Form 10-K
Table of Contents

 
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
 
Form 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2010
Commission file number: 000-30586
 
(IVANHOE ENERGY INC. LOGO)
Ivanhoe Energy Inc.
(Exact name of registrant as specified in its charter)
     
Yukon, Canada   98-0372413
(State or other jurisdiction of   (IRS Employer
incorporation or organization)   Identification No.)
654-999 Canada Place
Vancouver, BC, Canada V6C 3E1
(604) 688-8323

(Address and telephone number of the registrant’s principal executive offices)
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
    The 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.
þ Yes o No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. o Yes þ No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. þ Yes o No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). o Yes o No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
             
Large accelerated filer o   Accelerated filer þ   Non-accelerated filer o   Smaller reporting company o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
o Yes þ No
As of June 30, 2010, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $530,616,815, based on the Toronto Stock Exchange closing price on that date. At March 4, 2011, the registrant had 343,931,658 common shares outstanding.
 
 

 

 


 

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 Exhibit 10.18
 Exhibit 10.19
 Exhibit 10.20
 Exhibit 10.21
 Exhibit 21.1
 Exhibit 23.1
 Exhibit 23.2
 Exhibit 31.1
 Exhibit 31.2
 Exhibit 32.1
 Exhibit 32.2
 Exhibit 99.1
ABBREVIATIONS
As generally used in the oil and gas industry and in this Annual Report on Form 10-K (“Annual Report”), the following terms have the following meanings:
                     
bbl
  =   barrel   mcf   =   thousand cubic feet
bbls/d
  =   barrels per day   mcf/d   =   thousand cubic feet per day
boe
  =   barrel of oil equivalent   mmcf   =   million cubic feet
boe/d
  =   barrels of oil equivalent per day   mmcf/d   =   million cubic feet per day
mbbls
  =   thousand barrels   mmbbls   =   million barrels
mbbls/d
  =   thousand barrels per day   mmbls/d   =   million barrels per day
mboe
  =   thousands of barrels of oil equivalent   mmbtu   =   million British thermal units
mboe/d
  =   thousands of barrels of oil equivalent per day   tcf   =   trillion cubic feet
Oil equivalents compare quantities of oil with quantities of gas or express these different commodities in a common unit. A boe is derived by converting six thousand cubic feet of gas to one barrel of oil (6 mcf/1 bbl). Boes may be misleading, particularly if used in isolation. The conversion ratio is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

 

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CURRENCY AND EXCHANGE RATES
Unless otherwise specified, all reference to “dollars” or to “$” are to US dollars and all references to “Cdn$” are to Canadian dollars. The noon-day exchange rates for Cdn$1.00, as reported by the Bank of Canada, were:
                                         
(US$)   2010     2009     2008     2007     2006  
Closing
    1.01       0.96       0.82       1.01       0.86  
High
    1.01       0.97       1.03       1.09       0.91  
Low
    0.93       0.77       0.77       0.84       0.85  
Average Noon
    0.93       0.88       0.94       0.93       0.88  
On March 4, 2011, the noon-day exchange rate was US$0.97 for Cdn$1.00.
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
Certain statements in this Annual Report, including those appearing in Items 1 and 2 — Business and Properties and Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”), constitute “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 (the “Exchange Act”), and Section 27A of the United States Securities Act of 1933, as amended (the “Act”). Such forward-looking statements involve known and unknown risks, uncertainties and other factors which may cause our actual results, performance or achievements, or other future events, to be materially different from any future results, performance or achievements or other events expressly or implicitly predicted by such forward-looking statements. Such risks, uncertainties and other factors include:
   
our short history of limited revenue, losses and negative cash flow from our current exploration and development activities in Canada, Ecuador, China and Mongolia;
   
our limited cash resources and consequent need for additional financing;
   
our ability to raise additional financing when it is required or on acceptable terms;
   
the potential success of our Heavy-to-Light or HTLTM technology;
   
the potential success of our oil and gas exploration and development properties in Canada, Ecuador, China and Mongolia;
   
oil price volatility;
   
oil and gas industry operational hazards and environmental concerns;
   
government regulation and requirements for permits and licenses, particularly in the foreign jurisdictions in which we carry on business;
   
title matters;
   
risks associated with carrying on business in foreign jurisdictions;
   
conflicts of interests;
   
competition for oil and gas exploration properties from larger, better financed oil and gas companies; and
   
other statements contained herein regarding matters that are not historical facts.
Forward-looking statements can often be identified by the use of forward-looking terminology such as “may”, “expect”, “intend”, “estimate”, “anticipate”, “believe” or “continue” or the negative thereof or variations thereon or similar terminology. We believe that any forward-looking statements made are reasonable based on information available to us on the date such statements were made. However, no assurance can be given as to future results, levels of activity and achievements. Except as required by law, we undertake no obligation to update publicly or revise any forward-looking statements contained in this report. All subsequent forward-looking statements, whether written or oral, attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by these cautionary statements.
AVAILABLE INFORMATION
The principal executive offices of Ivanhoe Energy Inc. (“Ivanhoe,” the “Company,” “we,” “our,” or “us”) are 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.

 

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Electronic copies of the Company’s filings with the United States Securities and Exchange Commission (the “SEC”) and the Canadian Securities Administrators (the “CSA”) are available, free of charge, through our website (www.ivanhoeenergy.com) or, upon request, by contacting our investor relations department at (403) 817-1108.
Alternatively, the SEC and the CSA each maintains a website (www.sec.gov and www.sedar.com) that contains our reports, proxy and information statements and other published information that have been filed or furnished with the SEC and the CSA. The information on our website is not, and shall not be, deemed to be part of this Annual Report.
PART I
ITEMS 1 AND 2:  
BUSINESS AND PROPERTIES
GENERAL
Ivanhoe is an independent international heavy oil development and production company focused on pursuing long term growth in its reserve base and production using advanced technologies, including its HTL™ technology. Core operations are in Canada, Ecuador, China and Mongolia, with business development opportunities worldwide. Ivanhoe is the listed parent company and is responsible for Canadian operations. Operations in Latin American are conducted through Ivanhoe Energy Latin America Inc., while activities in China and Southeast Asia are operated by Sunwing Energy Ltd. (“Sunwing”).
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. On June 24, 1999, Black Sea Energy Ltd. merged with Sunwing, and we changed our name to Ivanhoe.
In 2005, Ivanhoe completed a merger with Ensyn Group Inc. (“Ensyn”) acquiring the proprietary, patented heavy oil upgrading process called HTL™. In July 2008, the Company acquired oil sand assets in the Athabasca region of Canada. Later in 2008, we signed a contract with the Ecuador state oil companies to explore and develop Ecuador’s Pungarayacu heavy oil field in Block 20. In 2009, Ivanhoe sold its wholly owned subsidiary, Ivanhoe Energy (USA) Inc., disposing of all our oil and gas exploration and production operations in the United States (“US”). We also acquired a production-sharing contract for the Nyalga Block XVI in Mongolia in 2009, through a merger with PanAsian Petroleum Inc., a privately-owned corporation.
CORPORATE STRATEGY
Ivanhoe continues to pursue its core strategies, which are:
   
Utilize long-standing knowledge and relationships in the Far East to pursue conventional oil and gas production and exploration opportunities;
   
Seek out heavy oil development projects globally that have operational needs that can benefit from our proprietary HTLTM technology; and
   
Bias new country entry and business development to projects that, because of their remote setting, geo-political status or operational needs, have been overlooked by the broader industry, subsequently expanding efforts in the new locations to more conventional oil and gas industry activities.
Pursuing Natural Gas in China
Ivanhoe’s wholly-owned subsidiary, Sunwing, has been conducting operations in China since the mid-1990s. In particular, Sunwing is focused on a key natural gas exploration project (the Zitong Block) in Sichuan Province of China. Sichuan is the oldest and one of the most productive gas producing regions of China. Sinopec and PetroChina have made significant gas discoveries in blocks adjacent to Sunwing’s Zitong Block.
The Sichuan Basin, located in central China approximately 930 miles southwest of Beijing, is the country’s largest gas-producing region, currently producing more than 800 mmcf/d and estimated by Chinese officials to contain a natural gas resource potential of 260 tcf. There is a strong and growing local market for natural gas, with approximately 120 million people living within the basin and with well-developed grid connections to adjacent industrial and population areas.
Natural gas sales are regulated in China and current prices are approximately $5.00/mcf at the wellhead. As part of China’s commitment to develop cleaner sources of energy, demand for natural gas is projected to continue to grow in the country and Sunwing’s goal is to tap into this burgeoning market.

 

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Importance of the Heavy Oil Segment of the Oil and Gas Industry
The global oil and gas industry is being impacted by the declining availability of low cost replacement reserves. This has resulted in volatility in oil markets and marked shifts in the demand and supply landscape. Ivanhoe believes that long term demand and the natural decline of conventional oil production will see the development of higher cost and lower value resources, including heavy oil.
Heavy oil developments can be segregated into two types: conventional heavy oil that flows to the surface without steam enhancement and non-conventional heavy oil and bitumen. While the Company focuses on the non-conventional heavy oil, both types of oil play an important role in our corporate strategy.
Production of conventional heavy oil has been steadily increasing worldwide, led by Canada and Latin America but with significant contributions from most other oil basins, including the Middle East and the Far East, as producers struggle to replace declines in light oil reserves. Even without the impact of the large non-conventional heavy oil projects in Canada and Venezuela, world heavy oil production has become increasingly more common.
With regard to non-conventional heavy oil and bitumen, a dramatic increase in interest and activity has been fueled by higher prices, in addition to various key advances in technology, including improved remote sensing, horizontal drilling and new thermal techniques. This has enabled producers to more effectively access the extensive heavy oil resources around the world.
These newer technologies, together with higher oil prices, have generated increased interest in heavy oil resources. Nevertheless, remaining challenges for profitable exploitation include: i) the requirement for steam and electricity to help extract heavy oil; ii) the need for diluent to move the oil once it is at the surface; iii) the heavy versus light oil price differentials that the producer is faced with when the product gets to market; and iv) conventional upgrading technologies are limited to very large scale, high capital cost facilities. These challenges can lead to “distressed” assets, where economics are poor, or to “stranded” assets, where the resource cannot be economically produced and lies fallow.
Ivanhoe’s Value Proposition
With the application of the HTL™ process, Ivanhoe seeks to address the key heavy oil development challenges and can do so at a relatively small minimum economic scale.
Ivanhoe’s HTL™ upgrading is a partial upgrading process that is designed to operate in facilities as small as 10,000 to 30,000 bbls/d. This is substantially smaller than the minimum economic scale for conventional stand-alone upgraders such as delayed cokers, which typically operate at scales of over 100,000 bbls/d. The HTL™ process is based on carbon rejection, a tried and tested concept in heavy oil processing. The key advantage of HTL™ is that it is a very fast process, with processing times typically under a few seconds. This results in smaller, less costly facilities and eliminates the need for hydrogen addition, an expensive, large minimum scale step typically required in conventional upgrading. HTL™ has the added advantage of converting the by-products from the upgrading process into onsite energy, rather than generating large volumes of low value coke.
The HTL™ process offers significant advantages as a field located upgrading alternative, integrated with the upstream heavy oil production operation. HTL™ provides four key benefits to the producer:
   
virtual elimination of external energy requirements for steam generation and/or power for upstream operations;
   
elimination of the need for diluent or blend oils for transport;
   
capture of the majority of the heavy versus light oil value differential; and
   
relatively small minimum economic scale of operations suited for field upgrading and for smaller field developments.
The economics of a project are effectively dictated by the advantages that HTL™ 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 Ivanhoe will have to establish its unique value proposition.
Implementation Strategy
Ivanhoe is an oil and gas company with a unique technology which addresses several major problems confronting the oil and gas industry today and the Company believes it has a competitive advantage because of its patented upgrading process. In addition, because Ivanhoe has experienced thermal recovery teams, the Company is in a position to add value and leverage its technology advantage by working with partners on stranded heavy oil resources around the world.

 

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The Company’s continuing strategy is as follows:
   
Advance its two key heavy oil projects — in Canada and Ecuador. Continue to deploy personnel and financial resources in support of the Company’s goal to become a significant heavy oil producer.
   
Advance the HTL™ process. Additional development work will continue to advance the HTL™ process through the commercial application of HTL™ upgrading in Canada, Ecuador and beyond.
   
Advance its natural gas project in the Zitong Block in Sichuan Province, China. Through its wholly-owned subsidiary, Sunwing Energy, proceed with additional planning and operational analysis to develop an appraisal program leading to a full development plan for the Zitong block.
   
Enhance the Company’s financial position to support its major projects. Implementation of large projects requires significant capital outlays. The Company is working on various financing initiatives and establishing the relationships required for future development activities.
   
Build internal capabilities. The Company continues to seek to build its internal leadership and technical capabilities through the addition of key personnel associated with each major project.
   
Continue to deploy the personnel and the financial resources to capture additional opportunities for development projects utilizing the Company’s HTL™ process. Commercialization of the Company’s upgrading process requires close alignment with partners, suppliers, host governments and financiers.
PROPERTY DESCRIPTIONS
Our oil and gas operations are broken down into three geographic areas: Canada, Ecuador and Asia. The Business and Technology Development area captures costs incurred in the pursuit of projects throughout the world as well as expenses incurred to develop, enhance and identify improvements in the application of the HTL™ technology.
Production, revenues, net income, capital expenditures and identifiable assets for these segments appear in Note 11 to the consolidated financial statements and in the MD&A in this Annual Report.
Integrated Oil and Gas Properties
Canada
Tamarack, acquired in 2008, is a 6,880 acre block located approximately 10 miles northeast of Fort McMurray, Alberta, Canada. Ivanhoe holds a 100% working interest in the property, subject only to a 20% back-in right held by Talisman Energy Canada (“Talisman”), which expires in mid-2011.
Our independent reserve evaluator, GLJ Petroleum Consultants Ltd. (“GLJ”), has assigned total 3P reserves of 220 mmbbls of bitumen to Tamarack. It is anticipated that the resources will be developed utilizing steam assisted gravity drainage (“SAGD”) technology. The Company expects that 12 well pads and approximately 160 SAGD well pairs will be required to fully develop and produce the targeted resource base.
In March 2010, a 28 well winter delineation program was completed, which provided information necessary for regulatory filings. In November 2010, Ivanhoe filed a comprehensive Environmental Impact Assessment with the Government of Alberta. In support of the application, Basic Engineering and Design and Front End Engineering and Design were completed to generate a Class III (+25/-20%) capital cost estimate. Subject to regulatory approvals from the Alberta Energy Resources Conservation Board and Alberta Environment, construction at Tamarack could commence in mid-2012, with commissioning and start-up of the production facilities expected in the fourth quarter of 2013.
Ecuador
In October 2008, Ivanhoe Energy Ecuador Inc., an indirect wholly owned subsidiary, signed a 30 year contract with the Ecuador state oil companies Petroecuador and Petroproduccion. The contract gives us the right to explore and develop the Pungarayacu heavy oil field in Block 20, an area of 426 square miles, approximately 125 miles southeast of Quito, Ecuador’s capital. We anticipate using HTL™ technology, as well as providing advanced oilfield technology, expertise and capital to develop, produce and upgrade heavy oil from the Pungarayacu field. The Company may also explore for lighter oil in the contract area and use any light oil discoveries to blend with the heavy oil for delivery to Petroproduccion.
In 2010, the IP-5b well was successfully drilled, cored and logged to a total depth of 1,080 feet. The well was perforated in the Hollin oil sands and steam was successfully injected into the reservoir resulting in production of heated heavy oil. The Company’s IP-15 well, drilled in 2010, encountered certain cementing and completion problems during steam injection operations and testing at the well was suspended without recovering oil. Ivanhoe sees significant variability between the two well locations, supporting the view that geological faulting is prevalent in Block 20 due to the close proximity of the Andes, directly to the west of the block. We plan to commence a seismic program following testing operations at IP-5b to increase understanding of the geological faulting and to help determine locations for our next appraisal wells.

 

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Conventional Oil and Gas Properties
Asia
China
Zitong
In November 2002, we entered into a 30 year production sharing contract with China National Petroleum Corporation (“CNPC”) for the Zitong block, which covers an area of approximately 658,000 gross acres after contractual relinquishments in the Sichuan basin. The parties will jointly participate in the development and production of any commercially viable deposits, with production rights limited to the later of 2032 or 20 years of continuous production. In 2006, we farmed out 10% of our working interest in the Zitong block to Mitsubishi Gas Chemical Company Inc. of Japan for $4.0 million.
In Phase I of the contract, Ivanhoe reprocessed 1,649 miles of existing 2D seismic data and acquired 705 miles of new 2D seismic data. Two wells were drilled and although both wells encountered expected reservoirs and gas was tested on the second well, neither well demonstrated commercially viable flow rates and both wells were suspended.
In Phase II, two wells were drilled in 2010 at the Zitong block, both resulting in gas discoveries. The Yixin-2 well was tested in December 2010 with gas flowing from the Xu-4 Formation. Following initial flow and pressure tests, the well was shut-in for pressure build-up. The Zitong-1 well reached total depth in December 2010 and was tested in January 2011, with gas flowing from the Xu-4 Formation. The well was subsequently shut-in to record reservoir pressure build-up and allow testing of the shallower, Xu-5 formation.
Following the drilling of the Zitong-1 and Yixin-2 wells, areas excluding those identified for development and future production were to be relinquished. In January 2011, Ivanhoe received notice that the exploration period has been extended for an additional six months.
Dagang
Ivanhoe’s oil production originates in the Kongnan oilfield in Dagang, Hebei Province, China (the “Dagang field”). We have a 30 year production sharing contract with CNPC, covering an area of 10,255 gross acres. From 2001 to 2007, we drilled 44 wells and commercial production commenced on January 1, 2009. The project reached cost recovery in September 2009 and our working interest decreased to 49%. Operations in the Dagang field will revert to CNPC at the end of the 20 year production phase of the contract or earlier if the field is abandoned.
In 2010, quotas restricted production to 70,000 gross tonnes or 1,400 bbls/d gross. Actual production in 2010 averaged 750 bbls/d net. Production quotas in 2011 are set at 80,000 gross tonnes or approximately 1,600 bbls/d gross.
Mongolia
Through a merger with PanAsian Petroleum Inc. in November 2009, we acquired a production sharing contract for the Nyalga Block XVI in the Khenti and Tov provinces in Mongolia. The block covers an area of approximately 3.1 million gross acres, after a 25% relinquishment in 2010. The five year exploration period is divided into three consecutive phases, consisting of two years (“Phase I”), one year (“Phase II”) and two years (“Phase III”), with the ability to nominate a two year extension following Phase I or Phase II.
During the initial seismic program, approximately 16% of the block in the Delgerkhaan area was declared by the Mongolian government to be a historical site and operations in this area were suspended. A letter from the Mineral Resources and Petroleum Authority of Mongolia (“MRPAM”) stated that the obligations under year one of Phase I would be extended for one year from the time the Company is allowed to re-enter the suspended area. To date, access has not been granted and discussions with MRPAM are ongoing. As a result, the government has adjusted the dates in which the project year begins. Phase II is now considered to have commenced on July 20, 2010.

 

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From late 2009 through the first quarter of 2010, the Company acquired an additional 465 kilometres of 2-D seismic across Block XVI, for a total of 925 kilometres of 2-D seismic data over the Kherulen sub-basin. In 2010, preparations commenced for a five well drilling program and a seismic acquisition program. The first exploratory location has been identified and we expect to initiate drilling operations in Mongolia in the first half of 2011.
RESERVES, PRODUCTION AND RELATED INFORMATION
In addition to the information provided below, please refer to the “Supplementary Disclosures About Oil and Gas Production Activities (Unaudited)” set forth in Item 8 in this Annual Report for certain details regarding the Company’s oil and gas proved reserves, the estimation process and production by country. We have not filed with nor included in reports to any other US federal authority or agency, any estimates of total proved oil reserves since the beginning of the last fiscal year.
The following table presents estimated proved, probable and possible oil reserves as of December 31, 2010:
Summary of Oil and Gas Reserves Using Average 2010 Prices(1)
                                 
    Canada     China        
(mbbl)   Tamarack     Dagang     Other     Total  
 
                               
Proved
                               
Developed
          1,186       79       1,265  
Undeveloped
          473             473  
 
                       
Total proved
          1,659       79       1,738  
 
                               
Probable
                               
Developed
          322             322  
Undeveloped
    175,684       470             176,154  
 
                               
Possible
                               
Developed
                       
Undeveloped
    43,809                   43,809  
(1)  
Reserves are the Company’s total gross reserves before royalty deductions.
Canada
Probable and Possible Reserves
In 2010, probable and possible reserves increased from nil in 2009 to 219,493 mbbls as a result of completing a 28 well delineation drilling program on the Tamarack lands, further technical evaluation and the submission of Ivanhoe’s regulatory application to the Government of Alberta in November 2010. Further reserve development is subject to regulatory approval and availability of financing.
Possible reserves are within the Tamarack project application area, but have a lower degree of certainty compared to our probable reserves due to lower quality reservoir characteristics or decreased certainty based on the level of reservoir delineation.
Basis of Reserves Estimates
Probable and possible reserves will be developed using a SAGD thermal recovery process, which has been successfully demonstrated in similar projects in the Athabasca Oil Sands region. Recovery estimates for Tamarack are based on applying appropriate recovery factors to original oil-in-place estimates developed through detailed reservoir characterization. The reservoir characterization is based on information gathered during historical field delineation programs. Recovery factors applied to the oil-in-place estimates are the result of simulation and analytical models, incorporating the actual performance of existing analog projects.

 

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China
Proved Reserves
Proved reserves at December 31, 2010, were 1,738 mbbls compared to 1,101 mbbls at December 31, 2009, an increase of 58% after 2010 production. Proved reserves increased due to in-field performance improvements from continued water injections, a partial natural water drive and our ongoing hydraulic fracture stimulation program in the Dagang field. Drilling activity in late December 2010 was successful and, in combination with geological review and reservoir mapping, supported additional future drilling locations. Proved reserves also benefitted from a pool extension due to the addition of re-activated wells in the periphery of the reservoir.
The transfer of reserves from proved undeveloped to the proved category was immaterial in 2010.
Probable Reserves
At December 31, 2010, probable reserves in China were 792 mbbls, an increase of 137% over the 334 mbbls reported at December 31, 2009. Additional probable reserves were assigned based on production improvements and increased recovery factors discussed under proved reserves.
Basis of Reserve Estimates
Reserve estimates were calculated using recovery forecasts based on historical production, supported by volumetric estimates using geological parameters. Recoveries rarely exceed 15% of the volumetrically calculated original oil-in-place per well spacing, which is judged acceptable for a water flood in a light oil reservoir. Improvements in production history and production declines are used for a review of producing reserves. With further mapping and geological reviews, proved and probable undeveloped reserves may then be assigned to future drilling and well optimizations.
Internal Control Over Reserve Estimation
Management is responsible for the estimates of oil and gas reserves and for preparing related disclosures. Estimates and related disclosures are prepared in accordance with SEC requirements, generally accepted industry practices in the US and the standards of the Canadian Oil and Gas Evaluation Handbook modified to reflect SEC requirements. Our reserve estimates and disclosures may differ from other Canadian issuers who follow National Instrument 51-101, “Standards of Disclosure for Oil and Gas Activities” (“NI 51-101”). Significant differences between SEC and Canadian reserve estimates and disclosures are described in the Special Note to Canadian Investors on page 10.
The process of estimating reserves requires complex judgments and decision making based on available geological, geophysical, engineering and economic data. To estimate the economically recoverable oil and gas reserves and related future net cash flows, we consider many factors and make various assumptions including:
   
expected reservoir characteristics based on geological, geophysical and engineering assessments;
   
future production rates based on historical performance and expected future operating and investment activities;
   
future oil and gas prices and quality differentials;
   
assumed effects of regulation by governmental agencies; and
   
future development and operating costs.
We believe these factors and assumptions are reasonable based on the information available to us at the time we prepared our estimates. However, these estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change.
Reserve estimates are categorized by the level of confidence that they will be economically recoverable. Proved reserves are those quantities of oil and gas, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible in future years from known reservoirs under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and gas actually recovered will equal or exceed the estimate. To achieve reasonable certainty, the technologies used in the estimation process have been demonstrated to yield results with consistency and repeatability.

 

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Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Therefore, probable reserves have a higher degree of uncertainty than proved reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. Although possible reserve locations are found by “stepping out” from proved reserve locations, estimates of probable and possible reserves are, by their nature, more speculative than estimates of proved reserves and, accordingly, are subject to substantially greater risk of being realized.
Our reserve estimates were prepared by GLJ and reviewed by our in-house Senior Engineering Advisor (“SEA”). Our SEA is a professional engineer, with over 25 years of experience in the oil industry focused on heavy oil recovery techniques. His past experience includes international positions responsible for thermal horizontal and vertical well development projects using state-of-the-art reservoir management techniques and advanced 3D reservoir visualization methods to integrate complex data sets. He has experience supervising project expansions and investigating new development scenarios using reservoir simulation and advanced economic modeling.
All reserve information in this Annual Report is based on estimates prepared by GLJ. The technical personnel responsible for preparing the reserve estimates at GLJ meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas by the Society of Petroleum Engineers. GLJ is an independent firm of petroleum engineers, geologists, geophysicists and petrophysicists; they do not own an interest in our properties and are not employed on a contingent fee basis.
Our Board of Directors reviews the current reserve estimates and related disclosures as presented by the independent qualified reserves evaluators in their reserve report. Our Board of Directors has approved the reserve estimates and related disclosures.
Special Note to Canadian Investors
Ivanhoe is a SEC registrant and files annual reports on Form 10-K; accordingly, our reserves estimates and regulatory securities disclosures are prepared based on SEC disclosure requirements. In 2003, certain Canadian securities regulatory authorities adopted NI 51-101 which prescribes standards that Canadian companies are required to follow in the preparation and disclosure of reserves and related information.
In 2010, we re-applied for, and received, exemptions from certain NI 51-101 requirements. These exemptions permit us to substitute disclosures based on SEC requirements for much of the annual disclosure required by NI 51-101 and to prepare our reserves estimates and related disclosures in accordance with SEC requirements, generally accepted industry practices in the US 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 reserve quantities disclosed in this Annual Report represent net reserves calculated on an average, first-day-of-the-month price during the 12 month period preceding the end of the year for 2010, using the standards contained in SEC Regulations S-X and S-K and Accounting Standards Codification 932 Extractive Activities — Oil and Gas (section 235-55), formerly Statement of Financial Accounting Standards No. 69, “Disclosures About Oil and Gas Producing Activities”. Such information differs from the corresponding information prepared in accordance with Canadian disclosure standards under NI 51-101. The primary differences between the current SEC requirements and the NI 51-101 requirements are as follows:
   
SEC registrants apply SEC reserves definitions and prepare their reserves estimates in accordance with SEC requirements and generally accepted industry practices in the US, whereas NI 51-101 requires adherence to the definitions and standards promulgated by the COGE Handbook;
   
the SEC mandates disclosure of proved reserves calculated using an average, first-day-of-the-month price during the 12 month period preceding and existing costs only, whereas NI 51-101 requires disclosure of reserves and related future net revenues using forecasted prices, with additional constant pricing disclosure being optional;
   
the SEC mandates disclosure of reserves by geographic area only, whereas NI 51-101 requires disclosure of more reserve categories and product types; and
   
the SEC leaves the engagement of independent qualified reserves evaluators to the discretion of a company’s board of directors, whereas NI 51-101 requires issuers to engage such evaluators.
The foregoing is a general and non-exhaustive description of the principal differences between SEC disclosure requirements and NI 51-101 requirements. Please note that the differences between SEC and NI 51-101 requirements may be material.

 

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Production, Sales Prices and Production Costs
                         
    2010     2009     2008  
Oil production (bbls/d)
    788       1,276       1,339  
Average sales price ($/bbl)
    75.52       53.60       98.73  
Average operating costs (1) ($/bbl)
    33.05       21.88       43.92  
(1)  
Average operating costs per unit of production, based on net interest after royalties, represent lifting costs, including a windfall gain levy. According to the “Administrative Measures on Collection of Windfall Gain Levy on Oil Exploitation Business,” enterprises exploiting and selling oil in China are subject to a windfall gain levy (the “Windfall Levy”) if the monthly weighted average price of oil is above $40.00/bbl. Excludes depletion and depreciation, income taxes, interest, selling and general administrative expenses.
Ivanhoe’s oil production originates in Asia, specifically the Dagang and Daqing fields in China. The majority of our production comes from Dagang and is sold to the national petroleum company.
Producing Oil Wells
The company does not have any producing gas wells. Producing oil wells are reported below.
                                                 
    2010     2009     2008  
    Gross(1)     Net(2)     Gross(1)     Net(2)     Gross(1)     Net(2)  
Asia
    44.0       21.6       44.0       21.6 (3)     44.0       36.1  
(1)  
Gross wells are the total number of wells in which a working interest is owned.
 
(2)  
Net wells are the sum of fractional working interests owned in gross wells.
 
(3)  
Our working interest in net wells was reduced from 82% to 49% as stipulated by the governing production sharing contracts upon the Company completing the recovery of its development investments in September 2009.
Drilling Activity
At December 31, 2010, we were actively drilling the Zitong-1 and Yixin-2 wells in our Zitong project and one well in our Dagang field. No wells were completed in 2010. The Company did not drill any exploration or development wells in 2009 or 2008.
Acreage
                                 
    Developed Acres     Undeveloped Acres(1)  
    Gross     Net     Gross     Net  
Canada
                7,520       7,520  
Ecuador
                272,639       272,639  
Asia — China(2)
    1,525       747       664,314       595,338  
Asia — Mongolia
                3,107,907       3,107,907  
(1)  
Undeveloped acreage is considered to be those acres on which wells have not been drilled or completed to a point that would permit production of commercial quantities of oil and gas regardless of whether or not such acreage contains proved reserves.
 
(2)  
The number of developed acres disclosed in respect of our China properties relates only to those portions of the field covered by our producing operations and does not include the remaining portions of the field previously developed by CNPC.
The Tamarack lease in Canada will expire in October 2016, but Ivanhoe has sufficient drill density to be granted a continuation by the Alberta Department of Energy one year prior to expiry or upon first production, whichever comes first. Although production activities from the Tamarack lease is anticipated to commence in 2013, we plan to apply for a continuation of the lease prior to its expiration if the project is delayed.
We signed a specific services contract with affiliated entities of the State of Ecuador in October 2008 that allows us to develop Block 20 for a term of 30 years, extendable by mutual agreement of the parties, for two additional periods of five years each, depending on the interests of the State and in conformity with local laws.
Acreage in the Dagang field will return to CNPC in 2027. Following the completion of Phase II of the Zitong Contract, the remaining acreage must be relinquished to CNPC except for areas identified for development and future production, which will be relinquished upon termination of the production sharing contract in 2032.

 

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Acreage in Mongolia is subject to periodic relinquishments up to the end of the exploration period and the remaining acreage designated for appraisal and development will expire 20 years after the final commercial discovery on the Nyalga block.
BUSINESS AND TECHNOLOGY DEVELOPMENT
The Company’s Business and Technology Development segment captures HTL™ activities as well as costs associated with the pursuit of new business development opportunities.
Technology Development
In April 2005, Ivanhoe acquired Ensyn and thereby obtained an exclusive, irrevocable license to the HTL™ process for all applications other than biomass. We have since continued to expand patent coverage to protect innovations to the HTL™ technology and to significantly extend Ivanhoe’s portfolio of HTL™ intellectual property. Ivanhoe is the assignee of three granted US patents and currently has three US patent applications pending. In other countries, 47 patents are pending. In addition, Ivanhoe owns exclusive, irrevocable licenses to 21 global patents as well as proprietary technological knowledge for the rapid thermal processing process of petroleum.
Ivanhoe operates a feedstock test facility (“FTF”) at the Southwest Research Institute in San Antonio, Texas. The FTF is a small 10-15 bbls/d, highly flexible state-of-the-art facility which will permit analysis of crude oil in small volumes. In 2010, the FTF was used to support basic and front-end engineering for a commercial-scale HTL™ plant for the Tamarack project in Canada. Also, the unit was used to support conceptual design for several projects, including Pungarayacu in Ecuador. As we continue to advance our technology, the FTF will serve an integral role in supporting the Company’s commercial operations.
The FTF replaced the Commercial Demonstration Facility (“CDF”), constructed in 2004. The CDF was decommissioned in 2010 and all future testing will be conducted at the FTF.
Business Development
The Company pursues HTL™ business development opportunities globally, with an emphasis on creating value from stranded resources or resource accumulations considered too small to be economically viable using other technologies. In 2010, HTLTM heavy oil and selected conventional oil opportunities were pursued in North and South America, the Middle East and North Africa.
CERTAIN FACTORS AFFECTING THE BUSINESS
Competition
The oil and gas industry is highly competitive. Our position in the oil and gas industry, which includes the search for and development of new sources of supply, is particularly competitive. Our competitors include major, intermediate and junior oil and gas companies and other individual producers and operators, many of which have substantially greater financial and human resources and more developed and extensive infrastructure. Our larger competitors, by reason of their size and relative financial strength, can more easily access capital markets and may enjoy a competitive advantage in the recruitment of qualified personnel. They may be able to absorb the burden of any changes in laws and regulations in the jurisdictions in which we do business more easily, adversely affecting our competitive position. Our competitors may be able to pay more for producing oil and gas properties and may be able to define, evaluate, bid for, and purchase a greater number of properties and prospects. Further, these companies may enjoy technological advantages and may be able to implement new technologies more rapidly. Our ability to acquire additional properties in the future will depend upon our ability to conduct efficient operations, to evaluate and select suitable properties, implement advanced technologies, and to consummate transactions in a highly competitive environment. The oil and gas industry also competes with other industries in supplying energy, fuel and other needs of consumers.

 

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Environmental Regulations
Our conventional oil and gas and HTL™ operations are subject to various levels of government laws and regulations relating to the protection of the environment in the countries in which we operate. We believe that our operations comply in all material respects with applicable environmental laws.
Environmental legislation imposes, among other things, restrictions, liabilities and obligations in connection with the generation, handling, storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases and emissions of various substances to the environment. As well, environmental regulations are imposed on the qualities and compositions of the products sold and imported. Environmental legislation also requires that wells, facility sites and other properties associated with our operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. In addition, certain types of operations, including exploration and development projects and significant changes to certain existing projects, may require the submission and approval of environmental impact assessments. Compliance with environmental legislation can require significant expenditures and failure to comply with environmental legislation may result in the imposition of fines and penalties and liability for clean-up costs and damages. We anticipate that changes in environmental legislation may require, among other things, reductions in emissions to the air from our operations and result in increased capital expenditures.
Operations in Canada are governed by comprehensive federal, provincial and municipal regulations. We have submitted the Regulatory Application/Environmental Impact Assessment for the Tamarack project to the Government of Alberta. The regulatory process is expected to take approximately 18 to 24 months. In addition, the Company will be required to obtain numerous ancillary approvals prior to commencing operations and will be subject to ongoing environmental monitoring and auditing requirements.
China, Mongolia and Ecuador continue to develop and implement more stringent environmental protection regulations and standards for different industries. Projects are currently monitored by governments based on the approved standards specified in the environmental impact statement prepared for individual projects.
Government Regulations
Our business is subject to certain federal, state, provincial and local laws and regulations in the regions in which we operate relating to the exploration for, and development, production and marketing of, crude oil and gas, as well as environmental and safety matters. In addition, the Chinese government regulates various aspects of foreign company operations in China. Such laws and regulations have generally become more stringent in recent years in the US, Canada, Ecuador and China, often imposing greater liability on a larger number of potentially responsible parties. Because the requirements imposed by such laws and regulations are frequently changed, we are not able to predict the ultimate cost of compliance.
EMPLOYEES
As at December 31, 2010, we had 211 employees actively engaged in the business. None of our employees are unionized.
ITEM 1A:  
RISK FACTORS
Our operations are exposed to various risks, some of which are common to others in the oil and gas industry and some of which are unique to our operations. Certain risks set out below constitute “forward-looking statements” and readers should refer to the “Special Note Regarding Forward-Looking Statements” set out on page 3 of this Annual Report.
Our ability to continue as a going concern may be adversely affected by inadequate funding
We have a history of operating losses and cash flow from operating activities will not be sufficient to meet our current obligations and fund future capital projects. Historically, we have relied upon equity capital as our principal source of funding. Continuation of the Company is dependent upon our ability to obtain additional capital to preserve our interests in current projects and to meet obligations associated with future projects. We may seek financing from a combination of strategic investors and/or public and private debt and equity markets, either at a parent company level or at the project level. There is no assurance that we will be able to obtain such financing on favorable terms, if at all, and any future equity issuances may be dilutive to investors. Obtaining financing may be hampered by the inability to attract strategic investors to our projects on acceptable terms, volatility in equity and debt markets and a sustained decrease in the market price of our common shares. Without access to financing, we may not be able to continue as a going concern.

 

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We may not be able to fund our substantial capital requirements
Our business is capital intensive and the advancement of our exploration projects in China and Mongolia, development projects in Canada and Ecuador and HTL™ initiatives require significant funding. Since cash flows from existing operations are insufficient to fund future capital expenditures, we intend to finance future capital projects with a combination of strategic investors and/or public and private debt and equity markets, either at a parent company level or at the project level or from the sale of existing assets. There is no assurance that we will be able to obtain such financing on favorable terms, if at all, and any future equity issuances may be dilutive to investors. Obtaining financing in the future may be hampered by the inability to attract strategic investors to our projects on acceptable terms, volatility in equity and debt markets and a sustained decrease in the market price of our common shares. If we fail to obtain adequate funding when needed, we may have to delay or forego 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.
We have fixed and contingent payment obligations to Talisman
As a result of acquiring our Athabasca heavy oil leases from Talisman in 2008, we have fixed and contingent payment obligations to Talisman. These obligations include a Cdn$40.0 million convertible promissory note (the “Convertible Note”) that, unless converted into Ivanhoe common shares, is due in July 2011, and a contingent payment of up to Cdn$15.0 million that will become due and payable if and when the requisite government and other approvals to develop the northern border of one of the Athabasca heavy oil leases are obtained. We intend to finance such future payments through debt and equity markets, arrangements with third parties, either at the Ivanhoe parent company level or at the subsidiary or project level or from the sale of existing assets. There is no assurance that we will be able to obtain such financing on favorable terms, if at all, and any future equity issuances may be dilutive to investors. Obtaining financing in the future may be hampered by the inability to attract strategic investors to our projects on acceptable terms, volatility in equity and debt markets and a sustained decrease in the market price of our common shares. Failure to obtain such additional financing could put us in default of our obligations to Talisman, which are secured by a first fixed charge and security interest in favor of Talisman over the Athabasca heavy oil leases and a general security interest in all of our present and after acquired property other than the common shares we own in our subsidiaries. In the case of such default, Talisman could foreclose on the secured assets, including the leases.
The volatility of oil prices may affect our financial results
Our revenues, operating results, profitability and future growth are highly dependent on the price of 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.
Oil prices may fluctuate widely in response to relatively minor changes in supply and demand, 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 (OPEC) 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; and 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.
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 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” in Item 7, MD&A, of this Annual Report.
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. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment, the assumptions used regarding prices for oil and gas, production volumes, required levels of operating and capital expenditures and quantities of recoverable oil reserves. 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 oil and gas prices after the date of the estimate may result in revisions to our reserve estimates. Revisions to prior estimates may be material.

 

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We may incur significant costs on exploration or development efforts which may prove unsuccessful or unprofitable
There can be no assurance that the costs we incur on exploration or development will result in an acceptable level of economic return. We may misinterpret geological or engineering data, which may result in material losses from 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 production costs.
We compete for oil and gas properties and personnel with many other exploration and development companies throughout the world who have access to greater resources
We operate in a highly competitive environment and compete with oil and gas companies and other individual producers and operators, many of which have longer operating histories and substantially greater financial and other resources. Many of these companies not only explore for and produce oil and gas, but also carry on refining operations and market petroleum and other products on a worldwide basis. We also compete with companies in other industries supplying energy, fuel and other needs to consumers. Our larger competitors, by reason of their size and relative financial strength, can more easily access capital markets and may enjoy a competitive advantage in the recruitment of qualified personnel. They may be able to absorb the burden of any changes in laws and regulations in the jurisdictions in which we do business and handle longer periods of reduced oil and gas prices more easily. Our competitors may be able to pay more for productive oil and gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects.
We compete with other companies to recruit and retain the limited number of individuals who possess the requisite skills and experience that are relevant to our business. This competition exposes us to the risk that we will have to pay increased compensation to such employees or increase the Company’s reliance and associated costs from partnering or outsourcing arrangements. There can be no assurance that employees with the abilities and expertise we require will be available.
Changes to laws, regulations and government policies in the jurisdictions in which we operate could adversely affect our ability to develop our projects
Our projects in Canada, Ecuador, China and Mongolia are subject to various international, federal, state, provincial, territorial and local laws and regulations relating to the exploration for and the development, production, upgrading, marketing, pricing, taxation and transportation of heavy oil, bitumen and related products and other matters, including environmental protection.
The exercise of discretion by governmental authorities under existing legislation and regulations, the amendment of existing legislation and regulations or the implementation of new legislation or regulations, affecting the oil and gas industry could materially increase the cost of developing and operating our projects and could have a material adverse impact on our business. There can be no assurance that laws, regulations and government policies relevant to our projects will not be changed in a manner which may adversely affect our ability to develop and operate them. Failure to obtain all necessary permits, leases, licenses and approvals, or failure to obtain them on a timely basis, could result in delays or restructuring of our projects and increase costs, all of which could have a material adverse effect on our business.
Construction, operation and decommissioning of these projects will be conditional upon the receipt of necessary permits, leases, licenses and other approvals from applicable government and regulatory authorities. The approval process can involve stakeholder consultation, environmental impact assessments, public hearings and appeals to tribunals and courts, among other things. An inability to secure local and regional community support could result in the necessary approvals being delayed or denied. There is no assurance that such approvals will be issued, or if granted, will not be appealed or cancelled or will be renewed upon expiry or will not contain terms and conditions that adversely affect the final design or economics of our projects.

 

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Complying with environmental and other government regulations could be costly and could negatively impact our production
Our operations are governed by various international, federal, state, provincial, territorial and local laws and regulations. Oil, gas, oil sands and heavy oil extraction, upgrading and transportation operations are subject to extensive regulation. Various approvals are required before such activities may be undertaken. We are subject to laws and regulations that govern the operation and maintenance of our facilities, the discharge of materials into the environment and other environmental protection issues. These laws and regulations may, among other potential consequences, require that we acquire permits before commencing drilling; restrict the substances that can be released into the environment with drilling and production activities; limit or prohibit drilling activities in 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.
The costs of complying with environmental laws and regulations in the future may harm our business. Furthermore, future changes in environmental laws and regulations may result in stricter standards and enforcement, larger fines and liability, and increased capital expenditures and operating costs, any of which could have a material adverse effect on our financial condition or results of operations.
No assurance can be given with respect to the impact of future environmental laws or the approvals, processes or other requirements thereunder or our ability to develop or operate our projects in a manner consistent with our current expectations. No assurance can be given that environmental laws will not limit project development or materially increase the cost of production, development or exploration activities or otherwise adversely affect our financial condition, results of operations or prospects.
Our business involves many operating risks that can cause substantial losses; insurance may not protect us against all these risks
Our operations are subject to many risks inherent in the oil and gas industry, including 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, any of which could cause us to experience material losses.
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.
Under environmental 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, if environmental damage occurs.
SAGD technologies for in-situ recovery of heavy oil and bitumen are energy intensive and may be unsustainable
We intend to integrate established SAGD thermal recovery techniques with our patented HTL™ upgrading process. Heavy oil recovery using the SAGD process is subject to technical and financial uncertainty. Current SAGD technologies for in-situ recovery of heavy oil and bitumen are energy intensive, requiring significant consumption of natural gas and other fuels for the production of steam used in the recovery process. The amount of steam required in the production process can also vary and impact costs. The performance of the reservoir can also impact the timing and levels of production using SAGD technology. While the technology is now being used by several producers, commercial application of this technology is still in the early stages relative to other methods of production and, accordingly, in the absence of an extended operating history, there can be no assurances with respect to the sustainability of SAGD operations.
We may not successfully commercialize our HTL™ technology
Success in commercializing our HTL™ technology in the oil and gas industry depends on our ability to economically design, construct and operate commercial-scale plants and a variety of other factors, many of which are outside our control. To date, commercial-scale HTL™ plants have only been constructed in the bio-mass industry.

 

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Technological advances could render our HTL™ technology 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 progress. It is possible that those advances could cause our HTL™ technology to become uncompetitive or obsolete.
Alternate sources of energy could lower the demand for our HTL™ technology
Alternative sources of energy are continually under development. If reliance upon petroleum based fuels decreases, the demand for our HTL™ upgraded product may decline. It is possible that technological advances in engine design and performance could reduce the use of petroleum based fuels, which would also lower the demand for our HTL™ upgraded product.
Efforts to commercialize our HTL™ technology may give rise to claims of infringement upon the patents or other 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 other rights of others in this technology until after we have made a substantial investment in the development and commercialization of projects utilizing the technology. Third parties may claim that the technology infringes upon past, present or future patented technologies. Legal actions could be brought against us and our licensors 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.
A breach of confidentiality obligations could put us at competitive risk and potentially damage our business
While discussing potential business relationships with third parties, we may disclose confidential information on operating results or proprietary intellectual property. Although confidentiality agreements are signed by third parties prior to the disclosure of any confidential information, a breach could put us at competitive risk and may cause significant damage to our business. The harm to our business from a breach of confidentiality cannot presently be quantified, but may be material and may not be compensable in damages. There is no assurance that, in the event of a breach of confidentiality, we will be able to obtain equitable remedies, such as injunctive relief, from a court of competent jurisdiction in a timely manner, if at all, in order to prevent or mitigate any damage to our business that such a breach of confidentiality may cause.
Certain projects are at a very early stage of development
Our projects are at varying stages of development. We have submitted the Regulatory Application/Environmental Impact Assessment for the Tamarack project to the Government of Alberta. The regulatory process is expected to take approximately 18 to 24 months; however, there is no assurance that the process will be completed on a timely basis and construction of the Tamarack Project could be significantly delayed. The Government of Alberta may not approve the project as proposed, or it may place certain conditions upon the approval, which could significantly impair the economics of the project. Our Zitong project in China and projects in Ecuador and Mongolia are at a very early stage of development; no reserves have yet been established and no detailed feasibility or engineering studies have yet been produced.
There can be no assurances that these projects will be completed within any time frame or within the parameters of any determined capital cost. We have yet to establish a defined schedule for financing and fully developing such projects. In our efforts to continue developing these projects, we may experience delays, interruption of operations or increased costs as a result of unanticipated events and circumstances. These include breakdowns or failures of equipment or processes; construction performance falling below expected levels of output or efficiency; design errors; challenges to proprietary technology; contractor or operator errors; non-performance by third party contractors; labor disputes; disruptions or declines in productivity; increases in materials or labor costs; inability to attract sufficient numbers of qualified workers; delays in obtaining, or conditions imposed by, regulatory approvals; violation of permit requirements; disruption in the supply of energy; and catastrophic events such as fires, earthquakes, storms or explosions.

 

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Our heavy oil project in Canada may be exposed to title risks and aboriginal claims
We have not obtained title opinions in respect of the Athabasca heavy oil leases we acquired from Talisman and there is a risk that our ownership of those leases may be subject to prior unregistered agreements or interests or undetected claims or interests that could impair our title. Any such impairment could jeopardize our entitlement to the economic benefits, if any, associated with the leases, which could have a material adverse effect on our financial condition, results of operations and ability to execute our business plans in a timely manner, if at all.
Aboriginal peoples have claimed aboriginal title and rights to large areas of land in western Canada where oil and gas operations are conducted, including a claim filed against the Government of Canada, the Province of Alberta, certain governmental entities and the regional municipality of Wood Buffalo (which includes the City of Fort McMurray, Alberta) claiming, among other things, aboriginal title to large areas of lands surrounding Fort McMurray where most of the oil sands operations in Alberta are located. Such claims, if successful, could affect the title to our heavy oil leases and have a material adverse effect on our business.
Our investment in Ecuador may be at risk if the agreement through which we hold our interest in the Block 20 project is challenged or cannot be enforced
We hold our interest in the Block 20 heavy oil project in Ecuador through a services agreement with Petroecuador and its subsidiary Petroproduccion. The agreement is governed by the laws of Ecuador. Although the agreement has been translated into English, the official and governing language of the agreement is Spanish and if any discrepancy exists between the official Spanish version of the agreement and the English translation, the official Spanish version prevails. There may be ambiguities, inconsistencies and anomalies between the official Spanish version of the agreement and the English translation that could materially affect how our rights and obligations under the agreement are conclusively interpreted and such interpretations may be materially adverse to our interests.
The dispute resolution provisions of the Block 20 agreement stipulate that disputes involving industrial property, including intellectual property, and technical or economic issues are subject to international arbitration. Other disputes are subject to resolution through mediation or arbitration in Ecuador. There is a risk that we, and the other parties to the Block 20 agreement, will be unable to agree upon the proper forum for the resolution of a dispute based on the subject matter of the dispute. There can also be no assurance that the other parties will comply with the dispute resolution provisions or otherwise voluntarily submit to arbitration.
Government policy in Ecuador may change to discourage foreign investment or requirements not foreseen may be implemented. There can be no assurance that our investments and assets in Ecuador will not be subject to nationalization, requisition or confiscation, whether legitimate or not, by any authority or body. While the Block 20 agreement contains provisions for compensation and reimbursement of losses we may suffer under such circumstances, there is no assurance that such provisions would effectively restore the value of our original investment. There can be no assurance that Ecuadorian laws protecting foreign investments will not be amended or abolished or that the existing laws will be enforced or interpreted to provide adequate protection against any or all of the risks described above. There can also be no assurance that the Block 20 agreement will prove to be enforceable or provide adequate protection against any or all of the risks described above.
Our business may be harmed if we are unable to retain our interests in licenses, leases and production sharing contracts
Some of our properties are held under licenses and leases, working interests in licenses and leases or production sharing contracts. If we fail to meet the specific requirements of the instrument through which we hold our interest, it may terminate or expire. We may not be able to meet any or all of the obligations required to maintain our interest in each such license, lease or production sharing contract. Some of our property interests will terminate unless we fulfill such obligations. If we are unable to satisfy these obligations on a timely basis, we may lose our rights in these properties. The termination of our interests in these properties may harm our business.
Our principal shareholder may significantly influence our business
As at the date of this Annual Report, our largest shareholder, Robert M. Friedland, owned approximately 15.22% 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.

 

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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 that these individuals will remain with us in the future. An unexpected partial or total loss of their services would harm our business.
Information 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 the availability and cost of capital; the 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; personnel; success or failure of activities in similar areas; changes in estimates of project completion costs; and our ability to attract other industry partners to acquire a portion of the working interest to reduce costs and exposure to risks.
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. Our plans regarding our projects might change.
ITEM 1B:  
UNRESOLVED STAFF COMMENTS
None.
ITEM 3:  
LEGAL PROCEEDINGS
The Company is a defendant in a lawsuit filed on November 20, 2008, in the United States District Court for the District of Colorado by Jack J. Grynberg and three affiliated companies. The suit alleged bribery and other misconduct and challenged the propriety of a contract awarded to the Company’s wholly-owned subsidiary Ivanhoe Energy Ecuador Inc. to develop Ecuador’s Pungarayacu heavy oil field. The plaintiff’s claims were for unspecified damages or ownership of the Company’s interest in the Pungarayacu field. The Company and related defendants filed motions to dismiss the lawsuit for lack of jurisdiction. The Court granted the motion and dismissed the case without prejudice. The Court granted Mr. Robert Friedland’s request to sanction plaintiffs and plaintiffs’ counsel for their conduct related to bringing the suit by awarding Mr. Friedland fees and costs. The Ivanhoe corporate defendants, including the Company, have been awarded their costs in defending the suit and have requested an award of attorneys’ fees.
On October 16, 2009, the plaintiffs filed a motion requesting that the Court vacate its judgment and allow discovery on jurisdictional issues on the grounds that plaintiffs had discovered new evidence. On July 15, 2010, the Court denied the plaintiffs’ motion to vacate the judgment. The request for attorneys’ fees remains pending before the Court. On August 13, 2010, the plaintiffs filed a notice of appeal challenging the district court’s judgment and some of its orders. The appeal is currently pending in the United States Court of Appeals for the Tenth Circuit. Briefing on the appeal is complete; the plaintiffs have filed an opening and reply brief and the Company and related defendants have filed a response brief. The Court has not announced whether it will hold oral argument on the appeal before it is decided. The likelihood of loss or gain resulting from the lawsuit, and the estimated amount of ultimate loss or gain, are not determinable or reasonably estimable at this time.
On December 30, 2010, the Company received a demand for arbitration from GAR Energy and Associates, Inc. (“GAR Energy”) and Gonzalo A. Ruiz and Janis S. Ruiz as successors in interest to and assignees of GAR Energy. The demand alleges breach of contract, fraud and other misconduct arising from a consulting agreement and various collateral agreements between GAR Energy and the Company relating to the Pungarayacu heavy oil field. The claimants seek actual damages of $250,000, a portion of the Company’s interest in the Pungarayacu field and other miscellaneous relief. The dispute is still in its early stages and arbitration proceedings, including discovery, have not yet commenced. The likelihood of loss or gain resulting from this dispute, and the estimated amount of ultimate loss or gain, are not determinable or reasonably estimable at this time.

 

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PART II
ITEM 5:  
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common shares trade on the Toronto Stock Exchange (the “TSX”) and The NASDAQ Capital Market (“NASDAQ”) under the symbols “IE” and “IVAN” respectively. The trading range of our common shares is as follows:
                                     
        TSX (Cdn$)     NASDAQ (US$)  
        High     Low     High     Low  
2010
                                   
  Q1     3.90       2.90       3.79       2.75  
 
  Q2     3.36       1.97       3.37       1.87  
 
  Q3     2.19       1.59       2.08       1.50  
 
  Q4     2.89       2.15       2.88       2.10  
 
                                   
2009
                                   
 
  Q1     1.53       0.57       1.22       0.45  
 
  Q2     2.16       1.38       1.85       1.10  
 
  Q3     2.98       1.31       2.81       1.13  
 
  Q4     3.25       2.20       3.12       2.02  
On December 31, 2010, the closing prices of our common shares were Cdn$2.72 on the TSX and $2.72 on NASDAQ.
As at December 31, 2010, a total of 334,365,482 of our common shares were issued and outstanding and held by 203 holders of record with an estimated 22,700 additional shareholders whose common 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.
EXEMPTIONS FROM CERTAIN NASDAQ MARKETPLACE RULES
As a Canadian issuer listed on NASDAQ, we are not required to comply with certain of NASDAQ’s Marketplace Rules and instead may comply with applicable Canadian requirements. As a foreign private issuer, we are only required to comply with the following NASDAQ rules: (i) we must have an audit committee that satisfies applicable NASDAQ requirements and that is composed of directors each of whom satisfy NASDAQ’s prescribed independence standards; (ii) we must provide NASDAQ with prompt notification after an executive officer of the Company becomes aware of any material non-compliance by us with any applicable NASDAQ Marketplace Rule; (iii) our common shares must be eligible for a Direct Registration Program operated by a clearing agency registered under Section 17A of the Exchange Act; and (iv) we must provide a brief description of any significant differences between our corporate governance practices and those followed by US companies quoted on NASDAQ.
Applicable Canadian rules pertaining to corporate governance require us to disclose in our management proxy circular, on an annual basis, our corporate governance practices, including whether or not our independent directors hold regularly scheduled meetings at which only independent directors are present, but there is no legal requirement in Canada for independent directors to hold regularly scheduled meetings at which only independent directors are present.
Although our independent directors hold meetings from time to time, as and when considered necessary or desirable by the independent lead director or by any other independent director, such meetings are not regularly scheduled.

 

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ENFORCEABILITY OF CIVIL LIABILITIES
We are a company incorporated under the laws of the Yukon Territory of Canada. Some of our directors, controlling shareholders, officers and representatives of the experts named in this Annual Report reside outside the US and a substantial portion of their assets and our assets are located outside the US. As a result, it may be difficult to effect service of process within the US upon the directors, controlling shareholders, officers and representatives of experts who are not residents of the US or to enforce against them judgments obtained in the courts of the US based upon the civil liability provisions of the federal securities laws or other laws of the US. 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 US, in original actions or in actions for enforcement of judgments of US courts, of liabilities based solely upon civil liability provisions of the US 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.
EXCHANGE CONTROLS AND TAXATION
There is no law or governmental decree or regulation in Canada that restricts the export or import of capital, or affects the remittance of dividends, interest or other payments to a non-resident holder of our common shares, other than withholding tax requirements.
There is no limitation imposed by the laws of Canada, the laws of the Yukon Territory, or our constating documents on the right of a non-resident to hold or vote our common shares, other than as provided in the Investment Canada Act (Canada) (the “Investment Act”), which generally prohibits a reviewable investment by an investor that is not a “Canadian”, as defined, unless after review, the minister responsible for the Investment Act is satisfied that the investment is likely to be of net benefit to Canada. An investment in our common shares by a non-Canadian who is not a “WTO investor” (which includes governments of, or individuals who are nationals of, member states of the World Trade Organization and corporations and other entities which are controlled by them), at a time when we were not already controlled by a WTO investor, would be reviewable under the Investment Act under two circumstances. First, if it was an investment to acquire control (within the meaning of the Investment Act) 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 (a “Cultural Business”). Currently, an investment in our common shares by a WTO investor, or by a non-Canadian at a time when we were already controlled by a WTO investor, would be reviewable under the Investment Act if it was an investment to acquire control and the value of our assets, as determined under Investment Act regulations, was not less than a specified amount, which for 2011 is Cdn$312 million. The Investment Act provides detailed rules to determine if there has been an acquisition of control. For example, a non-Canadian would acquire control of us for the purposes of the Investment Act if the non-Canadian acquired a majority of our outstanding common shares. The acquisition of less than a majority, but one-third or more, of our common shares would be presumed to be an acquisition of control of us unless it could be established that, on the acquisition, we were not controlled in fact by the acquirer through the ownership of common shares. An acquisition of control for the purposes of the Investment Act could also occur as a result of the acquisition by a non-Canadian of all or substantially all of our assets.
The Canadian Federal Government has brought forth certain amendments (the “Amendments”) to the Investment Act. Once they come into force, the Amendments would generally raise the thresholds that trigger governmental review. Specifically, with respect to WTO investors, the Amendments would see the thresholds for the review of direct acquisitions of control of a business which is not a Cultural Business increase from the current Cdn$312 million (based on book value) to Cdn$600 million (to be based on the “enterprise value” of the Canadian business) for the two years after the Amendments come into force, to Cdn$800 million in the following two years and then to Cdn$1 billion for the next two years. Thereafter, the threshold is to be adjusted to account for inflation. The Amendments will come into force when the government enacts regulations which, among other things, will provide how the “enterprise value” is to be determined.
The Investment Act also provides that the Minister of Industry may initiate a review of any acquisition by a non-Canadian of our common shares or assets if the Minister considers that the acquisition “could be injurious to (Canada’s) national security”.
Amounts that we may, in the future, pay or credit, or be deemed to have paid or credited, to shareholders as dividends in respect of the common shares held at a time when the beneficial owner is 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-US 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 US resident that is entitled to the benefits of the Convention is generally 15%. However, if the beneficial owner of such dividends is a US resident corporation that is entitled to the benefits of the Convention and owns 10% or more of our voting stock, the withholding rate is reduced to 5%. In the case of certain tax-exempt entities, which are residents of the US for the purpose of the Convention, the withholding tax on dividends may be reduced to 0%.

 

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SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS
See table under “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” set forth in Item 12 in this Annual Report.
PERFORMANCE GRAPH
See table under “Executive Compensation” set forth in Item 11 in this Annual Report.
SALES OF UNREGISTERED SECURITIES
All securities we issued during the years ended December 31, 2010 and 2009, which were not registered under the Act, have been detailed in previously filed Form 10-Qs and Form 8-Ks.
ITEM 6.  
SELECTED FINANCIAL DATA
FIVE YEAR SUMMARY OF SELECTED FINANCIAL DATA
The financial data presented below has been revised to account for the sale of all of the Company’s US oil and gas exploration and production operations in 2009 as discontinued operations on a retroactive basis in accordance with generally accepted accounting principles (“GAAP”) in Canada. See Note 18 to the consolidated financial statements under Item 8 in this Annual Report.
                                         
($000s, except per share amounts)   2010     2009     2008     2007     2006  
 
                                       
Results of Operations
                                       
Revenues
    21,928       23,658       50,670       26,689       36,320  
Net loss from continuing operations
    (29,110 )     (37,731 )     (38,476 )     (33,433 )     (25,677 )
Net loss from continuing operations per share — basic and diluted
    (0.09 )     (0.13 )     (0.15 )     (0.14 )     (0.11 )
 
                                       
Financial Position
                                       
Total assets
    409,585       281,763       346,875       266,516       278,144  
Debt
    39,832                          
Long term debt
          36,934       37,855       9,812       2,737  
Asset retirement obligations
    744       195       1,928       739       484  
Long term obligation
    1,900       1,900       1,900       1,900       1,900  
RECONCILIATION TO US GAAP
Our consolidated financial statements have been prepared in accordance with GAAP in Canada, which differ in certain respects from those principles that we would have followed had our consolidated financial statements been prepared in accordance with GAAP in the US. The differences between Canadian and US GAAP, which affect our consolidated financial statements, are described in detail in Note 20 to our consolidated financial statements in this Annual Report. Had we followed US GAAP, certain selected financial information would have been reported as follows:
                                         
($000s, except per share amounts)   2010     2009     2008     2007     2006  
 
Results of Operations
                                       
Revenues
    36,945       17,152       55,335       27,281       35,628  
Net loss from continuing operations
    (10,271 )     (32,679 )     (47,911 )     (23,080 )     (35,477 )
Net loss from continuing operations per share — basic and diluted
    (0.03 )     (0.12 )     (0.19 )     (0.10 )     (0.15 )
 
                                       
Financial Position
                                       
Total assets
    393,675       262,717       292,847       251,627       252,893  
Debt
    40,217                          
Long term debt
          38,005       40,392       10,412       2,737  
Asset retirement obligations
    744       195       1,928       739       484  
Long term obligation
    1,900       1,900       1,900       1,900       1,900  

 

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ITEM 7:  
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
         
Executive Overview of 2010 Results
    23  
Highlights
    24  
Change in Net Loss
    24  
Results of Operations
       
Revenue
    25  
Netbacks
    25  
Operating Costs
    26  
General and Administrative
    26  
Business and Technology Development
    26  
Depletion and Depreciation
    27  
Foreign Exchange
    27  
Interest
    27  
Impairment
    27  
Derivatives
    27  
Income Taxes
    28  
Discontinued Operations
    28  
Liquidity and Capital Resources
    28  
Critical Accounting Principles and Estimates
    30  
New Accounting Pronouncements
    32  
The following MD&A should be read in conjunction with the consolidated financial statements for the year ended December 31, 2010. The consolidated financial statements have been prepared in accordance with GAAP in Canada. The impact of significant differences between Canadian and US GAAP on the consolidated financial statements is disclosed in Note 20 to the consolidated financial statements. The date of this discussion is March 4, 2010. Unless otherwise noted, tabular amounts are in thousands of US dollars. Oil and gas volumes and reserves and related measures are presented on a working interest, before royalties basis.
EXECUTIVE OVERVIEW OF 2010 RESULTS
Production decreased in 2010 compared to 2009 as Ivanhoe’s working interest at Dagang, China was reduced to 49% upon the Company recovering its development costs in 2009. Although realized prices in 2010 were higher than in the past year, overall oil revenue declined due to lower production volumes. Lower revenue in combination with higher general and administrative costs resulted in additional cash flow used in operating activities in 2010 compared to 2009.
The net loss from continuing operations in 2010 improved over the prior year as the result of non-cash items. Lower depletion expense and an unrealized foreign exchange gain compensated for the decrease in revenue, the elimination of a future income tax recovery and higher stock-based compensation costs.
Capital expenditures totaled $86.3 million in 2010. A 28 well winter delineation program was completed in March 2010 at Tamarack. With the information gathered from the drilling program, Ivanhoe filed a comprehensive Environmental Impact Assessment with the Government of Alberta in November 2010. In support of the application, Basic Engineering and Design and Front End Engineering and Design were completed to generate a Class III (+25/-20%) capital cost estimate.
Two wells were drilled in the Pungarayacu field on Block 20 in Ecuador. The IP-5b well was drilled, perforated in the Hollin oil sands and steam was successfully injected into the reservoir resulting in production of heated heavy oil. The Company’s initial well, IP-15, encountered cementing and completion problems during steam injection operations and testing at the well was suspended without recovering oil.
Gas was discovered at the Zitong-1 and Yixin-2 wells drilled in the Zitong Block in China. Following initial flow and pressure tests, both wells have been shut-in for pressure build-up. In Dagang, one well was drilling at year end and five fracture stimulations were performed during 2010. In the Nyalga basin of Mongolia, additional 2D seismic was acquired and preparations were made for a further 2D seismic program and a drilling program.

 

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HIGHLIGHTS
                         
($000, except as stated)   2010     2009     2008  
 
                       
Average production (bbls/d)
    788       1,276       1,339  
Realized oil prices ($/bbl)
    75.52       53.60       98.73  
Oil revenue
    21,720       24,968       48,370  
 
                       
Cash flow provided by (used in) operating activities
    (17,764 )     (12,290 )     17,053  
Net loss (continuing operations(1))
    (29,110 )     (37,731 )     (38,476 )
Net loss per share — basic and diluted (continuing operations(1))
    (0.09 )     (0.13 )     (0.15 )
 
                       
Working capital (continuing operations(1))
    16,485       18,317       31,597  
Capital expenditures (continuing operations(1))
    86,285       26,373       21,063  
(1)  
In July 2009, the Company disposed of its US operations and used the proceeds for its ongoing projects. To properly reflect this sale in the Company’s 2010 consolidated financial statements, the results of the US operations have been separately identified in comparative disclosures as “Discontinued Operations.”
CHANGE IN NET LOSS
The following quantifies year-over-year changes in the components of net loss realized in the years ended December 31, 2010, 2009 and 2008.
                                         
    2010     Change     2009     Change     2008  
 
                                       
Cash items
                                       
Oil revenues
    21,720               24,968               48,370  
Production volumes
            (9,515 )             (2,384 )        
Oil prices
            6,267               (21,018 )        
Operating costs
    (9,503 )     688       (10,191 )     11,324       (21,515 )
General and administrative, less stock-based compensation
    (20,565 )     (2,563 )     (18,002 )     (6,198 )     (11,804 )
Business and technology development, less stock-based compensation
    (10,215 )     (872 )     (9,343 )     (3,458 )     (5,885 )
Realized foreign exchange gain (loss)
    (198 )     (87 )     (111 )     (346 )     235  
Realized gain (loss) on derivatives
          (124 )     124       4,554       (4,430 )
Net interest
    184       485       (301 )     283       (584 )
Current income tax expense
    (126 )     1,631       (1,757 )     (1,103 )     (654 )
 
                             
Total cash changes
    (18,703 )     (4,090 )     (14,613 )     (18,346 )     3,733  
 
                             
 
                                       
Non-cash items
                                       
Unrealized gain (loss) on derivatives
          1,459       (1,459 )     (7,577 )     6,118  
Unrealized foreign exchange gain (loss)
    3,523       8,632       (5,109 )     (3,347 )     (1,762 )
Depletion and depreciation
    (8,960 )     10,908       (19,868 )     5,893       (25,761 )
Stock-based compensation
    (6,095 )     (2,246 )     (3,849 )     (833 )     (3,016 )
Provision for impairment of intangible asset and development costs
          1,903       (1,903 )     13,151       (15,054 )
Write off of deferred financing costs
                      2,621       (2,621 )
Future income tax recovery
    1,125       (8,475 )     9,600       9,600        
Discontinued operations (net of tax)
          23,921       (23,921 )     (28,204 )     4,283  
Other
          530       (530 )     (417 )     (113 )
 
                             
Total non-cash changes
    (10,407 )     36,632       (47,039 )     (9,113 )     (37,926 )
 
                             
Net loss
    (29,110 )     32,542       (61,652 )     (27,459 )     (34,193 )
 
                             

 

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RESULTS OF OPERATIONS
Revenue
                         
    2010     2009     2008  
Production
                       
Asia (net bbls)
                       
Dagang
    273,868       452,573       471,817  
Daqing
    13,751       13,231       18,096  
 
                 
Total production
    287,619       465,804       489,913  
 
                 
Average daily production (bbls/d)
    788       1,276       1,339  
 
                       
Pricing
                       
Average realized oil price ($/bbl)
    75.52       53.60       98.73  
West Texas Intermediate (WTI) ($/bbl)
    79.39       61.80       99.65  
2010 vs 2009
Oil revenue in 2010 was lower than in 2009 as a result of lower production volumes, despite higher realized prices in the current year. Production in 2010 decreased primarily as a result of Ivanhoe’s working interest in the Dagang field decreasing to 49% in September 2009. The Company received a 2010 production quota of 70,000 gross tonnes or approximately 680 bbls/d net. The Company took advantage of this quota situation and performed certain maintenance workovers that normally would have been delayed. Production quotas in 2011 are set at 80,000 gross tonnes or approximately 1,600 bbls/d gross.
Dagang production is sold at the three month rolling average price of Cinta crude, which historically averages $3.00/bbl less than West Texas Intermediate (“WTI”). Following the increase in Cinta crude prices in 2010, our realized oil prices rose compared to 2009.
2009 vs 2008
Due to the combination of lower production and realized prices, oil revenue was lower in 2009 than in 2008. Production in 2009 decreased from 2008 due to normal field declines which were partially offset by productivity increases from adding new perforations, fracture stimulations and water flood response. In addition, Ivanhoe’s working interest in the Dagang field decreased from 82% to 49% in September 2009 upon the Company recovering its development investments.
Realized oil prices decreased 46% per barrel in 2009 compared to the prior year, consistent with the decline in Cinta crude.
Netbacks
                         
($/bbl)   2010     2009     2008  
Oil revenue(1)
    75.52       53.60       98.73  
Less operating costs
                       
Field operating
    (19.96 )     (17.13 )     (21.70 )
Windfall Levy
    (11.59 )     (4.00 )     (21.14 )
Engineering and support costs
    (1.50 )     (0.75 )     (1.08 )
 
                 
Net operating revenue(1)
    42.47       31.72       54.81  
Depletion
    (29.87 )     (38.70 )     (47.22 )
 
                 
Net revenue (loss) from operations(1)
    12.60       (6.98 )     7.59  
 
                 
(1)  
Oil revenue per barrel, net operating revenue per barrel and net revenue (loss) from operations per barrel do not have standardized meanings prescribed by Canadian GAAP and therefore may not be comparable to similar measures used by other companies. Please refer to the Non-GAAP Financial Measures at the end of this MD&A for more details.

 

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Operating Costs
2010 vs 2009
Operating costs on a per barrel basis rose in 2010, primarily as the result of an increase in the Windfall Levy administered in China due to higher realized oil prices in 2010 than in 2009. The Windfall Levy is imposed at progressive rates from 20% to 40% on the portion of the monthly weighted average sales price exceeding $40.00/bbl.
Higher field costs in 2010 also contributed to the increase in operating costs per barrel. Additional electrical and instrumentation costs were incurred in Dagang as we installed variable frequency drives on certain producing wells to assist in reducing future maintenance and power costs. Additional transportation, oil treatment and processing expenses were also incurred, as well as higher local office costs due to increased field activity.
2009 vs 2008
Operating costs on a per barrel basis, as well as in total, decreased in 2009 from the prior year due to lower field costs as well as a reduction in the Windfall Levy. Field operating costs in 2009 declined from 2008 as the result of decreased road and lease maintenance and workover costs, offset by higher oil treatment costs. Once key milestones in the Production Sharing Contract with CNPC were reached in September 2009, we incurred a smaller proportionate share of costs in 2009 and a decline in overall working interest. Had the Company paid a smaller proportionate share of costs in 2008 and the overall working interest had also been lower, field operating costs would have been $0.68/bbl lower in 2008. The Windfall Levy expense decreased in 2009 from the prior year since oil prices realized by the Company were lower in 2009.
General and Administrative
2010 vs 2009
General and administrative expenses (“G&A”) rose in 2010, primarily as a result of higher staff and office costs incurred with the Company’s growing commitments to its projects around the world. Staff and office costs increased $5.0 million in 2010 across all operating segments and corporate costs, such as stock exchange filing fees and non-cash stock-based compensation, increased by $1.8 million, which were offset by a decrease of $2.1 million in contract labour.
2009 vs 2008
In 2009, G&A rose in comparison to the prior period primarily as the result of higher costs in the corporate area and Ecuador. Corporate G&A rose $5.5 million in 2009 over 2008 due to incurring additional legal fees (see Item 3 to Part I of this Annual Report), corporate aircraft costs and personnel costs previously allocated to our US segment. These increases were partially offset by lower salary and benefit costs in 2009 due to the resignation of an executive in 2008, severance paid in 2008 and reallocating certain executive salaries to the Business and Technology Development segment. G&A for Ecuador were $1.6 million higher in 2009 as costs incurred prior to signing the contract to explore and develop Block 20 were minimal. G&A in China increased $0.8 million for 2009 over 2008 since a lower amount of G&A was allocated to capital projects in 2009. These increases were offset by a $0.5 million decrease in G&A incurred in Canada due to capitalizing costs related to the Tamarack property.
Business and Technology Development
2010 vs 2009
Business and technology development costs were higher in 2010 than in 2009. In 2010, the FTF was used to support basic and front-end engineering for a commercial-scale HTL™ plant for the Tamarack project in Canada and to support conceptual design for several projects, including Pungarayacu in Ecuador. Costs were also incurred in 2010 in connection with pursuing HTLTM heavy oil and selected conventional oil opportunities in North and South America, the Middle East and North Africa.
2009 vs 2008
Business and technology development expenses increased in 2009 over 2008, as a result of the startup of the FTF, opening an office in Houston, the pursuit of financing initiatives in 2009, as well as the reallocation of certain executive salaries to the Business and Technology Development segment in late 2008.

 

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Depletion and Depreciation
2010 vs 2009
Depletion and depreciation expense decreased in 2010 compared to 2009 due to lower depletion in Asia and reduced depreciation in the Business and Technology Development segment. Depletion in Asia was lower due to the combination of reduced production and higher proved reserves in China. We stopped depreciating the CDF at the end of 2009 when it was retired, lowering our depreciation expense in 2010.
2009 vs 2008
Ivanhoe’s depletion and depreciation expense in 2009 was lower than in 2008. Depletion in Asia decreased in 2009 as a result of an increase in proved reserves at our Dagang project in China as well as lower production in the current year. Additionally, our depreciation expense in the Business and Technology Development segment decreased in 2009 in comparison to the prior year as the depreciation expense associated with the FTF was lower than the depreciation expense incurred on the CDF.
Foreign Exchange
2010 vs 2009
The Company incurred a net foreign exchange gain in 2010 in comparison to a net foreign exchange loss in the prior year. In 2010, the Canadian dollar continued to strengthen relative to the US dollar resulting in a foreign exchange gain on the Cdn$150.0 million proceeds raised in our private placement in the first quarter of 2010, partially offset by a foreign exchange loss on our Canadian dollar debt.
2009 vs 2008
We incurred a foreign exchange loss primarily due to the translation of our Canadian dollar debt in 2009 and 2008. The loss was greater in 2009 than in 2008 due to the Canadian dollar strengthening relative to the US dollar.
Interest
2010 vs 2009
In the first quarter of 2010, the Company raised Cdn$150.0 million through a private placement. The short term investment of these funds earned interest income. Interest expense in 2010 was lower than in 2009 from the repayment of loan obligations associated with the Company’s China and US operations during the course of 2009.
2009 vs 2008
Interest expense in 2009 was lower in comparison to 2008 due to the repayment of debt. In 2008, we repaid a Cdn$12.5 million promissory note and $3.0 million against our bank loan for Asian operations.
Impairment
When the FTF was completed in 2009, we commenced the abandonment process for the CDF. The $0.9 million net asset value of the CDF was impaired. Additionally, $0.8 million of development costs related to the pursuit of projects in the Middle East were impaired in 2009.
In 2008, we impaired costs associated with our GTL project due to the lack of a definitive agreement and appropriate financing. Development costs of $5.1 million and intangible license costs of $10.0 million were written off.
The Company incurred costs associated with the pursuit of corporate financing initiatives by Sunwing. In the fourth quarter of 2008, this financing initiative was postponed indefinitely and therefore the associated costs were written down to nil.
Derivatives
In 2007, we entered into a costless collar derivative as required by the Company’s lenders to minimize variability in our cash flow. This derivative had a ceiling of $84.50/bbl and a floor of $55.00/bbl using the WTI as the index traded on the NYMEX. In December 2009, the Company repaid the outstanding loan balance and this derivative was subsequently cancelled.

 

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The derivative instrument resulted in a loss to the Company in 2009, compared to a gain in 2008, due to movements in WTI. WTI reached record highs at the beginning of the third quarter of 2008 before steadily declining at the end of the fourth quarter to a level that was the lowest dating back several years. The low benchmark prices continued into the first half of 2009, recovering in the last half of the year.
Income Taxes
The Company’s income tax recovery was lower in 2010 than in 2009 due to a decrease in future taxes in the current year. Future taxes were significantly higher in 2009 due to the sale of the Company’s US oil and gas operations.
In 2009, current income taxes included a provision for taxes in Asia and a net adjustment of $1.0 million related to 2008 from changes in the minimum depreciation and amortization periods for oil and gas companies by the Chinese State Tax Administration Bureau. The future tax recovery in 2009 was driven by the sale of our US operating segment.
In 2008, current taxes were payable on Asian operations.
Discontinued Operations
In 2009, Ivanhoe sold its wholly owned subsidiary, Ivanhoe Energy (USA) Inc., disposing of all our oil and gas exploration and production operations in the US. The US operations have been accounted for as discontinued operations on a retroactive basis in accordance with Canadian GAAP and the results for 2009 and 2008 have been amended accordingly.
The operating results for the discontinued operations were as follows:
                 
    2009     2008  
Revenue
               
Oil and gas
    5,455       18,120  
Gain on derivative instruments
    189       278  
Interest
    8       98  
 
           
 
    5,652       18,496  
 
           
Expenses
               
Operating
    2,132       5,137  
General and administrative
    139       2,413  
Depletion and depreciation
    3,772       6,143  
Interest and financing
    173       520  
 
           
 
    6,216       14,213  
 
           
Income (loss) before disposition
    (564 )     4,283  
Loss on disposition (net of tax of $29.6 million for 2009, nil for 2008)
    (23,357 )      
 
           
Net income (loss) from discontinued operations
    (23,921 )     4,283  
 
           
LIQUIDITY AND CAPITAL RESOURCES
Contractual Obligations and Commitments
The following information about our contractual obligations and other commitments summarizes certain liquidity and capital resource requirements. The information presented in the table below does not include planned, but not legally committed, capital expenditures or obligations that are discretionary and/or being performed under contracts which are cancelable with a 30 day notification period. Previous exploration commitments in Zitong and Nyalga have been fulfilled and therefore are not included below.
                                                 
    Total     2011     2012     2013     2014     After 2014  
Debt
    39,832       39,832                            
Interest
    2,042       2,042                          
Asset retirement obligations(1)
    1,939             332                     1,607  
Long term obligation
    1,900                               1,900  
Leases
    2,989       1,769       885       335              
 
                                   
Total
    48,702       43,643       1,217       335             3,507  
 
                                   
(1)  
Represents undiscounted asset retirement obligations after inflation. The discounted value ($0.7 million) of these estimated obligations is provided for in the consolidated financial statements.

 

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Debt
As described in Note 5 to the consolidated financial statements, the Company issued a Cdn$40.0 million convertible promissory note maturing in July 2011. The outstanding principal amount is convertible, at Talisman’s option, into a maximum of 12,779,552 Ivanhoe common shares at Cdn$3.13 per common share. Interest at the prime rate plus 2% is calculated daily and payable semi-annually. The estimated interest payments on the convertible promissory note are included in the above table.
Asset Retirement Obligations
The Company is required to remedy the effect of our activities on the environment at our operating sites by dismantling and removing production facilities and remediating any damage caused. At December 31, 2010, we estimated the total undiscounted, inflated cost to settle our asset retirement obligations in Canada, Ecuador and the FTF in the US was $1.9 million. These costs are expected to be incurred between 2013 and 2038. Ivanhoe does not make such a provision for asset retirement costs in connection with its oil and gas operations in China as dry holes are abandoned as occurred and the Company is under no obligation to contribute to the future costs to restore well sites or abandon the field.
Long Term Obligation
As part of its 2005 merger with Ensyn, the Company assumed an obligation to pay $1.9 million in the event that proceeds from the sale of units incorporating the HTL™ technology for petroleum applications reach a total of $100.0 million.
Operating Leases
We have long term operating leases for office space, which expire between January 2011 and September 2013.
Other
From time to time, Ivanhoe enters into consulting agreements whereby a success fee may be payable if and when either a definitive agreement is signed or certain other contractual milestones are met. Under the agreements, the consultant may receive cash, common shares, stock options or some combination thereof. These fees are not considered to be material.
The Company may provide indemnities to third parties, in the ordinary course of business, that are customary in certain commercial transactions, such as purchase and sale agreements. The terms of these indemnities will vary based upon the contract, the nature of which prevents Ivanhoe from making a reasonable estimate of the maximum potential amounts that may be required to be paid. The Company’s management is of the opinion that any resulting settlements relating to indemnities are immaterial.
In the normal course of business, we are subject to legal proceedings being brought against us. While the final outcome of these proceedings is uncertain, we believe that these proceedings, in the aggregate, are not reasonably likely to have a material effect on our financial position or results of operations.
Sources and Uses of Cash
The following table sets forth a summary of our cash flows from operating, investing and financing activities, as reported in the consolidated statements of cash flows.
                         
    2010     2009     2008  
Net cash provided by (used in) operating activities
    (17,764 )     (12,290 )     17,053  
Net cash provided by (used in) investing activities
    (79,860 )     6,396       (49,321 )
Net cash provided by (used in) financing activities
    138,286       (11,875 )     70,751  
Operating Activities
2010 vs 2009
Operating activities in 2010 used more cash than in 2009 primarily as a result of lower oil revenue and higher G&A costs, partially offset by current tax savings. 2009 operating activities benefitted from net cash from discontinued operations. An increase in accounts payable, partially offset by changes in accounts receivable and income taxes, represented working capital cash in flows from operating activities in 2010 compared to an overall working capital outflow in 2009.

 

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2009 vs 2008
Operating activities in 2009 resulted in a use of cash due to significantly lower revenue in 2009, in contrast to 2008 activities which generated cash inflows.
Investing Activities
2010 vs 2009
Net cash used for investing activities was higher in 2010 than in 2009 due to a more extensive capital program. Payables related to capital expenditures were higher at December 31, 2010, than the prior year, creating a source of working capital. In 2009, $35.3 million cash was generated from the sale of our US operating segment.
2009 vs 2008
In 2009, investing activities resulted in a net cash inflow due to the sale of the US operating segment. In comparison, $22.3 million was paid to acquire the Tamarack leases in 2008, and when combined with other capital expenditures, created a net cash outflow in 2008.
Financing Activities
2010 vs 2009
In 2010, financing activities raised $135.7 million of cash with the private placement of 50 million special warrants in February and March 2010 at a price of Cdn$3.00 per special warrant. Additional cash was raised through the exercise of stock options. The repayment of debt in 2009 resulted in a net cash outflow from financing activities.
2009 vs 2008
Financing activities in 2009 resulted in a net cash outflow due to the final debt repayment of long term notes and the repayment of a note associated with discontinued operations. In 2008, financing activities resulted in a net cash inflow due to a private placement in the third quarter and the receipt of cash from a Cdn$5.0 million loan.
Capital Structure
                 
As at December 31,   2010     2009  
Cash and cash equivalents
    67,817       21,512  
Debt
    39,832        
Long term debt
          36,934  
Shareholders’ equity
    324,109       208,029  
Ivanhoe intends to use its cash and cash equivalent balance to fulfill its commitments and partially fund operations in 2011. Cash flow from operating activities may be insufficient to meet operating requirements in the next 12 months and additional sources of funding, either at a parent company level or at a project level, will be required to grow the Company’s major projects and fully develop its oil and gas properties. Historically, Ivanhoe has used external sources of funding, such as public and private equity and debt markets. There is no assurance that we will be able to obtain additional financing on favorable terms, if at all, and any future equity issuances may be dilutive to our current investors. If we cannot secure additional financing, we may have to delay our capital programs and forfeit or dilute our rights in existing oil and gas property interests.
CRITICAL ACCOUNTING PRINCIPLES AND ESTIMATES
Our significant accounting policies may be found in Note 2 to the consolidated financial statements. Some of these policies involve critical accounting estimates because they require us to make particularly subjective or complex judgments about matters that are inherently uncertain and because of the likelihood that materially different amounts could be reported under different conditions or using different assumptions. The following section discusses our critical accounting estimates and assumptions and how they affect the amounts reported in our consolidated financial statements.

 

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Oil and Gas Reserves
The process of estimating quantities of reserves is inherently uncertain and complex. It requires significant judgment and decisions based on available geological, geophysical, engineering and economic data. These estimates may change substantially as additional data from ongoing development activities and production becomes available and as economic conditions impacting oil and gas prices and costs change. Such revisions could be upwards or downwards. For details on our reserve estimation process, refer to the section titled “Reserves, Production and Related Information” in Items 1 and 2 of this Annual Report. Reserve estimates have a material impact on depletion and the Company’s impairment evaluations, which in turn have a material impact on the results of operations.
Total proved reserves estimates are used to determine rates that are applied to each barrel of production in calculating our depletion expense. In 2010, depletion expense of $9.0 million was recorded. If our proved reserves estimates changed by 10%, our depletion and depreciation expense would have changed by approximately $0.6 million, assuming all other variables remained constant.
Impairment
Oil and Gas Properties and Development Costs
We periodically evaluate our oil and gas properties and development costs for impairment. Among other things, an impairment of these assets may be triggered by falling oil and gas prices, a significant negative revision to our reserve estimates, the inability to use our HTL™ technology in certain projects, changes in capital costs or the inability to raise sufficient financial resources to further develop the property. If one of these occurs, we assess if the undiscounted future net cash flows from proved reserves at future commodity prices plus the cost of undeveloped properties is less than the carrying value of the capitalized costs. If an impairment is found to exist, the impaired properties are written down to their fair value. The fair value of the assets is calculated based on future net cash flows from proved plus probable reserves, discounted at a risk-free interest rate using future commodity prices, plus the cost of undeveloped properties.
Cash flow estimates for our impairment assessments require assumptions about future prices and costs, reserves, discount rates and potential benefits from the application of our HTL™ technology. Given the significant assumptions required and the likelihood that actual conditions will differ, we consider the assessment of impairment to be a critical accounting estimate.
It is difficult to determine and assess how a decrease in proved reserves could impact our impairment tests. The relationship between our reserve estimates and the estimated undiscounted cash flows and the nature of the property-by-property impairment test is complex. As a result, we are unable to provide a reasonable sensitivity analysis of the impact that a reserve estimate decrease would have on our assessment of impairment.
Intangible Assets
Intangible assets consist of an exclusive, irrevocable license to deploy HTL™ technology our proprietary, patented heavy oil upgrading process. We periodically review the intangible assets for impairment or if an adverse event or change occurs. Indicators of adverse events could include HTL™ patent expiries, advancements of new technologies or the inability to successfully commercialize the HTL™ technology. To determine if the intangible assets are impaired, we assess if the undiscounted future cash flows are in excess of the carrying value. If not, the assets are reduced to their fair value based on expected discounted future cash flows.
We believe that the intangible asset impairment is a critical accounting estimate because it requires management to make assumptions about competitive technological developments, the successful commercialization of our HTL™ technology and future cash flows from the HTL™ technology. We cannot predict if an event that triggers impairment will occur, when it will occur or how it will affect the asset amounts we have reported. Although we believe our estimates are reasonable and consistent with current conditions, internal planning and expected future operations, such estimates are subject to significant uncertainties and judgments.
Future Income Taxes
We operate in a specialized industry and in several tax jurisdictions. As a result, our income is subject to various rates of taxation. The breadth of the Company’s operations and the global complexity of tax regulations require assessments of uncertainties and judgments in estimating the taxes we will ultimately pay. The final taxes paid are dependent upon many factors, including negotiations with taxing authorities in various jurisdictions, uncertain tax positions and resolution of disputes arising from federal, provincial, state and local tax audits. The resolution of these uncertainties and the associated final taxes may result in adjustments to our tax assets and tax liabilities.
We estimate future income taxes based upon temporary differences between the assets and liabilities that we report in our consolidated financial statements and the tax basis of our assets and liabilities as determined under applicable tax laws. We record a valuation allowance against our future income tax assets when we believe, based on all available evidence, that it is not “more likely than not” that all of our future income tax assets recognized will be realized. The amount of the future income tax asset recognized and considered realizable could, however, be reduced if projected income is not achieved.

 

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Convertible note liability
In connection with the acquisition of the Tamarack leases in July 2008 from Talisman, we issued a Convertible Note. The Convertible Note is a compound financial instrument, containing a debt instrument as well as an embedded conversion feature classified as equity. The residual basis method was used to value the instrument which means the fair value of the liability component was calculated and the remaining value was assigned to the equity component.
Management estimated the value of the liability component to be Cdn$37.9 million by discounting the expected interest and principal payments. The remaining value of Cdn$2.1 million was allocated to the equity component. If the interest rate used to discount the liability decreased by 1%, the amount of the Convertible Note originally recorded as a liability would increase by $1.0 million and the equity component would have been $1.0 million lower. Since the accretion of the liability component over the three year maturity period is capitalized on the balance sheet, there would not have been an impact on our operating results. Increasing the interest rate by 1% would have had the opposite, but equal, impact on our consolidated financial statements.
NEW ACCOUNTING PRONOUNCEMENTS
Transition to International Financial Reporting Standards
Effective January 1, 2011, we adopted International Financial Reporting Standards (“IFRS”) as our basis for accounting. Most adjustments required on transition to IFRS were made retrospectively against opening retained earnings as of the date of the first comparative balance sheet. Transitional adjustments relating to those standards where comparative figures are not required to be restated will only be made as of the first day of the year of adoption.
As a foreign private issuer in the US, we will be permitted to file with the SEC consolidated financial statements prepared under IFRS without a reconciliation to US GAAP. The impact of this change is that we will no longer prepare a reconciliation of our results to US GAAP. It is possible that some of our accounting policies under IFRS could be different from US GAAP.
First-time Adoption of International Financial Reporting Standards
“First-Time Adoption of International Financial Reporting Standards” (“IFRS 1”) provides companies adopting IFRS for the first time with a number of optional exemptions and mandatory exceptions to the general requirement for full retrospective application of IFRS where retrospective restatement would either be onerous or would not provide more useful information. As a result of relying upon the exemptions described below, there was no material impact in these areas at the date of transition to IFRS.

 

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Area of IFRS   Summary of Exemption Available
Property, plant and equipment
  Companies may elect to report property, plant and equipment from oil and gas operations on the opening balance sheet on the transition date at a deemed cost, instead of the actual cost, as though IFRS had been adopted retroactively. The deemed cost of an item may be either its fair value at the date of transition to IFRS or an amount reported under Canadian GAAP. The exemption can be applied on an asset-by-asset basis.
 
   
 
  Ivanhoe elected to report property, plant and equipment from oil and gas operations in its opening balance sheet on the transition date at the deemed cost previously calculated under Canadian GAAP.
 
 
   
Decommissioning liabilities
  In accounting for changes in decommissioning liabilities, IFRS requires changes in such obligations to be added to, or deducted from, the cost of the asset to which they relate. The adjusted depreciable amount of the asset is then depreciated prospectively over its remaining useful life. Rather than recalculating the effect of all such changes throughout the life of the obligation, companies may elect to measure the liability and the related depreciation effects at the date of transition to IFRS.
 
   
 
  Ivanhoe elected to measure only those decommissioning liabilities outstanding from our FTF on the date of transition to IFRS.
 
 
   
Stock-based compensation
  Companies may elect not to apply IFRS 2, “Share-Based Payment,” to stock options granted on or before November 7, 2002, or which vested before the date of transition to IFRS. Ivanhoe elected to utilize this exemption for the all stock options awarded after November 7, 2002, that vested before January 1, 2010.
 
 
   
Business combinations
  Companies may elect to either restate all past business combinations in accordance with IFRS 3, “Business Combinations,” or to apply an elective exemption from applying IFRS 3 to past business combinations Ivanhoe has elected to utilize this exemption such that transactions entered into prior to the transition date will not be restated.
 
Expected Areas of Significance
IFRS will have a significant impact on the Company’s ongoing accounting in the areas described below, in addition to the impact of transition policy choices made under IFRS 1.
     
Accounting    
Policy Area   Impact of Policy Adoption
Exploration and evaluation assets
  The Company followed the full cost method of accounting for its oil and gas operations under Canadian (“Cdn”) GAAP, whereby all costs related to the exploration for, and development of, oil and gas reserves were capitalized and periodically evaluated for impairment. Under IFRS, exploration costs will initially be capitalized as exploration and evaluation (“E&E”) assets until it can be determined if sufficient quantities of reserves have been found to justify commercial production. If commercial quantities of reserves are found, E&E assets will be reclassified to oil and gas properties and development costs and, if not, E&E assets will be expensed on the consolidated income statement. Costs incurred in connection with our projects in Canada, Ecuador, Mongolia and exploration projects in China will be reclassified as E&E assets, while producing assets in China will continue to be classified as oil and gas properties and development costs on the consolidated balance sheet.
 
 
   
Impairments
  Cdn GAAP generally used a two-step approach to impairment testing: first comparing asset carrying values with undiscounted future cash flows to determine whether impairment exists and then measuring any impairment by comparing asset carrying values with fair values calculated using discounted cash flows. International Accounting Standard 36, “Impairment of Assets,” uses a one-step approach for both testing and measuring of impairment, with asset carrying values compared directly with the higher of fair value less costs to sell and value in use (which uses discounted future cash flows). This may potentially result in more write downs where carrying values of assets were previously supported under Cdn GAAP on an undiscounted cash flow basis, but could not be supported on a discounted cash flow basis. IFRS also requires the reversal of any previous impairment losses where circumstances have changed such that impairments have been reduced. Cdn GAAP prohibits the reversal of impairment losses. IFRS will result in greater variability in our operating results and asset carrying values.
 
 
   
Capitalized G&A
  G&A directly related to exploration and development activities were capitalized as oil and gas properties and development costs under Cdn GAAP. The threshold to capitalize G&A is higher under IFRS; therefore, we expect to capitalize less G&A in the future and G&A on the consolidated income statement will be higher as a result.
 
 
   
Financial instruments
  Under Cdn GAAP, the equity component of the Company’s Convertible Note and the common share purchase warrants were classified as shareholders’ equity. In accordance with IAS 32, “Financial Instruments: Presentation,” financial instruments with an exercise price denominated in a currency other than our functional currency are accounted for as derivatives. Since our Convertible Note and common share purchase warrants are denominated in Cdn dollars and our functional currency is US dollars, these items were reclassified from shareholders’ equity to liabilities under IFRS. Additionally, IFRS requires derivative instruments to be recorded at fair value with changes in their fair value recognized in the income statement. This will create variability in our results of operations and the carrying value of liabilities.
 
 
   
Stock-based compensation
  Stock options were accounted for using the fair value method under Canadian GAAP. The fair value was determined using the Black Scholes option pricing model and recorded as compensation expense on a straight-line basis over the period that the stock options vested. Under IFRS 2, “Share-Based Payment,” compensation expense will be charged to earnings on a graded vesting basis. This will accelerate the compensation expense recognized on the consolidated income statement in comparison to Cdn GAAP.
 

 

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Off-Balance Sheet Arrangements
We have no off-balance sheet arrangements that would have a material adverse effect on our liquidity, consolidated financial position or results of operations.
ITEM 7A:  
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed in varying degrees to normal market risks inherent in the oil and gas industry, including commodity price risk, foreign currency exchange rate risk, credit risk and liquidity risk. We recognize these risks and manage our operations to minimize our exposures to the extent practicable.
COMMODITY PRICE RISK
Commodity price risk related to oil prices is one of Ivanhoe’s most significant market risk exposures. The Company’s operating results and financial condition are influenced by the prices we receive for our oil production. Oil prices may fluctuate widely in response to a variety of factors including global and domestic economic conditions, weather conditions, political stability, transportation facilities, the price and availability of alternative fuels and government regulations.
Based on our estimated 2011 production, a US$1.00/bbl change in the price of oil would increase or decrease net income and cash flows from operations for 2011 by US$0.82/bbl. In the past, we have used derivatives to minimize variability in our cash flow from operations when required to do so by loan covenants. However, no hedging contracts were in place in 2010 nor do we anticipate using hedging contracts in 2011 to manage our commodity price risk.
FOREIGN CURRENCY EXCHANGE RATE RISK
Ivanhoe is exposed to foreign currency exchange rate risk as a result of incurring capital expenditures and operating costs in currencies other than the US dollar. A substantial portion of our activities are transacted in or referenced to US dollars, including oil sales in Asia, capital spending in Ecuador and ongoing FTF operations. A portion of our transactions are in other currencies, such as Dagang operating costs paid in Chinese renminbi, Tamarack exploration activities funded in Cdn dollars and the 2010 common share issuance in Cdn dollars. The Company did not enter into any foreign currency derivatives in 2010, nor do we anticipate using foreign currency derivatives in 2011. To help reduce the Company’s exposure to foreign currency exchange rate risk, it seeks to hold assets and liabilities denominated in the same currency when appropriate.
The following table shows the Company’s exposure to foreign currency exchange rate risk on its net loss and comprehensive loss, assuming reasonably possible changes in the relevant foreign currency. This analysis assumes all other variables remain constant.
                 
    10% Increase     10% Decrease  
(Increase) Decrease in Net Loss and Comprehensive Loss   or Weakening     or Strengthening  
Chinese renminbi
    1,438       (1,758 )
Canadian dollar
    (2,089 )     167  
CREDIT RISK
Ivanhoe is exposed to credit risk with respect to its cash and cash equivalents, accounts receivable, note receivable, restricted cash and long term receivables. The Company’s maximum exposure to credit risk at December 31, 2010, is represented by the carrying amount of these non-derivative financial assets. Most of the Company’s credit exposures are with counterparties in the energy industry and are therefore exposed to normal industry credit risks. Ivanhoe manages its credit risk by only entering into sales contracts with established entities.
The Company believes its exposure to credit risk related to cash and cash equivalents, as well as restricted cash, is minimal due to the quality of the financial institutions where the funds are held and the nature of the deposit instruments.
Currently, all of the Company’s oil production is sold to one national oil corporation. As a result, 85% of the outstanding accounts receivable balance at December 31, 2010 (December 31, 2009 — 94%) is due from a national oil corporation. Long term value-added tax receivable from Ecuador will be recoverable upon commencement of commercial operations. Ivanhoe considers the risk of default on these items to be low due to the Company’s ongoing operations in China and Ecuador.

 

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LIQUIDITY RISK
Liquidity risk is the risk that suitable sources of funding for the Company’s business activities may not be available. Since cash flows from existing operations are insufficient to fund future capital expenditures, we intend to finance future capital projects with a combination of strategic investors and/or public and private debt and equity markets, either at a parent company level or at the project level or from the sale of existing assets. There is no assurance that we will be able to obtain such financing on favorable terms, if at all.
NON-GAAP FINANCIAL MEASURES
Oil revenue per barrel is calculated by dividing oil revenue by the Company’s total production for the respective periods presented. Net operating revenue per barrel is calculated by dividing oil revenue less operating costs by total production for the respective periods presented. Net revenue (loss) from operations per barrel is calculated by subtracting depletion from net operating revenue and dividing by total production for the respective periods presented. The Company believes oil revenue per barrel, net operating revenue per barrel and net revenue (loss) from operations per barrel are important to investors to evaluate operating results and the Company’s ability to generate cash. Each of the components used in these calculations can be reconciled directly to the consolidated statement of loss and comprehensive loss. The calculations of oil revenue per barrel, net operating revenue per barrel and net revenue (loss) from operations per barrel may differ from similar calculations of other companies in the oil and gas industry, thereby limiting its usefulness as a comparative measure.

 

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ITEM 8:  
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
         
    37  
 
       
Consolidated Financial Statements
       
 
       
    38  
 
       
    39  
 
       
    40  
 
       
    41  
 
       
    42  
 
       
    71  

 

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REPORT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS
To the Board of Directors and Shareholders of Ivanhoe Energy Inc.,
We have audited the accompanying consolidated financial statements of Ivanhoe Energy Inc. and subsidiaries, which comprise the consolidated balance sheets as at December 31, 2010 and 2009, and the consolidated statements of loss and comprehensive loss, shareholders’ equity and cash flows for each of the years in the three-year period ended December 31, 2010 and the notes to the consolidated financial statements.
Management’s Responsibility for the Consolidated Financial Statements
Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with Canadian generally accepted accounting principles, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.
Auditor’s Responsibility
Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.
We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.
Opinion
In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Ivanhoe Energy Inc. and subsidiaries as at December 31, 2010 and 2009 and the results of their operations and cash flows for each of the years in the three-year period ended December 31, 2010 in accordance with Canadian generally accepted accounting principles.
Emphasis of Matter
Without qualifying our opinion, we draw attention to Note 2 in the financial statements which indicates that the Company had an accumulated deficit of $284.9 million and working capital of $16.5 million at December 31, 2010 and cash flow used in operating activities of $17.8 million and a net loss of $29.1 million during the year ended December 31, 2010. These conditions, along with other matters as set forth in Note 2, indicate the existence of a material uncertainty that may cast significant doubt about the Company’s ability to continue as a going concern.
Other Matter
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 4, 2011 expressed an unqualified opinion on the Company’s internal control over financial reporting.
     
/s/ Deloitte & Touche LLP
 
Deloitte & Touche LLP
   
Independent Registered Chartered Accountants
   
Calgary, Canada
   
March 4, 2011
   

 

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IVANHOE ENERGY INC.
Consolidated Balance Sheets
December 31, 2010 and 2009
                 
(US$000s, except share amounts)   2010     2009  
Assets
               
Current Assets
               
Cash and cash equivalents (Note 15)
    67,817       21,512  
Accounts receivable
    6,359       5,021  
Note receivable
    264       225  
Prepaid and other current assets
    2,859       771  
Restricted cash (Note 18)
    500       2,850  
 
           
 
    77,799       30,379  
 
               
Oil and gas properties and development costs, net (Note 3)
    237,200       158,392  
Intangible assets (Note 4)
    92,153       92,153  
Long term receivables (Note 12)
    2,433       839  
 
           
 
    409,585       281,763  
 
           
 
               
Liabilities and Shareholders’ Equity
               
Current Liabilities
               
Accounts payable and accrued liabilities (Note 12)
    21,482       10,779  
Debt (Note 5)
    39,832        
Income tax payable (Note 14)
          530  
Asset retirement obligations (Note 6)
          753  
 
           
 
    61,314       12,062  
 
               
Long term debt (Note 5)
          36,934  
Asset retirement obligations (Note 6)
    744       195  
Long term obligation (Note 7)
    1,900       1,900  
Future income tax liability (Note 14)
    21,518       22,643  
 
           
 
    85,476       73,734  
 
           
 
               
Commitments and contingencies (Note 7)
               
 
               
Going concern and basis of presentation (Note 2)
               
 
               
Shareholders’ Equity
               
Share capital, issued 334,365,482 common shares
    550,562       422,322  
December 31, 2009 282,558,593 common shares
               
Purchase warrants (Note 8)
    33,423       19,427  
Contributed surplus
    22,983       20,029  
Convertible note (Note 5)
    2,086       2,086  
Accumulated deficit
    (284,945 )     (255,835 )
 
           
 
    324,109       208,029  
 
           
 
    409,585       281,763  
 
           
(See accompanying Notes to the Consolidated Financial Statements)
Approved on behalf of the Board:
     
(signed) “Robert M. Friedland”
Director
  (signed) “Brian F. Downey”
Director

 

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IVANHOE ENERGY INC.
Consolidated Statements of Loss and Comprehensive Loss
Three Years Ended December 31, 2010
                         
(US$000s, except per share amounts)   2010     2009     2008  
Revenue
                       
Oil
    21,720       24,968       48,370  
Gain (loss) on derivative instruments
          (1,335 )     1,688  
Interest
    208       25       612  
 
                 
 
    21,928       23,658       50,670  
 
                 
 
                       
Expenses
                       
Operating
    9,503       10,191       21,515  
General and administrative
    26,260       21,693       14,252  
Business and technology development
    10,615       9,501       6,453  
Depletion and depreciation
    8,960       19,868       25,761  
Foreign exchange (gain) loss
    (3,325 )     5,220       1,527  
Interest and financing
    24       856       1,309  
Impairment of intangible asset and development costs (Note 3)
          1,903       15,054  
Impairment of deferred financing costs (Note 13)
                2,621  
 
                 
 
    52,037       69,232       88,492  
 
                 
 
                       
Loss from continuing operations before income taxes
    (30,109 )     (45,574 )     (37,822 )
 
                       
(Provision for) recovery of income taxes (Note 14)
                       
Current
    (126 )     (1,757 )     (654 )
Future
    1,125       9,600        
 
                 
 
    999       7,843       (654 )
 
                 
 
                       
Net loss — continuing operations
    (29,110 )     (37,731 )     (38,476 )
Net (loss) income — discontinued operations (net of tax of $29.6 million for 2009, nil for 2008) (Note 18)
          (23,921 )     4,283  
 
                 
Net loss and comprehensive loss
    (29,110 )     (61,652 )     (34,193 )
 
                 
Net loss per common share
                       
Net loss — continuing operations, basic and diluted
    (0.09 )     (0.13 )     (0.15 )
Net (loss) income — discontinued operations, basic and diluted
          (0.09 )     0.02  
 
                 
Net loss per common share, basic and diluted
    (0.09 )     (0.22 )     (0.13 )
 
                 
 
                       
Weighted average number of common shares
                       
Basic and diluted (000s)
    327,442       279,722       258,815  
 
                 
(See accompanying Notes to the Consolidated Financial Statements)

 

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IVANHOE ENERGY INC.
Consolidated Statements of Shareholders’ Equity
Three Years Ended December 31, 2010
                         
(US$000s)   2010     2009     2008  
Common shares, beginning of year
    422,322       413,857       324,262  
Shares issued for cash, net of share issue costs (Note 8)
    121,697             82,451  
Shares issued for services
    799       207        
Shares issued for acquisition of a business, net of share issue costs (Note 17)
          6,874        
Exercise of stock options
    5,735       1,384       1,792  
Exercise of purchase warrants
    9              
Exercise of convertible debt
                4,862  
Shares issued for employee bonuses
                490  
 
                 
End of year
    550,562       422,322       413,857  
 
                 
 
                       
Purchase warrants, beginning of year (Note 8)
    19,427       18,805       23,078  
Issuance of special warrants on private placement
    13,999              
Warrants issued for acquisition of a business
          622        
Exercise of purchase warrants
    (3 )            
Expiry of purchase warrants
                (4,273 )
 
                 
End of year
    33,423       19,427       18,805  
 
                 
 
                       
Contributed surplus, beginning of year
    20,029       16,862       9,937  
Stock-based compensation expense
    6,894       3,659       3,239  
Exercise of stock options
    (3,940 )     (492 )     (587 )
Expiry of purchase warrants
                4,273  
 
                 
End of year
    22,983       20,029       16,862  
 
                 
 
                       
Convertible note, beginning of year
    2,086       2,086        
Issuance of convertible note
                2,086  
 
                 
End of year
    2,086       2,086       2,086  
 
                 
 
                       
Accumulated deficit, beginning of year
    (255,835 )     (194,183 )     (159,990 )
Net loss and comprehensive loss
    (29,110 )     (61,652 )     (34,193 )
 
                 
End of year
    (284,945 )     (255,835 )     (194,183 )
 
                 
(See accompanying Notes to the Consolidated Financial Statements)

 

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IVANHOE ENERGY INC.
Consolidated Statements of Cash Flows
Three Years Ended December 31, 2010
                         
(US$000s)   2010     2009     2008  
Operating Activities
                       
Net loss
    (29,110 )     (61,652 )     (34,193 )
Net loss (income) from discontinued operations
          23,921       (4,283 )
Items not requiring use of cash
                       
Depletion and depreciation
    8,960       19,868       25,761  
Provision for impairment
          1,903       15,054  
Stock-based compensation (Note 9)
    6,095       3,849       3,016  
Unrealized loss (gain) on derivative instruments
          1,459       (6,118 )
Impairment of deferred financing costs (Note 13)
                2,621  
Unrealized foreign exchange (gain) loss
    (3,523 )     5,109       1,762  
Future income tax recovery
    (1,125 )     (9,600 )      
Provision for uncollectible accounts
          174       625  
Other
    (14 )     553       519  
Abandonment costs settled (Note 6)
    (179 )     (118 )      
Changes in non-cash working capital items
    1,132       (459 )     6,016  
 
                 
Net cash (used in) provided by operating activities — continuing operations
    (17,764 )     (14,993 )     10,780  
Net cash provided by operating activities — discontinued operations
          2,703       6,273  
 
                 
Net cash (used in) provided by operating activities
    (17,764 )     (12,290 )     17,053  
 
                 
 
                       
Investing Activities
                       
Capital investments
    (86,285 )     (26,373 )     (21,063 )
Acquisition of oil and gas assets
                (22,308 )
Settlement of advances
                200  
Decrease (increase) in restricted cash
    2,350       (2,000 )     (850 )
Long term receivables
    (1,558 )     (587 )     73  
Changes in non-cash working capital items
    5,633       64       (1,035 )
 
                 
Net cash used in investing activities — continuing operations
    (79,860 )     (28,896 )     (44,983 )
Net cash provided by (used in) investing activities — discontinued operations
          35,292       (4,338 )
 
                 
Net cash (used in) provided by investing activities
    (79,860 )     6,396       (49,321 )
 
                 
 
                       
Financing Activities
                       
Shares and warrants issued on private placements, net of share issue costs
    135,696             82,451  
Share issue costs on acquisition
          (26 )      
Proceeds from exercise of options and warrants
    2,600       893       1,205  
Proceeds from debt obligations, net of financing costs
                4,790  
Payments of debt obligations
          (7,416 )     (15,750 )
Payments of deferred financing costs
                (2,621 )
Other
          (100 )     (50 )
Changes in non-cash working capital items
    (10 )     (26 )     26  
 
                 
Net cash provided by (used in) financing activities — continuing operations
    138,286       (6,675 )     70,051  
Net cash provided by (used in) financing activities — discontinued operations
          (5,200 )     700  
 
                 
Net cash provided by (used in) financing activities
    138,286       (11,875 )     70,751  
 
                 
 
                       
Foreign exchange gain (loss) on cash and cash equivalents held in a foreign currency
    5,643       16       (10,574 )
 
                 
Increase (decrease) in cash and cash equivalents, for the year
    46,305       (17,753 )     27,909  
Cash and cash equivalents, beginning of year
    21,512       39,265       11,356  
 
                 
Cash and cash equivalents, end of year
    67,817       21,512       39,265  
 
                 
 
                       
Cash and cash equivalents, end of year — continuing operations
    67,817       21,512       38,477  
 
                 
Cash and cash equivalents, end of year — discontinued operations
                788  
 
                 
(See accompanying Notes to the Consolidated Financial Statements)

 

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IVANHOE ENERGY INC.
Notes to the Consolidated Financial Statements
(all tabular amounts are expressed US$000s, except share and per share amounts)
1. NATURE OF OPERATIONS
Ivanhoe Energy Inc. (the “Company” or “Ivanhoe”), a Canadian company, is an independent international heavy oil development and production company focused on pursuing long term growth in its reserves and production. Ivanhoe plans to utilize advanced technologies designed to significantly improve recovery of heavy oil resources, including its HTL™ technology. In addition, the Company seeks to expand its reserve base and production through conventional exploration and production of oil and gas. Our core operations are carried out in Canada, Ecuador, China and Mongolia.
2. SIGNIFICANT ACCOUNTING POLICIES
These consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles (“GAAP”). The impact of material differences between Canadian and US GAAP on the consolidated financial statements is disclosed in Note 20.
The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts and other disclosures in these consolidated financial statements. Actual results may differ from those estimates. In particular, the amounts recorded for depletion and depreciation of the oil and gas properties and accretion for asset retirement obligations are based on estimates of reserves and future costs. By their nature, these estimates, and those related to future cash flows used to assess impairment of oil and gas properties and development costs as well as intangible assets, are subject to measurement uncertainty and the impact on the financial statements of future periods could be material.
Going Concern and Basis of Presentation
These consolidated financial statements have been prepared in accordance with GAAP applicable to a going concern, which assumes that Ivanhoe will be able to meet its obligations and continue operations for at least its next fiscal year. Realization values may be substantially different from carrying values as shown and these consolidated financial statements do not give effect to adjustments that may be necessary to the carrying values and classification of assets and liabilities should the Company be unable to continue as a going concern. Such adjustments could be material.
At December 31, 2010, Ivanhoe had an accumulated deficit of $284.9 million and working capital of $16.5 million. In 2010, cash used in operating activities was $17.8 million and the Company expects to incur further losses in the development of its business. Continuing as a going concern is dependent upon attaining future profitable operations to repay liabilities arising in the normal course of operations and accessing additional capital to develop the Company’s properties (refer to Notes 5 and 7). Ivanhoe intends to finance its future funding requirements through a combination of strategic investors and/or public and private debt and equity markets, either at a parent company level or at the project level. There is no assurance that Ivanhoe will be able to obtain such financing on favorable terms, if at all. Without access to additional financing in 2011, there is significant doubt that the Company will be able to continue as a going concern.
Principles of Consolidation
The consolidated financial statements include the accounts of the Company, its subsidiaries and any variable interest entities. Any reference to the Company or Ivanhoe throughout these consolidated financial statements refers to Ivanhoe, its subsidiaries, and any variable interest entities. All inter-entity transactions have been eliminated. Ivanhoe conducts some of its oil production activities through jointly controlled operations and the consolidated financial statements reflect only Ivanhoe’s proportionate interest in such activities.
Foreign Currency Translation
The Company’s functional currency is the US dollar. All of Ivanhoe’s operations are considered integrated and are translated into US dollars using the temporal method. Under this method, monetary assets and liabilities are translated at the exchange rate in effect at the balance sheet date. Non-monetary assets and liabilities, as well as operating transactions, are translated at the exchange rate prevailing at the time of the transaction. Translation exchange gains and losses are reflected in the results of operations.

 

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Cash and Cash Equivalents
Cash and cash equivalents include short term investments, such as money market deposits or similar type instruments, with an original maturity of 90 days or less when purchased.
Full Cost Accounting for Oil and Gas Operations
The Company follows the full cost method of accounting for oil and gas operations whereby all exploration and development expenditures are capitalized on a country-by-country cost center basis. Such expenditures could include lease and royalty interest acquisitions, geological and geophysical expenses, carrying charges for unproved properties, costs of drilling both successful and unsuccessful wells, gathering and production facilities and equipment, major renovations, financing, asset retirement costs and administrative costs related to capital projects.
Proceeds from the sale of oil and gas properties are applied against capitalized costs, without any gain or loss being realized, unless such sale would significantly alter the rate of depletion and depreciation, in which case a gain or loss would be recognized.
Capitalized Interest
The Company capitalizes interest on major development projects until construction is complete. Capitalized interest cannot exceed the actual interest incurred.
Depletion and Depreciation
Provision for depletion of oil and gas assets is calculated using the unit-of-production method, based on proved reserves net of royalties as evaluated by independent petroleum engineers. The cost basis used for the depletion provision is the capitalized costs of oil and gas assets, including undeveloped property, plus the estimated future development costs of proved undeveloped reserves.
Furniture and equipment are depreciated on a straight line basis over the estimated useful life of the respective assets, at rates ranging from three to five years. The Feedstock Testing Facility (“FTF”) is being depreciated over its expected economic life of 20 years.
Impairment
The Company annually evaluates the carrying values of its oil and gas properties and development costs whenever events or conditions occur that indicate that the carrying values may not be recoverable from future cash flows. If the carrying values exceed the sum of estimated undiscounted future cash flows expected from proved reserves, the asset is impaired. The impairment charge is measured by assigning a fair value to the asset equal to its estimated discounted future net cash flows expected from proved plus probable reserves and the excess carrying value is expensed in the results of operations. The cost of unproved properties is excluded from the impairment test described above and subject to a separate impairment test. If impaired, the carrying value of the unproved properties is included in the petroleum and gas depletable base.
Cash flow estimates require assumptions about future commodity prices, ultimate recoverability of oil and gas reserves, operating costs and other factors. Actual results can differ materially from these estimates.
Intangible Assets
Intangible assets are recognized and measured at cost. Intangible assets with finite lives are amortized over their estimated useful life. Intangible assets are reviewed at least annually for impairment, or when events or changes in circumstances indicate that the carrying value of an intangible asset may not be recoverable. If the carrying value of an intangible asset exceeds its fair value or expected discounted future cash flows, the excess is expensed to the results of operations.
Asset Retirement Costs
The Company provides for future asset retirement obligations on its resource properties and facilities based on estimates established by current legislation and industry practices. The asset retirement obligation is initially measured at fair value and capitalized to the asset as an asset retirement cost that is depreciated over the life of the related asset. The obligation is accreted through interest expense until it is settled.

 

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The fair value of the obligation is estimated by discounting expected future cash outflows to settle the asset retirement obligation using a credit-adjusted risk-free interest rate. Ivanhoe recognizes revisions to either the timing or the amount of the original estimate of undiscounted cash outflows as increases or decreases to the asset retirement obligation. Actual retirement costs are recorded against the obligation when incurred. Any difference between the recorded asset retirement obligations and the actual retirement costs incurred is recorded as a gain or loss in the settlement period.
Oil and Gas Revenue
Sales of oil and gas are recognized in the period in which the product is delivered to the customer. Oil and gas revenue represents the Company’s share and is recorded net of royalty payments to governments and other mineral interest owners.
In China, the Company conducts operations jointly with the government of China in accordance with a production sharing contract. Under this contract, the Company pays its share of operating costs and both its share and the government’s share of capital costs. The Company recovers the government’s share of the capital costs from future revenues over the life of the production sharing contract.
Income or Loss Per Common Share
Basic net income per common share is computed by dividing net income by the weighted average number of common shares outstanding during the period. Diluted net income per common share amounts are calculated based on net income divided by dilutive common shares. Dilutive common shares are arrived at by adding weighted average common shares to common shares issuable on conversion of options, using the treasury stock method. The treasury stock method assumes that proceeds received from the exercise of in-the-money options is used to repurchase common shares at the average market price. Dilution from the convertible debt is considered using the “if converted” method.
Income Taxes
Ivanhoe follows the liability method of accounting for future income taxes. Under the liability method, income tax assets and liabilities are recorded to reflect the expected future tax consequences of tax loss carry-forwards and temporary differences between the carrying value and the tax basis of the Company’s assets and liabilities. A valuation allowance is recorded if the future benefit of income tax assets, including unused tax losses, is not more likely than not to be ultimately realized. The effect of a change in tax rate on future income tax assets and liabilities is recognized in net income in the period in which the change is substantively enacted.
Stock-based Compensation
Options to purchase common shares are granted to directors, officers, employees and consultants at current market prices. The fair value of the options at the time of grant is recognized as a compensation expense in the results of operations over the vesting period of the option, with a corresponding increase to contributed surplus. Upon the exercise of the stock options, consideration paid together with the amount previously recognized in contributed surplus, is recorded as an increase in share capital. In the event that vested options expire unexercised, the previously recognized compensation expense associated with such stock options is not reversed. Forfeitures are estimated at the grant date and are subsequently adjusted to reflect actual forfeitures.
Financial Assets and Liabilities
Financial assets and financial liabilities are measured at fair value on initial recognition. Measurement in subsequent periods depends on whether the financial instrument has been classified as held-for-trading, loans and receivables, or other financial liabilities.
Financial assets and liabilities designated as held-for-trading are subsequently measured at fair value with changes in those fair values charged immediately to earnings. Ivanhoe classifies all derivative contracts as held-for trading. Cash and cash equivalents and restricted cash are classified as held-for-trading. Transaction costs are expensed as incurred.
Loans and receivables and other financial liabilities are subsequently measured at amortized cost using the effective interest method. Ivanhoe classifies accounts receivable and the note receivable as loans and receivables, and accounts payable, debt and the long term obligation as other financial liabilities. Transaction costs for other long term financial liabilities are deducted from the related liability and accounted for using the effective interest rate method.

 

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Fair value measurements are classified according to the following hierarchy based on the amount of observable inputs used to value the instrument.
Level 1 —  
Quoted prices are available in active markets. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 —  
Pricing inputs are other than quoted prices in an active market included in Level 1. Prices in Level 2 are either directly or indirectly observable as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value and volatility factors, which can be substantially observed or corroborated in the market place.
Level 3 —  
Valuation at this level are those with inputs for the asset or liability that are not based on observable market data.
Assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy.
3. OIL AND GAS PROPERTIES AND DEVELOPMENT COSTS
                                                 
As at December 31, 2010   Oil and Gas             Business and        
    Integrated     Conventional             Technology        
    Canada     Ecuador     Asia     Corporate     Development     Total  
Oil and gas properties
                                               
Proved
                159,551                   159,551  
Unproved
    125,435       26,249       39,126                   190,810  
 
                                   
 
    125,435       26,249       198,677                   350,361  
Accumulated depletion
                (108,334 )                 (108,334 )
Accumulated provision for impairment
                (16,550 )                 (16,550 )
 
                                   
 
    125,435       26,249       73,793                   225,477  
 
                                   
 
                                               
Development costs
                                               
Feasibility studies and other deferred costs
                                               
Iraq and Libya — HTL™
                            834       834  
Egypt — GTL
                            5,054       5,054  
Accumulated provision for impairment
                            (5,888 )     (5,888 )
Feedstock test facility
                            11,426       11,426  
Accumulated depreciation and impairment
                            (921 )     (921 )
 
                                   
 
                            10,505       10,505  
 
                                   
 
                                               
Furniture and equipment
    27       436       592       1,361       58       2,474  
Accumulated depreciation
    (17 )     (101 )     (229 )     (894 )     (15 )     (1,256 )
 
                                   
 
    10       335       363       467       43       1,218  
 
                                   
 
    125,445       26,584       74,156       467       10,548       237,200  
 
                                   

 

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As at December 31, 2009   Oil and Gas             Business and        
    Integrated     Conventional             Technology        
    Canada     Ecuador     Asia     Corporate     Development     Total  
Oil and gas properties
                                               
Proved
                148,110                   148,110  
Unproved
    94,431       6,755       14,411                   115,597  
 
                                   
 
    94,431       6,755       162,521                   263,707  
Accumulated depletion
                (99,744 )                 (99,744 )
Accumulated provision for impairment
                (16,550 )                 (16,550 )
 
                                   
 
    94,431       6,755       46,227                   147,413  
 
                                   
 
                                               
Development costs
                                               
Feasibility studies and other deferred costs
                                               
Iraq and Libya — HTL™
                            834       834  
Egypt — GTL
                            5,054       5,054  
Accumulated provision for impairment
                            (5,888 )     (5,888 )
Feedstock test facility
                            10,868       10,868  
Accumulated depreciation and impairment
                            (393 )     (393 )
 
                                   
 
                            10,475       10,475  
 
                                   
 
                                               
Furniture and equipment
    24       169       135       968       22       1,318  
Accumulated depreciation
    (8 )     (53 )     (92 )     (650 )     (11 )     (814 )
 
                                   
 
    16       116       43       318       11       504  
 
                                   
 
    94,447       6,871       46,270       318       10,486       158,392  
 
                                   
Costs associated with unproved oil and gas properties that were not subject to depletion amounted to $190.8 million at December 31, 2010 (December 31, 2009 — $115.6 million). Costs subject to depletion included future capital expenditures of $7.3 million at December 31, 2010 (December 31, 2009 — $3.3 million) relating to the development of proved undeveloped reserves, as estimated by the Company’s independent reserve engineers.
In 2010, $7.0 million (2009 — $4.1 million; 2008 — $1.0 million) in general and administrative expenses related directly to exploration and development activities and interest of $2.5 million (2009 — $2.2 million; 2008 — $3.8 million) were capitalized.
The Company performed a ceiling test calculation at December 31, 2010, 2009 and 2008 to assess the recoverable value of its oil and gas properties. The present value of future net revenue from the Company’s proved reserves exceeded the carrying value of the Company’s oil and gas properties in 2010, 2009 and 2008, resulting in no impairment in each of those years. West Texas Intermediate prices used in calculating the expected future cash flows were based on the following benchmark prices adjusted for gravity, transportation and other factors as required by sales agreements as at December 31, 2010:
         
($/bbl)      
2011
    88.00  
2012
    89.00  
2013
    90.00  
2014
    92.00  
2015
    95.17  
2016
    97.55  
2017
    100.26  
2018
    102.74  
2019
    105.45  
2020
    107.56  
Thereafter
  2% per year
 
     
In 2009, Ivanhoe impaired $0.8 million of development costs associated with its HTL™ projects in Iraq and Libya. Gas-to-Liquids technology (“GTL”) development costs of $5.1 million and intangible GTL assets of $10.0 million were impaired in 2008.

 

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When the Company’s FTF was placed into service, the Commercial Demonstration Facility was abandoned and the carrying value of $0.9 million was written down to nil in 2009.
4. INTANGIBLE ASSETS
The Company’s intangible assets consist of an exclusive, irrevocable license to deploy HTL™ technology, a master license permitting Ivanhoe to use the Syntroleum Process and the exclusive right to deploy the Rapid Thermal Processing process in all applications other than biomass. The carrying value of the HTL™ technology as at December 31, 2010 and 2009 was $92.2 million. This asset was not amortized and its carrying value was not impaired for the years ended December 31, 2010, 2009 and 2008.
5. DEBT
                 
As at December 31,   2010     2009  
Convertible note
    40,217       38,005  
Unamortized discount
    (385 )     (1,071 )
 
           
 
    39,832       36,934  
 
           
In connection with the acquisition of the Tamarack leases in July 2008 from Talisman Energy Canada (“Talisman”) (refer to Note 17), the Company issued a Cdn$40.0 million convertible promissory note (the “Convertible Note”) which matures in July 2011. Interest at the prime rate plus 2% is calculated daily and is payable semi-annually. The outstanding principal amount is convertible, at Talisman’s option, into a maximum of 12,779,552 Ivanhoe common shares at Cdn$3.13 per common share. The interest rate on the Convertible Note at December 31, 2010 was 5.00% (December 31, 2009 — 4.25%).
The Convertible Note is a compound financial instrument, containing a debt instrument as well as an embedded conversion feature classified as equity. The residual basis method was used to value the instrument. The fair value of the liability component was determined and the remaining value was assigned to the bifurcated equity component. The value of the liability was determined by discounting the expected interest and principal payments and was calculated at Cdn$37.9 million with the remaining value of Cdn$2.1 million allocated to the equity component. The liability component is accreted over the three year maturity period up to the Cdn$40.0 million principal amount using the effective interest rate method.
The Company’s obligations under the Convertible Note are secured by a first fixed charge and security interest in favor of Talisman against the acquired Talisman leases and the related assets acquired by the Company pursuant to the Talisman lease acquisition.
Interest expense included in the statement of operations was nil in 2010 (2009 — $0.8 million; 2008 — $1.2 million). In 2010, $2.5 million (2009 — $2.2 million; 2008 — $3.8 million) in interest was capitalized to oil and gas properties and development costs in the consolidated balance sheet.
6. ASSET RETIREMENT OBLIGATIONS
At December 31, 2010, the Company’s total estimated undiscounted inflated costs to settle its asset retirement obligations were approximately $1.9 million (December 31, 2009 — $0.9 million). These costs are expected to be incurred between 2013 and 2038 and have been discounted using an inflation rate specific to the country in which the costs will be incurred (2% to 4%) and a weighted average credit-adjusted risk-free rate of 5.2% (December 31, 2009 — 5.3%).
                 
As at December 31,   2010     2009  
Asset retirement obligations, beginning of year
    948       1,928  
Liabilities incurred
    479       185  
Liabilities settled
    (179 )     (118 )
Accretion expense
    23       79  
Revisions in estimated cash flows
    (527 )     (1,126 )
 
           
 
    744       948  
Less current portion
          (753 )
 
           
Asset retirement obligations, end of year
    744       195  
 
           

 

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7. COMMITMENTS AND CONTINGENCIES
Long Term Obligation
As part of its 2005 merger with Ensyn Group Inc., the Company assumed an obligation to pay $1.9 million in the event that proceeds from the sale of units incorporating the HTL™ technology for petroleum applications reach a total of $100.0 million.
Income Taxes
The Company has an uncertain tax position in China related to when it is entitled to take tax deductions on capitalized development costs that are amortized over six years on a straight line basis. To the extent that there is a different interpretation in the timing of the deductibility of development costs, this could potentially result in an increase in the current tax expense of $0.9 million.
The Company has an uncertain tax position related to the calculation of a gain on the consideration received from two farm-out transactions. To the extent that the calculation of the gain is interpreted differently and the amounts are subject to withholding tax, there would be an additional current tax expense of approximately $0.7 million.
No amounts have been recorded in the consolidated financial statements related to the above mentioned uncertain tax positions as management has determined the likelihood of an unfavorable outcome to the Company to be low.
Lease Commitments
In 2010, the Company expended $2.6 million (2009 — $1.2 million; 2008 — $1.1 million) on operating leases relating to the rental of office space, which expire between January 2011 and September 2013. As at December 31, 2010, future net minimum payments for operating leases were the following:
         
2011
    1,769  
2012
    885  
2013
    335  
 
     
 
    2,989  
 
     
Other
The Company may be required to make a Cdn$15.0 million cash payment to Talisman upon receiving government and other approvals necessary to develop the northern border of one of the Tamarack leases (refer to Note 17).
Occasionally, Ivanhoe enters into consulting agreements whereby a success fee may be payable if and when either a definitive agreement is signed or certain other contractual milestones are met. Under these agreements, the consultant may receive cash, common shares, stock options or some combination thereof.
From time to time, Ivanhoe is involved in litigation or has claims brought against it in the normal course of business. Management is currently not aware of any claims that would materially affect the reported financial position or results of operations.

 

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8. SHAREHOLDERS’ EQUITY
The authorized capital of the Company consists of an unlimited number of common shares without par value and an unlimited number of preferred shares without par value.
                         
(000s)   2010     2009     2008  
Common shares, beginning of year
    282,559       279,381       244,874  
Shares issued for cash
    50,000             29,334  
Shares issued for services
    280       81        
Shares issued for acquisition of a business (Note 17)
          2,683        
Exercise of stock options
    1,525       414       2,666  
Exercise of purchase warrants
    2              
Exercise of convertible debt
                2,291  
Shares issued for employee bonuses
                216  
 
                 
End of year
    334,366       282,559       279,381  
 
                 
The following reflects the changes in the Company’s common share purchase warrants for the three year period ended December 31, 2010.
                         
(000s)   2010     2009     2008  
Purchase warrants, beginning of year
    12,135       11,400       26,496  
Private placements
    12,500             29,334  
Issued on acquisition
          735        
Exercised
    (2 )           (29,334 )
Expired
                (15,096 )
 
                 
End of year
    24,633       12,135       11,400  
 
                 
                                                 
                                            Cash  
    Price per                             Exercise     Value on  
Year of   Special     Outstanding(1)     Value     Expiry     Price per     Exercise  
Issue   Warrant     (000s)     ($US000s)     Date     Share     ($US000s)  
2006
  US$ 2.23       11,398       18,802     May 2011   Cdn$ 2.93 (2)     33,577  
2009
    N/A       735       622     Feb 2011   Cdn$ 4.05       2,993  
2010
  Cdn$ 3.00       10,417       11,419     Feb 2011   Cdn$ 3.16       33,095  
2010
  Cdn$ 3.00       2,083       2,580     Feb 2011   Cdn$ 3.16       6,619  
 
                                   
 
            24,633       33,423                       76,284  
 
                                   
     
(1)  
One common share is issuable for each purchase warrant upon exercise.
 
(2)  
Each common share purchase warrant originally entitled the holder to purchase one common share at a price of $2.63 per share until the fifth anniversary date of the closing. In September 2006, these warrants were listed on the Toronto Stock Exchange and the exercise price was changed to Cdn$2.93.
In January 2010, the Company completed a Cdn$125.0 million private placement (the “Private Placement”) consisting of 41,666,667 special warrants (“Special Warrants”) at Cdn$3.00. Each Special Warrant was converted into one common share of the Company and one-quarter of a common share purchase warrant. Each whole common share purchase warrant entitles the holder to acquire one common share of the Company at an exercise price of Cdn$3.16 on or before February 25, 2011 (refer to Note 19). The net proceeds from the Private Placement were approximately Cdn$120.2 million after deducting fees and commissions of Cdn$4.3 million and expenses of the Private Placement of approximately Cdn$0.5 million.
Under the terms of the Private Placement, an additional 8,333,333 Special Warrants issuable at Cdn$3.00 per Special Warrant were subject to an option, which were exercised in February 2010 for Cdn$25.0 million. The net proceeds realized by the Company from the issue of the Special Warrants were Cdn$23.8 million, after deducting fees and commissions payable of Cdn$1.1 million and expenses of Cdn$0.1 million. Each Special Warrant was converted into one common share and one-quarter of a common share purchase warrant following the issuance of a receipt for a prospectus by applicable Canadian securities regulatory authorities, which occurred on March 12, 2010.

 

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The Company calculated the value of the common share purchase warrants using the Black Scholes option pricing model which included assumptions related to risk-free interest rates, volatility factors, and the expected life of the warrant. The value of the 10.4 million and 2.1 million purchase warrants issued in 2010 were calculated using a risk-free interest rate of 0.7% and 0.9% respectively, a volatility factor of 78.9% and 71.6% respectively and an expected life of one year.
In January 2010, one of the Company’s subsidiaries signed an agreement that granted a private investor an option to acquire a 20% interest in the subsidiary for Cdn$25.0 million. The option is valid for one year and does not become exercisable until the first quarter of 2011. The option was determined to have a nominal value at the grant date.
In 2009, 0.7 million purchase warrants were issued in exchange for outstanding warrants of a company that Ivanhoe acquired (refer to Note 17).
In July 2008, the Company completed a Cdn$88.0 million private placement consisting of 29,334,000 special warrants at Cdn$3.00 per special warrant (the “Offering”). Each of these special warrants entitled the holder to one common share of the Company upon exercise of the special warrant. In August 2008, all of these special warrants were exercised for 29,334,000 common shares. The net proceeds from the Offering were approximately Cdn$83.4 million after deducting the agents’ commission of Cdn$4.0 million and expenses of Cdn$0.6 million. The Company used Cdn$22.5 million of the net proceeds of the Offering to complete the cash component of the Talisman lease acquisition.
In April 2008, the Company obtained a loan from a third party finance company in the amount of Cdn$5.0 million bearing interest at 8% per annum. The principal and accrued and unpaid interest matured and was repayable in August 2008. In August 2008, the lender exercised its option to convert the entire outstanding balance into the Company’s common shares at a conversion price of Cdn$2.24 per share.
As the Company incurred a net loss for the years ended December 31, 2010, 2009 and 2008, the following potentially dilutive securities had an anti-dilutive effect on basic earnings per share:
                         
(000s of common shares)   2010     2009     2008  
Stock options
    16,927       15,013       11,913  
Purchase warrants
    24,633       12,135       11,400  
Convertible debt
    12,780       12,780       12,780  
 
                 
 
    54,340       39,928       36,093  
 
                 
9. STOCK-BASED COMPENSATION
The Company has an Employees’ and Directors’ Equity Incentive Plan under which it can grant stock options to directors and eligible employees to purchase common shares, issue common shares to directors and eligible employees for bonus awards and issue common shares under a share purchase plan for eligible employees. The total number of common shares that may be issued under this plan cannot exceed 7% of the Company’s issued and outstanding common shares which, at December 31, 2010, was 23.4 million (December 31, 2009 — 29.3 million). The maximum common share issuances under this plan was changed from a fixed number of common shares to a percentage of outstanding common shares in the second quarter of 2010.
Stock options are issued at the weighted average trading price for the five days immediately preceding the award and are conditional on continuing employment. Expiration and vesting periods are set at the discretion of the Board of Directors, but typically vest over three to four years and expire five to ten years from the date of issue. In 2007, the Company granted stock option awards that vest upon meeting various departmental and company-wide goals. At December 31, 2010, there were approximately 479,000 unvested options outstanding.

 

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The following table summarizes changes in the Company’s outstanding stock options:
                                                 
    2010     2009     2008  
            Weighted             Weighted             Weighted  
    Number     Average     Number     Average     Number     Average  
    of Stock     Exercise     of Stock     Exercise     of Stock     Exercise  
    Options     Price     Options     Price     Options     Price  
    (000s)     (Cdn$)     (000s)     (Cdn$)     (000s)     (Cdn$)  
Outstanding, beginning of year
    15,013       2.27       11,913       2.32       12,945       2.37  
Granted
    6,041       2.56       4,188       2.17       3,832       1.79  
Exercised
    (2,743 )     2.28       (413 )     2.46       (3,067 )     0.90  
Expired
    (635 )     2.60       (114 )     2.44       (580 )     5.78  
Forfeited
    (749 )     2.64       (561 )     2.41       (1,217 )     3.05  
 
                                   
Outstanding, end of year
    16,927       2.24       15,013       2.27       11,913       2.32  
 
                                   
 
                                               
Exercisable, end of year
    7,324       2.19       7,101       2.48       5,062       2.61  
 
                                   
The following table summarizes information respecting stock options outstanding and exercisable as at December 31, 2010:
                                                 
    Outstanding     Exercisable  
            Weighted Average                     Weighted Average        
Range of           Remaining     Weighted Average             Remaining     Weighted Average  
Exercise Prices   Outstanding     Contractual Life     Exercise Price     Exercisable     Contractual Life     Exercise Price  
(Cdn$)   (000s)     (years)     (Cdn$)     (000s)     (years)     (Cdn$)  
1.51 to 2.06
    6,289       2.7       1.74       3,723       2.3       1.73  
2.15 to 2.71
    7,788       4.9       2.34       2,079       2.7       2.41  
2.77 to 3.41
    2,850       3.8       3.08       1,522       1.6       2.98  
 
                                   
 
    16,927       3.9       2.24       7,324       2.3       2.19  
 
                                   
The fair value of each option award is estimated on the date of grant using the Black Scholes option pricing formula. Service condition options are amortized on a straight line attribution approach and performance condition options amortized over the service period, both with the following weighted average assumptions for the years presented:
                         
    2010     2009     2008  
Expected life (in years)
    6.0       4.6       4.0  
Volatility
    75.2 %     81.1 %     63.5 %
Dividend yield
    0.0 %     0.0 %     0.0 %
Risk-free rate
    2.6 %     2.6 %     3.1 %
The weighted average grant date fair value of stock options granted in 2010 was Cdn$1.73 (2009 — Cdn$1.62; 2008 — Cdn$0.90).

 

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The Company’s stock-based compensation related to option awards, share bonus awards and common shares issued for services were classified as follows in the consolidated statement of loss:
                         
    2010     2009     2008  
General and administrative
                       
Option awards
    5,695       3,484       2,241  
Share bonus awards
                207  
Shares issued for services
          207        
 
                 
 
    5,695       3,691       2,448  
Business and technology development
                       
Option awards
    400       158       432  
Share bonus awards
                136  
 
                 
 
    400       158       568  
Discontinued operations
                       
Option awards
          17       391  
Share bonus awards
                147  
 
                 
 
          17       538  
 
                 
 
    6,095       3,866       3,554  
 
                 
Additionally, in 2010, $0.8 million (2009 — nil; 2008 — $0.2 million) of stock-based compensation was capitalized to oil and gas properties and development costs.
10. RETIREMENT PLAN
In 2001, the Company adopted a defined contribution retirement or thrift plan (“401(k) Plan”) to assist US employees in providing for retirement or other future financial needs. Employees’ contributions (up to the maximum allowed by US tax laws) were matched 100% by the Company in 2010. In 2010, the Company’s matching contributions to the 401(k) Plan were $0.4 million (2009 — $0.4 million; 2008 — $0.5 million).
11. SEGMENT INFORMATION
The Company subdivides its operations into four areas: Oil and Gas — Integrated, Oil and Gas — Conventional, Business and Technology Development and Corporate. Accounting policies for segments are the same as those described in Significant Accounting Policies (refer to Note 2).
Oil and Gas — Integrated
Projects in this segment have two primary components: conventional exploration and production activities supported by enhanced oil recovery techniques, such as steam assisted gravity drainage and deployment of the HTL™ technology. The Company has two projects currently reported in this segment: a heavy oil project in Canada and a heavy oil project in Ecuador.
Oil and Gas — Conventional
Projects in this segment consist of conventional oil and gas exploration and production activities without enhanced oil recovery techniques or the use of HTL™ technology. The Company has two conventional projects in Asia, located in China and Mongolia. Prior to July 2009, the Company conducted conventional exploration, development and production activities primarily in the US (refer to Note 18).
Business and Technology Development
The Company’s Business and Technology Development segment captures HTL™ activities as well as costs associated with the pursuit of new business development opportunities.

 

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Corporate
The Corporate area tracks costs associated with the board of directors, executive officers, corporate debt, financings and other corporate activities.
                                                         
2010  
    Oil and Gas     Business and              
    Integrated     Conventional     Technology              
    Canada     Ecuador     Asia     US(1)     Development     Corporate(2)     Total  
Revenue
                                                       
Oil(3)
                21,720                         21,720  
Interest
                6                   202       208  
 
                                         
 
                21,726                   202       21,928  
 
                                         
 
                                                       
Expenses
                                                       
Operating
                9,503                         9,503  
General and administrative
    1,802       2,707       3,619                   18,132       26,260  
Business and technology development
    187       43                   10,385             10,615  
Depletion and depreciation
    9       47       8,697             (36 )     243       8,960  
Foreign exchange
    (15 )           (62 )                 (3,248 )     (3,325 )
Interest and financing
    6       7                   11             24  
 
                                         
 
    1,989       2,804       21,757             10,360       15,127       52,037  
 
                                         
 
                                                       
Loss — continuing operations before income taxes
    (1,989 )     (2,804 )     (31 )           (10,360 )     (14,925 )     (30,109 )
 
                                                       
(Provision for) recovery of income taxes
                                                       
Current
                (111 )                 (15 )     (126 )
Future
                (73 )           1,198             1,125  
 
                                         
 
                (184 )           1,198       (15 )     999  
 
                                         
 
                                                       
Net loss — continuing operations
    (1,989 )     (2,804 )     (215 )           (9,162 )     (14,940 )     (29,110 )
Net loss — discontinued operations
                                         
 
                                         
Net loss and comprehensive loss
    (1,989 )     (2,804 )     (215 )           (9,162 )     (14,940 )     (29,110 )
 
                                         
 
                                                       
Capital investments
    29,987       18,727       36,613             567       391       86,285  
 
                                         
 
                                                       
Identifiable assets as at December 31, 2010
    125,569       28,916       91,189             102,810       61,101       409,585  
 
                                         
     
(1)  
The Company sold its US operations in the third quarter of 2009.
 
(2)  
Corporate activities undertaken on behalf of a segment are allocated to that segment at cost.
 
(3)  
All revenues in Asia are generated from the sale of production to one customer.

 

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2009  
    Oil and Gas     Business and              
    Integrated     Conventional     Technology              
    Canada     Ecuador     Asia     US(1)     Development     Corporate(2)     Total  
Revenue
                                                       
Oil(3)
                24,968                         24,968  
Loss on derivative instruments
                (1,335 )                       (1,335 )
Interest
                6                   19       25  
 
                                         
 
                23,639                   19       23,658  
 
                                         
 
                                                       
Expenses
                                                       
Operating
                10,191                         10,191  
General and administrative
    1,129       2,269       2,777                   15,518       21,693  
Business and technology development
    560                         8,941             9,501  
Depletion and depreciation
    4       53       18,033             1,633       145       19,868  
Foreign exchange
    (8 )           71             2       5,155       5,220  
Interest and financing
                770             79       7       856  
Provision for impairment of intangible asset and development costs
                            1,903             1,903  
 
                                         
 
    1,685       2,322       31,842             12,558       20,825       69,232  
 
                                         
 
                                                       
Loss — continuing operations before income taxes
    (1,685 )     (2,322 )     (8,203 )           (12,558 )     (20,806 )     (45,574 )
 
                                                       
(Provision for) recovery of income taxes
                                                       
Current
                (1,399 )                 (358 )     (1,757 )
Future
                            9,600             9,600  
 
                                         
 
                (1,399 )           9,600       (358 )     7,843  
 
                                         
 
                                                       
Net loss — continuing operations
    (1,685 )     (2,322 )     (9,602 )           (2,958 )     (21,164 )     (37,731 )
Net loss — discontinued operations (net of tax of $29.6 million)
                      (23,921 )                 (23,921 )
 
                                         
Net loss and comprehensive loss
    (1,685 )     (2,322 )     (9,602 )     (23,921 )     (2,958 )     (21,164 )     (61,652 )
 
                                         
 
                                                       
Capital investments
    12,756       5,380       6,049             2,093       95       26,373  
 
                                         
 
                                                       
Identifiable assets as at December 31, 2009
    94,594       7,597       57,528             102,878       19,166       281,763  
 
                                         
     
(1)  
The Company sold its US operations in the third quarter of 2009.
 
(2)  
Corporate activities undertaken on behalf of a segment are allocated to that segment at cost.
 
(3)  
All revenues in Asia are generated from the sale of production to one customer.

 

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2008  
    Oil and Gas     Business and              
    Integrated     Conventional     Technology              
    Canada     Ecuador     Asia     US(1)     Development     Corporate(2)     Total  
Revenue
                                                       
Oil(3)
                48,370                         48,370  
Gain on derivative instruments
                1,688                         1,688  
Interest
                50                   562       612  
 
                                         
 
                50,108                   562       50,670  
 
                                         
 
                                                       
Expenses
                                                       
Operating
                21,515                         21,515  
General and administrative
    1,627       658       1,967                   10,000       14,252  
Business and technology development
    189                         6,264             6,453  
Depletion and depreciation
    3             23,135             2,618       5       25,761  
Foreign exchange
    26             278                     1,223       1,527  
Interest expense and financing
                821             76       412       1,309  
Provision for impairment of GTL intangible assets and development costs
                            15,054             15,054  
Write off of deferred financing costs
                2,621                         2,621  
 
                                         
 
    1,845       658       50,337             24,012       11,640       88,492  
 
                                         
 
                                                       
Loss — continuing operations before income taxes
    (1,845 )     (658 )     (229 )           (24,012 )     (11,078 )     (37,822 )
 
                                                       
Current provision for income taxes
                (650 )           (2 )     (2 )     (654 )
 
                                         
 
                                                       
Net loss — continuing operations
    (1,845 )     (658 )     (879 )           (24,014 )     (11,080 )     (38,476 )
Net income — discontinued operations
                      4,283                   4,283  
 
                                         
Net (loss) income and comprehensive (loss) income
    (1,845 )     (658 )     (879 )     4,283       (24,014 )     (11,080 )     (34,193 )
 
                                         
 
                                                       
Capital investments
    6,484       1,369       8,378             4,832             21,063  
 
                                         
 
                                                       
Identifiable assets as at December 31, 2008
    81,126       1,766       64,901       65,371       105,587       28,124       346,875  
 
                                         
     
(1)  
The Company sold its US operations in the third quarter of 2009.
 
(2)  
Corporate activities undertaken on behalf of a segment are allocated to that segment at cost.
 
(3)  
All revenues in Asia are generated from the sale of production to one customer.
12. FINANCIAL INSTRUMENTS
The Company’s financial instruments are comprised of cash and cash equivalents, accounts receivable, note receivable, restricted cash, long term receivables, accounts payable and accrued liabilities, debt and a long term obligation.
The Company’s cash and restricted cash are transacted in active markets and have been classified using Level 1 inputs.
Carrying amounts of financial instruments approximate their fair value except for debt. The Company calculated the fair value of its debt to be $40.2 million as at December 31, 2010.
Financial Risk Factors
In the normal course of operations, the Company is exposed to market risks resulting from movements in commodity prices, foreign currency exchange rates and interest rates, which may result in fluctuations in the fair value or future cash flows of its financial instruments.

 

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Commodity Price Risks
Commodity price risk refers to the risk that the value of a financial instrument or cash flows associated with the instrument will fluctuate due to the changes in market commodity prices. Oil prices and quality differentials are influenced by worldwide factors such as OPEC actions, political events and supply and demand fundamentals. The Company may periodically use different types of derivative instruments to manage its exposure to price volatility.
In 2007, the Company entered into a costless collar derivative to minimize variability in its cash flow from the sale of up to 18,000 bbls/month of the Company’s production from its Dagang field in China over a three year period. This derivative had a ceiling price of $84.50 /bbl and a floor price of $55.00 /bbl using the WTI as the index traded on the NYMEX. The contracts related to this derivative were put in place as part of the Company’s bank loan facility and consequently all remaining contracts were settled when this loan was repaid in December 2009.
Results of these derivative transactions for the three years ended December 31, 2010, are:
                         
    2010     2009     2008  
Realized gains (losses) on derivative transactions
          124       (4,430 )
Unrealized gains (losses) on derivative transactions
          (1,459 )     6,118  
 
                 
 
          (1,335 )     1,688  
 
                 
Foreign Currency Exchange Rate Risk
Ivanhoe is exposed to foreign currency exchange rate risk as a result of incurring capital expenditures and operating costs in currencies other than the US dollar. A substantial portion of the Company’s activities are transacted in or referenced to US dollars, including oil sales in Asia, capital spending in Ecuador and ongoing FTF operations. A portion of transactions are in other currencies, such as Dagang operating costs paid in Chinese renminbi, Tamarack exploration activities funded in Canadian dollars and the 2010 common share issuance in Canadian dollars. The Company did not enter into any foreign currency derivatives in 2010, nor do we anticipate using foreign currency derivatives in 2011. To help reduce the Company’s exposure to foreign currency exchange rate risk, the Company seeks to hold assets and liabilities denominated in the same currency when appropriate.
The following table shows the Company’s exposure to foreign currency exchange rate risk on its net loss and comprehensive loss, assuming reasonably possible changes in the relevant foreign currency. This analysis assumes all other variables remain constant.
                 
             
    Change From a 10%     Change From a 10%  
(Increase) Decrease in Net Loss and Comprehensive Loss   Increase or Weakening     Decrease or Strengthening  
Chinese renminbi
    1,438       (1,758 )
Canadian dollar
    (2,089 )     167  
Interest Rate Risk
Interest rate risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate as a result of changes in market interest rates. Interest rate risk arises from interest-bearing borrowings which have a variable interest rate. The Company’s net loss and accumulated deficit would not have changed with a change in interest rates in 2010 as the Company’s debt consists of the Convertible Note issued for the acquisition of the Tamarack leases for which interest is capitalized.
Credit Risk
Ivanhoe is exposed to credit risk with respect to its cash and cash equivalents, accounts receivable, note receivable, restricted cash and long term receivables. The Company’s maximum exposure to credit risk at December 31, 2010, is represented by the carrying amount of these non-derivative financial assets. Most of the Company’s credit exposures are with counterparties in the energy industry and are therefore exposed to normal industry credit risks. Ivanhoe manages its credit risk by entering into sales contracts only with established entities.

 

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The Company believes its exposure to credit risk related to cash and cash equivalents, as well as restricted cash, is minimal due to the quality of the financial institutions where the funds are held and the nature of the deposit instruments.
Currently, all of the Company’s oil production is sold to one national oil corporation. As a result, 85% of the outstanding accounts receivable balance at December 31, 2010 (December 31, 2009 — 94%) is due from a national oil corporation. Long term receivables are composed of value-added tax receivable amounts from Ecuador and will be recoverable upon commencement of commercial operations. Ivanhoe considers the risk of default on these items to be low due to the Company’s ongoing operations in China and Ecuador.
In 2008, the Company recorded an allowance associated with an advance balance for the outstanding amount of $0.7 million.
                 
As at December 31,   2010     2009  
Accounts receivable — current
    6,329       5,004  
Accounts receivable — over 90 days
    30       17  
 
           
 
    6,359       5,021  
 
           
Liquidity Risk
Liquidity risk is the risk that suitable sources of funding for the Company’s business activities may not be available. Since cash flows from existing operations are insufficient to fund future capital expenditures, we intend to finance future capital projects with a combination of strategic investors and/or public and private debt and equity markets, either at a parent company level or at the project level or from the sale of existing assets. There is no assurance that we will be able to obtain such financing on favorable terms, if at all.
         
As at December 31, 2010   Less than 1 year  
Accounts payable and accrued liabilities
    21,482  
Long term debt and interest
    41,275  
13. CAPITAL MANAGEMENT
The Company’s main source of funds has historically been public and private equity and debt markets. The Company’s cash flow from operating activities will not be sufficient to meet its operating and capital obligations and, as such, the Company intends to finance its operating and capital projects from a combination of strategic investors in its projects and/or public and private debt and equity markets, either at a parent company level or at a project level. There have been no significant changes in Management’s objectives, policies and processes to manage capital from the previous year.
The Company defines capital as total shareholders’ equity plus cash and cash equivalents and debt.
                 
As at December 31,   2010     2009  
Cash and cash equivalents
    67,817       21,512  
Debt
    39,832        
Long term debt
          36,934  
Shareholders’ equity
    324,109       208,029  
The Company’s management reviews the capital structure on a regular basis to maintain an optimal debt to equity balance. In order to maintain or adjust its capital structure, the Company may refinance its existing debt, raise new debt, seek cost sharing arrangements with partners or issue new shares.
In 2008, the Company expensed $2.6 million of deferred financing costs that were directly attributable to a proposed offering of securities for its wholly-owned Chinese subsidiary.
As at December 31, 2010, the Company is not subject to any financial covenants.

 

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14. INCOME TAXES
The Company and its subsidiaries are required to individually file tax returns in each of the jurisdictions in which they operate. The provision for income taxes differs from the amount computed by applying the statutory income tax rates to the net losses before income taxes. The combined Canadian federal and provincial statutory rates as at December 31, 2010, 2009 and 2008 were 28.0%, 29.0% and 29.5%, respectively. The sources and tax effects for the differences were as follows:
                         
    2010     2009     2008  
Loss from continuing operations before income taxes
    (30,109 )     (45,574 )     (37,822 )
Combined Canadian federal and provincial statutory rates
    28.0 %     29.0 %     29.5 %
 
                 
Tax benefit
    (8,431 )     (13,217 )     (11,158 )
Foreign net (gains) losses affected at lower income tax rates
    (396 )     106       4,562  
Effect of change in foreign exchange rates
    (2,309 )     (2,858 )     3,006  
Expiry of tax loss carry-forwards
    982       911       2,875  
Tax credit carry-forward
          (350 )      
Compensation not deductible
    1,310       1,456       753  
Financing costs not deductible
                695  
Net currency exchange (gains) losses not deductible
    (900 )     1,501       402  
Change in prior year estimate of tax loss carry-forwards
    (918 )     3,941       (59 )
Realized derivative (gains) losses not taxable/deductible
          334       (422 )
Effect of change in effective income tax rates on future tax assets
    1,096       (4,453 )     (331 )
Other differences
    425       32       (127 )
 
                 
 
    (9,141 )     (12,597 )     196  
Change in valuation allowance
    8,142       4,754       458  
 
                 
Provision for (recovery of) income taxes
    (999 )     (7,843 )     654  
 
                 
Significant components of the Company’s future net income tax assets and liabilities were as follows:
                                 
As at December 31,   2010     2009  
    Assets     Liabilities     Assets     Liabilities  
Oil and gas properties and investments
    266       (8,569 )     471       (1,124 )
Intangibles
          (30,493 )           (30,354 )
Tax loss carry-forwards
    54,990             37,583        
Tax credit carry-forward
                350        
Valuation allowance
    (37,712 )           (29,570 )      
 
                       
 
    17,544       (39,062 )     8,834       (31,478 )
 
                       

 

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The consolidated loss carry-forward amounts and the year of expiry as at December 31, 2010, are shown in the table below. In China, the loss carry-forwards have no expiration period. A loss of approximately Cdn$55.3 million from the disposition of Russian operations in 2000, is a capital loss for Canadian income tax purposes, and is available for carry-forward against future Canadian capital gains indefinitely and is not included in the future income tax assets above.
         
Year of Expiry        
2011
    505  
2012
    2,327  
2014
    5,243  
2015
    6,803  
2018
    2,093  
2019
    1,079  
2020 — 2025
    5,508  
2026 — 2030
    116,123  
No expiry
    63,994  
 
     
 
    203,675  
 
     
There are no current income taxes payable at December 31, 2010 (December 31, 2009 — $0.2 million related to China, $0.3 million related to the US).
Prior to the Company selling its US operating segment in July 2009, the Company had future tax assets arising from net operating loss carry-forwards generated by this business segment. These future income tax assets were partially offset by certain future income tax liabilities in the US and by a valuation allowance. As at June 30, 2009, as a result of the sale of the business segment, the Company was no longer able to offset these tax assets and liabilities but was required to present these future income tax assets as “assets from discontinued operations” and a future income tax liability, both in the amount of $29.6 million in the accompanying consolidated balance sheet. The future income tax assets classified as assets from discontinued operations were included in the $23.4 million loss on disposition. Revisions were made to the future income tax liability during the third quarter of 2009 based on revised projections of taxable income and utilization of net operating loss carry-forwards.
As at December 31, 2010, the Company’s future income tax liability is $21.5 million in the accompanying consolidated balance sheet, composed of $18.8 million in the US tax jurisdiction and $2.7 million related to Mongolia.
In April 2009, the Chinese State Tax Administration Bureau issued Circular [2009] No. 49 (the “Circular”) on depletion, depreciation and amortization expense by oil and gas companies. One of the changes to the existing rules included in the Circular that affects the Company was the increase of the minimum depreciation and amortization period from six years to eight years. The implementation of the new rules was retroactive to January 1, 2008. Upon reviewing the tax effect of the Circular, the Company revised its 2008 current tax payable in China to $1.6 million from the $0.6 million that was recorded in 2008. The $1.6 million tax payable was subsequently paid in June 2009.

 

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15. SUPPLEMENTAL CASH FLOW INFORMATION
Supplemental cash flow information for each of the years ended December 31 was as follows:
                         
    2010     2009     2008  
Cash paid during the year for
                       
Income taxes
    656       1,876       5  
Interest
    1,610       2,122       1,120  
 
                       
Investing and financing activities, non-cash
                       
Acquisition of business/assets
                       
Shares issued
          6,899        
Warrants issued
          622        
Debt issued
                52,052  
 
                 
 
          7,521       52,052  
 
                 
 
                       
Conversion of debt to common shares
                       
Extinguishment of debt
                4,737  
Extinguishment of interest
                125  
 
                 
 
                4,862  
 
                 
 
                       
Shares issued for bonuses and services
    799       207       490  
Stock-based compensation capitalized
                175  
 
                 
                         
 
    2010     2009     2008  
Changes in non-cash working capital items
                       
Operating activities
                       
Accounts receivable
    (551 )     (1,253 )     3,509  
Note receivable
    (39 )     (225 )      
Prepaid and other current assets
    176       (175 )     (48 )
Accounts payable and accrued liabilities
    2,076       1,314       1,905  
Income tax payable
    (530 )     (120 )     650  
 
                 
 
    1,132       (459 )     6,016  
 
                 
 
                       
Investing activities
                       
Accounts receivable
    (775 )     (140 )     7  
Prepaid and other current assets
    (2,264 )     41       (70 )
Accounts payable and accrued liabilities
    8,672       163       (972 )
 
                 
 
    5,633       64       (1,035 )
 
                 
 
                       
Financing activities
                       
Accounts payable and accrued liabilities
    (10 )     (26 )     26  
 
                 
 
    6,755       (421 )     5,007  
 
                 
Cash and cash equivalents are composed of the following:
                 
As at December 31,   2010     2009  
Bank accounts
    10,147       21,512  
Term deposit
    57,670        
 
           
 
    67,817       21,512  
 
           

 

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16. RELATED PARTY TRANSACTIONS
The Company has entered into agreements with a number of entities which are related or controlled through common directors or shareholders. These entities provide access to an aircraft, the services of administrative and technical personnel and office space or facilities in various international locations. The Company is billed on a cost recovery basis in most cases. In 2010, the costs incurred in the normal course of business with respect to the above arrangements amounted to $3.3 million (2009 — $3.8 million; 2008 — $3.0 million). These transactions have been measured at their exchange amount and are recorded in general and administrative and business and technology expense in the statement of operations. As at December 31, 2010, amounts included in accounts payable and accrued liabilities on the consolidated balance sheet under these arrangements were $0.2 million (December 31, 2009 — $0.1 million).
17. ACQUISITION AND PROJECT-RELATED AGREEMENTS
Mongolia
In November 2009, the Company completed the acquisition of PanAsian Petroleum Inc. (“PPI”) which provides it with the exclusive right to explore, develop and produce oil or gas within Block XVI in Mongolia’s Nyalga Basin. This transaction with PPI resulted in the Company issuing 2,683,291 common shares in exchange for all of the issued and outstanding common shares of PPI. In addition, existing purchase warrants in PPI were converted to 735,449 Ivanhoe purchase warrants that entitle the holders to purchase Ivanhoe’s common shares at Cdn$4.05 per share and expire in February 2011.
The consideration for this acquisition and the net assets acquired are summarized as follows:
         
Purchase consideration        
2,683,291 common shares(1)
    6,899  
735,449 warrants to purchase Ivanhoe common shares (Note 8)
    622  
 
     
 
    7,521  
 
     
 
       
Net assets acquired
       
Cash
    29  
Non-cash working capital, net
    (606 )
Oil and gas properties — unproved
    10,742  
Future income tax liability
    (2,644 )
 
     
 
    7,521  
 
     
     
(1)  
The closing share price on the Toronto Stock Exchange on the date of acquisition, November 26, 2009, was Cdn$2.70.
Canada
In July 2008, the Company acquired from Talisman two leases located in the Athabasca oil sands region in the Province of Alberta, Canada. The amount paid was Cdn$75.0 million of which Cdn$22.5 million was paid on closing and two promissory notes were issued to Talisman. The principal amount of the first note was Cdn$12.5 million with an interest rate of prime plus 2%. The first note matured and was repaid on December 31, 2008. The second promissory note was Cdn$40.0 million, with an interest rate of prime plus 2%. The second note matures in July 2011 and the outstanding principal amount is convertible at Talisman’s option into a maximum of 12,779,552 Ivanhoe common shares at Cdn$3.13 per common share.
The Company may be required to make a Cdn$15.0 million cash payment to Talisman upon receiving government and other approvals necessary to develop the northern border of one of the Tamarack leases.
Talisman retains a back-in right (the “Back-in Right”), exercisable once per lease until July 11, 2011, to re-acquire up to a 20% undivided interest in each lease. If the Back-in Right is exercised, the cost to Talisman would be 20% of 200% of Ivanhoe’s acquisition cost and certain expenses incurred since acquisition in respect of the relevant lease.
Until July 11, 2011, Talisman also has the right of first offer to acquire any interests in heavy oil projects in the Province of Alberta that the Company or any of its subsidiaries wishes to sell, excluding the acquired leases.
Ecuador
In October 2008, Ivanhoe Energy Ecuador Inc. (“IE Ecuador”) entered into a contract with Empresa Estatal de Petroleos del Ecuador, Petro (“Petroecuador”), the state oil company of Ecuador, and its affiliate, Empresa Estatal de Exploracion y Produccion de Petroleos del Ecuador, Petroproduccion (“Petroproduccion”) to explore and develop an exploration block in Ecuador that includes the Pungarayacu heavy oil field, utilizing the Company’s HTL™ technology. IE Ecuador is a wholly-owned subsidiary of Ivanhoe Energy Latin America Inc. (“IE Latin America”), a wholly-owned subsidiary of the Company.

 

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IE Ecuador will lead the development of the project. The contract is guaranteed by its parent company IE Latin America, which will obtain or provide funding and financing for IE Ecuador’s operations under the contract. The contract’s 30 year term may be extended by mutual agreement. To recover its investments, costs and expenses, and to provide for a profit, IE Ecuador will receive from Petroproduccion a payment of US$37.00/bbl of oil produced and delivered to Petroproduccion. The payment will be adjusted quarterly, on a weighted average basis, for movement in a basket of three US Government published producer price indices relating to steel products, refinery products and upstream oil and gas equipment.
18. DISCONTINUED OPERATIONS
In 2009, management commenced a process to sell all of the Company’s US oil and gas exploration and production operations. On July 17, 2009, the Company completed the sale of its wholly-owned subsidiary Ivanhoe Energy (USA) Inc. for a purchase price of $39.2 million. The purchaser acquired the Company’s oil and gas exploration and production operations in California and Texas and additional exploration acreage in California.
The Company used approximately $5.2 million of the sales proceeds to repay an outstanding loan to a third party financial institution holding a security interest in Ivanhoe Energy (USA) Inc.’s assets. The Company applied the balance of the sales proceeds in the ongoing development of its heavy oil projects in Canada and Ecuador and for general corporate purposes.
An escrow deposit of $2.0 million was set aside from the sale proceeds and made available to the purchaser for a period of one year to satisfy any indemnification obligations of the Company. In July 2010, the purchaser notified the Company of a claim against the entire escrow deposit for alleged breaches of certain covenants in the purchase and sale agreement in respect of tax matters. While the Company believed there was no basis for the claim, in the fourth quarter of 2010, Ivanhoe agreed to pay the purchaser $250,000 of the escrow deposit to avoid a lengthy legal dispute and the remaining $1.75 million was returned to Ivanhoe.
In conjunction with the disposition of the US assets and the Company’s focus on heavy oil opportunities, the Company closed its support office in Bakersfield, California and transferred its accounting operations to Calgary, Alberta. This transition was completed by the end of the second quarter of 2010. Total costs associated with this closure, including severance and retention payments, were approximately $0.6 million.
The operating results for this discontinued operation for the periods noted were:
                         
    2010     2009     2008  
Revenue
                       
Oil and gas
          5,455       18,120  
Gain on derivative instruments
          189       278  
Interest
          8       98  
 
                 
 
          5,652       18,496  
 
                 
Expenses
                       
Operating
          2,132       5,137  
General and administrative
          139       2,413  
Depletion and depreciation
          3,772       6,143  
Interest and financing
          173       520  
 
                 
 
          6,216       14,213  
 
                 
 
                       
Income (loss) before disposition
          (564 )     4,283  
Loss on disposition (net of tax of $29.6 million for 2009, nil for 2008)
          (23,357 )      
 
                 
 
                       
Net income (loss) from discontinued operations
          (23,921 )     4,283  
 
                 
19. SUBSEQUENT EVENTS
On January 24, 2011, the Company announced its application to extend the expiry date of 12,410,000 unlisted outstanding common share purchase warrants had been approved by the Toronto Stock Exchange. The extension excluded 90,000 warrants held by an insider. These warrants were scheduled to expire on January 26, 2011 and instead expired on February 25, 2011. The Company received proceeds of $27.2 million from the exercise of 8,616,665 out of the 12,320,000 common share purchase warrants. These proceeds will be used for general corporate purposes.

 

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20. ADDITIONAL DISCLOSURES REQUIRED UNDER US GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
The Company’s consolidated financial statements have been prepared in accordance with GAAP as applied in Canada. In the case of the Company, Canadian GAAP conforms in all material respects with US GAAP except for certain matters, the details of which are as follows:
Consolidated Balance Sheets
The application of US GAAP has the following effects on consolidated balance sheet items as reported under Canadian GAAP:
                                                         
As at December 31,   2010     2009  
    Canadian     Increase         US     Canadian     Increase         US  
    GAAP     (Decrease)     Notes   GAAP     GAAP     (Decrease)     Notes   GAAP  
Assets
                                                       
Current assets
                                                       
Cash and cash equivalents
    67,817                 67,817       21,512                 21,512  
Accounts receivable
    6,359                 6,359       5,021                 5,021  
Note receivable
    264                 264       225                 225  
Prepaid and other current assets
    2,859                 2,859       771                 771  
Restricted cash
    500                 500       2,850                 2,850  
 
                                           
Total current assets
    77,799                 77,799       30,379                 30,379  
 
                                                       
Oil and gas properties and development costs, net
    237,200       (38,500 )   (i)     221,290       158,392       (38,500 )   (i)     139,346  
 
            24,172     (ii)                     20,315     (ii)        
 
            (1,582 )   (iii)                     (861 )   (iii)        
 
                                                       
Intangible assets
    92,153                 92,153       92,153                 92,153  
Long term receivables
    2,433                 2,433       839                 839  
 
                                           
Total assets
    409,585       (15,910 )         393,675       281,763       (19,046 )         262,717  
 
                                           
 
                                                       
Liabilities and shareholders’ equity
                                                       
Current Liabilities
                                                       
Accounts payable and accrued liabilities
    21,482                 21,482       10,779                 10,779  
Debt
    39,832       504     (iii)     40,217                        
 
            (119 )   (iii)                     -              
Income tax payable
                          530                 530  
Derivative instruments
          7,228     (vi)     7,228             8,249     (vi)     8,249  
Asset retirement obligation
                          753                 753  
 
                                           
Total current liabilities
    61,314       7,613           68,927       12,062       8,249           20,311  
 
                                                       
Long term debt
                          36,934       1,225     (iii)     38,005  
 
                                      (154 )   (iii)        
Asset retirement obligations
    744                 744       195                 195  
Long term obligation
    1,900                 1,900       1,900                 1,900  
Future income tax liability
    21,518                 21,518       22,643                 22,643  
 
                                           
Total liabilities
    85,476       7,613           93,089       73,734       9,320           83,054  
 
                                           
 
                                                       
Shareholders’ equity
                                                       
Share capital
    550,562       74,455     (iv)     638,420       422,322       74,455     (iv)     510,784  
 
            (1,155 )   (v)                     (551 )   (v)        
 
            1,358     (vii)                     1,358     (vii)        
 
            13,200     (vi)                     13,200     (vi)        
Purchase warrants
    33,423       (33,423 )   (vi)           19,427       (19,427 )   (vi)      
Contributed surplus
    22,983       (2,593 )   (v)     17,443       20,029       (3,197 )   (v)     13,885  
 
            (2,947 )   (vi)                     (2,947 )   (vi)        
Convertible note
    2,086       (2,086 )   (iii)           2,086       (2,086 )   (iii)      
Accumulated deficit
    (284,945 )     (70,332 )         (355,277 )     (255,835 )     (89,171 )         (345,006 )
 
                                           
Total shareholders’ equity
    324,109       (23,523 )         300,586       208,029       (28,366 )         179,663  
 
                                           
Total liabilities and shareholders’ equity
    409,585       (15,910 )         393,675       281,763       (19,046 )         262,717  
 
                                           

 

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Oil and Gas Properties and Development Costs
  (i)  
There are certain differences between the full cost method of accounting for oil and gas properties as applied in Canada and as applied in the US. The principal difference is in the method of performing ceiling test evaluations. In the ceiling test evaluation for US GAAP purposes, the Company limits, on a country-by-country basis, the capitalized costs of oil and gas properties, net of accumulated depletion, depreciation and amortization and deferred income taxes, to (a) the present value of estimated future net revenues computed by applying a 12 month average oil price to reserves to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves computed using a discount factor of 10% and assuming continuation of existing economic conditions; plus (b) the cost of properties not being amortized (e.g. major development projects) and (c) the lower of cost or fair value of unproved properties included in the costs being amortized less (d) income tax effects related to the difference between the book and tax basis of the properties referred to in (b) and (c) above. If capitalized costs exceed this limit, the excess is charged as a provision for impairment. Unproved properties and major development projects are assessed on a quarterly basis for possible impairments or reductions in value. If a reduction in value has occurred, the impairment is transferred to the carrying value of proved oil and gas properties. The Company performed the ceiling test in accordance with US GAAP and determined that for the year ended December 31, 2010, no impairment provision was required. The cumulative differences in the amount of impairment provisions between US and Canadian GAAP were $38.5 million at December 31, 2010, and December 31, 2009.
  (ii)  
The cumulative differences in the amount of impairment provisions between US and Canadian GAAP resulted in reductions in accumulated depletion.
  (iii)  
Under Canadian GAAP, the Company was required to bifurcate the value of the Convertible Note, allocating a portion to debt and a portion to equity. Under US GAAP, convertible debt securities are classified as debt in their entirety. Under Canadian GAAP, this discount accretion was capitalized. To reconcile to US GAAP the entire $2.1 million recorded in equity is reversed as well as the unamortized discount of $0.4 million and the accreted discount that was capitalized in the amount of $1.6 million. In addition, because the convertible note is not denominated in US currency the re-measurement of the different carrying value for US GAAP results in an increase to net income. The foreign exchange gain of $0.1 million is shown as a separate amount in the US GAAP reconciliation of the Company’s balance sheet shown above and is adjusted to the foreign exchange expense line item in the US GAAP reconciliation of the statement of operations below.
Shareholders’ Equity
  (iv)  
In June 1999, the shareholders approved a reduction of stated capital in respect of the common shares by an amount of $74.5 million being equal to the accumulated deficit as at December 31, 1998. Under US GAAP, a reduction of the accumulated deficit such as this is not recognized except in the case of a quasi reorganization.
  (v)  
Under Canadian GAAP, the Company accounts for all stock options granted to employees and directors since January 1, 2002 using the fair value based method of accounting. Under this method, compensation costs are recognized in the financial statements over the stock options’ vesting period using an option-pricing model for determining the fair value of the stock options at the grant date. Under US GAAP, prior to January 1, 2006, the Company applied Accounting Principles Board (“APB”) Opinion No. 25, as interpreted by Financial Accounting Standards Board (“FASB”) Interpretation No. 44, in accounting for its stock option plan and did not recognize compensation costs in its financial statements for stock options issued to employees and directors. Beginning January 1, 2006, the Company applied the revision to FASB’s Accounting Standards Codification Manual (“ASC”) Topic 718 “Stock Compensation” (formerly Statement of Financial Accounting Standards (“SFAS”) No. 123R) which supersedes APB No. 25, “Accounting for Stock Issued to Employees”. The Company elected to implement this statement on a modified prospective basis whereby the Company began recognizing stock-based compensation in its US GAAP results of operations for the unvested portion of awards outstanding as at January 1, 2006 and for all awards granted after January 1, 2006. There are no significant differences between the accounting for stock options under Canadian GAAP and US GAAP subsequent to January 1, 2006.

 

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  (vi)  
The Company accounts for purchase warrants as equity under Canadian GAAP. The accounting treatment of warrants under US GAAP reflects the application of ASC Topic 815 “Derivatives and Hedging” (formerly SFAS No. 133). Under ASC Topic 815, share purchase warrants with an exercise price denominated in a currency other than a company’s functional currency are accounted for as derivative liabilities. Changes in the fair value of the warrants are required to be recognized in the statement of operations each reporting period for US GAAP purposes. At the time that the Company’s share purchase warrants are exercised, the value of the warrants will be reclassified to shareholders’ equity for 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.
  (vii)  
Under US GAAP, the aggregate value attributed to the acquisition of royalty rights during 1999 and 2000 was $1.4 million higher, due to the difference between Canadian and US GAAP in the value ascribed to the common shares issued, primarily resulting from differences in the recognition of effective dates of the transactions.
Consolidated Statements of Loss and Comprehensive Loss
The application of US GAAP had the following effects on net loss and net loss per share as reported under Canadian GAAP:
                             
    2010  
    Canadian     Increase         US  
    GAAP     (Decrease)     Notes   GAAP  
Revenue
                           
Oil
    21,720                 21,720  
Gain on derivative instruments
          15,017     (vi)     15,017  
Interest
    208                 208  
 
                     
 
    21,928       15,017           36,945  
 
                     
 
                           
Expenses
                           
Operating
    9,503                 9,503  
General and administrative
    26,260                 26,260  
Business and technology development
    10,615                 10,615  
Depletion and depreciation
    8,960       (3,857 )   (ix)     5,103  
Foreign exchange
    (3,325 )     35     (iii)     (3,290 )
Interest and financing
    24                 24  
 
                     
 
    52,037       (3,822 )         48,215  
 
                     
 
                           
Loss from continuing operations before income taxes
    (30,109 )     18,839           (11,270 )
 
                           
(Provision for) recovery of income taxes
                           
Current
    (126 )               (126 )
Future
    1,125                 1,125  
 
                     
 
    999                 999  
 
                     
 
                           
Net loss continuing operations
    (29,110 )     18,839           (10,271 )
Net loss — discontinued operations
                     
 
                     
Net loss and comprehensive loss
    (29,110 )     18,839           (10,271 )
 
                     
 
                           
Net loss per share
                           
Net loss — continuing operations, basic and diluted
    (0.09 )     0.06           (0.03 )
Net loss — discontinued operations, basic and diluted
                     
 
                     
Net loss per share, basic and diluted
    (0.09 )     0.06           (0.03 )
 
                     
 
                           
Weighted average number of common shares
                           
Basic and diluted (000s)
    327,442                 327,442  
 
                     

 

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    2009  
    Canadian     Increase         US  
    GAAP     (Decrease)     Notes   GAAP  
Revenue
                           
Oil
    24,968                 24,968  
Loss on derivative instruments
    (1,335 )     (6,506 )   (vi)     (7,841 )
Interest
    25                 25  
 
                     
 
    23,658       (6,506 )         17,152  
 
                     
 
                           
Expenses
                           
Operating
    10,191                 10,191  
General and administrative
    21,693                 21,693  
Business and technology development
    9,501       150     (viii)     9,651  
Depletion and depreciation
    19,868       (10,574 )   (ix)     9,294  
Foreign exchange
    5,220       (154 )   (iii)     5,066  
Interest and financing
    856                 856  
Provision for impairment of intangible asset and development
    1,903       (980 )   (viii)     923  
 
                     
 
    69,232       (11,558 )         57,674  
 
                     
 
                           
Loss from continuing operations before income taxes
    (45,574 )     5,052           (40,522 )
 
                           
(Provision for) recovery of income taxes
                           
Current
    (1,757 )               (1,757 )
Future
    9,600                 9,600  
 
                     
 
    7,843                 7,843  
 
                     
 
                           
Net loss continuing operations
    (37,731 )     5,052           (32,679 )
Net income (loss) — discontinued operations (net of tax of $29.6 million)
    (23,921 )     24,890     (x)     969  
 
                     
Net loss and comprehensive loss
    (61,652 )     29,942           (31,710 )
 
                     
 
                           
Net income (loss) per share
                           
Net loss — continuing operations, basic and diluted
    (0.13 )     0.01           (0.12 )
Net income (loss) — discontinued operations, basic and diluted
    (0.09 )     0.10           0.01  
 
                     
Net loss per share, basic and diluted
    (0.22 )     0.11           (0.11 )
 
                     
 
                           
Weighted average number of common shares
                           
Basic and diluted (000s)
    279,722                 279,722  
 
                     

 

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    2008  
    Canadian     Increase         US  
    GAAP     (Decrease)     Notes   GAAP  
Revenue
                           
Oil
    48,370                 48,370  
Gain on derivative instruments
    1,688       4,665     (vi)     6,353  
Interest
    612                 612  
 
                     
 
    50,670       4,665           55,335  
 
                     
 
                           
Expenses
                           
Operating
    21,515                 21,515  
General and administrative
    14,252                 14,252  
Business and technology development
    6,453                 6,453  
Depletion and depreciation
    25,761       (2,820 )   (ix)     22,941  
Foreign exchange
    1,527                 1,527  
Interest and financing
    1,309                 1,309  
Provision for impairment of intangible asset and development
    15,054       (4,640 )   (viii)     10,414  
Write off of deferred financing
    2,621                   2,621  
Provision for impairment of oil and gas properties
          21,560     (ix)     21,560  
 
                     
 
    88,492       14,100           102,592  
 
                     
 
                           
Loss from continuing operations before income taxes
    (37,822 )     (9,435 )         (47,257 )
 
                           
Current provision for income taxes
    (654 )               (654 )
 
                     
 
                           
Net loss continuing operations
    (38,476 )     (9,435 )         (47,911 )
Net income (loss) discontinued operations
    4,283       (19,423 )   (x)     (15,140 )
 
                     
Net loss and comprehensive loss
    (34,193 )     (28,858 )         (63,051 )
 
                     
 
                           
Net income (loss) per share
                           
Net loss — continuing operations, basic and diluted
    (0.15 )     (0.04 )         (0.19 )
Net income (loss) — from discontinued operations, basic and diluted
    0.02       (0.07 )         (0.05 )
 
                     
Net loss per share, basic and diluted
    (0.13 )     (0.11 )         (0.24 )
 
                     
 
                           
Weighted average number of common shares
                           
Basic and diluted (000s)
    258,815                 258,815  
 
                     
Development Costs
  (viii)  
For Canadian GAAP, feasibility, marketing and related costs incurred prior to executing a HTL™ or GTL definitive agreement are capitalized and are subsequently written down upon determination that a project’s future value has been impaired. The Company wrote off $5.1 million in GTL development costs under Canadian GAAP. These costs had already been expensed under US GAAP in previous periods and therefore this transaction reduced the net loss for US GAAP purposes in 2008.
Depletion and Depreciation
  (ix)  
As discussed under “Oil and Gas Properties and Development Costs” in this note, there is a difference between US and Canadian GAAP in performing the ceiling test evaluation under the full cost method. Application of the ceiling test evaluation under US GAAP has resulted in an accumulated net increase in impairment provisions on the Company’s US and China oil and gas properties. This net increase in US GAAP impairment provisions has resulted in lower depletion rates for US GAAP purposes and a reduction in the net losses for the years ended December 31, 2010, 2009 and 2008.

 

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Discontinued Operations
  (x)  
As at December 31, 2009, the $24.9 million adjustment related to discontinued operations included a $1.4 million increase that is attributed to the acquisition of royalty rights during 2000 and 1999 due to the difference between Canadian and US GAAP in the value ascribed to the common shares issued, primarily resulting from differences in the recognition of effective dates of the transactions. Additionally, there was a $3.1 million increase due to depletion. These increases were offset by $29.4 million decrease due to impairment differences. These accumulated balance sheet adjustments were charged off as part of the gain/loss calculation at the time of sale and flow through the statement of operations for the year ended December 31, 2009 in the Net Loss from Discontinued Operations line item.
Consolidated Statements of Cash Flows
As a result of the expensing of HTL™ and GTL development costs as required under US GAAP and the recovery of such costs, the statement of cash flow under US GAAP would result in a net use of cash from operating activities of $17.8 million, $12.4 million and cash provided from operating activities of $16.6 million for the year ended December 31, 2010, 2009 and 2008, respectively. Additionally, capital investments reported under investing activities would be $86.3 million, $26.2 million and $20.7 million for the years ended December 31, 2010, 2009 and 2008, respectively.
Additional US GAAP Disclosures
Oil and Gas Properties and Development Costs
The categories of costs included in “Oil and Gas Properties and Development Costs”, including the US GAAP adjustments were as follows:
                                                 
                                    Business and        
                                    Technology        
As at December 31, 2010   Canada     Ecuador     Asia     Corporate     Development     Total  
Property acquisition
    77,742       2,089       31,137                   110,968  
Capitalized interest
    4,936                               4,936  
Exploration
    30,085       19,763       75,091                   124,939  
Development
                91,885                   91,885  
Production facilities
          4,397                         4,397  
HTL™ facilities
    11,089                         11,426       22,515  
Support equipment and general property
    27       436       1,157       1,361       58       3,039  
 
                                   
 
    123,879       26,685       199,270       1,361       11,484       362,679  
Accumulated depletion and depreciation
    (17 )     (101 )     (84,391 )     (894 )     (936 )     (86,339 )
Provision for impairment
                (55,050 )                 (55,050 )
 
                                   
 
    123,862       26,584       59,829       467       10,548       221,290  
 
                                   
                                                 
                                    Business and        
                                    Technology        
As at December 31, 2009   Canada     Ecuador     Asia     Corporate     Development     Total  
Property acquisition
    77,093       852       42,298                   120,243  
Capitalized interest
    3,049                               3,049  
Exploration
    6,437       2,988       32,831                   42,256  
Development
                87,100                   87,100  
Production facilities
          2,483                         2,483  
HTL™ facilities
    6,991                         10,868       17,859  
Support equipment and general property
    24       601       427       968       22       2,042  
 
                                   
 
    93,594       6,924       162,656       968       10,890       275,032  
Accumulated depletion and depreciation
    (8 )     (53 )     (79,521 )     (650 )     (404 )     (80,636 )
Provision for impairment
                (55,050 )                 (55,050 )
 
                                   
 
    93,586       6,871       28,085       318       10,486       139,346  
 
                                   
As at December 31, 2010, the costs of unproved properties included in oil and gas properties and development costs, which have been excluded from the depletion and ceiling test calculations, were incurred as follows:
                                         
    Total     2010     2009     2008     Prior to 2008  
Property acquisition
    90,992       1,786       11,920       77,187       99  
Exploration
    98,235       72,705       17,655       6,325       1,550  
 
                             
 
    189,227       74,491       29,575       83,512       1,649  
 
                             

 

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As at December 31, 2010, the costs of unproved oil and gas by prospect were incurred as follows:
                                         
    Total     2010     2009     2008     Prior to 2008  
Canada
                                       
Tamarack
    123,852       30,282       12,480       81,090        
 
                                       
Ecuador
                                       
Block 20
    26,249       19,494       5,301       1,454        
 
                                       
Asia
                                       
Zitong Block
    23,652       20,403       632       968       1,649  
Nyalga Block
    15,474       4,312       11,162              
 
                             
 
    39,126       24,715       11,794       968       1,649  
 
                             
 
    189,227       74,491       29,575       83,512       1,649  
 
                             
Accounts Payable and Accrued Liabilities
The following was the breakdown of accounts payable and accrued liabilities as at December 31, 2010:
                 
Trade payables
    8,922       3,767  
Accrued liabilities
    12,560       7,012  
 
           
 
    21,482       10,779  
 
           
Stock-based Compensation
The aggregate intrinsic value of total options outstanding as well as options exercisable as at December 31, 2010 was $8.1 million and $3.8 million respectively. The total intrinsic value of options exercised during the year ended December 31, 2010 was $2.3 million (2009 — $3.0 million; 2008 — $5.4 million), and the cash received from exercise of options during the year ended December 31, 2010 was $2.6 million (2009 — $0.9 million; 2008 — $0.2 million).
A summary of the Company’s unvested options as at December 31, 2010, and changes during the year then ended, is presented below:
                 
    Number of     Weighted-Average  
    Stock Options     Grant Date Fair Value  
    (000s)     (Cdn$)  
Outstanding, beginning of year
    7,912       1.21  
Granted
    6,040       1.73  
Vested
    (3,060 )     1.53  
Cancelled and forfeited
    (748 )     1.77  
 
           
Outstanding, end of year
    10,144       1.55  
 
           
Unvested options outstanding as at December 31, 2010, by type:
         
Based on fulfilling service conditions
    9,665  
Based on fulfilling performance conditions
    479  
 
     
 
    10,144  
 
     
As at December 31, 2010, there was $10.0 million of total unrecognized compensation costs related to unvested share-based compensation arrangements granted by the Company. That cost is expected to be recognized over a weighted-average period of 3.0 years. The total fair value of options vested during the year ended December 31, 2010 was $4.7 million (2009 — $2.2 million; 2008 — $3.0 million).

 

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Impact of New and Pending US GAAP Accounting Standards
There were no changes in accounting standards in 2010 that affected or are expected to affect the Company. As a foreign private issuer in the US, Ivanhoe is permitted to file with the SEC consolidated financial statements prepared under IFRS beginning in 2011 without a reconciliation to US GAAP. The impact of this change is that the Company will no longer prepare a reconciliation of its results to US GAAP. It is possible that some of the Company’s accounting policies under IFRS could be different from US GAAP.

 

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SUPPLEMENTARY DISCLOSURES ABOUT OIL AND GAS PRODUCTION ACTIVITIES
(Unaudited)
(all tabular amounts are expressed in US$000s, except reserves and depletion rate amounts)
The following information about the Company’s oil and gas producing activities is presented in accordance with Accounting Standards Codification 932 Extractive Activities — Oil and Gas (section 235-55) formerly US SFAS No. 69, “Disclosures About Oil and Gas Producing Activities”.
Oil and Gas Reserves
Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations.
Proved developed oil and gas reserves are proved reserves that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Estimates of oil and gas reserves are subject to uncertainty and will change as additional information regarding the producing fields and technology becomes available and as future economic conditions change.
Reserves presented in this section represent the Company’s share of reserves, excluding royalty interests of others. The reserves were based on the estimates by the independent petroleum engineering firm of GLJ Petroleum Consultants Ltd. The changes in the Company’s net proved oil reserves in China for the three-year period ended December 31, 2010, were as follows:
         
(mbbls)        
Net proved reserves, December 31, 2007
    1,280  
Revisions of previous estimates
    242 (1)
Production
    (490 )
 
     
Net proved reserves, December 31, 2008
    1,032  
Revisions of previous estimates
    535 (2)
Production
    (466 )
 
     
Net proved reserves, December 31, 2009
    1,101  
Revisions of previous estimates
    925 (3)
Production
    (288 )
 
     
Net proved reserves, December 31, 2010
    1,738  
 
     
     
(1)  
The oil reserve revision is due to better performance of the Dagang property in relation to the 2007 reserve report.
 
(2)  
The oil reserve revision is due to improved production and fracture performance of the Dagang property in relation to what was estimated in the 2008 reserve report.
 
(3)  
The reserve revision in 2010 is mainly related to lower estimated decline rates on the Dagang property based on production to date.
Net proved producing reserves in China as at December 31, were as follows:
         
(mbbls)        
2008
    862  
2009
    885  
2010
    1,265  

 

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Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas Reserves
For the year ended December 31, 2010 and 2009, future net cash flows were computed using 12 month historical average prices in estimating the Company’s proved oil reserves, current costs, and statutory tax rates adjusted for tax deductions, that relate to existing proved oil reserves. For the year ended December 31, 2008, future net cash flows were computed using year-end prices, year-end costs, and statutory tax rates. The following standardized measure of discounted future net cash flows from proved oil reserves was computed using prices of $76.35, $58.00 and $41.57 /bbl of oil in 2010, 2009 and 2008, respectively. A discount rate of 10% was applied in determining the standardized measure of discounted future net cash flows.
The Company does not believe that this information reflects the fair market value of its oil and gas properties. Actual future net cash flows will differ from the presented estimated future net cash flows in that:
   
future production from proved reserves will differ from estimated production;
   
future production may also include production from probable and possible reserves;
   
future, rather than average annual, prices and costs will apply; and
   
existing economic, operating and regulatory conditions are subject to change.

 

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The standardized measure of discounted future net cash flows for China as at December 31 in each of the three most recently completed financial years were as follows:
         
    2010  
Future cash inflows
    132,745  
Future development and restoration costs
    (7,209 )
Future production costs
    (58,790 )
Future income taxes
    (12,238 )
 
     
Future net cash flows
    54,508  
10% annual discount
    (14,861 )
 
     
Standardized measure
    39,647  
 
     
         
    2009  
Future cash inflows
    63,862  
Future development and restoration costs
    (3,307 )
Future production costs
    (36,825 )
Future income taxes
    (593 )
 
     
Future net cash flows
    23,137  
10% annual discount
    (4,589 )
 
     
Standardized measure
    18,548  
 
     
         
    2008  
Future cash inflows
    42,906  
Future development and restoration costs
    (3,310 )
Future production costs
    (22,934 )
 
     
Future net cash flows
    16,662  
10% annual discount
    (2,576 )
 
     
Standardized measure
    14,086  
 
     
Note: The Company is using current costs in the preparation of the information shown in the tables above and to determine proved reserves. However, future production costs may not be easily comparable to historical production costs. The two main causes of difficulty in analyzing future production costs when compared to historical spending are summarized as follows:
  1.  
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 oil in the PRC are subject to a windfall gain levy (th