##### 






UNITED STATES SECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549

FORM 10-K


(Mark One)[X]
    
    Annual Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. For the
fiscal year ended December 31, 2003.or[   ]
    
    Transition Report pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934.
For the transition period from __________ to __________.Commission file number 000-30586


IVANHOE ENERGY INC.(Exact name of registrant as specified in its charter)

Yukon, Canada(State or other jurisdiction of
incorporation or organization)

98- 0372413(I.R.S. Employer
Identification No.)

654  999 Canada Place
Vancouver, British Columbia, Canada
V6C 3E1(Address of principal executive offices)

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

Securities to be registered pursuant to Section 12(b) of the Act: None

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

Title of each class
    
    Name of each exchange on which registeredCommon Shares, no par value
    
    The Toronto Stock ExchangeNASDAQ SmallCap Market


Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.

Yes [X]
    
    No [   ]


Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrants knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to
this Form 10-K.  [X]

Indicate by check mark whether the registrant is an accelerated filer as
defined in Rule 12b-2 of the Act.

Yes [X]
    
    No [   ]


As of March 1, 2004, 161,567,497 common shares of the Registrant were issued
and outstanding. The aggregate market value of the voting stock held by
non-affiliates of the Registrant on June 30, 2003 based on the closing price on
the NASDAQ SmallCap on that date, was $159,495,080.

Documents incorporated by reference: None





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TABLE OF CONTENTS



|                                                 |                                                                                               |                                              |  |  |  |  |  | 
|------------------------------------------------ | --------------------------------------------------------------------------------------------- | -------------------------------------------- |  |  |  |  |  | 
|                                                 | ITEMS 1 AND 2. BUSINESS AND PROPERTIES                                                       
|                                                 |                                                                                               | CORPORATE OVERVIEW                          
|                                                 |                                                                                               | HISTORICAL OVERVIEW                         
|                                                 |                                                                                               | CORPORATE STRATEGY                          
|                                                 |                                                                                               | OIL AND GAS PROPERTIES                      
|                                                 |                                                                                               | EOR PROJECTS                                
|                                                 |                                                                                               | GAS-TO-LIQUIDS PROJECTS                     
|                                                 |                                                                                               | RISK FACTORS                                
|                                                 |                                                                                               | COMPETITION                                 
|                                                 |                                                                                               | ENVIRONMENTAL REGULATIONS                   
|                                                 |                                                                                               | GOVERNMENT REGULATIONS                      
|                                                 |                                                                                               | EMPLOYEES                                   
|                                                 |                                                                                               | RESERVES, PRODUCTION AND RELATED INFORMATION
|                                                 | ITEM 3. LEGAL PROCEEDINGS                                                                    
|                                                 | ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS                                  
|PART II                                         
|                                                 | ITEM 5. MARKET FOR REGISTRANTS COMMON EQUITY AND RELATED STOCKHOLDER MATTERS                
|                                                 | ITEM 6. FIVE YEAR SUMMARY OF SELECTED FINANCIAL DATA                                         
|                                                 | ITEM 7. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|                                                 | ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK                          
|                                                 | ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA                                          
|                                                 | ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 
|                                                 | ITEM 9A. CONTROLS AND PROCEDURES                                                             
|PART III                                        
|                                                 | ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT                                  
|                                                 | ITEM 11. EXECUTIVE COMPENSATION                                                              
|                                                 | ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT                      
|                                                 | ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS                                      
|                                                 | ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES                                              
|Amended Standstill Agreement Linyi Holdings     
|Cooperation Agreement Ensyn Petroleum           
|Equity Incentive Program                        
|Agreement In Principal GTL and Syntroleum       
|Amendment 3 to Syntroleum Licencing Agreement   
|Settlement Agreement and Mutual Release         
|Heads of Agreement CITIC                        
|Stock Purchase & Shareholders Agreement Ensyn   
|LAK Ranch Farm-In Agreement Derek Res.          
|Farm-Out Agreement Richfirst, Pan-China, Sunwing
|Farm-Out & Exploration Agreement Knights Landing
|Code of Business Conduct and Ethics             
|Subsidiaries of Ivanhoe Energy Inc.             
|Consent of Gilbert Laustsen Jung Assoc.         
|Consent of Netherland, Sewell & Assoc.          
|Consent of Deloitte & Touche LLP                
|Section 302 Certification - CEO                 
|Section 302 Certification - CFO                 
|Section 906 Certification - CEO                 
|Section 906 Certification - CFO                 

TABLE OF CONTENTS

PagePART IItems 1 and 2
    
    Business and Properties
    
    
    4Corporate Overview
    
    
    4Historical Overview
    
    
    4Corporate Strategy
    
    
    5Oil and Gas Properties
    
    
    6EOR Projects
    
    
    11Gas-to-Liquids Projects
    
    
    12Risk Factors
    
    
    13Competition
    
    
    16Environmental Regulations
    
    
    16Government Regulations
    
    
    17Employees
    
    
    17Reserves, Production and Related Information
    
    
    17Item 3
    
    Legal Proceedings
    
    
    19Item 4
    
    Submission of Matters to a Vote of Security Holders
    
    
    19PART IIItem 5
    
    Market for Registrants Common Equity and Related Stockholder Matters
    
    
    19Item 6
    
    Five Year Summary of Selected Financial Data
    
    
    21Item 7
    
    Managements Discussion and Analysis of Financial Condition and
Results of Operations
    
    
    22Item 7A
    
    Quantitative and Qualitative Disclosures About Market Risk
    
    
    28Item 8
    
    Financial Statements and Supplementary Data
    
    
    29Item 9
    
    Changes In and Disagreements with Accountants on Accounting
and Financial Disclosure
    
    
    50Item 9A
    
    Controls and Procedures
    
    
    50PART IIIItem 10
    
    Directors and Executive Officers of the Registrant
    
    
    50Item 11
    
    Executive Compensation
    
    
    52Item 12
    
    Security Ownership of Certain Beneficial Owners and Management
    
    
    57Item 13
    
    Certain Relationships and Related Transactions
    
    
    58Item 14
    
    Principal Accountant Fees and Services
    
    
    59PART IVItem 15
    
    Exhibits, Financial Statement Schedules and Reports on Form 8-K
    
    
    60


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CURRENCY AND EXCHANGE RATES

Unless otherwise specified, all reference to dollars or to $ are to U.S.
dollars and all references to Cdn.$ are to Canadian dollars. The closing,
low, high and average noon buying rates in New York for cable transfers for the
conversion of Canadian dollars into U.S. dollars for each of the five years
ended December 31 as reported by the Federal Reserve Bank of New York were as
follows:

2003
    
    2002
    
    2001
    
    2000
    
    1999Closing
    
    $
    0.77
    
    
    $
    0.63
    
    
    $
    0.63
    
    
    $
    0.67
    
    
    $
    0.69Low
    
    $
    0.63
    
    
    $
    0.62
    
    
    $
    0.62
    
    
    $
    0.64
    
    
    $
    0.64High
    
    $
    0.77
    
    
    $
    0.66
    
    
    $
    0.67
    
    
    $
    0.70
    
    
    $
    0.69Average Noon
    
    $
    0.71
    
    
    $
    0.63
    
    
    $
    0.65
    
    
    $
    0.67
    
    
    $
    0.67


The average noon rate of exchange reported by the Federal Reserve Bank of New
York for conversion of U.S. dollars into Canadian dollars on March 1, 2004 was
$ 0.75 ($1.00 = Cdn.$1.34). Exchange rates are based upon the noon buying rate
in New York City for cable transfers in foreign currencies as certified for
customs purposes by the Federal Reserve Bank of New York.

ABBREVIATIONS

As generally used in the oil and gas business and in this Annual Report, the
following terms have the following meanings:

Boe
    
    = barrel of oil equivalentBbl
    
    = barrelMBbl
    
    = thousand barrelsMMBbl
    
    = million barrelsBopd
    
    = barrels of oil per dayBbls/d
    
    = barrels of per dayBoe/d
    
    = barrels of oil equivalent per dayMBbls/d
    
    = thousand barrels per dayMMBls/d
    
    = million barrels per dayMMBtu
    
    = million British thermal unitsMcf
    
    = thousand cubic feetMMcf
    
    = million cubic feetMcf/d
    
    = thousand cubic feet per dayMMcf/d
    
    = million cubic feet per day


When we refer to oil in equivalents, we are doing so to compare quantities of
oil with quantities of gas or to express these different commodities in a
common unit. In calculating Bbl equivalents, we use a generally recognized
standard in which one Bbl is equal to six Mcf. Boes may be misleading,
particularly if used in isolation. The conversion ratio is based on an energy
equivalency conversion method primarily applicable at the burner tip and does
not represent a value equivalency at the wellhead.

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements in this document are forward-looking statements within the
meaning of the United States Private Securities Litigation Reform Act of 1995,
Section 21E of the United States Securities Exchange Act of 1934, as amended,
and Section 27A of the United States Securities Act of 1933, as amended. Such
forward-looking statements involve known and unknown risks, uncertainties and
other factors which may cause our actual results, performance or achievements,
or other future events, to be materially different from any future results,
performance or achievements or other events expressly or implicitly predicted
by such forward-looking statements. Such risks, uncertainties and other factors
include, but are not limited to, our short history of limited revenue, losses
and negative cash flow from our current exploration and development operations
in the U.S. and China; our limited cash resources and consequent need for
additional financing; uncertainties regarding the potential success of our oil
and gas exploration and development projects in the U.S. and China;
uncertainties regarding the potential success of gas-to-liquids technology; oil
price volatility; oil and gas industry operational hazards and environmental
concerns; government regulation and requirements for permits and licenses,
particularly in the foreign jurisdictions in which we carry on business; title
matters; risks associated with carrying on business in foreign jurisdictions;
conflicts of interests; competition for a limited number of promising oil and
gas exploration properties from larger more well financed oil and gas
companies; and other statements contained herein regarding matters that are not
historical facts. Forward-looking statements can often be identified by the use
of forward-looking terminology such as may, will, expect, intend,
estimate, anticipate, believe or continue or the negative thereof or
variations thereon or similar terminology. We believe that any forward-looking
statements made are reasonable based on information available to us on the date
such statements were made. However, no assurance can be given as to future
results, levels of activity and achievements. We undertake no obligation to
update publicly or revise any forward-looking statements contained in this
report. All subsequent forward-looking statements, whether written or oral,
attributable to us or persons acting on our behalf are expressly qualified in
their entirety by these cautionary statements.

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ENFORCEABILITY OF CIVIL LIABILITIES

We have been organized under the laws of Canada and our executive offices are
located in British Columbia, Canada. Some of our directors, controlling persons
and officers and representatives of the experts named in this Annual Report on
Form 10-K reside outside the U.S. and a substantial portion of their assets and
our assets are located outside the U.S. As a result, it may be difficult for
you to effect service of process within the U.S. upon the directors,
controlling persons, officers and representatives of experts who are not
residents of the U.S. or to enforce against them judgments obtained in the
courts of the U.S. based upon the civil liability provisions of the federal
securities laws or other laws of the U.S. There is doubt as to the
enforceability in Canada against us or against any of our directors,
controlling persons, officers or experts who are not residents of the U.S., in
original actions or in actions for enforcement of judgments of U.S. courts, of
liabilities based solely upon civil liability provisions of the U.S. federal
securities laws. Therefore, it may not be possible to enforce those actions
against us, our directors and officers or experts named in this Annual Report
on Form 10-K.

AVAILABLE INFORMATION

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




ITEMS 1 AND 2. BUSINESS AND PROPERTIES




CORPORATE OVERVIEW

We are an international energy company engaged in the exploration for and
production of oil and gas, enhanced oil recovery and natural gas projects and
the application of heavy-to-light oil upgrading and gas-to-liquids
technologies. We were incorporated pursuant to the laws of the Yukon, Canada,
on February 21, 1995 under the name 888 China Holdings Limited. We were largely
inactive until early 1996. On June 3, 1996, we changed our name to Black Sea
Energy Ltd., and on June 24, 1999, we changed our name to Ivanhoe Energy Inc.

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

Our principal executive offices are located at Suite 654  999 Canada Place,
Vancouver, British Columbia, V6C 3E1, and our registered and records offices
are located at 300-204 Black Street, Whitehorse, Yukon, Y1A 2M9.




HISTORICAL OVERVIEW

Ivanhoe Energy Inc. is a company focused on three major strategies: (1)
conventional exploration and production (E&P), primarily oil and natural gas
in the U.S and China; (2) enhanced oil recovery (EOR) and natural gas
projects, on a production-sharing basis, with national petroleum companies and
other operators; and (3) monetization of stranded oil and gas reserves though
the application of advanced technologies such as heavy-to-light and
gas-to-liquids (GTL) technologies.

Following our incorporation in February 1995, we were largely inactive until
early 1996. Initially, our strategy was to seek out existing oil and gas
properties in Russia on which past field development practices did not maximize
reserve recoveries and to establish joint ventures with local partners to
enhance oil recovery. However, after successfully increasing oil production and
reserves at the Kalchinskoye field in western Siberia, a dispute with our
partner prevented us from proceeding with operations in the area. In August
2000 we settled the dispute and disposed of our assets for approximately $29
million, bringing to an end our activities in Russia.

In the third quarter of 1998, we began to implement a diversification program
aimed at expanding the geographical scope of our business. We added three
individuals to our Board of Directors who have international experience in the
oil and gas industry. David Martin, who is now our Chairman, was formerly the
President and CEO of Occidental Oil and Gas Corporation. E. Leon Daniel, who is
now our President and CEO, and John Carver, who is now one of our directors,
are also both former executives of Occidental Oil and Gas Corporation.

In August 1998, we began acquiring oil and gas exploration property interests
in Peru, which we relinquished in 2000 after our exploration test well was
unsuccessful.

In California, we started accumulating working interests and royalty interests
in the San Joaquin Valley in 1998, primarily through an exploration agreement
with Aera Energy LLC (Aera). This agreement entitled us to joint exploration
rights with Aera in return for

4



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analyzing and identifying oil and gas prospects. Under the agreement, we had
access to exploration, seismic and technical data owned by Aera. See Oil and
Gas Properties  California.

In June 1999, we expanded the geographical scope of our business by acquiring
Sunwing Energy Ltd. (Sunwing), an oil and gas company with operations in
China. As a result of our merger with Sunwing, we acquired two
production-sharing contracts with China National Petroleum Corporation (CNPC)
to develop and operate the Kongnan oilfield in Dagang, located in Hebei
Province and the Zhaozhou oilfield in Daqing in the Heilongjiang Province. We
subsequently sold our working interest in our Daqing oil and gas properties in
January 2002 so we could concentrate our Chinese efforts in the larger and more
prospective Dagang area. In April 2003, we received approval of our Overall
Development Program (ODP) for the Dagang field and in November 2003 we signed
a heads of agreement with China International Trust & Investment Company
(CITIC) to jointly develop the Dagang oil project, operated by Sunwing. See
Oil and Gas Properties  China.

In April 2000, we acquired a limited volume license from Syntroleum Corporation
(Syntroleum) to use its proprietary GTL technology to convert natural gas
into synthetic fuels. By sponsoring engineering and design work to extend the
Syntroleum technology for large-scale and more economical gas conversion, we
earned the right to upgrade our limited volume license to a master license. The
master license allows us to use Syntroleums proprietary process to convert
natural gas into an unlimited volume of ultra clean transportation fuels and
other synthetic petroleum products. We plan to use the technology in areas
with large natural gas deposits, which would otherwise be uneconomic to
develop. Our master license was amended in June 2003 to remove all territorial
restrictions, allowing us to use the Syntroleum proprietary process in an
unlimited number of GTL projects throughout the world.

Immediately following the Syntroleum master license acquisition, we began
actively pursuing development contracts for GTL plants in Qatar, Egypt and Oman
and have undertaken extensive feasibility studies in connection with these
opportunities. In December 2002, we formed a wholly owned subsidiary, GTL Japan
Corporation (GTLJ) to facilitate the participation of Japanese companies in
GTL projects. In May 2003, advanced negotiations with Qatar Petroleum and the
Qatari government to construct and operate a major GTL production facility in
Qatar terminated without an agreement being reached. We continue to pursue
several opportunities throughout the world to obtain rights to stranded natural
gas deposits to use as feedstock for GTL projects including initiation, in
August 2003, of a commercialization study in Bolivia. See Gas-to-Liquids
Projects.

In May 2000, we entered into an agreement with Discovery Operating, Inc.
(Discovery) to earn working interests in approximately 10,000 gross acres of
oil and gas exploration properties in the Spraberry Trend of the West Texas
Permian Basin in Midland County, Texas. We sold interests in the least
productive of our Spraberry wells in 2002, limiting our remaining holdings to
interests in 25 producing wells and approximately 2,500 gross acres. See Oil
and Gas Properties  Texas.

During 2000 and 2001, we leased the mineral rights in approximately 49,000
gross acres in the East Texas Basin and in 2001 entered into a joint venture
agreement with a subsidiary of Unocal Corp. (Unocal) to explore and develop
prospects in the Bossier Trend. We subsequently farmed-out our interests in
three wells drilled by Unocal and currently have mineral rights in
approximately 33,200 gross acres. See Oil and Gas Properties  Texas.

In February 2001, we extended our China interests. We entered into two
memoranda of understanding with PetroChina Corporation (PetroChina), a
subsidiary of CNPC, which gives us the exclusive right to negotiate
production-sharing contracts for the development of oil and gas reserves in
three blocks in the Sichuan Basin. In September 2002, we signed a 30-year
production-sharing contract for two of these blocks covering approximately
900,000 acres and in October 2003 initiated the first phase of the exploration
program. We are awaiting a response from PetroChina to begin negotiations on
the third block. The Sichuan Basin is a major oil and gas-producing region of
China located approximately 930 miles southwest of Beijing. See Oil and Gas
Properties  China.

In November 2003, we reached an agreement with Derek Resources (USA), Inc.
(Derek) to jointly develop the LAK Ranch field, a steam assisted gravity
drainage project covering approximately 7,500 gross acres in the Powder River
basin in Weston County, Wyoming. We will be the operator of the project and
will earn an initial 30% working interest in the project by financing the
capital cost of the pilot phase. Following the pilot phase, we will have the
option to increase our working interest to 60% by providing additional capital
toward the initial development phase for a total of $5 million, including the
amounts spent on the pilot phase. See EOR Projects  Wyoming.

In January 2004, we signed a Stock Purchase and Shareholders Agreement with
Ensyn Group, Inc. and its subsidiary, Ensyn Petroleum International Ltd.
(Ensyn), to acquire a 10% equity interest in Ensyn and exclusive rights to
use Ensyns proprietary crude-oil upgrading process (the Ensyn RTPTM Process)
in several key international markets. We believe the Ensyn RTPTM Process
technology offers excellent potential for commercializing heavy-oil fields
throughout the world. See EOR Projects  Ensyn.




CORPORATE STRATEGY

Our mission is to create shareholder value by finding and developing oil and
gas reserves through the implementation of three main

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strategies: (1) conventional exploration and production (E&P) of oil and gas,
primarily in the U.S. and China, (2) EOR development projects, and (3)
monetization of stranded oil and gas reserves through the application of our
licensed Syntroleum and Ensyn technologies. In pursuing these three business
development areas, we are focused on achieving a balance in our short, medium
and long-term goals. In the short term, we are focused on E&P and EOR projects
that can be implemented and achieve early production and cash flow. Our medium
term strategy is to concentrate on natural gas exploration and development and
our long-term priority is on GTL production of ultra clean fuels. During 2003
these strategies continued to mature and gain focus.

Our short-term objective is to focus on areas where production can be achieved
quickly and efficiently to create cash flow to fund our operations and allow us
to pursue our medium and long-term objectives. To date, we have established oil
and natural gas production in the South Midway property in the San Joaquin
Basin of California, in the Spraberry Trend of West Texas and at Dagang in
China.

One of the key elements of our medium term strategy is exploration and
development in the San Joaquin Basin of California and in East Texas. In 1998,
we acquired exploration rights through an agreement with Aera, Californias
largest producer. This agreement gave us access to a significant inventory of
exploration, seismic and technical data for the purpose of identifying
drillable prospects, primarily beneath existing oil fields in the San Joaquin
Basin. We recently farmed into the Sledge Hamar prospect, a property at the
southern extension of the South Belridge field, and Knights Landing, in
northern California, where we will fund a gathering system for four recent gas
discovery wells and plan to participate in drilling additional appraisal and
exploration wells in the lease block.

Our activities in China also have the potential to contribute to our
medium-term growth. Sunwing has commenced the development phase and has
established crude oil production in the Kongnan oilfield in Dagang, Hebei
Province. We remain encouraged by the results achieved in our pilot phase
production program and have commenced the active drilling and development phase
of the project. In September 2002, Sunwing entered into a 30-year
production-sharing contract with PetroChina in the western portion of the
Sichuan Basin. Under the terms of the agreement, Sunwing will develop natural
gas deposits on the 900,000 acre Zitong Block.The first three-year exploration
phase has begun with seismic activity. For a further description of our E&P
projects in the U.S. and China, see Oil and Gas Properties.

Our recently signed Stock Purchase and Shareholders Agreement with Ensyn
Group, Inc. and Ensyn will give us exclusive rights to use Ensyns proprietary
crude-oil upgrading process in several key oil producing countries. We believe
the Ensyn RTPTM Process technology offers excellent potential for
commercializing heavy-oil fields throughout the world. See EOR Projects 
Ensyn.

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

With our master license to use Syntroleums proprietary GTL technology, we are
currently pursuing opportunities in Qatar, Egypt and Bolivia to obtain rights
to stranded natural gas deposits to use as feedstock for GTL projects.




OIL AND GAS PROPERTIES

Our primary oil and gas properties are located in the San Joaquin Valley area
of California, the Midland and East Texas Basins in Texas and the Hebei and
Sichuan Provinces in China. Set forth below is a description of our material
oil and gas properties.

California

Over the past six years, we have acquired interests in a number of properties
in and around the San Joaquin Basin. To date, only our South Midway project
contains proved reserves and has wells on production. During the first quarter
of 2004, we established initial production at the Citrus and Sledge Hamar
prospects in the San Joaquin Valley. The commerciality of these two new
projects is currently under evaluation. We cannot assure you that any of our
other prospects in California will result in the development of commercially
viable production.

Aera Exploration Agreement

In 1998, we acquired rights to an exploration agreement with Aera covering an
area of more than 250,000 acres in the San Joaquin Valley. The Aera exploration
agreement gave us access to all of Aeras exploration, seismic and technical
data in the region for the purpose of identifying drillable exploration
prospects within the exclusive area. Using the extensive proprietary seismic
and technical databases owned by Aera and supplemented by us, we have
identified 30 prospects within 12 prospect areas of mutual interest

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(AMIs) covering approximately 76,000 gross acres. Of the 12 prospect AMIs we
have submitted, Aera has elected to take a working interest in 9 areas, in
which we have working interests ranging from 12.5% to 50% and we have a 100%
working interest in three prospect AMIs in which Aera elected not to
participate. We will continue to hold exploration rights to the lands within
previously designated and accepted prospect AMIs until an exploration well is
drilled in that prospect. Once we identify a drillable prospect and agree upon
working interests with Aera, we have an indefinite time to carry out
exploration drilling if Aera elects to participate in the prospect. If Aera
elects to participate but not to drill the designated prospect, or elects not
to participate, we have an additional two years to drill the prospect on our
own or with other parties. This two-year period will be extended as long as we
continue to drill or have established production.



| |  | South Midway
|- |  | ------------

In 2003, we drilled 17 wells in the southern expansion area of South Midway, 15
of which are producing wells. In addition to the recent drilling activity,
facilities were expanded in 2003 to gather, test and cycle-steam the new
production. A steam generator was purchased and installed to accelerate the
steam stimulation of producing wells and reduce leasing costs. Pending
continuation of the favorable response to steam, it is anticipated that the
second phase of the drilling program in the southern expansion will begin in
the second quarter of 2004 with the drilling of approximately 12 additional
wells.

By the end of 2003, production averaged 460 net Bopd from 51 producing wells,
including 140 Bopd from the southern expansion. Cyclic steaming operations are
in the early stages and peak production for the project is expected to occur by
mid-year 2005. In addition to drilling new wells, we are evaluating the
potential for production gains that may be achieved by switching to a
continuous steam application process that could double the recovery expected
from the current cyclic application process. We are the operator in South
Midway Sunset, with a 100% working interest and a 93% net revenue interest.



| |  | Citrus
|- |  | ------

The Citrus prospect is located in the southern extension of the currently
producing Lost Hills field, which is unrelated to our deep-gas prospect at
Northwest Lost Hills, 15 miles to the north. We acquired an interest in more
than 2,500 potentially productive acres offsetting the Lost Hills field, where
there has been recent development drilling. We are the operator and own
interests ranging between 83% and 100% in the prospect leases.

In December 2003, we completed drilling operations at Citrus #1, our first
horizontal well in this prospect. A total horizontal section of more than 1,900
feet was drilled at a vertical depth of 7,750 feet in the Antelope Shale
formation, an important producing zone to adjacent offsetting production wells.
This is our first well on the southeastern nose of the Lost Hills Antelope
field. The well is currently on production and we will consider a second
horizontal completion after our evaluation of the current production data.



| |  | Northwest Lost Hills
|- |  | --------------------

The Northwest Lost Hills #1-22 well, operated by Aera, began drilling in August
2001. The well was designed to fully evaluate the natural gas and condensate
reserve potential of the deep Temblor formation and reach a depth of
approximately 20,000 feet. This drilling objective was achieved in August 2002
after substantial delays and cost overruns resulting from difficult drilling
conditions. While drilling the well, we encountered several high-pressure
intervals, which indicated the presence of natural gas and decided to set
casing in preparation for testing. In 2003, the well was temporarily abandoned
pending the identification of one or more partners to share the costs of the
testing program. Temporary abandonment is expected to permit reentering the
well at a later date for testing. Until it is tested, the wells commercial
potential, if any, cannot be determined. Of the 8,500 gross acres encompassing
the Northwest Lost Hills prospect, we hold, on average, a 39% working interest.
We have a 42% working interest in the Northwest Lost Hills #1-22 well. If, as
and when we identify a partner to fund a test of the wells commercial
potential, our working interest is expected to decrease by up to 50%.



| |  | Belgian Anticline
|- |  | -----------------

We drilled the first well in this prospect in 2001 and found the prospective
gas sands, but they had been partially depleted by other nearby wells. A
second well in this prospect is contemplated in late 2004. We have a 40%
working interest in this prospect and Aera is the operator.

Other California Prospects



| |  | North South Forty
|- |  | -----------------

In 1999, we entered into an agreement with Prime Natural Resources, LLC
(Prime) to jointly conduct a 3-D seismic survey in the southern San Joaquin
Valley basin in order to identify new prospects over an area of approximately
80,000 acres. We subsequently

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entered into an exploration agreement with Prime and Aera in which we agreed to
pool certain of our acreage positions in the basin to share the costs of
carrying out the 3-D seismic program and to broaden our respective interests in
the area. The agreement with Prime and Aera expired in June 2003. Any acreage
contributed by the parties for which no drillable prospects had been identified
has either reverted back to the contributing party or the leases have been
allowed to expire. We currently have working interests from 17.5% to 50% in
approximately 19,600 gross acres.

Based on the results of the 3-D seismic interpretation, we plan to drill three
wells in the first half of 2004 with Prime. Our working interests in these
wells will be 50%.



| |  | Sledge Hamar
|- |  | ------------

In November 2003, we farmed into the Sledge Hamar prospect, which is located in
a 900-acre block at the southern extension of the South Belridge Field. The
operator Nahabedian Exploration Group (NEG) drilled the first well, Sledge
Hamar 1-7, in December 2003. The well reached a total depth of 5,704 feet and
encountered strong shows of oil and gas in several intervals of the Stevens
sand, which is a major oil-producing formation in the San Joaquin Valley. The
well is currently on production and plans to appraise this new pool discovery
are under consideration for later in 2004. We hold a 40% working interest in
the prospect.



| |  | Knights Landing
|- |  | ---------------

In February 2004, we farmed into the Knights Landing project, which is a
14,000-acre block located in the Sutter and Yolo counties, in northern
California, operated by NEG. Under this exploration and development farm-in
agreement, we purchased, for $1.0 million, a 50% interest in four recent
discoveries by NEG in the contract area and agreed to fund, for $0.6 million,
gas gathering, surface treatment facilities and meters to connect the four
wells to an existing pipeline system. The agreement also provides for us to
participate, at our election, in drilling additional exploration wells in the
lease block. The primary objective of this development and exploration program
is the Starkey Sand formation, which is an established producing reservoir in
the region that lies between depths of 2,000 and 3,500 feet. After payout, we
will hold a 50% working interest in the project.

Texas



| |  | Spraberry
|- |  | ---------

This producing property is located on 2,500 gross acres in the Spraberry Trend
of the West Texas Permian Basin in Midland County, Texas, which we acquired in
2002 through a farm-in from Discovery. After selling a portion of our working
interests in 2002 for approximately $3 million, we retain working interests
ranging from of 31% to 48% in 25 wells which are currently producing
approximately 100 net Boe/d. Discovery is the operator.



| |  | East Texas
|- |  | ----------

During 2000 and 2001, we acquired mineral rights in approximately 49,000 gross
acres in East Texas under a joint venture with Unocal. Unocal, as operator of
the joint venture, was to fund the drilling costs for the first several
exploration wells to offset the $10.1 million in leasehold, seismic and
processing costs we incurred to acquire the mineral rights. After our
respective investments in the joint venture have been equalized, we are to
share exploration, development and infrastructure costs equally.

Unocal subsequently drilled three wells on the Creslenn Ranch and Lone Star
prospects at a cost of $8.5 million. During drilling, indications of natural
gas were encountered from multiple pay sands such as the Bossier, Cotton Valley
and Pettit but no commercial levels of production were established. As a
result, Unocal elected to defer any further activity under the joint venture
and we have been seeking other parties to join and fund drilling and workover
activities on this acreage.

In 2003, we farmed out our interests in two wells drilled by Unocal in the
Creslenn Ranch prospect to Perryman Exploration Partners (Perryman) to test
the shallower zones in the wells. A successful gas recompletion was made in
the first well in July 2003 from the Pettit limestone. At the end of 2003, the
well was flowing at a rate of 400 gross Mcf per day. Perryman has recompleted
the second Creslenn Ranch well to test the Pettit zone and recovered oil, gas
and water. Perryman is considering further testing of this zone or testing a
shallower zone to establish commercial production in this well. Ivanhoe will
retain a 30% working interest after payout in these wells and a 50% working
interest in the remaining acreage.

In 2003, we farmed out our interest in the third well drilled by Unocal in the
Lone Star prospect to Kraker Martin Energy LLC (Kraker). Kraker recompleted
the well in the Cotton Valley sandstone formation and testing was completed
with no commercial production established. We retain a 12 1/2 percent
working interest in the well, which will increase to 25% after payout.

In November 2003, we farmed out our interest in the Catfish Creek prospect to
Perryman. Perryman is required to drill an 11,000 foot

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well in the second quarter of 2004 to test the Rodessa and Pettit formations.
We will retain a 25% working interest after payout in this prospect and
surrounding acreage.

We currently own mineral rights in approximately 33,200 gross acres in East
Texas but do not plan to renew leases as they expire except in the Creslenn
Ranch, Catfish Creek and Malakoff prospects which combined contain approximately
15,200 gross acres. We plan to drill an exploration well in the Malakoff
prospect in 2004.

China

We hold interests in China through our wholly-owned subsidiary Sunwing Energy
Ltd.



| |  | Dagang Project
|- |  | --------------

Sunwings producing property in China is a 30-year production-sharing contract
with CNPC, covering an area of 22,400 gross acres divided into six blocks in
the Kongnan oilfield in Dagang, Hebei Province, China (the Dagang Project).
Under the contract we operate the project and fund 100% of the development
costs to earn 82% of the net revenue from oil production until cost recovery,
at which time our entitlement reverts to 49%.

The contract stipulates that we have the right to market our oil domestically
or export it, sell our product in U.S. dollars and receive world market prices
for our product. We are currently selling our crude oil to CNPC at a
three-month rolling average price of Cinta crude oil, which over the past three
years has averaged approximately $2.00 per barrel less than the West Texas
Intermediate (WTI) price. Cinta is an Indonesian crude that is traded daily
on the international oil market.

All petroleum producers in China pay a value added tax of 5% on oil production.
We pay no royalty until annual gross production of crude oil from a particular
block within the Dagang Project exceeds 500,000 tonnes per annum. Royalties
then become payable at a rate of 2% and increase incrementally as the rate of
production increases to a maximum of 12.5% once annual gross production on a
block exceeds four million tonnes. Our entire interest in the Dagang Project
will revert to CNPC at the end of the 20-year production phase of the contract
or if we abandon the project earlier.

During 2001, we completed the pilot phase and in 2002 submitted the final draft
of an Overall Development Program (ODP) to Chinese regulatory authorities for
approval. Final Government approval was obtained in April 2003, after which the
development phase commenced. The current development program is expected to
cost approximately $198 million over a three-year period and is expected to
involve drilling 115 new wells and reworking an additional 28 of the 82
existing wells.

In January 2004, we signed a farm-out agreement with Richfirst Holdings Limited
(Richfirst), a wholly-owned subsidiary of CITIC, whereby Richfirst will
acquire a 40% working interest in the Dagang project in consideration for an
up-front payment of $20 million. The transaction is subject to approval from
CNPC and relevant Chinese Government Authorities, which is expected in the
first quarter of 2004. Richfirst will have the right to exchange its working
interest in the Dagang project for common shares in Sunwing, should we obtain a
public listing for Sunwing, or for common shares in Ivanhoe. CITIC also has
committed to assist in arranging non-recourse project financing for the
remainder of the Dagang development program.



| |  | Sichuan Basin
|- |  | -------------

In February 2001, we signed two memoranda of understanding with PetroChina.
These memoranda gave us the exclusive right to negotiate production-sharing
contracts for three land blocks in the Sichuan province. We agreed with
PetroChina to carry out joint feasibility studies on the Zitongxi, Zitongdong
and Yudong blocks. These blocks, located in the Sichuan Basin, approximately
930 miles southwest of Beijing cover an area of approximately 2.2 million
acres. PetroChina has drilled 39 wells on the three blocks, with twenty-six of
these wells having been classified as gas wells. PetroChina has production
tested 8 of the estimated 38 hydrocarbon bearing structures located on the
three blocks. In September 2002, we signed a production-sharing contract (the
Zitong Contract), with PetroChina covering both the Zitongxi and Zitongdong
blocks. The contract received final Chinese regulatory approval in November
2002.

Under the Zitong Contract, Sunwing has agreed to conduct an exploration program
on the Zitong block consisting of two phases, each three years in length. The
parties will jointly participate in the development and production of any
commercially viable deposits, with production rights limited to a maximum of
the lesser of 30 years following the date of the Zitong Contract or 20 years of
continuous production.

During the first phase of exploration, Sunwing must complete a minimum work
program consisting of reprocessing 2,000 kilometers of seismic data, completing
500 additional kilometers of new seismic lines and drilling and completing two
wells totaling at least 7,000 meters, with estimated minimum expenditures for
the program of at least $18 million. Upon completion of the first phase,

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Sunwing must relinquish up to 30% of the Zitong block. During 2003, we
reprocessed 2,500 kilometers of existing seismic data and commenced contract
negotiations for just over 1,000 kilometers of new 2-D seismic. The contract
was signed in January 2004 and fieldwork commenced at that time.

During phase two, Sunwing must complete a minimum work program consisting of
new seismic lines totaling 350 kilometers and drill and complete two additional
wells totaling 7,000 meters, with estimated minimum expenditures for the
program of at least $16 million. Following the completion of phase two,
Sunwing must relinquish all of the property except any areas identified for
development and production.

Sunwing can elect to commence the development of commercially viable deposits
at any time following the submission of an ODP. Once Sunwing completes phase
one of the exploration project, Sunwing can also elect not to proceed with
phase two of the exploration project. However, once Sunwing commences a phase
of the exploration project it must complete the minimum work program or else it
will be obligated to pay, to PetroChina, the cash equivalent of the deficiency
in the work program for that exploration phase.

If Sunwing identifies a field for development and/or production, the parties
will divide the participating interest in the project, with PetroChina entitled
to fund and take up to 51% of the participating interest and Sunwing funding
and taking the balance.

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

PetroChina retains the rights to production from six existing wells located on
the Zitong Block. Sunwing can drill new wells on the same structure as those
tapped by the existing wells, but Sunwings wells must be no closer than 1,000
meters from the existing wells.

In 2003, we established an office in Chengdu, the capital of Sichuan. We have
also completed our feasibility study obligations for the Yudong block and
submitted a report to PetroChina in April 2002. In September 2002, we
submitted a letter of intent to negotiate a production-sharing contract and our
work plan for the Yudong block, and are currently awaiting PetroChinas reply.



| |  | CITIC Alliance
|- |  | --------------

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

Under the terms of the agreement, CITIC Energy will assist Sunwing in raising
its profile in Asian capital markets and gaining access to future financing
opportunities. CITIC Energy will also support Sunwing in its plan to obtain a
listing for its shares on the Stock Exchange of Hong Kong.

Sunwing is expected to assist CITIC Energy in identifying and acquiring
interests in international oil and gas development projects and in introducing
GTL and other advanced energy-sector technologies to Chinas domestic oil and
gas industry. We hold a master license to Syntroleums proprietary GTL
process, the geographical scope of which includes China.

CITIC Energy has also agreed to assist Sunwing in its efforts to negotiate a
production-sharing contract with PetroChina covering the Yudong block in
Sichuan Province. Should a production-sharing contract for the Yudong block be
obtained, Sunwing and CITIC Energy will jointly participate in the development
of the project on a 70/30 basis. Within 180 days thereafter, either party can
elect to convert CITIC Energys 30% participating interest in the project into
a 20% equity interest in Sunwing. CITIC Energy has the right to appoint a
representative to Sunwings board of directors and will be entitled to appoint
a second representative if, as and when it acquires a 20% equity interest in
Sunwing.

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

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| |  | Daqing Project
|- |  | --------------

In 2002, we sold our Daqing project and retained an overriding royalty interest
of 4% before cost recovery and 2% thereafter. During 2003, the operator
undertook further development of the field increasing our royalty revenues from
$0.1 million in 2002 to $0.4 million in 2003.




EOR PROJECTS

Ensyn

In January 2004, we signed a Stock Purchase and Shareholders Agreement with
Ensyn Group, Inc. and Ensyn pursuant to which we acquired a 10% equity interest
in Ensyn and exclusive rights to use the proprietary Ensyn
RTPTM Process in
several key international markets. We have agreed to pay Ensyn $2.0 million and
to grant Ensyn the right to acquire an equity interest in each international
oil development project in which we use the Ensyn RTPTM Process. The purchase
price will be paid in four installments and completion of the acquisition is
subject to the attainment of specific milestones: (1) upon signing the heads of
agreement, (2) upon signing the Stock Purchase and Shareholders Agreement, (3)
upon Ensyn delivering a commercial demonstration facility to California and (4)
upon confirmation of the economic viability of the Ensyn RTPTM Process from the
commercial demonstration facility.

The Ensyn RTPTM Process upgrades the quality of heavy oil by producing lighter,
more valuable crude oil. Ensyn reports that this process yields up to a
three-fold economic improvement in heavy-oil projects. The heaviest hydrocarbon
fraction is consumed as fuel to generate the steam used to enhance recovery of
heavy crude. This lowers costs by reducing or eliminating the need to purchase
high-priced natural gas for steam generation and improves revenue since the
higher quality light-crude fraction can be sold at higher prices. The lighter
crude has improved viscosity that permits more efficient pumping through
pipeline networks and significantly reduces transportation costs to marketing
points. The Ensyn RTPTM Process uses readily available plant and process
components. The technology already has been successfully applied to continuous
wood/biomass processing, with several commercial plants in operation in Canada
and the U.S. An Ensyn pilot plant in Ontario, Canada, has completed more than
90 test runs on heavy oil.

We will have exclusive rights to use the Ensyn RTPTM Process in China,
Mongolia, Iraq, Oman and all countries in South America except Venezuela. In
these countries, our rights will be exclusive for an initial term of five years
subject to extension if and when commercial applications develop. We will have
non-exclusive rights to the process in other countries.

For each project we develop using the Ensyn RTPTM Process, Ensyn may elect to
receive a royalty or an equity participation in the project of no more than
10%, except for each such project that we develop in South America, other than
in Venezuela and Peru, where Ensyn may elect to receive an equity interest
equal to 25% of our interest.

In June 2003, both companies entered into a contract to evaluate the Ensyn
RTPTM Process on heavy crude oil produced from our South Midway field, in a
250-barrel-per-day commercial demonstration facility now being built by Ensyn
in the San Joaquin Valley, California.

Wyoming



| |  | LAK Ranch
|- |  | ---------

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

Under the terms of the joint operating agreement, we will be the operator of
the project and will earn an initial 30% working interest by financing the
capital cost of the pilot phase. Following the pilot phase, we will have the
option to increase our working interest to 60% by providing additional capital
toward the initial development phase for a total of $5.0 million, including the
amounts spent on the pilot phase. Thereafter, all future capital expenditures
are to be shared on a working-interest basis. Should we elect not to proceed
beyond the pilot phase our working interest will be reduced to 15% and Derek
will become the operator.

To date, Derek has completed a steam-assisted-gravity-drainage well pair to a
depth of 1,000 feet and 1,800 feet horizontally into the Newcastle Sand
formation. Surface steam-injection and oil-recovery equipment are in place.
Extensive testing indicates that because of the viscosity of the oil,
production can be expected to respond favorably to the application of
continuous heat through steam injection. Surface preparations for the pilot
phase are underway and steaming operations are expected to begin before the end
of the first quarter of 2004. Initially, steam will be injected into the
existing horizontal well and production is expected to commence shortly
thereafter. By the fourth quarter of 2004, five vertical steam-injection wells
are expected to be drilled, providing continuous steam application to the
reservoir and increasing production volumes from the horizontal production
well. We also plan a high-resolution

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3-D seismic data acquisition program to further identify the limits of the
field.

Assuming a successful pilot phase, the initial development phase is expected to
include additional horizontal production wells, new steam-injection wells
(vertical or horizontal) and expansion of surface facilities. We estimate that
the initial development phase could grow to more than 20 wells.




GAS-TO-LIQUIDS PROJECTS

Syntroleum License

We hold a non-exclusive master license entitling us to use Syntroleums
proprietary GTL process in an unlimited number of projects with no limit on
production volume. In June 2003, we gave up our rights for license fee credits
for the $10.0 million we paid for the master license and $2.0 million we
invested in Syntroleums Sweetwater project. In consideration, Syntroleum
removed certain territorial restrictions to our master license, which will
enable us to pursue GTL project opportunities worldwide, particularly in China.
Syntroleum has also agreed that, in respect of GTL projects in which both
companies participate, no additional license fees or royalties will be payable
and that Syntroleum will also contribute to any such project the right to
manufacture specialty and lubricant products. Both companies have the right to
pursue GTL projects independently, but we would be required to pay the normal
license fees and royalties in such projects.

Syntroleum Process

Syntroleums proprietary GTL process is designed to catalytically convert
natural gas into synthetic liquid hydrocarbons. This patented process uses
compressed air, steam and natural gas as initial components to the catalyst
process. As a result, this process (the Syntroleum Process) substantially
reduces the capital and operating cost and the minimum economic size of a GTL
plant as compared to the other oxygen-based GTL technologies.

Syntroleum developed its GTL technology based on a process developed in Germany
in the 1920s for the gasification of coal into oil, called the Fischer-Tropsch
reaction. Syntroleum has applied its principles to the conversion of natural
gas to synthetic liquid hydrocarbons. Syntroleum believes that it holds a
competitive advantage over other GTL technologies because the Syntroleum
Process uses air when converting natural gas into synthetic hydrocarbons.
Competitor GTL processes use either steam reforming or a combination of steam
reforming and partial oxidation with pure oxygen. A steam reformer and an air
separation plant necessary for oxidation are expensive and hazardous and
increase operating costs.

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

GTL Prospects

During 2001, we undertook detailed project feasibility studies for the
construction, operation and cost of GTL plants in both Qatar and Egypt. The
scope of our proposed project in Qatar included the development of natural gas
from the North Field, transporting that gas to shore, extracting the associated
liquids in a natural gas liquids (NGL) plant, moving the dry gas though the
GTL facility to create diesel and naphtha and storing and offloading the
products for shipment throughout the world. In May 2003, advanced negotiations
with Qatar Petroleum and the Qatari government to construct and operate such a
facility terminated without an agreement being reached. In the quarter ended
June 30, 2003, we wrote down $3.3 million of our GTL investments for
expenditures incurred in connection with these negotiations.

The feasibility studies we have undertaken for Egypt contemplate the natural
gas feedstock being purchased, rather than developed. A preliminary feasibility
study for a 45,000 barrels per day fuels, specialty products and lubricants GTL
plant in Egypt was completed and presented to the government of Egypt and its
agencies responsible for the development and monetization of its natural gas
reserves. We await the approval of our scope of work for a commercialization
study and the finalization of a heads of agreement authorizing the
commercialization study and setting aside sufficient natural gas reserves for a
45,000 barrels per day GTL plant.

We have conducted marketing and transportation feasibility studies for both
Europe and Asia Pacific regions in which we identified potential markets and
estimated premiums for GTL diesel and GTL naphtha. Based on our ongoing
commercialization studies and the growing demand for cleaner sources of energy
in Japan, we incorporated GTLJ to facilitate the potential future participation
by Japanese companies in GTL projects. Should we be successful in obtaining
the rights to develop such projects, we intend to assign up to 5% of our
interest to GTLJ. We would then invite Japanese companies from the refining and
distribution, exploration and production, and trading and manufacturing
industry sectors to invest in GTLJ. The proceeds raised would be used to fund
a portion of

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project costs, including front-end engineering and design.

In July 2003, we signed an agreement with Repsol-YPF Bolivia S.A. (Repsol)
and Syntroleum that brings us into a study to build a 90,000-barrel-per-day GTL
plant in southern Bolivia. The commercialization study includes an analysis of
alternative plant sites, transportation logistics and screening economics
conducted by representatives from Ivanhoe, Repsol and Syntroleum. The initial
phase of the commercialization study is expected to be completed in the first
quarter of 2004 at which time the decision is expected to be made whether or
not to proceed to the final phase of the commercialization study. Upon
determination that the project is economically feasible and meets financing
requirements, the three parties are expected to enter into discussions
regarding a joint-venture agreement prior to undertaking definitive engineering
and design work.




RISK FACTORS

We are subject to a number of risks due to the nature of the industry in which
we operate, the present state of development of our business and the foreign
jurisdictions in which we carry on business. The following factors contain
certain forward-looking statements involving risks and uncertainties. Our
actual results may differ materially from the results anticipated in these
forward-looking statements.

We have a history of losses and must generate greater revenue to achieve
profitability.

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

We are not able to guarantee the successful commercial development of our
licensed gas-to-liquids technology.

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

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

We were unsuccessful in concluding a GTL development and production-sharing
contract in Qatar and we can give no assurances as to when or if we will be
able to conclude such contracts in Egypt, Bolivia or other countries where we
are now, or will be, exploring GTL project opportunities.

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

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

Crude oil and natural gas prices are volatile.

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

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

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

Volatile oil and natural gas prices make it difficult to estimate the value of
producing properties for acquisition and often cause

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

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

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

We may not be successful in negotiating additional production sharing contracts
in China.

We hold our interests in China through two production-sharing contracts with
CNPC for the Dagang and Zitong blocks. We also have a memorandum of
understanding with PetroChina indicating a mutual intention to negotiate an
additional production-sharing contract in the Sichuan basin. We cannot assure
you, based on our existing memorandum of understanding with PetroChina, that we
will successfully negotiate additional production-sharing contracts. It is
possible that disputes between us could arise in the future, which must be
resolved under foreign law. We cannot be sure that we can enforce our legal
rights in foreign countries or that an effective legal remedy will be available
to us in any dispute governed by foreign law.

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

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

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

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

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

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

14



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

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

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

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

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

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

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

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

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

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

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

Complying with environmental and other government regulations could be costly
and could negatively impact our production.

Our operations are governed by numerous laws and regulations at various levels
of government in the countries in which we operate. These laws and regulations
govern the operation and maintenance of our facilities, the discharge of
materials into the environment and other environmental protection issues. The
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 on protected areas such as wetlands or wilderness
areas; require that reclamation measures be taken to prevent pollution from
former operations; require remedial measures to mitigate pollution from former
operations, such as plugging abandoned wells and remediating contaminated soil
and groundwater and require remedial measures be taken with respect to property
designated as a contaminated site, for which we are a responsible person.

Under these laws and regulations, we could be liable for personal injury,
clean-up costs and other environmental and property

15



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

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

We compete for oil and gas properties with many other exploration and
development companies throughout the world who have access to greater
resources.

We operate in a highly competitive environment in which we compete with other
exploration and development companies to acquire a limited number of
prospective oil and gas properties. Many of our competitors are much larger
than we are and, as a result, may enjoy a competitive advantage in accessing
financial, technical and human resources. They may be able to pay more for
productive oil and gas properties and exploratory prospects and to define,
evaluate, bid for and purchase a greater number of properties and prospects
than our financial, technical and human resources permit.

Our share ownership is highly concentrated and, as a result, our principal
shareholder effectively controls our business.

Our largest shareholder, Robert M. Friedland, owns approximately 29% of our
common stock and effectively controls our Board of Directors and determines 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 stock.

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

We rely upon a relatively small group of key management and technical
personnel. Messrs. David Martin, E. Leon Daniel and John Carver, in particular,
have extensive experience in oil and gas operations throughout the world. We do
not maintain any key man insurance. We do not have employment agreements with
certain of our key management and technical personnel and we cannot assure you
that these individuals will remain with us in the future. An unexpected partial
or total loss of their services would harm our business.




COMPETITION

The oil and gas industry is highly competitive. Our position in the oil and gas
industry, which includes the search for and development of new sources of
supply, is particularly competitive. Our competitors include major,
intermediate and junior oil and natural gas companies and other individual
producers and operators, many of which have substantially greater financial and
human resources and more developed and extensive infrastructure than we do. Our
larger competitors, by reason of their size and relative financial strength,
can more easily access capital markets than we can and may enjoy a competitive
advantage in the recruitment of qualified personnel. They may be able to absorb
the burden of any changes in laws and regulations in the jurisdictions in which
we do business more easily than we can, adversely affecting our competitive
position. Our competitors may be able to pay more for productive oil and
natural gas properties and may be able to define, evaluate, bid for, and
purchase a greater number of properties and prospects than we can. Further,
these companies may enjoy technological advantages and may be able to implement
new technologies more rapidly than we can. Our ability to acquire additional
properties in the future will depend upon our ability to conduct efficient
operations, to evaluate and select suitable properties, implement advanced
technologies, and to consummate transactions in a highly competitive
environment. The oil and gas industry also competes with other industries in
supplying energy, fuel and other needs of consumers. See Risk Factors.




ENVIRONMENTAL REGULATIONS

Both our oil and gas and GTL operations are subject to various levels of
government laws and regulations relating to the protection of the environment
in the countries in which they operate. See Risk Factors. We believe that our
operations comply in all material respects with applicable environmental laws.

In the U.S., environmental laws and regulations, implemented principally by the
Environmental Protection Agency, Department of Transportation and the
Department of the Interior and comparable state agencies, govern the management
of hazardous waste, the

16



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discharge of pollutants into the air and into surface and underground waters
and the construction of new discharge sources, the manufacture, sale and
disposal of chemical substances, and surface and underground mining. These laws
and regulations generally provide for civil and criminal penalties and fines,
as well as injunctive and remedial relief.

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




GOVERNMENT REGULATIONS

Our business is subject to certain U.S. and Chinese federal, state and local
laws and regulations relating to the exploration for, and development,
production and marketing of, crude oil and natural gas, as well as
environmental and safety matters. In addition, the Chinese government regulates
various aspects of foreign company operations in China. Such laws and
regulations have generally become more stringent in recent years in the U.S.,
often imposing greater liability on a larger number of potentially responsible
parties. It is not unreasonable to expect that the same trend will be
encountered in China. Because the requirements imposed by such laws and
regulations are frequently changed, we are not able to predict the ultimate
cost of compliance.




EMPLOYEES

At December 31, 2003 we had 103 employees. None of our employees are unionized.




RESERVES, PRODUCTION AND RELATED INFORMATION

See the Supplementary Disclosures About Oil and Gas Production Activities
which follows the notes to our financial statements set forth in Item 8 in this
Annual Report for information with respect to our oil and gas producing
activities. We have not filed with or included in reports to any other U.S.
federal authority or agency, any estimates of total proved crude oil or natural
gas reserves since the beginning of the last fiscal year.

The following tables set forth, for each of the last three fiscal years, our
average sales prices and average operating costs per unit of production.
Average operating costs include lifting costs and production taxes, but exclude
allocated head office engineering support costs, depreciation, depletion and
amortization, royalties, income taxes, interest, selling and administrative
expenses.

Average Sales Price
    
    Average Operating Costs2003
    
    2002
    
    2001
    
    2003
    
    2002
    
    2001Crude Oil and Natural Gas ($/Boe)U.S
    
    $
    25.69
    
    
    $
    22.43
    
    
    $
    21.93
    
    
    $
    7.65
    
    
    $
    6.76
    
    
    $
    7.28China
    
    $
    28.41
    
    
    $
    22.30
    
    
    $
    24.42
    
    
    $
    9.31
    
    
    $
    6.49
    
    
    $
    10.50


The following tables set forth the number of commercially productive wells
(both producing wells and wells capable of production) in which we held a
working interest at the end of each of the last three fiscal years:

2003
    
    2002
    
    2001Gross(1)
    
    Net(2)
    
    Gross(1)
    
    Net(2)
    
    Gross(1)
    
    Net(2)U.S
    
    
    77
    
    
    
    60.4
    
    
    
    60
    (3)
    
    
    43.9
    (3)
    
    
    59
    
    
    
    48.4China
    
    
    9
    
    
    
    7.4
    
    
    
    9
    (4)
    
    
    7.4
    (4)
    
    
    13
    
    
    
    10.8




---

|(1) |  | Gross wells are the total number of wells in which an interest is owned.                                                                                          
|--- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(2) |  | Net wells are the sum of fractional interests owned in gross wells.                                                                                               
|   
|(3) |  | After the sale of 4.4 net (7 gross) Spraberry wells in August 2002 and a
50% working interest, or 6.9 net wells, in our remaining Spraberry wells
in October 2002.
|   
|(4) |  | After the sale of 3.4 net (4 gross) Daqing wells in January 2002.                                                                                                 

The following table sets forth, for each of the last three fiscal years, our
participation in the completed drilling of net crude oil and natural gas wells:

17



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Exploratory

Productive2003
    
    2002
    
    2001U.S
    
    
    
    
    
    
    
    
    
    
    China
    
    
    
    
    
    
    
    
    
    
    Total
    
    
    0
    
    
    
    0
    
    
    
    0


Dry2003
    
    2002
    
    2001U.S
    
    
    
    
    
    
    1.7
    (1)
    
    
    1.5China
    
    
    
    
    
    
    
    
    
    
    Total
    
    
    0
    
    
    
    1.7
    
    
    
    1.5




---

|(1) |  | Includes 1.5 (3 gross) net exploratory wells drilled in Kentucky during
2001, which were determined to be dry in 2002.
|--- |  | ----------------------------------------------------------------------------------------------------------------------

At the end of 2003, 2002 and 2001 we had 2.8 (5 gross), 2.3 (5 gross) and 3.3
(7 gross) net exploratory wells, respectively, which were either in the process
of drilling or suspended.

Development

Productive2003
    
    2002
    
    2001U.S
    
    
    17.0
    
    
    
    8.8
    
    
    
    22.8China
    
    
    
    
    
    
    
    
    
    
    Total
    
    
    17.0
    
    
    
    8.8
    
    
    
    22.8


Dry2003
    
    2002
    
    2001U.S
    
    
    2.0
    
    
    
    
    
    
    
    China
    
    
    
    
    
    
    
    
    
    
    Total
    
    
    2.0
    
    
    
    0
    
    
    
    0


In the last quarter of 2003, we set surface casing for 6 development wells in
China, of which the first of these wells was completed in January 2004.

The following tables set forth our holdings of developed and undeveloped oil
and gas acreage as at December 31, 2003:

Developed
    
    UndevelopedGross
    
    Net
    
    Gross
    
    NetAcres(1)
    
    Acres(2)
    
    Acres(1)
    
    Acres(2)U.S
    
    
    12,420
    
    
    
    5,230
    
    
    
    126,519
    
    
    
    40,608China(3)
    
    
    1,729
    
    
    
    1,418
    
    
    
    900,320
    
    
    
    896,607




---

|(1) |  | Gross acres include the interests of others.                                                                                                                                                                                                  
|--- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(2) |  | Net acres exclude the interests of others.                                                                                                                                                                                                    
|   
|(3) |  | The number of developed acres disclosed in respect of our China project
relates only to those portions of the field covered by our producing
operations and does not include the remaining portions of the field
previously developed by CNPC.

The following table sets out estimates of our share of proved reserves in
respect of our U.S. and China operations and calculations of cash flows, before
tax and after tax, undiscounted and discounted at 10% and 15%, based on costs
and prices as at December 31, 2003. Estimates for our U.S. and China operations
were prepared by independent petroleum consultants Netherland, Sewell &
Associates Inc. and Gilbert Laustsen Jung Associates Ltd., respectively.

Our Share of
    
    Our Share ofOur Share
    
    Before Tax Cash Flows
    
    After Tax Cash Flowsin thousands of dollars
    
    in thousands of dollarsOIL
    
    GAS
    
    discounted at:
    
    discounted at:(MBbl)
    
    (MMcf)
    
    0%
    
    10%
    
    15%
    
    0%
    
    10%
    
    15%Net Proved Reserves(1)U.S
    
    
    1,563
    
    
    
    695
    
    
    $
    24,576
    
    
    $
    17,110
    
    
    $
    15,106
    
    
    $
    24,576
    
    
    $
    17,110
    
    
    $
    15,106China
    
    
    15,699
    
    
    
    
    
    
    
    232,591
    
    
    
    114,690
    
    
    
    82,019
    
    
    
    170,944
    
    
    
    81,764
    
    
    
    59,14217,262
    
    
    
    695
    
    
    $
    257,167
    
    
    $
    131,800
    
    
    $
    97,125
    
    
    $
    195,520
    
    
    $
    98,874
    
    
    $
    74,248




---

|(1) |  | Net Proved Reserves are our share of the estimated quantities of crude
oil which geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under
existing economic conditions. See the Supplementary Disclosures about
Oil and Gas Production Activities, which follow the notes to our
financial statements set forth in Item 8 of this Annual Report.
|--- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Ivanhoe is a United States Securities and Exchange Commission (SEC)
registrant and files annual reports on Form 10-K. Accordingly, our reserves
estimates and securities regulatory disclosures are prepared based on U.S.
disclosure standards. In 2003, certain Canadian securities regulatory
authorities adopted National Instrument 51-101  Standards of Disclosure for
Oil and Gas Activities(NI 51-101) which prescribes certain standards that
Canadian companies are required to follow in the preparation and

18



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disclosure of reserves and related information. We applied for, and have been
granted, exemptions from certain NI 51-101 disclosure requirements. These
exemptions permit us to substitute disclosures based on U.S. standards for much
of the annual disclosure required by NI 51-101 and to prepare our reserves
estimates and related disclosures in accordance with U.S. disclosure
requirements, generally accepted industry practices in the U.S. as promulgated
by the Society of Petroleum Engineers, and the standards of the Canadian Oil
and Gas Evaluation Handbook (the COGE Handbook) modified to reflect U.S.
disclosure requirements.

The reserves quantities disclosed in this Annual Report on Form 10-K represent
net proved reserves calculated on a constant price basis using the standards
contained in SEC Regulation S-X and FAS 69. Such information differs from the
corresponding information prepared in accordance with Canadian disclosure
standards under NI 51-101. The primary differences between the U.S.
requirements and the NI 51-101 requirements are as follows:



| |  |  | SEC registrants apply SEC reserves definitions and prepare their
reserves estimates in accordance with SEC requirements and generally
accepted industry practices in the U.S. whereas NI 51-101 requires
adherence to the definitions and standards promulgated by the COGE
Handbook;
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | the SEC mandates disclosure of proved reserves calculated using
year-end constant prices and costs only whereas NI 51-101 also requires
disclosure of reserves and related future net revenues using forecast
prices;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | the SEC mandates disclosure of proved and proved producing reserves
by country only whereas NI 51-101 requires disclosure of more reserve
categories and product types;
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | the SEC does not require separate disclosure of proved undeveloped
reserves or related future development costs whereas NI 51-101 requires
disclosure of more information regarding proved undeveloped reserves,
related development plans and future development costs; and
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | the SEC leaves the engagement of independent qualified reserves
evaluators to the discretion of a companys board of directors whereas
NI 51-101 requires issuers to engage such evaluators and to file their
reports.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

The foregoing is a general and non-exhaustive description of the principal
differences between U.S. disclosure standards and NI 51-101 requirements.




ITEM 3. LEGAL PROCEEDINGS

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




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

No matter was submitted to a vote of security holders during the fourth
quarter of 2003.




PART II




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

Market Information

Our common shares traded on the NASDAQ National Market and SmallCap Market
during 2002 and 2003. As a result of our shares closing below $1.00 per share
for 30 consecutive trading days during 2002 our shares were transferred from
the NASDAQ National Market to the NASDAQ SmallCap Market on December 27, 2002.
Currently our shares are traded on the NASDAQ SmallCap Market and The Toronto
Stock Exchange.

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

NASDAQ MARKET (IVAN)
(US$)

2003
    
    20024th Q
    
    3rd Q
    
    2nd Q
    
    1st Q
    
    4th Q
    
    3rd Q
    
    2nd Q
    
    1st QHigh
    
    
    7.55
    
    
    
    3.07
    
    
    
    1.18
    
    
    
    .60
    
    
    
    .65
    
    
    
    1.07
    
    
    
    2.02
    
    
    
    2.23Low
    
    
    2.52
    
    
    
    .79
    
    
    
    .42
    
    
    
    .50
    
    
    
    .53
    
    
    
    .85
    
    
    
    1.72
    
    
    
    1.93


THE TORONTO STOCK EXCHANGE (IE)
(CDN$)

2003
    
    20024th Q
    
    3rd Q
    
    2nd Q
    
    1st Q
    
    4th Q
    
    3rd Q
    
    2nd Q
    
    1st QHigh
    
    
    10.40
    
    
    
    4.15
    
    
    
    1.60
    
    
    
    .88
    
    
    
    1.01
    
    
    
    1.74
    
    
    
    3.12
    
    
    
    3.50Low
    
    
    3.30
    
    
    
    1.10
    
    
    
    .53
    
    
    
    .77
    
    
    
    .88
    
    
    
    1.45
    
    
    
    2.83
    
    
    
    3.11


19



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##### 



On December 31, 2003, the closing prices for our common shares were $3.74 on
the NASDAQ SmallCap Market and Cdn. $4.85 on The Toronto Stock Exchange.

Exemptions from Certain NASDAQ Corporate Governance Rules

NASDAQ rules provide that NASDAQ may provide exemptions from the NASDAQ
corporate governance standards to a foreign issuer when those standards are
contrary to a law, rule or regulation of any public authority exercising
jurisdiction over such issuer or contrary to generally accepted business
practices in the issuers country of domicile. We have applied to the NASDAQ
for, and expect to receive, exemptions from certain NASDAQ corporate governance
standards that are contrary to the laws, rules, regulations or generally
accepted business practices of Canada. These exemptions and the practices
followed by us are described below:



| |  |  | We are seeking and expect to receive an exemption from NASDAQs
requirement that a majority of the Board of Directors of a
corporation must be comprised of independent directors. The existing
Toronto Stock Exchange guidelines recommend but do not require that a
majority of the directors of a corporation be unrelated directors.
An unrelated director is a director who is independent of
management and is free from any interest and any business or other
relationship which could, or could reasonably be perceived to,
materially interfere with the directors ability to act with a view
to the best interests of the corporation, other than interests and
relationships arising from shareholding. Three of the eight
directors on our board are unrelated for the purposes of the
Toronto Stock Exchange guidelines.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Holders of Common Shares

As at December 31, 2003, a total of 161,359,339 of our common shares were
issued and outstanding and held by 135 holders of record with an estimated
47,600 additional stockholders whose shares were held for them in street name
or nominee accounts.

Dividends

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

Exchange Controls and Taxation

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

There is no limitation imposed by the laws of Canada, the laws of the Yukon, or
our constating documents on the right of a non-resident to hold or vote our
common shares, other than as provided in the Investment Canada Act(Canada)
(the Investment Act), which generally prohibits a reviewable investment by an
entity that is not a Canadian, as defined, unless after review, the minister
responsible for the Investment Act is satisfied that the investment is likely
to be of net benefit to Canada. An investment in our common shares by a
non-Canadian who is not a WTO investor (which includes governments of, or
individuals who are nationals of, member states of the World Trade Organization
and corporations and other entities which are controlled by them), at a time
when we were not already controlled by a WTO investor, would be reviewable
under the Investment Act under two circumstances. First, if it was an
investment to acquire control (within the meaning of the Investment Act) and
the value of our assets, as determined under Investment Act regulations, was
Cdn. $5 million or more. Second, the investment would also be reviewable if an
order for review was made by the federal cabinet of the Canadian government on
the grounds that the investment related to Canadas cultural heritage or
national identity (as prescribed under the Investment Act), regardless of asset
value. An investment in our common shares by a WTO investor, or by a
non-Canadian at a time when we were already controlled by a WTO investor, would
be reviewable under the Investment Act if it was an investment to acquire
control and the value of our assets, as determined under Investment Act
regulations, was not less than a specified amount, which for 2004 is Cdn.$237
million. The Investment Act provides detailed rules to determine if there has
been an acquisition of control. For example, a non-Canadian would acquire
control of us for the purposes of the Investment Act if the non-Canadian
acquired a majority of our outstanding common shares. The acquisition of less
than a majority, but one-third or more, of our common shares would be presumed
to be an acquisition of control of us unless it could be established that, on
the acquisition, we were not controlled in fact by the acquirer. An acquisition
of control for the purposes of the Investment Act could also occur as a result
of the acquisition by a non-Canadian of all or substantially all of our assets.

20



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##### 



Amounts that we may, in the future, pay or credit, or be deemed to have paid or
credited, to you as dividends in respect of the common shares you hold at a
time when you are not a resident of Canada within the meaning of the Income Tax
Act(Canada) will generally be subject to Canadian non-resident withholding tax
of 25% of the amount paid or credited, which may be reduced under the
Canada-U.S. Income Tax Convention (1980) (the Convention). Currently, under
the Convention, the rate of Canadian non-resident withholding tax on the gross
amount of dividends paid or credited to a U.S. resident is generally 15%.
However, if the beneficial owner of such dividends is a U.S. resident
corporation, which owns 10% or more of our voting stock, the withholding rate
is reduced to 5%. In the case of certain tax-exempt entities, which are
residents of the U.S. for the purpose of the Convention, the withholding tax on
dividends may be reduced to 0%.

Sales of Unregistered Securities

During the year ended December 31, 2003, we issued securities which were not
registered under the Securities Act of 1933 (the Act) as follows:



| |  |  | in April 2003, we issued 75,000 common shares to an accredited
investor for corporate finance advisory services in a transaction exempt
from registration under Section 4(2) of the Act;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | in June 2003, we issued 2,000,000 common shares at a price of $0.50
per share to a Hong Kong company pursuant to the conversion of a
previously issued $1,000,000 convertible debenture in a transaction
exempt from registration under Rule 903 of the Act;
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | in July 2003, we issued 3,000,000 special warrants at a price of
$1.00 per special warrant to a Bahamian institutional investor in a
transaction exempt from registration under Rule 903 of the Act. Each
special warrant was exercisable to acquire, for no additional
consideration one common share and one share purchase warrant following
the issuance of a receipt for a prospectus by applicable Canadian
securities regulatory authorities, which occurred in July 2003;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | in August 2003, we issued 3,000,000 special warrants at a price of
$1.00 per special warrant and 3,529,412 special warrants at a price of
$1.70 per special warrant to a Bahamian institutional investor in two
transactions exempt from registration under Rule 903 of the Act. Each
special warrant was exercisable to acquire, for no additional
consideration one common share and one share purchase warrant following
the issuance of a receipt for a prospectus by applicable Canadian
securities regulatory authorities, which occurred in September 2003;
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | in October 2003, we issued 3,125,000 special warrants at a price of
$4.00 per special warrant to a Bahamian institutional investor in a
transaction exempt from registration under Rule 903 of the Act. Each
special warrant was exercisable to acquire, for no additional
consideration one common share and four-tenths of one share purchase
warrant following the issuance of a receipt for a prospectus by
applicable Canadian securities regulatory authorities, which occurred in
November 2003; and
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | in November 2003, we issued 250,000 common shares at a price of $1.70
to a Bahamian institutional investor pursuant to the exercise of
previously issued share purchase warrants in a transaction exempt from
registration under Rule 903 of the Act.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------




ITEM 6. FIVE YEAR SUMMARY OF SELECTED FINANCIAL DATA

The selected financial data set forth below are derived from the accompanying
financial statements, which form part of this Annual Report. The financial
statements have been prepared in accordance with generally accepted accounting
principles (GAAP) applicable in Canada, which are not materially different
from GAAP in the U.S. except as noted immediately below in Reconciliation to
U.S. GAAP. See also Item 7 Managements Discussion and Analysis of Financial
Condition and Results of Operations.

The following table shows selected financial information for the years
indicated:

Year ended December 31,2003
    
    2002
    
    2001
    
    2000
    
    1999(stated in thousands of U.S. dollars, except per share amounts)Financial PositionTotal assets
    
    
    106,574
    
    
    
    107,088
    
    
    
    104,003
    
    
    
    99,800
    
    
    
    47,659Long-term debt
    
    
    833
    
    
    Nil
    
    Nil
    
    Nil
    
    NilShareholders equity
    
    
    100,537
    
    
    
    100,548
    
    
    
    96,897
    
    
    
    95,838
    
    
    
    41,692Results of OperationsRevenues
    
    
    9,659
    
    
    
    8,437
    
    
    
    9,722
    
    
    
    14,063
    (2)
    
    
    6,210Net income (loss)
    
    
    (29,703
    )(4)
    
    
    (6,819
    )(4)
    
    
    (21,122
    )(4)
    
    
    5,429
    
    
    
    (7,802
    )(1)Net incomes (loss) per share  basic
    
    
    (0.20
    )
    
    
    (0.05
    )
    
    
    (0.16
    )
    
    
    0.05
    
    
    
    (0.08
    )Net income (loss) per share  diluted
    
    
    (0.20
    )
    
    
    (0.05
    )
    
    
    (0.16
    )
    
    
    0.04
    
    
    
    (0.08
    )Cash FlowCash provided (used) by operating activities
    
    
    (2,059
    )
    
    
    (2,758
    )
    
    
    2,433
    
    
    
    (11,833
    )
    
    
    (6,230
    )Capital expenditures
    
    
    (15,391
    )
    
    
    (18,828
    )
    
    
    (40,504
    )
    
    
    (40,827
    )
    
    
    (10,728
    )Cash provided (used) by all other investing activities, net
    
    
    (537
    )
    
    
    5,286
    
    
    
    (155
    )
    
    
    32,002
    (3)
    
    
    5,158Cash provided by financing activities, net
    
    
    28,498
    
    
    
    10,583
    
    
    
    18,229
    
    
    
    47,715
    
    
    
    735




---

|(1) |  | Includes asset write-down of $2.5 million. See Note 8 to our financial
statements under Item 8 in our 2001 Annual Report.                 
|--- |  | ------------------------------------------------------------------------------------------------------------------------------------------
|   
|(2) |  | Includes $12.2 million gain on sale of our Russian project. See Note 9 to
our financial statements under Item 8 in our 2001 Annual Report.

21



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|(3) |  | Includes $28.2 million in proceeds from the sale of our Russian project.
See Note 9 to our financial statements under Item 8 in our 2001 Annual
Report.                                              
|--- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(4) |  | Includes asset write-downs of $23.3 million, $2.4 million and $14.0
million for 2003, 2002 and 2001, respectively. See Notes 4 and 13 to our
financial statements under Item 8 in this Annual Report.

Reconciliation to U.S. GAAP

Our financial statements have been prepared in accordance with GAAP applicable
in Canada, which differ in certain respects from those principles that we would
have followed had our financial statements been prepared in accordance with
GAAP in the U.S. The only material differences between Canadian and U.S. GAAP,
which affect our financial statements, is that an increase in ascribed value of
shares issued for royalty interests in 2000 and 1999 of $1.4 million,
additional impairment provision of $10.0 million in 2001 for our China
properties and net write-downs of $4.1 million from 2001 to 2003 in connection
with development costs for our GTL prospects is required under U.S. GAAP. For
the U.S. GAAP reconciliations, see Note 20 to our financial statements in this
Annual Report and Notes 19 and 15 to our financial statements under Item 8 in
our 2002 and 2001 Annual Reports, respectively.

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

Year ended December 31,2003
    
    2002
    
    2001
    
    2000
    
    1999(stated in thousands of U.S. dollars, except per share amounts)Financial PositionTotal Assets
    
    
    94,024
    
    
    
    91,921
    
    
    
    90,219
    
    
    
    101,158
    
    
    
    48,852Shareholders equity
    
    
    87,987
    
    
    
    85,279
    
    
    
    83,113
    
    
    
    97,196
    
    
    
    42,885Results of OperationsNet earnings (loss)
    
    
    (27,086
    )
    
    
    (8,202
    )
    
    
    (36,264
    )
    
    
    5,429
    
    
    
    (7,802
    )Net earnings (loss) per share  basic
    
    
    (0.18
    )
    
    
    (0.06
    )
    
    
    (0.28
    )
    
    
    0.05
    
    
    
    (0.09
    )Net earnings (loss) per share  diluted
    
    
    (0.18
    )
    
    
    (0.06
    )
    
    
    (0.28
    )
    
    
    0.05
    
    
    
    (0.09
    )Cash FlowCash used by operating activities
    
    
    (2,851
    )
    
    
    (4,656
    )
    
    
    (1,456
    )
    
    
    (11,833
    )
    
    
    (6,230
    )Capital expenditures
    
    
    (14,599
    )
    
    
    (16,932
    )
    
    
    (36,615
    )
    
    
    (40,827
    )
    
    
    (10,728
    )





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

Critical Accounting Principles and Estimates

Our accounting principles are described in Note 2 to Notes to the Consolidated
Financial Statements in Item 8. We prepare our Consolidated Financial
Statements in conformity with GAAP in Canada, which conform in all material
respects to U.S. GAAP except for those items disclosed in Note 20 to Notes to
the Consolidated Financial Statements. For U.S. readers we have detailed the
differences and have also provided a reconciliation of the differences between
U.S. and Canadian GAAP in Note 20 to Notes to the Consolidated Financial
Statements.

The preparation of our financial statements requires us to make estimates and
judgments that affect our reported amounts of assets, liabilities, revenue and
expenses. On an ongoing basis we evaluate our estimates, including those
related to asset impairment, revenue recognition, allowance for doubtful
accounts and contingencies and litigation. These estimates are based on
information that is currently available to us and on various other assumptions
that we believe to be reasonable under the circumstances. Actual results could
vary from those estimates under different assumptions and conditions.

We have identified the following critical accounting policies that affect the
more significant judgments and estimates used in preparation of our
consolidated financial statements.

Full Cost Accounting We follow the full cost method of accounting for our oil
and gas operations (as more fully described in Note 2 to the Consolidated
Financial Statements), as compared to the other generally accepted method,
successful efforts. Under the full cost method, costs associated with
geological and geophysical activities and drilling successful and unsuccessful
wells are capitalized on a country-by-country cost center basis. As a
consequence, we may be more exposed to potential impairments if the carrying
value of our evaluated oil and gas assets exceeds their future expected cash
flows. This may occur if recoverable reserve estimates decrease, commodity
prices decline or future estimates for capital, operating and income taxes
increase, to levels that would significantly affect anticipated future cash
flows.

Oil and Gas Reserves The process of estimating quantities of proved reserves
is inherently uncertain and the reserve estimates included in this document are
only estimates (see Risk Factors). You should not assume that the present
value of our future cash flows is the current market value of our estimated
proved oil and gas reserves. In accordance with GAAP, we base the estimated
future net cash flows from proved reserves on prices and costs on the date of
estimate. Actual future prices and costs may be materially

22



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##### 



higher or lower than the prices and costs at the date of estimate.

Depletion Our rate of recording depletion is dependent upon our estimate of
proved reserves and our assessment of unevaluated properties. If the estimates
of proved reserves decline or the carrying value of our evaluated oil and gas
assets increases as a result of our assessment of our unevaluated properties,
the rate at which we record our depletion expense increases, reducing net
income. A decline in proved reserves may occur from lower product prices, which
may make it uneconomic to drill for and produce higher cost fields.

Impact of New and Pending Canadian GAAP Accounting Standards

In December 2001, the Canadian Institute of Chartered Accountants (CICA) issued
Accounting Guideline 13, Hedging Relationships (AcG-13). AcG-13 establishes
certain conditions for when hedge accounting may be applied. The guideline is
effective for fiscal years beginning on or after July 1, 2003. Adoption of
AcG-13 is not expected to have a material impact on our financial position or
results of operations as we are already in compliance with Financial Accounting
Standards Board (FASB) Statement No. 133, Accounting for Derivative
Instruments and Hedging Activities.

In September 2002, the CICA approved Section 3063, Impairment of Long Lived
Assets (S.3063). S.3063 establishes standards for the recognition, measurement
and disclosure of the impairment of long-lived assets, and applies to
long-lived assets held for use. An impairment loss is recognized when the
carrying amount of a long-lived asset is not recoverable and exceeds its fair
value. S.3063 is effective for fiscal years beginning on or after April 1,
2003. Adoption of S.3063 is not expected to have a material impact on our
financial position or results of operations.

In December 2002, the CICA approved Section 3110, Asset Retirement
Obligations (S.3110). S.3110 requires liability recognition for retirement
obligations associated with property, plant and equipment. These obligations
are initially measured at fair value, which is the discounted future value of
the liabilities. This fair value is capitalized as part of the cost of the
related assets and amortized to expense over their useful life. The liabilities
accrete until expected settlement of the retirement obligations. S.3110 is
effective for fiscal years beginning on or after January 1, 2004. We elected
early implementation of this accounting policy. Accordingly, effective January
1, 2003, the Company changed its accounting policy to capitalize asset
retirement costs as part of the carrying value of its oil and gas properties
and adjusted the amount of its site restoration liability to the present value
of the liability for the corresponding asset retirement obligation as of this
date. The Company has adopted the policy without retroactive adjustment of
prior years because implementation of this change had an immaterial effect on
the Companys financial position and results of operations in prior years and
in the current period.

In September 2003, the CICA issued Accounting Guideline 16 Oil and Gas
Accounting   Full Cost (AcG 16). AcG 16 is to be applied no later than
January 1, 2004 and provides a new methodology for determining impairment of
oil and gas assets, provides linkage to the new standards for determination of
reserves and related disclosures under National Instrument 51-101 and revises
certain other aspects of accounting for oil and gas operations under the full
cost method. Adoption of AcG 16 is not expected to have a material impact on
our financial position or results of operations.

The following standards issued by the CICA do not impact us:



| |  |  | Accounting Guideline 14, Disclosure of Guarantees, effective for
interim and annual periods beginning on or after January 1, 2003.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Amendment to Section 3860, Financial Instruments Disclosure and
Presentation, effective for fiscal years beginning on or after November
1, 2004.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Section 1100, General Accounting Principles, effective for years
beginning on or after October 31, 2003.
| | - |  | ----------------------------------------------------------------------------------------------------------



| |  |  | Section 1400, General Standards of Financial Statement
Presentation, effective for years beginning on or after October 31,
2003.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------



| |  |  | Accounting Guideline 15, Consolidation of Variable Interest
Entities, effective for annual and interim periods beginning on or
after January 1, 2004.
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------

Results of Operations and Overview

Despite our disappointment with the termination of our negotiations for a GTL
development and production contract in Qatar, there were some promising
developments for Ivanhoe in the last half of 2003 and we are excited about
these opportunities going forward. Having received approval of the Dagang ODP
earlier in 2003, we commenced drilling our first development wells in December
2003 and completed our first well in January 2004. In November 2003, we signed
a heads of agreement with CITIC to jointly develop the Dagang field which calls
for the drilling of up to 115 new oil wells and 28 re-completions over a three
year period. We see significant potential from our new EOR projects. We plan to
use our thermal recovery and horizontal well expertise to develop the LAK Ranch
field in the Powder River Basin, Wyoming. Our acquisition of an equity stake in
Ensyn and exclusive rights to use the Ensyn RTPTM Process in specific countries
in the Far East, Mid East and South America offers us excellent potential for
commercializing heavy-oil

23



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##### 



fields in those regions. Although we have no signed agreements and all of our
work and preparation at this time is at the initial stages, we plan to leverage
the experience of our senior management in Iraq to help expedite the
development activities needed to increase oil production from existing fields.
We continue to pursue GTL projects in Qatar, Egypt and Bolivia and the removal
of territorial restrictions from our Syntroleum master license has opened GTL
opportunities in China and other countries under our worldwide strategic
alliance with CITIC. We completed reprocessing of existing seismic in the
Zitong natural gas field in the Sichuan Basin and have started the acquisition
of just over 1,000 kilometers of new 2-D seismic data in preparation for
drilling the first exploration well in the last half 2004.

Although production from our South Midway field increased 24% in 2003, total
U.S. production was down 6% as a result of the partial sale of reserves in the
Spraberry field in 2002. Production for 2003 in China was flat compared to
2002. Our revenues, however, increased 15% for 2003 due to a 20% increase in
oil and natural gas prices. See Production and Operations below for more
details.

Our net loss for 2003 was $29.7 million ($0.20 per share) compared to net
losses in 2002 and 2001 of $6.8 million ($0.05 per share) and $21.1 million
($0.16 per share), respectively. The increase in our net loss from 2002 to 2003
of $22.9 million is due mainly to a $20.0 million impairment of our U.S. oil
and gas assets, $0.9 million increase in write-downs of our GTL investments
from year-to-year and a $2.2 million increase in project identification and
general and administrative costs. See General and Administration below. This
is partially offset by an increase in net revenues of $0.7 million from 2002 to
2003. See Production and Operations below. The $20.0 million impairment for
2003 is due mainly to an increase in the carrying costs of our evaluated U.S.
oil and gas assets primarily in Northwest Lost Hills, East Texas and North
South Forty when compared to the estimated recoverable value of our U.S. proved
reserves at year end 2003. Such carrying costs increased as a result of our
decision, in the fourth quarter of 2003, to potentially farm-out up to 50% of
our working interest to one or more partners to fund a test of Northwest Lost
Hills # 1-22. During 2003, we completed our evaluation of significant portions
of our acreage positions in East Texas and North South Forty and either
relinquished or plan to relinquish our interests, thus adding to the carrying
value of our evaluated U.S. oil and gas assets.

The decrease in our net loss from 2001 to 2002 of $14.3 million is due mainly
to an $11.6 million decrease in write down of our properties from year-to-year
and a $3.2 million reduction in project identification and general and
administrative costs. We wrote-down $3.3 million of our GTL investments in
2003 as a result of the termination of our contract negotiation for a GTL
development and production contract in Qatar and we wrote-down $2.4 million in
2002 related to our investment in Syntroleums Sweetwater GTL project. In
2001, we wrote-down our U.S. oil and gas properties by $14.0 million due to an
impairment of our carrying costs as a result of a decline in oil and natural
gas prices in the fourth quarter.

Our net cash and cash equivalents increased by $10.5 million in 2003 compared
to decreases in 2002 and 2001 of $5.7 million and $20.0 million, respectively.
We raised $17.9 million more in 2003 than in 2002 through private placements
and the exercise of warrants and incentive stock options and we invested $3.4
million less in 2003 than in 2002 on exploration, development and GTL
activities. See Exploration and Development Activities and GTL Activities
below. This is partially offset by a reduction in cash generated from asset
sales as we sold non-core assets in China and Texas for $5.4 million in 2002.
The decrease in our cash deficiency from 2001 to 2002 of $14.3 million is due
mainly to a $21.7 million reduction in our spending on exploration, development
and GTL activities in 2002 and $5.4 million from the sale of non-core assets.
This is partially offset by an $8.1 million reduction in cash from private
placements and the exercise of warrants and incentive stock options and a
decrease in cash from operations of $5.2 million primarily as a result of
higher usage of working capital in 2002.

Production and Operations

Oil and gas revenues were $9.6 million in 2003 compared to revenues of $8.3
million and $9.1 million in 2002 and 2001, respectively. Production volumes in
2003 declined 4% from 2002 and declined 7% from 2001 to 2002 due mainly to the
sale of our interests in certain wells in the Spraberry field in the last half
of 2002 and our working interest in the Daqing field in January 2002. The
decline in production volumes in 2003 were more than offset by a 20% increase
in oil and natural gas prices from 2002 particularly in China where oil prices
increased 22%. Oil and natural gas prices for the U.S. and China combined were
down slightly from 2001 to 2002.

At our South Midway field we have drilled 58 wells, 51 of which are producing
wells. We are currently producing approximately 460 net Bopd compared to 490
and 400 net Bopd at the end of 2002 and 2001, respectively. We initiated our
full-scale cyclic steam enhancement program in May 2002 in the primary area of
South Midway, increasing initial production rates ranging from 2.5 to 4 times.
Two wells were drilled in the southern expansion of South Midway in 2002 and
responded very well to cyclic steaming with initial production rates of
approximately 50 net Bopd. In 2003, we drilled 15 new wells in the southern
expansion of South Midway. We started cyclic steaming the new southern
expansion wells in the fourth quarter of 2003 and the wells continue to respond
to heat injection. The project is still early in its life and as a result we
did not realize, at year-end 2003, the increase in proved reserves we had
anticipated at mid-year 2003. The reservoir is responding efficiently to steam
injection. With larger steam injection cycles, production is expected to peak
by mid-year 2005 and the project should realize the anticipated increase in
proved reserves. To date, we have cycle steamed all of the southern expansion
wells with two cycles and eight wells with a third cycle.

24



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At year-end 2003, we were producing from seven pilot phase wells in the Dagang
field at the rate of 393 net Bopd compared to 467 net Bopd and 432 net Bopd at
the end of 2002 and 2001, respectively. The decrease in production rates for
2003 is mainly due to workovers, natural declines and the suspension of one
pilot phase well pending conversion to water injection service. The production
decreases in Dagang were offset by an increase in production from the royalty
interest we retained in the Daqing project, which we sold in 2002.

Operating costs, including production taxes and engineering support, were $4.3
million for 2003 or $12.03 per Boe, compared to $3.8 million, or $10.33 per
Boe, in 2002 and $4.8 million, or $11.95 per Boe in 2001. On our U.S.
properties, the $0.89 per Boe increase in operating costs, excluding production
taxes and engineering support, in 2003 from 2002 is due mainly to the increased
usage of purchased natural gas for steam generation in the southern expansion
of South Midway. The increase in costs for steam generation of $2.36 per Boe is
partially offset in 2003 by a $1.47 per Boe reduction in costs at the Spraberry
field as the wells mature. In 2002, the increase in costs for steam generation
of $0.66 per Boe compared to 2001 is more than offset by a $1.18 per Boe
decrease in primary operating costs as a result of the installation of
permanent production and electrical facilities in 2001 at South Midway. The
$2.82 per Boe increase in operating costs, excluding production taxes and
engineering support, at the Dagang field in 2003 from 2002 is mainly due to
increased well workover costs and increased manpower costs in preparation for
the full field development. Our operating costs decreased $4.01 per Boe in
2002 from 2001 at our Dagang field as a result of the installation of permanent
electrical facilities on certain wells and an improvement in operating
efficiencies.

Depletion costs were $3.7 million for 2003, or $10.44 per Boe, compared to $3.1
million, or $8.35, per Boe, in 2002 and $3.0 million, or $7.56 per Boe, in
2001. U.S. depletion costs per Boe in 2003 increased 26% primarily as a result
of an increase in the carrying costs of our evaluated U.S. oil and gas assets
primarily in Northwest Lost Hills, East Texas and North South Forty. U.S.
depletion costs per Boe for 2002 increased 3% from 2001 primarily due to the
reduction in our reserves as a result of the partial sale of our interests in
Spraberry in 2002 and an increase in the carrying costs of our evaluated U.S.
oil and gas assets. This increase is partially offset by a $14.0 million
write-down of depletable costs in 2001. China depletion costs for 2003
increased 23% from 2002. A downward revision of our share of proved reserves at
Dagang as a result of increased oil prices in 2003 increased our depletion rate
$1.09 per Boe and $0.84 per Boe as a result of anticipated increases in Dagang
future development costs. China depletion costs for 2002 increased 22% from
2001 primarily as a result of anticipated increases in Dagang future
development costs resulting in an increase of $0.41 per boe and the sale of our
reserves at Daqing, which increased our depletion rate $1.10 per boe.

Production and operating information for 2001 to 2003 are detailed below:

2003
    
    2002
    
    2001U.S.
    
    China
    
    Total
    
    U.S.
    
    China
    
    Total
    
    U.S.
    
    China
    
    TotalNet ProductionBoe
    
    
    212,820
    
    
    
    144.422
    
    
    
    357,242
    
    
    
    227,301
    
    
    
    144,848
    
    
    
    372,149
    
    
    
    232,584
    
    
    
    165,599
    
    
    
    398,183Boe/day for the year
    
    
    583
    
    
    
    396
    
    
    
    979
    
    
    
    623
    
    
    
    397
    
    
    
    1,020
    
    
    
    637
    
    
    
    454
    
    
    
    1,091Per BoeOil and gas revenue
    
    $
    25.69
    
    
    $
    28.41
    
    
    $
    26.79
    
    
    $
    22.43
    
    
    $
    22.30
    
    
    $
    22.38
    
    
    $
    21.93
    
    
    $
    24.42
    
    
    $
    22.96Operating costs
    
    
    7.65
    
    
    
    9.31
    
    
    
    8.52
    
    
    
    6.76
    
    
    
    6.49
    
    
    
    6.66
    
    
    
    7.28
    
    
    
    10.50
    
    
    
    8.62Production taxes
    
    
    1.03
    
    
    
    
    
    
    
    0.62
    
    
    
    1.21
    
    
    
    
    
    
    
    0.74
    
    
    
    1.01
    
    
    
    
    
    
    
    0.59Engineering Support
    
    
    2.19
    
    
    
    4.40
    
    
    
    2.89
    
    
    
    2.38
    
    
    
    3.80
    
    
    
    2.93
    
    
    
    2.12
    
    
    
    3.62
    
    
    
    2.7410.87
    
    
    
    13.71
    
    
    
    12.03
    
    
    
    10.35
    
    
    
    10.29
    
    
    
    10.33
    
    
    
    10.41
    
    
    
    14.12
    
    
    
    11.95Net revenue before depletion
    
    
    14.82
    
    
    
    14.70
    
    
    
    14.76
    
    
    
    12.08
    
    
    
    12.01
    
    
    
    12.05
    
    
    
    11.52
    
    
    
    10.30
    
    
    
    11.01Depletion
    
    
    10.58
    
    
    
    10.23
    
    
    
    10.44
    
    
    
    8.39
    
    
    
    8.30
    
    
    
    8.35
    
    
    
    8.12
    
    
    
    6.79
    
    
    
    7.56Net revenue from operations
    
    $
    4.24
    
    
    $
    4.47
    
    
    $
    4.32
    
    
    $
    3.69
    
    
    $
    3.71
    
    
    $
    3.70
    
    
    $
    3.40
    
    
    $
    3.51
    
    
    $
    3.45


General and Administration

We continue to follow the practice of expensing the costs we incur in pursuing
and investigating new projects, as well as costs associated with investment
banking advice. In 2003, we incurred $7.9 million of general and administrative
and project identification costs compared to $5.7 million and $8.8 million in
2002 and 2001, respectively. For 2003, $1.0 million of the increase from 2002
is a result of a decrease in such costs being allocated to our exploration,
development and GTL activities due to a reduction in capital spending activity
during 2003. The balance of the increase for 2003 is associated with fees
incurred for the filing of a $100 million Canadian base shelf prospectus and
corresponding U.S. shelf registration statement, exploring the possibility of
securing a public listing for Sunwing and pursuing new sources of project
financing as well as an increase in insurance costs for 2003. The decrease for
2002 is directly attributable to our reduction in activities related to finding
and investigating new projects, including $1.4 million of investment banking
services incurred in 2001. In addition, in the third quarter of 2002, we
implemented a cost reduction program that continued into 2003.

Interest Income

Interest income represents income we earn on our excess cash balances during
the year. The $0.5 million reduction in interest income

25



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##### 



from 2001 to 2002 is due to decreased cash balances and a decline in interest
rate yields.

Income Taxes

We have significant tax losses available to carry forward and reduce taxes
otherwise payable. Details of these losses are in Note 14 to the consolidated
financial statements included herein under Item 8. Given the uncertainty as to
the utilization of these tax loss carry-forwards, we have followed the practice
of recording a provision against the tax benefit asset resulting from these
losses.

Exploration and Development Activities

Expenditures in 2003 on exploration and development activities were $14.6
million down from $16.9 million and $36.6 million in 2002 and 2001,
respectively. Capital spending in the U.S. was $8.4 million in 2003 down $4.9
million compared to 2002. Completion of our drilling of the Northwest Lost
Hills # 1-22 well and our drilling program in the Spraberry field in 2002
resulted in a $9.2 million decrease in 2003. This is partially offset by the
drilling of our first wells at the Citrus and Sledge Hamar fields in December
2003 and for the drilling of new producing wells at South Midway and the
construction of production facilities in the southern expansion of South
Midway. For 2002, capital spending in the U.S. was $13.3 million down $16.7
million compared to 2001, primarily due to a reduction in development drilling
in Spraberry and South Midway, the completion of our Magic Mountain and
Kentucky drilling programs in 2001, and the completion of our significant
acreage acquisition program in the Bossier Trend at year-end 2001. These
decreases were partially offset by a $2.4 million increase in drilling costs on
Northwest Lost Hills #1-22 in 2002.

Capital spending in China was $6.2 million, an increase of $2.6 million
compared to 2002. This increase is mainly due to the start up of drilling
under the Dagang development program at a cost of $2.1 million and $0.5 million
for the reprocessing of 2-D seismic on the Zitong block. For 2002, capital
spending in China was $3.6 million down $2.9 million compared to 2001,
primarily as a result of the completion of our pilot test program in our Dagang
project in February 2001 and the sale of our Daqing project in 2002, partially
offset by a $0.5 million increase in spending on the Sichuan project in 2002.

At South Midway, we drilled 19 development and appraisal wells in 2003. Sixteen
of these wells were commercial oil producers. This compares to 7 and 10
commercial oil wells we drilled in 2002 and 2001, respectively. After
initiating a pilot cyclic steam project in 2001, we commenced a full-scale
steam project in 2002 to enhance production. Facilities were expanded in 2003
to gather, test and cycle-steam the new production. Additionally, a steam
generator was purchased and installed in 2003 to accelerate the thermal
stimulation of producing wells and reduce the cost of leasing a steam
generator. We are currently evaluating the wells drilled in the southern
expansion before we drill additional wells in the second phase.

In Texas, we drilled 2 and 14 commercial wells in the Spraberry field in 2002
and 2001, respectively and in 2002 completed three wells drilled by Unocal
under a farm-out agreement in the Creslenn Ranch and Lone Star prospects.
Additionally, in 2001 we increased our acreage position in East Texas. In 2003,
we spent minimal capital in Texas to maintain certain acreage positions and to
farm-out our interests in Creslenn Ranch, Lone Star and Catfish Creek
prospects. In 2003, we farmed out our interests in the three wells drilled by
Unocal to test the shallower zones in the wells. A successful gas recompletion
was made in the first Creslenn Ranch well from the Pettit limestone and the
other two wells are in various stages of completion or testing of target zones.
We retain a 30% working interest in the Creslenn Ranch prospect after payout
and a 25% working interest in the Lone Star and Catfish Creek prospects after
payout. An 11,000 foot well to test the Rodessa and Pettit formations is
planned in the second quarter of 2004 in the Catfish Creek prospect as required
by the farm-out agreement.

The Northwest Lost Hills #1-22 well was spud in 2001 and successfully drilled
to a measured depth of 21,000 feet and a liner set to 19,620 feet in August
2002. While drilling the well, we encountered several high-pressure intervals,
which indicated the presence of natural gas. Northwest Lost Hills # 1-22 was
temporarily abandoned in 2003 until we can identify one or more partners to
share the costs of the testing program. Temporary abandonment is expected to
permit reentering the well at a later date for testing. Until it is tested, the
wells commercial potential, if any, cannot be determined.

In December 2003, we completed drilling operations on Citrus #1 and Sledge
Hamar # 1-7. These are our first wells in these two prospect areas. Both wells
are on production and the prospects are being evaluated for further
development.

We received approval of our ODP for Dagang in April 2003. In the fourth
quarter of 2003, we completed drilling of six surface holes and commenced
drilling of our first development well in December 2003, with completion and
testing operations occurring in January 2004. The well, Nan 105, initially
tested at 330 gross Bopd of 35 degree API oil, with no water. Plans for 2004
are to drill 22 development wells, 17 of which are expected to be completed,
build associated facilities and convert three existing wells to water injection
service.

In 2003, we commenced initial work on the first phase of a three-year
exploration program in our Zitong block by reprocessing 2,500 kilometers of
existing 2-D seismic data and commenced preparations to acquire just over 1,000
kilometers of new 2-D seismic data

26



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##### 



starting in January 2004. Following the seismic acquisition and
interpretation, we plan to spud the first of two exploration wells in the last
half of 2004, as required under the first phase of the Zitong Contract.

In 2002, we completed our feasibility study for the Yudong block within the
Sichuan province, submitted the report to PetroChina and submitted a letter of
intent to negotiate a contract and a work plan for Yudong. We currently await
PetroChinas reply.

Total capital spending on oil and gas operations, excluding non-cash
transactions, for 2001 to 2003 was as follows:

2003
    
    2002
    
    2001Capital Expenditures:U.S
    
    $
    8,386
    
    
    $
    13,306
    
    
    $
    30,047China
    
    
    6,213
    
    
    
    3,626
    
    
    
    6,568$
    14,599
    
    
    $
    16,932
    
    
    $
    36,615Comprised of:Property acquisition
    
    $
    650
    
    
    $
    913
    
    
    $
    4,788Royalty rights
    
    
    
    
    
    
    
    
    
    
    1,191Seismic
    
    
    95
    
    
    
    30
    
    
    
    1,348Exploration
    
    
    3,053
    
    
    
    10,811
    
    
    
    10,197Development
    
    
    10,801
    
    
    
    5,178
    
    
    
    19,091$
    14,599
    
    
    $
    16,932
    
    
    $
    36,615


GTL Activities

GTL expenditures were $0.8 million in 2003 down from $1.9 million and $3.9
million in 2002 and 2001, respectively. The decreases in 2003 and 2002 are
mainly due to the completion, in 2002, of technical and commercial feasibility
studies of the Syntroleum process in large-scale GTL facilities we initiated in
2001.

In May 2003, negotiations with Qatar Petroleum to construct and operate a GTL
production facility terminated without reaching an agreement and we wrote down
$3.3 million of our GTL investments for expenditures incurred in connection
with these negotiations.

In July 2003, we signed an agreement with Repsol and Syntroleum for a study to
build a 90,000-barrel-per-day GTL plant in Bolivia. The commercialization study
is underway including an analysis of alternative plant sites, transportation
logistics and project economics. Upon determination that the project is
economically feasible and meets financing requirements, the three parties will
enter into discussions regarding a joint-venture agreement prior to undertaking
definitive engineering and design work.

In December 2003, proposals for alternative plant designs for a GTL fuels,
specialty products and lubricants plant were prepared and presented to the
government of Egypt and its agencies responsible for the development and
monetization of its natural gas reserves. We await the approval of our scope of
work for a commercial feasibility study and the finalization of a heads of
agreement authorizing the commercial feasibility study and setting aside of
sufficient natural gas reserves for a 45,000 barrels per day GTL plant. We are
pursuing this project jointly with Syntroleum.

Liquidity and Capital Resources

Our capital expenditure budget for 2004 is $51.8 million. Fifty percent of this
budget is for oil and gas development programs in the Dagang, South Midway and
Citrus fields. Thirty five percent of the budget is for exploration programs in
the U.S. and our exploration capital commitment in the Zitong field including
the drilling of the first exploration well in 2004 following the completion of
seismic acquisition and interpretation. The remaining 15% of our budget is
primarily for the pursuit of EOR and GTL projects. The strategic alliance we
initiated with CITIC Energy in 2002 and further solidified in 2003 is expected
to be key to financing the development of Sunwings exploration and development
projects in China and possibly GTL and EOR projects that we may be successful
in acquiring worldwide. In January 2004, Sunwing signed farm-out and joint
operating agreements with Richfirst, a wholly-owned subsidiary of CITIC, to
acquire a 40% working interest in the Dagang project following an up front
payment of $20 million and approval by Chinas regulatory authorities, both of
which are expected to occur in the first quarter 2004. This agreement gives
Richfirst the option to exchange its working interest in Dagang for common
shares of Ivanhoe or Sunwing.

During 2003, we raised $24.1 million, net of share issue costs, through the
issuance of common shares in four private placements and $1.0 million through a
bank loan. Our current cash position is expected to enable us to initiate our
short-term objectives of exploration in East Texas, California and Zitong and
our development programs in our Citrus and Dagang fields as well as further our
EOR and GTL initiatives. We are also looking at acquisitions of proven and
probable reserves as a means of supplementing our growth strategy. In October
2003, we filed a base shelf prospectus with Canadian securities regulatory
authorities and a shelf registration statement with the U.S. Securities and
Exchange Commission to qualify for potential future sale in Canada and the U.S.
up to $100 million of various types of securities, including common shares,
preferred shares, warrants and debt securities. These shelf filings are
expected to give us greater flexibility to fund our expansion and capital
programs and will allow us to take advantage of a broader

27



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##### 



range of financing opportunities on a timelier basis. A combination of such
equity financing, as well as convertible debenture, debt and mezzanine
financing and joint venture partner participation, will be required to complete
our future capital programs. We cannot assure you that we will be successful in
raising the additional funds necessary or securing joint venture partners to
complete our capital programs. If we are unsuccessful, we will have to
prioritize our capital programs, which may result in delaying and potentially
losing some valuable business opportunities.

Contractual Obligations

The table below summarizes and cross-references the contractual obligations
that are reflected in our Consolidated Balance Sheets and/or disclosed in the
accompanying Notes:

Payments Due by YearTotal
    
    2004
    
    2005
    
    2006
    
    2007
    
    After 2007Purchase Agreements:
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    Consolidated Balance Sheets:Notes payable  current portion (Note 5)
    
    
    167
    
    
    
    167
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Long term debt (Note 5)
    
    
    833
    
    
    
    
    
    
    
    333
    
    
    
    333
    
    
    
    167
    
    
    
    Footnote Disclosure:
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Operating leases (Note 18)
    
    
    1,332
    
    
    
    533
    
    
    
    442
    
    
    
    306
    
    
    
    51
    
    
    
    Exploration commitment (a) (Note 17)
    
    
    16,600
    
    
    
    7,300
    
    
    
    9,300
    
    
    
    
    
    
    
    
    
    
    
    Total
    
    $
    18,932
    
    
    $
    8,000
    
    
    $
    10,075
    
    
    $
    639
    
    
    $
    218
    
    
    $
    




---

|(a) |  | This represents our estimate of the remaining expenditure commitment for
the minimum work program during the first phase of Zitong. This is a total
spending commitment and not a commitment per year. The amounts per year are
based on our current estimate.
|--- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Off Balance Sheet Arrangements

At December 31, 2003 and 2002, we did not have any relationships with
unconsolidated entities or financial partnerships, such as structured finance
or special purpose entities, which would have been established for the purpose
of facilitating off-balance sheet arrangements or other contractually narrow or
limited purposes. In addition, we do not engage in trading activities involving
non-exchange traded contracts. As such, we are not materially exposed to any
financing, liquidity, market or credit risk that could arise if we had engaged
in such relationships. We do not have relationships and transactions with
persons or entities that derive benefits from their non-independent
relationship with us, or our related parties, except as disclosed herein.

Related Party Transactions

We have entered into agreements with a number of entities, some of which are
related through common directors or shareholders, to share administrative
personnel, aircraft, office space and facilities. The agreement for the usage
of aircraft was terminated in 2003. We are billed on a cost recovery basis. The
costs incurred in the normal course of business with respect to the above
arrangements amounted to $0.9 million for 2003, $1.2 million for 2002 and $2.7
million for 2001. In addition, a company controlled by a director provides
consulting services to Ivanhoe. Consulting services and out of pocket expenses
paid to this company were $0.4 million for 2003 and 2002 and $0.7 million for
2001. At year-end, amounts included in accounts payable under these
arrangements totaled $0.1 million in 2003, $0.8 million in 2002 and $1.1
million in 2001.

We borrowed $1.25 million from a related company controlled by a director of
Ivanhoe. The loan, plus accrued interest, was repaid in September 2003.




ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

We currently have limited production in the U.S and China, which have not
generated sufficient cash from operations to fund our exploration and
development activities. Historically, we have relied on the equity markets as
the primary source of capital to fund our expansion and growth opportunities.

The Companys results of operations are sensitive mainly to fluctuations in oil
and natural gas prices. We periodically engage in derivatives to hedge the cash
flow from a portion of our U.S. oil production. See Note 12 to the
Consolidated Financial Statements in Item 8.

We are exposed to the risk that we may require a provision for impairment as to
the carrying value of our evaluated oil and gas assets.

28



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##### 



Such value is compared quarterly to the estimated recoverable value of our
proved reserves based on period-end commodity prices, unescalated. We impaired
$20.0 million and $14.0 million of our oil and gas assets in 2003 and 2001,
respectively. As at December 31, 2003, we have $31.2 million of oil and gas
assets, which have not yet been evaluated including $15.5 million in our
Northwest Lost Hills prospect. If we are unable to identify partners to share
the costs to test the Northwest Lost Hills # 1-22 well in 2004, or if the well
is tested but determined to be uneconomic, we may be required to further impair
the carrying value of our oil and gas assets.

We are exposed to the risk that we will be unable to engage competent
cost-effective contractors and suppliers for our operations, risks that damage
to, or malfunction of, our equipment will hinder our ability to carry out our
exploration activities and risks that foreign laws may not adequately protect
our interests in disputes with foreign partners and others.

In the international petroleum industry, most production is bought and sold in
U.S. currency or with reference to U.S. currency. Accordingly, we do not expect
to face foreign exchange risks if and when we commence large-scale commercial
production. Most of our business transactions are conducted in U.S. currency in
the countries in which we operate.

We currently have minimal debt obligations and, therefore, we do not believe
that we face any undue financial risk from interest rate fluctuations.




ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Financial Statements and Related Information

PageIndependent Auditors Report
    
    
    30Consolidated Financial StatementsConsolidated Balance Sheets
    
    
    31Consolidated Statements of Loss and Deficit
    
    
    32Consolidated Statements of Cash Flow
    
    
    33Notes to the Consolidated Financial Statements
    
    
    34Quarterly Financial Data (Unaudited)
    
    
    48Supplementary Disclosures About Oil and Gas Production
Activities (Unaudited)
    
    
    48


29



---



##### 



INDEPENDENT AUDITORS REPORT

To the Shareholders ofIvanhoe Energy Inc.:

We have audited the consolidated balance sheets of Ivanhoe Energy Inc. as at
December 31, 2003 and 2002 and the consolidated statements of loss and deficit
and cash flow for each of the three years in the period ended December 31,
2003. These financial statements are the responsibility of the Companys
management. Our responsibility is to express an opinion on these financial
statements based on our audits.

We conducted our audits in accordance with auditing standards generally
accepted in Canada and the United States of America. Those standards require
that we plan and perform an audit to obtain reasonable assurance whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.

In our opinion, these consolidated financial statements present fairly, in all
material respects, the financial position of Ivanhoe Energy Inc. as at December
31, 2003 and 2002 and the results of its operations and its cash flows for each
of the three years in the period ended December 31, 2003 in accordance with
Canadian generally accepted accounting principles.

Calgary, Alberta, Canada
February 26, 2004
    
    (signed) Deloitte & Touche LLP
Chartered Accountants


COMMENTS BY AUDITORS FOR U.S. READERS ON
CANADA  U.S. REPORTING DIFFERENCES

In the United States of America, reporting standards for auditors require the
addition of an explanatory paragraph (following the opinion paragraph)
outlining changes in accounting principles that have been implemented in the
financial statements. As discussed in Note 2 to the consolidated financial
statements, the Company changed its method of accounting for asset retirement
obligations to conform to the new Canadian Institute of Chartered Accountants
Handbook recommendations Section 3110. Also, as discussed in Note 9, the
Company changed its method of accounting for stock-based compensation to
conform to the new Canadian Institute of Chartered Accountants Handbook
recommendations Section 3870.

Calgary, Alberta, Canada
February 26, 2004
    
    (signed) Deloitte & Touche LLP
Chartered Accountants


30



---



##### 



IVANHOE ENERGY INC.
Consolidated Balance Sheets
(stated in thousands of U.S. Dollars)

As at December 31,2003
    
    2002AssetsCurrent AssetsCash and cash equivalents
    
    $
    14,491
    
    
    $
    3,980Accounts receivable (Note 3)
    
    
    2,720
    
    
    
    2,519Other
    
    
    409
    
    
    
    69117,620
    
    
    
    7,190Long term assets (Note 19)
    
    
    998
    
    
    
    462Oil and gas properties, equipment and GTL investments, net (Note 4)
    
    
    87,956
    
    
    
    99,436$
    106,574
    
    
    $
    107,088Liabilities and Shareholders EquityCurrent LiabilitiesAccounts payable and accrued liabilities
    
    $
    4,516
    
    
    $
    4,797Notes payable  current portion (Note 5)
    
    
    167
    
    
    
    500Convertible debentures (Note 6)
    
    
    
    
    
    
    1,0004,683
    
    
    
    6,297Long term debt (Note 5)
    
    
    833
    
    
    
    Asset retirement obligations (Note 7)
    
    
    521
    
    
    
    243Commitments and contingencies (Note 17)Shareholders EquityShare capital, issued 161,359,000 common shares;December 31, 2002 144,466,000 common shares (Note 8)
    
    
    160,804
    
    
    
    131,112Deficit
    
    
    (60,267
    )
    
    
    (30,564
    )100,537
    
    
    
    100,548$
    106,574
    
    
    $
    107,088


See accompanying Notes to the Consolidated Financial Statements.

Approved by the Board:

(signed) David Martin
Director
    
    (signed) E. Leon Daniel
Director


31



---



##### 



IVANHOE ENERGY INC.

Consolidated Statements of Loss and Deficit
(stated in thousands of U.S. Dollars, except per share data)

Year ended December 31,2003
    
    2002
    
    2001RevenueOil and gas revenue
    
    $
    9,569
    
    
    $
    8,329
    
    
    $
    9,144Interest income
    
    
    90
    
    
    
    108
    
    
    
    5789,659
    
    
    
    8,437
    
    
    
    9,722ExpensesOperating costs
    
    
    4,293
    
    
    
    3,841
    
    
    
    4,758General and administrative and project identification
    
    
    7,919
    
    
    
    5,667
    
    
    
    8,845Depletion and depreciation
    
    
    3,829
    
    
    
    3,312
    
    
    
    3,241Write downs and provision for impairment (Notes 4 and 13)
    
    
    23,321
    
    
    
    2,436
    
    
    
    14,00039,362
    
    
    
    15,256
    
    
    
    30,844Net Loss(Note 14)
    
    
    29,703
    
    
    
    6,819
    
    
    
    21,122Deficit, beginning of year
    
    
    30,564
    
    
    
    23,495
    
    
    
    2,373Loss on acquisition of shares (Note 8)
    
    
    
    
    
    
    250
    
    
    
    Deficit, end of year
    
    $
    60,267
    
    
    $
    30,564
    
    
    $
    23,495Net Loss per Share(Note 15)
    
    $
    0.20
    
    
    $
    0.05
    
    
    $
    0.16Weighted Average Number of Shares (in thousands)(Note 15)
    
    
    150,154
    
    
    
    142,314
    
    
    
    128,598


See accompanying Notes to the Consolidated Financial Statements.

32



---



##### 



IVANHOE ENERGY INC.

Consolidated Statements of Cash Flow
(stated in thousands of U.S. Dollars)

Year ended December 31,2003
    
    2002
    
    2001Operating ActivitiesNet loss
    
    $
    (29,703
    )
    
    $
    (6,819
    )
    
    $
    (21,122
    )Items not requiring use of cashWrite downs and provision for impairment (Notes 4 and 13)
    
    
    23,321
    
    
    
    2,436
    
    
    
    14,000Depletion and depreciation
    
    
    3,829
    
    
    
    3,312
    
    
    
    3,241Changes in non-cash working capital items
    
    
    494
    
    
    
    (1,687
    )
    
    
    6,314(2,059
    )
    
    
    (2,758
    )
    
    
    2,433Investing ActivitiesCapital spending
    
    
    (15,391
    )
    
    
    (18,828
    )
    
    
    (40,504
    )Proceeds from sale of assets (Note 4)
    
    
    
    
    
    
    5,351
    
    
    
    Deposit on investment (Note 19)
    
    
    (500
    )
    
    
    
    
    
    
    Other
    
    
    (37
    )
    
    
    (65
    )
    
    
    (155
    )(15,928
    )
    
    
    (13,542
    )
    
    
    (40,659
    )Financing ActivitiesShares issued on private placements, net of share issue costs
    
    
    24,070
    
    
    
    9,964
    
    
    
    17,903Shares issued on exercise of options and warrants
    
    
    3,928
    
    
    
    119
    
    
    
    326Proceeds from notes (Note 5)
    
    
    1,750
    
    
    
    500
    
    
    
    Payments of notes (Note 5)
    
    
    (1,250
    )
    
    
    
    
    
    
    28,498
    
    
    
    10,583
    
    
    
    18,229Increase (decrease) in cash and cash equivalents, for the year
    
    
    10,511
    
    
    
    (5,717
    )
    
    
    (19,997
    )Cash and cash equivalents, beginning of year
    
    
    3,980
    
    
    
    9,697
    
    
    
    29,694Cash and cash equivalents, end of year
    
    $
    14,491
    
    
    $
    3,980
    
    
    $
    9,697Supplementary InformationRegarding Non-Cash TransactionsInvesting activities, net assets acquired (Note 4)Overriding royalties
    
    $
    
    
    
    $
    
    
    
    $
    2,852Lease acquisition
    
    
    
    
    
    
    
    
    
    
    900Accounts receivable
    
    
    
    
    
    
    
    
    
    
    200$
    
    
    
    $
    
    
    
    $
    3,952Financing activities, non-cashShares issued on coversion of debenture (Note 6)
    
    $
    1,000
    
    
    $
    
    
    
    $
    Shares issued as consideration
    
    
    
    
    
    
    
    
    
    
    3,952$
    1,000
    
    
    $
    
    
    
    $
    3,952Included in the above are the following:Taxes paid or (refunded)
    
    $
    6
    
    
    $
    (27
    )
    
    $
    104Interest paid
    
    $
    96
    
    
    $
    74
    
    
    $
    111Changes in non-cash working capital itemsAccounts receivable
    
    $
    (201
    )
    
    $
    (581
    )
    
    $
    2,794Other current assets
    
    
    282
    
    
    
    (316
    )
    
    
    497Accounts payable and accrued liabilities
    
    
    413
    
    
    
    (790
    )
    
    
    3,023$
    494
    
    
    $
    (1,687
    )
    
    $
    6,314


See accompanying Notes to the Consolidated Financial Statements.

33



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##### 



IVANHOE ENERGY INC.

Notes to the Consolidated Financial Statements
(all tabular amounts are expressed in thousands of U.S. Dollars, except per share data)

1. NATURE OF OPERATIONS

Ivanhoe Energy Inc., a Canadian company, and its subsidiaries are focused
internationally on three major strategies: 1) exploration and development of
hydrocarbons 2) enhanced oil recovery and 3) the application of heavy-to-light
oil upgrading and gas-to-liquids technologies. Operations are currently carried
out in the U.S. and China.

2. SIGNIFICANT ACCOUNTING POLICIES

These consolidated financial statements have been prepared in accordance with
generally accepted accounting principles (GAAP) in Canada. The impact of
material differences between Canadian and U.S. GAAP on the consolidated
financial statements is disclosed in Note 20.

The preparation of financial statements requires management to make estimates
and assumptions that affect the reported amounts and other disclosures in these
consolidated financial statements. Actual results may differ from those
estimates.

Change in Accounting Policy

Prior to January 2003, the Company had estimated its future site restoration
and abandonment costs associated with its oil and gas properties and amortized
this estimate to operations using the unit-of-production method based upon
estimated proved reserves. The provision was included with depletion and
depreciation expense.

For fiscal years beginning after January 1, 2004, Canadian GAAP requires that
asset retirement costs and liabilities associated with site restoration and
abandonment of tangible long-lived assets be initially measured at a fair value
which approximates the cost a third party would incur in performing the tasks
necessary to retire such assets. The fair value is recognized in the financial
statements at the present value of expected future cash outflows to satisfy the
obligation. Subsequent to the initial measurement, the effect of the passage of
time on the liability for the asset retirement obligation (accretion expense)
and the amortization of the asset retirement cost are recognized in the results
of operations.

The Company has elected early implementation of this accounting policy.
Accordingly, effective January 1, 2003, the Company changed its accounting
policy to capitalize asset retirement costs as part of the carrying value of
its oil and gas properties and adjusted the amount of its site restoration
liability to the present value of the liability for the corresponding asset
retirement obligation as of this date. The Company has adopted the policy
without retroactive adjustment of prior years because implementation of this
change had an immaterial effect on the Companys financial position and results
of operations in prior years and in the current period (See Notes 4 and 7).

U.S. GAAP for asset retirement obligations conforms in all material respects to
Canadian GAAP. Implementation for U.S. GAAP is required for fiscal years
beginning after June 2002.

The asset retirement costs are being amortized using the unit of production
method based on estimated proved reserves. The amortization expenses and
accretion of the liability for the asset retirement obligation are included
with depletion and depreciation expense.

Principles of Consolidation

These consolidated financial statements include the accounts of Ivanhoe Energy
Inc. and its subsidiaries, all of which are wholly owned. We conduct most
exploration, development and production activities in our oil and gas business
jointly with others and our accounts reflect only the Companys proportionate
interest.

All inter-company transactions and balances have been eliminated for the
purposes of these consolidated financial statements.

Foreign Currency Translation

The Company uses the U.S. Dollar as its functional currency since it is the
currency in which the worldwide petroleum business denominates its business.
Monetary assets and liabilities denominated in foreign currencies are converted
at the exchange rate in effect

34



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##### 



at the balance sheet date and non-monetary assets and liabilities at the
exchange rates in effect at the time of acquisition or issue. Revenues and
expenses are converted at rates approximating exchange rates in effect at the
time of the transactions. Exchange gains or losses resulting from the
translation of foreign currency amounts are reflected in operations.

Cash and Cash Equivalents

Cash and cash equivalents include short-term money market instruments with
terms to maturity, at the date of issue, not exceeding 90 days.

Financial Instruments

The fair value of the Companys cash and cash equivalents, accounts receivable,
accounts payable and accrued liabilities, notes payable, long term debt and
convertible debenture approximates the carrying values due to the immediate or
short-term maturity of these financial instruments.

Oil and Gas Properties

The Company follows the full cost method of accounting for oil and gas
operations whereby all exploration and development expenditures are capitalized
on a country-by-country cost center basis. Such expenditures include land
acquisition costs, geological and geophysical expenses, carrying charges for
unproved properties, costs of drilling both productive and non-productive
wells, gathering and production facilities and equipment, and financing and
administrative costs related to capital projects. The Company periodically
evaluates its unproved properties for exploration and exploitation
opportunities. If the Company determines that the exploration or exploitation
potential of an unproved property has diminished, all, or a portion, of the
costs incurred on such property is impaired and transferred to the carrying
value of evaluated oil and gas assets. Proceeds from sales of oil and gas
assets are recorded as reductions in the carrying value of oil and gas assets,
unless such amounts would significantly alter the rate of depreciation and
depletion, whereupon gains or losses would be recognized in income. Maintenance
and repair costs are expensed as incurred, while improvements and major
renovations are capitalized.

Costs of evaluated oil and gas assets accumulated within each cost center,
including a provision for future development costs, are depleted using the unit
of production method based on estimated proved reserves. Significant
development projects and expenditures on unproved properties are excluded from
the depletion calculation until evaluated.

Royalty interests acquired are included in oil and gas properties and recorded
at cost.

The carrying value of evaluated oil and gas assets, accumulated within each
cost center, net of depletion provided, future income taxes and accumulated
impairment provisions, are compared annually to the non-discounted estimated
future net revenues from proved reserves (based on year-end non-escalated
prices), net of estimated administration and carrying costs, and related
production and income taxes (ceiling test). Any accumulated costs in excess
of the calculated ceiling test are charged to operations as a provision for
impairment.

Furniture and Fixtures

Furniture and fixtures are stated at cost. Depreciation is provided on a
straight-line basis over the estimated useful life of the respective assets, at
rates ranging from three to ten years.

Oil and Gas Revenue

Sales of crude oil and natural gas are recognized in the period in which the
product is delivered to the customer.

Loss Per Share

Basic earnings per share is calculated by dividing the net earnings available
to common shareholders by the weighted average number of common shares
outstanding. Diluted earnings per share reflects the potential dilution that
would occur if stock options and warrants were exercised. The treasury stock
method is used in calculating diluted earnings per share, which assumes that
any proceeds received from the exercise of in-the-money stock options and
warrants would be used to purchase common shares at the average market price
for the period (Note 15).

35



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##### 



Income Taxes

The Company follows the liability method of accounting for future income taxes.
Under the liability method, future income taxes are recognized to reflect the
expected future tax consequences arising from tax loss carry-forwards and
temporary differences between the carrying value and the tax basis of the
Companys assets and liabilities.

Stock Based Compensation

The Company has an Employees and Directors Equity Incentive Plan consisting
of stock option, bonus and share purchase incentives (Note 9). The Company
accounts for its stock-based compensation using intrinsic-values. Compensation
costs are not recognized in the financial statements for stock options granted
to employees and directors when granted at market value. Compensation costs
are, however, recognized in the financial statements for options granted to
non-employees based on the fair value of the options at the date granted.
Consideration paid upon exercise of stock options is credited to share capital.

Compensation expenses are recognized when shares are issued from the stock
bonus plan. The share purchase portion of the plan has not yet been activated.

3. CONCENTRATION OF CREDIT RISKS

The Company sells oil and natural gas products to pipelines, refineries, major
oil companies and foreign national petroleum companies. Where possible, credit
is extended based on an evaluation of the customers financial condition and
historical payment record.

The following summarizes the revenue receivable balances and revenues from
significant customers:

Accounts Receivable as at
    
    Oil and Gas Revenues for the Year EndedDecember 31,
    
    December 31,2003
    
    2002
    
    2003
    
    2002
    
    2001U.S. CustomersA
    
    $
    407
    
    
    $
    346
    
    
    $
    4,392
    
    
    $
    2,916
    
    
    $
    2,034B
    
    
    175
    
    
    
    192
    
    
    
    986
    
    
    
    1,764
    
    
    
    2,500C
    
    
    60
    
    
    
    63
    
    
    
    273
    
    
    
    390
    
    
    
    554All Others
    
    
    15
    
    
    
    
    
    
    
    65
    
    
    
    29
    
    
    
    13657
    
    
    
    601
    
    
    
    5,716
    
    
    
    5,099
    
    
    
    5,101China CustomerA
    
    
    950
    
    
    
    767
    
    
    
    4,103
    
    
    
    3,230
    
    
    
    4,043$
    1,607
    
    
    $
    1,368
    
    
    $
    9,819
    
    
    $
    8,329
    
    
    $
    9,144


Oil and gas revenues for the year ended December 31, 2003 in the table above do
not include $0.3 million of oil hedge losses from derivative activities.

Accounts receivable as at December 31, 2003 and 2002 in the table above do not
include $0.3 million of costs billed to joint venture partners and other
receivables and $0.8 million of advances to partners for joint operations where
the Company is not the operator.

4. OIL AND GAS PROPERTIES, EQUIPMENT AND GTL INVESTMENTS

Capital assets categorized by geographic location are as follows:

December 31, 2003
    
    December 31, 2002U.S.
    
    China
    
    Total
    
    U.S.
    
    China
    
    TotalOil and gas properties and
equipment
    
    $
    85,079
    
    
    $
    32,840
    
    
    $
    117,919
    
    
    $
    76,323
    
    
    $
    26,617
    
    
    $
    102,940Accumulated depletion
    
    
    (6,442
    )
    
    
    (3,804
    )
    
    
    (10,246
    )
    
    
    (4,036
    )
    
    
    (2,326
    )
    
    
    (6,362
    )Provision for impairment
    
    
    (34,000
    )
    
    
    
    
    
    
    (34,000
    )
    
    
    (14,000
    )
    
    
    
    
    
    
    (14,000
    )44,637
    
    
    
    29,036
    
    
    
    73,673
    
    
    
    58,287
    
    
    
    24,291
    
    
    
    82,578Gas to Liquids Investments:Master license
    
    
    10,000
    
    
    
    
    
    
    
    10,000
    
    
    
    10,000
    
    
    
    
    
    
    
    10,000Feasibility studies and other deferred costs
    
    
    4,072
    
    
    
    
    
    
    
    4,072
    
    
    
    6,603
    
    
    
    
    
    
    
    6,60314,072
    
    
    
    
    
    
    
    14,072
    
    
    
    16,603
    
    
    
    
    
    
    
    16,603Support equipment
    
    
    433
    
    
    
    31
    
    
    
    464
    
    
    
    457
    
    
    
    36
    
    
    
    493Accumulated depreciation
    
    
    (253
    )
    
    
    
    
    
    
    (253
    )
    
    
    (238
    )
    
    
    
    
    
    
    (238
    )180
    
    
    
    31
    
    
    
    211
    
    
    
    219
    
    
    
    36
    
    
    
    255$
    58,889
    
    
    $
    29,067
    
    
    $
    87,956
    
    
    $
    75,109
    
    
    $
    24,327
    
    
    $
    99,436


36



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##### 



Effective January 1, 2003, the Company capitalized $0.3 million as a result of
implementation of a new accounting policy on asset retirement obligations. For
the year ended December 31, 2003, $0.1 million of future asset retirement costs
was capitalized.

During 2002, the Company sold working interests in the Spraberry field in West
Texas for $3.0 million and the Daqing project in China for $2.4 million. The
Company retains an overriding royalty in the Daqing project of 4% before cost
recovery and 2% thereafter. The sale proceeds were credited to the respective
cost centers, (Note 2), as the sales did not represent significant dispositions
of the U.S. and China total reserve bases.

Costs as at December 31, 2003 and 2002 of $31.2 million and $46.6 million,
respectively, related to unevaluated oil and gas properties are excluded from
the depletable cost centers.

For the years ended December 31, 2003 and 2002 general and administrative
expenses related directly to acquisition, exploration, development and GTL
activities of $1.8 million and $2.6 million, respectively, were capitalized.

Gas-to-Liquids

The Company owns a master license from Syntroleum Corporation permitting the
Company to use their proprietary gas-to-liquid process (GTL) in an unlimited
number of projects around the world. The Syntroleum process converts natural
gas into synthetic liquid hydrocarbons that can be utilized to develop, among
other things, clean-burning diesel fuel. In July 2003, the master license was
amended in respect of GTL projects in which both the Company and Syntroleum
participate such that no additional license fees or royalties will be payable
by the Company and that Syntroleum will contribute to any such project the
right to manufacture specialty and lubricant products. Both companies have the
right to pursue GTL projects independently, but the Company would be required
to pay the normal license fees and royalties in such projects.

Since 2000, the Company has undertaken detailed project feasibility studies for
the construction, operation and cost of world-class GTL plants in Qatar, Egypt,
Oman and Bolivia. In addition, the Company conducted marketing,
commercialization and transportation feasibility studies. Marketing studies
were conducted for both Europe and the Asia-Pacific regions for GTL diesel and
naphtha. Markets within these regions were identified and premiums for the GTL
ultra clean fuels were estimated. Product forecasts from these studies were
used to complete studies with various Japanese companies to optimize the
commercial structure for utilization of GTL diesel and NGL products.

As a result of the cancellation of Syntroleums Sweetwater project in Australia
in 2002 and the termination of contract negotiations with Qatar Petroleum and
the Qatari government to construct and operate a major GTL production facility
in Qatar without an agreement being reached in May 2003, the Company has
written down $2.4 million and $3.3 million, respectively, of its GTL
investment. Costs associated with the feasibility studies and other such
related costs remain capitalized. Recovery of the GTL costs capitalized is
dependent upon finalizing contracts to access natural gas reserves in the
respective countries and the successful completion of GTL processing plants.

United States

In 1998, the Company acquired rights to an exploration agreement (Agreement)
with Aera Energy LLC (Aera), which gave the Company access to all of Aeras
exploration, seismic and technical data in southern San Joaquin Valley in
California for the purpose of identifying drillable exploration prospects
within the exclusive area. The Agreement provided the Company the right to a
working interest ownership in all drillable prospects in which Aera elects to
participate equal to a minimum of 12.5% and a maximum of 75%. In those
prospects in which Aera elects not to participate, the Company has the right to
proceed with a 100% working interest and to seek other joint venture partners.
Aera has the right to act as the operator for any drillable prospects in which
Area elects to participate.

The Company has identified 12 prospect Areas of Mutual Interest (AMIs)
containing a total of 30 drillable prospects in which Aera has elected to
participate under the Agreement. The Companys working interests, in these
AMIs, range from 12.5% to 50%. The Company has a 100% working interest in 3
AMIs in which Aera has declined to participate. In participation with Aera, the
Company has drilled 3 wells in the AMIs, 2 of which were unsuccessful and 1,
the Northwest Lost Hills #1-22 deep gas well, has been temporarily abandoned.
In the AMIs in which Aera has declined to participate, the Company has drilled
51 producing wells in South Midway and one well in the Citrus prospect, which
is currently on production and being evaluated.

The Company has drilled 27 producing wells in the Spraberry field and 5
producing wells in the Apache Flats field in West Texas with non-operating
working interests of 62.5% and 96.15% in Spraberry and 40% in Apache Flats. In
2002, the Company sold its interests in 7 Spraberry wells for $1.4 million and
50% of its interests in the remaining 20 Spraberry wells for $1.6 million.

The Company leased mineral rights in East Texas and entered into joint venture
agreements with a subsidiary of Unocal Corp.

37



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##### 



(Unocal) under which Unocal will earn a 50% interest in the Companys
holdings by expending the next $10.1 million of costs associated with
exploration and development of prospects. Unocal has drilled three wells in two
prospects and has spent $8.5 million. The Company has farmed out its interests
in the wells, one of which is producing commercial quantities of gas and the
other two are in various stages of testing and evaluation.

Provision for impairment amounts calculated for U.S. oil and gas properties is
$20.0 million and $14.0 million for 2003 and 2001, respectively. No provision
for impairment of oil and gas properties was required for 2002. (See Note 13.)

China

The Company currently holds a production-sharing contract to develop existing
oil properties in the Dagang region. The Company has been operating the Dagang
field under a pilot phase program since 2000 and in 2003 received final
governmental approval for its Overall Development Program (ODP) of the field.
In January 2004, the Company signed farm-out and joint operating agreements
with a wholly-owned subsidiary of China International Trust and Development
Corporation (CITIC) to acquire a forty percent working interest in the Dagang
project for an up-front payment of $20.0 million. The Company and CITIC will
incur 100% of the costs to earn 82% of the production, before recovery of costs
incurred, reverting to a 49% share post recovery. (See Note 19.)

Prior to 2002, the Company held a contract to develop existing oil fields in
the Daqing region and the pilot program was completed successfully in 1998. In
January 2002, the Company was successful in disposing of the project for $2.4
million and retains an overriding royalty on future production.

During the pilot testing phase at Dagang and Daqing all production costs net of
revenues were capitalized to oil and gas properties and equipment. With the
evaluation stage completed and the decision to enter the development and
implementation stage, all operating results beginning January 1, 2001 for
Dagang and March 1, 2001 for Daqing are included in the Companys results of
operations.

In September 2002, the Company signed a 30-year production-sharing contract
with PetroChina Corporation (PetroChina). The contract area, known as the
Zitong block, is located in the northwestern portion of the Sichuan Basin.
Under the terms of the contract, the Company will develop natural gas deposits
within the block and in return will receive approximately 75% of the revenue
until costs are recovered and approximately 45% thereafter. PetroChina has the
option to participate in any successful developments, with up to a 51% working
interest. In addition, pursuant to existing exclusive arrangements, the
Company has the right to negotiate a production-sharing contract for the Yudong
block located on the eastern edge of the Sichuan Basin.

Overriding Royalties

Through a series of transactions from 1999 to 2001, the Company acquired
overriding royalties in the AMI prospects and other properties in California
ranging from 1.46% to 6.58% in consideration for $0.9 million cash and the
issuance of 2,885,000 common shares at an aggregate ascribed value of $8.0
million, being 1,562,000 common shares at $2.02; 523,000 common shares at $1.76
and 800,000 common shares at $4.94. Of the total consideration paid, $0.9
million was allocated to property acquisition costs and $0.2 million to
accounts receivable.

5. NOTES PAYABLE

The Company borrowed $1.25 million from a related party at U.S. prime plus 3%.
The unsecured loan, due 90 days after written demand or on the closing date of
obtaining equity financing or December 31, 2005, whichever occurs earliest, was
repaid with accrued interest in September 2003. The Company negotiated a
revolving credit facility of $1.25 million to re-establish or extend that loan
in the future as needs arise.

In February 2003, the Company obtained a bank facility for up to $5.0 million
to drill 30 new oil wells and upgrade surface transmission and steam injection
facilities in the southern expansion of South Midway. Interest only is payable
until June 30, 2004 at 0.25% above the banks prime rate or 2.75% over the
London Inter-Bank Offered Rate (LIBOR) at the option of the Company. After
June 30, 2004, the loan is repayable over three years plus interest at 0.50%
above the banks prime rate or 3.0% over LIBOR, at the option of the Company.
The loan is secured by all the Companys rights and interests in the South
Midway properties. The loan balance as at December 31, 2003 is $1.0 million
with a three-month fixed LIBOR rate of 4.00%.

The scheduled maturities of the bank loan payable at December 31, 2003 are as
follows:

2004
    
    $
    1672005
    
    
    3332006
    
    
    3332007
    
    
    167$
    1,000


38



---



##### 



6. CONVERTIBLE DEBENTURE

In June 2003, the lender elected to convert the $1.0 million unsecured
convertible debenture into two million of the Companys common shares at $0.50
per share. All accrued interest on the debenture was paid as of the conversion
date.

7. ASSET RETIREMENT OBLIGATION

Effective January 2003, the Company changed its policy on accounting for
liabilities associated with site restoration and abandonment of its oil and gas
properties. The undiscounted amount of expected cash flows required to settle
the asset retirement obligations is estimated at $1.0 million to be settled
over a twelve-year period starting in 2010. The liability for the expected cash
flows, as reflected in the financial statements, has been discounted at 7%.
Implementation of the policy resulted in an additional provision for asset
retirement of $0.2 million. For the year ended December 31, 2003, $0.1 million
was added to the carrying amount of the asset retirement obligations.

8. SHARE CAPITAL

The authorized capital of the Company consists of an unlimited number of common
shares without par value and an unlimited number of preferred shares without
par value.

The total number of issued and outstanding common shares is as follows:

Number ofCommon Shares
    
    Amount(thousands)Balance December 31, 2000
    
    
    126,874
    
    
    $
    98,211Issued for private placements, net
    
    
    11,260
    
    
    
    17,903Issued on exercise of warrants
    
    
    127
    
    
    
    166Issued on exercise of options
    
    
    206
    
    
    
    160Issued on acquisition of overriding royalties (Note 4)
    
    
    800
    
    
    
    3,952Balance December 31, 2001
    
    
    139,267
    
    
    
    120,392Issued for private placements, net
    
    
    5,000
    
    
    
    9,964Issued on exercise of options
    
    
    163
    
    
    
    119Issued for services
    
    
    201
    
    
    
    387Elimination of employee loans
    
    
    
    
    
    
    409Retirement of
shares
    
    
    (165
    )
    
    
    (159
    )Balance December 31, 2002
    
    
    144,466
    
    
    
    131,112Issued for private placements, net
    
    
    12,654
    
    
    
    24,070Issued
on conversion of debenture (Note 6)
    
    
    2,000
    
    
    
    1,000Issued on exercise of warrants
    
    
    250
    
    
    
    425Issued on exercise of options
    
    
    1,363
    
    
    
    3,502Issued for services
    
    
    626
    
    
    
    695Balance December 31, 2003
    
    
    161,359
    
    
    $
    160,804


The Company loaned $0.4 million to an employee and two directors to facilitate
their exercise of stock options and warrants to purchase 165,000 common shares
of the Company. The Company held the shares as collateral for the loans. The
loan balances were previously netted against the share capital balances. In
December 2002, the Company determined the loans would not be renewed when they
became due in December 2002 and January 2003. Each of the borrowers authorized
the Company to acquire the shares held as collateral in full payment of their
loan amounts and accrued interest, thereon. Subsequently, the Company
eliminated the loans and retired the 165,000 common shares at the average price
of all common shares then issued and outstanding ($0.96 per share) and recorded
a $0.25 million loss to retained earnings.

Private Placements and Share Purchase Warrants

Under private placements in 2001 and 2002, the Company issued 11.3 million
common shares at $1.60 and 5.0 million common shares at $2.00, for net proceeds
of $17.9 million and $10.0 million, respectively.

In 2003, the Company closed four special warrant financings to advance its
worldwide exploration and production, enhanced oil recovery and GTL activities,
to pay down or restructure certain business indebtedness and for general
working capital purposes. The financings consisted of 12.7 million special
warrants from $1.00 to $4.00 per special warrant. Each special warrant entitles
the holder to acquire one common share and purchase warrants, at no additional
cost. The purchase warrants are exercisable to purchase additional common
shares through the anniversary dates of the special warrant financing at the
price per share as indicated in the following table:

39



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##### 



First Anniversary
    
    Second AnniversaryRemaining Number of
    
    Number of
    
    
    
    
    
    Price per Share
    
    
    
    
    
    Price per SharePurchase Warrants
    
    Common Shares
    
    Date
    
    (US$)
    
    Date
    
    (US$)(thousands)3,000
    
    
    1,500
    
    
    July 3,  2004
    
    $
    1.00
    
    
    July 3, 2005
    
    $
    1.103,000
    
    
    1,500
    
    
    August 18, 2004
    
    $
    1.00
    
    
    August 18, 2005
    
    $
    1.103,029
    
    
    1,515
    
    
    August 21, 2004
    
    $
    1.70
    
    
    August 21, 2005
    
    $
    1.873,125
    
    
    1,250
    
    
    October 31, 2004
    
    $
    4.00
    
    
    October 31, 2005
    
    $
    4.30


In November 2003, 500 thousand purchase warrants for $1.70 per share were
exercised for the purchase of 250 thousand shares.

9. STOCK BASED COMPENSATION

The Company has an Employees and Directors Equity Incentive Plan under which
it can grant stock options to directors, officers and employees to purchase
common shares, issue common shares to directors and employees for bonus awards
and issue shares under a share purchase plan for employees.

Stock options are issued at not less than the quoted market value on the date
of the grant and are conditional on continuing employment. Expiration and
vesting periods are set at the discretion of the Board of Directors. Options
granted prior to March 1, 1999 vested over a two-year period and expire ten
years from date of issue. Options granted after March 1, 1999 vest over four
years and expire five years from the date of issue.

Following is a summary of the stock option portion of the Companys Equity
Incentive Plan, including changes during the years ended:

December 31, 2003
    
    December 31, 2002
    
    December 31, 2001Weighted-
    
    
    
    
    
    Weighted-
    
    
    
    
    
    Weighted-Number
    
    Average
    
    Number
    
    Average
    
    Number
    
    Averageof
    
    Exercise
    
    of
    
    Exercise
    
    of
    
    ExerciseOptions
    
    Price
    
    Options
    
    Price
    
    Options
    
    Price(000s)
    
    (Cdn.$)
    
    (000s)
    
    (Cdn.$)
    
    (000s)
    
    (Cdn.$)Outstanding at beginning of
year
    
    
    10,265
    
    
    $
    2.69
    
    
    
    8,635
    
    
    $
    2.66
    
    
    
    8,161
    
    
    $
    2.45Granted
    
    
    840
    
    
    $
    4.95
    
    
    
    2,095
    
    
    $
    2.86
    
    
    
    846
    
    
    $
    4.63Exercised
    
    
    (1,363
    )
    
    $
    3.39
    
    
    
    (164
    )
    
    $
    1.57
    
    
    
    (206
    )
    
    $
    1.40Cancelled/forfeited
    
    
    (793
    )
    
    $
    4.42
    
    
    
    (301
    )
    
    $
    3.48
    
    
    
    (166
    )
    
    $
    4.04Outstanding at end of year
    
    
    8,949
    
    
    $
    2.64
    
    
    
    10,265
    
    
    $
    2.69
    
    
    
    8,635
    
    
    $
    2.66Options exercisable at year
end
    
    
    6,974
    
    
    $
    2.20
    
    
    
    7,122
    
    
    $
    2.13
    
    
    
    6,089
    
    
    $
    1.73


Effective January 2002, Canadian accounting standards require disclosure, on a
pro forma basis, of the impact on net income of using the fair value method for
stock options granted to employees and directors on or after that date. The
Company accounts for its stock-based compensation plans using the
intrinsic-value of the options. Under this method, compensation costs are not
recognized in the financial statements for share options granted to employees
and directors when issued at market value. Had stock based compensation expense
been determined based on the fair value at the option grant date, the Companys
net loss and net loss per share for the years ended December 31 2003 and 2002
would have been as follows:

Year ended December 31,2003
    
    2002Pro forma net loss
    
    $
    30,179
    
    
    $
    7,130Pro forma net loss per share
    
    $
    0.20
    
    
    $
    0.05


The foregoing is calculated in accordance with Black-Scholes options pricing
model, using the following data and assumptions: 72% to 100% price volatility,
using the prior two years weekly average prices of the Companys common shares;
expected dividend yield of 0%; option terms to expiry of 5 years, as defined by
the option agreements; risk-free rate of return as of the date of the grant of
4.08% to 5.58%, based on one and five year Government of Canada Bond yields.

The following table summarizes information respecting stock options outstanding
as at December 31, 2003:

Options Outstanding
    
    Options ExercisableWeighted-Average
    
    Weighted-
    
    
    
    
    
    Weighted-Range of
    
    Number
    
    Remaining
    
    Average
    
    Number
    
    AverageExercise Prices
    
    Outstanding
    
    Contractual Life
    
    Exercise Price
    
    Exercisable
    
    Exercise Price(Cdn.$)
    
    (000s)
    
    Yrs.
    
    (Cdn.$)
    
    (000s)
    
    (Cdn.$)$0.50 to $2.00
    
    
    4,286
    
    
    
    4.6
    
    
    $
    0.62
    
    
    
    4,001
    
    
    $
    0.55$2.50 to $3.60
    
    
    2,360
    
    
    
    2.1
    
    
    $
    2.89
    
    
    
    1,584
    
    
    $
    2.76$5.15 to $7.60
    
    
    2,303
    
    
    
    2.7
    
    
    $
    6.16
    
    
    
    1,389
    
    
    $
    6.30$0.50 to $7.60
    
    
    8,949
    
    
    
    3.4
    
    
    $
    2.64
    
    
    
    6,974
    
    
    $
    2.20


40



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##### 



10. RETIREMENT PLAN

In 2001, the Company adopted a defined contribution retirement or thrift plan
(401(k) Plan) to assist U.S. employees in providing for retirement or other
future financial needs. Employees contributions (up to the maximum allowed by
U.S. tax laws) are matched 50% by the Company in 2001 and increasing 10% per
year thereafter to a maximum of 100%. The Companys matching contributions to
the 401(k) Plan during 2003, 2002 and 2001 were $0.2 million for 2003 and $0.1
million per year for 2002 and 2001.

11. SEGMENT INFORMATION

Geographic segment results from operations for the years ended December 31,
2003, 2002 and 2001 are detailed below. The Company maintains a corporate
office in Canada with its operational office in the U.S. For this section any
amounts for Canada are included in the U.S. segment.

Year ended December 31, 2003U.S.
    
    China
    
    TotalOil and gas revenue
    
    $
    5,466
    
    
    $
    4,103
    
    
    $
    9,569Interest income
    
    
    90
    
    
    
    
    
    
    
    905,556
    
    
    
    4,103
    
    
    
    9,659Operating costs
    
    
    2,313
    
    
    
    1,980
    
    
    
    4,293Depletion and depreciation
    
    
    2,351
    
    
    
    1,478
    
    
    
    3,829Provision for impairment (Note 13)
    
    
    20,000
    
    
    
    
    
    
    
    20,00024,664
    
    
    
    3,458
    
    
    
    28,122Segment loss (income) before the following
    
    $
    19,108
    
    
    $
    (645
    )
    
    
    18,463Write down of GTL assets (Note 4)
    
    
    
    
    
    
    
    
    
    
    3,321General and administrative and project identification
    
    
    
    
    
    
    
    
    
    
    7,919Net loss
    
    
    
    
    
    
    
    
    
    $
    29,703Capital expenditures:Oil and gas
    
    $
    8,386
    
    
    $
    6,213
    
    
    $
    14,599Gas-to-liquids
    
    
    
    
    
    
    
    
    
    
    792$
    15,391Identifiable Assets:Oil & gas
    
    $
    61,379
    
    
    $
    30,766
    
    
    $
    92,145Gas-to-liquids
    
    
    
    
    
    
    
    
    
    
    14,429$
    106,574


41



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##### 



Year ended December 31, 2002U.S.
    
    China
    
    TotalOil and gas revenue
    
    $
    5,099
    
    
    $
    3,230
    
    
    $
    8,329Interest income
    
    
    108
    
    
    
    
    
    
    
    1085,207
    
    
    
    3,230
    
    
    
    8,437Operating costs
    
    
    2,351
    
    
    
    1,490
    
    
    
    3,841Depletion and depreciation
    
    
    2,110
    
    
    
    1,202
    
    
    
    3,3124,461
    
    
    
    2,692
    
    
    
    7,153Segment income before the following
    
    $
    746
    
    
    $
    538
    
    
    
    1,284Write down of GTL assets (Note 4)
    
    
    
    
    
    
    
    
    
    
    2,436General and administrative and project identification
    
    
    
    
    
    
    
    
    
    
    5,667Net loss
    
    
    
    
    
    
    
    
    
    $
    6,819Capital expenditures:Oil and gas
    
    $
    13,305
    
    
    $
    3,626
    
    
    $
    16,931Gas-to-liquids
    
    
    
    
    
    
    
    
    
    
    1,897$
    18,828Identifiable Assets:Oil and gas
    
    $
    64,448
    
    
    $
    25,281
    
    
    $
    89,729Gas-to-liquids
    
    
    
    
    
    
    
    
    
    
    17,359$
    107,088


Year ended December 31, 2001U.S.
    
    China
    
    TotalOil and gas revenue
    
    $
    5,101
    
    
    $
    4,043
    
    
    $
    9,144Interest income
    
    
    578
    
    
    
    
    
    
    
    5785,679
    
    
    
    4,043
    
    
    
    9,722Operating costs
    
    
    2,421
    
    
    
    2,337
    
    
    
    4,758Depletion and depreciation
    
    
    2,117
    
    
    
    1,124
    
    
    
    3,241Provision for impairment (Note 13)
    
    
    14,000
    
    
    
    
    
    
    
    14,00018,538
    
    
    
    3,461
    
    
    
    21,999Segment loss (income) before the following
    
    $
    12,859
    
    
    $
    (582
    )
    
    
    12,277General and administrative and project identification
    
    
    
    
    
    
    
    
    
    
    8,845Net loss
    
    
    
    
    
    
    
    
    
    $
    21,122Capital expenditures:Oil and gas
    
    $
    33,799
    
    
    $
    6,568
    
    
    $
    40,367Gas-to-liquids
    
    
    
    
    
    
    
    
    
    
    3,889$
    44,256Identifiable Assets:Oil and gas
    
    $
    61,750
    
    
    $
    25,067
    
    
    $
    86,817Gas-to-liquids
    
    
    
    
    
    
    
    
    
    
    17,186$
    104,003


42



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##### 



12. DERIVATIVE ACTIVITIES

The Companys results of operations are sensitive mainly to fluctuations in oil
and natural gas prices. The Company may periodically use different types of
derivative instruments to manage its exposure to price volatility, thus
mitigating fluctuations in commodity-related cash flows.

The Company entered into costless collar derivatives to hedge its cash flow
from the sale of 500 barrels of oil production per day over two six-month
periods starting October 2002 and June 2003. The derivatives had ceiling prices
of $30.45 and $28.95 per barrel for the June 2003 and October 2002 contracts,
respectively, and a floor price of $24.00 per barrel using WTI as the index
traded on the NYMEX. Gains and losses on derivatives are recognized in earnings
as they are realized. For the year ended December 31, 2003, the Company had
realized losses of $0.3 million on derivative transactions. The Company had
insignificant realized derivative losses for the year ended December 31, 2002.
The derivative losses are included in oil and gas revenue.

In conjunction with the October 2002 hedge, the Company posted collateral of
$0.6 million as security for the hedge. The collateral accrued interest at the
U.S. Federal Funds rate. The collateral was returned upon maturity of the hedge
contract in April 2003. As at December 31, 2002, the $0.6 million collateral is
included in other current assets.

The mark-to-market value of the derivatives is a liability of $0.1 million as
at December 31, 2002. There are no hedge contracts outstanding as at December
31, 2003.

13. PROVISION FOR IMPAIRMENT

The $20.0 million provision for impairment for 2003 is due mainly to an
increase in the carrying costs of the Companys evaluated U.S. oil and gas
assets primarily in East Texas, Northwest Lost Hills and other California
prospects when compared to the estimated recoverable value of its U.S. proved
reserves as at December 31, 2003. Such carrying costs increased as a result of
the decision, in the fourth quarter of 2003, to potentially farm-out up to 50%
of the Companys working interest to one or more partners to fund a test of
Northwest Lost Hills # 1-22. Additionally, evaluation of significant portions
of the Companys acreage positions in East Texas and the southern San Joaquin
Valley in California was completed in 2003 and either have been, or will be,
relinquished, thus adding to the carrying value of the Companys evaluated U.S.
oil and gas assets. The $14.0 million impairment for 2001 was mainly due to a
decline in oil and gas prices thus reducing the estimated recoverable value of
proved reserves as at December 31, 2001.

14. INCOME TAXES

The Company and its subsidiaries are required to individually file tax returns
in each of the jurisdictions in which they operate. Details of the
determination of the actual income tax expense for each of the three years are
detailed below. The loss of approximately $35.0 million from the Russian
operations in 2000, being the aggregate investment, not including accounting
write-downs, less proceeds received on settlement is a capital loss for
Canadian income tax purposes, available for carry-forward against future
Canadian capital gains indefinitely.

Year ended December 31,2003
    
    2002
    
    2001Loss before income taxes
    
    $
    29,703
    
    
    $
    6,819
    
    
    $
    21,122Composite statutory income tax rate
    
    
    43.20
    %
    
    
    43.20
    %
    
    
    43.20
    %Expected income tax recovery
    
    $
    (12,832
    )
    
    $
    (2,946
    )
    
    $
    (9,125
    )Tax benefit not recognized
    
    
    12,832
    
    
    
    2,946
    
    
    
    9,125Income tax expense
    
    $
    
    
    
    $
    
    
    
    $
    


The tax loss carry-forwards in Canada are Cdn. $51.8 million and in the U.S.
$57.7 million. The tax loss carry-forwards in Canada expire between 2004 and
2010 and in the U.S. between 2018 and 2023. In China, the Company has available
for carry-forward against future Chinese income $42.2 million of cost basis.
The Companys carrying value of assets for accounting purposes is $23.0 million
greater than that available for tax purposes.

Due to the uncertainty of utilizing these net tax assets, the Company has made
a valuation allowance of an equal amount against these potential recoverable
amounts as detailed below.

As at December 31,2003
    
    2002
    
    2001Future net tax assets
    
    $
    40,500
    
    
    $
    31,607
    
    
    $
    27,082Valuation allowance
    
    
    (40,500
    )
    
    
    (31,607
    )
    
    
    (27,082
    )Net future tax liability
    
    $
    
    
    
    $
    
    
    
    $
    


43



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##### 



15. NET LOSS PER SHARE

Had the Company generated net earnings during the years presented, the earnings
per share calculations for the years presented would have included the
following weighted average items:

Year ended December 31,(000's)2003
    
    2002
    
    2001Warrants
    
    
    556
    
    
    
    
    
    
    
    Convertible debenture
    
    
    499
    
    
    
    1,299
    
    
    
    545Stock options
    
    
    3,535
    
    
    
    2,986
    
    
    
    4,0184,590
    
    
    
    4,285
    
    
    
    4,563


Additionally, the earnings per share calculations would not have included
the following weighted average items because the exercise prices exceeded the
average market prices of the common shares:

Year ended December 31,(000's)2003
    
    2002
    
    2001Warrants
    
    
    140
    
    
    
    
    
    
    
    2,500Convertible debenture
    
    
    306
    
    
    
    
    
    
    
    Stock options
    
    
    3,802
    
    
    
    5,359
    
    
    
    2404,248
    
    
    
    5,359
    
    
    
    2,740


16. RELATED PARTY TRANSACTIONS

The Company has entered into agreements with a number of entities, some of
which are related through common directors or shareholders, to share
administrative personnel, aircraft, office space and facilities. The agreement
for the usage of aircraft was terminated in 2003. The Company is billed on a
cost recovery basis. The costs incurred in the normal course of business with
respect to the above arrangements amounted to $0.9 million for 2003, $1.2
million for 2002 and $2.7 million for 2001. In addition, a company controlled
by a director provides consulting services to the Company. Consulting services
and out of pocket expenses paid to this company were $0.4 million for 2003 and
2002 and $0.7 million for 2001. At year-end, amounts included in accounts
payable under these arrangements totaled $0.1 million in 2003, $0.8 million in
2002 and $1.1 million in 2001.

The Company borrowed $1.25 million from a related company controlled by a
director of the Company. The loan, plus accrued interest, was repaid in
September 2003. (See Note 5)

17. COMMITMENTS AND CONTINGENCIES

With the signing of the production-sharing contract in September 2002 for the
Zitong block, the Company is obligated to conduct a minimum exploration program
during the first three years, which will include acquiring seismic data,
reprocessing existing seismic and drilling two exploration wells. At the end of
the three-year period, if the Company does not complete the minimum exploration
program, and elects not to continue, it will be obligated to pay, to PetroChina
within 30 days, a cash equivalent of the deficiency in the work program. The
remaining cost of the minimum exploration program is estimated to be at least
$16.6 million as at December 31, 2003.

The Company has temporarily abandoned Northwest Lost Hills #1-22 pending the
identification of one or more partners to share the costs of the testing
program. If the well were permanently abandoned, the Company would be obligated
for its share of the costs to plug and abandon the well, which is estimated to
be $1.1 million. There is no provision in the balance sheet for this contingent
obligation.

18. LEASE COMMITMENTS

For the years ended December 31, 2003, 2002 and 2001, the Company expended $0.5
million, $0.6 million and $0.6. million, respectively, on operating leases
relating to the rental of office space, which expire between April 2005 and
March 2007. Such leases frequently provide for renewal options and require the
Company to pay for utilities, taxes, insurance and maintenance expenses. As at
December 31, 2003, future net minimum lease payments for operating leases
(excluding oil and gas and other mineral leases) were the following:

2004
    
    $
    5332005
    
    
    4422006
    
    
    3062007
    
    
    51Total minimum lease payments
    
    $
    1,332


44



---



##### 



19. SUBSEQUENT EVENTS

In January 2004, the Company signed a Stock Purchase and Shareholders
Agreement with Ensyn Group Inc. and its subsidiary, Ensyn Petroleum
International Ltd (Ensyn), pursuant to which we acquired a 10% equity
interest in Ensyn and exclusive rights to use the proprietary Ensyn RTPTM
Process in several key international markets. The Company will pay $2.0 million
and grant Ensyn rights to acquire equity interests in the Companys
international oil development projects that use the Ensyn RTPTM Process. The
purchase price for the 10% equity interest in Ensyn will be paid in four equal
installments and completion of the acquisition is subject to the attainment of
specific milestones: (1) upon signing the heads of agreement, (2) upon signing
the Stock Purchase and Shareholders Agreement, (3) upon Ensyn delivering a
commercial demonstration facility to California and (4) upon confirmation of
the economic viability of the Ensyn RTPTM Process from the commercial
demonstration facility. The first payment of $0.5 million was made in December
2003 and is included in long-term assets.

In January 2004, the Company signed farm-out and joint operating agreements
with Richfirst Holdings Limited (Richfirst), a wholly-owned subsidiary of
CITIC to jointly develop the Dagang oil project, operated by the Companys
wholly owned subsidiary, Sunwing Energy Ltd (Sunwing). Richfirst will
acquire a 40% working interest in the project following regulatory approvals
and an up-front payment of $20.0 million. The assignment of the interest to
Richfirst is subject to the approval of China National Petroleum Corporation
and the Ministry of Commerce of the Peoples Republic of China. The farm-out
agreement permits Richfirst to exchange its working interest in the Dagang
Project for common shares in the Company or Sunwing, should the Company seek
and secure a public listing for Sunwing.

In February 2004, the Company farmed into the Knights Landing project, which is
a 14,000-acre block located in the Sutter and Yolo counties, in northern
California. Under this exploration and development farm-in agreement, the
Company purchased, for $1.0 million, a 50% non-operated interest in four recent
discoveries in the contract area and agreed to fund, for $0.6 million, gas
gathering, surface treatment facilities and meters to connect the four wells to
an existing pipeline system. The agreement also provides for the Company to
participate, at its election, in drilling additional exploration wells in the
lease block.

In February 2004, the Company arranged a special warrant financing to advance
the Companys worldwide oil and gas operations and for general corporate
purposes. The financing consists of 5,448,276 million special warrants at $2.90
per special warrant. Each special warrant entitles the holder to acquire one
common share and one-half of a common share purchase warrant at no additional
cost. One common share purchase warrant is exercisable to purchase an
additional common share at $3.00 until February 15, 2005 and at $3.20 until
February 15, 2006.

20. ADDITIONAL DISCLOSURES REQUIRED UNDER U.S. GENERALLY ACCEPTED ACCOUNTING
PRINCIPLES (GAAP)

The Companys consolidated financial statements have been prepared in
accordance with GAAP as applied in Canada. In the case of the Company, Canadian
GAAP conforms in all material respects with U.S. GAAP except for certain
matters, the details of which are as follows:

Consolidated Statements of Loss

As discussed under Oil and Gas Properties in this note, there is a difference
in performing the ceiling test evaluation under full cost accounting between
U.S. and Canadian GAAP. Application of the ceiling test evaluation under U.S.
GAAP as at December 31, 2001 required an additional $10.0 million provision for
impairment with respect to the Companys China properties.

The capitalization of development costs permitted under Canadian GAAP in
connection with our GTL prospects is not permitted under U.S. GAAP. In
addition, under U.S. GAAP interest income would be classified as other income.

The application of U.S. GAAP has the following effects on net loss and net loss
per share as reported:

Year ended December 31,2003
    
    2002
    
    2001Net loss under Canadian GAAP
    
    $
    29,703
    
    
    $
    6,819
    
    
    $
    21,122Additional provision for impairment of China properties under U.S. GAAP
    
    
    
    
    
    
    
    
    
    
    10,000Depletion adjustment  China
    
    
    (88
    )
    
    
    (78
    )
    
    
    Write-down of GTL development costs under U.S. GAAP, net
    
    
    (2,529
    )
    
    
    1,461
    
    
    
    5,142Net loss under U.S. GAAP
    
    $
    27,086
    
    
    $
    8,202
    
    
    $
    36,264Net loss per share under U.S. GAAP Basic
    
    $
    0.18
    
    
    $
    0.06
    
    
    $
    0.28Weighted average shares outstanding under U.S. GAAP (in thousands) Basic
    
    
    150,154
    
    
    
    142,314
    
    
    
    128,598


45



---



##### 



Under U.S. GAAP, changes in the fair value of derivative instruments that meet
specific cash-flow hedge accounting criteria are reported in other
comprehensive income (OCI). The gains and losses on cash-flow hedge
transactions that are reported in OCI are reclassified to earnings in the
period in which earnings are affected by changes in the cash flow of the
underlying hedged item. The Companys hedging contracts qualify for hedge
accounting treatment. The mark-to-market value of these derivatives as at
December 31, 2002 is a liability of $0.1 million, which comprises the balance
of OCI as at December 31, 2002.

Stock based compensation

The Company has a stock-based compensation plan as more fully described in Note
9. With regards to its stock option plan, the Company applies APB Opinion No.
25, as interpreted by FASB (FIN) 44, in accounting for this plan and
accordingly no compensation cost has been recognized for stock options issued
to employees and directors. Had compensation expense been determined based on
fair value at the stock option grant date, consistent with the method of SFAS
No. 123, Accounting for Stock-Based Compensation, the Companys net loss and
net loss per share would have been increased to the pro forma amounts indicated
below:

Year ended December 31,2003
    
    2002
    
    2001Net loss under U.S. GAAP
    
    $
    27,086
    
    
    $
    8,202
    
    
    $
    36,264Stock-based compensation expense determined under
fair-value based method for all awards
    
    
    1,682
    
    
    
    1,885
    
    
    
    1,827Pro forma net loss under U.S. GAAP
    
    $
    28,768
    
    
    $
    10,087
    
    
    $
    38,091Net loss per common share under U.S
GAAP:Basic  as reported
    
    $
    0.18
    
    
    $
    0.06
    
    
    $
    0.28Basic  pro forma
    
    $
    0.19
    
    
    $
    0.07
    
    
    $
    0.30Stock options granted during period (thousands)
    
    
    690
    
    
    
    1,870
    
    
    
    846Weighted average exercise price
    
    $
    4.00
    
    
    $
    1.92
    
    
    $
    2.99Weighted average fair value of options granted during the
period
    
    $
    2.83
    
    
    $
    1.07
    
    
    $
    1.92


The foregoing is calculated in accordance with Black-Scholes option pricing
model, using the following data and assumptions: 59% to 108% price volatility,
using the prior one to three-year weekly average prices of the Companys common
shares; expected dividend yield of 0%; option terms to expiry of 5 to 10 years,
as defined by the option agreements; risk-free rate of return as of the date of
the grant of 4.08% to 5.70%, based on one and four year Government of Canada
Bond yields.

Consolidated Balance Sheets

The application of U.S. GAAP would have the following effects on balance sheet
items as reported:

Shareholders Equity

Shareholders equity at December 31, 2003 under Canadian
GAAP
    
    $
    100,537Adjustment to ascribed value of shares issued for royalty
interests
    
    
    1,358Impairment provision for China properties required under
U.S. GAAP
    
    
    (10,000
    )Depletion adjustment  China
    
    
    166Write-down of GTL development costs required under U.S. GAAP
    
    
    (4,074
    )Shareholders equity at December 31, 2003 under U.S. GAAP
    
    $
    87,987Shareholders equity at December 31, 2002 under Canadian
GAAP
    
    $
    100,548Adjustment to ascribed value of shares issued for royalty
interests
    
    
    1,358Impairment provision for China properties required under
U.S. GAAP
    
    
    (10,000
    )Depletion adjustment  China
    
    
    78Write-down of GTL development costs required under U.S. GAAP
    
    
    (6,603
    )OCI  Derivative mark- to-market adjustment
    
    
    (102
    )Shareholders equity at December 31, 2002 under U.S. GAAP
    
    $
    85,279


The shareholders approved, on June 22, 1999, the reduction of stated capital in
respect of the common shares by an amount of $74.4 million being equal to the
accumulated deficit as at December 31, 1998. Under U.S. GAAP, a reduction of
the deficit such as this is

46



---



##### 



not recognized except in the case of a quasi reorganization. The effect of this
is that under U.S. GAAP, share capital and deficit each are increased by $74.4
million at December 31, 2003 and 2002. As a result, shareholders equity under
U.S. GAAP would comprise the following:

As at December 31,2003
    
    2002Share capital (including adjustments above)
    
    $
    236,617
    
    
    $
    206,925Deficit (including adjustments above)
    
    
    (148,630
    )
    
    
    (121,544
    )Accumulated other comprehensive income
    
    
    
    
    
    
    (102
    )$
    87,987
    
    
    $
    85,279


Oil and Gas Properties

There are certain differences between the full cost method of accounting for
oil and gas assets as applied in Canada and as applied in the U.S. The
principal difference results in the method of performing ceiling test
evaluations under the full cost accounting rules. Under Canadian GAAP,
non-discounted future net revenues from oil and gas production, less an
estimate for future general and administrative expenses, financing costs and
income taxes are compared to the carrying value of the evaluated oil and gas
assets, whereas for U.S. GAAP future net revenues are discounted to present
value at 10% per annum and compared to the carrying value of the evaluated oil
and gas assets. The Company has performed the ceiling test in accordance with
U.S. GAAP and determined that there would be an additional provision for
impairment required in connection with the Companys China properties of $10.0
million for 2001. No additional impairment provisions are required for 2003,
and no impairment provision was required for 2002.

For U.S. GAAP purposes, the aggregate value attributed to the acquisition of
royalty rights is $1.4 million higher, due to the difference between Canadian
and U.S. GAAP in the value ascribed to the shares issued, primarily resulting
from differences in the recognition of effective dates of the transactions.

The categories of costs included in the cost of oil and gas properties,
equipment and GTL investments, including the adjustments in accordance with
U.S. GAAP, to the ascribed value of shares issued for royalty interests of $1.4
million, an additional provision for impairment of the Companys China
properties of $10.0 million and the write-down of GTL development costs are as
follows:

As at December 31,2003
    
    2002
    
    2001Property acquisition costs
    
    $
    17,518
    
    
    $
    16,868
    
    
    $
    15,956Royalty rights acquired
    
    
    10,582
    
    
    
    10,582
    
    
    
    10,582Exploration costs
    
    
    34,908
    
    
    
    31,760
    
    
    
    20,918Development costs
    
    
    56,269
    
    
    
    45,088
    
    
    
    45,325GTL license
    
    
    10,000
    
    
    
    10,000
    
    
    
    12,000Support equipment
    
    
    464
    
    
    
    493
    
    
    
    468129,741
    
    
    
    114,791
    
    
    
    105,249Accumulated depletion and depreciation
    
    
    (10,334
    )
    
    
    (6,523
    )
    
    
    (3,437
    )Provision for impairment
    
    
    (44,000
    )
    
    
    (24,000
    )
    
    
    (24,000
    )$
    75,407
    
    
    $
    84,268
    
    
    $
    77,812


Development costs as at December 31, 2003 include $0.4 million of asset
retirement costs.

As at December 31, 2003, the costs of unevaluated properties included in
capital assets are as follows:

Incurred InTotal
    
    2003
    
    2002
    
    2001
    
    Prior to 2001Property acquisition costs
    
    $
    9,874
    
    
    $
    2,318
    
    
    $
    1,686
    
    
    $
    4,642
    
    
    $
    1,228Royalty rights acquired
    
    
    8,095
    
    
    
    
    
    
    
    
    
    
    
    3,509
    
    
    
    4,586Exploration costs
    
    
    14,562
    
    
    
    2,925
    
    
    
    4,008
    
    
    
    4,222
    
    
    
    3,407$
    32,531
    
    
    $
    5,243
    
    
    $
    5,694
    
    
    $
    12,373
    
    
    $
    9,221


Accounts payable and accrued liabilities

The following is the breakdown of accounts payable and accrued liabilities:

As atDecember 31,2003
    
    2002Accounts payable
    
    $
    3,626
    
    
    $
    4,387Accrued salaries and related expenses
    
    
    858
    
    
    
    348Fair market value of oil hedge
    
    
    
    
    
    
    102Accrued interest
    
    
    2
    
    
    
    10Other accruals
    
    
    30
    
    
    
    52Total
    
    $
    4,516
    
    
    $
    4,899


47



---



##### 



Consolidated Statements of Cash Flow

As a result of the write-down of GTL development costs required under U.S.
GAAP, the statement of cash flow as reported would result in cash deficiencies
from operating activities of $2.9 million, $4.7 million and $1.5 million for
the years ended December 31, 2003, 2002 and 2001, respectively, and capital
spending reported under investing activities would be $14.6 million, $16.9
million and $36.6 million for the same periods ended, respectively.

Impact of New and Pending U.S. GAAP Accounting Standards

The following standards issued by the FASB do not impact us:



| |  |  | Interpretation No. 46, Consolidation of Variable Interest Entities,
effective for financial statements issued after January 31, 2003.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------



| |  |  | SFAS No. 150, Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity, effective for financial
statements issued after June 15, 2003.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | SFAS No. 132 (revised 2003), Employers Disclosures about Pensions
and Other Post Retirements Benefits  an amendment of SFAS No. 87, 88
and 106, effective for financial statements issued after December 15,
2003.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | SFAS No. 149, Amendment of Statement 133 on Derivative Instruments
and Hedging Activities, effective for contracts entered into or
modified after June 30, 2003.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------

QUARTERLY FINANCIAL DATA IN ACCORDANCE WITH CANADIAN AND U.S. GAAP (UNAUDITED)

QUARTER ENDEDMarch 31
    
    June 30
    
    September 30
    
    December 312003
    
    2002
    
    2003
    
    2002
    
    2003
    
    2002
    
    2003
    
    2002Oil and gas
revenues
    
    $
    2,531
    
    
    $
    1,663
    
    
    $
    2,332
    
    
    $
    1,981
    
    
    $
    2,405
    
    
    $
    2,328
    
    
    $
    2,301
    
    
    $
    2,357Operating
profit
    
    $
    1,633
    
    
    $
    807
    
    
    $
    1,384
    
    
    $
    969
    
    
    $
    1,257
    
    
    $
    1,258
    
    
    $
    1,002
    
    
    $
    1,454Net loss under Canadian
GAAP
    
    $
    998
    
    
    $
    1,521
    
    
    $
    4,465
    
    
    $
    1.107
    
    
    $
    1,206
    
    
    $
    3,064
    
    
    $
    23,034
    
    
    $
    1,127Net loss under U.S
GAAP
    
    $
    1,185
    
    
    $
    2,131
    
    
    $
    1,325
    
    
    $
    1,808
    
    
    $
    1,306
    
    
    $
    2,976
    
    
    $
    23,270
    
    
    $
    1,287Net loss per share under Canadian GAAP
    
    $
    0.01
    
    
    $
    0.01
    
    
    $
    0.03
    
    
    $
    0.01
    
    
    $
    0.01
    
    
    $
    0.02
    
    
    $
    0.15
    
    
    $
    0.01Net loss per share under U.S
GAAP
    
    $
    0.01
    
    
    $
    0.02
    
    
    $
    0.01
    
    
    $
    0.01
    
    
    $
    0.01
    
    
    $
    0.02
    
    
    $
    0.15
    
    
    $
    0.01




---

|    |  | Notes:                                                                                                                                                                                                                            
|--- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(1) |  | A $20.0 million provision for impairment of U.S. oil and gas assets
was recorded in the fourth quarter of 2003.                                                                                                                   
|   
|(2) |  | A $3.3 million write down of costs associated with the unsuccessful
negotiation of a GTL contract in Qatar was recorded in the second
quarter of 2003 for Canadian GAAP only as GTL costs are written off
currently for U.S. GAAP.
|   
|(3) |  | A $2.4 million write down of the Sweetwater, Australia GTL assets was
recorded in the third quarter of 2002.                                                                                                                      

SUPPLEMENTARY DISCLOSURES ABOUT OIL AND GAS PRODUCTION ACTIVITIES
(UNAUDITED)

The following information about the Companys oil and gas producing activities
is presented in accordance with U.S. Statement of Financial Accounting
Standards No. 69, Disclosures About Oil and Gas Producing Activities.

Oil and Gas Reserves

Proved oil and gas reserves are the estimated quantities of crude oil, natural
gas and natural gas liquids which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic conditions.

Proved developed oil and gas reserves are reserves, which can be expected to be
recovered from existing wells with existing equipment and operating methods.

Estimates of oil and gas reserves are subject to uncertainty and will change as
additional information regarding the producing fields and technology becomes
available and as future economic conditions change.

Reserves presented in this section represent the Companys share of reserves,
excluding royalty interests of others. The reserves for 2003 in the U.S. are
based on the estimates by the independent petroleum engineering firm of
Netherland, Sewell & Associates, Inc. The reserves for 2002 and 2001 in the
U.S. are based on estimates by the independent petroleum engineering firms of
Joe C. Neal & Associates and Allan Spivak Engineering. In China, the reserves
are based on estimates by the independent petroleum engineering

48



---



##### 



firm of Gilbert Laustsen Jung Associates Ltd.

The Companys net proved and net proved developed oil and gas reserves are as
follows:

Oil
    
    Gas(MBbl)
    
    (MMcf)Net proved reserves, December 31, 2000
    
    
    25,794
    
    
    
    6,296Extensions and discoveries
    
    
    923
    
    
    
    651Production
    
    
    (377
    )
    
    
    (127
    )Revisions to previous estimates
    
    
    (2,542
    )
    
    
    (5,189
    )Net proved reserves, December 31, 2001
    
    
    23,798
    
    
    
    1,631Extensions and discoveries
    
    
    710
    
    
    
    63Production
    
    
    (350
    )
    
    
    (103
    )Revisions to previous
estimates
    
    
    (2,881
    )
    
    
    (101
    )Sale of reserves
    
    
    (3,889
    )
    
    
    (671
    )Net proved reserves, December 31, 2002
    
    
    17,388
    
    
    
    819Extensions and discoveries
    
    
    480
    
    
    
    22Production
    
    
    (346
    )
    
    
    (50
    )Revisions to previous
estimates
    
    
    (260
    )
    
    
    (96
    )Net proved reserves, December 31, 2003
    
    
    17,262
    
    
    
    695Net proved developed reserves:December 31, 2001
    
    
    1,808
    
    
    
    1,215December 31, 2002
    
    
    1,179
    
    
    
    819December 31, 2003
    
    
    1,434
    
    
    
    695


Standardized Measure of Discounted Future Net Cash Flows and Changes Therein
Relating to Proved Oil and Gas Reserves

The following standardized measure of discounted future net cash flows from
proved oil and gas reserves has been computed using period end prices of $30.31
per barrel of oil ($29.04 per barrel in 2002 and $15.37 per barrel in 2001) and
$6.13 per Mcf of gas ($5.30 per Mcf in 2002 and $2.76 per Mcf in 2001) and
costs and period end statutory tax rates. A discount rate of 10% has been
applied in determining the standardized measure of discounted future net cash
flows.

The Company does not believe that this information reflects the fair market
value of its oil and gas properties. Actual future net cash flows will differ
from the presented estimated future net cash flows in that:



| |  |  | future production from proved reserves will differ from estimated
production;
| | - |  | -----------------------------------------------------------------------------



| |  |  | future production will also include production from probable and
potential reserves;
| | - |  | ------------------------------------------------------------------------------------



| |  |  | future rather than year end prices and costs will apply; and
| | - |  | ------------------------------------------------------------



| |  |  | existing economic, operating and regulatory conditions are subject
to change.
| | - |  | -----------------------------------------------------------------------------

The standardized measure of discounted future net cash flows as at December 31
in each of the three most recently completed financial years are as follows:

2003
    
    2002
    
    2001Future cash inflows
    
    $
    527,499
    
    
    $
    513,313
    
    
    $
    370,344Future development and restoration costs
    
    
    156,383
    
    
    
    134,452
    
    
    
    137,581Future production costs
    
    
    113,949
    
    
    
    150,828
    
    
    
    156,103Future income taxes
    
    
    61,647
    
    
    
    52,656
    
    
    
    5,526Future net cash flows
    
    
    195,520
    
    
    
    175,377
    
    
    
    71,13410% annual discount
    
    
    96,646
    
    
    
    94,110
    
    
    
    52,845Standardized measure
    
    $
    98,874
    
    
    $
    81,267
    
    
    $
    18,289


Changes in standardized measure of discounted future net cash flows as at
December 31 in each of the three most recently completed financial years are as
follows:

2003
    
    2002
    
    2001Sale of oil & gas net of production costs
    
    $
    (5,276
    )
    
    $
    (4,488
    )
    
    $
    (4,386
    )Net changes in pricing and productions costs
    
    
    43,926
    
    
    
    164,210
    
    
    
    (110,584
    )Sale of reserves
    
    
    
    
    
    
    (47,685
    )
    
    
    Discoveries and extensions
    
    
    5,076
    
    
    
    9,585
    
    
    
    4,955Revisions of previous estimates
    
    
    (16,788
    )
    
    
    (63,467
    )
    
    
    22,167Net change in future development costs
    
    
    (12,289
    )
    
    
    3,230
    
    
    
    (1,640
    )Accretion of discount
    
    
    2,958
    
    
    
    1,593
    
    
    
    6,541Increase (decrease)
    
    
    17,607
    
    
    
    62,978
    
    
    
    (82,947
    )Standardized measure, beginning of year
    
    
    81,267
    
    
    
    18,289
    
    
    
    101,236Standardized measure, end of year
    
    $
    98,874
    
    
    $
    81,267
    
    
    $
    18,289


49



---



##### 



Costs Incurred in Oil and Gas Property Acquisition, Exploration, and
Development Activities are as follows:

Year ended December 31,2003
    
    2002
    
    2001Property AcquisitionProved
    
    $
    
    
    
    $
    
    
    
    $
    Unproved
    
    
    650
    
    
    
    913
    
    
    
    5,688Royalty rights
    
    
    
    
    
    
    
    
    
    
    4,043Exploration
    
    
    3,148
    
    
    
    10,841
    
    
    
    11,545Development
    
    
    11,181
    (1)
    
    
    5,178
    
    
    
    19,091$
    14,979
    
    
    $
    16,932
    
    
    $
    40,367




---

|(1) |  | Development cost additions for the year ended December 31, 2003 include
$0.4 million of asset retirement costs.
|--- |  | ---------------------------------------------------------------------------------------------------------------

Depletion, per unit of net production, before provision for impairment:

U.S.Year ended December 31, 2003
    
    $
    10.58Year ended December 31, 2002
    
    $
    8.39Year ended December 31, 2001
    
    $
    8.12ChinaYear ended December 31, 2003
    
    $
    10.23Year ended December 31, 2002
    
    $
    8.30Year ended December 31, 2001
    
    $
    6.79


Results of Producing Activities:

Year ended December 31,2003
    
    2002
    
    2001Oil and gas revenue
    
    $
    9,569
    
    
    $
    8,329
    
    
    $
    9,144Operating costs
    
    
    4,293
    
    
    
    3,841
    
    
    
    4,758Depletion (including provision for impairment)
    
    
    23,730
    
    
    
    3,108
    
    
    
    27,133Results of operations from producing activities
    
    $
    (18,454
    )
    
    $
    1,380
    
    
    $
    (22,747
    )





ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.




ITEM 9A. CONTROLS AND PROCEDURES

The Company carried out an evaluation, under the supervision and with the
participation of the Companys management, including the Companys CEO and CFO,
of the effectiveness of the design and operation of the Companys disclosure
controls and procedures pursuant to the 1934 Securities Exchange Act. Based
upon that evaluation, the CEO and CFO concluded that, as of December 31, 2003,
the Companys disclosure controls and procedures are effective in timely
alerting them to material information required to be included in the Companys
periodic SEC filings relating to the Company (including its consolidated
subsidiaries). There were no significant changes in the Companys internal
control over financial reporting or in other factors that could significantly
affect its internal control over financial reporting during the year ended
December 31, 2003, nor any significant deficiencies or material weaknesses in
such internal control over financial reporting requiring corrective actions. As
a result, no corrective actions were taken.




PART III




ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The following table provides the names of all of our directors and executive
officers, their positions, terms of office and their principal occupations
during the past five years. Each director is elected for a one-year term or
until his successor has been duly elected or appointed. Officers serve at the
pleasure of the Board of Directors.

50



---



##### 



Name, Age and
    
    Position with
    
    Present Occupation andMunicipality of Residence
    
    the Registrant
    
    Principal Occupation for the Past Five YearsDAVID R. MARTIN, age 72
Santa Barbara, California
    
    Chairman of the Board and
Director(since August,
1998)
    
    Chairman of the Board of Ivanhoe Energy Inc.
(August 1998  present); President,
Cathedral Mountain Corporation (1997 
present); President and Chief Executive
Officer, Occidental Oil and Gas Corporation
(1986-1996); Executive Vice President and
Director, Occidental Petroleum Corporation
(1986-1996)ROBERT M. FRIEDLAND, age 53
Hong Kong
    
    Deputy Chairman(since
June, 1999) and Director
(since February, 1995)
    
    Chairman and President, Ivanhoe Capital
Corporation, a Singapore based venture capital
company principally involved in establishing and
financing international mining and exploration
companiesE. LEON DANIEL, age 67
Park City, Utah
    
    President,
Chief Executive Officer
(since June, 1999)
and Director
(since August, 1998)
    
    President and Chief Executive Officer of
Ivanhoe Energy Inc. (June, 1999  present);
Executive Vice President, Worldwide Business
Development, Occidental Oil and Gas
Corporation (1996-1998);
Vice President Engineering, Drilling and Production,
Occidental Petroleum Corporation (1997-1998)JOHN A. CARVER, age 71
Bakersfield, California
    
    Director
(since August, 1998)
    
    Retired (1998); Senior Vice President,
Worldwide Exploration, Occidental Petroleum
Corporation (1997-1998)R. EDWARD FLOOD, age 58
Reno, Nevada
    
    Director
(since June, 1999)
    
    Deputy Chairman, Ivanhoe Mines Ltd. (May,
1999  present); Mining Analyst, Haywood
Securities (May, 1999  September 2001)
President, Ivanhoe Mines Ltd. (1995-1999)SHUN-ICHI SHIMIZU, age 63
Tokyo, Japan
    
    Director
(since July, 1999)
    
    Managing Director of C.U.E. Management
Consulting Ltd. (1994  present)HOWARD R. BALLOCH, age 52
Beijing, China
    
    Director
(since January, 2002)
    
    President, The Balloch Group
(July 2001  present); President, Canada
China Business Council (July 2001 
present); Canadian Ambassador to China,
Mongolia and Democratic Republic of Korea
(April 1996  July 2001)J. STEVEN RHODES, age 52
Los Angeles, California
    
    Director
(since December, 2003)
    
    Chairman and Chief Executive Officer. Claiborne-
Rhodes, Inc. (2001  present); Senior Vice President,
First Southwest Company (1999 2001)
White House, Chief Domestic Advisor to Vice
President George Bush (1981  1985)W. GORDON LANCASTER, C.A. age
60
Vancouver, British Columbia
    
    Chief Financial Officer
(Effective January 1, 2004)
    
    Vice President Finance and Chief Financial Officer
of Xantrex Technology Inc., (July 2003  December
2003); Vice President Finance and Chief Financial
Officer of Power Measurement, Inc., (August 2000 
June 2003)
2003); Senior President Finance and Chief Financial
Officer of Lions Gate Entertainment Corp., (1998 
2000)JOHN OKEEFE, age 55
Houston, Texas
    
    Executive
Vice-President,
Investor Relations and
Chief Financial Officer
(From September, 2000 to
December 2003)
    
    Executive Vice-President, Investor Relations
and Chief Financial Officer of Ivanhoe
Energy Inc. (September 2000  December 2003);
Vice-President, Investor Relations of Santa
Fe Snyder Corporation (1999  September
2000); Director, Investor Relations of Oryx
Energy Company (1991-1999)PATRICK CHUA, age 48
Hong Kong, China
    
    Executive
Vice-President
(since June, 1999)
    
    Executive Vice-President of Ivanhoe Energy
Inc. (June, 1999  present); President
and Director of Sunwing Energy Ltd.
(Bermuda) (March 2000  present):
Co-Chairman and Director of Sunwing Energy
Ltd. (June, 1996  June, 1999)GERALD MOENCH, age 55
Lethbridge, Alberta
    
    Executive
Vice-President
(since June, 1999)
    
    Executive Vice-President of Ivanhoe Energy
Inc. (June, 1999  present); President
and Director, Sunwing Energy Ltd. (July,
1997  June, 1999)


51



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##### 



Each of our directors was elected at our last annual general meeting of
shareholders held on June 19, 2003. The term of office of each director
concludes at our next annual general meeting of shareholders, unless the
directors office is earlier vacated in accordance with our by-laws. There are
no family relationships among any of our directors, officers or key employees.

As required under the Business Corporations Act(Yukon), our Board of Directors
has an Audit Committee. We also have a Compensation Committee. The members of
the Audit Committee are Messrs. Edward Flood, Howard Balloch and Steven Rhodes.
Mr. Rhodes replaced Mr. Shun-ichi Shimizu effective March 2, 2004. Mr. Flood,
an independent director of the Company, has been determined by the Board of
Directors to be an Audit Committee financial expert. The members of the
Compensation Committee are Messrs. Edward Flood, Howard Balloch and Steven
Rhodes. Mr. Rhodes was appointed to the Compensation Committee on March 2,
2004.

Management is responsible for our financial reporting process including our
system of internal control over financial reporting and for the preparation of
consolidated financial statements in accordance with generally accepted
accounting principles in Canada. Our independent auditors are responsible for
auditing those financial statements. The members of the audit committee are not
our employees, and are not professional accountants or auditors. The audit
committees primary purpose is to assist the Board of Directors to fulfill its
oversight responsibilities by reviewing the financial information provided to
shareholders and others, the systems of internal controls which management has
established to preserve our assets and the audit process. It is not the audit
committees duty or responsibility to conduct auditing or accounting reviews or
procedures or to determine that our financial statements are complete and
accurate and in accordance with generally accepted accounting principles in
Canada. In giving its recommendation to the Board of Directors, the audit
committee has relied on managements representations that the financial
statements have been prepared with integrity and objectivity and in conformity
with generally accepted accounting principles in Canada and on the opinion of
the independent auditors included in their report on our financial statements.

Based solely on a review of the reports furnished to us, we believe that during
2003 all of our directors, executive officers and 10% shareholders complied
with the applicable requirements for reporting initial ownership and changes in
ownership of our common shares.

Code of Business Conduct and Ethics

We have a Code of Business Conduct and Ethics applicable to all employees,
officers and directors regardless of their position in our organization, at all
times and everywhere we do business. The Code provides that our employees,
officers and directors will uphold our commitment to a culture of honesty,
integrity and accountability and that we require the highest standards of
professional and ethical conduct from our employees, officers and directors.
Our Code of Business Conduct and Ethics has been filed as Exhibit 14.1 to this
Annual Report.




ITEM 11. EXECUTIVE COMPENSATION

In accordance with the requirements of applicable securities legislation in
Canada, the following executive compensation disclosure is provided in respect
of the Companys President and Chief Executive Officer as at December 31, 2003,
and each of the Companys four most highly compensated executive officers
(Named Executive Officers) whose annual compensation exceeded Cdn$100,000 in
the year ended December 31, 2003. During the year ended December 31, 2003, the
aggregate compensation paid to all executive officers of the Company whose
annual compensation exceeded Cdn$40,000 was US$1,300,000.00.

Summary Compensation Table

The following table sets forth a summary of all compensation paid during the
years ending December 31, 2001, 2002 and 2003 to each of the Named Executive
Officers.

52



---



##### 



SUMMARY COMPENSATION TABLE

Annual Compensation
    
    Long Term CompensationAwards
    
    PayoutsSecuritiesUnder
    
    RestrictedOptions/
    
    Shares orOther
    
    SARs
    
    RestrictedName and
    
    
    
    
    
    Salary
    
    Bonus
    
    Annual
    
    Granted
    
    Share
    
    LTIP
    
    All OtherPrincipal Position
    
    Year
    
    $US
    
    $US
    
    Compensation
    
    (#)
    
    Units
    
    Payouts
    
    CompensationE. Leon Daniel
    
    
    2003
    
    
    
    332,610
    
    
    
    
    
    
    
    6,133
    (6)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    9,792
    (7)President & Chief
    
    
    2002
    
    
    
    266,500
    
    
    
    
    
    
    
    2,674
    (6)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    5,415
    (7)Executive
Officer(1)
    
    
    2001
    
    
    
    150,000
    
    
    
    81,123
    (9)
    
    
    2,046
    (6)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Patrick Chua
    
    
    2003
    
    
    
    144,000
    
    
    
    32,449
    (9)
    
    
    5,262
    (6)Executive
Vice President(2)
    
    
    2002
    
    
    
    182,970
    
    
    
    
    
    
    
    5,083
    (6)
    
    
    60,000
    
    
    
    
    
    
    
    
    
    
    
    2001
    
    
    
    180,000
    
    
    
    
    
    
    
    12,794
    (6)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    John OKeefe
    
    
    2003
    
    
    
    205,562
    
    
    
    
    
    
    
    8,742
    (6)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    24,898
    (8)Executive Vice President
    
    
    2002
    
    
    
    219,845
    
    
    
    
    
    
    
    7,716
    (6)
    
    
    75,000
    
    
    
    
    
    
    
    
    
    
    
    7,200
    (7)Investor Relations & Chief
    
    
    2001
    
    
    
    174,955
    
    
    
    
    
    
    
    6,455
    (6)
    
    
    250,000
    
    
    
    
    
    
    
    
    
    
    
    5,250
    (7)Financial Officer(3)David R. Martin
    
    
    2003
    
    
    
    205,562
    
    
    
    54,082
    (9)
    
    
    3,057
    (6)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    9,792
    (7)Chairman(4)
    
    
    2002
    
    
    
    253,167
    
    
    
    
    
    
    
    3,074
    (6)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    7,200
    (7)2001
    
    
    
    150,000
    
    
    
    
    
    
    
    2,546
    (6)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    3,000
    (7)Gerald Moench
    
    
    2003
    
    
    
    150,000
    
    
    
    33,801
    (9)
    
    
    4,379
    (6)Executive Vice President(5)
    
    
    2002
    
    
    
    152,475
    
    
    
    
    
    
    
    3,535
    (6)
    
    
    50,000
    
    
    
    
    
    
    
    2001
    
    
    
    150,000
    
    
    
    
    
    
    
    3,085
    (6)
    
    
    
    
    
    
    
    
    
    
    




---

|(1) |  | Mr. Leon Daniel was appointed President and Chief Executive Officer on
June 22, 1999, and has been a director of the Company since August 25,
1998.            
|--- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(2) |  | Mr. Chua was appointed as an Executive Vice President in June 1999.                                                                                            
|   
|(3) |  | Mr. OKeefe was Executive Vice President Investor Relations and Chief
Financial Officer from September, 2000 to December 2003.                                 
|   
|(4) |  | Mr. Martin has been Chairman and one of the Companys directors since
August 1998.                                                                             
|   
|(5) |  | Mr. Moench was appointed an Executive Vice President in June 1999.                                                                                             
|   
|(6) |  | Includes premiums paid by us on behalf of the Named Executive Officer for
medical, dental and other health insurance coverage.                                 
|   
|(7) |  | Companys matching contribution to the 401(k) plan, a US defined
contribution retirement plan available to US employees.                                       
|   
|(8) |  | Includes Companys matching contribution to the 401(k) plan of $9,792
plus accrued vacation pay of $15,106.                                                    
|   
|(9) |  | Bonuses earned in 2003 are payable in cash and Company shares from the
Share Bonus Plan at fair market value on date of approval by the
Compensation Committee.

Options and Stock Appreciation Rights (SARs)

No options were granted to our Named Executive Officers in the financial year
ended December 31, 2003.

Aggregated Option Exercises in Last Fiscal Year and Year End Option Values

During the financial year ended December 31, 2003, John OKeefe exercised
options for 200,000 shares at Cdn. $6.22 per share, 100,000 shares at Cdn.
$3.60 per share and 30,000 shares at Cdn. $3.10 per share and Gerry Moench
exercised options for 50,000 shares at Cdn. $2.50 per share. No other named
executive officers exercised options in 2003.

Number ofSecurities
    
    Value ofUnderlying
    
    UnexercisedUnexercised Options
    
    In-the-MoneyShares Acquired
    
    
    
    
    
    at December 31,
    
    Options at DecemberName
    
    on Exercise
    
    Value Realized
    
    2003
    
    31, 2003(#)
    
    ($)
    
    (#)
    
    ($)E. Leon Daniel
    
    
    
    
    
    
    
    
    
    
    666,667
    
    
    
    725,001Patrick Chua
    
    
    
    
    
    
    
    
    
    
    560,000
    
    
    
    1,361,000John OKeefe
    
    
    330,000
    
    
    
    805,229
    
    
    
    50,000
    
    
    
    62,500Dave Martin
    
    
    
    
    
    
    
    
    
    
    3,400,000
    
    
    
    14,790,000Gerald Moench
    
    
    50,000
    
    
    
    161,954
    
    
    
    195,000
    
    
    
    495,750


Indebtedness of Directors, Executive Officers and Senior Officers

There was no indebtedness of any officers, directors, employees and former
officers, directors and employees of the Company in connection with the
purchase of securities of the Company as at March 2, 2004.

53



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##### 



Defined Benefit and Actuarial Plan

The Company does not presently provide a pension plan for our employees.
However, in 2001 the Company adopted a defined contribution retirement or
thrift plan (401(k) Plan) to assist U.S. employees in providing for retirement
or other future financial needs. Employees contributions (up to the maximum
allowed by U.S. tax laws) are matched by the Company 50% starting in 2001 and
increasing 10% per year thereafter to a maximum of 100%. The Companys matching
contributions to the 401(k) Plan during 2003, 2002 and 2001 were $0.2 million
for 2003 and $0.1 million per year for 2002 and 2001.

Employment Contracts, Termination of Employment and Change-In-Control
Arrangements

The Company has written contracts of employment with Messrs. E. Leon Daniel and
W. Gordon Lancaster. Until December 31, 2003, the Company also had a written
contract of employment with Mr. John OKeefe. Otherwise, the Company has no
written employment contracts or termination of employment or change of control
arrangements with any of our directors or Named Executive Officers. Each of the
written employment contracts the Company has with the Named Executive Officers
allows us to terminate the Named Executive Officer for cause in which case the
Named Executive Officer would have no entitlement to any compensation with
respect to the termination. None of the contracts provides for a change of
control arrangement.

Mr. Daniels contract provides for an annual salary of not less than $300,000
over the term of employment of five years, commencing on April 30, 2002, unless
terminated earlier in accordance with the provisions of the contract. Either
party may terminate the contract upon one years notice provided however that
the Company may terminate Mr. Daniels employment at any time without notice by
paying him an amount equal to the lesser of one years salary or the prorated
amount of his annual salary that he would have earned between the date of
termination and the expiration of the contract term. Mr. Daniel is eligible to
receive a cash bonus and a stock bonus each year, as determined by the
Compensation Committee. Mr. Daniel is entitled to participate in the Companys
employee benefit programs on the same basis as all of the Companys other
employees.

Commencing in September 2000, the Company had an employment contract with Mr.
John OKeefe, the Companys former Executive Vice-President of Investor
Relations and Chief Financial Officer. The contract had no fixed term of
employment and provided for an annual salary of $200,000. Mr. OKeefe was
entitled to participate in the Companys employee benefit programs on the same
basis as all of the Companys other employees. Effective December 31, 2003, Mr.
OKeefe elected to terminate his employment with the Company. Mr. OKeefe
received no additional compensation upon termination of his contract but was
entitled to exercise his vested incentive stock options.

As of January 1, 2004, the Company entered into an employment contract with Mr.
W. Gordon Lancaster having no fixed term of employment and providing for an
initial annual salary of $200,000, subject to review annually by the
Compensation Committee, and the same benefit entitlements available to the
Companys other executive officers. Under the terms of the contract, Mr.
Lancaster was granted an initial incentive stock option to acquire 250,000
common shares, which vest over 4 years and expire on the 5th anniversary of the
date of grant. The Company may terminate Mr. Lancasters employment for any
reason by delivering to him six months written notice.

Director Compensation

All independent directors receive director fees of $2,000 per month. We did not
pay any other cash or fixed compensation to our directors for acting as such.
We reimburse our directors for expenses they reasonably incur in the
performance of their duties as directors and they are also eligible to
participate in our Employees and Directors Equity Incentive Plan. One of our
non-executive directors, John A. Carver, was engaged as a full time employee
effective January 1, 2002 and receives a salary in his capacity as an employee.

Employees and Directors Equity Incentive Plan

Our Employees and Directors Equity Incentive Plan, as amended (the Plan)
consists of three component plans: a common share option plan (the Share
Option Plan), a common share bonus plan (the Share Bonus Plan), and a common
share purchase plan (the Share Purchase Plan). The purpose of the Plan is to
advance our corporate interests by encouraging equity participation by our
directors, officers, employees and service providers through the acquisition of
our shares.

The following is a brief description of the terms of the Plan.

Share Option Plan

The Share Option Plan allows the Board of Directors to grant options to acquire
our common shares in favor of our directors, officers, employees and service
providers. Options are subject to adjustment in the event of a subdivision or
consolidation of our common

54



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##### 



shares, an amalgamation, or other corporate event affecting our common shares.
Participation in the Share Option Plan is limited to directors, officers,
employees and service providers, who are, in the opinion of our Board of
Directors, in a position to contribute to our future growth and success.

In determining the number of common shares made subject to an option, we
consider, among other things, the optionees relative present and potential
contribution to our success and to the prevailing policies of each stock
exchange on which our shares are listed. The Board of Directors determines the
date of grant, the number of optioned common shares, the exercise price per
share, the vesting period and the exercise period. The minimum exercise price
of any option granted under the Share Option Plan is the weighted average price
of our common shares on the principal stock exchange on which our common shares
trade for the five trading days prior to the date of grant.

Unless earlier terminated upon an optionees death or termination of employment
or appointment, options are exercisable for a period of up to ten years. We
may, in our discretion, accelerate unvested options if a take-over bid is made
for our common shares.

Share Bonus Plan

The Share Bonus Plan permits our Board of Directors to issue up to an aggregate
maximum of 2,000,000 of our common shares as bonus awards to our directors,
officers, employees and service providers on a discretionary basis having
regard to such merit criteria as the Board of Directors may determine. As at
December 31, 2003 there were 1,155,870 shares available to be issued from the
Share Bonus Plan.

Share Purchase Plan

Participation in the Share Purchase Plan is limited to employees who have
completed at least one year (or less, at the discretion of the Board of
Directors) of continuous service on a full-time basis and who are designated by
the Board of Directors as eligible to participate in the Share Purchase Plan.

Eligible employees may contribute up to 10% of their annual basic salary to the
Share Purchase Plan in semi-monthly installments. We then make contributions on
a quarterly basis equal to the employees contribution.

At the end of each calendar quarter, the eligible employee receives a number of
our common shares equal to the aggregate amount contributed by the employee
participant and by us, on the participants behalf, divided by the weighted
average trading price of our common shares on our principal stock exchange
during the previous three months.

The Share Purchase Plan component of the Plan has not yet been activated.

General

The aggregate maximum number of our common shares, which we may issue, or
reserve for issuance under the Plan, is currently 20,000,000 common shares. Any
increase is subject to Toronto Stock Exchange approval and approval by our
shareholders. The maximum number of our common shares which we may, at any
time, reserve for issuance to any one person under the Plan may not exceed 5%
of our issued and outstanding common shares. As at December 31, 2003, there
were 5,521,640 shares available to be issued from our Employees and Directors
Equity Incentive Plan.

Our Board of Directors has the right to amend, modify or terminate our Equity
Incentive Plan. However, any amendment to the Equity Incentive Plan which would
materially increase the benefits under the Plan, materially modify the
requirements as to eligibility for participation in the Plan or materially
change the number of our common shares that may be issued or reserved for
issuance under the Plan, is subject to Toronto Stock Exchange approval and the
approval of our shareholders.

Compensation Committee Interlocks and Insider Participation

During the year ended December 31, 2003, our Compensation Committee consisted
of Messrs. Edward Flood and Howard Balloch.

Board Compensation Committee Report on Executive Compensation

Our executive compensation program is administered by the Compensation
Committee. The members of the Compensation Committee are both non-employee
directors. Following review and approval by the Committee, decisions relating
to executive compensation are reported to and approved by the full Board of
Directors. The Committee has directed the preparation of this report and has
approved its contents and its submission to shareholders.

55



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##### 



The basic philosophy underlying our executive compensation program is that the
interests of our executive officers should be aligned as closely as possible
with the interests of Ivanhoe and its shareholders as a whole. Compensation for
our executive officers is, accordingly, designed to achieve the following
objectives: to provide a strong incentive to management to contribute to the
achievement of our short-term and long-term corporate goals; to ensure that the
interests of our executive officers and the interests of our shareholders are
aligned; and to enable us to attract, retain and motivate executive officers of
the highest caliber in light of the strong competition in our industry for
qualified personnel. Our approach to compensation for senior executives and
other employees is designed to recognize both corporate and individual
performance, and the fact that, insofar as competition for highly skilled
employees is intense, the levels of compensation we offer should be comparable
to those offered elsewhere in our industry.

The compensation that we pay to our executive officers generally consists of
cash, equity and equity incentives. Our compensation policy reflects a belief
that an element of total compensation for our executive officers should be at
risk in the form of stock options, so as to create a strong incentive to build
shareholder value. The Compensation Committee oversees and sets the general
guidelines and principles for the compensation packages for senior management.
As well, the Compensation Committee assesses the individual performance of our
executive officers and makes recommendations to the Board of Directors. Based
on these recommendations, the Board of Directors makes decisions concerning the
nature and scope of the compensation to be paid to our executive officers.

The base salaries of our executive officers are determined using a subjective
assessment of each individuals performance, experience and other factors we
believe to be relevant. We also consider recommendations from outside
compensation consultants and use compensation data obtained from publicly
available sources. We believe that current executive officer salaries are
appropriate to ensure that our executive officers compensation remains close
to the median level of most of the comparative compensation data. All of our
executive officers are eligible to receive discretionary bonuses, based upon
Ivanhoes overall performance and achievement of corporate objectives and our
subjective assessment of each executive officers contribution to such
performance and achievement. Incentive bonuses awarded for the 2003 fiscal
year consisted of 55% cash and 45% common shares issued at fair market value
under the share bonus plan component of our Employees and Directors Equity
Incentive Plan.

The specific relationship of corporate performance to executive compensation
under our executive compensation program is created through equity compensation
mechanisms. Incentive stock options, which vest and become exercisable through
the passage of time, link the bulk of our equity-based executive compensation
to shareholder return, measured by increases in the market price of our common
shares. We also make discretionary bonus awards of common shares to our
employees, including our executive officers. Such awards are intended to
recognize extraordinary contributions to the achievement of corporate
objectives.

Eligibility for participation from time to time in the various equity incentive
mechanisms available under our Employees and Directors Equity Incentive Plan
is determined after we have thoroughly reviewed and taken into consideration
the individual performance and contribution to overall corporate performance by
each prospective participant. All outstanding stock options that have been
granted under our Employees and Directors Equity Incentive Plan were granted
at prices not less than 100% of the fair market value of Ivanhoe common shares
on the dates such options were granted.

Ivanhoe relies heavily upon stock options to compensate its executive officers.
We believe that stock-based incentives encourage and reward effective
management that results in long-term corporate financial success, as measured
by stock appreciation. Stock-based incentives awarded to our executive officers
are based on the Committees subjective evaluation of each executive officers
ability to influence our long-term growth and to reward outstanding individual
performance and contributions to our business. Our reliance upon stock options
also reflects our stage of development, our limited history of earnings and the
priority allocation of our limited financial resources to the development of
our business.

The compensation paid to our Chief Executive Officer for the fiscal year ended
December 31, 2003 was based on the same basic factors and criteria used to
determine executive compensation generally. As with executive compensation
generally, we believe that there is necessarily some subjectivity involved in
determining the compensation of our Chief Executive Officer and we do not use
predetermined performance criteria when setting his compensation. In
determining an appropriate level of compensation for our Chief Executive
Officer, we subjectively and quantitatively analyze his performance, Ivanhoes
overall corporate performance and our Chief Executive Officers contribution to
that performance. Specific factors considered in setting bonus levels include
shareholder returns, our operational and financial results and the success of
our acquisition, exploration and development programs and strategies. We also
consider our Chief Executive Officers level and scope of responsibility,
experience and the compensation practices of other industry participants for
executives of similar responsibility.

Our Chief Executive Officers minimum salary is set by his employment contract,
the material terms of which are described under Employment Contracts,
Termination of Employment and Change-in-Control Arrangements. This contract
also provides that our Chief Executive Officer is eligible to receive, on an
annual basis, a cash bonus and a non-cash bonus in an amount determined by the
Committee based on such criteria as the Committee may determine from time to
time. We awarded a bonus of $81,123 to our Chief Executive Officer in respect
of the 2003 fiscal year. This bonus consisted of 55% cash and 45% common shares
issued at fair market value under the share bonus plan component of our
Employees and Directors Equity Incentive Plan. In determining the quantum of

56



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##### 



our Chief Executive Officers bonus, the principal factor we took into account
was the creation of shareholder value, measured by the increase in the market
price of our common shares during 2003. In this regard, reference is made to
the performance graph that follows this report.

Submitted on behalf of the Compensation Committee:
Mr. R. Edward Flood
Mr. Howard R. Balloch

Performance Graph

The following graph and table compares the cumulative shareholder return on a
$100 investment in common shares of the Company to a similar investment in
companies comprising the S&P/TSX Composite Index, including dividend
reinvestment, for the period from December 31, 1998 to December 31, 2003.

(LINE GRAPH)

As at December 31,1998
    
    1999
    
    2000
    
    2001
    
    2002
    
    2003Ivanhoe Energy Inc.
    
    Cdn. $100
    
    Cdn. $711
    
    Cdn. $1,961
    
    Cdn. $592
    
    Cdn. $189
    
    Cdn. $1,276S&P/TSX Composite
Index
    
    Cdn. $100
    
    Cdn. $132
    
    Cdn. $141
    
    Cdn. $124
    
    Cdn. $108
    
    Cdn. $137





ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Except as set forth below, no person or group is known to beneficially own 5%
or more of our issued and outstanding common shares. Based on information known
to us, the following table sets forth the beneficial ownership of each such
person or group in our common shares as at February 2, 2004.

Name and Address of
    
    Number of Shares
    
    PercentageTitle of Class
    
    Beneficial Owner
    
    Beneficially Owned(1)
    
    of ClassCommon Shares
    
    Robert M. Friedland
    
    
    46,611,725
    (2)
    
    
    28.87
    %Flat B, 31st FloorPrimrose Court56A Conduit RoadHong KongCommon Shares
    
    Directors and Executive Officers as a Group
    
    
    54,410,837
    (3)
    
    
    33.49
    %(11 persons)




---

|(1) |  | Beneficial ownership is determined in accordance with the rules of the
Securities and Exchange Commission and generally includes voting or
investment power with respect to securities. Unissued common shares
subject to options, warrants or other convertible securities currently
exercisable or convertible, or exercisable or convertible within 60 days,
are deemed outstanding for the purpose of computing the beneficial
ownership of common shares of the person holding such
|--- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

57



---



##### 



|    |  | convertible security but are not deemed outstanding for computing the
beneficial ownership of common shares of any other person.                         
|--- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(2) |  | 46,611,725 common shares are held indirectly through Newstar Securities
SRL, Premier Mines Ltd. and Evershine LLC, companies controlled by Mr.
Friedland.
|   
|(3) |  | Includes 5,796,667 unissued common shares issuable to directors and
senior officers upon exercise of incentive stock options.                            

Security Ownership of Management

The following table sets forth the beneficial ownership at February 2, 2004 of
our common shares by each of our directors, our named executive officers and by
all of our directors and executive officers as a group:

Amountand Natureof Beneficial
    
    Percentage
    
    Incentive StockTitle of Class
    
    Name of Beneficial Owner
    
    Ownership
    
    of Class
    
    Options Included in (a)(a)
    
    (b)
    
    (c)Common Shares
    
    David R. Martin
    
    
    4,349,460
    
    
    
    2.60
    
    
    
    3,400,000Common Shares
    
    Robert M. Friedland
    
    
    46,611,725
    
    
    
    28.87
    
    
    
    Common Shares
    
    E. Leon Daniel
    
    
    1,243,290
    
    
    
    0.74
    
    
    
    666,667Common Shares
    
    John A. Carver
    
    
    543,547
    
    
    
    0.33
    
    
    
    250,000Common Shares
    
    R. Edward Flood
    
    
    175,029
    
    
    
    0.10
    
    
    
    150,000Common Shares
    
    Shun-ichi Shimizu
    
    
    98,500
    
    
    
    0.06
    
    
    
    Common Shares
    
    J. Steven Rhodes
    
    
    150,000
    
    
    
    0.09
    
    
    
    150,000Common Shares
    
    W. Gordon Lancaster
    
    
    250,000
    
    
    
    0.15
    
    
    
    250,000Common Shares
    
    Patrick Chua
    
    
    575,300
    
    
    
    0.34
    
    
    
    560,000Common Shares
    
    Gerald Moench
    
    
    202,200
    
    
    
    0.12
    
    
    
    195,000Common Shares
    
    Howard R. Balloch
    
    
    150,000
    
    
    
    0.09
    
    
    
    150,000Common Shares
    
    All directors and executive officers as a group(11 persons)
    
    
    54,349,051
    
    
    
    33.49


Securities Authorized for Issuance under Equity Compensation Plans

Our shareholders have approved our Employees and Directors Equity Incentive
Plan (the Plan) and all amendments increasing the number of common shares
available for issuance under the Plan. The Plan is intended to further align
our directors and managements interests with the companys long-term
performance and the long-term interests of our shareholders. The material terms
of the Plan are summarized in Item 11 Executive Compensation. The following
information is as at December 31, 2003:

Number ofsecuritiesremaining availableNumber of
    
    
    
    
    
    for future issuancesecurities to be
    
    
    
    
    
    under equityissued upon
    
    Weighted-average
    
    compensation plansexercise of
    
    exercise price of
    
    (excludingoutstanding
    
    outstanding
    
    securitiesoptions, warrants
    
    options, warrants
    
    reflected in columnPlan category
    
    and rights
    
    and rights
    
    (a))(a)
    
    (b)
    
    (c)Equity compensation
plans approved by
shareholders
    
    
    8,996,664
    
    
    $
    2.64
    
    
    
    5,521,640Equity compensation
plans not approved
by shareholders
    
    
    0
    
    
    
    
    
    
    
    0Total
    
    
    8,996,664
    
    
    
    
    
    
    
    5,521,640





ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Transactions with Management and Others

The Company borrowed $1.25 million from Ivanhoe Capital Finance Ltd., a company
wholly owned by Mr. Robert Friedland. The unsecured loan, due 90 days after
written demand, or on the closing date of an equity financing or December 31,
2005 whichever occurs earliest, was repaid with accrued interest, at U.S. prime
plus 3%, in September 2003. The Company negotiated a revolving credit facility
of $1.25 million to re-establish or extend that loan in the future as needs
arise.

Certain Business Relationships

We are parties to cost sharing agreements with other companies wholly or
partially owned by Mr. Robert M. Friedland. Through these agreements, we share
office space, furnishings, equipment and communications facilities in Vancouver
and Singapore and an aircraft on a cost recovery basis. We also share the costs
of employing administrative and non-executive management personnel at these
offices. During the year ended December 31, 2003, our share of these costs was
$0.9 million. The agreement for the usage of the aircraft was terminated in
2003.

During the year ended December 31, 2003 a company controlled by Mr. Shun-ichi
Shimizu received $0.4 million for consulting services and out of pocket
expenses.

58



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##### 






ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The following table summarizes the aggregate fees billed by Deloitte & Touche
LLP:

Year ended December 31,($000's)2003
    
    2002Audit Fees (a)
    
    $
    183
    
    
    $
    148Tax Fees (b)
    
    
    43
    
    
    
    95Total
    
    $
    226
    
    
    $
    243




---

|(a) |  | Fees for audit services billed in 2003 and 2002 consisted of:
|--- |  | -------------------------------------------------------------



| |  |  | Audit of the Companys annual financial statements
| | - |  | --------------------------------------------------



| |  |  | Reviews of the Companys quarterly financial statements
| | - |  | -------------------------------------------------------



| |  |  | Comfort letters, statutory and regulatory audits, consents and other
services related to Canadian and U.S. securities regulatory matters
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------

(b) Fees for tax services billed in 2003 and 2002 consisted of tax compliance
and tax planning and advice:



| |  |  | Fees for tax compliance services totaled $36 thousand and $46
thousand in 2003 and 2002, respectively. Tax compliance services are
services rendered based upon facts already in existence or transactions
that have already occurred to document, compute, and obtain government
approval for amounts to be included in tax filings and consisted of:
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | i. |  | Federal, state and local income tax return assistance
| | -- |  | -----------------------------------------------------



| | ii. |  | Preparation of expatriate tax returns
| | --- |  | -------------------------------------



| | iii. |  | Assistance with tax return filings in certain foreign
jurisdictions
| | ---- |  | -------------------------------------------------------------------



| |  |  | Fees for tax planning and advice services totaled $7 thousand and $49
thousand in 2003 and 2002, respectively. Tax planning and advice are
services rendered with respect to proposed transactions or that alter a
transaction to obtain a particular tax result. Such services consisted
of:
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | i. |  | Tax advice related to structuring certain proposed
mergers, acquisitions and disposals.
| | -- |  | ---------------------------------------------------------------------------------------

In considering the nature of the services provided by Deloitte & Touche LLP,
the Audit Committee determined that such services are compatible with the
provision of independent audit services. The Audit Committee discussed these
services with Deloitte & Touche LLP and Ivanhoe management to determine that
they are permitted under the rules and regulations concerning auditor
independence promulgated by the U.S. Securities and Exchange Commission (the
SEC) to implement the Sarbanes-Oxley Act of 2002, as well as the American
Institute of Certified Public Accountants.

Audit Committee Approval

Before Deloitte & Touche LLP is engaged by Ivanhoe or our subsidiaries to
render audit or non-audit services, the engagement is approved by our Audit
Committee. All services provided by Deloitte & Touche LLP after May 6, 2003
were approved by our Audit Committee.

The Audit Committee has adopted a pre-approval policy for audit or non-audit
service engagements. This policy describes the permitted audit, audit-related,
tax, and other services (collectively, the Disclosure Categories) that
Deloitte & Touche LLP may perform. The policy requires that, prior to the
beginning of each fiscal year, a description of the services (the Service
List) expected to be performed by Deloitte & Touche LLP in each of the
Disclosure Categories in the following fiscal year be presented to the Audit
Committee for approval. Services provided by Deloitte & Touche LLP during the
following year that are included in the Service List are pre-approved following
the policies and procedures of the Audit Committee.

Any requests for audit, audit-related, tax, and other services not contemplated
on the Service List must be submitted to the Audit Committee for specific
pre-approval and cannot commence until such approval has been granted.
Normally, pre-approval is provided at regularly scheduled meetings. However,
the authority to grant a specific pre-approval between meetings, as necessary,
has been delegated to the Chairman of the Audit Committee. The Chairman must
update the Audit Committee at the next regularly scheduled meeting of any
services that were granted specific pre-approval.

In addition, although not required by the rules and regulations of the SEC, the
Audit Committee generally requests a range of fees associated with each
proposed service on the Service List and any services that were not originally
included on the Service List. Providing a range of fees for a service
incorporates appropriate oversight and control of the independent auditor
relationship, while permitting us to receive immediate assistance from the
independent auditor when time is of the essence. On a quarterly basis, the
Audit Committee reviews the status of services and fees incurred year-to-date
against the original Service List and the forecast of remaining services and
fees for the fiscal year.

59



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##### 



PART IV

ITEM 15.   EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

The following financial statements and exhibits are filed as part of this
Annual Report:

(a)
    
    
    1.
    
    
    
    
    
    
    Financial Statements:Deloitte & Touche LLP Auditors Report on Consolidated Balance
Sheets of Ivanhoe Energy Inc. as at December 31, 2003 and 2002 and
Consolidated Statements of Loss and Deficit and Consolidated
Statements of Cash Flow of Ivanhoe Energy Inc. for the years ended
December 31, 2003, 2002 and 2001.
Consolidated Balance Sheets of Ivanhoe Energy Inc. as at December
31, 2003 and 2002
Consolidated Statements of Loss and Deficit of Ivanhoe Energy Inc.
For the years ended December 31, 2003, 2002 and 2001.
Consolidated Statements of Cash Flow of Ivanhoe Energy Inc. for
the
years ended December 31, 2003, 2002 and 2001.2.
    
    
    
    
    
    
    Financial Statement Schedules:Supplementary Disclosures about Oil and Gas Production Activities
(Unaudited)3.
    
    
    
    
    
    
    Exhibits3.1
    
    
    Articles of Ivanhoe Energy Inc. as amended to June 24, 1999
(incorporated by reference to Exhibits 1.1 through to 1.4 of Form
20-F filed with the Securities and Exchange Commission on
February 28, 2000)3.2
    
    
    Bylaws of Ivanhoe Energy Inc. (incorporated by reference to
Exhibit 1.1 of Form 20-F filed with the Securities and Exchange
Commission on February 28, 2000)10.1
    
    
    Petroleum Contract for Kongnan Block, Dagang Oilfield of the
Peoples Republic of China dated September 8, 1997 between China
National Petroleum Corporation and Pan-China Resources Ltd., as
amended June 11, 1999 (incorporated by reference to Exhibit 3.15
of
Form 20-F filed with the Securities and Exchange Commission on
February 28, 2000)Exhibits10.2
    
    
    Volume License Agreement dated April 26, 2000 between Syntroleum
Corporation and Ivanhoe Energy Inc. (incorporated by reference to
Exhibit 3.37 of Amendment No. 2 to Form 20-F filed with the
Securities and Exchange Commission on July 24, 2000)10.3
    
    
    Master License Agreement Amendment No. 1 dated October 11, 2000
between Syntroleum Corporation and Ivanhoe Energy Inc.
(incorporated by reference to Exhibit 10.18 of Form 10-K filed
with the Securities and Exchange Commission on March 16, 2001)10.4
    
    
    Joint Study Agreement between Petro China Company Limited and
Sunwing Energy Ltd. dated 29 March 2001, for the purposes of
entering into Production Sharing Contracts on the Yudong block.
(Incorporated by reference to Exhibit 10.21 of Form 10-K filed
with
the Securities and Exchange Commission on March 14, 2002)10.5
    
    
    Joint Study Agreement between Petro China Company Limited and
Sunwing Energy Ltd. dated 29 March 2001, for the purposes of
entering into Production Sharing Contracts on the Zitongxi and
Zitondong blocks. (Incorporated by reference to Exhibit 10.22 of
Form 10-K filed with the Securities and Exchange Commission on
March 14, 2002)10.6
    
    
    Joint Venture Agreement and Operating Agreement dated 1 July 2001
between Union Oil Company of California and Ivanhoe Energy (USA)
Inc. on the Creslenn Ranch Area, Henderson County, Texas.
(Incorporated by reference to Exhibit 10.23 of Form 10-K filed
with the Securities and Exchange Commission on March 14, 2002)10.7
    
    
    Joint Venture Agreement and Operating Agreement dated 1 October
2001 between Union Oil Company of California and Ivanhoe Energy
(USA) Inc., in the Bossier Trend, Anderson, Freestone & Henderson
Counties, Texas (Incorporated by reference to Exhibit 10.24 of
Form
10-K filed with the Securities and Exchange Commission on March
14, 2002)






---



##### 



10.8
    
    
    Modification Agreement for Petroleum Development Contract for
Kongnan Block, Dagang Oilfield, the Peoples Republic of China,
dated 24 October 2001. (Incorporated by reference to Exhibit
10.25 of Form 10-K filed with the Securities and Exchange
Commission on March 14, 2002)10.9
    
    
    Consulting Agreement dated 13 January 2002 between Ivanhoe Energy
Inc. and Nahwan Trading LLC. (Incorporated by reference to
Exhibit 10.27 of Form 10-K filed with the Securities and Exchange
Commission on March 14, 2002)10.10
    
    
    Petroleum Contract dated September 2002 for Zitong Block, Sichuan
Basin of the Peoples Republic of China . (Incorporated by
reference to Exhibit 10.12 of Form 10-K filed with the Securities
and Exchange Commission on March 19, 2003)10.11
    
    
    Strategic Development Alliance Letter Agreement dated September
26, 2002 between the Company and CITIC Energy Ltd. (Incorporated
by reference to Exhibit 10.13 of Form 10-K filed with the
Securities and Exchange Commission on March 19, 2003)10.12
    
    
    Loan Agreement dated 31 December 2002 between the Company and
Ivanhoe Capital Finance Limited. (Incorporated by reference to
Exhibit 10.15 of Form 10-K filed with the Securities and Exchange
Commission on March 19, 2003)10.13
    
    
    Amended Standstill Agreement between Linyi Holdings Limited and
the Company dated May 5, 200310.14
    
    
    Cooperation Agreement between Ensyn Petroleum International Ltd.
and Ivanhoe Energy (USA) Inc. dated May 30, 200310.15
    
    
    Employees and Directors Equity Incentive Plan  June 200310.16
    
    
    Agreement in Principle for GTL Project Development between
Syntroleum Corporation and the Company dated June 18, 2003Exhibits10.17
    
    
    Amendment No. 3 to Master License Agreement between Syntroleum
Corporation and the Company dated July 1, 200310.18
    
    
    Settlement Agreement and Mutual Release between Aera Energy, LLC
and Ivanhoe Energy (USA) Inc. dated November 5, 200310.19
    
    
    Heads of Agreement between China International Trust and
Investment Corporation and the Company dated November 18, 200310.20
    
    
    Stock Purchase and Shareholders Agreement between Ensyn Group,
Inc., Ensyn Petroleum International Ltd. and Ivanhoe Energy (USA)
Inc. dated January 15, 200410.21
    
    
    LAK Ranch Farm-in Agreement between Derek Resources (USA) Inc.
and Ivanhoe Energy (USA) Inc. dated January 15, 200410.22
    
    
    Farm-out Agreement among Richfirst Holdings Limited, Pan-China
Resources Limited, Sunwing Energy Ltd. and the Company dated
January 18, 200410.23
    
    
    Farmout and Exploration Agreement, Knights Landing Starkey Sand
Development Program between Ivanhoe Energy (USA) Inc. and
Nahabedian Exploration Group, LLC dated February 17, 200414.1
    
    
    Code of Business Conduct and Ethics21.1
    
    
    Subsidiaries of Ivanhoe Energy Inc.23.1
    
    
    Consent of Gilbert Laustsen Jung Associates Ltd., Petroleum
Engineers23.2
    
    
    Consent of Netherland, Sewell & Associates, Inc.23.3
    
    
    Consent of Deloitte & Touche LLP


2



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##### 



31.1
    
    
    Certification by the Chief Executive Officer Pursuant to Section
302 of the Sarbanes-Oxley Act of 200231.2
    
    
    Certification by the Chief Financial Officer Pursuant to Section
302 of the Sarbanes-Oxley Act of 200232.1
    
    
    Certification by the Chief Executive Officer Pursuant to Section
906 of the Sarbanes-Oxley Act of 200232.2
    
    
    Certification by the Chief Financial Officer Pursuant to Section
906 of the Sarbanes-Oxley Act of 2002(b)
    
    
    
    
    
    
    
    Reports on Form 8-K:


The Company filed a report on Form 8-K on November 24, 2003, which included
information under Item 5 of such form.

3



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##### 



SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.

IVANHOE ENERGY INCBy:
    
    /s/   E. LEON DANIELName:
    
    E. Leon DanielTitle:
    
    President and Chief Executive OfficerDated:
    
    March 2, 2004


Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.

Signature
    
    Title
    
    Date/s/   E. LEON DANIEL

E. Leon Daniel
    
    President, Chief Executive
Officer and Director
(Principal Executive Officer)
    
    March 2, 2004/s/   W. GORDON LANCASTER

W. Gordon Lancaster
    
    Chief Financial Officer
(Principal Financial and
Accounting Officer)
    
    March 2, 2004/s/   DAVID R. MARTIN

David Martin
    
    Chairman of the Board and Director
    
    March 2, 2004/s/   ROBERT M. FRIEDLAND

Robert M. Friedland
    
    Deputy Chairman and Director
    
    March 2, 2004/s/   JOHN A. CARVER

John A. Carver
    
    Director
    
    March 2, 2004/s/   R. EDWARD FLOOD

R. Edward Flood
    
    Director
    
    March 2, 2004/s/   SHUN-ICHI SHIMIZU

Shun-ichi Shimizu
    
    Director
    
    March 2, 2004/s/   HOWARD R. BALLOCH

Howard Balloch
    
    Director
    
    March 2, 2004/s/   J. STEVEN RHODES

J. Steven Rhodes
    
    Director
    
    March 2, 2004


4



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##### 



EXHIBIT INDEX

Exhibit No.
    
    Description3.1
    
    Articles of Ivanhoe Energy Inc. as amended to June 24, 1999 (incorporated by reference to
Exhibits 1.1 through to 1.4 of Form 20-F filed with the Securities and Exchange Commission
on February 28, 2000)3.2
    
    Bylaws of Ivanhoe Energy Inc. (incorporated by reference to Exhibit 1.1 of Form 20-F filed
with the Securities and Exchange Commission on February 28, 2000)10.1
    
    Petroleum Contract for Kongnan Block, Dagang Oilfield of the Peoples Republic of China
dated September 8, 1997 between China National Petroleum Corporation and Pan-China
Resources Ltd., as amended June 11, 1999 (incorporated by reference to Exhibit 3.15 of
Form 20-F filed with the Securities and Exchange Commission on February 28, 2000)10.2
    
    Volume License Agreement dated April 26, 2000 between Syntroleum Corporation and
Ivanhoe Energy Inc. (incorporated by reference to Exhibit 3.37 of Amendment No. 2 to
Form 20-F filed with the Securities and Exchange Commission on July 24, 2000)10.3
    
    Master License Agreement Amendment No. 1 dated October 11, 2000 between Syntroleum
Corporation and Ivanhoe Energy Inc. (incorporated by reference to Exhibit 10.18 of
Form 10-K filed with the Securities and Exchange Commission on March 16, 2001)10.4
    
    Joint Study Agreement between Petro China Company Limited and Sunwing Energy Ltd.
dated 29 March 2001, for the purposes of entering into Production Sharing Contracts on
the Yudong block. (Incorporated by reference to Exhibit 10.21 of Form 10-K filed with
the Securities and Exchange Commission on March 14, 2002)10.5
    
    Joint Study Agreement between Petro China Company Limited and Sunwing Energy Ltd.
dated 29 March 2001, for the purposes of entering into Production Sharing Contracts on
the Zitongxi and Zitongdong blocks. (Incorporated by reference to Exhibit 10.22 of Form
10-K filed with the Securities and Exchange Commission on March 14, 2002)10.6
    
    Joint Venture Agreement and Operating Agreement dated 1 July 2001 between Union Oil
Company of California and Ivanhoe Energy (USA) Inc. on the Creslenn Ranch Area,
Henderson County, Texas. (Incorporated by reference to Exhibit 10.23 of Form 10-K filed
with the Securities and Exchange Commission on March 14, 2002)10.7
    
    Joint Venture Agreement and Operating Agreement dated 1 October 2001 between Union
Oil Company of California and Ivanhoe Energy (USA) Inc., in the Bossier Trend, Anderson,
Freestone & Henderson Counties, Texas. (Incorporated by reference to Exhibit 10.24 of Form
10-K filed with the Securities and Exchange Commission on March 14, 2002)10.8
    
    Modification Agreement for Petroleum Development Contract for Kongnan Block, Dagang
Oilfield, the Peoples Republic of China, dated 24 October 2001. (Incorporated by reference to
Exhibit 10.25 of Form 10-K filed with the Securities and Exchange Commission on March 14, 2002)10.9
    
    Consulting Agreement dated 13 January 2002 between Ivanhoe Energy Inc. and Nahwan
Trading LLC. (Incorporated by reference to Exhibit 10.27 of Form 10-K filed with the
Securities and Exchange Commission on March 14, 2002)10.10
    
    Petroleum Contract dated September 2002 for Zitong Block, Sichuan Basin of the Peoples Republic
of China. (Incorporated by reference to Exhibit 10.12 of Form 10-K filed with the Securities and
Exchange Commission on March 19, 2003)10.11
    
    Strategic Development Alliance Letter Agreement dated September 26, 2002 between the Company
and CITIC Energy Ltd. (Incorporated by reference to Exhibit 10.13 of Form 10-K filed with the
Securities and Exchange Commission on March 19, 2003)10.12
    
    Loan Agreement dated 31 December 2002 between the Company and Ivanhoe Capital Finance
Limited (Incorporated by reference to Exhibit 10.15 of Form 10-K filed with the Securities and
Exchange Commission on March 19, 2003)10.13
    
    Amended Standstill Agreement between Linyi Holdings Limited and the Company dated May 5, 200310.14
    
    Cooperation Agreement between Ensyn Petroleum International Ltd. and Ivanhoe Energy (USA) Inc.
dated May 30, 200310.15
    
    Employees and Directors Equity Incentive Plan  June 200310.16
    
    Agreement in Principle for GTL Project Development between Syntroleum Corporation and the
Company dated June 18, 2003


5



---



##### 



Exhibit No.
    
    Description10.17
    
    Amendment No. 3 to Master License Agreement between Syntroleum Corporation and the Company
dated July 1, 200310.18
    
    Settlement Agreement and Mutual Release between Aera Energy, LLC and Ivanhoe Energy (USA)
Inc. dated November 5, 200310.19
    
    Heads of Agreement between China International Trust and Investment Corporation and the Company
dated November 18, 200310.20
    
    Stock Purchase and Shareholders Agreement between Ensyn Group, Inc., Ensyn Petroleum
International Ltd. and Ivanhoe Energy (USA) Inc. dated January 15, 200410.21
    
    LAK Ranch Farm-in Agreement between Derek Resources (USA) Inc. and Ivanhoe Energy (USA)
Inc. dated January 15, 200410.22
    
    Farm-out Agreement among Richfirst Holdings Limited, Pan-China Resources Limited, Sunwing
Energy Ltd. and the Company dated January 18, 200410.23
    
    Farmout and Exploration Agreement, Knights Landing Starkey Sand Development Program between
Ivanhoe Energy (USA) Inc. and Nahabedian Exploration Group, LLC dated February 17, 200414.1
    
    Code of Business Conduct and Ethics21.1
    
    Subsidiaries of Ivanhoe Energy Inc.23.1
    
    Consent of Gilbert Laustsen Jung Associates Ltd., Petroleum Engineers23.2
    
    Consent of Netherland, Sewell & Associates, Inc.23.3
    
    Consent of Deloitte & Touche LLP31.1
    
    Certification by the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 200231.2
    
    Certification by the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 200232.1
    
    Certification by the Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 200232.2
    
    Certification by the Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002


6