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, 2005

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		V6C3E1
(Address of principal executive offices)		(Zip Code)

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

No Changes

(Former name, former address and former fiscal year, if changed since last report)

None

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. Yes o No þ

     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. Yes o No þ

     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.

     Yes þ No o

     Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

     Large accelerated filer o Accelerated filer þ Non-accelerated filer o

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

     As of June 30, 2005, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $471,351,580 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 February 28, 2006
Common Shares, no par value		229,430,769 shares

DOCUMENTS INCORPORATED BY REFERENCE
None

 

 

TABLE OF CONTENTS

				Page
PART I
Items 1 and 2		Business and Properties
		Corporate Overview			4
		Historical Overview			4
		Corporate Strategy			4
		Heavy Oil Processing Technology			5
		Gas-to-Liquids Technology			6
		Oil and Gas Properties			8
		Other Enhanced Oil Recovery Projects			12
		Employees			12
		Reserves, Production and Related Information			12
		Additional Factors Affecting the Business			14
		Competition			14
		Environmental Regulations			15
		Environmental Provisions			15
		Government Regulations			15
Item 1A		Risk Factors			15
Item 1B		Unresolved Staff Comments			19
Item 3		Legal Proceedings			19
Item 4		Submission of Matters to a Vote of Security Holders			19
PART II
Item 5		Market for Registrant’s Common Equity and Related Stockholder Matters			20
Item 6		Five Year Summary of Selected Financial Data			22
Item 7		Management’s Discussion and Analysis of Financial Condition and Results of Operations			23
Item 7A		Quantitative and Qualitative Disclosures About Market Risk			39
Item 8		Financial Statements and Supplementary Data			40
Item 9		Changes In and Disagreements with Accountants on Accounting and Financial Disclosure			76
Item 9A		Controls and Procedures			76
Item 9B		Other Information			78
PART III
Item 10		Directors and Executive Officers of the Registrant			78
Item 11		Executive Compensation			81
Item 12		Security Ownership of Certain Beneficial Owners and Management			87
Item 13		Certain Relationships and Related Transactions			88
Item 14		Principal Accountant Fees and Services			89
PART IV
Item 15		Exhibits and Financial Statement Schedules			90

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:

		2005				2004				2003				2002				2001
Closing		$	0.86			$	0.83			$	0.77			$	0.63			$	0.63
Low		$	0.79			$	0.72			$	0.63			$	0.62			$	0.62
High		$	0.87			$	0.85			$	0.77			$	0.66			$	0.67
Average Noon		$	0.83			$	0.77			$	0.71			$	0.63			$	0.65

The average noon rate of exchange reported by the Federal Reserve Bank of New York for conversion of U.S. dollars into Canadian dollars on February 28, 2006 was $ 0.88 ($1.00 = Cdn.$1.14).

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 to express these different commodities in a common unit. In calculating Bbl equivalents, 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.

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, but are not limited to, our short history of limited revenue, losses and negative cash flow from our current exploration and development activities in the U.S. and China; our limited cash resources and consequent need for additional financing; our ability to raise additional financing; future benefits to be derived from the acquisition of Ensyn Group, Inc. (“Ensyn”); uncertainties regarding the potential success of our oil and gas exploration and development properties in the U.S. and China; uncertainties regarding the potential success of heavy-to light oil upgrading and gas-to-liquids technologies; 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 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. 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

Copies of our annual reports on Form 10-K, our quarterly reports on Form 10-Q, our current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available free of charge on or through our website at http://www.ivanhoe-energy.com/or through the Securities and Exchange Commission’s website at http://www.sec.gov/.

ITEMS 1 AND 2 BUSINESS AND PROPERTIES

CORPORATE OVERVIEW

We are an independent international energy company engaged in the exploration for and production of oil and gas, enhanced oil recovery and natural gas projects and the application of heavy oil upgrading using a proprietary rapid thermal processing technology (“RTP^TM Technology”) and the conversion of natural gas-to-liquids (“GTL”) using a licensed technology. Our core operations are in the United States and China, but we have business and product development opportunities worldwide.

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

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. Our headquarters for operations are located at Suite 400 – 5060 California Avenue, Bakersfield, California, 93309.

HISTORICAL OVERVIEW

We were incorporated pursuant to the laws of the Yukon, 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.

Since 1996 we have pursued a business plan of evaluating and exploiting potentially attractive opportunities to acquire, develop and explore for oil and gas, principally in California, China and in the late 1990’s, in Russia. Our business activities in Russia concluded in 2000.

In 2000, we acquired a master license from Syntroleum Corporation (“Syntroleum”) to use its proprietary GTL technology to convert natural gas into ultra clean transportation fuels and other synthetic petroleum products.

On April 15, 2005, we acquired all the issued and outstanding common shares of Ensyn whereby we acquired an exclusive, irrevocable license to Ensyn’s RTP^TM Technology for use in the upgrading of heavy oil to produce lighter, more valuable crude oil at lower costs and in smaller size facilities than required by conventional technologies.

CORPORATE STRATEGY

Our objective is to create shareholder value by finding and developing oil and gas reserves principally through the application of our RTP^TM Technology for upgrading heavy oil, and as well, through the monetization of stranded gas reserves through the application of the GTL technology licensed from Syntroleum and through conventional exploration and production (“E&P”) of oil and gas, primarily in the U.S. and China.

The most significant element of our strategy was put in place with the acquisition of Ensyn in the second quarter of 2005 (“Merger”). We intend to apply Ensyn’s leading-edge RTP^TM Technology as a critical, value added tool in the development of reserves and production and to establish partnerships with owners of heavy oil reserves where we will build, own and operate commercial heavy-to-light facilities. The use of the RTP^TM Technology will allow us to upgrade heavy oil at facilities located in the field to produce lighter, more valuable crude oil at lower costs and in smaller size facilities than required by conventional technologies. Our heavy oil upgrading technology has four key competitive advantages:

	•		It is field-located and effective at a relatively small minimum scale of 10,000 to 15,000 barrels per day;
	•		The value of the upgraded liquid product means the producer is able to capture the majority of the price differential between heavy and light crude oil;
	•		The upgraded product is easily transported by pipeline without the need for light blend oils; and
	•		The process generates significant on-site excess energy, replacing natural gas for production of steam and/or power used in heavy oil recovery.

The RTP^TM Technology adds significant incremental value, flexibility and risk avoidance to heavy oil producers in areas with existing infrastructure and alternative development options, such as Western Canada, and is also a unique option for the development of stranded heavy oil or tar sands deposits that cannot be produced due to lack of on-site energy or transportation challenges. We believe that these innovative characteristics of this heavy-to-light oil process will provide us with an opportunity to significantly increase our base of oil reserves worldwide through joint venture and production sharing arrangements. We consider the acquisition of Ensyn a major advance in the implementation of our corporate strategy because it will offer significant potential for broadening our access to project opportunities that might not otherwise be available to us.

Another key part of our strategy is to become a leader in the development and operation of GTL projects. We foresee rapidly increasing future demand for clean energy as environmental regulations become more stringent and the world’s crude oil becomes more sour and heavy. We believe that Syntroleum’s proprietary GTL technology holds significant potential for the economic production of synthetic fuels from stranded natural gas deposits throughout the world, which would otherwise be uneconomic to exploit. Although there are several competing GTL technologies, we believe that the Syntroleum technology offers several key advantages. We believe the Syntroleum plant is safer to operate because, unlike competing technologies, the conversion process utilizes compressed air rather than pure oxygen and that plant construction is less expensive.

Our third objective is to focus on exploiting our existing mineral interest holdings, particularly in California’s San Joaquin Basin and at the Dagang oil field and the Zitong gas projects in China. Our plan is to identify new opportunities where production can be achieved quickly and efficiently to create cash flow to fund our operations and allow us to pursue our heavy oil and GTL opportunities.

HEAVY OIL PROCESSING TECHNOLOGY

RTP ^TM License

With the Merger with Ensyn, we acquired an exclusive, irrevocable license to deploy, worldwide, the RTP^TM Technology for petroleum applications as well as the exclusive right to deploy RTP^TM Technology in all applications other than biomass. We believe that the value of owning an exclusive, irrevocable right to the technology can be maximized by using it to create opportunities to acquire interests, and actively participate, in heavy oil development projects by building and owning the projects rather than licensing the technology to third parties.

RTP^TM Process

Heavy oil deposits throughout the world, including bitumen, represent a potentially massive resource, holding quantities of heavy oil more than double the existing global reserves of light or conventional oil. Heavy oil extraction and transportation presents a number of technological challenges and typically requires extensive and cost-intensive infrastructure. Higher viscosity makes the transportation of heavy oil through conventional pipelines difficult or impossible unless it is first blended with lighter, lower viscosity oil or expensive diluents. As a result, less than 1% of the world’s heavy oil deposits are currently under active development. We believe that we have a unique opportunity to accumulate reserves by acquiring interests in stranded heavy oil deposits that would otherwise be uneconomic to develop through conventional means and developing them on an incremental, cost-efficient basis using RTP™ Technology.

The RTP^TM Technology upgrades the quality of heavy oil by producing lighter, more valuable crude oil. The heaviest hydrocarbon fraction is consumed as fuel to generate the steam used to enhance recovery of heavy crude. The lighter crude has improved viscosity that permits more efficient pumping through pipeline networks and potentially reduces transportation costs to marketing points. The RTP^TM Technology uses readily available plant and process components.

We believe that the RTP™ Technology will offer a number of potential cost saving and revenue-enhancement benefits. The reduction or elimination of the need for an external energy source, usually natural gas, for steam production used in the heavy oil recovery process, often a substantial added cost to conventional producers, could significantly reduce the operating cost of extracting the heavy oil. The RTP™ Technology upgraded oil is likely to command a higher market price, reducing what would otherwise be a significant price differential between heavy and light oil. The price paid to producers for heavy oil is lower than the price paid for light oil as the heavy oil requires additional refining. Unlike conventional heavy oil extraction facilities, which usually must be constructed on a large scale in order to be economical and therefore require a significant up-front capital investment, we expect to be able to deploy the RTP™ Technology on a relatively small scale and independent of refineries, which should allow us to develop smaller heavy oil fields that would otherwise be uneconomic to exploit using conventional technologies. The scalability of RTP™ Technology-equipped facilities offers the potential to incrementally develop heavy oil deposits financed by cash flow. Given their limited infrastructure requirements, RTP™ Technology-equipped facilities can be located in relatively remote areas where constructing conventional facilities would not be feasible.

RTP^TM Project Plans and Opportunities

•

Aera Energy LLC Agreement

In August 2004, Ivanhoe Energy HTL Inc. (“IE HTL”) (formerly Ensyn Group, Inc.) and Aera Energy LLC (“Aera”) signed an agreement that set out the financial and operational parameters for a commercial heavy oil project using the RTP™ Technology in Aera’s California heavy oil fields. We are continuing to negotiate for a definitive agreement to build an RTP™ Plant that would yield upgraded, heavy oil and excess thermal energy. The excess thermal energy from this RTP™ Plant would provide Aera an alternative to volatile natural gas prices and thereby lower Aera’s operating expense associated with steam generation, the most significant component of their operating expense. The RTP™ Plant, if completed, would be owned and operated by IE HTL. Additional RTP™ Plants, with a combined heavy oil throughput of up to 45,000 barrels per day, may be installed on Aera’s properties if the performance of the initial RTP™ Plant meets expectations. Aera is one of California’s leading oil producers.

•

RTPTM Commercial Demonstration Facility

In 2004, an RTP^TM Commercial Demonstration Facility (“RTP^TM CDF”) was constructed by an Ensyn joint venture on Aera’s property in the Belridge Field for the purpose of demonstrating the RTP^TM Technology on a commercial scale. In March 2005, initial performance testing of the RTP^TM CDF was completed successfully and the results of the test were verified by the independent consulting firms Muse, Stancil & Co. and Purvin & Gertz Inc. The RTP^TM CDF demonstrated an overall processing capacity of approximately 1,000 barrels-per-day of raw, heavy oil and a hot section capacity of 300 barrels-per-day. We have successfully completed an extended program of technical and operational enhancements to the RTP^TM CDF at a cost of $0.6 million, which culminated in a successful extended run in January 2006 that achieved a number of important performance goals. We are now building on these positive test results by expanding our testing of crude oil from potential resource partners with an initial focus on heavy crude oil from California and Western Canada, including bitumen from Canada’s Athabasca tar sands region. The RTP^TM CDF runs to date have successfully demonstrated a number of commercial configurations and processing alternatives, including both high yield (once through) and high quality (recycle) modes of operation. A number of process enhancements have been validated during the RTP^TM CDF test program, including gas sulphur capture, heavy metals capture and crude acidity reduction.

•

RTPTM Plant Design Package

In the second quarter of 2005, we completed a preliminary design package for a cost of $1.2 million prepared by Colt Engineering Corporation for a 15,000 barrels-per-day feed of raw, heavy oil (5,000 barrels per day hot-section) commercial RTP™ facility (“RTP^TM Plant”). The design package included various studies and costing estimates for both high yield and high quality schemes that would be designed to produce maximum steam or electrical generation for each configuration at varying levels of heavy oil input into the plant. The location that was part of the design basis is Aera’s Belridge oil field using the heavy oil produced there as feedstock. This heavy oil is moderately heavy at 13^o API and is similar to many target heavy oil resources found worldwide, including Canada’s heavy oil from the Cold Lake and Peace River areas of Alberta. The various plant configurations were evaluated as well as the capital estimates that are being used in our economic models.

•

ConocoPhillips Canada Resources Corp. Agreement

Under a pre-existing agreement between IE HTL and ConocoPhillips Canada Resources Corp. (“ConocoPhillips Canada”), certain non-exclusive rights to use the RTP™ Technology for petroleum applications in Canada were granted. ConocoPhillips Canada has the right, through August 2010, to place orders for RTP™ Plants with input capacity of up to 250,000 barrels-per-day. Should ConocoPhillips Canada install RTP™ Plants, IE HTL is entitled to receive royalties per barrel after the first 50,000 barrels-per day of feedstock input capacity. In addition to these rights, ConocoPhillips Canada has the right to test Athabasca bitumen in the RTP^TM CDF, for a fee. Plans are currently underway by ConocoPhillips Canada to transport a quantity of bitumen to the RTP^TM CDF site for an extended test run, in a variety of test configurations. A test program has been agreed to with ConocoPhillips Canada and when completed, would represent a significant advancement in our targeted test program with resource owners, particularly those in the vast Athabasca tar sands region in Alberta.

GAS-TO-LIQUIDS TECHNOLOGY

Syntroleum License

We hold a non-exclusive master license entitling us to use Syntroleum’s proprietary GTL process in an unlimited number of projects with no limit on production volume. In June 2003, we gave up our rights for license fee credits for the $10.0 million we paid for the master license and $2.0 million of other credits. In consideration, Syntroleum removed certain territorial restrictions to our master

license, which will enable us to pursue GTL project opportunities worldwide. Syntroleum has also agreed that, in respect of GTL projects in which both companies participate, no additional license fees or royalties will be payable. Both companies have the right to pursue GTL projects independently, but we would be required to pay Syntroleum the normal license fees and royalties in such projects.

Syntroleum Process

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”) 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.

Syntroleum developed its GTL technology based on a process developed in Germany in the 1920s for the gasification of coal into oil, called the Fischer-Tropsch reaction. Syntroleum has applied its principles to the conversion of natural gas to synthetic liquid hydrocarbons. Syntroleum believes that it holds a competitive advantage over other GTL technologies because the Syntroleum Process uses air when converting natural gas into synthetic hydrocarbons (i.e. diesel, naphtha and LPG). 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.

From our perspective, the attraction of the Syntroleum Process lies in the commercialization of stranded natural gas. Such gas exists in discovered and known reservoirs, but requires innovative gas processing to produce products that can be marketed on an economic basis. Operators consider natural gas to be stranded based on the relative size of the fields and their remoteness from comparable sized markets.

GTL Projects

We have performed detailed project feasibility studies for the construction, operation and cost of plants from 45,000 to 90,000 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. Our capital investment in GTL activities increased to $1.1 million for 2005 compared to $0.1 million in 2004.

In 2004, we initiated a feasibility study to convert coal to synthesis gas (“CTL”) as a feedstock for the Syntroleum Fischer-Tropsch process. The objective of the study is to explore opportunities for converting coal into clean burning CTL fuels in parts of the world where there is a relatively cheap supply of sizeable coal deposits. China and Mongolia both have large coal deposits and China in particular has a rapidly growing need for clean energy.

•

Egypt

In 2005, we signed a memorandum of understanding (“MOU”) with Egyptian Natural Gas Holding Company (“EGAS”), the state organization charged with the management of Egypt’s natural gas resources, to prepare a feasibility study to construct and operate a GTL plant that would convert natural gas to ultra-clean liquid fuels in Egypt. EGAS has agreed to commit up to 4.2 trillion cubic feet of natural gas, or approximately 600 MMcf/d for the anticipated 20-year operating life of the proposed project, if the study indicates that a GTL project is economically feasible. We completed an engineering design of a GTL plant to incorporate the latest advances in the GTL technology and are also in the process of obtaining an updated market analysis for GTL products to reflect changes since the original evaluation was completed several years ago. Plant capacity options of 45,000 and 90,000 Bbls/d will be evaluated. If the feasibility study indicates that a GTL plant is economically viable the parties will enter into negotiations for a definitive agreement for the development of a project. For 2005, we incurred costs for engineering, design and market studies totaling $1.1 million.

•

Bolivia

In July 2003, we signed a participation agreement with Repsol-YPF Bolivia S.A. (“Repsol”) and Syntroleum for a commercialization study to build a 90,000Bbls/d GTL plant in southern Bolivia. The commercialization study included an analysis of alternative plant sites, transportation logistics and screening economics conducted by representatives from Ivanhoe, Repsol and Syntroleum. The initial phase of the commercialization study was completed in 2004 and we determined that under Bolivia’s current hydrocarbon tax regulations a 90,000 Bbls/d GTL plant could be commercially viable. However, due to the passing of a referendum to overhaul Bolivia’s tax regulations in the third quarter of 2004 we elected to postpone any further work on the commercialization study. The participation agreement with Repsol and Syntroleum expired at the end of 2004 and we elected not to renew the participation agreement. Due to the uncertainty in Bolivia and as a result of our on-going evaluation of our GTL projects, we wrote down our $0.3 million investment in 2005.

OIL AND GAS PROPERTIES

Our principal oil and gas properties are located in California’s San Joaquin Basin and Sacramento Gas Basin, the Powder River Basin in Wyoming and the Hebei and Sichuan Provinces in China. Set forth below is a description of these properties.

California

Over the past seven years, we acquired interests in a number of properties in and around the San Joaquin Basin. In 2004, we acquired properties in the Knights Landing field in the Sacramento Gas Basin and established production in the Citrus field in the San Joaquin Basin. To date, our South Midway, Citrus, Knights Landing and North Salt Creek properties contain proved reserves and have wells on production. We cannot assure you that any of our other prospects in California will result in the development of commercially viable production.

Aera Exploration Agreement

The Aera exploration agreement, 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.

•

South Midway

We currently have 57 producing wells in South Midway and are the operator, with a working interest of 100% and a 93% net revenue interest. In 2005, we drilled four new wells on the South Midway properties, consisting of one step-out well, one exploratory well and two temperature observation wells. The exploratory well was successful and plans are underway for a cycle of steam in early 2006 to realize the well’s maximum production. Our capital investment in South Midway of $1.1 million for 2005 was equal to our investment level in 2004 when we drilled six development wells and one exploratory well. Four of the six development wells were completed as producers.

In the southern expansion area of South Midway, we have supplemented the cyclic steam project with a pilot to test continuous steam injection into four wells. The project began in October 2005 and by year-end 2005 the production performance was showing good response to the continuous injection. If successful, continuous steam injection could increase recovery of the oil in place by an estimated 50-70%, similar to recovery in other fields in the area, and add additional probable reserves to our proved undeveloped reserves. Current production from the southern expansion area is approximately 160 gross Bopd and total South Midway production is approximately 530 gross Bopd.

•

Citrus

In October 2005, we farmed out our working interest for a carried interest in one exploration well in 640 gross undeveloped acres and two optional exploration test wells in two additional 640 gross undeveloped acre sections in the Citrus prospect. The farmee must drill one well in each of the three 640-acre sections in order to earn a working interest in that section. We will retain a royalty interest in each of those sections until payout of the exploration well at which time we have the option to convert our royalty interest to a 50% working interest. In addition, we will retain a 100% working interest in approximately 600 undeveloped gross acres in the Citrus prospect. In 2005, our development activities at Citrus were $0.1 million, a decrease of $5.5 million compared to 2004 when we drilled three successful wells.

•

Northwest Lost Hills

The Northwest Lost Hills #1-22 deep well, operated by Aera, began drilling in August 2001. The well was designed to evaluate the natural gas and condensate reserve potential of the deep Temblor formation and reached a depth of approximately 21,000 feet. This drilling objective was achieved in August 2002 after substantial delays and cost overruns resulting from difficult drilling conditions. While drilling the well, we encountered several high-pressure intervals which indicated the presence of natural gas and set casing in preparation for testing. In 2003, the well was temporarily suspended pending the identification of one or more partners to share the costs of the testing program. In August 2005, we concluded a farm-out of one-third of our 42% working interest to Aera to complete

and test the Northwest Lost Hills # 1-22 deep gas well at no additional cost to Ivanhoe. Our share of completion equipment, of approximately $1.0 million, previously purchased by the joint venture partners, was used in the completion of the well including a 4 ¹/2-inch liner, which was run over the open hole to a depth of 21,000 feet. The well was tested in January 2006 and in two tests flowed a non-commercial rate of 400 Mcf/d and 5,000 Bbls/d of water. Aera recommended abandoning the well, with which we concur, and abandonment operations will commence in the third quarter of 2006 at an anticipated net cost to us of $0.7 million. We have no further plans to explore in this prospect.

Other California Prospects

•

Knights Landing

In February 2004, we farmed into the Knights Landing field, which is a 15,700 gross-acre block located in the Sutter and Yolo counties in northern California, by purchasing a 50% working interest in four previous discoveries in the contract area and funding gas gathering, surface treatment facilities and meters to connect the four wells to an existing pipeline system. In 2004, we drilled nine new exploratory wells to earn a 50% working interest after payout in any new discoveries, which resulted in three successful completions and six dry holes. Three of these new wells were successful and by April 2005 had been tied into the existing pipeline system and were on production. In December 2004, we reached an agreement with the operator of the field to purchase its interest in the field, increasing our working interests in the field and 11 existing producing natural gas wells to between 80% and 100%. In late 2005, a 3-D seismic data program was acquired over 25 square miles covering our Knights Landing acreage block. We completed our seismic acquisition program in December 2005 and have initiated interpretation of the seismic data. We expect to complete processing and interpretation of the seismic data by the end of the second quarter of 2006 and to recommence drilling in the third quarter of 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. We spent $2.5 million on development activities at Knights Landing in 2005 on seismic plus the costs to hook up the three successful exploration wells drilled in 2004, a decrease of $4.6 million compared to 2004.

We reached peak average production from our Knights Landing gas wells of 185 gross Boe/d (110 net Boe/d) in the third quarter of 2005 but by the end of 2005, production from the Knights Landing wells had been fully depleted in all but one well, which was producing 12 gross Boe/d (7 net Boe/d).

•

North Salt Creek

In mid-2004, we farmed into the McCloud River prospect near the Cymric field in the San Joaquin Basin. We have a 24% working interest in this 880 gross-acre prospect and are the operator. The initial well resulted in a dry hole. A second prospect, North Salt Creek #1, was drilled to 2,500 feet on the acreage in 2005 and encountered multiple oil and gas bearing horizons. North Salt Creek #1 commenced natural gas sales in September 2005 at a rate of 1,000 Mcf/day. Drilling of two follow-up wells was completed in the fourth quarter of 2005. Multiple targets were encountered in both of these wells. Production testing indicated the reservoir contains heavy 12^o API oil and will likely require steam to produce commercially. We are in the process of obtaining permits to test steam these wells. Our expenditures for 2005 totaled $0.5 million and additional drilling to develop this field is planned for 2006.

•

North Yowlumne

In December 2005, drilling commenced on the North Yowlumne prospect with a planned total depth of 13,000 feet to test the Stevens sands that have produced over 100 million barrels of oil at the nearby Yowlumne field. We hold a 12.5% working interest in this prospect and have farmed out an 87.5% interest in the initial well and prospect. In the event of a discovery, we will own a 56.25% working interest in the well after payout. Results of the well will be known during the first quarter of 2006. We own an interest in approximately 6,900 gross acres in the prospect.

Wyoming

•

LAK Ranch

In January 2004, we signed farm-in and joint operating agreements with Derek Resources (USA), Inc. (“Derek”) for the joint development of the LAK Ranch field, a thermal recovery/horizontal well oil project in Weston County, Wyoming. The LAK Ranch field covers approximately 7,500 gross acres in Wyoming’s Powder River basin.

We are the operator of the project and earned an initial 30% working interest by financing the capital cost of the pilot phase. Following the pilot phase, we will have the option to increase our working interest to 60% by providing additional capital toward the initial development phase for a total of $5.0 million, including the amounts spent on the pilot phase. Thereafter, all future capital expenditures are to be shared on a working-interest basis. Should we elect not to proceed beyond the pilot phase our working interest

will be reduced to 15% and Derek will become the operator. At the end of 2005 our working interest was 43%.

Prior to the farm-in agreement, Derek completed a steam assisted gravity drainage horizontal well pair to a depth of 1,000 feet and 1,800 feet into the Newcastle Sand formation. Surface steam-injection and oil-recovery equipment was installed. Extensive testing indicates that, because of the viscosity of the oil, production can be expected to respond favorably to the application of continuous heat through steam injection. Facility modifications for the pilot phase were completed in the second quarter of 2004 to enable steam injection in the producing horizontal well.

The ultra-high resolution 3-D seismic survey needed to better define the optimum reservoir development locations was completed in December 2004 with results evaluated during the second quarter of 2005. In addition, one vertical well was drilled in the first quarter of 2005 for data collection purposes. We used the data from the 3-D seismic survey to plan and drill three vertical injection wells and test the potential of continuous steam injection. We commenced continuous steaming in the fourth quarter of 2005. An early production response was realized from this injection, with oil rates increasing from 10 to 45 bopd. We plan continuous steam injection throughout 2006, while monitoring the production response. Based on observed production and temperature responses, we will evaluate the potential to expand the pilot project.

Following completion of the pilot phase, the development phase would include additional horizontal production wells, new steam-injection and extension of surface facilities. The performance of the pilot phase will dictate the development timing. We invested $1.2 million in LAK Ranch in 2005, a decrease of $0.8 million compared to 2004. We expect to reach a decision regarding the development phase by the fourth quarter of 2006.

China

•

Dagang

Our producing property in China is a 30-year production-sharing contract with China National Petroleum Corporation (“CNPC”), covering an area of 22,400 gross acres divided into six 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%. 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 for common shares in Ivanhoe 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 acquired Richfirst’s 40% working interest.

The production-sharing contract stipulates that we have the right to market our oil domestically or export it, sell our product in U.S. dollars and receive world market prices for our product. We are currently selling our crude oil to CNPC at a three-month rolling average price of Cinta crude oil, which is currently averaging approximately $3.00 per barrel less than the West Texas Intermediate (“WTI”) price. Cinta is an Indonesian crude that is traded daily on the international oil market.

All petroleum producers in China pay a value added tax of 5% on oil production. We pay no royalty until annual gross production of crude oil from a particular block within the Dagang field exceeds 500,000 tonnes per annum. Royalties then become payable at a rate of 2% and increase incrementally as the rate of production increases to a maximum of 12.5% once annual gross production on a block exceeds four million tonnes. 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.

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. In 2004, we drilled 19 development wells and in 2005 we drilled and completed an additional 19 wells, had one well awaiting completion and recompleted 6 existing wells. We incurred $23.8 million for our development activities in the Dagang field, in 2005, an increase of $3.8 million compared to 2004.

The year-end 2005 gross production rate was 2,310 Bopd compared to 1,655 Bopd at the end of 2004. Review of test results in the most northerly block of the Dagang field confirmed the presence of significant faulting and poor reservoir continuity, eliminating the potential for economic development in that block. By the end of 2005, we had drilled a total of 39 development wells, as compared to the estimated 115 wells set out in the approved ODP. We suspended drilling to allow for detailed evaluation of well productivity and production decline performance. In the fourth quarter of 2005, we reached agreement with CNPC to reduce the overall scope of the ODP to approximately 60 wells. Subsequent to that agreement, and as a result of lower than anticipated well productivity on the most recent wells, a review of our investment and return potential was undertaken. Our fracture stimulation program was expanded to allow a quicker evaluation of the potential of the blocks being developed. We continue to conduct technical reviews and evaluate the results

of our stimulation program to provide the information necessary to make critical decisions on resuming our drilling program.

As provided for in the production-sharing contract, if CNPC requests us to resume development operations within a reasonable period of time, and we fail to resume operations within that time frame, CNPC has the right to request us to give up our rights in the oil field. We are currently in discussions with CNPC, based on our evaluations and further economic studies of productivity of the field, as to the scope of the final ODP. We expect to resolve this with CNPC in the second quarter of 2006. Should there be a disagreement between CNPC and ourselves as to the final ODP scope, there are arbitration provisions in the contract that allow us to settle matters such as this.

•

Sichuan Basin

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 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.

During the first phase of exploration, which expired in December 2005, we were to complete a minimum work program consisting of reprocessing approximately 1,250 miles of seismic data, completing approximately 300 additional miles of new seismic lines and drilling at least 23,000 feet. Upon completion of the first phase, we must relinquish up to 30% of the Zitong block. From 2003 to 2005, we reprocessed approximately 1,550 miles of existing seismic data and acquired approximately 700 miles of new seismic data plus interpretation of all the seismic data. In the second quarter of 2005, we drilled our first well, Dingyuan 1, to a depth of approximately 9,000 feet. The well was not commercially viable and cement plugs were set that will allow us to use the surface location and re-enter the well bore for a potential directional hole. During 2005, we spent $4.0 million to acquire and process seismic data and $2.9 million to drill our first well, Dingyuan 1 compared to $6.9 million spent in 2004 to complete the acquisition, processing and interpretation of our seismic program.

In December 2005, we were granted an extension of the first phase to May 31, 2006 provided the second exploration well is spud before May 1, 2006. If the second exploration well is spud before May 1, 2006 but we are unable to complete the drilling operation before May 31, 2006, CNPC will grant a further six-month extension to complete the drilling operation.

In January 2006, we finalized a farm-out agreement with Mitsubishi Gas Chemical Company Inc. of Japan (“Mitsubishi”). Mitsubishi will pay us $4.0 million for a 10% interest in the Zitong block, subject to approval from the relevant Chinese authorities. After the drilling of a second exploration well in 2006, which is expected to substantially satisfy our work commitment for the first phase, we will evaluate the results and make an election at that time as to our decision, along with Mitsubishi, to enter into the next three-year exploration phase.

If we elect to participate in the second phase, we must complete a minimum work program consisting of new seismic lines totaling approximately 200 miles and drill approximately 23,000 feet, with estimated minimum expenditures for the program of $16 million. Following the completion of phase two, we must relinquish all of the property except any areas identified for development and production. If we elect to enter into phase two, we must complete the minimum work program or we will be obligated to pay to CNPC the cash equivalent of the deficiency in the work program for that exploration phase.

If we identify a field for development and/or production, the parties will divide the participating interest in the project, with CNPC entitled to fund and take up to 51% of the participating interest and Mitsubishi and us the remaining 49%.

Once commercial production commences, we will recover annual exploration, development and operating costs from up to 60% of gross oil production and 70% of gross natural gas production. After annual cost recovery, we are entitled to production equaling our participating interest, subject to certain additional rights of the Chinese government. Assuming we, along with Mitsubishi, hold a 49% participating interest, we will be entitled to approximately 75% of production initially, declining to approximately 45% after full exploration and development cost recovery.

CNPC retains the rights to production from six existing wells located on the Zitong block. We can drill new wells on the same structure as those tapped by the existing wells, but our wells must be no closer than 3,280 feet from the existing wells.

•

CITIC Alliance

In October 2002, we entered into an agreement with CITIC Energy Ltd. (“CITIC Energy”) to form a strategic alliance to seek out and develop oil and gas projects in China and around the world. CITIC Energy is a subsidiary of CITIC, a major Chinese state-owned enterprise that holds interests in a wide range of industries.

In April 2003, we entered into a further agreement with CITIC Energy that enables both companies to form a global strategic alliance to investigate, explore and develop oil, natural gas, metallurgical coal, liquefied natural gas and GTL projects in China and around the world, to help supply China’s future energy requirements. The agreement builds upon the initial partnership formed between the two companies in October 2002 and follows discussions both between the two companies and with asset owners of potential projects in China and in other parts of the world.

OTHER ENHANCED OIL RECOVERY PROJECTS

Enhanced oil recovery, also referred to as tertiary recovery, refers to a variety of processes to increase the amount of oil removed from a reservoir, typically by injecting a liquid (e.g., steam, surfactant) or gas (e.g., nitrogen, carbon dioxide). EOR techniques are generally utilized after oil and gas production levels decline from primary recovery and secondary recovery (e.g. waterflood) methods. The most successful by far of the EOR methods is steam injection.

•

Iraq

In October 2004, we signed an 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^o API heavy oil at a depth of about 1,000 feet.

We will evaluate the potential response of the Qaiyarah oil field to the latest in EOR techniques, along with the potential value that could be added using the RTP^TM Technology to produce higher quality, more valuable crude oil. The work will include an assessment of the oil-in-place in the reservoirs, and the optimum EOR and heavy oil processing methods to establish economically recoverable volumes at the Qaiyarah oil field.

The reservoir assessment has been completed and various recovery methods have been evaluated. Facility design work is currently progressing and once complete, an economic evaluation will follow. If the evaluation studies indicate development of the field is economically viable, we will present a development plan and offer a commercial proposal to implement an EOR program for the Qaiyarah oil field. We expect to submit our proposal to the Iraq Ministry of Oil in the second half of 2006. The Iraq Ministry of Oil is under no obligation to execute the project or to enter into formal commercial negotiations at the completion of our study.

We invested $1.7 million and $0.2 million in 2005 and 2004, respectively, on the Qaiyarah heavy oil field project. In addition, we invested $1.1 million and $1.8 million in 2005 and 2004, respectively, on other projects in Iraq including submission of four bids for the engineering, design and procurement of oil production facilities and EOR development projects. Our bids are still under consideration by the Iraq Ministry of Oil.

•

Colombia

In late 2004, we signed an MOU with Ecopetrol S.A. (“Ecopetrol”) for a study of the heavy crudes from the large Castilla and Chichimene oil fields in Colombia, located about 75 miles southeast of Bogotá in the Central Llanos Basin. We did not meet the company-size requirements that Ecopetrol specified in its final bidding qualifications for the “Llanos Basin Heavy Crude Project”, which included the Castilla and Chichimene fields and in the third quarter of 2005 we wrote down our $0.3 million investment in this project. We continue to review the potential for other heavy oil upgrading opportunities in Colombia.

EMPLOYEES

As at December 31, 2005, we had 153 employees. None of our employees are unionized.

RESERVES, PRODUCTION AND RELATED INFORMATION

See the “Supplementary Disclosures About Oil and Gas Production Activities”, 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. 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.

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 only and exclude depletion and depreciation, income taxes, interest, selling and administrative expenses.

		Average Sales Price												Average Operating Costs
		2005				2004				2003				2005				2004				2003
Crude Oil and Natural Gas ($/Boe)
U.S		$	44.01			$	34.66			$	25.69			$	15.64			$	11.76			$	10.87
China		$	49.97			$	36.11			$	28.41			$	8.27			$	8.14			$	13.71

The following tables 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.

		2005																2004																2003
		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.			87	(1)			69.3	(1)			3	(1)			1.5	(1)			84	(2)			67.2	(2)			13				11.7				76				59.9				1				0.5
China			43				21.2				—				—				21				10.3	(3)			—				—				9				7.4				—				—

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
		2005								2004								2003								2005								2004								2003
		Oil				Gas				Oil				Gas				Oil				Gas				Oil				Gas				Oil				Gas				Oil				Gas
U.S.			1.5				0.2				0.4				3.0				—				—				—				1.8	(1)			1.4				4.0				—				—
China			—				—				—				—				—				—				—				1.0				—				—				—				—
Total			1.5				0.2				0.4				3.0				—				—				—				2.8				1.4				4.0				—				—

Development

		Productive Wells																								Dry Wells
		2005								2004								2003								2005								2004								2003
		Oil				Gas				Oil				Gas				Oil				Gas				Oil				Gas				Oil				Gas				Oil				Gas
U.S.			1.0				—				7.3	(1)			—				17.0				—				—				—				2.0				—				2.0				—
China			10.8				—				7.9				—				—				—				—				—				—				—				—				—
Total			11.8				—				15.2				—				17.0				—				—				—				2.0				—				2.0				—

Wells in Progress

At the end of 2005, 2004 and 2003 we had 1.1 (3 gross), 2.9 (6 gross) and 2.8 (5 gross) net wells, respectively, which were either in the process of drilling or suspended.

The following table sets forth our holdings of developed and undeveloped oil and gas acreage as at December 31, 2005. 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.			14,055				6,176				104,387				31,838
China (1)			2,969				1,461				888,924				884,280

The following table sets out estimates of our share of proved reserves in respect of our U.S. and China operations and calculations of cash flows, before tax and after tax, undiscounted and discounted at 10% and 15%, based on costs and prices as at December 31, 2005. Estimates for our U.S. and China operations were prepared by independent petroleum consultants Netherland, Sewell & Associates Inc. and Gilbert Laustsen Jung Associates Ltd., respectively.

													Our Share of												Our Share of
										Before Tax Cash Flows												After Tax Cash Flows
		Our Share								In Thousands of U.S. Dollars												In Thousands of U.S. Dollars
		Oil				Gas				Discounted at:												Discounted at:
		(Mbbl)				(MMcf)				0%				10%				15%				0%				10%				15%
Net Proved Reserves (1)
U.S.			1,272				1,685			$	47,829			$	32,174			$	28,128			$	47,829			$	32,174			$	28,128
China			1,300				—				55,569				44,114				39,997				53,985				43,299				39,397
			2,572				1,685			$	103,398			$	76,288			$	68,125			$	101,814			$	75,473			$	67,525

Special Note to Canadian Investors

Ivanhoe is a United States Securities and Exchange Commission (“SEC”) registrant and files annual reports on Form 10-K. Accordingly, our reserves estimates and securities regulatory disclosures are prepared based on U.S. disclosure standards. 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 have been granted, exemptions from certain NI 51-101 disclosure requirements. These exemptions permit us to substitute disclosures based on U.S. standards for much of the annual disclosure required by NI 51-101 and to prepare our reserves estimates and related disclosures in accordance with U.S. disclosure 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 U.S. disclosure requirements.

The reserves quantities disclosed in this Annual Report on Form 10-K represent net proved reserves calculated on a constant price basis using the standards contained in SEC Regulation S-X and SFAS No. 69. Such information differs from the corresponding information prepared in accordance with Canadian disclosure standards under NI 51-101. The primary differences between the U.S. 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 also requires disclosure of reserves and related future net revenues using forecasted prices;
	•		the SEC mandates disclosure of proved and proved producing 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 U.S. disclosure standards and NI 51-101 requirements.

ADDITIONAL FACTORS AFFECTING THE BUSINESS

See also Item 7 of this Form 10-K.

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. See “Risk Factors”.

Environmental Regulations

Our conventional oil and gas and EOR operations are subject to various levels of government laws and regulations relating to the protection of the environment in the countries in which they operate. See “Risk Factors”. 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.

In China, environmental regulation does not exist on a national level. Individual projects are monitored by the state and the standard of environmental regulation depends on each case.

Environmental Provisions

As at December 31, 2005, a $1.7 million provision has been made for future site restoration and plugging and abandonment of wells in the U.S. and $0.1 million for the removal of the RTP^TM CDF and restoration of the Aera site occupied by the RTP^TM CDF. The future cost of these obligations is estimated at $2.2 million and $0.1 million for the U.S. wells and RTP^TM CDF, respectively. 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. During 2005, we added $1.0 million and $0.1 million to our provision for future site restoration and plugging and abandonment of U.S. wells and RTP^TM CDF, respectively.

Government Regulations

Our business is subject to certain U.S. and Chinese federal, state and local laws and regulations 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 in the U.S., often imposing greater liability on a larger number of potentially responsible parties. It is not unreasonable to expect that the same trend will be encountered in China. Because the requirements imposed by such laws and regulations are frequently changed, we are not able to predict the ultimate cost of compliance.

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. The following factors contain certain forward-looking statements involving risks and uncertainties. Our actual results may differ materially from the results anticipated in these forward-looking statements.

We are not able to guarantee the successful commercial development of the RTP ^TM Technology.

To date, no commercial-scale RTP^TM Plants have been constructed using the RTP^TM Technology and, therefore, the process has not been proven to be financially viable on a commercial scale. Other developers of competing heavy-oil processing technologies may have significantly more financial resources than we do and may be able to use this to obtain a competitive advantage.

We may not be able to conclude joint venture or production-sharing contracts using the RTP ^TM Technology.

We have signed an MOU to study the economic feasibility of RTP™ heavy oil processing facilities in Iraq but we can give no assurances as to when or if we will be able to conclude joint ventures or production-sharing contracts employing RTP^TM Technology.

We are not able to guarantee the successful commercial development of our licensed GTL technology.

To date, no commercial-scale GTL plants have been constructed using the Syntroleum Process and, therefore, the process has not been proven on a commercial scale. Other developers of GTL technology have significantly more financial resources than we do and may be able to use this to obtain a competitive advantage.

We may not be able to conclude a GTL development and production-sharing contract.

To date, we have been unsuccessful in concluding a GTL development and production-sharing contract and we can give no assurances as to when or if we will be able to conclude a contract in any of the countries where we are now, or will be, exploring GTL project opportunities.

Our efforts to commercialize the Syntroleum Process and the RTP ^TM Technology may give rise to claims of infringement upon the patents or proprietary rights of others.

We own licenses to employ the Syntroleum Process and the RTP^TM Technology process but we may not become aware of claims of infringement upon the patents or rights of others in these respective technologies until after we have made a substantial investment in the development and commercialization of projects utilizing these licensed technologies. Third parties may claim that the technologies we license have infringed 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 affected technologies. 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 affected technologies. 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 affected licensed 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 GTL or heavy oil processing technologies competitive with the Syntroleum Process and the RTP^TM Technology that we license, may have significantly more resources to spend on litigation.

Technological advances could significantly decrease the cost of upgrading petroleum and, if we are unable to adopt or incorporate technological advances into our operations, the RTP ^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 RTP^TM Technology, 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 RTP^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 RTP^TM Technology facilities to become uncompetitive.

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

Expansion of our operations will require significant capital expenditures for which we may be unable to provide sufficient financing. Our need for additional capital may harm our financial condition.

We will be required to make substantial capital expenditures far beyond our existing capital resources to develop a GTL, EOR or RTP^TM Technology project, to exploit our existing reserves and to discover new oil and gas reserves. Historically, we have relied, and continue to rely, on external sources of financing to meet our capital requirements to continue acquiring, exploring and developing oil and gas properties and to otherwise implement our corporate development and investment strategies. We have, in the past, relied upon equity capital as our principal source of funding. We plan to obtain the future funding we will need through debt and equity markets or through project participation arrangements with third parties, but we cannot assure you that we will be able to obtain additional funding when it is required and whether it will be available on commercially acceptable terms. We also make offers to acquire oil and gas properties in the ordinary course of our business. If these offers are accepted, our capital needs may increase substantially. If we fail to obtain the funding that we need when it is required, we may have to forego or delay potentially valuable opportunities to acquire new oil and gas properties 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 a history of losses and must generate greater revenue to achieve profitability.

We commenced operations in 1997 and have been involved in three start-up situations in Russia, China and the U.S. Like most start-up companies we have incurred losses during our start-up activities. Our current cash flows alone are insufficient to fund our business plans, necessitating further growth and funding for implementation. We may be unable to achieve the needed growth to obtain profitability, fund debt repayments and related interest payments and may fail to obtain the funding that we need when it is required.

Conflict in the Middle East may hamper our GTL and EOR project objectives.

Ongoing tensions and conflict in the Middle East could harm our business by making it difficult or impossible to continue our pursuit of GTL and EOR projects in the region or to obtain financing for projects we do succeed in obtaining. It is impossible to predict the occurrence of such events, how long they will last, the economic consequences of the conflict for the energy industry, regionally and globally, and how our business might be affected over the longer term.

Government regulations in foreign countries may limit our activities and harm our business operations.

We carry on business in China and we may, in the future, carry on business in other foreign jurisdictions with governments, governmental agencies or government-owned entities. The foreign legal framework for the agreements through which we carry on business now or in the future, particularly in developing countries, is often based on recent political and economic reforms and newly enacted legislation, which may not be consistent with long-standing local conventions and customs. As a result, there may be ambiguities, inconsistencies and anomalies in the agreements or the legislation upon which they are based which are atypical of more developed legal systems and which may affect the interpretation and enforcement of our rights and obligations and those of our foreign partners. Local institutions and bureaucracies responsible for administering foreign laws may lack a proper understanding of the laws or the experience necessary to apply them in a modern business context. Foreign laws may be applied in an inconsistent, arbitrary and unfair manner and legal remedies may be uncertain, delayed or unavailable.

You should not unduly rely on reserve information because reserve information represents estimates.

Reserve estimates involve a great deal of uncertainty, because they depend in large part upon the reliability of available geologic and engineering data, which is inherently imprecise. Geologic and engineering data are used to determine the probability that a reservoir of oil and natural gas exists at a particular location, and whether oil and natural gas are recoverable from a reservoir. Recoverability is ultimately subject to the accuracy of data including, but not limited to, geological characteristics of the reservoir structure, reservoir fluid properties, the size and boundaries of the drainage area and reservoir pressure and the anticipated rate of pressure depletion.

The evaluation of these and other factors is based upon available seismic data, computer modeling, well tests and information obtained from production of oil and natural gas from adjacent or similar properties, but the probability of the existence and recoverability of reserves is less than 100% and actual recoveries of proved reserves usually differ from estimates.

Reserve estimates also require numerous assumptions relating to operating conditions and economic factors including, among others, the price at which recovered oil and natural gas can be sold, the costs of recovery, prevailing environmental conditions associated with drilling and production sites, availability of enhanced recovery techniques, ability to transport oil and natural gas to markets and governmental and other regulatory factors, such as taxes and environmental laws.

A negative change in any one or more of these factors could result in quantities of oil and natural gas previously estimated as proved reserves becoming uneconomic. For example, a decline in the market price of oil or natural gas to an amount that is less than the cost of recovery of such oil and natural gas in a particular location could make production thereof commercially impracticable. The risk that a decline in price could have that effect is magnified in the case of reserves requiring sophisticated or expensive production enhancement technology and equipment, such as some types of heavy oil. Each of these factors, by having an impact on the cost of recovery and the rate of production, will also affect the present value of future net cash flows from estimated reserves.

In addition, estimates of reserves and expected future net cash flows therefrom prepared by different independent engineers, or by the same engineers at different times, may vary substantially.

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 document. Whether we ultimately implement our plans will depend on availability and cost of capital; receipt of 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.

We cannot guarantee the successful commercialization of our exploration activities.

We have exploration and development projects in the U.S. and China. Our projects are at various stages and, like all exploration companies in the oil and gas industry, we are exposed to the significant risk that our exploration activities will not necessarily result in a discovery of economically recoverable volumes.

We might not be successful in acquiring and developing new prospects and our exploration and development properties may not contain any significant proved reserves.

Our future exploration and development success depends upon our ability to find, develop and acquire additional economically recoverable oil and natural gas reserves. The successful acquisition and development of oil and gas properties requires proper forecasting of recoverable reserves, oil and gas prices and operating costs, potential environmental and other liabilities and productivity of new wells drilled.

Estimates of cost to explore, develop and produce are inherently inexact. As a result, we might not recover the purchase price of a property from the sale of production from the property, or might not realize an acceptable return from properties we acquire. Our estimates of exploration, development and production costs can be affected by such factors as permitting regulations and requirements, weather, environmental factors, unforeseen technical difficulties and unusual or unexpected formations, pressures and work interruptions.

Exploration and development involves significant risks. Few wells which are drilled are developed into commercially producing fields. Substantial expenditures may be required to establish the existence of proved reserves, and we cannot assure you that sufficient commercial quantities of oil and gas deposits will be discovered to enable us to recover our exploration and development costs and sustain our business.

Our business may be harmed if we are unable to retain our licenses, leases and working interests in licenses and leases.

Some of our properties are held under licenses and leases and working interests in licenses and leases. If we, or the holders of the licenses or leases, fail to meet the specific requirements of each license or lease, the license or lease may terminate or expire. We cannot assure you that any of the obligations required to maintain each license or lease will be met. The termination or expiration of our licenses or leases or our working interest relating to a license or lease may harm our business. Some of our property interests will terminate unless we fulfill certain obligations under the terms of our agreements related to such properties. If we are unable to satisfy these conditions on a timely basis, we may lose our rights in these properties. The termination of our interests in these properties may harm our business.

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. These laws and regulations govern the operation and maintenance of our facilities, the discharge of materials into the environment and other environmental protection issues and may, among other potential consequences, require that we acquire permits before commencing drilling; restrict the substances that can be released into the environment with drilling and production activities; limit or prohibit drilling activities on protected areas such as wetlands or wilderness areas; require that reclamation measures be taken to prevent pollution from former operations; require remedial measures to mitigate pollution from former operations, such as plugging abandoned wells and remediating contaminated soil and groundwater and require remedial measures be taken with respect to property designated as a contaminated site.

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

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

Crude oil and natural gas prices are volatile.

Fluctuations in the prices of oil and natural gas will affect many aspects of our business, including our revenues, cash flows and earnings; our ability to attract capital to finance our operations; our cost of capital; the amount we are able to borrow and the value of our oil and natural gas properties.

Both oil and natural gas prices are extremely volatile. Oil prices are determined by international supply and demand. Political developments, compliance or non-compliance with self-imposed quotas, or agreements between members of the OPEC can affect world oil supply and prices. Any material decline in prices could result in a reduction of our net production revenue and overall value. The economics of producing from some wells could change as a result of lower prices and as a result, we could elect not to produce from certain wells. Any material decline in prices could also result in a reduction in our oil and natural gas acquisition and development activities.

In addition, a material decline in oil and natural gas prices from historical average prices could adversely affect our ability to borrow and to obtain additional capital on attractive terms.

Volatile oil and natural gas prices make it difficult to estimate the value of producing properties for acquisition and often cause disruption in the market for oil and natural gas producing properties, as buyers and sellers have difficulty agreeing on such value. Price volatility also makes it difficult to budget for and project the return on acquisitions and development and exploration projects.

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 share ownership is highly concentrated and, as a result, our principal shareholder significantly influences our business.

As at the date of this annual report, our largest shareholder, Robert M. Friedland, owned approximately 21% 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 and technical personnel. Messrs. David Martin and E. Leon Daniel, in particular, have extensive experience in oil and gas operations throughout the world. 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.

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

We are not currently a party to any material legal proceedings.

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

None

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

Market Information

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

		NASDAQ CAPITAL MARKET (IVAN)
		(U.S.$)
		2005																2004
		4th Qtr				3rd Qtr				2nd Qtr				1st Qtr				4th Qtr				3rd Qtr				2nd Qtr				1st Qtr
High			2.00				2.50				2.95				3.34				3.20				2.33				3.06				4.28
Low			.99				1.97				1.98				2.04				2.03				1.22				2.08				1.96

		TORONTO STOCK EXCHANGE (IE)
		(CDN$)
		2005																2004
		4th Qtr				3rd Qtr				2nd Qtr				1st Qtr				4th Qtr				3rd Qtr				2nd Qtr				1st Qtr
High			2.32				3.06				3.60				4.02				3.90				3.00				4.15				5.49
Low			1.16				2.30				2.52				2.52				2.56				1.62				2.88				2.63

On December 31, 2005, the closing prices for our common shares were $1.06 on the NASDAQ Capital Market and Cdn. $1.23 on the Toronto Stock Exchange.

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 a majority of an issuer’s board of directors be comprised of independent directors determined on the basis of prescribed independence criteria. 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 a majority of our board of directors is comprised of independent directors, based on prescribed independence criteria, which differ slightly from the criteria prescribed in the NASDAQ Marketplace Rules.

Although applicable Canadian rules pertaining to corporate governance make reference, as part of a series of non-prescriptive corporate governance guidelines based on what are perceived to be “best practices”, to the desirability a board comprised of a majority of independent directors, there is no legal requirement in Canada that mandates a board comprised of a majority of independent directors. Our board of directors consists of 5 individuals who are independent and 5 individuals who are not independent, applying the criteria prescribed by applicable Canadian rules pertaining to corporate governance and the criteria prescribed by the NASDAQ Marketplace Rules.

Enforceability of Civil Liabilities

We were organized under the laws of Canada and our executive offices are located in British Columbia, Canada. Some of our directors, controlling persons and 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 persons, 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 persons, 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 persons or experts named in this Annual Report on Form 10-K.

Holders of Common Shares

As at December 31, 2005, a total of 220,779,335 of our common shares was issued and outstanding and held by 222 holders of record with an estimated 36,297 additional shareholders whose shares were held for them in street name or nominee accounts.

Dividends

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

Exchange Controls and Taxation

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

There is no limitation imposed by the laws of Canada, the laws of the Yukon, 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. 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 2006 is Cdn.$265 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.

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) (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%.

Sales of Unregistered Securities

	•		During the year ended December 31, 2005, we issued securities, which were not registered under the Securities Act of 1933 (the “Act”), as follows:
	•		in February 2005, we issued a convertible promissory note in the principal amount of $6.0 million to an arm’s length lender in a transaction exempt from registration under Rule 903 of the Act. The principal amount and all accrued and unpaid interest was convertible into common shares of the Company at a price of U.S.$2.25 per common share. The conversion rights were not exercised and expired in November 2005;
	•		in April 2005, we issued 4,100,000 special warrants at a price of Cdn.$3.10 per special warrant to institutional and individual investors in a transaction exempt from registration under Rule 903 of the Act. 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 July 2005. One common-share purchase warrant will entitle the holder to purchase one common share at a price of Cdn.$3.50 exercisable until the second anniversary date of the special warrant date of issue;

	•		in April 2005, we issued 29,999,886 common shares in exchange for all of the issued and outstanding common shares of Ensyn in a transaction exempt from registration under Section 3(a)(10) of the Act;
	•		in May 2005, we issued a convertible promissory note in the principal amount of $2.0 million to an arm’s length lender in a transaction exempt from registration under Rule 903 of the Act. The principal amount and all accrued and unpaid interest was convertible into common shares of the Company at a price of U.S.$2.15 per common share. The conversion rights were not exercised and expired in November 2005;
	•		in June 2005, we issued 1,500,000 common shares at a price of U.S.$1.10 to a Canadian institutional investor pursuant to the exercise of previously issued share purchase warrants in a transaction exempt from registration under Rule 903 of the Act;
	•		in July 2005, we issued 1,000,000 special warrants at a price of Cdn.$3.10 per special warrant to an institutional investor in a transaction exempt from registration under Rule 903 of the Act. Each special warrant was exercised in November 2005 to acquire, for no additional consideration, one common share and one share purchase warrant.. One common share purchase warrant will entitle the holder to purchase one common share at a price of Cdn.$3.50 exercisable until the second anniversary date of the special warrant date of issue;
	•		in August 2005, we issued 1,500,000 common shares at a price of U.S.$1.10 to a Bahamian institutional investor pursuant to the exercise of previously issued share purchase warrants in a transaction exempt from registration under Rule 903 of the Act;
	•		in September 2005, we issued 1,514,706 common shares at a price of U.S.$1.87 to a Bahamian institutional investor pursuant to the exercise of previously issued share purchase warrants in a transaction exempt from registration under Rule 903 of the Act;
	•		in November 2005, we issued 2,000,000 common share purchase warrants to an arm’s length lender in a transaction exempt from registration under Rule 903 of the Act. Each common share purchase warrant is exercisable to purchase one common share of the Company at a price of U.S.$2.00 per common share at any time until November 2007; and
	•		in November 2005, we issued 11,196,330 special warrants at U.S.$1.63 per special warrant to four individual investors in a transaction exempt from registration under Rule 903 of the Act. 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 December 2005. One common share purchase warrant will entitle the holder to purchase one common share at a price of U.S.$2.50 exercisable until the second anniversary date of the special warrant date of issue.

ITEM 6. FIVE YEAR SUMMARY OF 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, which are not materially different from GAAP in the U.S. except as noted immediately below in “Reconciliation to U.S. GAAP”. See also Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations”.
		The following table shows selected financial information for the years indicated:

		December 31,
		(stated in thousands of U.S. dollars, except per share amounts)
		2005				2004				2003				2002				2001
Financial Position
Total assets			240,877				118,486				106,574				107,088				104,003
Long-term debt			4,972				2,639				833			Nil				Nil
Shareholders’ equity			204,767				103,586				100,537				100,548				96,897
Common shares outstanding (in thousands)			220,779				169,665				161,359				144,466				139,267
Capital investments			43,301				46,454				15,391				18,828				40,504
Results of Operations
Revenues			29,939				17,997				9,659				8,437				9,722
Net loss			13,512	(1)			20,725	(1)			30,179	(1)			7,130	(1)			21,122	(1)
Net loss per share — basic and diluted			0.07				0.12				0.20				0.05				0.16

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 only material differences between Canadian and U.S. GAAP, which affect our financial statements are as follows:

	•		adjustment for the reduction in stated capital in 1999,
	•		increase in the ascribed value of shares issued for the acquisition of U.S. royalty interests in 1999 and 2000,
	•		net additional impairment provision for our China oil and gas properties in 2001 and 2005, net of depletion expense,
	•		net additional impairment provision for our U.S. oil and gas properties in 2004 and 2005, net of depletion expense,
	•		net additional expense from 2001 to 2005 in connection with development costs for our GTL and EOR projects, and
	•		reduction in the net losses from 2002 to 2005 for stock based compensation accounted for under the intrinsic value method for U.S. GAAP.

For the U.S. GAAP reconciliations, see Note 23 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,
		(stated in thousands of U.S. dollars, except per share amounts)
		2005				2004				2003				2002				2001
Financial Position
Total assets			224,935				105,791				94,024				91,921				90,219
Shareholders’ equity			188,825				90,892				87,987				85,279				83,113
Results of Operations
Net loss			14,972				19,696				27,086				8,202				36,264
Net loss per share — basic and diluted			0.07				0.12				(0.18				0.06				0.28

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

TABLE OF CONTENTS

		Page
Executive Overview of 2005 Results			23
Financial Results – Year to Year Change in Net Loss			24
Net Operating Revenues			25
General and Administrative			28
Business and Product Development			29
Depletion and Depreciation			30
Net Interest			31
Write-Down of GTL and EOR Investments			31
Impairment of Oil and Gas Properties			32
Liquidity and Capital Resources			32
Contractual Obligations and Commitments			34
Critical Accounting Principles and Estimates			34
Impact of New and Pending Canadian GAAP Accounting Standards			38
Impact of New and Pending U.S. GAAP Accounting Standards			38
Off Balance Sheet Arrangements			39
Related Party Transactions			39

THE FOLLOWING SHOULD BE READ IN CONJUNCTION WITH THE CONSOLIDATED FINANCIAL STATEMENTS INCLUDED IN THIS ANNUAL REPORT ON FORM 10-K. THE CONSOLIDATED FINANCIAL STATEMENTS HAVE BEEN PREPARED IN ACCORDANCE WITH GAAP IN CANADA. THE IMPACT OF SIGNIFICANT DIFFERENCES BETWEEN CANADIAN AND U.S. GAAP ON THE FINANCIAL STATEMENTS IS DISCLOSED IN NOTE 23 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.

NOTE: CANADIAN INVESTORS SHOULD READ THE SPECIAL NOTE TO CANADIAN INVESTORS ON PAGE 14 WHICH HIGHLIGHTS DIFFERENCES BETWEEN OUR RESERVE ESTIMATES AND RELATED DISCLOSURES THAT ARE OTHERWISE REQUIRED BY CANADIAN REGULATORY AUTHORITIES.

Executive Overview of 2005 Results

Although our 2005 results were improved over those a year ago, we were not profitable for the year. Revenue for 2005 increased by 66% or $11.9 million to $29.9 million as a result of a 34% increase in production in China and a 19% production increase in the U. S.

as well as from increased oil and gas prices in both regions. However, this improvement was offset in part by $2.9 million of increased costs related to our business and product development activities, including the operation of our heavy oil RTP^TM CDF and by a $7.0 million increase in depletion and depreciation. We impaired our China oil and gas properties by $5.0 million during 2005 compared to a $16.3 million impairment of our U.S. oil and gas properties in 2004.

Our single goal continues to be to build our oil and gas reserve base and production. In executing this plan, we believe that our most valuable assets are our licensed patented technologies and our employees with their unique technical experience. Our immediate priority is to build on the positive test results achieved at our heavy oil RTP^TM CDF located in the San Joaquin Basin, California and to establish partnerships with owners of heavy oil reserves where we will build, own and operate commercial heavy-to-light oil processing facilities that use our RTP^TM Technology.

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

		Year ended December 31,
		2005				2004				2003
Net loss			13,512				20,725				30,179
Net loss per share			0.07				0.12				0.20
Average annual production (Mboe/d)			1,738				1,376				979
Capital investments			43,301				46,454				15,391
Cash flow (deficit) from operating activities			9,358				4,032				(1,522	)

Financial Results — Year to Year Change in Net Loss

The following provides an analysis of our changes in net losses for the year ended December 31, 2005 when compared to the same period for 2004 and for the year ended December 31, 2004 when compared to the same period for 2003:

		2005 vs.				2004 vs
		2004				2003
Net Losses for 2004 and 2003		$	20,725			$	30,179
Favorable (unfavorable) variances:
Cash Items:
Net Operating Revenues:
Production volumes			4,334				4,534
Oil and gas prices			7,671				3,442
Hedge loss			—				250
Less: Operating costs			(2,530	)			(780	)
			9,475				7,446
General and administrative			(1,589	)			405
Business and product development			(2,893	)			(582	)
Net interest			(881	)			(36	)
Total Cash Variances			4,112				7,233
Non-Cash Items:
Depletion and depreciation			(6,965	)			(3,653	)
Stock based compensation			(837	)			(800	)
Write downs of GTL and EOR investments			(386	)			3,071
Impairment of oil and gas properties			11,350				3,650
Other			(61	)			(47	)
Total Non-Cash Variances			3,101				2,221
Net Losses for 2005 and 2004		$	13,512			$	20,725

Our net loss for 2005 was $13.5 million ($0.07 per share) compared to our net loss in 2004 of $20.7 million ($0.12 per share). The decrease in our net loss from 2004 to 2005 of $7.2 million was due mainly to an $11.4 million reduction in impairment of our U.S. and China oil and gas properties and a $9.5 million increase in net operating revenues. This was partially offset by a $7.0 million increase in depletion and depreciation expense, a $5.3 million increase in general administrative and business and product development expenses including stock based compensation, a $0.9 million net increase in interest and financing costs and a $0.4 million increase in write downs of our GTL and EOR investments.

Our net loss for 2004 was $20.7 million ($0.12 per share) compared to our net loss in 2003 of $30.2 million ($0.20 per share). The decrease in our net loss from 2003 to 2004 of $9.5 million was due mainly to a $3.7 million reduction in impairment of our U.S. oil and gas properties, $3.1 million decrease in write-downs of our GTL investments and a $7.4 million increase in net operating revenues. This was partially offset by a $3.7 million increase in depletion and depreciation expense and a $1.0 million increase in general administrative and business and product development expenses including stock based compensation.

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

Net Operating Revenues

•

Production Volumes 2005 vs. 2004

Net production volumes in 2005 increased 26% from 2004 due to 34% and 19% increases in production volumes in our China and U.S. properties, respectively, resulting in increased revenues of $4.3 million.

China

Net production volumes increased 48% at the Dagang field for 2005. This increase in production volumes accounted for $3.3 million of our increase in revenues for 2005. We placed 22 new wells on production during 2005 bringing to 43 the total number of Dagang wells on production, or available for production. In 2005, we initiated a stimulation program in the northern blocks of the field where we were experiencing less than expected results. We stimulated 13 of our northern block wells and added, on average, incremental production per well of 65 gross Bopd (30 net Bopd), with current production levels of 85 gross Bopd (40 net Bopd) per well. We continue to evaluate production results of other northern block wells to identify additional stimulation candidates. As at December 31, 2005, 39 wells were on production and producing 2,310 gross Bopd (1,080 net Bopd). This is a 40% increase in production rates compared to 1,655 gross Bopd (774 net Bopd) as at December 31, 2004.

Our royalty percentage from the Daqing field was reduced from 4% to 2% in May 2005 when the operator of the properties reached payout of its investment. As a result, our share of production volumes decreased 28% for 2005 compared to the same period in 2004.

U.S.

The 19% increase in U.S. production volumes for 2005 was due mainly to a 286% increase in production at our Knights Landing gas field in northern California. In April 2005, three Knights Landing wells that were drilled and completed in 2004 were connected to a gas sales line and placed on production. As at December 31, 2005, production from the Knights Landing wells had been fully depleted in all but one well, which was producing 12 gross Boe/d (7 net Boe/d) compared to average peak production rates of 411 gross Boe/d (267 net Boe/d) reached in the third quarter of 2005 resulting in a decrease in production volumes of 30.5 gross Mboe (19.9 net Mboe) for the fourth quarter of 2005.

Our production volumes at Citrus for 2005 were up 10% compared to 2004, however, production volumes for the fourth quarter of 2005 were down 7.9 gross Mboe (6.1 net Mboe) from average peak production levels reached in the fourth quarter of 2004 reflecting a natural decline in the wells. As at December 31, 2005, we were producing 77 gross Boe/d (60 Boe/d net) at Citrus compared to 198 gross Boe/d (159 Boe/d net) as at December 31, 2004.

Our production at South Midway increased 7% for 2005 primarily as a result of our continuous steam injection program in the southern expansion of South Midway, which has more than offset the natural decline in production from the wells in the primary section of South Midway. Additionally, in 2005 we drilled one in-fill well in the southern expansion and one successful exploration well adjacent to the primary area of South Midway, which contributed to the increase in production. As at December 31, 2005, we were producing 536 gross Boe/d (499 net Boe/d) at South Midway compared to 542 gross Boe/d (504 net Boe/d) as at December 31, 2004.

The decrease in production volumes in other U.S. properties for 2005 was primarily due to the natural decline in production rates from our Spraberry field in West Texas and as a result of the sale of our interest in the Sledge Hamar property in the fourth quarter of 2004.

We consider LAK Ranch to be a pilot program and as such offset net operating revenues from the field with our capital investment in LAK Ranch. Accordingly, revenues, operating costs and production volumes from LAK Ranch are not included in this analysis.

The following is a comparison of changes in production volumes for the year ended December 31, 2005 when compared to the same period in 2004:

		Years ended December 31,
		Net Boe’s								Percentage
		2005				2004				Change
China:
Dagang			282,582				190,309				48	%
Daqing			32,236				44,626				-28	%
			314,818				234,935				34	%
U.S.:
South Midway			196,428				183,875				7	%
Citrus			34,257				31,008				10	%
Knights Landing			57,106				14,786				286	%
Others			31,883				38,945				-18	%
			319,674				268,614				19	%
			634,492				503,549				26	%

•

Production Volumes 2004 vs. 2003

Net production volumes in 2004 increased 41% from 2003 due to 63% and 26% increases in production volumes in our China and U.S. properties, respectively, resulting in increased revenues of $4.5 million.

China

Net production volumes at the Dagang field increased 46% in 2004 despite the farm-out of 40% of our interest in June 2004. We commenced development of the Dagang field in late 2003 and by the end of 2004 we drilled 19 wells of which 16 were completed and placed on production. As at December 31, 2004, our gross production rate was 1,655 Bopd (774 net Bopd) compared to 505 Bopd at the end of 2003 (236 net Bopd adjusted for a 40% farm-out for comparability to 2004). As at December 31, 2004, a total of 22 wells were producing at our Dagang field. Additionally, we benefited from the expanded Daqing field development program and the royalty interest we retained after the sale of our working interest in this field in 2002 as our royalty share of production increased 224% from 2003.

U.S.

Net production volumes in the U.S. increased 26% in 2004 mainly from the Citrus and Knights Landing fields, both of which started production in 2004, as well as from our development program at South Midway. We farmed into the Knights Landing gas field in northern California in February 2004 with a 50% working interest in 4 producing natural gas wells and in December 2004 improved the potential of our California properties by increasing our working interest to between 80% and 100% in 12 Knights Landing natural gas wells capable of production and selling our interest in the Sledge Hamar field. We are the operator of the Citrus field and have a 100% working interest before payout in three Citrus wells, which were completed and placed on production in 2004. We saw increased production rates from our successful drilling and steaming operations at our South Midway field where we drilled 19 producing wells from 2003 to 2004. As at December 31, 2004, we were producing from 95 wells in the South Midway, Spraberry, Citrus, and Knights Landing fields at gross rates of production of approximately 1,320 Boe/d (920 net Boe/d).

The following is a comparison of changes in production volumes for the year ended December 31, 2004 when compared to the same period in 2003:

		Years ended December 31,
		Net Boe’s								Percentage
		2004				2003				Change
China:
Dagang			190,309				130,651				46	%
Daqing			44,626				13,771				224	%
			234,935				144,422				63	%
U.S.:
South Midway			183,875				169,858				8	%
Citrus			31,008				—				100	%
Knights Landing			14,786				—				100	%
Others			38,945				42,962				-9	%
			268,614				212,820				26	%
			503,549				357,242				41	%

•

Oil and Gas Prices 2005 vs. 2004

Oil and gas prices increased 33% per Boe in 2005 generating $7.7 million in additional revenue as compared to 2004. We realized an average of $49.97 per Boe from our operations in China during 2005, which was an increase of $13.85 per Boe from 2004 prices and accounted for $4.5 million of our increase in revenues. From the U.S. operations, we realized an average of $44.01 per Boe during 2005, which was an increase of $9.35 per Boe and accounted for $3.2 million of our increased revenues.

•

Oil and Gas Prices 2004 vs. 2003

Oil and gas prices increased 32% per Boe in 2004 generating $3.4 million in additional revenue as compared to 2003. We realized an average of $36.11 per Boe from our operations in China during 2004, which was an increase of $7.70 per Boe from 2003 prices and accounted for $1.7 million of our increase in revenues. From the U.S. operations, we realized an average of $34.66 per Boe during 2004, which was an increase of $8.97 per Boe and accounted for $1.7 million of our increased revenues.

We entered into costless collar derivatives to hedge our cash flow from the sale of 500 barrels of oil production per day over two six-month periods starting October 2002 and June 2003. We realized losses of $0.3 million on these derivative transactions in 2003 but had no derivative contracts in place during 2005 or 2004.

•

Operating Costs 2005 vs. 2004

Operating costs for 2005 increased $2.5 million in absolute terms from 2004 or $1.91 on a per Boe basis.

China

Operating costs in China, including engineering support, increased 2% or $0.13 per Boe for 2005. Field operating costs increased $1.45 per Boe or 24% in 2005 primarily due to higher power costs, permanent land fees on producing wells, security costs and increased treatment and processing costs due to higher water production rates. These increases were partially offset by reductions in workover and maintenance costs. Engineering support for 2005 decreased $1.32 per Boe or 63% compared to 2004 resulting from the increase in production volumes from the Dagang field in relation to the level of support required to operate the field.

U.S.

Operating costs in the U.S., including engineering support and production taxes, increased 33% or $3.88 per Boe for 2005. Field operating costs increased $2.50 per Boe for 2005 due mainly to an increase in fuel costs incurred for the cyclic and continuous steam operations at South Midway. For 2005, we spent $3.70 per Boe or 32% of our total U.S. field operating costs for fuel at South Midway compared to $1.71 per Boe or 19% of our total U.S. field operating costs in 2004 as a result of the increase in natural gas prices during 2005. However, these increases in natural gas prices for the steaming operations at South Midway were more than offset by the price increase per barrel of oil received from our South Midway production during 2005 as our net operating revenue at South Midway increased $6.46 per Boe from 2004. In addition, our field operating costs increased $1.10 per Boe for 2005 primarily as a result of workovers at Knights Landing to complete new zones in the existing wells as production from the lower zones depleted. Engineering support increased $0.99 per Boe for 2005 due mainly to the start up of production operations at Knights Landing, where we became the operator in December 2004, and due to the start up of continuous steaming operations in the southern expansion of South Midway. Production taxes were up $0.39 per Boe due mainly to a full year assessment of our property values at Citrus and Knights Landing during 2005 and an increase in ad valorem taxes at South Midway due to a refund received in 2004.

•

Operating Costs 2004 vs. 2003

Operating costs for 2004 increased $0.8 million in absolute terms from 2003 but decreased $1.96 on a per Boe basis.

China

Operating costs in China, including engineering support, decreased 41% or $5.57 per Boe for 2004 due mainly to an increase in production from the Dagang field in relation to the level of fixed field operating costs and engineering support required to operate the field and reduced well workover and power costs during 2004.

U.S.

Operating costs in the U.S., including engineering support and production taxes, increased 8% or $0.89 per Boe for 2004. Field operating costs increased $1.29 per Boe due mainly to an increase in fuel costs incurred for the cyclic steam operations in the southern expansion of South Midway, increased costs to treat hydrogen sulfide levels in the gas produced from the South Midway field and the start up of production operations at our Citrus, Knights Landing, and Sledge Hamar fields. This is partially offset by a reduction in workover costs at our South Midway and Spraberry fields from 2003. Engineering support increased $0.19 per Boe due mainly to the start up of production operations at Citrus, where we are the operator, and also at Knights Landing where we became the operator in December 2004. Production taxes are down $0.59 per Boe due mainly to a retroactive reassessment of property values at South Midway, which led to a refund of prior ad valorem taxes paid and a reduction in assessed values.

Production and operating information including oil and gas revenue, operating costs and depletion, on a per Boe basis, from 2003 to 2005 are detailed below:

		Year ended December 31,
		2005												2004												2003
		U.S.				China				Total				U.S.				China				Total				U.S.				China				Total
Net Production:
Boe			319,674				314,818				634,492				268,614				234,935				503,549				212,820				144,422				357,242
Boe/day for the year			876				863				1,738				734				642				1,376				583				396				979

		Per Boe												Per Boe												Per Boe
Oil and gas revenue		$	44.01			$	49.97			$	46.97			$	34.66			$	36.11			$	35.34			$	25.69			$	28.41			$	26.79
Field operating costs			11.44				7.49				9.48				8.94				6.04				7.59				7.65				9.31				8.52
Production taxes			0.83				—				0.42				0.44				—				0.23				1.03				—				0.62
Engineering support			3.37				0.78				2.08				2.38				2.10				2.25				2.19				4.40				2.89
			15.64				8.27				11.98				11.76				8.14				10.07				10.87				13.71				12.03
Net operating revenue			28.37				41.70				34.99				22.90				27.97				25.27				14.82				14.70				14.76
Depletion			15.53				29.77				22.60				16.80				12.18				14.64				10.58				10.23				10.44
		$	12.84			$	11.93			$	12.39			$	6.10			$	15.79			$	10.63			$	4.24			$	4.47			$	4.32

General and Administrative

Our changes in general and administrative expenses, before and after considering increases in non-cash stock based compensation, for the year ended December 31, 2005 when compared to the same period for 2004 and for the year ended December 31, 2004 when compared to the same period for 2003 were as follows:

		2005 vs.				2004 vs
		2004				2003
Favorable (unfavorable) variances:
Oil and Gas Activities:
China		$	(1,116	)		$	216
U.S.			(188	)			1,119
Corporate			(950	)			(1,730	)
			(2,254	)			(395	)
Less: stock based compensation			665				800
		$	(1,589	)		$	405

	•		General and Administrative 2005 vs. 2004
			China

General and administrative expenses related to the China operations increased $1.1 million for 2005 due to costs incurred associated with financing discussions for our Dagang field development project.

U.S.

General and administrative expenses related to U.S. operations, before allocations to capital and operating costs, increased $1.4 million for 2005 primarily due to increased labor costs, including non-cash stock based compensation of $0.5 million. This is partially offset by increased allocations of general and administrative expenses to capital investments and operating costs of $0.8 million and $0.4 million, respectively, due to the increased levels of administrative support required for our GTL and EOR projects and due to becoming the operator at Knights Landing in December 2004 and the start up of continuous steaming operations in the southern expansion of South Midway in 2005.

Corporate

General and administrative costs related to Corporate activities increased $1.0 million for 2005 due mainly to a $0.6 million increase in labor costs, including non-cash stock based compensation of $0.2 million, and a $0.6 million increase in professional fees incurred in the first half of 2005 to complete our first year of compliance with the provisions of Section 404 of the Sarbanes-Oxley Act of 2002. This is a partially offset by a $0.2 million reduction in premiums for directors and officers liability insurance.

	•		General and Administrative 2004 vs. 2003
			China

General and administrative expenses related to the China operations, before allocations of costs to capital and operating costs, increased $0.4 million primarily due to increased labor costs and ramp up of administrative offices required to support the development and exploration activities initiated at the end of 2003. This is offset by increased allocations of general and administrative costs to capital investments and operating costs of $0.5 million and $0.1 million, respectively, primarily as a result of the development program and increased operations at our Dagang field.

U.S.

General and administrative expenses related to U.S. operations, before allocations to capital and operating costs, increased $0.8 million for 2004 primarily due to increased labor costs, including non-cash stock based compensation. This is offset by increased allocations of general and administrative to capital investments and operating costs of $1.5 million and $0.4 million, respectively, as a result of increased levels of exploration and development activities in the U.S. during 2004 and the start up of production operations at Citrus, where we are the operator, and also at Knights Landing where we became the operator in December 2004.

Corporate

Corporate general and administrative expenses increased $1.7 million mainly due to $0.8 million incurred during 2004 to comply with the provisions of Section 404 of the Sarbanes-Oxley Act of 2002, a $0.8 million increase in non-cash stock based compensation related to the issuance of stock options and other net increases such as higher costs for directors and officers liability insurance.

Business and Product Development

Our changes in business and product development, before and after considering increases in non-cash stock based compensation, for the year ended December 31, 2005 when compared to the same period for 2004 and for the year ended December 31, 2004 when compared to the same period for 2003 were as follows:

		2005 vs.				2004 vs
		2004				2003
Favorable (unfavorable) variances:
GTL		$	164			$	(140	)
EOR			(3,229	)			(442	)
			(3,065	)			(582	)
Less: stock based compensation			172				—
		$	(2,893	)		$	(582	)

•

Business and Product Development 2005 vs. 2004

During 2005, much of the focus of our business and product development activities was on EOR opportunities, particularly related to heavy oil processing, which resulted in a $0.2 million reduction in expenses we incurred related to GTL activities. Of the $3.2 million increase in business and product development expenses for 2005 associated with EOR activities, $1.6 million, including $0.2 million for non-cash stock based compensation, was related to consulting fees and travel costs to develop opportunities for our RTP^TM Technology in the U.S., Canada, Iraq and other countries in the Middle East. In addition, operating expenses of the RTP^TM CDF to develop and identify improvements in the application of the RTP^TM Technology are expensed as part of our business and product development activities and contributed $1.6 million to the increase in business and product development for EOR activities in 2005.

•

Business and Product Development 2004 vs. 2003

We incurred a higher level of business and product development costs during 2004 related to identification of new opportunities for our GTL and heavy oil processing technologies particularly in the Middle East and China resulting in increased business and product development costs of $0.6 million.

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.

•

Depletion and Depreciation 2005 vs. 2004

Depletion and depreciation increased $7.0 million in 2005, $3.8 million of which was due to the increase in depletion rates to $22.60 per Boe in 2005 compared to $14.64 per Boe in 2004 and $3.2 million was due to increased production volumes from 2004.

China

China’s depletion rate for 2005 was $29.77 per Boe compared to $12.18 per Boe for 2004, an increase of $17.59 per Boe resulting in a $4.1 million increase in depletion expense for 2005. Our depletion rate for the fourth quarter of 2005 was $43.76 per Boe compared to $14.33 per Boe for the same period in 2004. These increases were due mainly to two factors:

	•		As noted in prior periodic reports on Form 10Q and in related shareholder communications, we have suspended new drilling activity at our Dagang field in order that we may assess production decline performances on recently drilled wells, as well as maximizing cash flow from these operations. As a result, we have reduced our estimate of the overall development program and our independent engineering evaluators, Gilbert Laustsen Jung and Associates, have revised downward their estimate of our proved reserves as at December 31, 2005.
	•		We impaired the cost of our first Zitong block exploration well, Dingyuan 1, resulting in $12.2 million of those and other associated costs being included with our proved properties and therefore subject to depletion.

Additionally, increases in production volumes in China accounted for $2.4 million of the increase in depletion expense for 2005.

U.S.

The U.S. depletion rate for 2005 was $15.53 per Boe compared to $16.80 per Boe for 2004, a decrease of $1.27 per Boe resulting in a $0.3 million decrease in depletion expense for 2005. Our depletion rate for the fourth quarter of 2005 was $18.01 per Boe compared to $14.96 per Boe for the same period in 2004. Production volume increases in the U.S. resulted in a $0.8 million increase in our depletion expense for 2005.

•

Depletion and Depreciation 2004 vs. 2003

Depletion and depreciation increased $3.7 million in 2004, $1.6 million of which was due to the increase in depletion rates to $14.64 per Boe in 2004 compared to $10.44 per Boe in 2003 and $2.1 million was due to increased production volumes from 2003.

China

The China depletion rate for 2004 was $12.18 per Boe compared to $10.23 per Boe for 2003, an increase of $1.95 per Boe resulting in a $0.3 million increase in depletion expense for 2005. This increase was due mainly to a downward revision of our share of proved reserves at Dagang as a result of continued increases in oil prices from 2003 and additional anticipated increases in future development costs. During periods of increasing oil prices our share of proved oil reserves decreases, as fewer barrels of oil are required to recover our costs under our production-sharing contract with CNPC. Production volume increases in China accounted for $1.1 million of the increase in depletion expense for 2004.

U.S.

The U.S. depletion rate for 2004 was $16.80 per Boe compared to $10.58 per Boe for 2003, an increase of $6.22 per Boe resulting in a $1.3 million increase in depletion expense for 2005. Despite a $16.3 million impairment of our U.S. oil and gas properties in 2004, our depletion rate increased in 2004 primarily as a result of significant costs of finding and acquiring proved reserves at our Knights Landing and Citrus fields as estimated by our independent engineering evaluators, Netherland, Sewell & Associates, as at December 31, 2004. Production volume increases in the U.S. accounted for $1.0 million of the increase in depletion expense for 2004.

Net Interest

•

Net Interest 2005 vs. 2004

In 2005, we borrowed the full amount of a $6.0 million stand-by loan facility, which we arranged in 2004, and amended the loan agreement to provide the lender the right to convert unpaid principal and interest during the loan term to the Company’s common shares. We finalized a second 8% convertible loan agreement with the same lender for $2.0 million. Interest expense and financing costs for 2005 increased $0.8 million in 2005 as a result of these convertible loans. In addition, interest income decreased $0.1 million during 2005.

•

Net Interest 2004 vs. 2003

Our interest expense and financing costs increased $0.2 million for 2004 as a result of a 3% financing fee incurred for a $6.0 million stand-by loan facility with interest at 8% per annum. This increase was mostly offset by an increase in interest income for 2004.

Write-Down of GTL and EOR Investments

As discussed below in this Item 7 in “Critical Accounting Principles and Estimates — Research and Development”, for Canadian GAAP we capitalize technical and commercial feasibility costs incurred for GTL or EOR projects, including studies for the marketability of the projects’ products, subsequent to executing an MOU. 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 GTL and EOR assets. For U.S. GAAP, all such costs are expensed as incurred.

•

Write-Down of GTL and EOR Investments 2005 vs. 2004

In 2005, we wrote down $0.3 million related to our GTL project in Bolivia and $0.3 million related to our MOU with Ecopetrol for the ‘Llanos Heavy Basin Crude Project’. We wrote down our investment in the GTL project in Bolivia due to the impact that political and fiscal uncertainty in Bolivia could have on the viability of a GTL plant and our investment in the MOU with Ecopetrol as our Company did not meet the company-size requirements specified by Ecopetrol in their final bidding qualifications for the ‘Llanos Basin Heavy Crude Project’, which included the Castilla and Chichimene field developments. This compares to the write down of $0.3 million in 2004 for our investment in the Oman GTL project.

•

Write-Down of GTL and EOR Investments 2004 vs. 2003

In 2004, we wrote down our $0.3 million investment in the Oman GTL project as our opportunity to build a 45,000-barrel per day GTL fuels plant in Oman failed to materialize due to a lack of sufficient committed gas volumes. This compares to the $3.3 million write-down of our GTL investments in connection with negotiation costs incurred to construct and operate a GTL production facility

in Qatar, which was terminated in 2003 without reaching a definitive agreement.

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 2005 vs. 2004

We impaired our China oil and gas properties by $5.0 million in 2005, compared to a $16.3 million impairment of our U.S. oil and gas properties in 2004. As a result of production decline performance and drilling results from the wells drilled in the northern blocks of the Dagang field, we reduced our estimate of the overall field development program and our independent engineering evaluators, Gilbert Laustsen Jung and Associates, have revised downward their estimate of our proved reserves as at December 31, 2005. Additionally, we impaired 70% of our costs incurred in the Zitong block due to an unsuccessful first exploration well resulting in those costs, equal to $12.2 million, being included with the carrying value of proved properties for the ceiling test calculation.

As a result of the unsuccessful test of the Northwest Lost Hills # 1-22 well in January 2006, we fully evaluated the Northwest Lost Hills prospect as at December 31, 2005 resulting in an addition of $8.9 million to the carrying value of our U.S. cost center for the ceiling test calculation. However, no impairment of our U.S. oil and gas properties was required in 2005 for Canadian GAAP purposes.

•

Impairment of Oil and Gas Properties 2004 vs. 2003

We impaired our U.S. oil and gas properties by $16.3 million in 2004, compared to an impairment of $20.0 million in 2003. The impairment for 2004 is due to an evaluation of a number of our proved properties at the Knights Landing, Citrus and South Midway fields, and a further impairment of our unproved properties, primarily Northwest Lost Hills.

At the Knights Landing gas field, our 2004 drilling resulted in three successful completions and six dry holes. We plan to use 3-D seismic to improve the discovery rate in this field when we resume drilling in 2006. The impairment of our Northwest Lost Hills prospect reflected the farm-out of a portion of our working interest to fund a test of the well, which was completed unsuccessfully in 2006.

No impairment of our China oil and gas properties was required in 2004 for Canadian GAAP purposes.

Liquidity and Capital Resources

Sources and Uses of Cash

Our net cash and cash equivalents decreased by $2.6 million for the year ended December 31, 2005 compared to a decrease of $5.2 million and an increase of $10.5 million for the same periods in 2004 and 2003, respectively.

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Operating Activities

Our operating activities provided $9.4 million in cash for the year ended December 31, 2005 compared to $4.0 million provided by operating activities for the same period in 2004 and $1.5 million used by operating activities for the same period in 2003. The increases in cash from operating activities for the years ended December 31, 2005 and 2004 were mainly due to increases in net production volumes of 26% and 41%, respectively, and increases in oil and gas prices of 33% and 32%, respectively. The increases in net revenues for the years ended December 31, 2005 and 2004 were partially offset by increases of $4.5 million and $0.2 million, respectively, in general and administrative and business and product development expenses, excluding stock based compensation, and a $0.8 million increase in interest expense and financing costs for the year ended December 31, 2005 when compared to the same period in 2004.

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Investing Activities

Our investing activities used $51.1 million in cash for the year ended December 31, 2005 compared to $34.7 million used in investing activities for the same period in 2004. For the year ended December 31, 2005, compared to the same period in 2004, we spent $13.5 million more on the Merger, which was completed in April 2005, and we advanced $1.2 million during 2005 under a consultancy agreement. In addition, we had no sales of assets for the year ended December 31, 2005 compared to $14.0 million of cash generated

from asset sales in China for the comparable period in 2004. These increases in our investing activities for the year ended December 31, 2005 were partially offset by an $11.9 million decrease in cash required for our capital investment activities for 2005 when compared to the same period in 2004, which was mainly due to an $8.8 million increase in our non-cash working capital associated with our investing activities.

For the year ended December 31, 2004, we used $27.3 million more in cash for capital investment activities and $4.5 million more on Merger related activities than for the comparable period in 2003. This was partially offset by $14.0 million of cash generated from asset sales in China for the year ended December 31, 2004 when compared to the same period in 2003.

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Financing Activities

Our financing activities provided $39.2 million in cash for the year ended December 31, 2005 compared to $25.4 million of cash provided by financing activities for the comparable period in 2004. We closed three special warrant financings by way of private placements during the year ended December 31, 2005 and issued 13.8 million common shares for net proceeds of $26.7 million compared to two special warrant financings by way of private placements for the year ended December 31, 2004 and issued 7.2 million common shares for $20.4 million. 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 – See Item 5 of this Annual Report on Form 10-K, “Sales of Unregistered Securities”. We generated $4.5 million more from the exercise of stock options and common share purchase warrants for the year ended December 31, 2005 compared to the same period in 2004.

We generated $6.3 million in cash from net debt financing for the year ended December 31, 2005 compared to $3.3 million in cash for the same period in 2004. For the year ended December 31, 2005, we received $8.0 million from two convertible loans, $4.0 million of which was refinanced in November 2005 by the issuance of 2.5 million common shares. For the year ended December 31, 2004, we received $4.0 million from our bank loan facility to develop the southern expansion of South Midway. For the years ended December 31, 2005 and 2004 we made principal payments on our bank loan of $1.7 million and $0.7 million, respectively.

For the year ended December 31, 2004, we generated $3.0 million less in cash from financing activities than for the comparable period in 2003. We closed three special warrant financings by way of private placements during the year ended December 31, 2003 and issued 12.7 million common shares for net proceeds of $24.1 million compared to two special warrant financings by way of private placements for the year ended December 31, 2004 and issued 7.2 million common shares for $20.4 million. We generated $2.2 million more from the exercise of stock options and common share purchase warrants for the year ended December 31, 2003 compared to the same period in 2004. This is partially offset by $3.3 million in net proceeds received from our bank loan facility to develop the southern expansion of South Midway for the year ended December 31, 2004 compared to the same period in 2003.

		Year ended December 31,
		2005				2004				2003
Cash flow (deficit) from operating activities		$	9,358			$	4,032			$	(1,522	)
Investing Activities
Capital investments, after changes in non-cash working capital			(31,279	)			(43,190	)			(15,928	)
Merger, net of working capital			(10,096	)			—				—
Equity investment and Merger related costs			(8,462	)			(5,016	)			(500	)
Proceeds from sale of assets			—				13,958				—
Advance payments			(1,200	)			—				—
Other			(78	)			(410	)			(37	)
			(51,115	)			(34,658	)			(16,465	)
Financing Activities
Proceeds from private placements, net of all share issue costs			26,578				20,428				24,070
Proceeds from exercise of options and purchase warrants			6,248				1,723				3,928
Net debt financing			6,333				3,306				500
			39,159				25,457				28,498
Net Sources (Uses) of Cash		$	(2,598	)		$	(5,169	)		$	10,511

Outlook for 2006

Our capital investment budget for 2006 is $37.4 million. Approximately 60% of our 2006 capital investment budget is for oil and gas exploration and development activities, primarily in the U.S, where we plan to drill 23 development wells and 15 exploration wells. In China, we plan to drill three development wells at the Dagang field and one exploration well in the Zitong block during 2006. The remaining 40% of our capital investment budget is split evenly between GTL and EOR, including heavy oil processing activities. If

we are successful in negotiating a definitive agreement for a GTL plant in Egypt as well as for one or more RTP^TM Plants in North America, we will commence with front-end engineering and design activities in 2006.

We incurred a net loss of $13.5 million for the year ended December 31, 2005, and, as at December 31, 2005, had an accumulated deficit of $95.3 million and negative working capital of $11.4 million. We plan to finance approximately 50% of our 2006 capital investment budget with cash generated from operations but this will not be sufficient to satisfy our current obligations and meet our capital investment objectives. Our plans include the sale of additional equity securities, alliances or other partnership agreements with entities with the resources to support our projects as well as convertible loan, debt and mezzanine financing in order to generate sufficient resources to assure continuation of our operations and achieve our capital investment objectives. We continue active negotiation with a third party for the formation of a joint venture for the deployment, in a specific region of the world, of the GTL and RTP™ technologies we license or own. The transaction that is being discussed would, if consummated, include a potentially significant equity investment in Ivanhoe by the third party. No assurances can be given that we and the third party with whom we are presently negotiating will successfully conclude this potential transaction nor that we will be able to raise additional capital or enter into one or more alternative business alliances with other parties if this potential transaction is not successfully concluded. If we are unable to obtain adequate additional financing or enter into such business alliances, we will be required to sharply curtail our operations, which may include the sale of assets.

Contractual Obligations and Commitments

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

		Payments Due by Year
		(stated in thousands of U.S. dollars)
		Total				2006				2007				2008				2009				After 2009
Purchase Agreement:		$	100			$	100			$	—			$	—			$	—			$	—
Consolidated Balance Sheet:
Note payable – current portion (Note 7)			1,667				1,667				—				—				—				—
Long term debt (Note 7)			4,972				—				4,972				—				—				—
Asset retirement obligations (Note 8)			1,780				950				100				—				—				730
Long term obligation (Note 9)			1,900				—				1,900				—				—				—
CITIC note payable (Note 22)			7,386				2,050				2,460				2,460				416				—
Other Commitments:							—				—				—				—				—
Interest payable (1)			762				458				304				—				—				—
Lease commitments (Note 9)			2,287				763				608				461				287				168
Zitong exploration commitment (Note 9)			4,300				4,300				—				—				—				—
Total		$	25,154			$	10,288			$	10,344			$	2,921			$	703			$	898