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, 2006

OR

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

For the transition period from _______ to _______

IVANHOE ENERGY INC.

(Exact name of registrant as specified in its charter)

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

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

Securities registered pursuant to Section 12(b) of the Act:

None

Securities registered pursuant to Section 12(g) of the Act:

Title of each class		Name of each exchange on which registered
Common Shares, no par value		Toronto Stock Exchange NASDAQ Capital Market

     Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

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 (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act (Check one).

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, 2006, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $590,875,805 based on the average bid and asked price as reported on the National Association of Securities Dealers Automated Quotation System National Market System.

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

Class		Outstanding at March 8, 2007
Common Shares, no par value		241,254,394 shares

DOCUMENTS INCORPORATED BY REFERENCE
None

 

 

TABLE OF CONTENTS

		Page
PART I
Items 1 and 2 Business and Properties
General			4
Corporate Strategy			4
Heavy to Light Oil Upgrading Technology			5
Gas-to-Liquids Technology			6
Oil and Gas Properties			7
Employees			9
Reserves, Production and Related Information			9
Item 1A Risk Factors			11
Item 1B Unresolved Staff Comments			15
Item 3 Legal Proceedings			15
Item 4 Submission of Matters to a Vote of Security Holders			15
PART II
Item 5 Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchase of Equity Securities			16
Item 6 Five Year Summary of Selected Financial Data			18
Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations			19
Item 7A Quantitative and Qualitative Disclosures About Market Risk			38
Item 8 Financial Statements and Supplementary Data			39
Item 9 Changes In and Disagreements with Accountants on Accounting and Financial Disclosure			77
Item 9A Controls and Procedures			77
Item 9B Other Information			79
PART III
Item 10 Directors, Executive Officers and Corporate Governance			79
Item 11 Executive Compensation			81
Item 12 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			88
Item 13 Certain Relationships and Related Transactions, and Director Independence			89
Item 14 Principal Accounting Fees and Services			89
PART IV
Item 15 Exhibits and Financial Statement Schedules			91

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:

		2006				2005				2004				2003				2002
Closing		$	0.86			$	0.86			$	0.83			$	0.77			$	0.63
Low		$	0.85			$	0.79			$	0.72			$	0.63			$	0.62
High		$	0.91			$	0.87			$	0.85			$	0.77			$	0.66
Average Noon		$	0.88			$	0.83			$	0.77			$	0.71			$	0.63

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, 2007 was $ 0.85 ($1.00 = Cdn.$1.17).

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; uncertainties regarding the potential success of heavy-to-light oil upgrading and gas-to-liquids technologies; uncertainties regarding the potential success of our oil and gas exploration and development properties in the U.S. and China; oil price volatility; oil and gas industry operational hazards and environmental concerns; government regulation and requirements for permits and licenses, particularly in the foreign jurisdictions in which we carry on business; title matters; risks associated with carrying on business in foreign jurisdictions; conflicts of interests; competition for a limited number of what appear to be promising oil and gas exploration properties from larger more well financed oil and gas companies; and other statements contained herein regarding matters that are not historical facts. Forward-looking statements can often be identified by the use of forward-looking terminology such as “may”, “expect”, “intend”, “estimate”, “anticipate”, “believe” or “continue” or the negative thereof or variations thereon or similar terminology. We believe that any forward-looking statements made are reasonable based on information available to us on the date such statements were made. However, no assurance can be given as to future results, levels of activity and achievements. 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 United States Securities and Exchange Commission’s website at http://www.sec.gov/.

ITEMS 1 AND 2 BUSINESS AND PROPERTIES

GENERAL

Ivanhoe Energy is an independent international heavy oil development and production company focused on pursuing long-term growth in its reserve base and production.

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

We were incorporated pursuant to the laws of the Yukon Territory of Canada, on February 21, 1995 under the name 888 China Holdings Limited. On June 3, 1996, we changed our name to Black Sea Energy Ltd., and on June 24, 1999, we changed our name to Ivanhoe Energy Inc.

Our principal executive office is located at Suite 654 — 999 Canada Place, Vancouver, British Columbia, V6C 3E1, and our registered and records office is located at 300-204 Black Street, Whitehorse, Yukon, Y1A 2M9. Our headquarters for operations are located at Suite 400 – 5060 California Avenue, Bakersfield, California, 93309.

CORPORATE STRATEGY

Importance of the Heavy Oil Segment of the Oil and Gas Industry

The global oil and gas industry is operating near capacity, driven by sharp increases in demand from developing economies and the declining availability of replacement low cost reserves. This has resulted in a significant increase in the relative price of oil and marked shifts in the demand and supply landscape. These shifts include demand moving toward China and India, while supply has shifted towards the need to develop higher cost/lower value resources, including heavy oil and bitumen.

Heavy oil developments can be segregated into two types: conventional heavy oil which flows to the surface without steam enhancement and non-conventional heavy oil and bitumen. While we focus on the heavier non-conventional heavy oil, both are playing an important role in creating opportunities for Ivanhoe.

Production of conventional heavy oil has been steadily increasing worldwide, led by Canada and Latin America but with significant contributions from most oil basins, including the Middle East and the Far East, as producers struggle to replace declines in light oil reserves. Even without the impact of the large non-conventional heavy oil projects in Canada and Venezuela, world oil production has been getting heavier. Refineries, on the other hand, have not been able to keep up with the need for deep conversion capacity, and heavy-light price differentials have widened significantly.

With regard to non-conventional heavy oil and bitumen, the dramatic increase in interest and activity has been fueled by higher prices, in addition to various key advances in technology, including improved remote sensing, horizontal drilling, and new thermal techniques. This has enabled producers to much more effectively access the extensive, heavy oil resources around the world.

These newer technologies, together with firm oil prices, have generated increased access to heavy oil resources, although for profitable exploitation, key challenges remain, with varied weightings, project by project: 1) the requirement for steam and electricity to help extract heavy oil, 2) the need for diluent to move the oil once it is at the surface, and 3) the wide heavy-light price differentials that the producer is faced with when the product gets to market. These challenges can lead to “distressed” assets, where economics are poor, or to “stranded” assets, where the resource cannot be economically produced and lies fallow.

Ivanhoe’s Value Proposition

Ivanhoe’s application of the patented rapid thermal processing process (“RTP^TM Process”) for heavy oil upgrading (“HTL Technology” or “HTL”) seeks to address the three key heavy oil development challenges outlined above, and can do so at a relatively small scale.

In addition to improving oil quality, an HTL facility can yield surplus energy for production of the steam and electricity used in heavy oil production. The thermal energy generated by the HTL process can provide heavy oil producers with an alternative to increasingly volatile prices for natural gas that now is widely used to generate steam. Test yields of the low-viscosity, upgraded product are greater than 85% by volume, and high conversion of the heavy residual fraction is achieved. In addition to the liquid upgraded oil product, a small amount of valuable by-product gas is produced, and usable excess heat is generated from the by-product coke.

Ivanhoe’s HTL process offers three potential advantages in that it can virtually eliminate cost exposure to natural gas and diluent, solve the transport challenge, and capture the majority of the heavy to light oil price differential for oil producers. Testing indicates that Ivanhoe’s HTL process can accomplish this at a much smaller scale and at lower per barrel capital cost compared with established competing technologies, using readily available plant and process components. Since HTL facilities will be designed for installation near the wellhead, they are expected to eliminate the need for diluent and may make large, dedicated upgrading facilities unnecessary.

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

The economics of a project are effectively dictated by the advantages that HTL can bring to a particular opportunity. The more stranded the resource and the fewer monetization alternatives that the resource owner has, the greater the opportunity the Company will have to establish the Ivanhoe value proposition.

Implementation Strategies

In order to capture the value that our HTL Technology provides, the Company is pursuing the following strategies:

	1.		Build a portfolio of major HTL projects. We will continue to deploy our personnel and our financial resources in support of our goal to capture opportunities for development projects utilizing our HTL technology.
	2.		Advance the technology. Additional development work will continue as we advance the technology through the first commercial application and beyond.
	3.		Enhance our financial position in anticipation of major projects. Implementation of large projects requires significant capital outlays. We are refining our financing plans and establishing the relationships required for the development activities that we see ahead.
	4.		Build internal capabilities in advance of major projects. The HTL technical team, which includes our own staff, specialized consultants including the inventors of the technology, and our enhanced oil recovery (“EOR”) team will be supplemented and expanded to add additional expertise in areas such as project management.
	5.		Build the relationships that we will need for the future. Commercialization of our technologies demands close alignment with partners, suppliers, host governments and financiers.
	6.		Capture value from other company assets as we complete the transition to a heavy oil focused company. Revenue from existing operations in California and China will be utilized to fund growth of the business. Non-heavy oil related investment opportunities in our portfolio will be leveraged to capture value and provide maximum return for the company.

HEAVY TO LIGHT OIL UPGRADING TECHNOLOGY

RTP^TM License and Patents

In April 2005, we acquired all the issued and outstanding common shares of Ensyn Group, Inc. (“Ensyn”) whereby we acquired an exclusive, irrevocable license to Ensyn’s RTP^TM Process for all applications other than biomass. In January 2007 the Company received a Notice of Allowance from the U.S. Patent Office for the first of a family of additional petroleum upgrading patent applications. Since Ivanhoe acquired the patented heavy oil upgrading technology it has been working to expand patent coverage to protect innovations to the HTL Technology as they are developed. This allowance is the first patent protection that has been granted directly to Ivanhoe Energy, and significantly broadens the Company’s portfolio of HTL intellectual property for petroleum upgrading and opens up additional HTL patenting opportunities for Ivanhoe Energy.

Commercial Demonstration Facility

In 2004, Ensyn constructed a Commercial Demonstration Facility (“CDF”) to confirm earlier pilot test results on a larger scale and to test certain processing options. This facility, that the Company acquired as part of the Ensyn merger was built in the Belridge field, a large heavy oil field owned by Aera Energy LLC, a company owned by affiliates of ExxonMobil and Shell. In March 2005, initial performance testing of the CDF was completed successfully and the results of the test were verified by two large independent engineering consulting firms. The 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.

The CDF test runs to date have successfully demonstrated that product upgraded by the CDF compares favorably to test runs carried out at Ensyn’s pilot facility. We will continue to test 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. In addition, we have validated a number of process enhancements during the CDF test program including flue gas de-sulphurization, heavy metals capture and crude acidity reduction. One of the other continuing objectives of the CDF will be to provide engineering information for the scale-up of the plant to anticipated commercial levels.

In January 2007, the company completed a significant run at its CDF. This run, the most successful to date, was the culmination of a multi-month program that included tailoring the CDF for the processing of heavy crude fractions in configurations matched to specific commercial opportunities that the Company has identified. This run processed California vacuum tower bottoms (“VTBs”), which are the heaviest component of California heavy oil. These VTBs, which are solid at room temperature, are heavier and more viscous than Athabasca bitumen that is found in the Canadian oil sands.

This test run, performed using a High Yield, or “once through” configuration, follows a program of enhancements to the CDF. The run confirmed these enhancements and was also geared to the generation of information related to certain new commercial configurations that the company has developed in recent months. These new configurations were developed in the context of commercial opportunities and are the result of extensive analysis of data from prior runs carried out by the Company’s technical team as well as outside experts in process engineering and upgrading technology. We believe these new configurations may represent a simple and cost effective alternative for the processing of some of the more challenging heavy crudes around the world. The Company will continue to pursue these innovative configurations in forthcoming tests and analyses.

HTL Business Development

We are pursuing HTL business development opportunities around the world.

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 have completed the reservoir assessment and have evaluated various recovery methods. Facility design work is complete and we completed an economic evaluation in the third quarter of 2006. Based on this evaluation we submitted a technical proposal to the Iraq Ministry of Oil. We have since presented the results of the technical proposal to an Iraqi team of experts and are currently responding to their questions. We will offer a commercial proposal for the development of the Qaiyarah oil field subsequent to satisfying all of the Oil Ministry’s questions. The Iraq Ministry of Oil is under no obligation to execute the project or to enter into formal commercial negotiations.

GAS-TO-LIQUIDS TECHNOLOGY

Syntroleum License

We own a non-exclusive master license entitling us to use Syntroleum Corporation’s (“Syntroleum”) proprietary technology (“GTL Technology” or “GTL”) to convert natural gas into ultra clean transportation fuels and other synthetic petroleum products in an unlimited number of projects with no limit on production volume. Syntroleum’s proprietary GTL process is designed to catalytically convert natural gas into synthetic liquid hydrocarbons. This patented process uses compressed air, steam and natural gas as initial components to the catalyst process. As a result, this process (the “Syntroleum Process^TM”) substantially reduces the capital and operating costs and the minimum economic size of a GTL plant as compared to the other oxygen-based GTL technologies. Competitor GTL processes use either steam reforming or a combination of steam reforming and partial oxidation with pure oxygen. A steam reformer and an air separation plant necessary for oxidation are expensive and considered hazardous and increase operating costs.

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

GTL Business Development

At the present time, we are not actively pursing any GTL projects other than the Egyptian GTL project described herein. In 2005, we signed a memorandum of understanding with Egyptian Natural Gas Holding Company (“EGAS”), the state organization responsible for managing Egypt’s natural gas resources, to prepare a feasibility study to construct and operate a GTL plant that would convert natural gas to ultra-clean liquid fuels in Egypt. We completed an engineering design of a GTL plant to incorporate the latest advances in Syntroleum GTL technology and have completed market and pricing analysis for GTL products to reflect changes since the original evaluation was completed several years ago. Plant capacity options of 47,000 and 94,000 Bbls/d were evaluated and in May 2006, we presented the feasibility study report to EGAS along with three commercial proposals. Based on EGAS’ review, and response to the proposals, we submitted a revised proposal in October 2006. EGAS will agree to commit, at no cost to the project, up to 4.2 trillion cubic feet of natural gas, or approximately 600 MMcf/d for the anticipated 20-year operating life of the project, subject to EGAS completing an economic feasibility analysis of the GTL project for Egypt, the negotiation and signature of a mutually agreeable term sheet and subsequently a definitive agreement and approval by the Company’s Board of Directors and the appropriate authorities in Egypt.

OIL AND GAS PROPERTIES

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

United States

•

Production and Development

          South Midway

We currently have 59 producing wells in South Midway and are the operator, with a working interest of 100% and a 93% net revenue interest. In 2006, we drilled ten new wells on the South Midway properties compared to 2005 when we drilled one development well, two temperature observation wells and one exploratory well. The ten new wells are producing 150 gross Bopd. Three wells in this program were drilled to test for pool extensions or new pool discoveries. Two extensions were found which will lead to more development work and potential reserves.

In the southern expansion area of South Midway, we have supplemented the cyclic steam project with a pilot to test continuous steam injection into five 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. This could add additional probable reserves to our proved undeveloped reserves. The Company should be able to make an assessment as to whether this continuous steam injection was successful by the fourth quarter of 2007. Current production from the southern expansion area is approximately 150 gross Bopd and total South Midway production is approximately 590 gross Bopd.

          Other

In 2000, we farmed into the Spraberry property, which is a producing property located on 2,500 gross acres in the Spraberry Trend of the West Texas Permian Basin in Midland County, Texas. After selling a portion of our working interest in 2002 for approximately $3 million, we retain working interests ranging from 31% to 48% in 25 wells, which are currently producing approximately 80 net Boe/d. The declines of the oil and gas rates in this West Texas position should be very moderate over time. The moderate declines should lead to consistent performance and long life reserves.

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. The initial well resulted in a dry hole. In 2005, a second prospect, North Salt Creek #1, was drilled to 2,500 feet on the acreage and was a discovery, encountering 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. Each of these wells were steamed, the results of which were sub economic. One of the intervals is in a diatomite formation which has a large amount of oil in place. This interval will be tested in another well to be drilled in 2007. More steam stimulation of this diatomite interval will occur in 2007 with the view that successive steam cycles will provide commercial rates of production.

In the first quarter of 2006, we sold our working interest in our three producing wells in the Citrus prospect for $5.4 million. We still

hold 2,316 net acreage in this prospect, all of which has been farmed out. As part of this farm out the Company retained a carried 35% working interest in two wells that are expected to be drilled in 2007 to a depth of 5,000 feet. This farm out contemplates up to four wells, and we would retain a 20% working interest in the other two wells that would be drilled to a depth of 9,500 feet.

•

Exploration

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

          Knights Landing

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

In late 2005, we acquired a 3-D seismic data program over 25 square miles covering our Knights Landing acreage block. We completed our seismic acquisition program in December 2005 and completed processing and interpretation of the seismic data in 2006. We expect to recommence drilling in the third quarter of 2007. 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.

          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.

          Other

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. The well did not produce commercial quantities of hydrocarbons during several tests and has been suspended indefinitely by the operator. In March 2007, the Company assigned its rights to this property for $1.0 million and retained a carried 15% working interest in future drilling of the prospect.

China

•

Production and Development

Our producing property in China is a 30-year production-sharing contract with China National Petroleum Corporation (“CNPC”), covering an area of 12,110 gross acres divided into four blocks in the Kongnan oilfield in Dagang, Hebei Province, China (the “Dagang field”). Under the contract, as operator, we fund 100% of the development costs to earn 82% of the net revenue from oil production until cost recovery, at which time our entitlement reverts to 49%. Our entire interest in the Dagang field will revert to CNPC at the end of the 20-year production phase of the contract or if we abandon the field earlier.

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

During 2001, we completed the pilot phase and in 2002 submitted the final draft of our Overall Development Plan (“ODP”) to the Chinese regulatory authorities for approval. Final government approval was obtained in April 2003, after which the development phase commenced in late 2003. By the end of 2006, we had drilled a total of 39 development wells, as compared to the estimated 115 wells set out in the approved ODP. We suspended drilling in late 2005 to allow for detailed evaluation of well productivity and production decline performance. In the fourth quarter of 2006, we reached agreement with CNPC to reduce the overall scope of the ODP to approximately 44 wells.

The year-end 2006 gross production rate was 1,877 Bopd compared to 2,310 Bopd at the end of 2005. We currently sell our crude oil at a three-month rolling average price of Cinta crude currently averaging approximately $3.00 per barrel less than West Texas Intermediate (“WTI”) price. During 2006 we completed 1 well drilled in 2005, fracture stimulated 12 wells and re-completed 13 wells. In addition, we relinquished 2 of the six blocks that were part of the original development plan.

•

Exploration

In November 2002, we received final Chinese regulatory approval for a 30-year production-sharing contract (the “Zitong Contract”), with CNPC for the Zitong block, which covers an area of approximately 900,000 acres in the Sichuan basin. Under the Zitong Contract, we agreed to conduct an exploration program on the Zitong block consisting of two phases, each three years in length. The parties will jointly participate in the development and production of any commercially viable deposits, with production rights limited to a maximum of the lesser of 30 years following the date of the Zitong Contract or 20 years of continuous production.

In the second quarter of 2005, we drilled our first well, 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. In October 2006, the Company commenced drilling a second exploration well which is being drilled to a target depth of 12,800 feet. The completion and testing of the well is anticipated the second quarter 2007.

In 2006, we farmed-out 10% of our working interest in the Zitong block to Mitsubishi Gas Chemical Company Inc. of Japan (“Mitsubishi”) for $4.0 million. Mitsubishi has the option to increase its participating interest to 20% by paying $0.4 million plus costs per percentage point prior to any discovery, or $8.0 million plus costs for an additional 10% interest after completion and testing of the first well drilled under the farm-out agreement. The Company and Mitsubishi (the “Zitong Partners”) will await the results of the second exploration well after which a decision will be made whether or not to enter into the next three-year exploration phase (“Phase 2”). The $4.0 million advance from Mitsubishi was used to pay for the initial well costs and there was no unspent balance at December 31, 2006. If the Company elects not to enter into Phase 2, it will be required to pay CNPC, within 30 days after its election, a cash equivalent of its share of the deficiency in the work program estimated to be $0.3 million after the drilling of the second Phase 1 well. If the Company elects not to enter Phase 2, costs related to the Zitong block in the approximate amount of $8.3 million will be required to be included in the depletable base of the China full cost pool. This may result in a ceiling test impairment related to the China full cost pool in a future period.

If the Zitong Partners elect to participate in Phase 2, they must complete a minimum work program involving the acquisition of approximately 200 miles of new seismic lines, which was satisfied in the Phase 1 expenditures, and approximately 23,000 feet of drilling, with estimated minimum expenditures for the program of $21.6 million excluding seismic acquisition. Following the completion of Phase 2, we must relinquish all of the property except any areas identified for development and production. If the Zitong Partners elect to enter into Phase 2, they 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.

EMPLOYEES

As at December 31, 2006, we had 150 employees and consultants actively engaged in the business. 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
		2006				2005				2004				2006				2005				2004
Crude Oil and Natural Gas ($/Boe)
U.S.		$	54.86			$	44.01			$	34.66			$	19.54			$	15.64			$	11.76
China		$	62.04			$	49.97			$	36.11			$	20.58			$	8.27			$	8.14

The following table sets forth the number of commercially productive wells (both producing wells and wells capable of production) in which we held a working interest at the end of each of the last three fiscal years. Gross wells are the total number of wells in which a working interest is owned and net wells are the sum of fractional working interests owned in gross wells.

		2006																2005																2004
		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.			89				73.5				2				1.0				87				69.3				3				1.5				84				67.2				13				11.7
China			42				34.4	(1)			—				—				43				21.2				—				—				21				10.3	(1)			—				—

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

Exploratory

		Productive Wells																								Dry Wells
		2006								2005								2004								2006								2005								2004
		Oil				Gas				Oil				Gas				Oil				Gas				Oil				Gas				Oil				Gas				Oil				Gas
U.S.			—				—				1.5				0.2				0.4				3.0				0.6	(1)			—				—				1.8	(2)			1.4				4.0
China			—				—				—				—				—				—				—				—				—				1.0				—				—
Total			—				—				1.5				0.2				0.4				3.0				0.6				—				—				2.8				1.4				4.0

Development

		Productive Wells																								Dry Wells
		2006								2005								2004								2006								2005								2004
		Oil				Gas				Oil				Gas				Oil				Gas				Oil				Gas				Oil				Gas				Oil				Gas
U.S.			9.0				—				1.0				—				7.3				—				—				—				—				—				2.0				—
China			—				—				10.8				—				7.9				—				—				—				—				—				—				—
Total			9.0				—				11.8				—				15.2				—				—				—				—				—				2.0				—

Wells in Progress

At the end of 2006, 2005 and 2004 we had 5.3 (6 gross), 1.1 (3 gross) and 2.9 (6 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, 2006. 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.			7,691				4,428				96,672				29,373
China (1)			2,969				2,435				888,924				883,306

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, 2006. Estimates for our U.S. and China operations were prepared by independent petroleum consultants Netherland, Sewell & Associates Inc. and GLJ Petroleum Consultants 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.			1,220				417			$	30,420			$	23,088			$	20,711			$	30,420			$	23,088			$	20,711
China			1,785				—				53,497				42,792				38,887				53,497				42,792				38,887
			3,005				417			$	83,917			$	65,880			$	59,599			$	83,917			$	65,880			$	59,599

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 SEC disclosure requirements. In 2003, certain Canadian securities regulatory authorities adopted National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) which prescribes certain standards that Canadian companies are required to follow in the preparation and disclosure of reserves and related information. We applied for, and have been granted, exemptions from certain NI 51-101 disclosure requirements. These exemptions permit us to substitute disclosures based on SEC requirements for much of the annual disclosure required by NI 51-101 and to prepare our reserves estimates and related disclosures in accordance with SEC requirements, generally accepted industry practices in the U.S. as promulgated by the Society of Petroleum Engineers, and the standards of the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”) modified to reflect SEC requirements.

The reserves quantities disclosed in this Annual Report on Form 10-K represent net proved reserves calculated on a constant price basis using the standards contained in SEC Regulation S-X and Statement of Financial Accounting Standards No. 69, “Disclosures About Oil and Gas Producing Activities”. Such information differs from the corresponding information prepared in accordance with Canadian disclosure standards under NI 51-101. The primary differences between the SEC requirements and the NI 51-101 requirements are as follows:

	•		SEC registrants apply SEC reserves definitions and prepare their reserves estimates in accordance with SEC requirements and generally accepted industry practices in the U.S. whereas NI 51-101 requires adherence to the definitions and standards promulgated by the COGE Handbook;
	•		the SEC mandates disclosure of proved reserves calculated using year-end constant prices and costs only whereas NI 51-101 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 SEC disclosure requirements and NI 51-101 requirements.

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 may not be able to meet our substantial capital requirements.

Our business is capital intensive and the advancement of either our HTL or GTL project development initiatives will require significant investments in property acquisitions and development activities. Since our revenues from existing operations are insufficient to fund the capital expenditures that will be required to implement our HTL and GTL project development initiatives, we

will need to rely on external sources of financing to meet our capital requirements. We have, in the past, relied upon equity capital as our principal source of funding. We may seek to obtain the future funding we will need through debt and equity markets, through project participation arrangements with third parties or from the sale of existing assets, 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. If we fail to obtain the funding that we need when it is required, we may have to forego or delay potentially valuable project acquisition and development opportunities or default on existing funding commitments to third parties and forfeit or dilute our rights in existing oil and gas property interests. Our limited operating history may make it difficult to obtain future financing.

We might not successfully commercialize our technology, and commercial-scale HTL and GTL plants based on our technology may never be successfully constructed or operated.

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

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

We own a license to use the HTL technology that we are seeking to commercialize but we may not become aware of claims of infringement upon the patents or rights of others in this technology until after we have made a substantial investment in the development and commercialization of projects utilizing it. Third parties may claim that the technology infringes upon past, present or future patented technologies. Legal actions could be brought against the licensor and us claiming damages and seeking an injunction that would prevent us from testing or commercializing the technology. If an infringement action were successful, in addition to potential liability for damages, we and our licensors could be required to obtain a claiming party’s license in order to continue to test or commercialize the technology. Any required license might not be made available or, if available, might not be available on acceptable terms, and we could be prevented entirely from testing or commercializing the technology. We may have to expend substantial resources in litigation defending against the infringement claims of others. Many possible claimants, such as the major energy companies that have or may be developing proprietary heavy oil upgrading technologies competitive with our technology, may have significantly more resources to spend on litigation.

Technological advances could significantly decrease the cost of upgrading heavy oil and, if we are unable to adopt or incorporate technological advances into our operations, our HTL technology could become uncompetitive or obsolete.

We expect that technological advances in the processes and procedures for upgrading heavy oil and bitumen into lighter, less viscous products will continue to occur. It is possible that those advances could make the processes and procedures, which are integral to the HTL technology that we are seeking to commercialize, less efficient or cause the upgraded product being produced to be of a lesser quality. These advances could also allow competitors to produce upgraded products at a lower cost than that at which our HTL technology is able to produce such products. If we are unable to adopt or incorporate technological advances, our production methods and processes could be less efficient than those of our competitors, which could cause our HTL technology facilities to become uncompetitive.

The development of alternate sources of energy could lower the demand for our HTL technology.

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 our HTL technology upgraded product. It is also possible that technological advances in engine design and performance could reduce the use of oil and bitumen, which would lower the demand for such products.

The volatility of oil prices may affect our financial results.

Our revenues, operating results, profitability and future rate of growth are highly dependent on the price of, and demand for, oil. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. Even relatively modest changes in oil prices may significantly change our revenues, results of operations, cash flows and proved reserves. Historically, the market for oil has been volatile and is likely to continue to be volatile in the future.

The price of oil may fluctuate widely in response to relatively minor changes in the supply of and demand for oil, market uncertainty and a variety of additional factors that are beyond our control, such as weather conditions, overall global economic conditions,

terrorist attacks or military conflicts, political and economic conditions in oil producing countries, the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls, the level of demand and the price and availability of alternative fuels, speculation in the commodity futures markets, technological advances affecting energy consumption, governmental regulations and approvals, proximity and capacity of oil pipelines and other transportation facilities.

These factors and the volatility of the energy markets make it extremely difficult to predict future oil price movements with any certainty. Declines in oil prices would not only reduce our revenues, but could reduce the amount of oil we can economically produce. This may result in our having to make substantial downward adjustments to our estimated proved reserves and could have a material adverse effect on our financial condition and results of operations. In addition, a substantial long-term decline in oil prices would severely impact our ability to execute a heavy oil development program

Lower oil prices could negatively impact our ability to borrow.

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

Our ability to sell assets and replace revenues generated from any sale of our existing properties depends upon market conditions and numerous uncertainties.

During 2006, we were involved in negotiations for a business combination transaction involving our China assets that, if completed, would have resulted in our China assets being owned and operated by a separate publicly traded company. Although the transaction was not completed, we are continuing to explore opportunities to generate capital for the ongoing development of our core HTL business, which may involve the sale of some or all of our exploration, development and production assets in China and the U.S. There can be no assurance that we will sell any such assets nor that any such sale, if and when made, will generate sufficient capital for the ongoing development of our core HTL business, which will require the acquisition of one or more properties hosting deposits of heavy oil. Our operating revenues and cash flows would likely decrease significantly following the sale of any material portion of our existing producing assets and would likely remain at lower levels until we were able to replace the lost production with production from new properties.

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

We may be required under generally accepted accounting principles in Canada and the U.S. to write down the carrying value of our properties if oil prices decline or if we have substantial downward adjustments to our estimated proved reserves, increases in our estimates of development costs or deterioration in our exploration results. See “Critical Accounting Principles and Estimates – Impairment of Proved Oil and Gas Properties” in Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report.

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.

Estimates of proved reserves and future net revenue may change if the assumptions on which such estimates are based prove to be inaccurate.

Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment and the

assumptions used regarding prices for oil and natural gas, production volumes, required levels of operating and capital expenditures, and quantities of recoverable oil reserves. Oil prices have fluctuated widely in recent years. Volatility is expected to continue and price fluctuations directly affect estimated quantities of proved reserves and future net revenues. Actual prices, production, development expenditures, operating expenses and quantities of recoverable oil reserves will vary from those assumed in our estimates, and these variances may be significant. Also, we make certain assumptions regarding future oil prices, production levels, and operating and development costs that may prove incorrect. Any significant variance from the assumptions used could result in the actual quantity of our reserves and future net cash flow being materially different from the estimates we report. In addition, actual results of drilling, testing and production and changes in natural gas and oil prices after the date of the estimate may result in revisions to our reserve estimates. Revisions to prior estimates may be material.

Information in this document regarding our future plans reflects our current intent and is subject to change.

We describe our current exploration and development plans in this Annual Report. Whether we ultimately implement our plans will depend on availability and cost of capital; receipt of HTL technology process test results, additional seismic data or reprocessed existing data; current and projected oil or gas prices; costs and availability of drilling rigs and other equipment, supplies and personnel; success or failure of activities in similar areas; changes in estimates of project completion costs; our ability to attract other industry partners to acquire a portion of the working interest to reduce costs and exposure to risks and decisions of our joint working interest owners.

We will continue to gather data about our projects and it is possible that additional information will cause us to alter our schedule or determine that a project should not be pursued at all. You should understand that our plans regarding our projects might change.

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

Some of our properties are held under licenses and leases, working interests in licenses and leases or production sharing contracts. If we fail to meet the specific requirements of the instrument through which we hold our interest, it may terminate or expire. We cannot assure you that any or all of the obligations required to maintain our interest in each such license, lease or production sharing contract will be met. Some of our property interests will terminate unless we fulfill such obligations. If we are unable to satisfy these obligations on a timely basis, we may lose our rights in these properties. The termination of our interests in these properties may harm our business.

We may incur significant costs on exploration or development efforts which may prove unsuccessful or unprofitable.

There can be no assurance that the costs we incur on exploration or development will result in an economic return. We may misinterpret geologic or engineering data, which may result in significant losses on unsuccessful exploration or development drilling efforts. We bear the risks of project delays and cost overruns due to unexpected geologic conditions, equipment failures, equipment delivery delays, accidents, adverse weather, government and joint venture partner approval delays, construction or start-up delays and other associated risks. Such risks may delay expected production and/or increase costs of production or otherwise adversely affect our ability to realize an acceptable level of economic return on a particular project in a timely manner or at all.

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

There are hazards and risks inherent in drilling for, producing and transporting oil. These hazards and risks may result in loss of hydrocarbons, environmental pollution, personal injury claims, and other damage to our properties and third parties and include fires, natural disasters, adverse weather conditions, explosions, encountering formations with abnormal pressures, encountering unusual or unexpected geological formations, blowouts, cratering, unexpected operational events, equipment malfunctions, pipeline ruptures, spills, compliance with environmental and government regulations and title problems.

We are insured against some, but not all, of the hazards associated with our business, so we may sustain losses that could be substantial due to events that are not insured or are underinsured. The occurrence of an event that is not covered or not fully covered by insurance could have a material adverse impact on our financial condition and results of operations. We do not carry business interruption insurance and, therefore, the loss and delay of revenues resulting from curtailed production are not insured.

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.

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 20% of our common shares. As a result, he has the voting power to significantly influence our policies, business and affairs and the outcome of any corporate transaction or other matter, including mergers, consolidations and the sale of all, or substantially all, of our assets.

In addition, the concentration of our ownership may have the effect of delaying, deterring or preventing a change in control that otherwise could result in a premium in the price of our common shares.

If we lose our key management and technical personnel, our business may suffer.

We rely upon a relatively small group of key management personnel. Given the technological nature of our business, we also rely heavily upon our scientific and technical personnel. Our ability to implement our business strategy may be constrained and the timing of implementation may be impacted if we are unable to attract and retain sufficient personnel. We do not maintain any key man insurance. We do not have employment agreements with certain of our key management and technical personnel and we cannot assure you that these individuals will remain with us in the future. An unexpected partial or total loss of their services would harm our business.

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, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASE OF EQUITY SECURITIES

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.$)

		2006																2005
		4th Qtr				3rd Qtr				2nd Qtr				1st Qtr				4th Qtr				3rd Qtr				2nd Qtr				1st Qtr
High			1.65				2.43				2.96				3.27				2.00				2.50				2.95				3.34
Low			1.18				1.40				2.26				1.25				0.99				1.97				1.98				2.04

TORONTO STOCK EXCHANGE (IE)
(CDN$)

		2006																2005
		4th Qtr				3rd Qtr				2nd Qtr				1st Qtr				4th Qtr				3rd Qtr				2nd Qtr				1st Qtr
High			1.89				2.72				3.31				3.75				2.32				3.06				3.60				4.02
Low			1.36				1.59				2.50				1.44				1.16				2.30				2.52				2.52

On December 29, 2006, the closing prices for our common shares were $1.35 on the NASDAQ Capital Market and Cdn. $1.57 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 of 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. As of the date of this Annual Report on Form 10-K, our board of directors consists of 6 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. However, if all of the individuals nominated by management for election to our board of directors are elected at our next annual meeting of shareholders on May 3, 2007, our board of directors will consist of 5 individuals who are independent and 6 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 are a company incorporated under the laws of the Yukon Territory of Canada and our executive offices are located in British Columbia, Canada. Some of our directors, controlling shareholders, officers and representatives of the experts named in this Annual Report on Form 10-K reside outside the U.S. and a substantial portion of their assets and our assets are located outside the U.S. As a result, it may be difficult for you to effect service of process within the U.S. upon the directors, controlling shareholders, officers and representatives of experts who are not residents of the U.S. or to enforce against them judgments obtained in the courts of the U.S. based upon the civil liability provisions of the federal securities laws or other laws of the U.S. There is doubt as to the enforceability in Canada against us or against any of our directors, controlling shareholders, officers or experts who are not residents of the U.S., in original actions or in actions for enforcement of judgments of U.S. courts, of liabilities based solely upon civil liability provisions of the U.S. federal securities laws. Therefore, it may not be possible to enforce those actions against us, our directors, officers, controlling shareholders or experts named in this Annual Report on Form 10-K.

Holders of Common Shares

As at December 31, 2006, a total of 241,215,798 of our common shares were issued and outstanding and held by 213 holders of record with an estimated 40,002 additional shareholders whose shares were held for them in street name or nominee accounts.

Dividends

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

Exchange Controls and Taxation

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

There is no limitation imposed by the laws of Canada, the laws of the Yukon Territory, or our constating documents on the right of a non-resident to hold or vote our common shares, other than as provided in the Investment Canada Act (Canada) (the “Investment Act”), which generally prohibits a reviewable investment by an entity that is not a “Canadian”, as defined, unless after review, the minister responsible for the Investment Act is satisfied that the investment is likely to be of net benefit to Canada. An investment in our common shares by a non-Canadian who is not a “WTO investor” (which includes governments of, or individuals who are nationals of, member states of the World Trade Organization and corporations and other entities which are controlled by them), at a time when we were not already controlled by a WTO investor, would be reviewable under the Investment Act under two circumstances. First, if it was an investment to acquire control (within the meaning of the Investment Act) and the value of our assets, as determined under Investment Act regulations, was Cdn.$5 million or more. Second, the investment would also be reviewable if an order for review was made by the federal cabinet of the Canadian government on the grounds that the investment related to Canada’s cultural heritage or national identity (as prescribed under the Investment Act), regardless of asset value. 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 2007 is Cdn.$281 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), as amended, (the “Convention”). Currently, under the Convention, the rate of Canadian non-resident withholding tax on the gross amount of dividends paid or credited to a U.S. resident is generally 15%. However, if the beneficial owner of such dividends is a U.S. resident corporation, which owns 10% or more of our voting stock, the withholding rate is reduced to 5%. In the case of certain tax-exempt entities, which are residents of the U.S. for the purpose of the Convention, the withholding tax on dividends may be reduced to 0%.

Sales of Unregistered Securities

During the year ended December 31, 2006, we issued securities, which were not registered under the Securities Act of 1933 (the “Act”), as follows:

	•		in February 2006, we issued 8,591,434 shares in exchange for an additional 40% working interest in the Dagang field to CITIC in a transaction exempt from registration under Rule 903 of the Act;
	•		in March 2006, we issued 100 common shares at a price of U.S.$3.20 to an 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 April 2006, we issued 11,400,000 special warrants at U.S.$2.23 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 May 2006. Originally, one common share purchase warrant would entitle the holder to purchase one common share at a price of U.S.$2.63 exercisable until the fifth anniversary date of the special warrant date of issue. In September 2006 these warrants were listed on the Toronto Stock Exchange and the exercise price was changed to Cdn.$2.93.

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
		2006				2005				2004				2003				2002
		(stated in thousands of US dollars, except per share amounts)
Financial Position
Total assets			248,544				240,877				118,486				106,574				107,088
Long-term debt			4,237				4,972				2,639				833			Nil
Shareholders’ equity			228,386				204,767				103,586				100,537				100,548
Common shares outstanding (in thousands)			241,216				220,779				169,665				161,359				144,466
Capital investments			17,842				43,282				46,454				15,391				18,828
Results of Operations
Revenues			48,100				29,939				17,997				9,659				8,437
Net loss			(25,492	)(1)			(13,512	)(1)			(20,725	)(1)			(30,179	)(1)			(7,130	)(1)
Net loss per share — basic and diluted			(0.11	)			(0.07	)			(0.12	)			(0.20	)			(0.05	)

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 Company has restated its U.S. GAAP financial position as at December 31, 2005 and results of operations for the year ended December 31, 2005, to correct the accounting treatment of certain warrants for U.S. GAAP purposes. The warrants that are subject to restatement were issued in 2005. Previously, the Company accounted for these instruments as equity under both Canadian and U.S. GAAP. The treatment of warrants was changed under U.S. GAAP to correct for the application of Statement of Financial Accounting Standard No. 133 “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”). Under SFAS No. 133, share purchase warrants with an exercise price denominated in a currency other than the company’s functional currency are accounted for as derivative liabilities. Changes in the fair value of the warrants are required to be recognized in the statement of operations each reporting period for U.S. GAAP purposes. Under the Company’s previous U.S. GAAP accounting treatment, no changes in fair value were recorded. At the time that the Company’s share purchase warrants are exercised, the value of the warrants will be reclassified to shareholders’ equity for US GAAP purposes. Under Canadian GAAP, the fair value of the warrants on the issue date is recorded as a reduction to the proceeds from the issuance of common shares, with the offset to the warrant component of equity. The warrants are not revalued to fair value under Canadian GAAP. The cumulative effects of the U.S. GAAP restatement as at December 31, 2005 are as follows: an increase in liabilities of $0.1 million, a decrease in purchase warrants classified within shareholders’ equity of $2.9 million, and a decrease in accumulated deficit of $2.9 million. The only other 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, 2005 and 2006, net of depletion expense,

	•		net additional impairment provision for our U.S. oil and gas properties in 2004, 2005 and 2006, net of depletion expense,
	•		net additional expense from 2001 to 2006 in connection with development costs for our GTL and HTL 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 19 to our financial statements in this Annual Report on Form 10-K.

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

		December 31
						2005
		2006				(as restated)				2004				2003				2002
		(stated in thousands of US dollars, except per share amounts)
Financial Position
Total assets			216,365				224,935				105,791				94,024				91,921
Shareholders’ equity — as originally reported			188,829				188,825				90,892				87,987				85,279
Prior period adjustment			—				(80	)			—				—				—
Shareholders’ equity — as restated			188,829				188,745				90,892				87,987				85,279
Results of Operations
Net loss — as originally reported			(42,422	)			(14,972	)			(19,696	)			(27,086	)			(8,202	)
Prior period adjustment			—				2,866				—				—				—
Net loss — as restated			(42,422	)			(12,106	)			(19,696	)			(27,086	)			(8,202	)
Net loss per share — basic and diluted			(0.18	)			(0.07	)			(0.12	)			(0.18	)			(0.06	)
Prior period adjustment			—				0.01				—				—				—
Net loss per share — as restated			(0.18	)			(0.06	)			(0.12	)			(0.18	)			(0.06	)

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

TABLE OF CONTENTS

		Page
Ivanhoe Energy’s Business			20
Executive Overview of 2006 Results			20
Financial Results – Year to Year Change in Net Loss			21
Net Operating Revenues			21
General and Administrative			25
Business and Technology Development			26
Write-off of Deferred Acquisition Costs			27
Net Interest			27
Depletion and Depreciation			27
Write-Down of GTL and HTL Investments			28
Impairment of Oil and Gas Properties			28
Financial Condition, Liquidity and Capital Resources			29
Contractual Obligations and Commitments			30
Critical Accounting Principles and Estimates			31
Impact of New and Pending Canadian GAAP Accounting Standards			34
Impact of New and Pending U.S. GAAP Accounting Standards			35
Off Balance Sheet Arrangements			36
Related Party Transactions			36
Certain Factors Affecting the Business			37

THE FOLLOWING SHOULD BE READ IN CONJUNCTION WITH THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED DECEMBER 31, 2006. THE CONSOLIDATED FINANCIAL STATEMENTS HAVE BEEN PREPARED IN ACCORDANCE WITH GENERALLY ACCEPTED ACCOUNTING PRINCIPLES IN CANADA (“GAAP”). THE IMPACT OF SIGNIFICANT DIFFERENCES BETWEEN CANADIAN AND U.S. GAAP ON THE FINANCIAL STATEMENTS IS DISCLOSED IN NOTE 19 TO THE CONSOLIDATED FINANCIAL STATEMENTS.

OUR DISCUSSION AND ANALYSIS OF OUR OIL AND GAS ACTIVITIES WITH RESPECT TO OIL AND GAS VOLUMES, RESERVES AND RELATED PERFORMANCE MEASURES IS PRESENTED ON OUR WORKING INTEREST BASIS AFTER ROYALTIES. ALL TABULAR AMOUNTS ARE EXPRESSED

IN THOUSANDS OF U.S. DOLLARS, EXCEPT PER SHARE AND PRODUCTION DATA INCLUDING REVENUES AND COSTS PER BOE.

Ivanhoe Energy’s Business

Ivanhoe Energy is an independent international heavy oil development and production company focused on pursuing long-term growth in its reserve base and production. Ivanhoe Energy plans to utilize technologically innovative methods designed to significantly improve recovery of heavy oil resources, including the application of the patented rapid thermal processing process (“RTP^TM Process”) for heavy oil upgrading (“HTL Technology” or “HTL”) and enhanced oil recovery (“EOR”) techniques. In addition, the Company seeks to expand its reserve base and production through conventional exploration and production (“E&P”) of oil and gas. Finally, the Company is exploring an opportunity to monetize stranded gas reserves through the application of the conversion of natural gas-to-liquids using a technology (“GTL Technology” or “GTL”) licensed from Syntroleum Corporation. Our core operations are in the United States and China, with business development opportunities worldwide.

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

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

Executive Overview of 2006 Results

Oil and gas revenue increased by 60% or $17.9 million as a result of a combination of a 25% increase in production and a 28% increase in oil and gas prices. However, this improvement was more than offset by an $8.5 million increase in oil and gas operating costs and an $18.1 million increase in depletion and depreciation. A major contributor to the significant increase in depletion and depreciation expense for 2006 was the downward revisions in our China reserve estimates in the fourth quarter of 2005.

For the year, cash flow from operating activities increased by 45% to $14.4 million, an increase of $4.5 million while at the same time we significantly reduced the capital expenditure program associated with our conventional oil and gas exploration and development activities as we more closely focused the Company’s activities on the development and deployment of our HTL Technology.

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

		Year ended December 31,
		2006				2005				2004
Oil and gas revenue		$	47,748			$	29,800			$	17,795
Net loss		$	(25,492	)		$	(13,512	)		$	(20,725	)
Net loss per share		$	(0.11	)		$	(0.07	)		$	(0.12	)
Average production (Boe/d)			2,178				1,738				1,376
Net operating revenue per Boe		$	60.06			$	46.97			$	35.34
Capital investments		$	17,842			$	43,282			$	46,454
Cash flow from operating activities		$	14,352			$	9,870			$	4,032

Financial Results — Year to Year Change in Net Loss

The following provides a summary analysis of our net losses for each of the three years ended December 31, 2006 and a summary of year-over-year variances for the year ended December 31, 2006 compared to 2005 and for the year ended December 31, 2005 compared to 2004:

							Favorable										Favorable
							(Unfavorable)										(Unfavorable)
		2006					Variances					2005					Variances					2004
Summary of Net Loss by Significant Components:
Cash Items:
Net operating revenues:
Oil and Gas Revenues:		$	47,748									$	29,800									$	17,795
Production volumes							$	8,888									$	4,334
Oil and gas prices								9,060										7,671
Realized gain on derivative instruments			69					69					—					—					—
Less: Operating costs			(16,133	)				(8,530	)				(7,603	)				(2,530	)				(5,073	)
Total net operating revenues			31,684					9,487					22,197					9,475					12,722
General and administrative, less stock based compensation			(7,648	)				(60	)				(7,588	)				(1,589	)				(5,999	)
Business and technology development, less stock based compensation			(7,221	)				(2,416	)				(4,805	)				(2,893	)				(1,912	)
Acquisition costs			(736	)				(736	)				—					—					—
Net interest			(29	)				982					(1,011	)				(881	)				(130	)
Total Cash Variances			16,050					7,257					8,793					4,112					4,681
Non-Cash Items:
Unrealized loss on derivative instruments			(493	)				(493	)				—					—					—
Depletion and depreciation			(32,550	)				(18,103	)				(14,447	)				(6,965	)				(7,482	)
Stock based compensation			(2,921	)				(808	)				(2,113	)				(837	)				(1,276	)
Write-downs of HTL and GTL investments			—					636					(636	)				(386	)				(250	)
Impairment of oil and gas properties			(5,420	)				(420	)				(5,000	)				11,350					(16,350	)
Other			(158	)				(49	)				(109	)				(61	)				(48	)
Total Non-Cash Variances			(41,542	)				(19,237	)				(22,305	)				3,101					(25,406	)
Net Loss		$	(25,492	)			$	(11,980	)			$	(13,512	)			$	7,213				$	(20,725	)

Our net loss for 2006 was $25.5 million ($0.11 per share) compared to our net loss in 2005 of $13.5 million ($0.07 per share). The increase in our net loss from 2005 to 2006 of $12.0 million was due mainly to an $18.1 million increase in a non-cash charge for depletion and depreciation. The increase in unfavorable non-cash charges was offset by an increase in favorable cash variances of $7.3 million, mainly due to an increase of $9.5 million in net operating revenues offset by a $2.5 million increase in general administrative and business and technology development expenses excluding stock based compensation.

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 a $9.5 million increase in net operating revenues and an $11.4 million reduction in impairment of our U.S. and China oil and gas properties. This was partially offset by a $7.0 million increase in depletion and depreciation expense, a $4.5 million increase in general administrative and business and technology development expenses excluding 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 HTL and GTL investments.

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

Net Operating Revenues

The following is a comparison of changes in production volumes for the year ended December 31, 2006 when compared to the same period in 2005 and for the year ended December 31, 2005 when compared to the same period for 2004:

		Years ended December 31,												Years ended December 31,
		Net Boe’s								Percentage				Net Boe’s								Percentage
		2006				2005				Change				2005				2004				Change
China:
Dagang			554,185				282,582				96	%			282,582				190,309				48	%
Daqing			20,946				32,236				-35	%			32,236				44,626				-28	%
			575,131				314,818				83	%			314,818				234,935				34	%
U.S.:
South Midway			188,379				196,428				-4	%			196,428				183,875				7	%
Spraberry			23,242				27,940				-17	%			27,940				33,498				-17	%
Citrus			4,733				34,257				-86	%			34,257				31,008				10	%
Knights Landing			237				57,106				-100	%			57,106				14,786				286	%
Others			3,339				3,943				-15	%			3,943				5,447				-28	%
			219,930				319,674				-31	%			319,674				268,614				19	%
			795,061				634,492				25	%			634,492				503,549				26	%

Net production volumes in 2006 increased 25% from 2005 due to an 83% increase in production volumes in our China properties offset by a 31% decrease in our U.S. properties, resulting in increased revenues of $8.9 million.

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 resulting in increased revenues of $4.3 million.

Oil and gas prices increased 28% per Boe in 2006 generating $9.1 million in additional revenue as compared to 2005. We realized an average of $62.04 per Boe from operations in China during 2006, which was an increase of $12.07 per Boe from 2005 prices and accounted for $7.1 million of our increase in revenues. From the U.S. operations, we realized an average of $54.86 per Boe during 2006, which was an increase of $10.85 per Boe and accounted for $2.0 million of our increased revenues.

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 $13.86 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.

Operating costs, including production taxes and engineering support, for 2006 and 2005 increased $8.29, or 69.12 %, per Boe, $1.93, or 19 %, per Boe, from the previous years. These costs for 2006 and 2005 increased $8.5 million, and $2.5 million, in absolute terms from the previous years.

			China
	•		Production Volumes 2006 vs. 2005

Net production volumes increased 96% at the Dagang field for 2006. As a result of the 2005 development program, oil production volume increased by 22% or by 61.7 Mboe in 2006 when compared to 2005. During 2005 we placed 22 new wells on production and fracture stimulated 13 wells in the northern block of this project and in 2006 we completed one well, fracture stimulated 12 wells and re-completed 13 wells. Additionally, volumes at the Dagang field increased in 2006 when compared to 2005 by 74 % or 209.9 Mboe due to the re-acquisition of Richfirst’s 40% working interest in this project in February 2006.

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 35% for 2006 compared to the same period in 2005. In addition, production from the field is declining.

•

Production Volumes 2005 vs. 2004

Net production volumes increased 48% at the Dagang field 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. 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.

As a result of the May 2005 decrease in our royalty percentage noted above, our share of production volumes decreased 28% for 2005 compared to the same period in 2004.

•

Operating Costs 2006 vs. 2005

Operating costs in China, including engineering support, increased 149% or $12.31 per Boe for 2006 when compared to 2005. Field operating costs increased due to high power costs, increased workover and maintenance costs, related supervision and increased treatment and processing fees attributable to higher water production rates. With the suspension of our drilling activity at our Dagang field in December 2005, a major portion of our Dagang field office costs, which were previously being capitalized, are now being expensed as part of our operating activities. Engineering support increased due to a higher allocation of support to production as we reduced our capital activity in the Dagang field in 2006 when compared to 2005. The increase in production volume in 2006 due to the 2005 drilling program at the Dagang field, in relation to the level of support required to operate the field, results in the per Boe decrease for 2006 when compared to 2005.

In March 2006, the Ministry of Finance of the Peoples Republic of China (“PRC”) issued the “Administrative Measures on Collection of Windfall Gain Levy on Oil Exploitation Business” (the “Windfall Levy Measures”). According to the Windfall Levy Measures, effective as of March 26, 2006, enterprises exploiting and selling crude oil in the PRC are subject to a windfall gain levy (the “Windfall Levy”) if the monthly weighted average price of crude oil is above $40 per barrel. The Windfall Levy is imposed at progressive rates from 20% to 40% on the portion of the weighted average sales price exceeding $40 per barrel. For financial statement presentation the Windfall Levy is included in operating costs. The Windfall Levy resulted in $5.74 per Boe of the overall increase in 2006 when compared to 2005.

•

Operating Costs 2005 vs. 2004

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.
	•		Production Volumes 2006 vs. 2005

U.S. production volumes decreased 31% in 2006 when compared to 2005 mainly as a result of the decline in production from the Knights Landing field which had been depleted to minimal levels at the end of 2005 and the sale of our Citrus property effective February 1, 2006.

In addition, our production at South Midway decreased 4% for 2006 primarily as a result of several wells in the southern expansion of South Midway being down while we made repairs to our steam facilities. Contributions from the two in-fill wells in the southern expansion and seven in-fill wells in the primary area of South Midway drilled and completed in the second half of 2006 will not be a major impact until 2007. As at December 31, 2006, we were producing 590 gross Boe/d (543 net Boe/d) at South Midway compared to 536 gross Boe/d (499 net Boe/d) as at December 31, 2005.

•

Production Volumes 2005 vs. 2004

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.

•

Operating Costs 2006 vs. 2005

Operating costs in the U.S., including engineering support and production taxes, in 2006 decreased $0.7 million in absolute terms from 2005. However, on a per Boe basis operating costs increased 25% or $3.90 per Boe in 2006 when compared to 2005. Field operating costs increased $3.00 per Boe for 2006 when compared to 2005, primarily resulting from increases in primary operating costs at South Midway due to several maintenance projects related to the processing facilities. Although costs in the South Midway steaming operations did not fluctuate significantly in absolute terms, they did make up a larger portion of the overall cost per Boe as production in other fields declined. Engineering support increased $0.58 per Boe for 2006, when compared to 2005 as the same level of support was required to operate the fields even though there was a decline in production. Production taxes were up $0.32 per Boe for 2006 when compared to 2005, largely as the result of an increase in ad valorem taxes at South Midway and our Spraberry field in West Texas.

•

Operating Costs 2005 vs. 2004

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.

* * *

Production and operating information including oil and gas revenue, operating costs and depletion, on a per Boe basis, from 2004 to 2006 are detailed below:

		Year ended December 31,
		2006												2005												2004
		U.S.				China				Total				U.S.				China				Total				U.S.				China				Total
Net Production:
Boe			219,930				575,131				795,061				319,674				314,818				634,492				268,614				234,935				503,549
Boe/day for the year			603				1,576				2,178				876				863				1,738				734				642				1,376

		Per Boe												Per Boe												Per Boe
Oil and gas revenue		$	54.86			$	62.04			$	60.06			$	44.01			$	49.97			$	46.97			$	34.66			$	36.11			$	35.34
Field operating costs			14.44				14.07				14.17				11.44				7.49				9.48				8.94				6.04				7.59
Production tax and Windfall Levy			1.15				5.74				4.47				0.83				—				0.42				0.44				—				0.23
Engineering support			3.95				0.77				1.65				3.37				0.78				2.08				2.38				2.10				2.25
			19.54				20.58				20.29				15.64				8.27				12.00				11.76				8.14				10.07
Net operating revenue			35.32				41.46				39.77				28.37				41.70				34.99				22.90				27.97				25.27
Depletion			24.23				40.57				36.05				15.53				29.77				22.60				16.80				12.18				14.64
		$	11.09			$	0.89			$	3.72			$	12.84			$	11.93			$	12.39			$	6.10			$	15.79			$	10.63

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, 2006 when compared to the same period for 2005 and for the year ended December 31, 2005 when compared to the same period for 2004 were as follows:

		2006 vs.				2005 vs.
		2005				2004
Favorable (unfavorable) variances:
Oil and Gas Activities:
China		$	739			$	(1,116	)
U.S.			(498	)			(188	)
Corporate			(892	)			(950	)
			(651	)			(2,254	)
Less: stock based compensation			591				665
		$	(60	)		$	(1,589	)

	•		General and Administrative 2006 vs. 2005
			China

General and administrative expenses related to the China operations decreased $0.7 million for 2006 due to a $1.1 million one time charge in 2005 for the write off of deferred costs incurred associated with financing discussions for our Dagang field development project. This decrease was primarily offset by an increase of $0.3 million in foreign currency losses.

U.S.

General and administrative expenses related to U.S. operations increased $0.5 million in 2006. Allocations to capital investments decreased $1.5 million as a result of less capital activity for 2006 when compared to 2005. This increase in expense was offset by a decrease of $0.7 million for bonuses accrued in 2005 compared to nil in 2006, a $0.2 million decrease in stock based compensation and a decrease of $0.2 million for a reduction in contract labor.

Corporate

General and administrative costs related to Corporate activities increased $0.9 million for 2006 when compared to 2005. The increase for 2006 was due to a $0.4 million increase in salaries and benefits (a $0.8 million increase in stock based compensation offset by a decrease of $0.3 million for bonuses accrued in 2005), a $0.2 million increase in outside legal, a $0.3 million increase in financial consulting, a $0.5 million increase in corporate governance costs and a $0.3 million increase for a one time charge in 2006 for the write off of the deferred loan costs on the convertible loan that was paid by way of the issuance of common shares in the April 2006 private placement. These increases were offset by a $0.7 million decrease in reduced professional fees incurred to comply with the provisions of Section 404 of the Sarbanes-Oxley Act of 2002 (“SOX”) as a portion of the 2004 SOX review was performed in the first quarter of 2005. In addition, current year costs for SOX are lower as there are no start up costs that we experienced in 2005.

	•		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 HTL and GTL 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.

Business and Technology Development

Our changes in business and technology development, before and after considering increases in non-cash stock based compensation, for the year ended December 31, 2006 when compared to the same period for 2005 and for the year ended December 31, 2005 when compared to the same period for 2004 were as follows:

		2006 vs.				2006 vs.
		2005				2005
Favorable (unfavorable) variances:
HTL		$	(2,506	)		$	(3,229	)
GTL			(127	)			164
			(2,633	)			(3,065	)
Less: stock based compensation			217				172
		$	(2,416	)		$	(2,893	)

•

Business and Technology Development 2006 vs. 2005

As in 2005 most of the focus of our business and technology development activities was on HTL opportunities. Operating expenses of the CDF to develop and identify improvements in the application of the HTL Technology are expensed as part of our business and technology development activities and contributed $1.1 million to the increase in business and technology development for HTL activities in 2006. Part of this increase was due to the CDF operating for a full year in 2006 versus a partial year in 2005. In addition contract services, including engineering work related to CDF processing runs and legal fees related to patents, increased $0.7 million in 2006. The remainder of the increase is related to consulting fees and travel costs to develop opportunities for our HTL Technology.

•

Business and Technology Development 2005 vs. 2004

During 2005, much of the focus of our business and technology development activities was on HTL 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 technology development expenses for 2005 associated with HTL 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 HTL Technology. In addition, operating expenses of the CDF to develop and identify improvements in the application of the HTL Technology are expensed as part of our business and technology development activities and contributed $1.6 million to the increase in business and technology development for HTL activities in 2005.

Write-off of Deferred Acquisition Costs

In February 2006, the Company signed a non-binding memorandum of understanding regarding a proposed merger of Sunwing with China Mineral Acquisition Corporation (“CMA”), a U.S. public corporation. In May 2006 the parties entered a definitive agreement for the transaction. CMA’s bylaws stipulated that if the transaction was not completed by August 31, 2006 CMA would be required to dissolve and distribute its assets (substantially all of which was cash) to its shareholders. CMA requested, but was unable to obtain, an extension of this deadline from its shareholders. Since the transaction could not be completed by the August 31 deadline, the definitive agreement was terminated and the Company wrote off deferred acquisition costs previously capitalized in the amount of $0.7 million.

Net Interest

•

Net Interest 2006 vs. 2005

In the fourth quarter of 2005, two convertible loans totaling $8.0 million (see 2005 vs. 2004 analysis below) were exchanged for a $4.0 million term note. This term note was paid off early in the second quarter of 2006. The reduction in interest and financing costs resulting from the reduction in these loans from year to year was $0.8 million. In addition, interest income increased by $0.6 million as average cash balances were significantly higher throughout 2006 when compared to 2005. These favorable increases were offset by a $0.4 million increase in interest and financing costs related to the note with CITIC. This note was part of the consideration for the re-acquisition of the 40% interest in the Dagang field.

•

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.

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 2006 vs. 2005

Depletion and depreciation increased $18.1 million in 2006, due to an increase in depletion rates of $13.45 per Boe resulting in additional depletion expense of $8.1 million for 2006. Additionally, higher production rates resulted in increase in depletion of $6.2 million for 2006. We began depreciating the CDF in 2006 which also contributed to the overall increase in depletion and depreciation in the amount of $3.8 million for 2006.

China

China’s depletion rate for 2006 was $40.57 per Boe compared to $29.77 per Boe for 2005. The increase of $10.80 per Boe resulted in $6.2 million increase in depletion expense for 2006. This increase was due mainly to two factors:

	•		We suspended new drilling activity in December 2005 at our Dagang field in order to assess production decline performances on recently drilled wells, as well as maximizing cash flow from these operations. As a result, we reduced our estimate of the overall development program and our independent engineering evaluators, GLJ Petroleum Consultants Ltd., revised downward their estimate of our proved reserves at December 31, 2005.
	•		In the second quarter of 2005, we impaired the cost of our first Zitong block exploration well resulting in $12.5 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 $7.8 million of the increase in depletion expense for 2006.

U.S.

The U.S. depletion rate for 2006 was $24.23 per Boe compared to $15.53 per Boe for 2005, an increase of $8.70 per Boe resulting in a $1.9 million increase in depletion expense. This increase was mainly due to the impairment of the remaining cost of our Northwest

Lost Hills #1-22 exploration well as at December 31, 2005, resulting in $8.9 million of those costs being included with our proved properties and therefore subject to depletion in the first quarter of 2006. In addition, the impairment of other properties in December 2006, including Yowlumne, LAK Ranch and Catfish Creek, resulted in $4.8 million of those costs being included with our proved properties and therefore subject to depletion in the fourth quarter of 2006. Increases in revisions to reserve estimates at December 31, 2006, mainly at South Midway, slightly offset the additional costs being added to the pool. Production volume decreases in the U.S. resulted in a $1.6 million decrease in our depletion expense for 2006.

HTL

The CDF was in a commissioning phase as at December 31, 2005 and, as such, had not been depreciated as at December 31, 2005. The commissioning phase ended in January 2006 and the CDF was placed into service. In 2006 $3.8 million of depreciation was recorded for the CDF.

•

Depletion and Depreciation 2005 vs. 2004

Depletion and depreciation increased $7.0 million in 2005, $5.1 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 $1.9 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 $5.5 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 the reduced overall development program at our Dagang field and the subsequent reduction by our independent engineering evaluators, GLJ Petroleum Consultants of their estimate of our proved reserves as at December 31, 2005. We also impaired the cost of our first Zitong block exploration well 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 $1.0 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 $0.4 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 $0.9 million increase in our depletion expense for 2005.

Write-Down of HTL and GTL 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 HTL or GTL 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 HTL and GTL assets. For U.S. GAAP, all such costs are expensed as incurred.

•

Write-Down of HTL and GTL Investments 2006 vs. 2005

In 2006, we had no write downs for our HTL and GTL projects. This compares to the write down of $0.3 million related to our GTL project in Bolivia and $0.3 million related to our MOU with Ecopetrol for a heavy crude project in Colombia in 2006.

•

Write-Down of HTL and GTL 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 Colombia ‘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 bid to participate in the project was not successful. This compares to the write down of $0.3 million in 2004 for our investment in the Oman GTL project.

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 2006 vs. 2005

We impaired our China oil and gas properties by $5.4 million in 2006, compared to $5.0 million in 2005. The 2006 impairment was mainly the result of increased operating costs of the Dagang field, including costs of the Windfall Levy established in March 2006.

•

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 $16.4 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 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.

Financial Condition, Liquidity and Capital Resources

Sources and Uses of Cash

Our net cash and cash equivalents increased by $7.2 million for the year ended December 31, 2006 compared to decreases of $2.6 million and $5.2 million for the same periods in 2005 and 2004, respectively.

•

Operating Activities

Our operating activities provided $14.4 million in cash for the year ended December 31, 2006 compared to $9.9 million and $4.0 million for the same periods in 2005 and 2004. The increases in cash from operating activities for the years ended December 31, 2006 and 2005 were mainly due to increases in net production volumes of 25% and 26%, respectively, and increases in oil and gas prices of 28% and 33%, respectively. The increases in net revenues for the years ended December 31, 2006 and 2005 were partially offset by increases of $2.5 million and $4.5 million, respectively, in general and administrative and business and technology development expenses, excluding stock based compensation for the year ended December 31, 2006 when compared to the same period in 2005.

•

Investing Activities

Our investing activities used $25.6 million in cash for the year ended December 31, 2006 compared to $51.1 million used in investing activities for the same period in 2005. For 2006, we reduced our capital asset expenditures by $25.4 million principally as a result of reduced expenditures for new drilling at our Dagang project of $17.3 million, reduced exploration expenditures of $4.5 million at our Zitong project and reduced expenditures of $2.6 million on projects in Iraq. In 2006, we generated $6.0 million of cash from asset sales in the U.S. compared to nil for the year ended December 31, 2005. In addition, during 2005, we spent $18.6 million on the Ensyn merger, which was completed in April 2005, including $6.8 million on the acquisition of the remaining joint venture interest in the CDF, and we advanced $1.2 million under a consultancy agreement. These decreases in our investing activities for the year ended December 31, 2006 were partially offset by a $24.7 million increase in our non-cash working capital associated with our 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. Our capital expenditures declined by $3.2 million, principally as a result of reduced exploration expenditures in our California properties. For the year ended December 31, 2005, compared to the same period in 2004, we spent $13.5 million more on the Ensyn 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, the majority 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.

•

Financing Activities

Our financing activities provided $18.4 million in cash for year ended December 31 2006 compared to $38.6 million of cash provided by financing activities for the year ended December 31 2005. The $20.2 million decrease in cash from financing activities is mainly due to a $7.1 million decrease in cash from private placements and exercises of warrants and options in addition to a $13.7 million decrease in net debt financing.

In April 2006 the Company closed a private placement of 11.4 million special warrants at $2.23 per special warrant for a total of $25.4 million. Each special warrant entitles the holder to receive, at no additional cost, one common share and one common share purchase warrant. All of the special warrants were subsequently exercised for common shares and common share purchase warrants. Each common share purchase warrant originally entitled the holder to purchase one common share at a price of $2.63 per share until the fifth anniversary date of the closing. In September 2007, these warrants were listed on the Toronto Stock Exchange and the exercise price was changed to Cdn.$2.93. Of the proceeds, $4.0 million has been used to pay down long-term debt and the balance will be used to pursue opportunities for the commercial deployment of the Company’s heavy oil upgrading technology, to advance its oil and gas operations and for general corporate purposes.

Our financing activities provided $38.6 million in cash for the year ended December 31, 2005 compared to $25.5 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. 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.

Outlook for 2007

Our 2007 capital program budget ranges from approximately $20 million to $25 million and will encompass both continuing development of our existing producing oil and gas properties to maximize near-term cash flow and to further the development and deployment of our proprietary HTL oil upgrading technology. Management’s plans include alliances or other arrangements with entities with the resources to support the Company’s projects as well as project financing, debt and mezzanine financing or the sale of equity securities in order to generate sufficient resources to meet its capital investment and operating objectives. The Company intends to utilize revenue from existing operations to fund the transition of the Company to a heavy oil exploration, production and upgrading company and non-heavy oil related investments in our portfolio will be leveraged or monetized to capture value and provide maximum return for the Company. No assurances can be given that we will be able to enter into one or more alternative business alliances with other parties or raise additional capital. If we are unable to enter into such business alliances or obtain adequate additional financing, we will be required to curtail our operations, which may include the sale of assets.

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				2007				2008				2009				2010				After 2010
Consolidated Balance Sheets:
Note payable – current portion (Note 6)		$	2,147			$	2,147			$	—			$	—			$	—			$	—
Long term debt (Note 6)			4,237				—				3,825				412				—				—
Asset retirement obligation (Note 7)			1,953				—				742				17				484				710
Long term obligation (Note 8)			1,900				—				—				1,900				—				—
Other Commitments:
Interest payable (1)			653				437				212				4				—				—
Lease commitments (Note 8)			3,990				998				970				776				651				595
Zitong exploration commitment (Note 8)			906				906				—				—				—				—
Total		$	15,786			$	4,488			$	5,749			$	3,109			$	1,135			$	1,305