regulations for Goods, Works and Services of PETROECUADOR and its Affiliate Companies, issued through Executive Decree No 552 and published in Official Register 194 of October 19, 2007...”

PETROECUADOR’s Executive President, through letter 392-PEP-2008 of June 9, 2008, appointed a Committee to review IVANHOE ENERGY ECUADOR INC’s proposal. On June 10, 2008t, this Committee submitted the “CONCLUSIVE FINAL MINUTES INVOLVING IVANHOE ENERGY ECUADOR INC’s proposal. On June 11, 2008, the Committee submitted “AN ADDENDUM TO THE NEGOTIATING MINUTES REGARDING THE DRAFT CONTRACT TO BE ENTERED BETWEEN PETROECUADOR, PETROPRODUCCION AND IVANHOE ENERGY ECUADOR INC FOR SPECIFIC SERVICES TO DEVELOP AND EXPLOIT CRUDE OIL IN BLOCK 20, PUNGARAYACU FIELD, IN THE AMAZON REGION”. The Legal Committee stated that “among the direct Contracting procedures, Art 23, letter b) of the above-mentioned Regulations¹, establishes that this method may be used for unique suppliers when the use of patents or trademarks are involved, which would be the case of Ivanhoe Energy Ecuador Inc.”. The Committee recommended “the Vice-President of PETROPRODUCCION to ask the Contracting Committee to award and authorize celebration of the contract, as provided in Art 7 of the Contracting Regulations”. In addition, it establishes that “In accordance with Art 19 of the Contracting Regulations, the Executive President and the Vice-President will be responsible of implementing the contract award resolution”.

By Letter 2465-VPR-PPR-2008 of June 16, 2008, the Vice-President of PETROPRODUCCION sent the Executive President of PETROECUADOR, for review and decision of PETROPRODUCCION Contracting Committee, the following documents: Conclusive Final Minutes, Addendum to the Negotiating Minutes, and the Draft Contract to be signed by PETROECUADOR, PETROPRODUCCION and IVANHOE ENERGY ECUADOR INC for Specific Services to Develop, Produce and Improve Crude Oil in Block 20, which involves the Pungarayacu Field in the Ecuadorian Amazon Region. The contract is for an undetermined amount.

The Vice-President of PETROPRODUCCION, through Resolution 2008235-VPR-PPR-2008 dated June 17, 2008, Resolved: “To qualify IVANHOE ENERGY ECUADOR INC as the UNIQUE SUPPLIER for using patents of the Heavy-to-Light (HTL) technology, for heavy oil improvement”.

On July 8, 2008, the Technical-Financial Negotiating Committee submitted its Financial-Technical Conclusive Minutes for Development and Production of the Pungarayacu Field, Block 20, which included a technical-financial analysis of the negotiated contract terms. Through letter 3051-PPR-ACUM-2008 of July 22, 2008, the Committee sent to the Executive President of PETROECUADOR the supporting documents, for review and approval by PETROPRODUCCION’S Contracting Committee.

Resolution 024-CC-PPR-2008-07-29, dated July 29, 2008 of PETROPRODUCCION’s Contracting Committee: 1. With the affirmative votes of PETROECUADOR’S EXECUTIVE PRESIDENT AND PETROPRODUCCION’S VICE-PRESIDENT RESOLVED TO AWARD AND AUTHORIZE CELEBRATION OF THE CONTRACT WITH IVANHOE ENERGY ECUADOR INC TO PROVIDE SPECIFIC SERVICES FOR DEVELOPMENT AND PRODUCTION OF CRUDE OIL IN THE PUNGARAYACU FIELD, BLOCK 20, BY CONTRIBUTING WITH TECHNOLOGY, CAPITAL AND MACHINERY/EQUIPMENT AND OTHER GOODS AND SERVICES NEEDED TO COMPLY WITH ITS OBLIGATIONS. THE COMPANY WILL USE ITS PATENTED HTL™ (HEAVY-TO-LIGHT) TECHNOLOGY TO IMPROVE CRUDE OIL QUALITY, CONFIRM RESERVES AND CARRY OUT COMPLEMENTARY EXPLORATION ACTIVITIES IN THE PRE-CRETACEOUS OF THE PUNGARAYACU FIELD, AT ITS OWN RISK AND EXPENSE AND DURING A TERM OF 30 YEARS...”

¹ Contracting Regulations for Specific Works, Goods and Services of Empresa Estatal Petróleos del Ecuador, PETROECUADOR and its Affiliate Companies.

Resolution No 024-CC-PPR-2008-07-29 of July 29, 2008 does not indicate the contract price.

Draft Contract:

Clause 2: BACKGROUND, item 2.5 reads: “PETROECUADOR’s Contracting Committee, in accordance with the provisions of Article 7 of the Contracting Rules and Regulations for Specific Works, Goods and Services of Empresa Estatal Petróleos del Ecuador, PETROECUADOR and its Affiliate Companies, authorized the Executive President of PETROECUADOR and the Vice-President of PETROPRODUCCION to sign this Contract”.

Clause 9: CONTRACTUAL PAYMENT AND PAYMENTS TO CONTRACTOR, item 9.1 establishes that: During the life of this Contract, CONTRACTOR will receive payment every month (Contractual Payment). Such payment will be calculated taking into account the number of Fiscalized Production barrels produced in Block 20 during that month.

Clause 15: Registrations and Value of Contract, item 25.2 — Undetermined Amount of Contract: Given the nature of this Contract, its value is not quantifiable on the date of its execution. Therefore...it is of undetermined amount.

ANALYSIS:

The documents attached to the request made by PETROECUADOR and PETROPRODUCCION to this Control Entity for issuance of a report indicate that given de nature of the Contract to be celebrated, it is of undetermined amount. Therefore, it does not establish submittal by contractor of a Performance Bond.

PETROECUADOR indicates that it is a Direct Contracting, as established in Art 17 of the Hydrocarbons Law, as set forth in Articles 23 and 24 of the Contracting Regulations for Specific Works, Goods and Services of Empresa Estatal Petróleos del Ecuador, PETROECUADOR and its Affiliate Companies. In addition, it indicates that in accordance with Art 33 of its Manual, IVANHOE ENERGY ECUADOR is the unique supplier of the “Heavy-to-Light” (HTL™) technology, owned and patented by IVANHOE ENERGY ECUADOR and its Related Companies. The company has been qualified in PETROECUADOR and financing will be at the contractor’s expense.

Based on the above, please be informed as follows:

Art. 18 of the Contracting Regulations for Specific Works, Goods and Services of Empresa Estatal Petróleos del Ecuador, PETROECUADOR and its Affiliate Companies establishes that depending on the contract value and prior to celebrating the contract, the companies must have a report from the Nation’s Attorney General. In addition, Article 47 of its Manual establishes that all types of contracts will require a report from the Nation’s Attorney General if the contract value exceeds the base amount established for Competitive Bidding.

The Organic Law for the Office of the Nation’s Attorney General establishes that the Nation’s Attorney General will issue reports on any contracts celebrated by the Government Entities included in Article 18 of the Political Constitution, as well as on those involving private companies which use public resources, if the contract value exceeds the amount established fro Competitive Bidding.

In view of the above and since PETROECUADOR and PETROPRODUCCION established that the Contract is of UNDETERMINED AMOUNT, the contract does not meet the facts set forth in the Nation’s Attorney Office Organic Law, nor the provisions of the Contracting Regulations and Manual involving Specific Works, Goods and Services of Empresa Estatal Petróleos del Ecuador and its Affiliate Companies and does not require a report from the Control Entity. Therefore, I abstain from issuing such report.

Notwithstanding the above, the Executive President of PETROECUADOR, the Vice-President of PETROPRODUCCION and the members of the Direct Contracting Negotiating Committee and other officials who participated in the process will be responsible to determine if the scope of the works and the technical-financial conditions apply to the Contracting of specific works, goods and services for development, production or complementary exploitation of oil fields/areas with proven reserves reverted to the State or discovered with government resources, or fields exploited by PETROPRODUCCION where the Contracting Regulations for Specific Works, Goods and Services of Empresa Estatal Petróleos del Ecuador and its Affiliate Companies apply, and do not involve service contracts for hydrocarbon exploration and exploitation. . They will also be liable for the technical and financial issues agreed, as dictated by the Ecuadorian Legislation on any contractual provision, and will abide by the legal, regulatory and administrative provisions involving Direct Contracting, contract award, price, payment terms, term, legalization and implementation, as established in Article 54 of the Nation’s Attorney General Organic Law and the Contracting regulations of PETROECUADOR and its Affiliate Companies.

By the Nation’s Attorney General

Sincerely yours,

Dr. Gustavo Ramos Puertas
NATION’S DEPUTY ATTORNEY GENERAL, AT INTERIM

cc: State Comptroller’s Office

ANNEX 10

(Translation of the State Comptroller’s Office Official Letter)

Official Letter No. 024563 DCP

Department:	PUBLIC CONTRACTING BUREAU
Subject:	Specific services to develop, produce and improve crude oil in Block 20.

Quito, September 29, 2008

Captain Camilo Delgado Montenegro
Vice-President
PETROPRODUCCION
Ave. de los Shyris No. 34-382 y Portugal
Fax: 2449-000
Quito

Dear Sir:

This is in response to your Official Letters 7119-PPR-LEG-2008 and 7727-PPR-LEG-2008, dated August 21 and September 5, 2008, respectively; the latter received in our office on September 8. The above-mentioned letters request the report required by Law for the specific services draft contract for crude oil development, production and improvement in Block 20, which includes the Pungarayacu Field in the Ecuadorian Amazon Region, which will be signed with IVANHOE ENERGY ECUADOR INC. The contract is for an undetermined amount and the term is 30 years from the date of contract execution.

BACKGROUND

1. On June 5, 2007, the Central University of Ecuador signed a Cooperation Agreement with IVANHOE ENERGY ECUADOR INC., creating a strategic partnership with said company to obtain oil projects and, subsequently, upon allocation to the University of the oil blocks (Oil Project Areas), evaluate, develop and exploit such areas. It was agreed that after the signing of the agreement, the Parties would negotiate a detailed agreement (Partnership Contract) reflecting the results of the discussions and consultations, including the creation of a Partnership Committee.

Based on this Agreement, the University would obtain rights to develop, operate and exploit the oil projects prospecting areas, in partnership with PETROECUADOR, as established in the Hydrocarbons Law and its regulations. The University would take the necessary steps to obtain all the technical data for the project areas covered by the Agreement. On the other hand, IVANHOE would be responsible to prepare and implement a technical plan to evaluate, develop and exploit the first project areas selected by the Parties. The parties also agreed that they would jointly develop and negotiate all contracts and/or operation agreements for oil projects signed with the Ecuadorian Government.

2. The Vice-President of PETROPRODUCCION, taking into account:: a) The “Cooperation Agreement between the Central University of Ecuador and IVANHOE ENERGY ECUADOR INC.” b) IVANHOE ENERGY ECUADOR INC’s letter dated October 29, 2007, to the Constitutional President of Ecuador, stating the company’s interest to participate in the exploration and development of the Pungarayacu Oil field, using its patented Heavy-to-Light (HTL) technology to process heavy oil. c) The formal proposal for the integral economic development of the Pungarayacu Field, was submitted to PETROECUADOR on December 6, 2007, for analysis by the Ecuadorian Government and to reach a possible agreement. d) The visit made by a commission appointed by the Vice-President of PETROPRODUCCION to company facilities in Bakersfield, California, USA, to study and verify the technical conditions of the Heavy-to-Light (HTL) system proposed by IVANHOE ENERGY ECUADOR INC. e) PETROECUADOR’s Executive President indicated that the visit made to company facilities by PETROPRODUCCION’s committee deemed valuable using the experience, technology and financial capacity of IVANHOE ENERGY ECUADOR INC., and that the company would be willing to make immediately an initial investment of US$2,000,000.00 dollars to begin the development process of the Pungarayacu Field, in accordance with PETROPRODUCCION’s requirements. f) The company submitted documentation proving that it is the owner of the patented Heavy-to-Light (HTL) technology, and therefore, it is the unique supplier and owner of such technology, in accordance with the provisions of letter b), Article 23 of the Contracting Regulations for Specific Works, Goods and Services of Empresa Estatal Petróleos del Ecuador, PETROECUADOR and its affiliate companies. RESOLVED: 1) qualifying IVANHOE ENERGY ECUADOR INC. as the unique supplier of the Heavy-to-Light (HTL) technology to improve heavy oils. 2) Order that the resolution be registered, numbered and notified to all areas of the Affiliate Company; and, 3) Order the Chief of the Contracts Coordination Unit to implement the resolution, as established in Resolution No 2008235 dated June 11, 2008.

3. The “Technical-Financial Final Minutes for Development and Production of the Pungarayacu Field, Block 20” were signed on July 8, 2008 by the Technical-Financial Negotiations Committee, appointed by the Vice-President of PETROPRODUCCION, and IVANHOE ENERGY ECUADOR INC representatives, which included the financial terms and conditions. Such document will be included in the contract.

4. PETROPRODUCCION’s Contracting Committee authorized execution of the contract with IVANHOE ENERGY ECUADOR INC, at its meeting of July 29, 2008, through Resolution 024-CC-PPR-2008-07-29 dated July 29, 2008 as follows: “...1. PETROECUADOR’S EXECUTIVE PRESIDENT AND PETROPRODUCCION’S VICE-PRESIDENT VOTED IN FAVOR OF AWARDING AND AUTHORIZING EXECUTION OF THE CONTRACT WITH IVANHOE ENERGY ECUADOR INC. THE CONTRACT IS TO PROVIDE SPECIFIC SERVICES FOR DEVELOPMENT AND PRODUCTION OF CRUDE OIL IN THE PUNGARAYACU FIELD, BLOCK 20, BY CONTRIBUTING WITH TECHNOLOGY, CAPITAL AND MACHINERY OR EQUIPMENT AND OTHER GOODS AND SERVICES NEEDED TO COMPLY WITH ITS OBLIGATIONS. THE COMPANY WILL USE ITS PATENTED HTL (HEAVY-TO-LIGHT) TECHNOLOGY TO IMPROVE CRUDE OIL QUALITY, CONFIRM RESERVES AND CARRY OUT COMPLEMENTARY EXPLORATION ACTIVITIES IN THE PRE-CRETACEOUS OF THE PUNGARAYACU FIELD, AT ITS OWN RISK AND EXPENSE AND DURING A TERM OF 30 YEARS. MR. JORGE LUIS GONZALEZ, DELEGATE OF PETROECUADOR’S BOARD OF DIRECTORS REFRAINED FROM VOTING AND EXPLAINED THAT SINCE HE WAS NEW IN PETROPRODUCCION’S CONTRACTING COMMITTEE HE WAS NOT FULLY KNOWLEDGABLE OF THE BACKGROUND OR TECHNICAL/FINANCIAL ANALYSIS THAT SERVED AS BASIS TO AWARD THE CONTRACT. THE CONTRACT WAS AWARDED WITH THE FOLLOWING RECOMMENDATIONS: THE CONTRACT MUST INCLUDE AS QUALIFYING DOCUMENT THE MINUTES SIGNED ON JUNE 10, 2008. CLAUSE TWO OF THE CONTRACT, BACKGROUND, MUST STATE ALL THE ANNEXES, NEGOTIATION MINUTES AND DOCUMENTS THAT SERVED AS BASIS DURING THE NEGOTIATIONS PROCESS. 2. AUTHORIZE THE EXECUTIVE PRESIDENT OF PETROECUADOR AND THE EXECUTIVE VICE-PRESIDENT OF PETROPRODUCCION TO EXECUTE THE CONTRACT WITH IVANHOE ENERGY ECUADOR INC..., UPON ISSUANCE OF THE REPORTS BY THE STATE COMPTROLLER’S OFFICE AND THE NATION’S ATTORNEY GENERAL OFFICE. — THIS RESOLUTION IS FOR IMMEDIATE IMPLEMENTATION.

5. Article 2, letters b) and c) of the Substitute Regulations for Delegation of Signatures in official documents of the State Comptroller’s Office, issued through Agreement No 016-CG, published in Supplement of Official Register No 395 of August 4, 2008, establish that the Deputy Comptroller General will sign all reports involving public sector draft contracts, in the amounts set forth in the Call for Bid and the Competitive Bidding Process, as established by Law.

6. Transitory Provision 5 of the General Regulations for the Public Contracting National System, issued through Supplement to Official Register 399 of August 8, 2008, establishes that Contracting processes which begun before the above-referenced Law entered in force, involving entities that were not subject to the Public Contracting Law, will abide by the regulations that were applicable to them at the time the process begun. The top authority of the entity involved will be fully responsible for it.

LEGAL BASIS

Upon reviewing the documentation submitted, we have established that the review process carried out by the support committees and the officials from the Ministry of Mines and Petroleum and PETROPRODUCCION, the Contracting process used as reference the following rules of procedure:

HYDROCARBONS LAW

Art. 2 — (Replaced by Law 101, O.R. 306, 13-08-1982; paragraph 1 replaced, paragraphs 2 and 3 added by Article 1 of Law 44, O.R. 326, 29-11-1993; par. 3 amended and par. 4 added by Law 49, O.R. 346, 28-12-1993; par. 6 amended by Art. 24 of Law 45, O.R. 283, 26-09-1989). The State will explore and exploit the reservoirs mentioned in the preceding article, directly through PETROECUADOR. PETROECUADOR may perform such activities either directly or through partnership agreements, sharing agreements, service contracts for hydrocarbon exploration and exploitation, or other contractual systems established in the Ecuadorian legislation. It may also create semipublic companies with national and international enterprises legally establish in Ecuador.

Contracts for exploration and exploitation of marginal oil fields are those executed by the State trough PETROECUADOR. Subject to the provisions of paragraph 1, Article 46 of the Political Constitution of Ecuador, such contracts authorize contractors to explore and exploit marginal production oil fields currently exploited by PETROPRODUCCION, by making all the investments required by the additional exploration and exploitation activities.

Marginal oil fields are those qualified by the Ministry of Mines and Petroleum as fields with low operational or financial priority because they are not close to PETROECUADOR’s infrastructure, contain heavy oil or require very expensive recovery techniques. The additional exploitation and exploration activities, however, must represent greater technical and financial efficiency in benefit of the State’s interests. These fields may not exceed 1% of the national production rate and will be subject to the international standards for oil reserves conservation. These contracts are awarded through a competitive bidding process organized by the Special Committee, as established in Article 19, and shall give priority to national companies in the hydrocarbons sector, either by themselves or in partnership.

Awarding of these contracts shall try to take into account:

a)	The highest amount to be invested in the area,
b)	Minimum production assured, or
c)	Production costs.

PETROECUADOR may procure itself the specific goods or services required or may celebrate contracts for Contracting of specific goods or services, giving priority to national companies, on equal terms. For such purpose, PETROECUADOR will announce on a timely and continuous basis the works and services it may require.

When PETROECUADOR participates in any of the petroleum industry stages, through its Affiliate Companies or celebrates contracts of any nature whatsoever, PETROECUADOR financial system established in its Special Law shall apply.

The President of Ecuador will allocate from the net income obtained from service contracts to explore and exploit hydrocarbons, the resources required in order to create a permanent investment fund to seek new hydrocarbon reserves. PETROECUADOR will manage this fund, under supervision by the State Comptroller’s Office.

Art. 17 — (Replaced by Art 5, Law 101, O.R. 306, 13-08-1982) — The specific goods and services contracts referred to in paragraph two, Article 2, are those by which a company undertakes to implement specific works or services for PETROECUADOR, contributing with technology, capital and equipment required to comply with the contractual obligations, in exchange for a price or cash compensation. The parties will agree on the price and payments terms, as established by Law.

Note — Reference in this article to paragraph two, Art. 2 actually applies to paragraph 5, Art. 2 of the Law.

Art. ... — (Added by Art. 6, Law 44, O.R. 326, 29-11-1993) — In addition to the contractual methods established in article 3, PETROECUADOR, if convenient to the State’s interests, may also execute operating contracts for construction, operation of main oil pipelines, fuel pipelines and gas pipelines, terminals and hydrocarbon processing plants with national or foreign companies well reputed and legally incorporated in Ecuador. Such companies may create their own partnerships. Contractors may operate the fuel pipelines, gas pipelines, terminals and processing plants. Upon termination of the construction and operation contract, the provisions of Article 29, paragraph 2 shall apply.

Art. 23 — (Replaced by Art. 9, Law 44, O.R. 326, 29-11-1993) — The exploration period in all crude oil exploration and exploitation contracts, will be of up to four (4) years, extendable for two (2) additional years, upon prior justification by contractor and authorization by PETROECUADOR. Operations shall begin in the area within the first six (6) months from the date the contract is registered at the Hydrocarbons Registry. The registration shall take place within thirty (30) days from execution of the corresponding contract.

In all contracts, the crude oil exploitation period may last up to twenty (20) years, extendable by PETROECUADOR in accordance with the development plan for the area, if it is convenient to the State’s interests.

Art. 81 — Hydrocarbon exploration and exploitation contracts, as well as the routes for the oil and gas pipelines, location of refineries and hydrocarbon or petrochemical industrial facilities shall be subject to review by the Joint Command of the Armed Forces, in order that it issues its opinion, as required by the National Security Law.

Art. 93 — (Replaced by Art. 24, Law 45, O.R. 283, 26-09-1989) — All works, services, Contracting of equipment and other goods, or the purchase/sale of hydrocarbons engaged by PETROECUADOR and its Affiliate Companies in compliance with this Law, shall be implemented and monitored in accordance with the procedures of this Special Law and its regulations.

Contracting Regulations for specific works, goods and services of Empresa Estatal Petróleos del Ecuador, PETROECUADOR and its Affiliate Companies.

Art. 7 — Entities and officers responsible of awarding and executing contracts in PETROECUADOR and its Affiliate Companies — The officers responsible to award and celebrate contracts are as follows:

a) The Contracting Committee, comprised by one delegate from PETROECUADOR’s Board of Directors, PETROECUADOR’s Executive President and the Vice-President of the corresponding Affiliate Company will award contracts that exceed 1% of PETROECUADOR’s consolidated budget. In contracts executed by PETROECUADOR and depending on the contract purpose, the committee will also include the Manager of the Area that will be using such goods or services; ....

Art. 19 — Execution — PETROECUADOR’s Executive President and the Vice-President of the corresponding Affiliate Company will be the liable to execute the award resolution and to make all technical, financial, legal and administrative decisions for implementation of the contract.

Art. 23 — Direct Contracting — This exception process will apply in the following events:

b) Contracting of goods or services unique in the marketplace and with a unique supplier or which involve the use of patents or trademarks, as well as purchases made abroad with the manufacturer and the maintenance and repair at the manufacturer authorized workshops, qualified in advance by the Executive President of PETROECUADOR or the vice-presidents of the Affiliate Companies.

In all direct Contracting processes, PETROECUADOR’s Executive President or the vice-presidents of each Affiliate Company may appoint an official or a committee to develop the corresponding process, in order that they prepare a report to support the corresponding direct contract award.

These Contracting processes do not require previous registration of individuals or companies.

In the event that a direct Contracting process is not completed, the responsible officer will prepare the corresponding report before closing the process. Codification of the Contracting Manual for specific works, goods and services of Empresa Estatal Petróleos del Ecuador, PETROECUADOR, and its Affiliate Companies.

Art. 7 — Officials Responsible to Award and Sign Contracts

1. The Contracting Committee of PETROECUADOR comprises one delegate from PETROECUADOR’s Board of Directors, PETROECUADOR’s Executive President and the manager of the area that will use the goods or services, depending on the contract purpose. This committee awards contracts not exceeding 1% of PETROECUADOR’s consolidated annual budget and authorizes the Executive President to execute the contract.

2. The Contracting Committee of the Affiliate Companies comprises one delegate from PETROECUADOR’s Board of Directors, PETROECUADOR’s Executive President and the Vice-President of the corresponding Affiliate Company. This committee awards contracts not exceeding 1% of PETROECUADOR’s consolidated annual budget and authorizes the Vice-President of the corresponding Affiliate Company to execute the contract.

3. PETROECUADOR’s Executive President awards and celebrates contracts with amounts ranging between 0,05 and 1% of PETROECUADOR’s consolidated annual budget, as well as corporate contracts of any amount and which involve activities of PETROECUADOR with one or several of its Affiliate Companies.

Corporate contracts are those whose purpose involve PETROECUADOR with one or several activities of its Affiliate Companies.

4. The vice-presidents of the corresponding Affiliate Companies and the managers or top authorities of the actual units created or to be created on a temporary basis, award and celebrate contracts with values ranging between 0,05% and 1% of PETROECUADOR’s consolidated annual budget.

5. The executives that follow in rank to the President of PETROECUADOR and the Vice-Presidents of the Affiliate Companies and the managers or top authorities of the actual units created or to be created on a temporary basis, award and celebrate contracts if the contract amount reaches 0,0075% and is lower than 0,05% of PETROECUADOR’s consolidated annual budget.

6. The officials following in rank the level established in the preceding paragraph, as dictated by the structure of each Affiliate or Temporary Unit, will award and sign contracts abiding by the amounts and procedures set forth in Annex 1, which is an integral part of this manual,. The contract amount may not exceed 0,0075% of PETROECUADOR’s consolidated annual budget (cc Art 7 r).

As regards to contracts with undetermined amounts, the proposed contract and contract award will be under the responsibility of the Executive President of PETROECUADOR, the Vice-Presidents of the Affiliate Companies or the Managers/top authorities of the actual units created or to be created on a temporary basis, as applicable.

Art. 33 — Situations that justify a direct Contracting

Direct Contracting will only apply in the events foreseen in Art 23 of the Contracting regulations, upon prior issuance of the corresponding resolution that qualifies using such method...

In the event of a unique supplier, national or foreign, which is unique in the marketplace or in cases involving the use of patents, the offer or shall justify such condition by submitting the supporting documents. In the event of standardization of trademarks, a reasoned resolution is required. Qualification of exceptions will be the responsibility of the executive president, the vice-presidents of the Affiliate Companies, the Managers/top authorities of the actual units created or to be created on a temporary basis, as applicable.

Contractings foreseen in letter d), Art 23 of the Contracting regulations, notwithstanding the contract amount, legal, technical and financial conditions, and observing the scope of their authority, will require approval by PETROECUADOR’s Executive President, the Affiliate Companies’ vice-presidents, managers/top authorities of the actual units created or to be created on a temporary basis.

Hiring of professional services, national or foreign, shall meet the following requirements:

a) The user area shall justify the need from a technical and financial point of view.

b) If a foreign company will provide professional services, such company must be domiciled in Ecuador and/or designate a representative, as applicable.

c) Foreign individuals residing in the country shall comply with all the legal requirements applicable in Ecuador to provide professional services.

Direct Contracting may include a screening and competencies process among bidders, in order to obtain optimum Contracting conditions for PETROECUADOR and its Affiliate Companies.

ANALYSIS

1. The Board of Director’s Secretary, at interim, through memo No 113-SDD-2008 of June 13, 2008, notified the Vice-President of PETROPRODUCCION regarding Resolution 44-DIR-2008, adopted during the meeting held on Monday, May 19, 2008, ratified on June 10, 2008. Such resolution states as follows: “...In view that the specific services contract with IVANHOE had to be signed by March 2008 to develop and produce heavy oil in the Pungarayacu Field, using IVANHOE’s state-of-the-art patented technology; and, taking into account that contracts shall include a price per barrel produced, which include costs, expenses, investments and reasonable profits, the Board resolved to ask IVANHOE to submit its offer within 30 days. In the event that IVANHOE does not submit its offer as required, PETROPRODUCCION will prepare the terms and conditions for a competitive bidding process”.

Upon reviewing the above Resolution, we observe that the Board of Directors thought at a time in implementing a competitive bidding process at national and international level.

2. As regards to the legal basis used in the various documents attached to the paperwork, it is observed that PETROECUADOR and its Affiliate PETROPRODUCCION did not observe:

• The provisions of Article 17, Hydrocarbons Law, which establishes that the price and payment terms will be agreed by the parties. The contract is for an undetermined amount.

• The provisions of paragraph 2, Article 23 of the Hydrocarbons Law, contract term. The contract establishes a term of 30 years, while the legal provision establishes a maximum term of 20 years, extendable by mutual agreement.

• The provisions of Article 81 of the above-referenced Law, which establishes that hydrocarbon exploration and exploitation contracts shall be reviewed by the Joint Command of the Armed Forces, in order that it issues its opinion, as required by the National Security Law.

3. As established in letter a), Article 7 of the Contracting Regulations for Specific Works, Goods and Services of Empresa Estatal Petróleos del Ecuador, PETROECUADOR and its Affiliate Companies, participation of the various entities will depend on the contract price.

The contract is for an undetermined amount and the provisions of the last paragraph, Article 7, of the Contracting Manual’s Codification for specific works, goods and services of PETROECUADOR and its Affiliate Companies were applicable. Therefore, PETROECUADOR’s Executive President, the Affiliate Companies’ vice-presidents or the managers/top authorities of the actual units created or to be created on a temporary basis had capacity to award the contract, as applicable.

4. Clause 12, “Solution of Disputes”, sub-clause 22.1, first paragraph, involving arbitration, does not observe the provisions of Article 14, Political Constitution, which establishes that contracts entered in Ecuador by Government entities with foreign individuals or companies, are not subject to foreign jurisdiction.

OPINION

Article 18 of the Contracting Regulations for Specific Works, Goods and Services of Empresa Estatal Petróleos del Ecuador, PETROECUADOR and its Affiliate Companies sets forth that PETROECUADOR or its Affiliates, prior to signing the contract shall have the opinion of the Nation’s Attorney General and the State Comptroller’s Office, if required due to the contract price. Article 47, Contracting Manual Codification for Specific Works, Goods and Services of Empresa Estatal Petróleos del Ecuador and its Affiliate Companies provides that contractual methods foreseen in Chapter V of the Contracting Regulations, if the price exceeds the base amount established for a competitive bidding process, will require simultaneous opinion by the Nation’ Attorney General and the State Comptroller’s Office.

Item 16, Article 31 of the State Comptroller’s Office Organic Law establishes that the legal opinions requested by Government entities are issued when the contract price is equal or higher than the price established by Law for Competitive Bidding.

It is observed that the above provisions condition the opinion of Top Control Entities to the existence of a minimum amount. Therefore, in view that the contract is for an undetermined amount, as established in clauses 9 and 15, the contract does not meet the feasibility budgets for issuance of a report.

Upon reviewing the paperwork submitted, the State Comptroller’s Office abstains from issuing the report required by Law regarding the draft contract sent for review.

In accordance with the provisions of Article 120, Political Constitution, the officials of PETROECUADOR and its Affiliate Company PETROCOMERCIAL that participate in the Contracting process and any decisions taken by them will not be exempt of liability for their actions or omissions in performing their duties.

Sincerely,
By the State’s Comptroller

Dr. Eduardo Muñoz Vega
Deputy State’s Comptroller, at interim

ANNEX 11

(Translation of the State Comptroller’s Office Official Letter)

Official Letter No. 025181 DCP

Department:	PUBLIC CONTRACTING BUREAU
Subject:	Services to develop, produce and improve crude oil.

Quito, October 2, 2008

Captain Camilo Delgado Montenegro
Vice-President
PETROPRODUCCION
Quito

Dear Sir:

This is with reference to Official Letter 8629 PPR-LEG-2008 dated October 2, 2008, with observations regarding Official Letter 024563 DCP of September 29, 2008, by which this entity abstained from issuing an opinion on the draft contract for specific services to develop, produce and improve crude oil in Block 20, which includes the Pungarayacu Field in the Ecuadorian Amazon Region. The contract is to be signed with IVANHOE ENERGY ECUADOR INC for an undetermined amount and has a term of 30 years from execution of the contract.

Please note that the observations contained in the abstention report are for referential purposes. Therefore, since such observations are not an integral part of the report required by Law, as established in the State Comptroller’s Office Organic Law, they are not binding. Consequently, your entity could celebrate the contract if it is beneficial to public interests.

Sincerely yours,
By the State’s Comptroller

Dr. Eduardo Muñoz Vega
Deputy State’s Comptroller, at interim

ANNEX 12

(Pungarayacu Field Development)

NOBOA, PEÑA, LARREA & TORRES, LOGO

October 14, 2008

Mr. Oscar Blake
Legal Counsel
IVANHOE ENERGY (USA) INC
Av. Suite 400
Bakersfield, California
U.S.A.

Dear Sir:

Having revised and compared the Spanish and English translation of “The Specific Services Contract for Development, Production and Upgrading of Crude Oil in Block 20 (Pungarayacu Oil Fiel) in the Ecuadorian Amazon Region” (THE CONTRACT), I hereby certify the following:

a. That the English translation to THE CONTRACT is accurate in form and content and do not violate any Ecuadorean Law.

Kind Regards,

/s/ Mario Larrea

Mario Larrea
Attorney at Law

EX-10.25

Exhibit 10.25

CONTRACT MODIFICATIONS TO THE SPECIFIC SERVICES CONTRACT TO
DEVELOP, PRODUCE, AND UPGRADE CRUDE OIL IN BLOCK 20, INVOLVING THE
PUNGARAYACU FIELD IN THE ECUADORIAN AMAZON REGION.
SIGNED BETWEEN:
THE ECUADORIAN STATE PETROLEUM COMPANY, PETROECUADOR, AND ITS
SUBSIDIARY, THE ECUADORIAN STATE COMPANY FOR PETROLEUM
EXPLORTATION AND PRODUCTION, PETROPRODUCCION, AND THE COMPANY
IVANHOE ENERGY ECUADOR INC.
(February 11, 2009)

1. First: Appearing Parties:

The following parties appear to sign these contract modifications: firstly, the Ecuadorian State Petroleum Company, PETROECUADOR, and its Subsidiary, the Ecuadorian State Petroleum Company for Exploration and Production, PETROPRODUCCION, represented by Rear Admiral Luis Aurelio Jaramillo Arias and Ship Captain E.M.C., Camilo Delgado Montenegro, as Executive President and Vice President, respectively, both duly authorized by the Contracting Committee of PETROPRODUCCION, as shown through the attached documents, herein PETROECUADOR AND PETROPRODUCCION; and, secondly, the company IVANHOE ENERGY ECUADOR INC., represented by its General Proxy in Ecuador, and therefore its Legal Representative in Ecuador, Carlos Espinoza, as verified by the documents added hereto, herein the CONTRACTOR, and duly authorized by the Head Office.

2. Second: Background:

Two Point One (2.1) On October 9, 2008, a specific services contract was signed for the development, production, and upgrading of crude oil in Block 20, involving the Pungarayacu Field in the Ecuadorian Amazon Region, between: The Ecuadorian State Petroleum Company, PETROECUADOR and its Subsidiary, the Ecuadorian State Company for Exploration and Production of Petroleum, PETROPRODUCCION, and the company IVANHOE ENERGY ECUADOR INC.

Two Point Two (2.2) The parties freely, spontaneously, and voluntarily, free from any deficiency or pressure, have mutually agreed to clarify certain formal issues and interpretation of the specific services contract for the development, production, and upgrading of crude oil in Block 20, involving the Pungarayacu Field (herein the main contract) because it is in the best interest of the Ecuadorian State.

Two Point Three (2.3) Article 3 of the Contracting Regulation for Specific Goods and Services of the State Petroleum Company PETROECUADOR and its subsidiary companies establish that “PETROECUADOR and its subsidiaries may sign, according to the scope of this regulation, any type of contract, agreement, or deal of any nature whatsoever, as long as they are necessary to comply with their purposes as permitted by the Law.”

Two Point Four (2.4) The Eleventh Clause of the main contract deals with contract modification and the procedures to be followed in such an event.

Two Point Five (2.5) Sub-clause Eleven Point One, in the pertinent section, establishes that “This Contract may only be modified by mutual agreement between the Parties and following authorization from the Contracting Committee...”

Two Point Six (2.6) That through Resolution No. 001-CC-VPR -2009, from January 21, 2009, the PETROPRODUCCION Contracting Committee has authorized signing these contractual modifications to the main contract for specific services with IVANHOE ENERGY ECUADOR INC.

Two Point Seven (2.7) That Through Resolution No. 002-CC.VPR.2009-02-05, from February 5, 2009, the PETROPRODUCCION Contracting Commitittee has authorized signing the contractual modification to the main contract for specific services with IVANHOE ENERGY ECUADOR INC.

3. Modification:

Three Point One (3.1) In the clause Twelve Point One, “Tax Administration and Profit Sharing,” first paragraph, after the phrase, “to include a factor,” eliminate the word “automatic,” and at the end of this paragraph, include the phrase, “any readjustments will be made according to clauses 9.1.2 and 12.9,” leaving the clause to read in the following way:

“The CONTRACTOR will pay income tax according to the regulations found in the Organic Law for the Domestic Tax System, and all other regulations applicable to the subject matter. The CONTRACTOR may deduct any investments, costs, and expenses made according to the legal framework valid in Ecuador, and therefore, such amounts would not be subject to income tax payment. If, at some time after the contract is signed, the tax system is modified in such a way that investments, costs, and expenses may be deducted by the CONTRACTOR, the CONTRACTOR will have the right, from that day forward, to include a correction factor in the form of a Contractual Payment that compensates the economic effects any modifications to the tax regulations. Any readjustment of this kind will be done according to clauses 9.1.2 and 12.9.”

Three Point Two (3.2) In clause Eighteen “Regarding Assignment of Rights,” following the phrase on obligations derived from this Contract, eliminate the phrase, “with the authorization of PETROPRODUCCION. If this requirement is not fulfilled, such assignment will be null and void, and the CONTRACTOR will be responsible for any damages caused. The CONTRACTOR, under its exclusive responsibility, may assign rights to receive amounts payable to the CONTRACTOR under this Contract to agencies that grant financing for the operations of this Contract,” and substitute it with the following: “according to the first and second paragraphs of Article 48 of the Hiring Regulations for Specific Goods and Services of the State Petroleum Company PETROECUADOR and its Subsidiary companies.” The clause would, therefore, read in the following way:

“The CONTRACTOR may assign or transfer its rights and obligations derived from this Contract according to the first and second paragraphs of Article 48 of the Hiring Regulations for Specific Goods and Services of the State Petroleum Company PETROECUADOR and its Subsidiary companies.”

Three Point Three (3.3) In the sub-clause Nineteen Point One, in the phrase, “to execute this contract,” insert the word “objective” after the word this, and in the next line, add the phrase, “observing the laws and regulations written on that subject matter, when applicable.” The sub-clause would, therefore, read in the following way:

“The CONTRACTOR may subcontract, under its own responsibility and risk, the work or services necessary to execute the objective of this Contract, observing the laws and regulations written on that subject matter, when applicable. Such work and services will be executed in the CONTRACTOR’S name, and the CONTRACTOR will maintain direct responsibility over all of the obligations established in this Contract and derived from it, which may not be waived on the grounds of subcontracting. PETROPRODUCCION will not assume any responsibility for this concept, even for reasons of solidarity.”

Three Point Four (3.4) In sub-clause “Twenty four Point Two, Legal Frame of Reference,” at the end, eliminate the phrase: “If there is any opposition from among the indicated documents, the order or priority among them will be the following: this Contract, Laws, and Regulations,” and replace it with the following: “Interpretation will follow clause 3 of this contract.”

“The legal frame of reference that is applicable to this Contract includes but is not limited to the instruments listed below: One — Law of Hydrocarbons, enacted through Official Record No. 711, from November 15, 1978, and its reforms. Two — Special Law for the State Petroleum Company of Ecuador (PETROECUADOR) and its Subsidiary Companies, enacted through the Official Record No. 283, from September 26, 1989, and its pertinent reforms and regulations. Three — the Organic Law of Tax Equality, enacted through Official Record No. 242 from December 29, 2007. Four — Law No. 122, which creates the Development Fund for the Provinces in the Amazon Region, which was published in the Official Record No. 676 from May 3, 1991, and its reforms and interpretative law. Five — the Law of Arbitration and Mediation, which was published in the Official Record No. 145 from September , 1997, and its reforms. Six — the General Insurance Law and its reforms. Seven — the Organic Law for Customs and its Regulations. Eight — the Substitute Regulation for Hydrocarbon Operations. Nine — the Substitute Regulation to the Environmental Regulation for Hydrocarbon Operations in Ecuador, which was published in the Official Record No. 265, from February 13, 2001. Ten — the Regulations for Contracting Goods, Work, and Services for PETROECUADOR and other laws that are valid upon signing the Contract and that were applicable to Hydrocarbon activities. Its interpretation will be according to clause 3 of this Contract.”

4. Ratification:

All of the other clauses and appendices from the main contract No. 2008-065 that have not been modified through this instrument will remain valid and have their full effect on the parties.

5. Appendices:

The documents named in the first clause of this contract will be an intrinsic part of this contract, along with the appointments of the legal representatives of PETROECUADOR, PETROPRODUCCION, and IVANHOE ENERGY ECUADOR INC.

CALM. Luís JARAMILLO Arias
EXECUTIVE PRESIDENT
OF PETROECUADOR CPNV-EMC Camilo DELGADO Montenegro
VICEPRESIDENT
OF PETROPRODUCCIÓN

Mr. Carlos Espinoza
GENERAL PROXY
FOR IVANHOE ENERGY ECUADOR INC.

March 12, 2009

Mr. Oscar Blake
Legal Counsel
IVANHOE ENERGY (USA)INC
Av. Suite 400
Bakersfield, California
U.S.A.

Dear Sir:

Having revised and compared the Spanish and English translation of the contract modification “To the Specific Services Contract To Develop, Produce, and Upgrade Crude Oil in Block 20, (Pungarayacu Oil Field) in the Ecuadorean Amazon Region”, (THE CONTRACT MODIFICATION), I hereby certify the following:

a. That the English translation to the CONTRACT MODIFICATION is accurate in form and content and do not violate any Ecuadorean Law.

Kind Regards,

Mario Larrea
Senior Partner

EX-21.1

Exhibit 21.1

SUBSIDIARIES OF REGISTRANT

Name of Subsidiary (Jurisdiction)	Ownership
IVANHOE ENERGY INTERNATIONAL INC. (B.V.I.)		100	%
IVANHOE ENERGY HOLDINGS INC. (NEVADA)		100	%
Ivanhoe Energy (USA) Inc. (Nevada)	100% (indirect		)
Ivanhoe Energy Petroleum Projects Inc. (Nevada)	100% (indirect		)
Ivanhoe Energy HTL Inc. (Nevada)	100% (indirect		)
Ivanhoe HTL Petroleum Ltd. (Nevada)	100% (indirect		)
Ivanhoe Energy HTL (USA) Inc. (Nevada & California)	100% (indirect		)
IVANHOE ENERGY INTERNATIONAL VENTURES INC. (BVI)		100	%
Ivanhoe Energy (Middle East) Inc. (BVI)	100% (indirect		)
Energy Resources Development Japan Corporation (Japan)	99% (indirect		)
Ivanhoe Energy (Latin America) Inc. (BVI)	100% (indirect		)
SUNWING HOLDING CORPORATION (Barbados)		100	%
Sunwing Energy Ltd. (Bermuda)	100% (indirect
Sunwing Zitong Energy Ltd. (BVI)	100% (indirect		)
Sunwing Management Limited (Hong Kong)	99% (indirect		)
Pan-China Resources Ltd. (BVI)	100% (indirect		)
Dagang Resources Ltd. (BVI)	100% (indirect		)
China Ivanhoe Energy Ltd. (BVI)	100% (indirect		)
IVANHOE ENERGY ADVISORY INC. (BVI)		100	%
IVANHOE ENERGY LATIN AMERICA INC. (BC)		100	%
Ivanhoe Energy Ecuador Inc. (BC)	100% (indirect		)
IVANHOE ENERGY MENA INC. (BC)		100	%
IVANHOE ENERGY CANADA INC. (AB)		100	%

EX-23.1

Exhibit 23.1

	Principal Officers:
	Harry Jung, P. Eng.
	President, C.E.O.
	Dana B. Laustsen, P. Eng.
	Executive V.P., C.O.O.
	Keith M. Braaten, P. Eng.
	Executive V.P.
	Officers / Vice Presidents:
	Terry L. Aarsby, P. Eng.
	Jodi L. Anhorn, P. Eng.
	Neil I. Dell, P. Eng.
	David G. Harris, P. Geol.
	Myron J. Hladyshevsky, P. Eng.
	Bryan M. Joa, P. Eng.
	John H. Stilling, P. Eng.
	Douglas R. Sutton, P. Eng.
	James H. Willmon, P. Eng.

LETTER OF CONSENT

TO: Ivanhoe Energy Inc.

Dear Sir:

We hereby consent to the inclusion of the Form 10-K of Ivanhoe Energy Inc. for 2008, of our report dated February 10, 2009 on oil and gas reserves of Ivanhoe Energy Inc. and its subsidiaries.

Yours very truly,

GLJ PETROLEUM CONSULTANTS LTD.

“ORIGINALLY SIGNED BY”

Bryan M. Joa, P. Eng.
Vice-President

Dated: March 10, 2009
Calgary, Alberta
CANADA

EX-23.2

Exhibit 23.2

[NETHERLAND, SEWELL & ASSOCIATES, INC. LOGO]

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

We hereby consent to the inclusion in the Form 10-K of Ivanhoe Energy, Inc. for 2008, of our report dated February 11, 2009, on oil and gas reserves of Ivanhoe Energy, Inc. and its subsidiaries.

NETHERLAND, SEWELL & ASSOCIATES, INC.
By:	“Danny D. Simmons”
	Danny D. Simmons, P.E.
	President and Chief Operating Officer

Houston, Texas
March 11, 2009

EX-23.3

Exhibit 23.3

CONSENT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS

We consent to the incorporation by reference in Registration Statements No. 333-113054, 333-143029 and 333-151943 on Form S-8 of our reports dated February 26, 2009, relating to the consolidated financial statements of Ivanhoe Energy Inc. (which report expressed an unqualified opinion and includes an explanatory paragraph regarding conditions and events that cast substantial doubt on the Company’s ability to continue as a going concern), and the effectiveness of internal control over financial reporting, appearing in this Annual Report on Form 10-K of Ivanhoe Energy Inc. for the year ended December 31, 2008.

(signed) “Deloitte & Touche LLP”

Independent Registered Chartered Accountants
Calgary, Canada
March 16, 2009

EX-31.1

EXHIBIT 31.1

CERTIFICATION BY THE CHIEF EXECUTIVE OFFICER

PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Robert M. Friedland, certify that:

1.	I have reviewed this Annual Report on Form 10-K of Ivanhoe Energy Inc.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a – 15(f) and 15d – 15(f)) for the registrant and have:

a.)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
c.)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors:

a.)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

*     *     *

By:	/s/ Robert M. Friedland
	Robert M. Friedland
	Chief Executive Officer

Date: March 16, 2009

EX-31.2

EXHIBIT 31.2

CERTIFICATION BY THE CHIEF FINANCIAL OFFICER
PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, W. Gordon Lancaster, certify that:

1.	I have reviewed this Annual Report on Form 10-K of Ivanhoe Energy Inc.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a – 15(f) and 15d – 15(f)) for the registrant and have:

a.)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
c.)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors:

a.)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

*     *     *

By:	/s/ W. Gordon Lancaster
	W. Gordon Lancaster
	Chief Financial Officer

Date: March 16, 2009

EX-32.1

EXHIBIT 32.1

CERTIFICATION BY THE
CHIEF EXECUTIVE OFFICER PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, Robert M. Friedland, Chief Executive Officer, of Ivanhoe Energy Inc, hereby certify that:

(a) our periodic report on Form 10-K for the year ended December 31, 2008 (the “Form 10-K”), fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934, as amended, and related interpretations; and

(b) the information contained in the Form 10-K fairly presents, in all material respects, the financial condition and our results of operations.

*     *     *

By:	/s/ Robert M. Friedland
	Robert M. Friedland
	Chief Executive Officer

Date: March 16, 2009

EX-32.2

EXHIBIT 32.2

CERTIFICATION BY THE
CHIEF FINANCIAL OFFICER PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, W. Gordon Lancaster, Chief Financial Officer, of Ivanhoe Energy Inc., hereby certify that:

(a) our periodic report on Form 10-K for the year ended December 31, 2008 (the “Form 10-K”), fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934, as amended, and related interpretations; and

(b) the information contained in the Form 10-K fairly presents, in all material respects, the financial condition and our results of operations.

*     *     *

By:	/s/ W. Gordon Lancaster
	W. Gordon Lancaster
	Chief Financial Officer

Date: March 16, 2009