eh1400448_10k-2013.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, 2013
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, 2013, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $82,643,930 based on the Toronto Stock Exchange closing price on that date. At March 7, 2014, the registrant had 114,824,253 common shares outstanding.
 
 


 
 
 

 

TABLE OF CONTENTS
 
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80
96
98
99
100
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$)
2013
 
2012
 
2011
Closing
0.94
 
1.01
 
0.98
High
1.02
 
1.03
 
1.06
Low
0.93
 
0.96
 
0.94
Average noon
0.97
 
1.00
 
1.01
 
On March 7, 2014, the noon-day exchange rate was US$0.92 for Cdn$1.00.
 
 
 
2

 

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”, “seek”, “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 may be 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.
 
 
 
3


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 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.

Key advances in technology for non-conventional heavy oil and bitumen, 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; 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.
 
 
 
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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 an analogue of the fluid catalytic cracking process, a tried and tested concept in oil processing. The key advantage of HTL® is the short cracking residence time of a few seconds. This results in smaller, less costly facilities and eliminates the need for hydrogen in hydrotreating units, 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.
 
Project economics can be enhanced with the addition of HTL®. HTL®’s value proposition is greatest the more isolated the resource and where the resource owner has the fewest monetization alternatives.

Implementation Strategy
 
Ivanhoe is an oil and gas company with a patented 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.
 
 
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 18 to the consolidated financial statements in Item 8 and in the MD&A in Item 7 of 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
 
 
 
5

 
thermal recovery (“SAGD”) and HTL® facility. Our independent reserve evaluator, GLJ Petroleum Consultants Ltd. (“GLJ”), has assigned net probable reserves after royalties of 136 mmbbls of bitumen to Tamarack.

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. On January 21, 2013, 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. In August 2013, the Company enhanced its application by submitting an addendum. The addendum included results acquired in the first quarter of 2013 from the testing and coring of three additional wells and 3D seismic data from a portion of the project's area. 

In December 2013, the Company learned that the Alberta Energy Regulator (“AER”) intends to conduct a thorough technical review of the factors that affect reservoir containment of shallow SAGD projects and will be consulting with stakeholders to develop formal regulatory requirements. Following discussions with each affected industry applicant, the AER issued a bulletin with interim guidelines. The AER now indicates that they will develop the new requirements following extensive industry and stakeholder engagement. This decision and process affects all shallow SAGD projects, including Ivanhoe's Tamarack Project.

Ivanhoe met with the AER in December 2013 and was advised that, per the interim guidelines, the Tamarack application would not continue to be processed until (a) 3D seismic has been collected and interpreted over the entire initial development area and (b) the maximum operating pressure meets the interim guidelines.

The Company then prepared to launch a seismic program over the remaining portion of the initial development area for which seismic had not been shot, and continued to discuss with the AER the validity of the Company’s methodology for its proposed maximum operating pressure.  The Company was given an indication that the AER might consider assessing and ruling on the validity of its methodology, but in a letter dated February 6, 2014 and received by the Company on February 24, 2014, the AER said that it would not do so.  At that point the Company cancelled the costly seismic program for this winter.

The Company is continuing its discussions with the AER and is exploring its alternatives for moving the Tamarack Project forward. In addition, the Company continues its discussions with local stakeholders to address any statements of concern as part of the regulatory process.  Ivanhoe continues to believe that its proposed development plan for Tamarack is safe and economically viable and expects the project will be approved. However, until the new formal regulatory requirements are known, Ivanhoe cannot determine whether the Tamarack Project, as currently proposed, will ultimately fit within those requirements.
 
The Company has suspended activity, including capital investment, on its current Tamarack oil sands project application, except for essential items, pending clarity from the AER on the final regulatory requirements for shallow SAGD projects and/or any continuing discussions the Company might have with the AER.
 
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 fluctuates based on three published producer price indices and, in the Company’s opinion, tracks West Texas Intermediate benchmark 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 at its test facility in San Antonio.  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.
 
 
 
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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.

During 2013, the Company drilled well IP-14b to a total depth of 1,150 feet and encountered hydrocarbons in the Hollin formation.  On December 31, 2013, the first phase of the Specific Services Contract between Ivanhoe and the Ecuadorian Government, representing the evaluation phase, ended.  The next steps in the contract would be the pilot and exploitation phases. However during 2013, the Company has been engaged in discussions with a large international oil company regarding the concept 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 which has been used in separate discussions with the Government of Ecuador. The ultimate objective of these discussions with the Ecuadorian Government has been the establishment of mutually acceptable terms and conditions allowing for the formation of a consortium between the Company and the third party to jointly develop 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. Although Ivanhoe remains optimistic, there is no assurance that this objective will be achieved or achieved in a timely manner. The outcome of these discussions is likely to have a significant impact on the Company’s continuing participation in the Block 20 project.

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 currently covers an area of approximately 9,239 square kilometers. 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 elect 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.

In early 2013, the Company completed the acquisition of a 106 kilometer 2-D seismic program and completed processing of the results. This new seismic data has been incorporated with the recent drilling results by independent consultants and an up-to-date prospects report has been finalized as of the third quarter of 2013. The report has recommended potential for three drill sites to be evaluated based on this review result.

The five year initial term of the exploration license was to expire July 19, 2013. The Company applied for, and was granted a two year extension to the PSC after meeting the minimum expenditure requirement, extending the term to July 19, 2015 providing additional time to find a partner or buyer.

The PSC permits an additional two year extension from July 2015.
 
 
 
7


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, 2013.

Summary of Oil and Gas Reserves Using Average 2013 Prices

   
Canada
 
   
Bitumen
 
(mbbl)
 
Tamarack
 
Probable
     
Developed
     
Undeveloped
    141,477  
Possible
       
Developed
     
Undeveloped
    31,465  

Canada
 
Probable and Possible Reserves
 
No additional reserves were assigned to Tamarack in 2013 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. See Internal Control over Reserve Estimation for a distinction between possible reserves and probable reserves.

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 U.S. Securities and Exchange Commission (“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 Canadian Securities Administrators  (“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 10.

The process of estimating reserves requires complex judgments and decision making based on available geological, geophysical, engineering and economic data. To estimate the economically recoverable oil and gas reserves and related future net cash flows, we consider many factors and make various assumptions including, but not limited to:

 
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.
 
 
 
8


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 government regulations, 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 23 years of broad industry experience with the past 14 years focusing on petroleum engineering in the oil and gas industry in Canada. His past experience includes development, planning and managing subsurface engineering for oil projects in Canada, forecasting and optimizing production, and evaluating new recovery processes.

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 2013, 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
 
 
 
9

 
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
 
   
2013
   
2012(1)
   
2011
 
Oil production (bbls/d)
          850       967  
Average sales price ($/bbl)
          114.28       105.93  
Average operating cost (2) ($/bbl)
          42.90       44.10  
 
 
(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. No oil production occurred in 2013 as a result of the sale of all producing assets in 2012.

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. Ivanhoe filed the Tamarack Project application in 2010 and the application has been under regulatory review since that time. Recent regulatory changes will require Ivanhoe to submit additional technical data and information in order for process of the application to continue. In addition, there are pending regulatory changes which have yet to be finalized which could materially affect the project as current envisaged

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 Ecuadorian Government and in conformity with local laws. On December 31, 2013, the first phase of the Specific Services Contract between Ivanhoe and the Ecuadorian Government, representing the evaluation phase, ended.  The next steps in the contract would be the pilot and exploitation phases. However, as discussed above, during 2013, Ivanhoe and a large international oil company were engaged in discussions to create a consortium to jointly develop Block 20 beginning in 2014. Ivanhoe is also engaged in separate discussions with the Ecuadorian Government respecting the consortium proposal. The outcome of these discussions is likely to have a significant impact on the Company’s continuing participation in the Block 20 project.
 
 
 
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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
                   
2013(2)
 
 
 
2012(2)
 
1.0
1.0
 
1.0
1.0
 
2.0
2011
 
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 and December 31, 2013 we were not actively drilling wells.

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 13 US patent applications pending. In other countries, the Company has 57 patents granted and 32 pending patents. 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 2032.

Global demand for crude oil and liquid fuels is expected to continue to create an opportunity for additional exploitation of heavy oil resources.  Many heavy oil resources exist in the form of stranded assets which tend to be geographically remote or difficult to access.  In these remote locations, industrial infrastructure may be immature and the availability of construction resources is constrained.  In addition, production techniques continue to become ever more complex.  As a result, the development of heavy oil remains economically challenged and deployment of conventional solutions to solve these challenges can be impractical.  However, because of the global abundance of heavy oil deposits, we believe heavy oil is expected to remain an important global hydrocarbon resource.  An economic means of extraction is therefore needed to address the challenges of heavy oil development.

Ivanhoe Energy’s HTL® process is intended to provide an alternative to the traditional approach to the transportation of heavy crude oil.  HTL® aims to convert heavy, viscous crude oil into lighter, stable, more valuable and easily transportable products. The essence of the process undertakes rapid thermal conversion of heavy oil into high value Synthetic Crude Oil (“SCO”).

HTL® should position the heavy oil producer to capture the majority of the market value differential between heavy and light oil and eliminate the need for adding diluent to enable transportation.  In addition, by-products from HTL® can be used to produce significant amounts of energy for utilization on-site.  Traditionally, heavy crude is diluted with light oil such that it can be transported from the well to the refinery.  HTL® offers a new process where partial upgrading can be deployed close to the well, resulting in a much lighter, lower viscosity and stable product that can be transported to the refinery without diluent.

HTL® plants can be economically constructed at smaller scales than conventional upgrading processes and operate at a fraction of the per-barrel cost.  Reduced complexity as well as a smaller footprint make it possible for HTL® plants to operate in remote locations not possible with conventional technologies.  By integrating HTL® onto an FPUSO (Floating, Production, Upgrading, Storage, and Offloading) vessel, it becomes possible to develop stranded offshore heavy oil fields.

Ivanhoe has modularized the HTL® design, further widening the gap between the cost of HTL® and that of conventional upgrading facilities.  The modules are fabricated off-site and transported via barge, rail or road to the construction site.

When processing heavy crude oils with an 8° to 16° API gravity, HTL® produces a synthetic crude oil of 16° to 24° 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.
 
 
 
 
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The Kline Group, consultants to the energy and chemical industries, completed an evaluation in 2013 which compares HTL® to more than 10 other upgrading technologies under development today.  In this comparison, The Kline Group concluded that HTL® is the leading partial upgrading technology based on five significant advantages:
 
 
it is a novel carbon rejection process that is best suited for application in the field;
 
 
it produces high yields of valuable, transportable SCO;
 
 
it is in an advanced stage of developmet;
 
 
it requires lower capital costs; and,
 
 
it requires lower operating costs.
 
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. 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. See Part I, Item 1A “Risk Factors - We may not successfully commercialize our HTL® technology.

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 facilitates 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 HTL® plants. In 2013, Ivanhoe processed heavy crude for Ecopetrol in the FTF and produced commercially attractive yields and product properties.

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.
 
 
 
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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 2010. The AER is a new regulatory authority responsible for our project application. In January 2014, the AER announced that it is reviewing its standards for approving all shallow SAGD projects, including ours.  While the process for establishing the new standards continues, the processing of our application has been suspended.  Part of the approval process will require the disposition of two Statements of Concerns, one filed by Suncor Energy Inc. and another by the Athabasca Chipewyan First Nation. 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, 2013, we had 75 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, 19th  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.


 
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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 4.

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.
 
 
 
14


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. For example, AER’s recent announcement that it is reviewing its standards for approving all shallow SAGD projects is likely to result in delays in the process of developing our Tamarack Project. 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. In the case of our Tamarack Project, until AER’s new regulatory requirements are known, we cannot determine whether the Tamarack Project, as currently proposed, will ultimately meet those requirements. If it does not, there can be no assurance that the project can be developed and operated in a manner that is both economically viable and compliant with regulatory requirements. 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.
 
 
 
15


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.
 
 
 
16



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. The AER is reviewing its approval standards for SAGD project applications and the outcome is uncertain.

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 might not become aware of claims of infringement of the patents or other rights of others in deploying the HTL® technology until after we have made a substantial investment in the development and commercialization of HTL® projects. Third parties may claim that our HTL® designs and operations infringe their patents. Legal actions could be brought against us claiming damages and seeking injunctions that would prevent us from testing or commercializing our technology. If an infringement action were successful, in addition to potential liability for damages, we could be required to obtain and pay for a claiming party’s license or be enjoined from using the HTL® technology.  We might have to expend substantial resources in litigation defending any such infringement claims. Some possible claimants may have significantly more resources to spend on litigation than we do.

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. The approval of our Tamarack Project has been suspended pending review by the AER of standards for approval of all shallow SAGD projects. Although we believe that we will successfully complete the regulatory approval process, 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
 
 
 
17

 
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.

We have been engaged in discussion with a large international oil company regarding 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 which has been used in separate discussions with the Government of Ecuador. The ultimate objective of discussions with the Government of Ecuador has been the establishment of mutually acceptable terms and conditions allowing for the formation of a consortium between the Company and the third party to jointly develop Block 20. The
 
 
 
18

 
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. The outcome of these discussions is likely to have a significant impact on the Company’s continuing participation in the Block 20 project.

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, Robert M. Friedland, a director and our Executive Co-Chairman, was our largest shareholder, owning approximately 17% of our common shares. As a result, he has the voting power to significantly influence our policies, business and affairs and the outcome of any corporate transaction or other matter, including mergers, consolidations and the sale of all, or substantially all, of our assets. In addition, the concentration of our ownership may have the effect of delaying, deterring or preventing a change in control that otherwise could result in a premium in the price of our common shares.

If we lose our key management and technical personnel, our business may suffer
 
We rely upon a relatively small group of key management personnel. 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 or that it should be disposed of. This information may also cause us to acquire or initiate new projects. Our plans regarding our projects might change.

We may be unable to maintain the listing of our common shares on NASDAQ despite the reverse stock-split
 
In September, 2013, the Company received a notification from the Listing Qualification 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 and that the Company could regain compliance if at any time prior to March 5, 2014 the closing bid price of the Company’s common shares was at least $1.00 for a minimum of 10 consecutive business days.  On February 18, 2014, the Company applied to the NASDAQ for an additional compliance period of 180 days, which was granted. If the Company does not otherwise regain compliance with the minimum bid price requirements in a timely manner, the Company may need to take other action, including seeking the approval of its shareholders to effect a reverse split of its common shares to maintain its NASDAQ listing, as it did in 2013 in order to remedy a previous minimum bid price deficiency, or seeking inclusion in a different U.S. marketplace or trading system.

Reducing the number of issued and outstanding common shares through a reverse split is intended to increase the per share market price of the common shares and thereby cure the minimum bid price deficiency. However, the per share 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
 
 
 
19

 
perception of the Company’s business and other factors, which are unrelated to the number of common shares outstanding. There is a risk that, despite a reverse split or any other action taken by the Company, the common shares will be delisted from the NASDAQ.
 
A cyber incident could result in information theft, data corruption, operational disruption, and/or financial loss.
 
Businesses have become increasingly dependent on digital technologies to conduct day-to-day operations. At the same time, cyber incidents, including deliberate attacks or unintentional events, have increased. A cyber-attack could include gaining unauthorized access to digital systems for purposes of misappropriating assets or sensitive information, corrupting data, or causing operational disruption, or result in denial of service on websites.

The oil and gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production, and upgrading activities. For example, software programs are used to interpret seismic data, manage drilling rigs, production equipment and gathering and transportation systems, conduct reservoir modeling and reserves estimation, for compliance reporting, and for upgrading process data modelling. The use of mobile communication devices has also increased rapidly. The complexity of the technologies needed to extract oil in increasingly remote physical environments without adequate infrastructure and global competition for oil and gas resources make certain information more attractive to thieves.

We depend on digital technology, including information systems and related infrastructure, to process and record financial and operating data, communicate with our employees and business partners, analyze seismic and drilling information, estimate quantities of oil reserves, and for many other activities related to our business. Our business partners, including vendors, service providers, and financial institutions, are also dependent on digital technology.

Our technologies, systems and networks, and those of our business partners may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period.

A cyber incident involving our information systems and related infrastructure, or that of our business partners, could disrupt our business plans and negatively impact our operations in the following ways, among others:
 
 
unauthorized access to seismic data, reserves information or other sensitive or proprietary information could have a negative impact on our competitive position in developing our oil resources;
 
 
data corruption, communication interruption, or other operational disruption during drilling activities could result in a dry hole cost or even drilling incidents;
 
 
data corruption or operational disruption of production infrastructure could result in loss of production or accidental discharge;
 
 
a cyber-attack on a vendor or service provider could result in supply chain disruptions which could delay or halt one of our major projects, effectively delaying the start of cash flows from the project;
 
 
a cyber-attack involving commodities exchanges or financial institutions could slow or halt commodities trading, thus preventing us from marketing our production or engaging in hedging activities, resulting in a loss of revenues;
 
 
a cyber-attack on a communications network or power grid could cause operational disruption resulting in loss of revenues and increased expenses;
 
 
a deliberate corruption of our financial or operational data could result in events of non-compliance which could lead to regulatory fines or penalties; and
 
 
significant business interruptions could result in expensive remediation efforts, distraction of management, damage to our reputation, or a negative impact on the price of our common stock.
 
Although to date we have not experienced any material losses relating to cyber incidents, there can be no assurance that we will not suffer such losses in the future. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities.

ITEM 1B:  UNRESOLVED STAFF COMMENTS
 
None.
 

 
 
20

 
ITEM 3:  LEGAL PROCEEDINGS
 
Cotundo Minerales S.A.
 
On August 9, 2013, Cotundo Minerales S.A. (“Cotundo”) served us with a notice of claim against the Company, two of its subsidiaries, and Company board member Robert Friedland, filed in the Supreme Court of British Columbia. The Company and its two subsidiaries have been served; to the Company’s knowledge Robert Friedland has not been served. The Company and its two subsidiaries filed a response on September 24, 2013.  The suit alleges that the Company misused confidential information provided to it by Cotundo related to the Pungarayacu heavy oil field in Ecuador.  Cotundo seeks damages in the form of lost profits, an imposition of a trust in favor of Cotundo, a transfer of Ivanhoe’s interest in the Pungarayacu field to Cotundo, interest, and costs.

The plaintiff and claims in the recent lawsuit by Cotundo overlap with those from a previous lawsuit filed against the Company, its subsidiaries, Mr. Friedland and others in the United States District Court for the District of Colorado on November 20, 2008.  That case was dismissed by the trial court for lack of personal jurisdiction, and that dismissal was affirmed by the United States Court of Appeals for the Tenth Circuit on July 12, 2012.  The plaintiffs filed a writ of certiorari with the United States Supreme Court, which was denied on January 14, 2013.  Both the district court and the appellate court in the prior case awarded fees and costs to the Ivanhoe defendants.

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.

GAR Energy
 
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 evidentiary hearing on the merits (trial) was held September 9-13, 2013. On March 14, 2014 the Company received the verdict from the arbitrators.  The panel awarded a take-nothing judgment against the plaintiffs and in favor of the Company, meaning that the Company prevailed entirely on the merits.  The Company will now consider taking action to recover its attorneys’ fees in defending the case.
 
 
 
21


 
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
2013
Q1
 
2.85
1.80
 
2.09
1.77
 
Q2
 
1.61
0.92
 
1.98
0.90
 
Q3
 
1.10
0.63
 
1.07
0.60
 
Q4
 
0.95
0.37
 
0.93
0.35
2012(1)
Q1
 
4.02
2.46
 
3.99
2.49
 
Q2
 
3.45
1.32
 
3.45
1.77
 
Q3
 
2.28
1.50
 
2.31
1.56
 
Q4
 
2.67
1.23
 
2.74
1.23
2011(1)
Q1
 
10.74
8.01
 
11.01
8.25
 
Q2
 
8.52
4.74
 
8.91
4.80
 
Q3
 
5.88
3.06
 
6.09
2.96
 
Q4
 
4.41
2.25
 
4.38
2.16
 
 
(1)
Prior periods have been restated to reflect the three for one common share consolidation which occurred on April 25, 2013 described below.

On December 31, 2013, the closing price of our common shares was Cdn$0.64 on the TSX and $0.62 on NASDAQ.

As at March 7, 2013, a total of 114,824,253 of our common shares were issued and outstanding and held by 318 holders of record with an estimated 23,800 additional shareholders whose common shares were held for them in street name or nominee accounts.

On April 22, 2013, the Company’s shareholders approved a proposal to affect a reverse stock-split of the Company’s common shares in order to regain compliance with the minimum bid price requirements set forth in the NASDAQ Listing Rules. The reverse stock-split took effect on April 25, 2013. As a result of the reverse stock-split shareholders received one new common share for every three old common shares held and an initial trading price for the new common shares above the NASDAQ minimum bid price was established thereby enabling the Company to regain compliance on May 9, 2013.

On September 6, 2013, the Company received a notification letter from the Listing Qualifications Department of the NASDAQ notifying the Company that the Company again did not meet the minimum bid price requirements set forth in the NASDAQ Listing Rules and that the Company could regain compliance if at any time prior to March 5, 2014 the closing bid price of the Company’s common shares was at least $1.00 for a minimum of 10 consecutive business days. For additional information, refer to the Form 8-K filed on September 12, 2013. On February 18, 2014, the Company applied to the NASDAQ for an additional compliance period of 180 days, which was granted and will expire on September 2, 2014.

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.
 
 
 
22



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 audit and compensation committees that satisfy applicable NASDAQ requirements and that are 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 2014 is Cdn$354 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.
 
 
 
23


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$354 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, 2013, 2012 and 2011, which were not registered under the Act, have been detailed in previously filed Form 10-Qs or 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)
 
2013
   
2012
   
2011
   
2010
 
Results of Operations
                       
Net loss from continuing operations
    (143,754 )     (64,018 )     (26,761 )     (22,258 )
Net loss from continuing operations per share – basic and diluted(1)
    (1.25 )     (0.56 )     (0.23 )     (0.21 )
                                 
Financial Position
                               
Total assets
    232,173       402,057       413,710       394,418  
Long term debt
    63,012       65,214       61,892        
Long term derivative instruments
          181       1,617        
Long term provisions
    2,589       3,157       1,919       3,008  
 
 
(1)
Prior periods have been restated to reflect the three for one common share consolidation which occurred on April 25, 2013 described in Item 5.
 
 
 
 
24

 
ITEM 7: MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
   
25
26
26
26
27
27
27
28
28
28
28
29
29
29
29
30
33
35
35

The following MD&A should be read in conjunction with the audited consolidated financial statements for the year ended December 31, 2013 (the “Financial Statements”). The Financial Statements have been prepared in accordance with and using accounting policies in full compliance with IFRS as issued by the 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 17, 2014.  Unless otherwise noted, tabular amounts are in thousands of US dollars. 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 2013 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, the Company 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 may cause investors to shift their funding priorities into, or out of, the heavy-oil sector.
 
 
 
25


HIGHLIGHTS
 
($000, except as stated)
 
2013
   
2012
   
2011
 
Capital expenditures
    16,927       47,444       51,060  
                         
Net cash used in operating activities
    (36,432 )     (27,060 )     (26,245 )
Net loss from continuing operations
    (143,754 )     (64,018 )     (26,761 )
Net loss per share from continuing operations – basic and diluted
    (1.25 )     (0.56 )     (0.23 )

Net loss from continuing operations in 2013 was $143.8 million, an increase of $79.8 million compared to $64.0 million in 2012. The increase in net loss from continuing operations is mainly attributable to $101.1 million in non-cash impairment charges discussed in detail below, $6.9 million higher general and administrative expenses in 2013 and $1.2 million in other net changes. The increase in net loss from continuing operations was partially offset by $11.9 million higher recovery of deferred income taxes, $7.6 million lower exploration and evaluation expenses in 2013, $3.7 million in net foreign currency gains in 2013 compared to $1.2 million in net losses in 2012, $3.0 million loss on debt repayment in 2012 that did not recur in 2013 and $2.0 million lower finance expenses in 2013. The changes in the items impacting net loss from continuing operations are discussed below.

Capital expenditures amounted to $16.9 million in 2013. In Ecuador, $8.4 million was spent on environmental work, road work and in drilling of the IP-14b appraisal well. In Canada, the Company spent $7.5 million on a seismic and drilling program that will provide further information for initial development on the Tamarack Project including determining optimal well pair locations.

RESULTS OF OPERATIONS
 
Impairment Charges
 
The Company’s 2013 results included a net loss from continuing operations of $143.8 million primarily driven by a non-cash impairment charge related to HTL® of $101.1 million, resulting in a zero carrying value for this asset. The impairment charge was offset by a net recovery of $11.6 million on the corresponding future income tax liability for the FTF and intangible assets that was derecognized as a result of the impairment charge.

At the end of 2013 the Company’s market capitalization was substantially lower than the carrying value of its assets. This relationship is an indicator of impairment which results in a detailed asset evaluation under IFRS. During that evaluation the Company examines its forecasted future cash flows, given past results, and discounts them at a discount rate determined at December 31, 2013. The Company used the modified Capital Asset Pricing Model to calculate its discount rates, which steadily rose over 2013, including a sharp increase in the fourth quarter to 26%. Two factors caused this increase in discount rate, the increasing yield to maturity on the Company’s convertible debentures and the increase in the equity size premium caused by a decreasing market capitalization.

At times, the discount rate required under IFRS may be different than the discount rate used by the Company to evaluate its projects as IFRS requires point in time measurement whereas the Company, when considering commercial feasibility and value, evaluates its projects over a period of time which can minimize the volatility in discount rates when compared to short-term measurement results. IFRS is strict in using observable market data. In the fourth quarter of 2013, the Company’s share price and yields from publicly traded debt required the Company to assign additional risk premiums above what the Company has historically been required to use. Considering these factors, and as required under IFRS, the Company used a discount rate at year end of approximately 26% to conduct its impairment analysis for HTL®. For commercial and planning purposes the Company utilizes discount rates in the range 10-15%.

The Company’s projected cash flows from projects utilizing HTL® technology typically generate an internal rate of return lower than the 26% discount rate used at year end, triggering the impairment charge in the period. Under IFRS, the impairment charge can be reversed in the future once facts and circumstances relating to the charge change.

The non-cash impairment charge for HTL® was driven by the application of accounting standards and capital-cost procedures given the market information available and does not represent the Company’s assessment of commercial value regarding HTL®. The Company believes that the HTL® technology holds significant commercial value and continues to pursue its business development initiatives to achieve commercialization of the HTL® technology. In 2013, these efforts included engaging a third party engineering consultant firm to compare the HTL® technology to its competitors which concluded that HTL® had the opportunity to be the leading partial upgrading technology. Additional work was completed
 
 
 
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which also proved that HTL® synthetic crude oil is stable and compatible with conventional transportation, pipeline & storage systems and can be processed in a refinery. As well, the Company successfully upgraded heavy oil extracted from Ecopetrol S.A.’s San Fernando T2 formation in Colombia crude from 8° API to 15° API.

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 2013 were $4.4 million, relatively unchanged from the 2012 operating costs of $4.3 million.

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

General and Administrative
 
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 $38.1 million in 2013, an increase of $7.0 million compared to costs of $31.1 million in 2012. The increase is primarily due to $3.1 million in increased legal costs mainly related to the proceedings discussed in Part I, Item 3 “Legal Proceedings” disclosed within this Annual Report, $1.0 million one-time staff costs related to severance and retention of key employees in the Asia segment in the first quarter of 2013 and the $1.3 million excess of short-term incentive compensation over the 2012 accrual. $1.6 million other G&A expenses accounted for the remainder of the difference.

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 a lawsuit against the Company 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.

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 2013 was $15.4 million, $7.6 million lower than E&E expense of $23.0 million in 2012. In July 2013, the Government of Mongolia confirmed the extension of the Company’s PSC for a two year period, expiring in July 2015. The Company believes it has exceeded minimum expenditure requirements of the first 5 year term of the PSC by a significant margin. As part of the Company’s refocus of global activities, it is actively pursuing potential candidates to purchase or farm-in on the Mongolian PSC. The Company has updated the geology and exploration potential of the Mongolian PSC property based on recent drilling and 2D seismic data completed early in 2012 and has identified drillable targets. The Company expensed $4.7 million in capital costs in the third quarter of 2013 to reduce the carrying value of assets related to the Mongolian PSC to their estimated recoverable amount at that time. The Company expensed the remaining $10.7 million in capital costs in the fourth quarter of 2013 to further reduce the carrying value of assets related to the Mongolian PSC to nil as the Company does not anticipate a purchase or farm-in on the Mongolian PSC in the short term due to the current uncertainty surrounding Mongolian government regulation. The Mongolian Government is currently reviewing the various laws and regulations pertaining to the mineral and energy industry in Mongolia. For this reason, committed activity for the current year has been significantly reduced and until there is greater clarity with respect to the regulatory environment in Mongolia, it is uncertain when, or if, a potential purchase or farm-in process will be successfully concluded.

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.
 
 
 
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E&E expense in 2011 was $2.8 million. 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.

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 2013 was $1.0 million, unchanged from 2012.

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

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 $3.7 million gain on foreign currency exchange in 2013 compared to a $1.2 million loss in 2012. During 2013 the Canadian dollar weakened in comparison to the US dollar, resulting in gains on the translation of the Company’s Convertible Debentures, which was partially offset by losses on translation of Canadian dollar cash. By contrast, during 2012, the Canadian dollar strengthened in comparison to the US dollar, resulting in losses on the translation of the Company’s Convertible Debentures, which was partially offset by gains on translation of Canadian dollar cash. Despite the Company holding more Canadian dollar cash on average in 2013 than it did in 2012, the average cash balance was less than that of the Company’s Convertible Debentures. Additionally, the absolute magnitude of the Canadian dollar weakening in 2013 was significantly more than the absolute magnitude of the Canadian dollar strengthening in 2012.

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.

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

As at December 31, 2013, the Company valued the convertible component of the Convertible Debentures at nil compared to $0.2 million as at December 31, 2012. The lower valuation, which resulted in an unrealized gain of $0.2 million in 2012, was a result of lower Company share prices in 2013 which the Company’s uses as an input in estimating the fair value of the derivative.

As at December 31, 2012, the Company valued the convertible component of the Convertible Debentures at approximately $0.2 million compared to $1.6 million as at December 31, 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.

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

Finance expense in 2013 was $2.3 million, a decrease of $2.0 million compared to $4.3 million in 2012. The decrease is primarily due to a reduction of $3.4 million in gross interest expense resulting from lower debt in 2013 which the Company used to fund operations while closing the 2012 asset dispositions. This was partially offset by a $1.0 million increase in net interest being expensed due to lower capital expenditures to which interest would be allocated in 2013 compared to 2012 combined with a reduction of $0.4 million to holdback proceeds from the transaction with MIE Holding Corporation (“MIE”), in which the Company disposed of its wholly-owned subsidiary, Pan-China Resources Ltd. to MIE.

Finance expense in 2012 was $4.3 million, an increase of $3.9 million compared to $0.4 million in 2011. The increase was due to higher debt in 2012 which the Company used to fund operations while closing the 2012 asset dispositions as well as
 
 
 
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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.

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 later 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 $14.3 million in 2013 compared to a recovery of $2.4 million in 2012. The $11.9 million increase in recovery is mainly due to $11.6 million in future income tax liabilities for the HTL® assets that were derecognized as a result of the impairment charge as well as a deferred tax recovery of the impairment of the Mongolia assets resulting in a recovery of $2.7 million. This was partially offset by a reduction in deferred tax recoveries of $2.4 million mainly due to non-operating losses recorded in 2012 that did not recur in 2013.

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.

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 China Exploration and Production Co. (“Shell”).

In exchange for Sunwing’s interest in the Zitong Petroleum Contract, the Company received 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 received the full US$5.1 million in holdback proceeds in June 2013 and the final US$3.7 million in proceeds were released as part of the 2012 China National Petroleum Corporation's cost recovery audit in December 2013.

In early 2013 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 of 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 received $3.6 million in holdback proceeds in July 2013.
 
 
 
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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
   
2014
   
2015
   
2016
   
2017
   
After 2017
 
Long term debt(1)
    68,926                   68,926              
Interest on long term debt(1)
    9,891       3,963       3,963       1,965              
Decommissioning obligations(2)
    4,091                   199             3,892  
Leases
    3,033       993       826       704       352       158  
Total
    85,941       4,956       4,789       71,794       352       4,050  
 
 
(1)
Long term debt is denominated in Canadian dollars and has been translated to US dollars at an exchange rate of approximately CAD=0.9402 USD.
 
(2)
Represents undiscounted decommissioning obligations after inflation. The discounted value of these estimated obligations ($2.4 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, which commenced 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, 2013, Ivanhoe estimated the total undiscounted, inflated cost to settle its decommissioning obligations in Canada, for the FTF in the US and in Ecuador was $4.1 million. These costs are expected to be incurred in 2016-2032, 2029 and 2038, respectively.

Leases
 
The Company has long term leases for office space and vehicles, which expire between 2014 and 2018.

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.
 
 
 
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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:

   
2013
   
2012
   
2011
 
Net cash used in operating activities
    (36,432 )     (27,060 )     (26,245 )
Net cash (used in) provided by investing activities
    (2,003 )     77,662       (85,422 )
Net cash (used in) provided by financing activities
    (8 )     (5,388 )     61,423  

Liquidity
 
Ivanhoe’s existing financial resources are insufficient to fund the future capital expenditures necessary to advance the development of our existing projects and to maintain the Company’s business activities at their current level. In the near term, the Company will require other sources of financing in order to continue operating its business as currently constituted. Ivanhoe intends to finance its future funding requirements through a combination of strategic investors and/or public and private debt and equity markets, either at a parent company level or at the project level, and through the sale of interests in existing oil properties. There is no assurance that the Company will be able to obtain such financing, or obtain it on favorable terms.

These activities include discussions with a large international oil company for the creation of a joint financial participation arrangement in respect of its Pungarayacu project in Ecuador. The transaction contemplated by these discussions, if and when consummated, would be expected to generate additional cash. While progress in reaching the transaction objective has been made by the potential transaction participants, there is no assurance that the objective can be achieved, or achieved in a timely manner or that such participation will be approved by regulatory authorities in Ecuador. Without timely access to a sufficient source of financing to enable the Company to make its planned capital expenditures and otherwise fund the cost of carrying on its business, the Company may have to significantly curtail its existing business activities and may be unable to continue as a going concern.

Operating Activities
 
Net cash used in operating activities in 2013 was $36.4 million, an increase of $9.4 million from $27.0 million of net cash used in operating activities in 2012. The increase is primarily due to $6.9 million in increased cash G&A expenses as discussed above less non-cash share-based compensation expense and $2.5 million in other net changes impacting operating activities, which includes a net decrease of $1.1 million due to taxes, closing costs and the previous year’s results related to the discontinued operations in China.

The impact on net cash used in operating activities in 2013 compared to 2012 discussed above is summarized in the following table:

   
2013
   
2012
   
Change
 
Cash taxes paid related to discontinued operations
    (7,455 )           (7,455 )
General and administrative  expense less non-cash share-based compensation expense
    (34,547 )     (27,647 )     (6,900 )
Cash transaction costs paid related to discontinued operations
    (2,072 )           (2,072 )
Net cash provided by operating activities of discontinued operations
    (3,372 )           (3,372 )
Other net items impacting net cash used in operating activities
    (3,022 )     587       (3,609 )
Zitong cash proceeds received
    8,810             8,810  
PCR cash proceeds received
    5,226             5,226  
Net cash used in operating activities
    (36,432 )     (27,060 )     (9,372 )

Net cash used in operating activities in 2012 was $27.0 million, an increase of $0.8 million from $26.2 million of net 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.

Investing Activities
 
E&E Expenditures
 
E&E capital expenditures in 2013 were $15.9 million. The Company’s Canada segment spent $7.5 million on a seismic and drilling program that will provide further information for initial development on the Tamarack Project including determining
 
 
 
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optimal well pair locations. In Ecuador, $8.4 million was spent on environmental work, road work and in drilling of the IP-14b appraisal well.

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.

Property, Plant and Equipment Expenditures
Property, Plant and Equipment (“PP&E”) capital expenditures in 2013 were $1.1 million related to office and computer equipment as well as leasehold improvements.

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.

Proceeds on Disposal of Discontinued Operations
 
Proceeds on disposal of discontinued operations in 2012 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. In June 2013 the customary holdback period of six months from the transaction date expired and the company received the full holdback proceeds ($5.1 million); and, in December 2013 the Company received the remaining proceeds once the China National Petroleum Corporation (“CNPC”) completed its annual cost recovery audit for 2012 expenditures ($3.7 million).

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 received $3.6 million in holdback proceeds in July 2013.

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 the Zitong Block, the Company received the $20.0 million in cash that had been posted for the performance bond in February 2013.

Financing Activities
 
Net cash used in financing activities in 2013 was nil, which was $5.4 million lower compared to net cash provided in financing activities of $5.4 million in 2012.

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.
 
 
 
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Capital Structure
 
As at December 31
 
2013
   
2012
 
Long term debt
    63,012       28.2 %     65,214       17.7 %
Shareholders’ equity
    160,277       71.8 %     302,998       82.3 %
Total capital
    223,289       100.0 %     368,212       100.0 %

On April 22, 2013, the Company’s shareholders approved a proposal to affect a reverse stock-split of the Company’s common shares in order to regain compliance with the minimum bid price requirements set forth in the NASDAQ Listing Rules. The reverse stock-split took effect on April 25, 2013. As a result of the reverse stock-split shareholders received one new common share for every three old common shares held and an initial trading price for the new common shares above the NASDAQ minimum bid price was established thereby enabling the Company to regain compliance on May 9, 2013.

On September 6, 2013, the Company received a notification letter 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 and that the Company could regain compliance if at any time prior to March 5, 2014 the closing bid price of the Company’s common shares was at least $1.00 for a minimum of 10 consecutive business days. For additional information, refer to the Form 8-K filed on September 12, 2013. On February 18, 2014, the Company applied to the NASDAQ for an additional compliance period of 180 days, which was granted and will expire on September 2, 2014.

CRITICAL ACCOUNTING PRINCIPLES AND ESTIMATES
 
The Financial Statements have been prepared in accordance with 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
 
 
 
33

 
if an adverse event or change occurs. Indicators of adverse events could include HTL® patent expiries or advancements of new technologies. 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 (loss).

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.

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.

Provisions for Decommissioning and Restoration Costs
 
The Company recognizes liabilities for the future decommissioning and restoration of E&E assets and PP&E. Management applies judgment in assessing the existence and extent of the Company’s decommissioning and restoration obligations at the end of each reporting period, as well as in determining whether the nature of the activities performed is related to decommissioning and restoration activities or normal operating activities.

These provisions are based on estimated costs, which take into account the anticipated method and extent of restoration consistent with legal requirements, technological advances and the possible future use of the site. Since these estimates are specific to the assets involved, there are many individual judgments and assumptions underlying the Company’s total provision. Actual costs are uncertain and estimates can vary as a result of changes to relevant laws and regulations, the emergence of new technology, operating experience and changes in prices. The expected timing of future decommissioning and restoration activities may change due to certain factors, including oil and gas reserves life. Changes to assumptions related to future expected costs, discount rates and timing may have a material impact on the amounts presented.

The fair value of these provisions is estimated by discounting the expected future cash outflows using a credit-adjusted risk-free interest rate. In subsequent periods, the provision is adjusted for the passage of time by charging an amount to accretion of liabilities in financing expense based on the discount rate.
 
 
 
34


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. During 2013, the IASB decided that a mandatory date of January 1, 2015 would not allow sufficient time for entities to prepare to apply the new standard because the impairment phase of the project has not yet been completed. Accordingly, the IASB decided that a new date should be decided upon when the entire IFRS 9 project is closer to completion. The full impact of this standard will not be known until the phases addressing hedging and impairments have been completed.

OFF-BALANCE SHEET ARRANGEMENTS
 
We have no off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on the Company's financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.

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 2013, nor do we anticipate using foreign currency derivatives in 2014. 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 2013, 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
(336)
336

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, 2013 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 or upon the completion of the sale of the joint venture interest currently contemplated by the Company in respect of the Pungarayacu project. Ivanhoe considers the risk of default on this to be low due to the Company’s ongoing operations in Ecuador.
 
 
 
35


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
 
37
39
39
40
41
42
43
67
 
 

 
 
36

 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
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, 2013 and December 31, 2012, 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, 2013, 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, 2013 and 2012 and their financial performance and cash flows for each of the years in the three-year period ended December 31, 2013, in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board.

Emphasis of Matter
 
Without modifying our opinion, we draw attention to Note 1 in the consolidated financial statements which indicates that as at December 31, 2013, the Company had an accumulated deficit of $458.7 million, and working capital surplus of $19.2 million, excluding assets held for sale, and during the year ended December 31, 2013, cash used in operating activities was $36.4 million and the Company expects to incur further losses in the development of its business. These conditions, along with other matters as set forth in Note 1, indicate the existence of a material uncertainty that casts substantial doubt about the Company’s ability to continue as a going concern.
 
 
 
37


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, 2013, based on the criteria established in Internal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 17, 2014 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ Deloitte LLP
Chartered Accountants
 
March 17, 2014
Calgary, Canada
 
 
 
 
 
38

 
 
CONSOLIDATED FINANCIAL STATEMENTS
 
IVANHOE ENERGY INC.
Consolidated Statements of Financial Position
 
         
December 31,
   
December 31,
 
(US$000s)
 
Note
   
2013
   
2012
 
                   
Assets
                 
Current Assets
                 
Cash and cash equivalents
          23,556       62,819  
Restricted cash
    5       500       20,500  
Accounts receivable
    6, 10       534       14,848  
Prepaid and other
            942       1,593  
Assets held for sale
    6       51,929        
 
            77,461       99,760  
                         
Intangible assets
    7       152,823       285,311  
Property, plant and equipment
    8       1,066       10,205  
Long term receivables
    10       603       6,551  
Note receivable
            220       230  
 
            232,173       402,057  
                         
Liabilities and Shareholders’ Equity
                       
Current Liabilities
                       
Accounts payable and accrued liabilities
    10, 21       6,295       14,436  
Income taxes
    6, 13             1,720  
 
            6,295       16,156  
                         
Long term debt
    9       63,012       65,214  
Long term derivative instruments
    10, 11             181  
Long term provisions
    12       2,589       3,157  
Deferred income taxes
    13             14,351  
              71,896       99,059  
                         
Shareholders’ Equity
                       
Share capital
    15       586,358       586,108  
Contributed surplus
    15       32,614       29,759  
Accumulated deficit
            (458,695 )     (312,869 )
 
            160,277       302,998  
 
            232,173       402,057  
                         
Nature of operations and going concern
    1                  
 
(See accompanying Notes to the Consolidated Financial Statements)

 
 
39

 
IVANHOE ENERGY INC.
Consolidated Statements of Loss and Comprehensive Loss
 

         
Year Ended December 31,
 
(US$000s, except share and per share amounts)
 
Note
   
2013
   
2012
   
2011
 
                         
Interest and other income
          427       28       572  
                               
Expenses and other
                             
Operating
          4,426       4,252       4,561  
General and administrative
          38,068       31,149       38,579  
Exploration and evaluation
    7       15,381       22,994       2,774  
Impairment of intangible assets
    7       92,153              
Impairment of property, plant and equipment
    8       8,943              
Depreciation
    8       1,014       961       1,014  
Foreign currency exchange (gain) loss
            (3,656 )     1,247       (534 )
Derivative instruments gain
    10       (177 )     (1,430 )     (13,148 )
Finance
    9       2,340       4,328       361  
Gain on derecognition of long term provision
                        (1,900 )
Loss on debt repayment
                  2,977        
 
            158,492       66,478       31,707  
                                 
Net loss before income taxes
            (158,065 )     (66,450 )     (31,135 )
                                 
(Provision for) recovery of income taxes
                               
   Current
    13       (41 )           (7 )
   Deferred
    13       14,352       2,432       4,381  
              14,311       2,432       4,374  
                                 
Net loss and total comprehensive loss from continuing operations
            (143,754 )     (64,018 )     (26,761 )
Net income (loss) and total comprehensive income (loss) from discontinued operations
    6       (2,072 )     49,644       1,485  
Net loss and total comprehensive loss
            (145,826 )     (14,374 )     (25,276 )
                                 
Net (loss) income per common share, basic and diluted
                               
From continuing operations
            (1.25 )     (0.56 )     (0.23 )
From discontinued operations
            (0.02 )     0.43       0.01  
From net loss
            (1.27 )     (0.13 )     (0.22 )
                                 
Weighted average number of common shares
                               
Basic and diluted (000s)
            114,785       114,713       114,226  

(See accompanying Notes to the Consolidated Financial Statements)
 
 

 
 
40

 
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 December 31, 2010
          111,455       550,562       23,141       (273,219 )     300,484  
Net loss and comprehensive loss
                            (25,276 )     (25,276 )
Shares issued for services
          56       335                   335  
Exercise of stock options
    16       328       4,164       (2,231 )           1,933  
Exercise of purchase warrants
    15       2,874       31,047                   31,047  
Share-based compensation expense
    16                   5,614             5,614  
Balance December 31, 2011
            114,713       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
            114,713       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
    16                   3,289             3,289  
Balance December 31, 2012
            114,713       586,108       29,759       (312,869 )     302,998  
 
                                               
                                                 
 
         
Share Capital
                         
           
Shares
           
Contributed
   
Accumulated
         
(US$000s, except share amounts)
 
Note
      (000s )  
Amount
   
Surplus
   
Deficit
   
Total
 
                                                 
Balance December 31, 2012
            114,713       586,108       29,759       (312,869 )     302,998  
Net loss and comprehensive loss
                              (145,826 )     (145,826 )
Funding of equity-settled share-based awards
                        (132 )           (132 )
Share-based compensation expense
    16       111       250       2,987             3,237  
Balance December 31, 2013
            114,824       586,358       32,614       (458,695 )     160,277  

(See accompanying Notes to the Consolidated Financial Statements)
 
 
 
41


IVANHOE ENERGY INC.
Consolidated Statements of Cash Flows
 
         
Year Ended December 31,
 
(US$000s)
 
Note
   
2013
   
2012
   
2011
 
                         
Operating Activities
                       
Net loss
          (145,826 )     (14,374 )     (25,276 )
Adjustments to reconcile net loss to cash from operating activities
                             
Depletion and depreciation
    8       1,014       7,642       8,030  
Exploration and evaluation expense
    7       15,381       22,994        
Impairment of intangible assets
    7       92,153              
Impairment of property, plant and equipment
    8       8,943              
Share-based compensation expense
    16       3,521       3,502       5,883  
Unrealized foreign currency exchange loss (gain)
            (3,379 )     800       (446 )
Unrealized derivative instruments gain
    10       (177 )     (1,613 )     (12,965 )
Current income tax expense
    6, 13       41       1,720       2,122  
Deferred income tax recovery
            (14,352 )     (3,422 )     (3,392 )
Finance expense
            2,340       4,328       361  
Financing costs
                        269  
Derecognition of long term provision
                        (1,900 )
Pre-tax gain on disposal of discontinued operations
    6             (57,007 )      
Loss on debt repayment
                  2,977        
Other
            31       39       50  
Current income tax paid
            (1,761 )     (641 )     (1,481 )
Interest paid
            (1,027 )     (3,428 )     (333 )
Share-based payments
            (188 )     (166 )      
Changes in non-cash working capital items
    20       6,854       9,589       2,833  
Net cash used in operating activities
            (36,432 )     (27,060 )     (26,245 )
                                 
Investing Activities
                               
Intangible expenditures
            (15,871 )     (40,112 )     (37,390 )
Property, plant and equipment expenditures
            (1,056 )     (7,332 )     (13,670 )
Proceeds  on disposal of discontinued operations
    6             131,755        
Restricted cash
            20,000             (20,500 )
Long term receivables
            (955 )     (2,606 )     (1,536 )
Interest paid
            (2,936 )     (5,693 )     (4,011 )
Changes in non-cash working capital items
    20       (1,185 )     1,650       (8,315 )
Net cash provided by (used in) investing activities
            (2,003 )     77,662       (85,422 )
                                 
Financing Activities
                               
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  
Changes in non-cash working capital items
    20       (8 )     (32 )     57  
Net cash (used in) provided by financing activities
            (8 )     (5,388 )     61,423  
                                 
Foreign exchange gain (loss) on cash and cash equivalents held in a foreign currency