eh1300404_10k-2012.htm


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, 2012
Commission file number: 000-30586
 

 
GRAPHIC
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:
 
Title of each class
 
Name of each exchange on which registered
Common Shares, No Par Value
 
Toronto Stock Exchange
The NASDAQ Capital Market
 
Securities registered pursuant to Section 12(g) of the Act: None
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.       o Yes  þ  No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.        o Yes  þ No

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.        þ  Yes  o No

Indicate by check mark 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, 2012, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $153,410,090 based on the Toronto Stock Exchange closing price on that date. At March 7, 2013, the registrant had 344,472,761 common shares outstanding.
 


 
 

 
 
TABLE OF CONTENTS
 
PART I
4
 
13
 
18
 
18
 
19
PART II
19
 
22
 
23
 
33
 
34
 
71
 
71
 
73
PART III
73
 
79
 
96
 
98
 
99
PART IV
100

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
mbbls/d
=   thousand barrels per day
bbls/d
=   barrels per day
mboe
=   thousands of barrels of oil equivalent
boe
=   barrel of oil equivalent
mboe/d
=   thousands of barrels of oil equivalent per day
boe/d
=   barrels of oil equivalent per day
mmbbls
=   million barrels
mbbls
=   thousand barrels
mmbbls/d
=   million barrels per day

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.

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$)
2012
 
2011
 
2010
Closing
1.01
 
0.98
 
1.01
High
1.03
 
1.06
 
1.01
Low
0.96
 
0.94
 
0.93
Average noon
1.00
 
1.01
 
0.97

On March 7, 2013, the noon-day exchange rate was US$0.97 for Cdn$1.00.


 
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
 
With the exception of historical information, certain matters discussed 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”), are forward-looking statements that involve risks and uncertainties.

Statements that contain words such as “could”, “should”, “can”, “anticipate”, “estimate”, “propose”, “plan”, “expect”, “believe”, “will”, “may” and similar expressions and statements relating to matters that are not historical facts constitute “forward-looking statements” within the meaning of the “safe harbor” provisions of the United States Private Securities Litigation Reform Act of 1995. In particular, forward-looking statements contained in this Annual Report include, but are not limited to statements relating to or associated with individual wells, regions or projects. Any statements as to possible future crude oil prices; future production levels; future royalty and tax levels; future capital expenditures, their timing and their allocation to exploration and development activities; future asset acquisitions or dispositions; future sources of funding for the Company’s capital programs; future debt levels; availability of future credit facilities; possible commerciality of the Company’s projects; development plans or capacity expansions; future ability to execute dispositions of assets or businesses; future formation of joint ventures and other business relationships with third parties; future sources of liquidity, cash flows and their uses; future drilling of new wells; ultimate recoverability of current and long term assets; ultimate recoverability of reserves or resources; expected operating costs; estimates on a per share basis; future foreign currency exchange rates, future expenditures and future allowances relating to environmental matters and the Company’s ability to comply therewith; dates by which certain areas will be developed, come on-stream or reach expected operating capacity; and changes in any of the foregoing are forward-looking statements.

Statements relating to “reserves” are forward-looking statements, as they involve the implied assessment, based on estimates and assumptions that the reserves described exist in the quantities predicted or estimated and can be profitably produced in the future.

The forward-looking statements contained in this Annual Report are based on certain assumptions and analyses made by the Company in light of its experience and its perception of historical trends, current conditions and expected future developments as well as other factors it believes are appropriate in the circumstances. By their nature, forward-looking statements involve inherent risks and uncertainties, including the risk that the outcome that they predict will not be achieved. Undue reliance should not be placed on forward-looking statements as a number of important factors could cause the actual results to differ materially from the beliefs, plans, objectives, expectations and anticipations, estimates and intentions expressed in the forward-looking statements, including those set out below and those detailed in Item 1A, “Risk Factors,” and Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” in this Annual Report. Such factors include, but are not limited to:  the Company’s short history of limited revenue, losses and negative cash flow from its current exploration and development activities in Canada, Ecuador, Mongolia and the United States; the Company’s limited cash resources and consequent need for additional financing; the ability to raise capital as and when required, or to raise capital on acceptable terms; the timing and extent of changes in prices for oil and gas; competition for oil and gas exploration properties from larger, better financed oil and gas companies; environmental risks; title matters; drilling and operating risks; uncertainties about the estimates of reserves and the potential success of the Company’s Heavy-to-light (“HTL™”) technology; the potential success of the Company’s oil and gas properties in Canada, Ecuador and Mongolia; the prices of goods and services; the availability of drilling rigs and other support services; legislative and government regulations; political and economic factors in countries in which the Company operates; and implementation of the Company’s capital investment program.

The forward-looking statements contained in this Annual Report are made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward-looking statements, whether as a result of new information, future events or otherwise, unless required by applicable securities laws. The forward-looking statements contained herein are expressly qualified in their entirety by this cautionary statement.

 

 
PART I

 
ITEMS 1 AND 2:  BUSINESS AND PROPERTIES
 
GENERAL
 
Ivanhoe Energy Inc. (“Ivanhoe,” the “Company,” “we,” “our,” or “us”) 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 and Ecuador, with business development opportunities worldwide.

The Company was 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, the Company changed its name to Black Sea Energy Ltd. On June 24, 1999, Black Sea Energy Ltd. merged with Sunwing Energy Ltd. (“Sunwing”), and the name was changed to Ivanhoe Energy Inc.

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 from Talisman Energy Canada (“Talisman”) oil sand interests, including certain oil sand leases in the Athabasca region of Canada (“Tamarack” or the “Tamarack Project”). Later in 2008, the Company 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 its oil and gas exploration and production operations in the United States (“US”). Also in 2009, the Company acquired a production sharing contract for the Nyalga Block XVI in Mongolia, through the takeover of PanAsian Petroleum Inc., a privately-owned corporation. In 2012, the Company sold its wholly owned subsidiary, Pan-China Resources Ltd, and assigned 100% of its participating interest in the Contract for Exploration, Development and Production in the Zitong Block, in both cases to third parties, disposing of its oil and gas exploration and production operations in China.

CORPORATE STRATEGY
 
Ivanhoe continues to pursue its core strategies, which are:
 
 
Seek out heavy oil development projects globally that have operational needs that can benefit from our proprietary HTL™ technology;
 
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; and
 
Maximize the value of existing assets through strategic investment, development and partnerships.

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 marked shifts in the demand and supply landscape. Ivanhoe believes that, despite the recent emergence of light shale oils, the long term supply and demand for oil globally will require 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 thermal 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. 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, key advances in technology, including improved remote sensing, horizontal drilling and new thermal techniques have led to sustained increases in project activity.

These newer technologies 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 do so at a relatively small minimum economic scale.

Ivanhoe’s HTL™ technology is a partial upgrading process that is designed to operate economically 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 the short resonance time, 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 can be enhanced 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. In addition, with Ivanhoe’s experience in thermal recovery schemes, 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.
 
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.
 
 
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 by maintaining key personnel associated with each major project and additional critical technical capabilities as needed. In 2012, Carlos Cabrera completed his first full year as Executive Chairman of Ivanhoe. Previously, Mr. Cabrera spent 35 years with UOP LLC, a Honeywell company, where he has held several managerial and technology positions.  His experience and leadership in the refining industry adds a key capability to the Company's HTL™ commercialization efforts.
 
 
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 core oil and gas operations are located in two geographic areas: Canada and Ecuador. The Technology Development operation captures costs incurred to develop, enhance and identify improvements in the application of the HTL™ technology. The Company also has an exploration project in Mongolia. Net income, capital expenditures and identifiable assets for these segments appear in Note 19 to the consolidated financial statements and in the MD&A in this Annual Report.
 
Canada
 
Tamarack, acquired from Talisman in 2008, is a 6,880 acre lease located approximately 10 miles northeast of Fort McMurray, Alberta, Canada. The Tamarack Project envisages a two-phased 40,000 bbl/d steam-assisted gravity drainage thermal recovery (“SAGD”) and HTL™ facility. Our independent reserve evaluator, GLJ Petroleum Consultants Ltd. (“GLJ”), has assigned net probable reserves of 139 mmbbls of bitumen to Tamarack. Talisman held a 20% back-in right which expired in July 2011. Additionally, in 2011, Ivanhoe repaid a $40 million promissory note to Talisman that was part of the initial purchase price.

Ivanhoe filed an Environmental Impact Assessment for the Tamarack Project in November 2010. Regulators completed their initial review of the Company’s application and, as is customary, provided an initial set of Supplemental Information Requests (“SIRs”) in the third quarter of 2011. The Company submitted the supplemental information to the regulators in the fourth quarter of 2011.

The Company received additional SIRs in the second and fourth quarters of 2012 and responded to the SIRs in July and November 2012, respectively. Subsequent to December 31, 2012, the Company received a Completeness Determination from Alberta Environment and Sustainable Resource Development pursuant to Section 53 of the Environmental Protection Act following its review of the Tamarack Environmental Impact Assessment.

The Company is currently in discussions with local stakeholders to address any statements of concern as part of the regulatory processSuccessful completion of these discussions, followed by an Order in Council from the Government of Alberta, will allow the Company to move forward with the implementation phase of the Tamarack Project. The Company anticipates completing these remaining milestones in the second quarter 2013. Project advancement, as currently envisaged, is subject to receiving an Order in Council from the Alberta Government and financing.

Ecuador
 
In October 2008, Ivanhoe Energy Ecuador Inc., an indirect wholly owned subsidiary, signed a 30 year specific services contract with the Ecuadorian state oil companies Petroecuador and Petroproduccion. The contract (which was subsequently assigned to another Ecuadorian state oil company, Petroamazonas) gives Ivanhoe 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 city. The specific services contract provides for the Ecuadorian Government to pay a fee for each barrel of oil produced from the field. This fee varies with three well known producer price indices and, in management’s opinion, tracks West Texas Instrument oil price movements. The Company anticipates 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 blend any light oil discoveries with the heavy oil for delivery to Petroamazonas.

In 2010, Ivanhoe drilled its first two appraisal wells in the Pungarayacu field.  The second, 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.  In 2011, the heavy crude oil extracted from the IP-5b well was successfully upgraded to local pipeline specifications using Ivanhoe’s proprietary HTL™ upgrading process.  Later in 2011, the Company completed a 190-kilometre 2-D seismic survey over the southern portion of Block 20. Following the analysis of the seismic program, Ivanhoe began preparing to drill one exploration well into the deeper Hollin and pre-cretaceous horizons in the southern part of the Pungarayacu Block to test the potential of lighter oil resources, which would prove beneficial for blending purposes and overall project economics.

In 2012, the Company drilled well IP-17 in the pre-cretaceous zone in the Southern portion of the Block to test the formations in this area. It was successfully drilled to a depth of 13,594 feet, where it was cased and suspended.  The well confirmed the presence of hydrocarbons in the Hollin and Napo formations and evaluated the potential of the deeper, pre-cretaceous structures. While hydrocarbons were found in the Hollin and Napo formations, the reservoir in the immediate vicinity of the well was not suitable for commercial exploitation.
 
 

 
The Company has engaged in discussions with a third party respecting the possibility of jointly investing and participating in the development and operation of Block 20. During the course of these discussions, the parties have developed a framework of commercial terms intended to form the basis for separate discussions with the Government of Ecuador. The ultimate objective of discussions with the Government is the establishment of mutually acceptable terms and conditions allowing for the formation of a consortium between the Company and the third party to jointly participate in Block 20. The formation of the consortium is contingent upon the successful negotiation of definitive and legally binding agreements that reflect the achievement of this objective. There is no assurance that this objective can be achieved, or achieved in a timely manner.

Asia
 
Mongolia
 
Through a merger with PanAsian Petroleum Inc. in November 2009, we acquired a production sharing contract (“PSC”) for the Nyalga Block XVI in the Khenti, Govi Sumber and Tov provinces in Mongolia. The project is operated by a Mongolian registered company Shaman LLC (“Shaman”) which is an indirect wholly-owned subsidiary of Panasian Energy Ltd. The block covers an area of approximately 9,239 square kilometers, after a 25% area relinquishment in 2010 and an additional 20% area relinquishment in 2012. 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 adjusted the dates on which the project year begins. Phase II is now considered to have commenced on July 20, 2010.

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. The seismic was used to drill two wells in 2011. The first exploration well, N16-1E-1A, was drilled and abandoned as the well did not encounter oil shows in the reservoir. The Company observed oil staining, fluorescence and increases in background gas at its second exploration well site at N16-2E-B. After extensive laboratory testing of the drill cuttings from the second well it was determined that the oil was not of a mobile nature and the decision was made to forego any completion operations. Well site reclamation work has been completed and the local government has signed off on the acceptance of the reclamation works.

The project is in the final year of the five year initial term of the exploration license expiring July 19, 2013. According to the PSC, provided that minimum expenditures have been met, the exploration license can be extended for an additional two years by giving written notice to the Mongolian Government 30 days prior to the expiry of the initial 5 year term. There is also provision for an additional two year extension. Although 2011 costs under audit have not been finalized, Shaman expects to exceed minimum expenditure requirements by a significant margin.

Subsequent to December 31, 2012, the Company completed acquisition of a 106 kilometer 2-D seismic program and will process that data seeking exploration prospects.

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 probable and possible oil reserves as of December 31, 2012. The Company previously reported proved reserves associated with its Dagang project in China which was sold in 2012.

Summary of Oil and Gas Reserves Using Average 2012 Prices
 
   
Canada
 
   
Bitumen
 
(mbbl)
 
Tamarack
 
Probable
     
Developed
     
Undeveloped
    138,857  
Possible
       
Developed
     
Undeveloped
    32,929  

 
Canada
 
Probable and Possible Reserves
 
No additional reserves were assigned to Tamarack in 2012 as further reserve development is subject to regulatory approval of the Company’s application for the project, sanctioning by the Board of Directors and further delineation drilling.

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
 
Recovery estimates for Tamarack are based on a combination of reservoir simulation, detailed reservoir characterization and analogue project performance.

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 in this Annual Report 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 (the “COGE Handbook”) modified to reflect SEC requirements. As a Canadian public company, we are also subject to the disclosure requirements of National Instrument 51-101 (‘‘NI 51-101’’) of the CSA, which requires us to disclose reserves and other oil and gas information in accordance with the prescribed standards of NI 51-101. The prescribed standards differ, in certain respects, from SEC requirements. See the Special Note to Canadian Investors on page 9.

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.

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 (P.Eng.) in Alberta, with over 33 years of broad petroleum engineering experience in the oil and gas industry in Canada. His past experience includes reserves estimations for government filings, reservoir development engineering for both oil and gas projects, economic evaluations for potential acquisitions and dispositions, production operations, project management, budgeting and corporate planning.

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 an 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, the CSA adopted NI 51-101 which prescribes standards that Canadian public companies engaged in oil and gas activities are required to follow in the preparation and disclosure of reserves and related information.

Until 2010, we had an exemption from certain requirements of NI 51-101 which permitted us to substitute disclosures based on SEC requirements for some of the annual disclosure required by NI 51-101 and to prepare our reserve 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 COGE Handbook, modified to reflect SEC requirements. This exemption is no longer available to us for reserve reporting in Canada.

We have, however, received another exemption from the CSA which, among other things, allows us to disclose reserves and related information in accordance with applicable US disclosure requirements provided that we also make disclosure of our reserves and other oil and gas information in accordance with applicable NI 51-101 requirements. We disclose reserve information in accordance with applicable US disclosure requirements in this Annual Report. We disclose reserves and other oil and gas information in accordance with applicable NI 51-101 requirements in our Form 51-101F1, Statement of Reserves Data and Other Oil and Gas Information, which is filed with the CSA and available at www.sedar.com.

The reserve quantities disclosed in this Annual Report represent reserves calculated on an average, first-day-of-the-month price during the 12 month period preceding the end of the year for 2012, using the standards contained in SEC Regulations S-X and S-K and Accounting Standards Codification 932 Extractive Activities – Oil and Gas (section 235), 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; 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.

Production, Sales Prices and Production Costs
 
   
2012(1)
   
2011
   
2010
 
Oil production (bbls/d)
    850       967       788  
Average sales price ($/bbl)
    114.28       105.93       75.52  
Average operating cost (2) ($/bbl)
    42.90       44.10       33.05  
 
 
(1)
2012 production information relates to the Company’s project in Dagang which was sold in December 2012 and includes eleven months of results.
 
(2)
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 exceeds a certain threshold.  Average operating costs exclude depletion and depreciation, income taxes, interest, selling and general administrative expenses.
 
Ivanhoe’s oil production originated in Asia, specifically the Dagang and Daqing fields in China. The majority of our production came from Dagang and was sold to the Chinese national petroleum company. In December 2012, the Company sold the productive oil wells that were associated with its properties in China.

Acreage
 
   
Developed Acres
   
Undeveloped Acres(1)
 
   
Gross
   
Net
   
Gross
   
Net
 
Asia – Mongolia
                2,283,234       2,283,324  
Canada
                7,520       7,520  
Latin America
                272,639       272,639  
 
 
(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.

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.

We signed a specific services contract with the Ecuadorian state oil companies in October 2008 that allows us to develop and operate 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 Mongolia is subject to periodic relinquishments up to the end of the exploration period and the remaining acreage, if any, designated for appraisal and development will expire 20 years after the final commercial discovery on the Nyalga block.

Drilling Activity
 
   
Net Exploratory
   
Net Development
   
Total
 
(net wells)(1)
 
Productive
   
Dry Holes
   
Total
   
Productive
   
Dry Holes
   
Total
   
Wells Drilled
 
Asia
                                         
2012(2)
          1.0       1.0       1.0             1.0       2.0  
2011(3)
          1.0       1.0       2.5             2.5       3.5  
 
 
(1)
Net wells are the sum of fractional working interests owned in gross wells.
 
(2)
At December 31, 2012 we were not actively drilling wells.
 
(3)
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.

 

TECHNOLOGY DEVELOPMENT
 
The Company’s Technology Development segment captures HTL™ activities.  In April 2005, Ivanhoe merged with Ensyn and thereby obtained an exclusive, irrevocable license to the HTL™ process for all applications other than biomass. The Company has 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 six granted US patents and currently has five US patent applications pending. In other countries, the Company has 44 patents granted and 32 patents are pending. In addition, Ivanhoe owns exclusive, irrevocable licenses to 17 global patents for the rapid thermal processing process as it pertains to petroleum. The expiration date for Ivanhoe’s key patents is 2028.

Ivanhoe Energy is in the process of commercializing HTL™; a proprietary and patented process that is intended to significantly increase the economic viability of heavy oil by partially upgrading it at the well site and creating a synthetic crude oil (“SCO”) that is more valuable to international refineries.

The world-wide production of heavy oil has to overcome currently embraced conventional methods of extraction, transportation and refining which are too capital intensive and often uneconomic. HTL™ is designed to be a low-cost, efficient and environmentally sound way to create greater economic value from heavy oil. It can be used at the well site to partially upgrade and significantly improve the properties of heavy oil by reducing viscosity, increasing gravity and removing contaminants.

When processing heavy crude oils with an 8° to 10° API gravity, HTL™ produces a synthetic crude oil of 18° to 20° API.  The process substantially reduces the viscosity and converts the residual oil to high value synthetic crude oil, which can be processed by most modern refineries. The HTL™ synthetic crude oil, when priced at the refinery gate and blended with a typical crude diet, has been valued by a third party engineering firm at close to Brent pricing.

The technology is ready to be built. Engineering has been done, including sizing vessels and it has been modularized so that it can be transported and built it in remote locations. The company intends to commercialize the technology through two different models. The field integrated model, such as the Tamarack project, integrates an HTL™ facility with production operations and the resulting synthetic crude oil is sold to downstream customers. Ivanhoe is also developing midstream projects in which resource owners deliver heavy crude to a centralized HTL™ facility that would partially upgrade the heavy oil for a fee.

Ivanhoe has a feedstock test facility (“FTF”) located at the Southwest Research Institute in San Antonio, Texas. The FTF has the functionality of a full-scale commercial facility, but at a size that allows for multi-run optimization and testing of third party crude oils from around the world. It provides an accurate estimate of the commercial processing characteristics of target crudes and facilitate the generation of intellectual property, including the development of new patents and operational know-how. In 2010, the FTF supported basic and front-end engineering for a commercial-scale HTL™ plant for the Tamarack Project in Canada. In 2011, activities at the FTF focused on the assay and analyses related to the successful upgrading of the heavy oil recovered from the Pungarayacu IP-5b well in Ecuador. In 2012, Ivanhoe continued to exploit the unit to further technology development, process improvement as well as commercial engineering of HTLTM plants.
 
 
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 more easily absorb the burden of any changes in laws and regulations in the jurisdictions in which we do business, 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, evaluate and select suitable properties, implement advanced technologies, and consummate transactions in a highly competitive environment. The oil and gas industry also competes with other industries in supplying energy, fuel and other needs of consumers.


 
Environmental Regulations
 
Our oil and gas and HTL™ operations are subject to various levels of government regulation 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 laws regulate 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, increased air quality standards for our operations and may result in increased capital expenditures.

Operations in Canada are governed by comprehensive federal, provincial and municipal regulations. We submitted the Regulatory Application/Environmental Impact Assessment for the Tamarack Project to the Government of Alberta in November 2010The regulatory process is expected to conclude in the second quarter of 2013. 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.

Ecuador and Mongolia continue to develop and implement more stringent environmental protection regulations and standards for industry. Projects are currently monitored by governments based on the approved standards specified in the environmental impact statements prepared for individual projects, located on the Company’s website.

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 Ecuadorian and Mongolian governments regulate various aspects of foreign company operations in their respective countries. Such laws and regulations have generally become, globally, more stringent in recent years, 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, 2012, we had 89 employees. None of our employees are unionized.
 
AVAILABLE INFORMATION
 
The principal corporate office of Ivanhoe Energy Inc. is located at 999 Canada Place, Suite 654, Vancouver, British Columbia, V6C 3E1. Our registered and records office is located at 300-204 Black Street, Whitehorse, Yukon, Y1A 2M9 and our operational headquarters are located at 101-6th Avenue SW, 21st Floor, Calgary, Alberta, T2P 3P4.

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. The information on our website is not, and shall not be, deemed to be part of this Annual Report.

Each of the SEC (www.sec.gov) and the CSA (www.sedar.com) maintains a website from which you can access our reports, proxy and information statements and other published information that have been filed or furnished with the SEC and the CSA. A copy of this Annual Report is located at the SEC’s Public Reference Room at 100 F Street, NE, Washington, D.C. 20549. Information on the operation of the Public Reference Room can be obtained by calling the SEC at 1-800-SEC-0330.

 

 
ITEM 1A:  RISK FACTORS
 
We are exposed to various risks, some of which are common to other companies in the oil and gas industry and some of which are unique to our business. Certain risks set out below constitute “forward-looking statements” and readers should refer to the “Special  Note Regarding Forward-Looking Statements” on page 3.

If we are unable to adequately fund our substantial capital and operating requirements our ability to continue as a going concern could be adversely affected
 
Our business is capital intensive and the advancement of our projects in Canada, Ecuador and Mongolia and our HTL™ technology commercialization initiatives require significant funding. We have a history of operating losses and our current exploration and development activities do not generate cash flow sufficient to meet our funding obligations and capital expenditure plans. Historically, we have relied upon equity capital as our principal source of funding. The sustainability of our business is dependent upon our having reliable access to additional capital in order to meet obligations associated with our existing projects and capitalize upon potentially valuable opportunities to acquire and develop future projects. We may seek financing from a combination of strategic investors and/or public and private debt and equity markets, either at the parent company level or at a project level. There is no assurance that we will be able to obtain such financing or obtain it on favorable terms and any future equity issuances may be dilutive to our existing shareholders.

Our access to financing may be limited by an inability to attract strategic partners willing to invest in our projects on acceptable terms, ongoing volatility in equity and debt markets and a sustained downturn in the market price of our common shares.  Without access to sufficient amounts of financing or the ability to undertake other cash generating activities, we may have to delay or forego potentially valuable project acquisition and development opportunities or default on existing funding commitments to third parties. This could result in the dilution or forfeiture of our rights in existing projects, which would cast substantial doubt that the Company would be able to continue as a going concern.

Talisman’s security interest in our Tamarack project assets could impede our ability to secure third party debt
 
When we acquired our Tamarack project in 2008, we incurred a series of debt obligations in favor of Talisman secured by a first fixed charge and security interest in the Tamarack oil sands leases and a general security interest in all of our present and after acquired property, other than our equity interests in our subsidiaries (through which we hold our HTL™ technology and our projects in Ecuador and Mongolia). Although we have satisfied substantially all of the material debt obligations we owed to Talisman, we remain subject to a contingent payment obligation of up to Cdn$15.0 million, which is also secured by Talisman’s security interest. This contingent obligation becomes due and payable if and when we obtain the requisite government and other approvals necessary to develop the northern border of one of the leases. We are obliged to use commercially reasonable efforts to obtain these approvals. However, despite our efforts, the risks inherent in oil field development, including potential environmental considerations, create significant uncertainty as to when, if ever, we will be able to obtain these approvals and, consequently, we cannot predict when, if ever, this contingent obligation will become due and payable or when Talisman’s security interest will be released and discharged.

The Talisman security interest restricts our ability to grant security over our Tamarack project assets to secure debt obligations to third parties that we may create in the future. Assets unencumbered by the Talisman security interest may be insufficient as collateral to secure these obligations. This could adversely affect our ability to obtain debt financing or to obtain it on favorable terms. Since Talisman’s security interest secures a contingent obligation of potentially indefinite duration, we cannot predict when, and on what terms, we will be able to mitigate this risk.

The volatility of oil prices may affect the commercial viability of our projects
 
The commercial viability of our exploration and development projects is highly dependent on the price of oil. Prices also affect our ability to borrow money or raise additional capital. Even relatively modest changes in oil prices may significantly change an oil and gas company’s 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 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 reserves and future net revenue may change if the assumptions on which such estimates are based prove to be inaccurate
 
Reserve estimates 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 reserves and future net cash flow being materially different from those estimated. 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 reserve estimates. Revisions to prior estimates may be material.

We may incur significant costs on exploration or development 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 commodities 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 more readily endure longer periods of reduced oil and gas prices. 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 on, 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 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 that they will be renewed upon expiry or will not contain terms and conditions that adversely affect the final design or economics of our projects.
 
Complying with environmental and other government regulations could be costly and could negatively impact our operations
 
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 contaminated.

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 mandated by such laws on 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. In the course of carrying out our operations, we may encounter unexpected and materially adverse circumstances or events, including fires, natural disasters, catastrophic weather conditions, explosions, unusual or unexpected geological formations including formations with abnormal pressures, blowouts, cratering, equipment malfunctions, pipeline ruptures, spills or discharges of hazardous substances, or title problems. Any such unexpected and materially adverse circumstances or events 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 if we experience events or circumstances for which we are not insured or are underinsured. The occurrence of an uninsured or underinsured event could have a material adverse impact on our financial condition and results of operations. We do not carry business interruption insurance and, therefore, we bear the risk of any loss or deferral of revenues resulting from a curtailment of future production.

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 for environmental damage is available at a reasonable cost. Accordingly, we could be exposed to potentially significant losses and liabilities 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 vary and any material variance can impact costs. The performance of the reservoir can also affect the timing and levels of production using SAGD technology. Although SAGD technology is now being used by several producers, commercial application of the technology is still in its early stages relative to other methods of production. In the absence of an extended and demonstrated operating history, there can be no assurances with respect to the sustainability of SAGD operations.

We may not successfully commercialize our HTL™ technology
 
Successful commercialization of our HTL™ technology in the oil and gas industry is contingent upon our ability to identify and acquire appropriate sources of feedstock for, and 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 and operated in the bio-mass industry.

Technological advances could render our HTL™ technology obsolete
 
We expect that technological advances in competing processes and procedures for upgrading heavy oil and bitumen into lighter, less viscous products will continue to be made. It is possible that these competing processes and procedures could cause our HTL™ technology to become uncompetitive or obsolete.

Alternate sources of energy could lower the demand for the products that our HTL™ technology is intended to produce
 
Alternative sources of energy are continually under development. If reliance upon petroleum based fuels decreases, the demand for products that our HTL™ technology is intended to produce 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 products that our HTL™ technology is intended to produce.

Efforts to commercialize our HTL™ technology may give rise to claims of infringement upon the patents or other proprietary rights of others
 
We own licenses 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 respecting operating results or proprietary intellectual property. Although we regularly require third parties to sign confidentiality agreements prior to the disclosure of any confidential information, an unauthorized disclosure of confidential information 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 are in the midst of a regulatory approval process with the Government of Alberta in respect of our Tamarack Project. Although we believe that we will successfully complete the
 
 
 
regulatory approval process sometime during the second quarter of 2013, there is no assurance that the process will be successfully completed, or completed on a timely basis. If the regulatory approval process becomes more protracted than anticipated, construction of the Tamarack Project could be significantly delayed. There is also a risk that the Government of Alberta may not approve the project as proposed or that it may impose conditions upon its approval which could significantly impair the economics of the project. Our 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 any of our projects will be completed within any anticipated time frame or within the parameters of any anticipated capital cost. We have yet to establish a definitive schedule for financing and fully developing these projects. Other factors, in addition to lack of financing, may hinder our ability to develop and operate our projects on a timely basis. 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 upon, regulatory approvals; violation of permit requirements; disruption in the supply of energy; and catastrophic events such as fires, earthquakes, storms or explosions.

Our Tamarack Project may be exposed to title risks and aboriginal claims
 
We hold our interest in the Tamarack Project through leases granted by the Government of Alberta, which we purchased from Talisman. There is a risk that the land covered by these leases may be subject to prior unregistered agreements or interests or undetected claims or interests that could impair our leasehold title. Any such impairment could adversely affect our ability to construct and operate the Tamarack Project on the basis presently contemplated, which could have a material adverse effect on our financial condition, results of operations and ability to execute our current business plan in a timely manner.
 
Aboriginal peoples have claimed aboriginal title and rights to large areas of land in western Canada where oil and gas operations are conducted, including claims that, if successful, could delay or otherwise adversely affect the construction and operation of the Tamarack Project, which could have a material adverse effect on our business.
 
Our Block 20 Project in Ecuador may be at risk if the agreement through which we hold our interest is challenged or cannot be enforced
 
We hold our interest in the Block 20 Project in Ecuador through a specific services agreement with an Ecuadorian national oil company. 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 will be unable to agree with the Ecuadorian national oil company as to whether a dispute should be referred to international arbitration or mediation or arbitration in Ecuador. There can also be no assurance that the Ecuadorian national oil company will comply with the dispute resolution provisions or otherwise voluntarily submit to arbitration.

Government policy in Ecuador may change to discourage foreign investment or legal requirements pertinent to foreign investment in Ecuador may change in unforeseen ways. 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 contracts
 
The interests we hold in our projects are derived from licenses, leases and contracts. If we fail to meet the specific requirements of the instrument through which we hold our interest in a particular project, 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 contract. Some of our project 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 projects. The termination of our interests in these projects 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 17% of our common shares and held the position of Executive Co-Chairman and is a member of our Board of Directors. As a result, he has the voting power to significantly influence our policies, business and affairs and the outcome of any corporate transaction or other matter, including mergers, consolidations and the sale of all, or substantially all, of our assets. In addition, the concentration of our ownership may have the effect of delaying, deterring or preventing a change in control that otherwise could result in a premium in the price of our common shares.

If we lose our key management and technical personnel, our business may suffer
 
We rely upon a relatively small group of key management personnel. In respect of the technological aspect 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. Although we have employment agreements with each of our key management and technical personnel, there is no assurance that these individuals will remain in our employ 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 a number of factors including the availability and cost of capital; our ability to demonstrate the commerciality of the HTL™ technology; favorable exploration results; current and projected oil or gas prices; costs and availability of drilling rigs and other equipment; supplies; personnel; timeliness of regulatory and third party approvals; reliability of project development cost estimates; and our ability to attract other industry partners to participate with us in our projects in order to reduce costs and exposure to risks.

We assess and gather data about our projects on an ongoing basis and it is possible that additional information will cause us to alter our schedule for the development of a particular project or determine that the project should not be pursued at all. Our plans regarding our projects might change.
 
 
ITEM 1B:  UNRESOLVED STAFF COMMENTS
 
None.
 
 
ITEM 3:  LEGAL PROCEEDINGS
 
On July 12, 2012, the United States Court of Appeals for the Tenth Circuit affirmed the dismissal of a lawsuit against the Company and related parties that had been filed on November 20, 2008 in the United States District Court for the District of Colorado. The plaintiffs in the case are Jack J. Grynberg and three affiliated companies. The ruling from the Tenth Circuit affirms the district court’s judgment dismissing the case without prejudice. The Court of Appeals denied plaintiffs’ request for rehearing and issued a mandate.  Following the conclusion of that appeal, the plaintiffs filed a petition for a writ of certiorari from the United States Supreme Court, which was denied on January 14, 2013.  The Supreme Court's denial finally concludes the appellate proceedings.

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 plaintiffs’ 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 district court granted the motion and dismissed the case without prejudice. The district court also 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, also have been awarded costs and fees as the prevailing parties in the trial court.
 
 

The Court of Appeals’ July 12, 2012 order affirmed the district court’s judgment and related orders. The Court of Appeals also concluded that the Ivanhoe Corporate defendants, including the Company, are entitled to fees and costs they incurred on appeal. The Court of Appeals remanded the case to the district court for the limited purpose of computing a proper award of appellate fees and costs. Following remand, the plaintiffs and the Ivanhoe Corporate defendants engaged in negotiations and reached an agreement to fully dispose of the Ivanhoe Corporate defendants’ claim for appellate fees and costs. After the agreement was reached, the district court closed the case in its entirety on September 26, 2012. The Company recovered approximately $0.5 million in costs.

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. GAR Energy subsequently abandoned its demand for arbitration and filed suit against the Company and subsidiaries in the Superior Court for Kern County, California on March 11, 2011. The lawsuit alleges breach of contract, fraud and other misconduct arising from a consulting agreement and various other agreements between GAR Energy and the Company relating to the Pungarayacu heavy oil field. The plaintiffs seek actual damages of $250,000 and a portion of the Company’s interest in the Pungarayacu field. The plaintiffs seek other miscellaneous relief, including requests for a declaration of some of the parties’ rights and legal relations under a consulting agreement, attorneys' fees and certain litigation costs and expenses, disgorgement of the Company's past, current and/or future profits attributable to the Pungarayacu field and certain other fields in Ecuador, tort damages and exemplary and punitive damages, the imposition of constructive trusts over certain amounts and profits requested by the plaintiffs, and pre-judgment and post-judgment interest. The Company removed the case to the United States District Court for the Eastern District of California and all of the defendants have answered and filed counterclaims for attorneys’ fees. Defendants filed a motion to dismiss certain claims and to compel arbitration of others. Plaintiffs’ filed a motion to remand the case to state court. On December 23, 2011, the Magistrate Judge denied plaintiffs’ motion to remand and issued findings and recommendations that would send all of the parties and all of the claims to arbitration should the district court Judge assigned to the case adopt them. On January 19, 2012 the district court Judge adopted the Magistrate Judge’s findings and recommendations in full, ordered the parties to arbitration and stayed the district court proceedings to allow for the completion of the arbitration. The arbitration hearing is set for September 2013 and the parties are currently engaged in discovery. 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. The Company believes that the plaintiff’s claims have no merit.


ITEM 4:  MINE SAFETY DISCLOSURES
 
Not applicable.
 

 
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
2012
Q1
 
1.34
0.82
 
1.33
0.83
 
Q2
 
1.15
0.44
 
1.15
0.44
 
Q3
 
0.76
0.50
 
0.76
0.52
 
Q4
 
0.89
0.40
 
0.91
0.41
2011
Q1
 
3.58
2.67
 
3.67
2.75
 
Q2
 
2.84
1.58
 
2.97
1.60
 
Q3
 
1.96
1.02
 
2.03
0.99
 
Q4
 
1.47
0.75
 
1.46
0.72
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

 
 
On December 31, 2012, the closing price of our common shares was Cdn$0.71 on the TSX and $0.7051 on NASDAQ.

As at March 7, 2013, a total of 344,472,761 of our common shares were issued and outstanding and held by 187 holders of record with an estimated 22,500 additional shareholders whose common shares were held for them in street name or nominee accounts.

The Company received a notification from the Listing Qualifications Department of the NASDAQ notifying the Company that the Company did not meet the minimum bid price requirements set forth in the NASDAQ Listing Rules. The Company could regain compliance if at any time prior to November 20, 2012 the closing bid price of the Ivanhoe’s common stock was at least $1.00 for a minimum of 10 consecutive business days. On November 1, 2012, the Company applied to the NASDAQ for an additional compliance period of 180 days which was granted and will expire on May 20, 2013.

The Company intends to seek approval of its shareholders to effect a reverse stock-split of its common shares in order to regain compliance with the minimum bid price requirements set forth in the NASDAQ Listing Rules. Reducing the number of issued and outstanding common shares through a common share consolidation is intended, absent other factors, to increase the per share market price of the common shares. However, the market price of the common shares will also be affected by the Company’s financial and operational results, its financial position, including its liquidity and capital resources, the development of its projects, industry conditions, the market’s perception of the Company’s business and other factors, which are unrelated to the number of common shares outstanding.

While a reverse stock-split will result in an initial trading price above the NASDAQ minimum bid price, the market considerations mentioned above will be the ultimate arbiter of the Company’s share price. The ability of the Company to remain above the minimum bid price and maintain a NASDAQ listing will be determined by the markets.

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. Our non-management directors hold regularly scheduled meetings but not all of our non-management directors are independent.

ENFORCEABILITY OF CIVIL LIABILITIES
 
We are a company incorporated under the laws of Yukon, 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 (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 2013 is Cdn$344 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 announced certain forthcoming 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$344 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%.


 
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, 2012, 2011 and 2010, 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
 
SUMMARY OF SELECTED FINANCIAL DATA
 
The following table presents selected financial data based on International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”) and should be read in conjunction with our accompanying “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in Item 7 of this report and with the audited consolidated financial statements and the related notes thereto included in Item 8 of this report. Results of operations are shown for continuing operations, which exclude the operations discontinued in China, for the fiscal years presented.

($000s, except per share amounts)
 
2012
   
2011
   
2010
 
Results of Operations
                 
Net loss from continuing operations
    (64,018 )     (26,761 )     (22,258 )
Net loss from continuing operations per share – basic and diluted
    (0.19 )     (0.08 )     (0.07 )
                         
Financial Position
                       
Total assets
    402,057       413,710       394,418  
Long term debt
    65,214       61,892        
Long term derivative instruments
    181       1,617        
Long term provisions
    3,157       1,919       3,008  

 

 
 
ITEM 7: MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
23
24
 
24
25
25
25
26
26
26
26
27
27
27
27
31
32

The following MD&A should be read in conjunction with the audited consolidated financial statements for the year ended December 31, 2012 (the “Financial Statements”). The Financial Statements have been prepared in accordance with and using accounting policies in full compliance with IFRS and International Accounting Standards (“IAS”) issued by the International Accounting Standards Board (“IASB”) and Interpretations of the International Financial Reporting Interpretations Committee.

As a foreign private issuer in the US, Ivanhoe is permitted to file with the SEC financial statements prepared under IFRS without a reconciliation to US generally accepted accounting principles (“US GAAP”). It is possible that some of our accounting policies under IFRS could be different from US GAAP.
 
The date of this discussion is March 18, 2013.  Unless otherwise noted, tabular amounts are in thousands of US dollars. Oil and gas production, revenue, reserves and related measures are presented net of royalty payments to governments.

BUSINESS ENVIRONMENT
 
The Company’s core operations are in Canada and Ecuador. Canada offers a relatively stable business environment in which to operate due to established infrastructure and political stability. However the oil and gas sector currently faces challenges including transportation of oil and gas products to international markets and the associated environmental impact of these projects. The Company believes that the long term demand for oil and gas will remain strong and that further development, particularly in the heavy oil segment, will be required in order to meet this anticipated demand.
 
Ecuador regulates various aspects of foreign company operations and has had periods of political instability in the past. With the recent election of the incumbent Ecuadorian President, the Company anticipates the government’s future policy toward foreign investment in oil and gas operations will remain consistent and one in which the Company can operate.
 
The development of the Company’s oil and gas and HTL™ operations are capital intensive. In the past, Ivanhoe has used external sources of funding such as public and private equity and debt markets. The Company is impacted by industry influences including commodity prices and larger macro-economic factors that have had investors recently rotating out of commodity investments and may affect the Company’s ability to obtain financing on acceptable terms.
 

 
 
 
HIGHLIGHTS
 
($000, except as stated)
 
2012
   
2011
   
2010
 
Capital expenditures
    47,444       51,060       70,980  
                         
Cash flow used in operating activities
    (27,060 )     (26,245 )     (31,290 )
Net loss from continuing operations
    (64,018 )     (26,761 )     (22,258 )
Net loss per share from continuing operations – basic and diluted
    (0.19 )     (0.08 )     (0.07 )

In December 2012, the Company discontinued its operations in China with the transfer of the Company’s interest in the Contract for Exploration, Development and Production in the Zitong Block to Shell China Exploration and Production Company (“Shell”) for $105.0 million and the sale of Pan-China Resources Ltd. to MIE Holding Corporation (“MIE”) for $45.0 million, each subject to adjustments and certain holdback amounts. The Company used a portion of the proceeds to extinguish its short term debt and the remaining proceeds will be used within the Company’s remaining business.

Net loss from continuing operations in 2012 was $64.0 million, an increase of $37.2 million compared to $26.8 million in 2011. The increase is mainly attributable to $20.2 million in higher exploration and evaluation expenses and an $11.7 million lower unrealized derivative gain in 2012.
 
Capital expenditures amounted to $47.4 million in 2012.
 
In Ecuador, $23.4 million in capital expenditures were used to drill a 13,594 foot well, IP-17, into the pre-cretaceous zone in the Southern portion of the Block to test the formations in this area. The well confirmed the presence of hydrocarbons in the Hollin and Napo formations and evaluated the potential of the deeper, pre-cretaceous structures. While hydrocarbons were found in the Hollin and Napo formations, the reservoir in the immediate vicinity of the well was not suitable for commercial exploitation.

In Canada, the Company spent $3.8 million in capital expenditures to support the Tamarack Project regulatory process. The Company received additional Supplemental Information Requests (“SIR”) from the Alberta regulators in the second and fourth quarters of 2012 and responded to the SIRs in July and November 2012, respectively. The Company is currently in discussions with local stakeholders to address any statements of concern as part of the regulatory process. Project advancement, as currently envisaged, is subject to regulatory approval and financing. The Company expects to complete remaining regulatory milestones in the second quarter of 2013.

In China, the Company had capital expenditures of $12.4 million for the seismic program at Zitong, $7.3 million for drilling two wells at Dagang, one of which was completed in the second quarter of 2012; the second well was completed in the third quarter of 2012, and $0.5 million in other expenditures. These expenditures relate to discontinued operations that were sold in December 2012.

RESULTS OF OPERATIONS
 
Discontinued Operations
 
Zitong Block
 
On December 27, 2012 Sunwing Zitong Energy, a wholly owned subsidiary of the Company, completed the transfer of the Company’s participating interest in the Zitong Petroleum Contract to Shell.

In exchange for Sunwing’s interest in the Zitong Petroleum Contract, the Company will receive total pre-tax cash proceeds of $105.0 million subject to a holdback pending the completion of regulatory audits. Initial pre-tax proceeds of approximately $96.2 million were delivered on closing. The Company will receive the remaining proceeds once CNPC completes its annual cost recovery audit for 2012 expenditures ($3.7 million); and a customary holdback period of six months from the transaction date expires ($5.1 million), less any post-closing adjustments.

Subsequent to December 31, 2012, Shell assumed the obligations under the Zitong Supplementary Agreement and replaced the Company’s performance bond with its own. As a result, the collateral for that performance bond, presented as restricted cash on the Company’s balance sheet at December 31, 2012, was released on February 1, 2013.


 
Pan-China Resources Ltd.
 
On December 17, 2012 the Company completed the sale to MIE Holdings Corporation (“MIE”) for all of the outstanding shares of its indirect, wholly owned subsidiary, Pan-China Resources Ltd.

As consideration, the Company received $45.0 million in cash, less $5.4 million in adjustments and a $4.0 million holdback. The Company will receive the holdback amount six months after closing if there are no claims from MIE.

Operating Costs
 
Operating costs in the Technology Development segment are incurred at the Company’s Feedstock Test Facility (“FTF”) at the Southwest Research Institute in San Antonio, Texas and mainly consist of labor and materials. 

FTF operating costs in 2012 were $4.3 million, relatively unchanged from the 2011 operating costs of $4.6 million.

FTF operating costs of $4.6 million in 2011 were $0.5 million higher than the $4.1 million in costs incurred in 2010 due to activities associated with assay and analyses related to the successful upgrading of the heavy oil recovered from the Pungarayacu IP-5b well in Ecuador and planned maintenance costs associated with enhancements implemented at the FTF in the second quarter of 2011.

General and Administrative
 
G&A expenses mainly consist of staff, office and legal and other contract services costs.

The Company incurred G&A expenses of $31.1 million in 2012, a decrease of $7.5 million compared to costs of $38.6 million in 2011. G&A expenses were lower in 2012 due to lower staff and legal and other contract services costs. Staff costs decreased $3.6 million compared to 2011 because the formalization of the Company’s compensation program in 2011 resulted in the Company accruing two years of short term incentive costs for that year; 2012 also benefitted from lower share-based payment expense due to higher employee turnover in 2012. Legal and other contract services costs decreased $2.0 million from 2011 mainly due to the conclusion of the Grynberg lawsuit and recovery of the Company’s costs as a result of a favorable ruling in that case. G&A costs also decreased $1.9 million from 2011 mainly due to less allocated shared services activity and lower professional service fees relating to audit and financing activities.

G&A expenses were $38.6 million in 2011, an increase of $2.4 million compared to G&A expenses of $36.2 million in 2010. The higher G&A costs in 2011 mainly result from increased legal costs of $2.0 million, in connection with proceedings further described in Part I, Item 3 of this Form 10-K, as well as financing costs associated with the Cdn$73.3 million convertible unsecured subordinated debentures (“Convertible Debentures”) issued in the second quarter of 2011 and contract engineering costs of $0.4 million related to Ivanhoe’s HTL™ technology to investigate new applications. The higher costs in 2011 were partially offset by lower charitable contributions; in 2010, the Company committed to a $1.0 million donation to flood victims in Ecuador.

Exploration and Evaluation
 
Costs of exploring for, and evaluating, oil and gas properties are initially capitalized as intangible exploration and evaluation (“E&E”) assets and charged to E&E expense only if sufficient reserves cannot be established or once the costs are determined to have no future value.

E&E expense in 2012 was $23.0 million, $20.2 million higher than E&E expense of $2.8 million in 2011. The IP-17 exploratory well in the southern part of Block 20 in Ecuador led to the discovery of non-commercial quantities of hydrocarbons and the Company expensed $19.9 million in related costs in 2012. In addition, the Company also expensed $2.9 million in capital costs in 2012 relating to the second Mongolian well drilled in 2011. Independent laboratory tests finalized in September 2012 on the drill cuttings from Mongolia indicated that there is a high probability that mobile oil in the well is limited. Other E&E costs of $0.2 million were expensed in the second quarter of 2012.

E&E expense in 2011 was $2.8 million, a decrease of $2.1 million from an E&E expense of $4.9 million in 2010. Drilling costs of $2.1 million were expensed in connection with the exploration well in Mongolia that was plugged and abandoned.  In addition, it was determined that $0.7 million of expenditures related to the seismic program in Ecuador would have limited future value and were therefore charged to E&E expense.

E&E expense in 2010 related to the drilling of two appraisal wells on Block 20 in Ecuador. The first appraisal well, IP-15, encountered cementing and completion problems prior to steam injection operations and testing was suspended without recovering oil resulting in $4.9 million of drilling and testing costs expensed in 2010.
 
 

Depreciation
 
Depreciation expense is primarily charges for the amortization of capitalized costs of the FTF but also includes furniture and equipment depreciation.

Depreciation expense in 2012 was $1.0 million, unchanged from 2011.

Depreciation expense in 2011 was $1.0 million, an increase of $0.7 million compared to $0.3 million in 2010. The increase is driven by a lower than normal 2010 depreciation amount that resulted from Commercial Demonstration Facility salvage costs coming in lower than previously recorded amounts.

Foreign Currency Exchange
 
The gain or loss on foreign currency exchange results from the revaluation of monetary assets and liabilities denominated in currencies other than the Company’s functional currency, the US dollar, at each period end and from the settlement of the Company’s payables denominated in foreign currencies.

The Company incurred a $1.2 million loss on foreign currency exchange in 2012 compared to a $0.5 million gain in 2011. The loss on foreign exchange in 2012 is mainly due to the revaluation of the Canadian denominated Convertible Debentures as the Canadian dollar strengthened near the end of 2012 compared to the 2011 closing exchange rate resulting in a higher translated debt in 2012.

The Company incurred a smaller net foreign exchange gain of $0.5 million in 2011 in comparison to $3.3 million from the prior year. The Canadian dollar was stronger than the US dollar in the first nine months of 2011, subsequently weakening in the fourth quarter of 2011. Net foreign exchange gains incurred on the translation of the Company’s Canadian dollar denominated cash, debt and payables in the first three quarters of 2011 were partially offset by net foreign exchange losses in the fourth quarter.

In the first quarter of 2010, the Company incurred a net foreign exchange gain on the translation of its Canadian dollar cash raised in the Cdn$150.0 million private placement when the Canadian dollar strengthened against the US dollar, which was partially offset by a net foreign exchange loss incurred in the second quarter of 2010 when the Canadian dollar weakened.  In the second half of 2010, additional foreign exchange gains were incurred on the translation of monetary items as the Canadian dollar continued to strengthen relative to the US dollar.

Derivative Instruments
 
The gain on derivative instruments results from accounting for the changes in the fair value of derivative instruments through earnings.

In 2012, the Company valued the convertible component of the Convertible Debentures at approximately $0.2 million compared to $1.6 million in 2011. The lower valuation, which resulted in an unrealized gain of $1.4 million in 2012, was a result of lower Company share prices in 2012 which the Company’s uses as an input in estimating the fair value of the derivative.

In 2011, the unrealized gain on derivative instruments was $13.1 million compared to $18.6 million in 2010. An unrealized gain on the convertible component of the Convertible Debentures totaled $7.8 million and a combination of the expiry and revaluation of the Company’s purchase warrants resulted in a gain of $4.1 million. Additionally, a gain of $1.2 million was recognized on the revaluation of the convertible portion of the Cdn$40.0 million convertible promissory note issued to Talisman (“Convertible Note”). The revaluation of an option granted to a private investor in January 2010 to acquire an equity interest in one of the Company’s subsidiaries created a loss of $0.2 million in the current year.

The $18.6 million unrealized gain recorded in 2010 stemmed from a $15.0 million and $3.6 million gain, respectively, on the revaluation of the purchase warrants and the Convertible Note.

Finance
 
Finance expense consists of interest expense and the unwinding of the discount rate for decommissioning obligations.

Finance expense in 2012 was $4.3 million, an increase of $3.9 million compared to $0.4 million in 2011. The increase is due to higher debt in 2012 which the Company used to fund operations while closing the 2012 asset dispositions as well as a lower allocation of interest to capital expenditures as debt funding near the last half of 2012 was used more for ongoing operations than capital projects.
 
 

Finance expense in 2011 was $0.4 million and did not change materially compared to 2010.

Loss on Debt Repayment
 
The Company classified its short term debt as a financial liability measured at amortized cost which allows for transaction costs to be amortized over the life of the debt instrument.

In December 2012, subsequent to the closing of the China asset dispositions, the Company used a portion of the proceeds to repay its short term debt earlier than the maturity date of the debt. This repayment resulted in the remaining deferred transaction costs of the debt instruments being charged through earnings at the time repayment was made. In 2012, these costs amounted to $3.0 million.
 
Gain on Derecognition of Long Term Provision
 
As part of the 2005 merger agreement with Ensyn, the Company assumed a $1.9 million contingent obligation. In the third quarter of 2011, the Company determined, based on recent events and clarification of contract terms, that satisfaction of the specific contractual contingencies was unlikely and the liability was derecognized.

Provision for Income Taxes
 
The Company recorded a deferred tax recovery of $2.4 million in 2012 compared to a recovery of $4.4 million in 2011. The $2.0 million decrease in recovery is mainly due to a reduction in the valuation allowance in 2011 in respect of certain US operating losses that were determined to be more likely than not to be realized as well as a reduction in net operating losses from lower expenses in 2012.

The Company recorded a deferred tax recovery of $4.4 million in 2011 compared to a recovery of $1.2 million in 2010. The $3.2 million increase in the recovery in 2011 was mainly due to a reduction in the valuation allowance previously mentioned as well as an increase in US operating losses.

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.

   
Total
   
2013
   
2014
   
2015
   
2016
   
After 2016
 
Long term debt(1)
    73,684                         73,684        
Interest on long term debt(1)
    14,824       4,237       4,237       4,237       2,113        
Decommissioning obligations(2)
    4,222             625                   3,597  
Leases
    3,130       1,546       626       426       426       106  
Total
    95,860       5,783       5,488       4,663       76,223       3,703  
 
 
(1)
Long term debt is denominated in Canadian dollars and has been translated to US dollars at an exchange rate of approximately CAD=1.005 USD.
 
(2)
Represents undiscounted decommissioning obligations after inflation. The discounted value of these estimated obligations ($2.9 million) is provided for in the consolidated financial statements.
 
Long Term Debt and Interest
 
As described in the Financial Statements, the Company issued Cdn$73.3 million of Convertible Debentures maturing on June 30, 2016. The Convertible Debentures bear interest at an annual rate of 5.75%, payable semi-annually on the last day of June and December of each year, commencing on December 31, 2011.

Decommissioning Provisions
 
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, 2012, Ivanhoe estimated the total undiscounted, inflated cost to settle its decommissioning obligations in Canada, for the FTF in the US and in Ecuador was $4.2 million. These costs are expected to be incurred in 2014, 2029 and 2038, respectively.


 
Leases
 
The Company has long term leases for office space and vehicles, which expire between 2013 and 2017.

Other
 
Should Ivanhoe receive government and other approvals necessary to develop the northern border of one of the Tamarack Project leases, the Company will be required to make a cash payment to Talisman of up to Cdn$15.0 million, as a conditional, final payment for the 2008 purchase transaction.

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. Similarly, agreements entered into by the Company may contain cancellation fees or liquidated damages provisions for early termination.  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 not likely to be material.

In the ordinary course of business, the Company is subject to legal proceedings being brought against it. While the final outcome of these proceedings is uncertain, the Company believes that these proceedings, in the aggregate, are not reasonably likely to have a material effect on its financial position or earnings.

Sources and Uses of Cash
 
The Company’s cash flows from operating, investing and financing activities, as reflected in the consolidated statements of cash flows, are summarized in the following table:

   
2012
   
2011
   
2010
 
Net cash used in operating activities
    (27,060 )     (26,245 )     (31,290 )
Net cash provided by (used in) investing activities
    77,662       (85,422 )     (68,684 )
Net cash (used in) provided by financing activities
    (5,388 )     61,423       138,286  

Ivanhoe’s existing financial resources are insufficient to fund the future capital expenditures necessary to advance the development of our existing projects. The Company intends to use its working capital to meet its commitments. The Company has engaged in discussions with a third party respecting the possibility of jointly investing and participating in the development and operation of Block 20. During the course of these discussions, the parties have developed a framework of commercial terms intended to form the basis for separate discussions with the Government of Ecuador. The ultimate objective of discussions with the Government is the establishment of mutually acceptable terms and conditions allowing for the formation of a consortium between the Company and the third party to jointly participate in Block 20. The formation of the consortium is contingent upon the successful negotiation of definitive and legally binding agreements that reflect the achievement of this objective. There is no assurance that this objective can be achieved, or achieved in a timely manner.

Additional sources of funding 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. However, there is no assurance that these sources of funding will be available to the Company in the future or available on acceptable terms, and any future equity issuances may be dilutive to current investors. If Ivanhoe cannot secure additional financing, the Company may have to delay its capital programs and forfeit or dilute its rights in existing oil and gas property interests.
 
Operating Activities
 
Cash used in operating activities in 2012 was $27.0 million, an increase of $0.8 million from $26.2 million of cash used in operating activities in 2011. The increase was mainly due to higher interest costs in 2012 from financing operations with a higher amount of debt than the prior year and was partially offset by lower general and administrative costs.

Cash used in operating activities in 2011 was $26.2 million, $5.1 million lower than $31.3 million used in operations in 2010 as growth in revenue exceeded increases in operating costs and G&A expenses.
 
 

Investing Activities
 
E&E Expenditures
 
E&E capital expenditures in 2012 were $40.1 million. In Canada, Ivanhoe spent $3.8 million to support the regulatory process at Tamarack and $23.4 million in drilling costs for the IP-17 exploration well in the southern part of Block 20 in Ecuador. Capitalized costs of $19.9 million associated with the IP-17 well were expensed in the third quarter as non-commercial quantities of hydrocarbons were discovered. Certain costs related to IP-17 remain capitalized as the well may be used in future development. In Asia, the Company spent $12.4 million for the seismic program at Zitong and $0.5 million on other expenditures.

E&E capital expenditures in 2011 were $37.4 million. In Ecuador, the Company spent $10.7 million primarily to complete a 190-kilometre 2-D seismic survey of Block 20. In Canada, $6.3 million in engineering and environmental costs were spent to support the regulatory process at Tamarack. In the Nyalga basin of Mongolia, $3.3 million in costs were incurred. Expenditures incurred on the Company’s first exploration well at N16-1E-1A were expensed. The drilling rig was mobilized to a second site, N16-2E-B, and drilling commenced in the middle of September 2011. In China, capital expenditures in 2011 were $17.1 million. The Yixin-2 and Zitong-1 gas wells at the Company’s Zitong project in China were tested and fracture stimulated.

E&E capital expenditures in 2010 were $65.3 million. In Canada, the Company spent $26.5 million on its winter delineation drilling program at Tamarack in early 2010 and on its regulatory application to the Government of Alberta submitted in November 2010.  In Ecuador, the Company spent $11.6 million on two appraisal wells on Block 20. The first appraisal well, IP-15, encountered certain cementing and completion problems prior to steam injection operations and testing was suspended without recovering oil. The second appraisal well, IP-5b, was successfully drilled, cored and logged. Capital expenditures in China in 2010 were $24.6 million. The Company successfully drilled two wells, Yixin-2 and Zitong-1.
 
Property, Plant and Equipment Expenditures
 
PP&E capital expenditures in 2012 were $7.3 million. The Company drilled two wells at Dagang, one of which was completed in the second quarter of 2012; the second well was completed in the third quarter of 2012.
 
PP&E capital expenditures in 2011 were $13.7 million. At Dagang, four wells were drilled and completed. A well drilled in 2010 was also completed in early 2011. The fracture stimulation program at Dagang continued throughout the year.

PP&E capital expenditures in 2010 were $5.6 million. The Company conducted five fracture stimulations at the Dagang field during the year.
 
Proceeds on Disposal of Discontinued Operations
 
Proceeds on disposal of discontinued operations were approximately $131.8 million before taxes.

On December 27, 2012 Sunwing Zitong Energy, a wholly owned subsidiary of the Company, completed the transfer of the Company’s participating interest in the Zitong Petroleum Contract to Shell. In exchange for Sunwing’s interest in the Zitong Petroleum Contract, the Company received pre-tax proceeds of approximately $96.2 million. The Company will receive the remaining proceeds once CNPC completes its annual cost recovery audit for 2012 expenditures ($3.7 million); and a customary holdback period of six months from the transaction date expires ($5.1 million), less any post-closing adjustments.

On December 17, 2012 the Company completed the sale to MIE for all of the outstanding shares of its indirect, wholly owned subsidiary, Pan-China Resources Ltd. As consideration, the Company received $45.0 million in cash, less $5.4 million in adjustments and a $4.0 million holdback. The Company will receive the holdback amount six months after closing if there are no claims from MIE.
 
Restricted Cash
 
In December 2011, Ivanhoe was required to post a $20.0 million performance bond as part of the completion and signing of the Supplementary Agreement with CNPC. Following the disposition of the Company’s interest in Zitong and subsequent to December 31, 2012, the Company received the $20.0 million in cash that was posted for the performance bond.
 
 
 
Financing Activities
 
Cash used in financing activities in 2012 was $5.4 million, an increase of $66.8 million compared to cash provided by financing activities in 2011 of $61.4 million. In December 2012, the Company secured $10.0 million in working capital which was repaid prior to December 31, 2012 along with the outstanding loans provided by UBS and ICFL subsequent to the closing of the China asset dispositions. In 2011, the Company raised $72.9 million, net of issuance costs, through the issuance of the Convertible Debentures in order to repay the Convertible Note due to Talisman on July 11, 2011, as well as operating expenses and capital expenditures. Cash proceeds of $29.9 million were also raised in 2011 through the exercise of purchase warrants and stock options.

Cash provided by financing activities in 2011 was $61.4 million, $76.9 million lower than $138.3 million raised in 2010. In 2010, the Company raised $135.7 million, net of issuance costs, through a private placement of 50 million special warrants at a price of Cdn$3.00 per special warrant.

Capital Structure
 
As at December 31
 
2012
   
2011
 
Long term debt
    65,214       17.7 %     61,892       16.5 %
Shareholders’ equity
    302,998       82.3 %     314,137       83.5 %
Total capital
    368,212       100.0 %     376,029       100.0 %

At December 31, 2012, Ivanhoe’s market capitalization was less than the carrying value of the Company’s assets.  Management does not consider this to be determinative that an impairment exists as there are factors which should be considered when interpreting Ivanhoe’s recent trading price, such as industry influences including commodity prices and larger macro-economic factors that have had investors recently rotating out of commodity investments. Management does not believe the full value of the Company’s oil and gas assets or HTL™ technology is reflected in Ivanhoe’s current stock price.

The Company received a notification from the Listing Qualifications Department of the NASDAQ notifying the Company that the Company did not meet the minimum bid price requirements set forth in the NASDAQ Listing Rules. The Company could regain compliance if at any time prior to November 20, 2012 the closing bid price of the Ivanhoe’s common stock was at least $1.00 for a minimum of 10 consecutive business days. On November 1, 2012, the Company applied to the NASDAQ for an additional compliance period of 180 days which was granted and will expire on May 20, 2013.

The Company intends to seek approval of its shareholders to effect a reverse stock-split of its common shares in order to regain compliance with the minimum bid price requirements set forth in the NASDAQ Listing Rules. Reducing the number of issued and outstanding common shares through a common share consolidation is intended, absent other factors, to increase the per share market price of the common shares. However, the market price of the common shares will also be affected by the Company’s financial and operational results, its financial position, including its liquidity and capital resources, the development of its projects, industry conditions, the market’s perception of the Company’s business and other factors, which are unrelated to the number of common shares outstanding.

While a reverse stock-split will result in an initial trading price above the NASDAQ minimum bid price, the market considerations mentioned above will be the ultimate arbiter of the Company’s share price. The ability of the Company to remain above the minimum bid price and maintain a NASDAQ listing will be determined by the markets.

 
 

 
CRITICAL ACCOUNTING PRINCIPLES AND ESTIMATES
 
The Financial Statements have been prepared in accordance with IFRS as issued by the IASB. The Financial Statements are not subject to qualification relating to the application of IFRS as issued by the IASB.

A detailed summary of the Company’s significant accounting policies is included in Note 3 to the Financial Statements. Some of these policies involve critical accounting estimates as they require the Company 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 critical accounting estimates and assumptions and how they affect the amounts reported in the Company’s Financial Statements.

Intangible E&E Assets
 
Management must determine if intangible E&E assets, which have not yet resulted in the discovery of proved reserves, should continue to be capitalized or charged to E&E expense. When making this determination, Ivanhoe considers factors such as the Company’s drilling results, planned exploration and development activities, the financial capacity of the Company to further develop the property, the ability to use the Company’s HTL™ technology in certain projects, lease expiries, market conditions and technical recommendations from its exploration staff.

Although the Company believes its estimates are reasonable and consistent with current conditions, internal planning and expected future operations, such estimates are subject to significant uncertainties and judgments. Ivanhoe cannot predict if an event that triggers impairment will occur, when it will occur, or how it will affect the reported asset amounts.

Impairment
 
Property, Plant and Equipment (“PP&E”)
 
Prior to the sale of its producing oil and gas properties in 2012, the Company periodically assessed its oil and gas assets, or groups of assets, for impairment whenever events or changes in circumstances indicated the carrying value may not be recoverable. Among other things, an impairment may be triggered by falling oil and gas prices, a significant negative revision to reserve estimates, the inability to use the Company’s HTL™ technology in certain projects, changes in capital costs or the inability to raise sufficient financial resources to further develop the property.

Cash flow estimates for the Company’s impairment assessments require significant assumptions about future prices and costs, production, reserves volumes and discount rates, as well as potential benefits from the application of its HTL™ technology. Given the significant assumptions required and the likelihood that actual conditions will differ, the assessment of impairment of oil and gas assets was considered to be a critical accounting estimate.

Intangible Technology Assets
 
The Company’s intangible technology assets consist of an exclusive, irrevocable license to deploy its HTL™ technology. Ivanhoe annually reviews the technology assets, and the associated FTF assets recorded within PP&E, 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. The intangible asset impairment is a critical accounting estimate because it requires Ivanhoe to make assumptions about competitive technological developments, the successful commercialization of its HTL™ technology and future cash flows from the HTL™ technology.

Ivanhoe cannot predict if an event that triggers impairment will occur, when it will occur, or how it will affect the reported asset amounts. Although the Company believes its estimates are reasonable and consistent with current conditions, internal planning and expected future operations, such estimates are subject to significant uncertainties and judgments.

Oil and Gas Reserves
 
The process of estimating quantities of reserves is inherently uncertain and complex. It requires significant judgments and decisions based on available geological, geophysical, engineering and economic data. These estimates may change substantially as additional data from ongoing development activities and production 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 the Company’s impairment evaluations, which in turn have a material impact on earnings.
 
 

Option Pricing Model
 
The Company uses the Black-Scholes option pricing model to measure the fair value of stock options and equity settled Restricted Share Units (“RSUs”) on the date of grant. Determining the fair value of stock-based awards on the grant date requires judgment, including estimating the expected life of the award, the expected volatility of the Company’s common shares and expected dividends. In addition, judgment is required to estimate the number of awards that are expected to be forfeited. Changes in assumptions can materially affect the estimated fair value, and therefore, the existing models do not necessarily provide precise measures of fair value.

Convertible Debentures
 
On June 9, 2011, the Company issued Cdn$73.3 million of Convertible Debentures. The Canadian dollar denominated debt is considered to contain an embedded derivative since the functional currency of the Company is the US dollar. As a result, the Convertible Debentures were bifurcated into debt and the equity conversion option, which was recognized at fair value using the Black-Scholes valuation method. Changes in the fair value of the equity conversion option are recorded in earnings; therefore the valuation of the equity conversion option is a critical accounting estimate.

The Black-Scholes valuation method requires the input of highly subjective assumptions regarding expected volatility of the Company’s share price and the risk-free interest rate. If the volatility used to fair value the equity conversion component at December 31, 2012 decreased by 10%, the fair value of the equity conversion option would decrease by $0.2 million. If volatility increased by 10%, the fair value of the equity conversion option would increase by $0.4 million.

Convertible Note
 
In connection with the acquisition of the Tamarack leases in July 2008 from Talisman, the Company issued a Cdn$40.0 million Convertible Note. The Canadian dollar denominated debt was considered to contain an embedded derivative since the functional currency of the Company is the US dollar. As a result, the Convertible Note was bifurcated into debt and the equity conversion option, which was recognized at fair value using the Black-Scholes valuation method. Changes in the fair value of the equity conversion option were recorded in earnings, and as a result, the valuation of the equity conversion option was a critical accounting estimate prior to the maturity of the Convertible Note on July 11, 2011.

Deferred Income Taxes
 
Ivanhoe operates in a specialized industry and in several tax jurisdictions. As a result, the Company’s 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 that the Company will ultimately pay. The final taxes paid are dependent upon many factors, including negotiations with taxation authorities in various jurisdictions, uncertain tax positions and resolution of disputes arising from federal, provincial, state and local tax audits.

The deferred income tax liability is a critical accounting estimate because it requires Ivanhoe to make assumptions about the resolution of these uncertainties and the associated final taxes may result in adjustments to the Company’s tax assets and tax liabilities.
 
NEW ACCOUNTING PRONOUNCEMENTS
 
New Accounting Pronouncements
 
The Company has reviewed new and revised accounting pronouncements listed below, that have been issued, but are not yet effective. There are no other standards or interpretations issued, but not yet adopted, that are anticipated to have a material effect on the reported loss or net assets of the Company.

IFRS 9 Financial Instruments (“IFRS 9”)

The first phase of IFRS 9 was issued in November 2009 and is intended to replace IAS 39, “Financial Instruments: Recognition and Measurement” (“IAS 39”). IFRS 9 uses a single approach to determine whether a financial asset is measured at amortized cost or fair value, as opposed to the multiple rules in IAS 39. The approach is based on how an entity manages its financial instruments given its business model and the contractual cash flow characteristics of the financial assets. The standard also requires a single impairment method to be used, replacing the multiple impairment methods in IAS 39. IFRS 9 is effective for reporting periods beginning on or after January 1, 2015. The full impact of this standard will not be known until the phases addressing hedging and impairments have been completed.



IFRS 10 Consolidated Financial Statements (“IFRS 10”)

IFRS 10 was issued in May 2011 and sets a single basis for consolidation, that being control of an entity. IFRS 10 replaces portions of IAS 27, “Consolidated and Separate Financial Statements” and Standing Interpretations Committee 12, “Special Purpose Entities” that provide a single model on how entities should prepare consolidated financial statements. This standard is effective for reporting periods on or after January 1, 2013, with earlier adoption permitted. The Company does not anticipate any changes to the consolidated financial statements as a result of this standard.

IFRS 11 Joint Arrangements (“IFRS 11”)

IFRS 11, issued in May 2011, establishes principles for financial reporting by entities involved in a joint arrangement and distinguishes between joint operations and joint ventures. IFRS 11 supersedes the current IAS 31, “Interests in Joint Ventures” and Standing Interpretations Committee 13, “Jointly Controlled Entities-Non Monetary Contributions by Venturers” and is effective for reporting periods beginning on or after January 1, 2013, with earlier adoption permitted. The Company does not anticipate any changes to the consolidated financial statements as a result of this standard.

IFRS 12 Disclosure of Interests in Other Entities (“IFRS 12”)

IFRS 12, issued in May 2011, establishes a single set of disclosure objectives, and requires minimum disclosures designed to meet those objectives, regarding interests in subsidiaries, joint arrangements, associates or unconsolidated structured entities. IFRS 12 is intended to combine the disclosure requirements on interests in other entities currently located throughout different standards. This standard is effective for reporting periods on or after January 1, 2013, with earlier adoption permitted. The Company does not anticipate significant changes to its disclosure of interests in other entities as a result of this standard.

IFRS 13 Fair Value Measurements (“IFRS 13”)

IFRS 13, issued in May 2011, defines fair value, sets out a single IFRS framework for measuring fair value and requires disclosures about fair value measurements. IFRS 13 applies to IFRS that require or permit fair value measurements or related disclosures, except in specified circumstances. IFRS 13 is to be applied for reporting periods beginning on or after January 1, 2013, with earlier adoption permitted. The Company does not anticipate significant changes to its fair value measurements and related disclosures as a result of this standard.

IAS 28 Investments in Associates and Joint Ventures (“IAS 28”)

IAS 28 was amended in 2011 and prescribes the accounting for investments in associates and sets out the requirements for the application of the equity method when accounting for investments in associates and joint ventures. IAS 28 is effective for reporting periods beginning on or after January 1, 2013, with earlier adoption permitted. The Company does not anticipate any changes to the consolidated financial statements as a result of this standard. 

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 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.

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 capital spending in Ecuador and ongoing FTF operations. Some of the Canada exploration activities are funded in Canadian dollars and the Convertible Debentures were issued in Canadian dollars in 2011. The Company did not enter into any foreign currency derivatives in 2012, nor do we anticipate using foreign currency derivatives in 2013. 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 for 2012, assuming reasonably possible changes in the relevant foreign currency. This analysis assumes all other variables remain constant.

(Increase) Decrease in Net Loss and Comprehensive Loss
 
10% Increase
or Weakening
   
10% Decrease
or Strengthening
 
Canadian dollar
    1,287       (1,444)  

CREDIT RISK
 
Ivanhoe is exposed to credit risk with respect to its cash and cash equivalents, restricted cash, accounts receivable, note receivable and long term receivables. The Company’s maximum exposure to credit risk at December 31, 2012 is represented by the carrying amount of these non-derivative financial assets.

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.

Long term value-added tax receivable from the Ecuadorian government will be recoverable upon commencement of commercial operations. Ivanhoe considers the risk of default on this to be low due to the Company’s ongoing operations in Ecuador.

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 the 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 or obtain it on favorable terms.
 
 
ITEM 8:  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 
35
Consolidated Financial Statements
 
36
37
38
39
40
66


 

 
 
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 (the “Company”), which comprise the consolidated statements of financial position as at December 31, 2012 and December 31, 2011, and the consolidated statements of loss and comprehensive loss, statements of changes in equity and statements of cash flows for each of the years in the three-year period ended December 31, 2012, and a summary of significant accounting policies and other explanatory information.

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 International Financial Reporting Standards as issued by the International Accounting Standards Board, 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 the Company as at December 31, 2012 and 2011 and their financial performance and cash flows for each of the years in the three-year period ended December 31, 2012, in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board.

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, 2012, 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 18, 2013 expressed an unqualified opinion on the Company’s internal control over financial reporting.

 
/s/ Deloitte LLP
Independent Registered Chartered Accountants
 
March 18, 2013
Calgary, Canada

 
PART I   FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

IVANHOE ENERGY INC.
Consolidated Statements of Financial Position

         
December 31,
   
December 31,
 
(US$000s)
 
Note
   
2012
   
2011
 
                   
Assets
                 
Current Assets
                 
Cash and cash equivalents
    5       62,819       16,890  
Restricted cash
    6, 25       20,500       20,500  
Accounts receivable
    7,11       14,848       7,859  
Note receivable
            230       227  
Prepaid and other
            1,593       1,411  
Assets held for sale
    7             41,902  
 
            99,990       88,789  
                         
Intangible assets
    8       285,311       273,986  
Property, plant and equipment
    9       10,205       46,979  
Long term receivables
    11       6,551       3,956  
 
            402,057       413,710  
                         
Liabilities and Shareholders’ Equity
                       
Current Liabilities
                       
Accounts payable and accrued liabilities
    22       14,436       15,548  
Derivative instruments
    11             183  
Income taxes
    7,14       1,720       641  
 
            16,156       16,372  
                         
Long term debt
    10       65,214       61,892  
Long term derivative instruments
    11, 12       181       1,617  
Long term provisions
    13       3,157       1,919  
Deferred income taxes
    14       14,351       17,773  
              99,059       99,573  
                         
Shareholders’ Equity
                       
Share capital
    16       586,108       586,108  
Contributed surplus
    16       29,759       26,524  
Accumulated deficit
            (312,869 )     (298,495 )
              302,998       314,137  
              402,057       413,710  
                         
Nature of operations and going concern
    1                  
 
(See accompanying Notes to the Consolidated Financial Statements)




IVANHOE ENERGY INC.
Consolidated Statements of Loss and Comprehensive Loss

         
Year Ended December 31,
 
(US$000s, except share and per share amounts)
 
Note
   
2012
   
2011
   
2010
 
                         
Interest income
          28       572       202  
                               
Expenses and other
                             
Operating
          4,252       4,561       4,086  
General and administrative
          31,149       38,579       36,153  
Exploration and evaluation
    8       22,994       2,774       4,934  
Depreciation
    9       961       1,014       259  
Foreign currency exchange loss (gain)
            1,247       (534 )     (3,269 )
Derivative instruments gain
    11       (1,430 )     (13,148 )     (18,571 )
Finance
    10       4,328       361       24  
Gain on derecognition of long term provision
    13             (1,900 )      
Loss on debt repayment
            2,977              
 
            66,478       31,707       23,616  
                                 
Net loss before income taxes
            (66,450 )     (31,135 )     (23,414 )
                                 
(Provision for) recovery of income taxes
                               
   Current
    14             (7 )     (15 )
   Deferred
    14       2,432       4,381       1,171  
              2,432       4,374       1,156  
                                 
Net loss and total comprehensive loss from continuing operations
            (64,018 )     (26,761 )     (22,258 )
Net income (loss) and total comprehensive income (loss) from discontinued operations
    7       49,644       1,485       (4,324 )
Net loss and total comprehensive loss
            (14,374 )     (25,276 )     (26,582 )
                                 
Net (loss) income per common share, basic and diluted
                               
From continuing operations
            (0.19 )     (0.08 )     (0.07 )
From discontinued operations
            0.14       0.01       (0.01 )
From net loss
            (0.05 )     (0.07 )     (0.08 )
                                 
Weighted average number of common shares
                               
Basic and diluted (000s)
            344,139       342,678       327,442  
 
(See accompanying Notes to the Consolidated Financial Statements)



IVANHOE ENERGY INC.
Consolidated Statements of Changes in Equity

 
       
Share Capital
                   
         
Shares
         
Contributed
   
Accumulated
       
(US$000s, except share amounts)
 
Note
      (000s)    
Amount
   
Surplus
   
Deficit
   
Total
 
                                       
Balance January 1, 2010
          282,559       422,322       18,724       (246,637 )     194,409  
Net loss and comprehensive loss
                            (26,582 )     (26,582 )
Shares issued for cash, net of share issue costs
    16       50,000       121,697                   121,697  
Shares issued for services
            280       799                   799  
Exercise of stock options
    17       1,524       5,735       (3,940 )           1,795  
Exercise of purchase warrants
            2       9                   9  
Share-based compensation expense
    17                   8,357             8,357  
Balance December 31, 2010
            334,365       550,562       23,141       (273,219 )     300,484  
 
                                               
                                                 
 
         
Share Capital
                         
           
Shares
           
Contributed
   
Accumulated
         
(US$000s, except share amounts)
 
Note
      (000s)    
Amount
   
Surplus
   
Deficit
   
Total
 
                                                 
Balance December 31, 2010
            334,365       550,562       23,141       (273,219 )     300,484  
Net loss and comprehensive loss
                              (25,276 )     (25,276 )
Shares issued for services
            169       335                   335  
Exercise of stock options
    17       985       4,164       (2,231 )           1,933  
Exercise of purchase warrants
    16       8,620       31,047                   31,047  
Share-based compensation expense
    17                   5,614             5,614  
Balance December 31, 2011
            344,139       586,108       26,524       (298,495 )     314,137  
 
                                               
                                                 
 
         
Share Capital
                         
           
Shares
           
Contributed
   
Accumulated
         
(US$000s, except share amounts)
 
Note
      (000s)    
Amount
   
Surplus
   
Deficit
   
Total
 
                                                 
Balance December 31, 2011
            344,139       586,108       26,524       (298,495 )     314,137  
Net loss and comprehensive loss
                              (14,374 )     (14,374 )
Funding of equity-settled share-based awards
                        (54 )           (54 )
Share-based compensation expense
    17                   3,289             3,289  
Balance December 31, 2012
            344,139       586,108       29,759       (312,869 )     302,998  
 
(See accompanying Notes to the Consolidated Financial Statements)



IVANHOE ENERGY INC.
Consolidated Statements of Cash Flows

         
Year Ended December 31,
 
(US$000s)
 
Note
   
2012
   
2011
   
2010
 
                         
Operating Activities
                       
Net loss
          (14,374 )     (25,276 )     (26,582 )
Adjustments to reconcile net loss to cash from operating activities
                             
Depletion and depreciation
    9       7,642       8,030       6,524  
Exploration and evaluation expense
    8       22,994             3,537  
Share-based compensation expense
    17       3,502       5,883       7,557  
Unrealized foreign currency exchange loss (gain)
            800       (446 )     (3,523 )
Unrealized derivative instruments gain
    11       (1,613 )     (12,965 )     (18,571 )
Current income tax expense
    7,14       1,720       2,122       126  
Deferred income tax recovery
            (3,422 )     (3,392 )     (1,171 )
Finance expense
            4,328       361       24  
Financing costs
                  269        
Derecognition of long term provision
    13             (1,900 )      
Pre-tax gain on disposal of discontinued operations
    7       (57,007 )            
Loss on debt repayment
            2,977              
Other
            39       50       (38 )
Current income tax paid
            (641 )     (1,481 )     (656 )
Interest paid
            (3,428 )     (333 )      
Share-based payments
            (166 )            
Decommissioning costs settled
                        (179 )
Changes in non-cash working capital items
    21       9,589       2,833       1,662  
Net cash used in operating activities
            (27,060 )     (26,245 )     (31,290 )
                                 
Investing Activities
                               
Intangible expenditures
            (40,112 )     (37,390 )     (65,347 )
Property, plant and equipment expenditures
            (7,332 )     (13,670 )     (5,633 )
Proceeds  on disposal of discontinued operations
    7       131,755              
Restricted cash
                  (20,500 )      
Long term receivables
            (2,606 )     (1,536 )     (1,558 )
Interest paid
            (5,693 )     (4,011 )     (1,610 )
Changes in non-cash working capital items
    21       1,650       (8,315 )     5,464  
Net cash provided by (used in) investing activities
            77,662       (85,422 )     (68,684 )
                                 
Financing Activities
                               
Shares and warrants issued on private placements, net of share issue costs
    16                   135,696  
Debt proceeds, net of transaction costs
            64,644       72,914        
Repayment of debt
            (70,000 )     (41,421 )      
Proceeds from exercise of options and warrants
                  29,873       2,600  
Changes in non-cash working capital items
    21       (32 )     57       (10 )
Net cash (used in) provided by financing activities
            (5,388 )     61,423       138,286  
                                 
Foreign exchange gain (loss) on cash and cash equivalents held in a foreign currency
      715       (1,183 )     5,643  
Increase (decrease) in cash and cash equivalents, for the year
            45,929       (51,427 )     43,955  
Cash and cash equivalents, beginning of year
            16,890       68,317       24,362  
Cash and cash equivalents, end of year
            62,819       16,890       68,317  
 
(See accompanying Notes to the Consolidated Financial Statements)



IVANHOE ENERGY INC.
Notes to the Consolidated Financial Statements
(tabular amounts in US$000s, except share and per share amounts)

1. NATURE OF OPERATIONS
 
Ivanhoe Energy Inc. (the “Company” or “Ivanhoe”) is a publicly listed limited liability company incorporated under the laws of Yukon, Canada. Ivanhoe’s common shares are listed on the Toronto Stock Exchange (“TSX”) and the NASDAQ Stock Market (“NASDAQ”). The principal corporate office of Ivanhoe is located at 999 Canada Place, Suite 654, Vancouver, British Columbia, V6C 3E1. Our registered and records office is located at 300-204 Black Street, Whitehorse, Yukon, Y1A 2M9 and our operational headquarters are located at 101-6th Avenue SW, 21st Floor, Calgary, Alberta, T2P 3P4.

Ivanhoe 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, such as its HTL™ technology, that are designed to improve recovery of heavy oil resources. In addition, the Company seeks to expand its reserve base and production through conventional exploration and production of oil and gas.

The December 31, 2012 consolidated financial statements (“Financial Statements”) have been prepared using International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”).

The December 31, 2012 Financial Statements were approved by the Board of Directors and authorized for issue on March 1, 2013.

The Financial Statements are presented in US dollars and all values are rounded to the nearest thousand dollars except where otherwise indicated.

2. BASIS OF PRESENTATION
 
2.1 Statement of Compliance
 
The Financial Statements have been prepared in accordance with IFRS as issued by the IASB. The Financial Statements are not subject to qualification relating to the application of IFRS as issued by the IASB.

2.2 Basis of Presentation
 
The Financial Statements have been prepared on an historical cost basis, except derivative instruments, which are measured at fair value as explained in accounting policies set out in Note 3.

3. SIGNIFICANT ACCOUNTING POLICIES
 
3.1 Basis of Consolidation
 
The Financial Statements incorporate the financial statements of the Company, its subsidiaries, all of which are wholly owned, and special purpose entities that are controlled by the Company. All intercompany balances, transactions, revenue and expenses are eliminated on consolidation. The consolidated accounts are prepared using uniform accounting policies.

3.2 Foreign Currency Translation
 
The Company and its subsidiaries’ reporting currency and the functional currency of its operations is the US dollar as this is the principal currency of the economic environments in which they operate.

Monetary assets and liabilities denominated in foreign currencies are translated at the exchange rate in effect on the date of the statement of financial position. Non-monetary assets and liabilities, as well as operating transactions, are translated at the exchange rate prevailing at the time of the transaction. Translation gains and losses are reflected in earnings.



3.3 Cash and Cash Equivalents
 
Cash and cash equivalents includes cash on hand, deposits at banks, restricted cash and short term highly liquid investments with original maturities of three months or less.

3.4 Restricted Cash
 
Restricted cash balances that are not expected to be released within three months or less are reported separately from restricted cash balances included in cash and cash equivalents.

3.5 Intangible Assets
 
i. Exploration and Evaluation Assets
 
Costs of exploring for, and evaluating, oil and gas properties are initially capitalized as intangible exploration and evaluation assets (“E&E assets”). Costs may include license fees, technical studies, seismic programs, exploratory drilling and directly attributable general and administrative costs. Interest on borrowings incurred to finance qualifying E&E assets is capitalized.

If E&E assets result in sufficient proved reserves to justify commercial production and technical feasibility can be established, the assets will be tested for impairment and reclassified as property, plant and equipment (“PP&E”). If E&E assets result in sufficient reserves to justify commercial production, but those reserves cannot be classified as proved, the assets will be tested for impairment and continue to be capitalized as intangible assets as long as progress is being made to assess the reserves and economic viability of the well and/or related project. If sufficient reserves cannot be established, the corresponding E&E assets are charged to exploration and evaluation expense (“E&E expense”).

E&E assets which may be attributable to a broad exploration area, such as license fees, technical studies or seismic programs, will be reclassified to PP&E or charged to E&E expense to best reflect the nature of the assets. Costs incurred prior to establishing the legal right to explore an area are charged to E&E expense as incurred.

ii. Technology Assets
 
The Company’s HTL™ technology license (“Technology Assets”) consist of an exclusive, irrevocable license to deploy its HTL™ technology. Technology Assets are measured at cost and classified as an intangible asset. Amortization of the Technology Assets will commence when the technology is available for use in field operations.

iii. Derecognition
 
An intangible asset is derecognized on disposal or when no future economic benefits are expected from use or disposal. Gains or losses arising from derecognition are measured as the difference between the net disposal proceeds and the carrying amount of the asset and are recognized in profit or loss when the intangible asset is derecognized.

3.6 Property, Plant and Equipment
 
i. Oil and Gas Property and Equipment
 
PP&E is reported at cost less accumulated depletion, depreciation and accumulated impairment losses. PP&E may include the purchase price, reclassified E&E assets, any costs directly attributable to bringing the asset to the location and condition necessary for its intended use and decommissioning costs. Interest on borrowings incurred to finance qualifying PP&E is capitalized until the asset is capable of fulfilling its intended use.

PP&E is depleted using the unit-of-production method based on proved plus probable reserves, taking into account associated future development costs. For purposes of these calculations, production and reserves of natural gas are converted to barrels on an energy equivalent basis at a ratio of six thousand cubic feet of natural gas for one barrel of oil. Depletion rates are updated annually unless there is a material change in circumstances, in which case they would be updated more frequently.

ii. Other Assets
 
Furniture and equipment are depreciated on a straight-line basis over the estimated useful life of the respective assets, ranging from three to five years. The Feedstock Test Facility (“FTF”) is depreciated over its expected economic life of 20 years.
 
 

3.7 Assets Held for Sale and Discontinued Operations
 
Non-current assets are classified as held for sale if their carrying amounts will be recovered through a sale transaction rather than through continuing use. This classification is required when the sale is highly probable and the asset is available for immediate sale in its present condition. For the sale to be highly probable, management must be committed to a plan to sell the asset, the asset must be actively marketed for sale at a price that is reasonable in relation to its fair value and the sale is expected to be completed within one year.

Non-current assets classified as held for sale are measured at the lower of the carrying amount and fair value less costs to sell, with impairments recognized in the consolidated statement of loss in the period measured. Non-current assets held for sale are presented in current assets within the consolidated statement of financial position. Assets held for sale are not depleted, depreciated or amortized.

Unless otherwise indicated, information presented in the notes to the financial statements relates only to the Company’s continuing operations. Information related to discontinued operations is included in Note 7 and in some instances, where appropriate, is included as a separate disclosure within the individual footnotes.

3.8 Impairment
 
The Company periodically assesses tangible and intangible assets or groups of assets for impairment annually or earlier whenever events or changes in circumstances indicate the carrying value of an asset may not be recoverable. Individual assets are grouped into cash generating units for impairment purposes at the lowest level at which there are identifiable cash inflows that are largely independent of the cash inflows of other groups of assets.

If indicators of impairment exist, the recoverable amount of the asset group is estimated. An asset group’s recoverable amount is the higher of its fair value less costs to sell and its value in use. In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and risks specific to the asset. Where the carrying amount of an asset group exceeds its recoverable amount, the asset group is considered impaired and is written down to its recoverable amount.

Previously recognized impairment losses are reversed if there has been a change in the estimates used to determine the asset group’s recoverable amount. If that is the case, the carrying amount of the asset group is increased to its revised rec