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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
 Washington, D.C. 20549
 FORM 10-K
 (Mark One)þ
    
    Annual Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. For the
fiscal year ended December 31, 2004.or
  o
    
    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
    
    Toronto Stock Exchange
NASDAQ 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  þ    No  o 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.   þ Indicate by check mark whether the registrant is an accelerated filer as defined in Rule 12b-2 of
the Act. Yes  þ    No  o As at February 25, 2005, 169,892,413 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,
2004 based on the closing price on the NASDAQ SmallCap Market on that date, was $369,335,406. Documents incorporated by reference: None




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TABLE OF CONTENTS  
 PagePART IItems 1 and 2
    
    Business and Properties
    
    
    4Corporate Overview
    
    
    4Historical Overview
    
    
    4Corporate Strategy
    
    
    5Oil and Gas Properties
    
    
    6Enhanced Oil Recovery and Heavy-To-Light Oil Projects
    
    
    11Gas-to-Liquids Projects
    
    
    14Risk Factors
    
    
    16Competition
    
    
    20Environmental Regulations
    
    
    20Environmental Provisions
    
    
    20Government Regulations
    
    
    21Employees
    
    
    21Reserves, Production and Related Information
    
    
    21Item 3
    
    Legal Proceedings
    
    
    23Item 4
    
    Submission of Matters to a Vote of Security Holders
    
    
    23PART IIItem 5
    
    Market for Registrants Common Equity and Related Stockholder Matters
    
    
    23Item 6
    
    Five Year Summary of Selected Financial Data
    
    
    25Item 7
    
    Managements Discussion and Analysis of Financial Condition and
Results of Operations
    
    
    26Item 7A
    
    Quantitative and Qualitative Disclosures About Market Risk
    
    
    40Item 8
    
    Financial Statements and Supplementary Data
    
    
    41Item 9
    
    Changes In and Disagreements with Accountants on Accounting
and Financial Disclosure
    
    
    70Item 9A
    
    Controls and Procedures
    
    
    70PART IIIItem 10
    
    Directors and Executive Officers of the Registrant
    
    
    72Item 11
    
    Executive Compensation
    
    
    74Item 12
    
    Security Ownership of Certain Beneficial Owners and Management
    
    
    80Item 13
    
    Certain Relationships and Related Transactions
    
    
    81Item 14
    
    Principal Accountant Fees and Services
    
    
    81PART IVItem 15
    
    Exhibits, Financial Statement Schedules and Reports on Form 8-K
    
    
    82
 2




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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: 2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000Closing
    
    $
    0.83
    
    
    $
    0.77
    
    
    $
    0.63
    
    
    $
    0.63
    
    
    $
    0.67Low
    
    $
    0.72
    
    
    $
    0.63
    
    
    $
    0.62
    
    
    $
    0.62
    
    
    $
    0.64High
    
    $
    0.85
    
    
    $
    0.77
    
    
    $
    0.66
    
    
    $
    0.67
    
    
    $
    0.70Average Noon
    
    $
    0.77
    
    
    $
    0.71
    
    
    $
    0.63
    
    
    $
    0.65
    
    
    $
    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 February 25, 2005 was $ 0.81 ($1.00 =
Cdn.$1.24). ABBREVIATIONS As generally used in the oil and gas business and in this Annual Report on Form 10-K, the following
terms have the following meanings: Boe
    
    = barrel of oil equivalentBbl
    
    = barrelMBbl
    
    = thousand barrelsMMBbl
    
    = million barrelsBopd
    
    = barrels of oil per dayBbls/d
    
    = barrels per dayBoe/d
    
    = barrels of oil equivalent per dayMboe/d
    
    = thousands of 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 industry standard in which one Bbl is equal to six Mcf.
Boes may be misleading, particularly if used in isolation. The conversion ratio is based on an
energy equivalency conversion method primarily applicable at the burner tip and does not represent
a value equivalency at the wellhead. SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS Certain statements in this document are forward-looking statements within the meaning of the
United States Private Securities Litigation Reform Act of 1995, Section 21E of the United States
Securities Exchange Act of 1934, as amended, and Section 27A of the United States Securities Act of
1933, as amended. Such forward-looking statements involve known and unknown risks, uncertainties
and other factors which may cause our actual results, performance or achievements, or other future
events, to be materially different from any future results, performance or achievements or other
events expressly or implicitly predicted by such forward-looking statements. Such risks,
uncertainties and other factors include, but are not limited to, our short history of limited
revenue, losses and negative cash flow from our current exploration and development operations in
the U.S. and China; our limited cash resources and consequent need for additional financing; our
ability to raise additional financing; future benefits to be derived from the proposed acquisition
of Ensyn Group, Inc. (Ensyn); conditions to completing the Ensyn acquisition and timetable for
completion and other matters; uncertainties regarding the potential success of our oil and gas
exploration and development properties in the U.S. and China; uncertainties regarding the potential
success of heavy-to light oil upgrading and gas-to-liquids technologies; 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. 3




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ENFORCEABILITY OF CIVIL LIABILITIES We were 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,
officers, controlling persons 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 (HTL)
oil upgrading and gas-to-liquids (GTL) technologies. Our core operations are in the United States
and China, with business development opportunities worldwide. We were incorporated pursuant to the laws of the Yukon, Canada, on February 21, 1995 under the name
888 China Holdings Limited. On June 3, 1996, we changed our name to Black Sea Energy Ltd., and on
June 24, 1999, we changed our name to Ivanhoe Energy Inc. Our 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 office is located at Suite 654  999 Canada Place, Vancouver, British
Columbia, V6C 3E1, and our registered and records office is located at 300-204 Black Street,
Whitehorse, Yukon, Y1A 2M9. Our headquarters for operations is located at Suite 400  5060
California Avenue, Bakersfield, California, 93309. 
 HISTORICAL OVERVIEW We were incorporated in 1995 and, in 1996, established a series of joint ventures in Russia with
local partners to enhance oil recovery from certain Russian oil and gas properties on which past
field development practices had not maximized reserve recoveries. However, after successfully
increasing oil production and reserves at the Kalchinskoye field in western Siberia, a dispute with
our partner arose in 1998, which effectively prevented us from continuing to participate in the
project. Although the dispute was settled in 2000, our management had already decided to terminate
our business activities in Russia and implement a diversification program aimed at expanding the
geographical scope of our business. During 1998, we accumulated working interests and royalty interests in the San Joaquin Basin of
California, primarily through an exploration agreement with Aera Energy LLC (Aera). This
agreement entitled us to joint exploration rights with Aera in return for analyzing and identifying
oil and gas prospects on properties owned by Aera in the San Joaquin Basin of southern 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 acquisition of
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 located in Heilongjiang Province. We subsequently disposed of our
interest in the Daqing field but retained a royalty. In April 2003, we received approval of our
Overall Development Program (ODP) for the Dagang field and in September 2003 we commenced
drilling. We signed a farm-out agreement with China International Trust & Investment Corporation
(CITIC) for 40% of the Dagang field. This farm-out agreement provides that the parties will
jointly develop the field, with Sunwing as the operator. 4




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In April 2000, we acquired a limited volume license and, subsequently, a master license from
Syntroleum Corporation (Syntroleum) to use its proprietary GTL technology to convert natural gas
into synthetic fuels. The master license allows us to use Syntroleums proprietary process in an
unlimited number of GTL projects throughout the world to convert natural gas into an unlimited
volume of ultra clean transportation fuels and other synthetic petroleum products (Site License).
We plan to use the technology in areas with large natural gas deposits, which would otherwise be
uneconomic to develop. Our master license expires on the latter of April 2015 or five years from
the effective date of the last Site License issued to us by Syntroleum. During 2000 and 2001, we expanded into Texas by earning working interests in oil and gas
exploration properties in the Spraberry Trend of the West Texas Permian Basin and leasing mineral
rights in the East Texas Basin. In 2001, we entered into a joint venture agreement with a
subsidiary of Unocal Corp. (Unocal) to explore and develop prospects in the Bossier Trend of the
East Texas Basin. We subsequently farmed-out our interests in three wells drilled by Unocal and
currently have mineral rights in approximately 7,400 gross acres. In February 2001, we extended our China interests. We entered into two memoranda of understanding
with PetroChina Corporation (PetroChina), a subsidiary of CNPC, which gave 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
with CNPC for two of these blocks covering approximately 900,000 acres, which were combined into
one Zitong block. In October 2003, we initiated the first phase of the exploration program in the
Zitong block. We have the right to negotiate a production-sharing contract for the third block, the
one-million-acre Yudong Block, located on the eastern edge of the Sichuan Basin. In December 2002, we formed a wholly owned subsidiary, GTL Japan Corporation (GTLJ) to facilitate
the participation of Japanese companies in GTL projects and in November 2004 changed the name to
Energy Resources Development Japan Corporation (ERDJ) and expanded the charter of the company to
include participation of multi-national companies in enhanced oil recovery (EOR) projects,
including those involving HTL oil upgrading. In January 2004, we finalized an agreement with Derek Resources (USA), Inc. (Derek) to jointly
develop the LAK Ranch field, a steam assisted gravity drainage (SAGD) project covering
approximately 7,300 gross acres in the Powder River basin in Weston County, Wyoming. In January 2004, we entered into a stock purchase and shareholders agreement with Ensyn and its
subsidiary, Ensyn Petroleum International Limited (EPIL) pursuant to which we acquired a 10%
equity interest in EPIL for $2.0 million and certain rights to use their proprietary rapid thermal
processing technology (RTP Technology). We subsequently increased our equity interest in EPIL to
15% in consideration of a cash payment to EPIL of $1.0 million. In December 2004, we signed a definitive merger agreement to acquire Ensyn for $85 million. We
agreed to pay $10 million in cash and to issue common shares valued at $75 million based on a
weighted, 10-day average of our closing share price on the NASDAQ SmallCap Market determined prior
to the closing of the acquisition (subject to a minimum issuance of 30 million shares), in exchange
for all of the issued and outstanding shares of Ensyn common shares and the rights of holders of
purchase warrants to acquire shares of Ensyn common shares that remain unexercised immediately
after the effective time of the merger. We currently expect the merger with Ensyn to be completed
early in the second quarter of 2005. Prior to the closing of the transaction, Ensyn will be
required to satisfy our defined performance criteria for their California Commercial Demonstration
Facility (CDF). In December 2004, we purchased the remaining working interest in seven wells, either producing or
capable of producing, that we did not already own in the Knights Landing field in the Sacramento
Gas Basin of northern California and an 80% working interest in four additional producing wells in
which we did not previously hold an interest. The purchase includes mineral leases on 13,000 gross
acres surrounding the producing wells. We originally farmed into this field in February 2004 for a
50% working interest after pay out. 
 CORPORATE STRATEGY Our objective is to create shareholder value by finding and developing oil and gas reserves through
the implementation of three main 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 the Ensyn RTPTM Technology and
the technology licensed from Syntroleum. 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 continue exploration and development of our significant mineral
interest holdings in California, Wyoming and China and develop opportunities for the Ensyn RTP
TM Technology in the oil sector. Our long-term priority is on GTL production of ultra
clean fuels and specialty petroleum products. We have advanced each of these objectives during the
past year and our projects continue to mature. Our short-term objective is to focus on exploiting our existing mineral interest holdings and
identifying new opportunities where 5




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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 and Citrus properties in the San Joaquin Basin, in the
Knights Landing field in the Sacramento Gas Basin, in the Spraberry Trend of the West Texas Permian
Basin and at the Dagang field in China. Over the next twelve months, we plan to drill more than
thirty development wells on our current producing properties, six exploration wells in East Texas
and non-Aera properties in California and also initiate a completion and testing program of our
Northwest Lost Hills # 1-22 well, which is our deep gas play in the San Joaquin Basin. One of the key elements of our medium-term strategy is continued exploration and development in the
San Joaquin Basin. In 1998, we acquired exploration rights through an agreement with Aera,
Californias largest producer. This agreement gave us access to Aeras inventory of exploration,
seismic and technical data for the purpose of identifying drillable prospects, primarily beneath or
adjacent to existing oil fields in the San Joaquin Basin. Nine identified drillable prospects, in
which Aera has agreed to participate, have yet to be explored. The LAK Ranch field is also a key
element of our medium-term strategy. After completion of an ultra-high resolution 3-D seismic
survey and interpretation in the first half of 2005, we plan to drill additional delineation wells
to prove up oil-in-place reserves and commerciality of a full steam injection SAGD project. Our exploration activities in China also have the potential to contribute to our medium-term
growth. In September 2002, we entered into a 30-year production-sharing contract with CNPC in the
western portion of the Sichuan Basin. Under the terms of the agreement, we will explore for and
develop natural gas deposits on the 900,000-acre Zitong block.We plan to commence the drilling of
our first exploration well on this block in the first quarter of 2005. One of the most significant elements of our medium-term strategy is the acquisition of Ensyn.
Current test results from over 90 test runs on heavy oil at Ensyns pilot plant in Ontario show
that Ensyns RTP Technology offers a means of improving the value of heavy, sour crude oils in a
manner that is comparable to established coking technologies but at significantly lower operating
and capital costs. In addition, these test results evidence that the RTP Technology reduces or
eliminates the need for an external energy source (usually natural gas, for steam production used
in the recovery process), reduces the viscosity of the heavy oil and also permits the use of the
processed oil to be used as a blending agent to facilitate the transportation of heavy oil by
pipeline. We believe that the innovative characteristics of Ensyns RTP Technology offer the means to
technologically and economically improve the production and marketing of heavy oil in the petroleum
industry, which will provide us with an opportunity to significantly increase our base of oil
reserves worldwide through joint venture and production sharing arrangements. As a result, the
acquisition is expected to represent a major advance in the implementation of our corporate
strategy because it will offer significant potential for broadening our access to project
opportunities that might not otherwise be available to us. 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 we believe the plant is safer to operate
because, unlike competing technologies, the conversion process utilizes compressed air rather than
pure oxygen. 
 OIL AND GAS PROPERTIES Our primary oil and gas properties are located in Californias San Joaquin Basin and Sacramento Gas
Basin, the West Texas Permian and East Texas Basins, the Powder River Basin in Wyoming 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 seven years, we acquired interests in a number of properties in and around the San
Joaquin Basin. In 2004, we acquired properties in the Knights Landing field in the Sacramento Gas
Basin and established production in the Citrus field in the San Joaquin Basin. To date, our South
Midway, Citrus and Knights Landing properties contain proved reserves and have wells on production.
We cannot assure you that any of our other prospects in California will result in the development
of commercially viable production. Aera Exploration Agreement The Aera exploration agreement, originally covering an area of more than 250,000 acres in the San
Joaquin Basin, gave us access to all of Aeras exploration, seismic and technical data in the
region for the purpose of identifying drillable exploration prospects. To date, we have identified
13 prospects within 11 areas of mutual interest (AMIs) covering approximately 72,400 gross acres.
Of the 13 prospects submitted, Aera has elected to take a working interest in 10 prospects,
resulting in us retaining working interests ranging 6




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from 12.5% to 50%. We have a 100% working interest in three prospects 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 on that prospect. There is no time
deadline for drilling to occur if Aera elects to participate in the drilling of a prospect. If Aera
elects not to participate we have an additional two years to drill the prospect on our own or with
other parties. This two-year period will be extended as long as we continue to drill or have
established production.  
    South Midway We currently have 55 producing wells in South Midway and are the operator, with a working interest
of 100% and a 93% net revenue interest. In 2004, we drilled seven new wells on the South Midway
properties, consisting of six step-out development locations and one exploratory well. Four of the
six development wells were completed as producers. The exploratory well was unsuccessful and will
be held for a future disposal well. In the southern expansion area, we have supplemented the cyclic steam project with a pilot to test
continuous steam injection into two wells. The project began in October 2004 and by year-end 2004
it was beginning to yield increased production in the surrounding wells. If successful, continuous
steam injection could increase recovery of the oil in place by an estimated 50-70%, similar to
recovery in other fields in the area, and add a significant amount of probable reserves to our
proved undeveloped reserves. Current production from the southern expansion area is approximately
165 Bopd and total South Midway production is approximately 585 Bopd.  
    Citrus We are the operator of the Citrus field, 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 have leased mineral interests ranging from 83% to 100% in approximately
3,400 gross acres offsetting the Lost Hills field, where there has been development drilling. One horizontal and two vertical development wells were drilled and completed on this southern
extension area of the Lost Hills field in 2004. Production is currently approximately 120 Bopd and
450 Mcf/d of gas with all three wells on rod pump. We are evaluating drilling another horizontal
leg on Citrus #1 by the second quarter of 2005. The target upper Antelope zone, located a few
hundred feet above the existing horizontal well, should yield improved oil rates and reduced water
from the lease. Development drilling may resume during the last half of 2005, following this test.  
    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. Progress has been made towards finding investment partners
to complete and test the Temblor formation and resolution of the Northwest Lost Hills #1-22 well is
expected in 2005. Until it is tested, the wells commercial potential, if any, cannot be
determined. Of the approximately 8,000 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% under a new arrangement.  
    Belgian Anticline We drilled the first well in this prospect in 2001 and found non-commercial gas shows. A second
well in this prospect, originally contemplated for 2004, has been delayed and may be drilled in
2005. We have a 40% working interest in this prospect and Aera is the operator. Other California Prospects  
    Knights Landing In February 2004, we farmed into the Knights Landing field, which is a 13,000-acre block located in
the Sutter and Yolo counties, in northern California. Under this exploration and development
farm-in agreement, we purchased, for $1.0 million, a 50% working interest in four previous
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. We
drilled nine new exploratory wells under this agreement in order to earn a 50% working interest
after payout in any new discoveries. Our 2004 drilling resulted in three successful completions 7




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and six dry holes. The three new discovery wells are expected to be connected in the first quarter
of 2005. The primary objective of this development and exploration program is the Starkey Sand
formation, which is an established producing reservoir in the region that lies between depths of
2,000 to 3,500 feet. In December 2004, we reached an agreement with the operator of the field to purchase its interest,
increasing our working interests in the field and existing producing gas wells to between 80% and
100%. We plan to use 3-D seismic to identify additional prospects and development well locations
as well as reduce the dry hole risk in this gas producing area. Gross production is currently
1,520 Mcf/d from six producing wells. Well workovers are planned to increase gas rates and reduce
operating costs.  
    North South Forty In 1999, we entered into agreements with two other companies to pool certain of our acreage
positions and jointly conduct a 3-D seismic survey in the southern San Joaquin Basin in order to
identify new prospects. Although these agreements expired in 2003, we identified four drillable
prospects covering approximately 13,400 gross acres, in which we have working interests ranging
from 17.5% to 50%. We participated with a 50% working interest in drilling two exploration prospects in the North
South Forty area during 2004 but both wells were plugged and abandoned. In December 2004, we participated in drilling a well with a carried 50% working interest in the
third of the four prospects we developed from the 3-D seismic data in the North South Forty area.
The Peach #1 well is located just west of the North Antelope Hills field. The well was drilled to a
depth of 4,500 feet and initial evaluation was encouraging at test rates of 800Mcf/d on a 9/16-inch
choke. During the test, the well produced natural gas and condensate with no water production. We
will follow up testing with an estimate of commerciality, the drilling of an appraisal well and
discussions with gas buyers. Gas gathering facilities and natural gas markets exist in close
proximity to the discovery.  
    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 first well, Sledge Hamar 1-7, began
producing in January 2004 at 30 Bopd from the Stevens sands at 4,950 feet. However, the follow up
well drilled in April 2004 encountered the Stevens sands below the oil/water contact and tested
only water. After evaluating the production results and other potential hydrocarbon intervals, we
concluded that the future economic potential was unfavorable and, in December 2004, sold our
working interest.  
    McCloud Ranch / North Salt Creek In mid-2004, we farmed into the McCloud River Prospect near the Cymric field in the San Joaquin
Basin with a 24% working interest. The initial well resulted in a dry hole. As a result of follow
up work in the area, a second prospect was developed on the acreage called the North Salt Creek
prospect. It is anticipated that we will participate with a 24% working interest and serve as
operator for drilling this prospect in the first quarter of 2005. We have an interest in 1,140
gross acres over this prospect. 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 2000 through a farm-in. 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 80
net Boe/d.  
    East Texas We currently own mineral rights in approximately 7,400 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 4,300 gross acres. We spud the first well in the Malakoff prospect in the first quarter of 2005 where we will have a
25% carried working interest. The well is located in Henderson County, Texas and will be drilled to
8,200 feet to test the Rodessa and Travis Peak sands in the prospect. We have an interest in
approximately 1,300 gross acres in the prospect. In November 2003, we farmed out our interest in the Catfish Creek prospect for an 11,000-foot well
to test the Rodessa and Pettit 8




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formations. We will retain a 25% working interest after payout in this prospect and surrounding
acreage. We plan to spud this well after drilling the first well in the Malakoff prospect. In 2003, we farmed out our interests in two wells we drilled in the Creslenn Ranch prospect 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 and is currently on production. The second well was plugged and
abandoned after determination was made that it was not economic. We retain a 30% working interest
after payout in the producing well and a 50% working interest in the remaining acreage. 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. Prior to the farm-in agreement, Derek completed a SAGD horizontal well pair to a depth of 1,000
feet and 1,800 feet into the Newcastle Sand formation. Surface steam-injection and oil-recovery
equipment were installed. 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. Facility modifications for the pilot phase were completed in the second quarter of 2004
to enable steam injection in the producing horizontal well. Two cycle steam stimulation treatments
were performed during the year. The second cycle of steam injection was completed in September
2004 with over 13,000 barrels of steam injected into the horizontal well. Production following the
second steaming increased from the first steam cycle. The well is currently producing minimal
amounts of oil and may be stimulated with a third steam cycle in the first quarter of 2005, pending
results of seismic interpretation and recent drilling data. The ultra-high resolution 3-D seismic survey needed to better define the optimum reservoir
development locations began in November and was completed in December 2004. We expect evaluation
results during the second quarter of 2005. In addition, one vertical well was drilled in the first
quarter of 2005 for data collection purposes. After completion of the 3-D seismic survey we plan to
use the data to plan and drill injection wells and test the potential of continuous steam
injection. Following completion of the pilot phase, the development phase is scheduled to include additional
horizontal production wells, new steam-injection and extension of surface facilities. We estimate
that, at the low end of the initial development phase the program could grow to more than 20
producing wells. During the pilot phase, our working interest has increased from an initial 30% to
39% by year-end 2004. Should we decide to enter into the next two phases of the contract, our
working interest will increase to a maximum of 60%. Should we elect not to proceed beyond the pilot
phase, our working interest would be reduced to 15% and we would no longer be the operator. China  
    Dagang Our 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 field). Under the contract as operator, we fund 100% of the
development costs to earn 82% of the net revenue from oil production until cost recovery, at which
time our entitlement reverts to 49%. In January 2004, we negotiated farm-out and joint operating
agreements with Richfirst Holdings Limited (Richfirst), a wholly owned subsidiary of CITIC
whereby Richfirst paid $20.0 million to acquire a 40% working interest in the field after Chinese
regulatory approvals, which were finalized in June 2004. Richfirst will have the right to exchange
its working interest in the Dagang field for common shares in Sunwing, should we obtain a public
listing for Sunwing, or for common shares in Ivanhoe. Richfirsts right to exchange its working
interest for Ivanhoe common shares expires in December 2005. CITIC also has committed to assist in
arranging non-recourse project financing for the remainder of the Dagang development program. The production-sharing 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 historically has averaged approximately $2.00 per barrel less than the West Texas
Intermediate 9




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(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 field 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 field will revert to CNPC at the end
of the 20-year production phase of the contract or if we abandon the field earlier. During 2001, we completed the pilot phase and in 2002 submitted the final draft of our ODP to the
Chinese regulatory authorities for approval. Final government approval was obtained in April 2003,
after which the development phase commenced in late 2003. In 2004, we drilled 19 development wells
of which 16 were completed and placed on production. The year-end 2004 gross production rate was
1,655 Bopd. To complete the ODP over the next three years, we expect to drill 90 new wells and
rework an additional 28 of the 82 existing wells at an estimated cost to Ivanhoe of $113 million.  
    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 the Zitong and Yudong land blocks
in Sichuan Province, which cover an area of approximately 2.2 million acres. We agreed with
PetroChina to carry out joint feasibility studies on the blocks located in the Sichuan Basin,
approximately 930 miles southwest of Beijing. In September 2002, we signed a production-sharing
contract (the Zitong Contract), with CNPC. The Zitong Contract received final Chinese regulatory
approval in November 2002. Under the Zitong Contract, we agreed to conduct an exploration program on the Zitong block
consisting of two phases, each three years in length. The parties will jointly participate in the
development and production of any commercially viable deposits, with production rights limited to a
maximum of the lesser of 30 years following the date of the Zitong Contract or 20 years of
continuous production. During the first phase of exploration, we must complete a minimum work program consisting of
reprocessing approximately 1,250 miles of seismic data, completing approximately 300 additional
miles of new seismic lines and drilling and completing two wells totaling at least 23,000 feet,
with estimated minimum expenditures for the program of $18 million. Upon completion of the first
phase, we must relinquish up to 30% of the Zitong block. During 2003 and 2004, we reprocessed
approximately 1,550 miles of existing seismic data and acquired approximately 540 miles of a
700-mile seismic acquisition program. Following processing and interpretation of the seismic data,
we selected the location of our first exploration well and expect to spud the well in the first
quarter of 2005. If we elect to participate in phase two, we must complete a minimum work program consisting of new
seismic lines totaling approximately 200 miles and drill and complete two additional wells totaling
approximately 23,000 feet, with estimated minimum expenditures for the program of $16 million.
Following the completion of phase two, we must relinquish all of the property except any areas
identified for development and production. We can elect to commence the development of commercially viable deposits at any time following the
submission of an ODP. Once we complete phase one of the exploration project, we can also elect not
to proceed with phase two of the exploration project. However, once we commence a phase of the
exploration project we must complete the minimum work program or we will be obligated to pay, to
CNPC, the cash equivalent of the deficiency in the work program for that exploration phase. If we identify a field for development and/or production, the parties will divide the participating
interest in the project, with CNPC entitled to fund and take up to 51% of the participating
interest. Once commercial production commences, we 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, we are entitled to production equaling our participating interest, subject to
certain additional rights of the Chinese government. Assuming we hold a 49% participating interest,
we will be entitled to approximately 75% of production initially, declining to approximately 45%
after full exploration and development cost recovery. CNPC retains the rights to production from six existing wells located on the Zitong block. We can
drill new wells on the same structure as those tapped by the existing wells, but our wells must be
no closer than 3,280 feet 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. 10




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
    CITIC Alliance In October 2002, we 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. We are 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 us in our efforts to negotiate a production-sharing contract
with PetroChina covering the Yudong block in the Sichuan Basin. 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. 
 ENHANCED OIL RECOVERY AND HEAVY-TO-LIGHT OIL PROJECTS  
    Ensyn The Ensyn RTPTMTechnology, patented in the U.S., Canada and other countries, upgrades
the quality of heavy oil by producing lighter, more valuable crude oil. Ensyn reports that this
process dramatically improves the economics 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
RTPTMTechnology uses readily available plant and process components. The RTPTMTechnology already has been successfully applied to continuous wood/biomass
processing, in six commercial plants in operation in Canada and the U.S. A seventh biomass plant is
under construction in Canada. The technology has recently been applied to petroleum processing and
an Ensyn pilot plant in Ontario, Canada has completed more than 90 test runs on heavy oil. In
addition, Ensyns 1,000-barrel-per-day CDF, located in the Belridge heavy oil field near
Bakersfield, California, successfully started up in December 2004. Ensyn currently plans to use the
facility to process local heavy oil, as well as to test a range of heavy crudes from around the
world. During 2004, we acquired, for $3.0 million, a 15% equity interest in EPIL and exclusive rights to
use the proprietary Ensyn RTPTM Technology in key international markets in China,
Mongolia, Iraq, Oman and all countries in South America except Venezuela. In these countries, we
have exclusive rights to use the Ensyn RTP Technology for an initial term of five years until
January 2009, subject to extension if and when commercial plants are constructed. For each project
we develop using the Ensyn RTPTMTechnology in our exclusive territories, Ensyn could
elect to receive an equity participation in the project for the same proportionate cost we paid.
The participation that may be obtained by Ensyn could be no more than 10%, except for each such
project that we develop in South America, other than in Peru, where Ensyn could elect to receive an
equity interest equal to 25% of our interest. Ensyns equity position would offset and eliminate
the payment of license fees for use of the Ensyn RTPTMTechnology in the project. On December 11, 2004, Ivanhoe, Ivanhoe Merger Sub, Inc. (Merger Sub), a Delaware corporation and
our wholly-owned subsidiary, and Ensyn entered into an Agreement and Plan of Merger (the Merger
Agreement), pursuant to which Merger Sub will be merged with and into Ensyn and Ensyn will become
our wholly owned subsidiary (the Merger) and all of the issued and outstanding shares of Ensyn
common stock will be converted into the right to receive cash and common shares of Ivanhoe. 11




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We have agreed to pay $10 million in cash and issue Ivanhoe common shares (Merger Shares) in
exchange for all of the issued and outstanding Ensyn common shares and all unissued Ensyn common
shares issuable upon the future exercise of any purchase warrants that remain unexercised when the
Merger takes effect. The number of Merger Shares to be issued will be the greater of: (i)
30,000,000 or (ii) the quotient obtained by dividing $75 million by the weighted average of the
closing prices of Ivanhoe common shares on the NASDAQ SmallCap Market over a period of ten
consecutive trading days determined five business days prior to the scheduled date of a special
meeting of the shareholders of Ensyn at which their approval of the Merger will be sought. One-third of the total number of Merger Shares issued will be deposited and held in an escrow fund
(the Indemnity Escrow Fund) to secure certain obligations on the part of the Ensyn shareholders
and to indemnify us for damages arising from breaches of warranties and covenants under, and other
circumstances more particularly described in, the Merger Agreement. Subject to any prior claims by
us for indemnification, one-half of the Merger Shares in the Indemnity Escrow Fund will be released
to the Ensyn shareholders no later than 20 days from (i) the date that we, Ensyn or any of our
respective controlled affiliates enters into a definitive agreement with an unaffiliated third
party for the construction or use of a processing plant equipped with the RTP Technology and
having a minimum daily input processing capacity of 10,000 barrels of oil per day (an RTP Plant)
or (ii) the second anniversary of the closing date of the Merger, whichever is earlier. The
balance of the Merger Shares in the Indemnity Escrow Fund will be released, subject to any prior
claims by us for indemnification, as of (i) the second anniversary of the date that we, Ensyn or
any of our respective controlled affiliates enters into a definitive agreement with an unaffiliated
third party for the construction or use of an RTP Plant, (ii) the second anniversary of the date
that we or any of our controlled affiliates commences construction of an RTP Plant, (iii) the date
that we, Ensyn or any of our respective controlled affiliates enters into a second definitive
agreement with an unaffiliated third party for the construction or use of an RTP Plant, (iv) the
date that we or any of our controlled affiliates commences construction of a second RTP Plant, and
(v) the third anniversary of the closing date of the Merger, whichever is earliest but, in any
event, no earlier than the first anniversary of the closing date of the Merger. Ensyn currently uses the RTP Technology in two ways: a biomass process that transforms wood and
other organic material into bio-fuels, resins and other products (the Renewables Business) and a
petroleum process that upgrades heavy oil and bitumen, into lighter, less viscous petroleum
products (the Petroleum Business). The Merger Agreement provides that Ensyn will use
commercially reasonable efforts to distribute to its shareholders, by way of a dividend prior to
the Merger taking effect, all of the issued and outstanding shares of a newly formed wholly owned
subsidiary that, prior to such distribution, will indirectly own and operate the Renewables
Business. Ensyn will retain the Petroleum Business when it becomes our wholly owned subsidiary
pursuant to the Merger. Upon the Merger taking effect, we will thereafter share the intellectual
property rights in the RTP Technology with Ensyn through a series of cross-licensing and
non-competition arrangements. Upon the implementation of the Merger, two individuals designated by Ensyn will be appointed to our
Board of Directors. We have agreed to use our reasonable best efforts to nominate Ensyns designees
for re-election to our Board of Directors annually for at least five years. The respective obligations of the parties to consummate the Merger are subject to a number of
conditions precedent customary in similar transactions. These conditions include the adoption of
the Merger Agreement and the approval of the Merger by a majority of the votes cast by the Ensyn
shareholders at a special meeting to be convened for that purpose and, if the number of Merger
Shares to be issued, together with any other common shares of Ivanhoe issued or issuable pursuant
to any private placement equity financing transactions undertaken by us in connection with the
Merger, exceeds the maximum number of common shares that we would be permitted to issue without
shareholder approval under the applicable rules of the Toronto Stock Exchange, approval of the
issuance of such Ivanhoe common shares by a majority of the votes cast by our shareholders at a
special meeting to be convened for that purpose. Our obligation to effect the Merger is also subject to Ensyns RTP Technology-equipped commercial
demonstration facility in California having satisfied certain technical performance requirements
and criteria provided for in the Merger Agreement. This condition will be satisfied when we receive
reports from certain third party technical consultants confirming that the facility has met the
requisite requirements and criteria. The transactions contemplated by the Merger Agreement are expected to close early in the second
quarter of 2005. Either we, or Ensyn, may elect to terminate the Merger Agreement if the Merger has
not been consummated by May 15, 2005, subject to an extension of up to sixty days in certain
circumstances more particularly described in the Merger Agreement. There can be no assurance that
the transactions contemplated by the Merger Agreement will be consummated. The Boards of Directors of both Ivanhoe and Ensyn have approved the merger transaction. In reaching
its decision to approve the merger transaction, our Board of Directors considered a variety of
factors, a number of which are summarized below:  
    Acquiring innovative petroleum production technology is a key aspect of our corporate
strategy.A key aspect of our corporate strategy is to grow our business by expanding our
oil and gas reserve base. Although part of this strategy involves 12




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conventional exploration and production, our management recognizes that we lack the size and
the significant financial resources necessary to pursue the conventional exploration and
production growth strategies historically undertaken by large, integrated oil companies. The
core of our corporate strategy is to accelerate the development of our business by leveraging
the experience, expertise and existing business relationships of our senior management
personnel. We seek projects requiring relatively low initial capital outlays to which we can
apply innovative technology and enhanced recovery techniques in developing them. Our Board of
Directors believes that the acquisition of Ensyns RTP Technology will represent a major
advance in the implementation of our corporate strategy in that it offers significant
potential for broadening our access to project opportunities that might not otherwise be
available to us.
    Ensyns RTP Technology represents a unique approach to heavy oil upgrading.The
innovative characteristics of Ensyns RTP Technology offer the means to technologically
and economically improve the production and marketing of heavy oil in the petroleum
industry. Current test results from over 90 test runs on heavy oil at Ensyns pilot plant
in Ontario show that the RTP Technology offers a means of improving the value of heavy,
sour crude oils in a manner that is comparable to established coking technologies but at
significantly lower operating and capital costs. In addition, these test results evidence
that the RTP Technology reduces or eliminates the need for an external energy source
(usually natural gas, for steam production used in the recovery process), reduces the
viscosity of the heavy oil and also permits the use of the processed oil to be used as a
blending agent to facilitate the transportation of heavy oil by pipeline.
    Heavy oil represents a vast untapped resource.Heavy oil deposits throughout the world
represent a potentially massive resource, holding quantities of heavy oil more than double
the existing global reserves of light or conventional oil. Heavy oil extraction and
transportation presents a number of technological challenges and typically requires
extensive and cost-intensive infrastructure. Higher viscosity makes the transportation of
heavy oil through conventional pipelines difficult or impossible unless it is first blended
with lighter, lower viscosity oil or expensive diluents. As a result, less than 1% of the
worlds heavy oil deposits are currently under active development. Our Board of Directors
believes that Ensyns RTP Technology offers us the unique opportunity to accumulate
reserves by acquiring interests in stranded heavy oil deposits that would otherwise be
uneconomic to develop through conventional means and developing them on an incremental,
cost-efficient basis using Ensyns RTP Technology.
    Application of Ensyns RTP Technology to heavy oil deposits offers potentially
significant economic benefits.Our Board of Directors believes that, if the Ensyn RTP
Technology can be deployed on a commercial scale, it will offer a number of potential cost
saving and revenue-enhancement benefits. The reduction or elimination of the need for an
external energy source, usually natural gas, for steam production used in the heavy oil
recovery process, often a substantial added cost to conventional producers, could
significantly reduce the operating cost of extracting the heavy oil. The RTP Technology
upgraded oil is likely to command a higher market price, reducing what would otherwise be a
significant price differential between heavy and light oil. The price paid to producers
for heavy oil is lower than the price paid for light oil as the heavy oil requires
additional refining. Unlike conventional heavy oil extraction facilities, which usually
must be constructed on a large scale in order to be economical and therefore require a
significant up-front capital investment, we expect to be able to deploy the RTP Technology
on a relatively small scale and independent of refineries, which should allow us to develop
smaller heavy oil fields that would otherwise be uneconomic to exploit using conventional
technologies. The scalability of RTP Technology-equipped facilities offers the
potential to develop heavy oil deposits on an incremental basis financed by cash flow.
Given their limited infrastructure requirements, RTP Technology-equipped facilities can be located in relatively remote areas where constructing conventional
facilities would not be feasible.
    Exclusive control of Ensyns RTP Technology in its application to petroleum processing
gives us an important strategic advantage.Although we already hold exclusive licensing
rights to deploy Ensyns RTP Technology in petroleum processing projects in a number of
countries, including China, Mongolia, Iraq, Oman and most of South America and
non-exclusive rights to use the technology elsewhere in the world, exclusive control of the
technology throughout the world increases our leverage in the pursuit of our strategic
plans and objectives. We believe that the value of the technology can be maximized by using
it to create opportunities to acquire interests, and actively participate, in heavy oil
development projects rather than licensing the technology to third parties and collecting
passive licensing payments. The acquisition of Ensyn will advance this strategy by giving
us the exclusive right, subject to limited pre-existing licensing rights, to deploy the
RTP Technology anywhere in the world, including in the key North American markets. At the
same time, the acquisition will effectively result in us re-acquiring from Ensyn the future
project participation rights (between 10% and 25%) we granted to Ensyn when we first
acquired exclusive licensing rights in the technology and will minimize our obligations to
pay licensing fees in respect of those projects we develop using the technology.
    Combining the technical expertise of Ensyns personnel with the international petroleum
industry experience and expertise of our personnel will benefit us.Our Board of Directors
believes that aligning the interests of Ensyns shareholders with those of our shareholders
ensures that we will continue to enjoy access to the benefits of the scientific and
technological expertise possessed by Ensyns personnel. Our management team has been
working closely with key members of Ensyns management 13




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team, including Ensyns co-founders, for nearly two years. The acquisition of Ensyn should
create synergies between the technical expertise of Ensyns personnel and the international
petroleum industry experience and expertise of our personnel and result in a more integrated
Ivanhoe/Ensyn management team for the deployment of the RTP Technology, as the former Ensyn
shareholders will become significant shareholders in our company and two members of Ensyns
management will join our Board of Directors.  
    Iraq In October 2004, we signed a memorandum of understanding (MOU) with the Ministry of Oil of the
Government of Iraq to study and evaluate the shallow Qaiyarah oil field in Iraq. The fields
reservoirs contain a large proven accumulation of 17.1o API heavy oil at a depth of
about 1,000 feet. We will evaluate the potential response of the Qaiyarah oil field to the latest in EOR techniques,
along with the potential value that could be added using the Ensyn RTPTM Technology to
produce higher quality, more valuable crude oil. The work will include an assessment of the
oil-in-place in the reservoirs, and the optimum EOR/HTL methods to establish economically
recoverable volumes at the Qaiyarah oil field. If the evaluation studies indicate development of the field is economically viable, we will present
a development plan and offer a commercial proposal to implement an EOR program for the Qaiyarah oil
field. The Iraqi Ministry of Oil is under no obligation to execute the project or to enter into
formal commercial negotiations at the completion of our study.  
    Colombia In December 2004, we signed an MOU with Ecopetrol S.A. (Ecopetrol) for a study of the heavy
crudes from the large Castilla and Chichimene oil fields in Colombia. The two oil fields are about
75 miles southeast of Bogotá in the Central Llanos Basin. This region is an active oil producing
area and the Castilla and Chichimene fields have successfully been producing oil since the 1970s. In the initial phase, we will run tests on the two heavy crudes to determine the value that could
be added to these fields using the Ensyn RTPTM Technology. Ecopetrol S.A., formerly Empresa Colombiana de Petroleos, is a public company with 100% of its
shares currently owned by the Republic of Colombia. Ecopetrol is exclusively devoted to searching
for, producing, transporting, storing, refining and marketing hydrocarbons and is the fourth
largest national oil company in Latin America. Gross oil production in 2003, by Ecopetrol and its
associates, was 541,000 Bopd, and year-end reserves were over 1.5 billion barrels. 
 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 Syntroleum 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 costs 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 14




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oxidation are expensive and considered 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 Projects We have performed detailed project feasibility studies for the construction, operation and cost of
GTL plants in both Qatar and Egypt. 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. In the second quarter
of 2004, we wrote down our $0.3 million investment in the Oman GTL project as our opportunity to
build a 45,000-barrels per day GTL fuels plant in Oman failed to materialize due to a lack of
sufficient uncommitted gas volumes. We have conducted marketing and transportation feasibility studies for both European and Asia
Pacific regions in which we identified potential markets and estimated premiums for GTL diesel and
GTL naphtha. 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. In November 2004, we changed the name of GTLJ to ERDJ and
expanded the charter of the company to include participation of multi-national companies in EOR
projects, including those involving HTL oil upgrading. Should we be successful in obtaining the
rights to develop such projects, we intend to assign a certain percentage of our interest in the
project to ERDJ. We would then invite multi-national companies from the refining and distribution,
exploration and production, and trading and manufacturing industry sectors to invest in ERDJ. The
proceeds raised would be used to fund a portion of the total project capital costs, including
front-end engineering and design. In 2004, we initiated a feasibility study to convert coal to synthesis gas (CTL) as a feedstock
for the Syntroleum Fischer-Tropsch process. The objective of the study is to explore opportunities
for converting coal into clean burning CTL fuels in parts of the world where there is a relatively
cheap supply of sizeable coal deposits. China in particular, has large coal deposits and a rapidly
growing need for clean energy.  
    Egypt 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. The Egyptian governmental agencies are now making economic comparisons of
the three alternative methods for gas monetization that they have available to them: (1) pipeline
exports to Syria and Jordan, (2) liquefied natural gas exports to Europe and (3) GTL. This is an
ongoing analysis and we believe our GTL proposal remains a viable alternative for Egypt.
Discussions continue with Egyptian officials to promote the GTL alternative. Accordingly, we have
recently initiated a new detailed GTL fuels plant engineering feasibility and product price study
that takes full advantage of the latest advancements in the Syntroleum technology.  
    Bolivia In July 2003, we signed a participation agreement with Repsol-YPF Bolivia S.A. (Repsol) and
Syntroleum for a commercialization 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 was completed in 2004 and we
determined that under Bolivias current hydrocarbon tax regulations a 90,000-barrel-per-day GTL
plant could be commercially viable. However, due to the passing of a referendum to overhaul
Bolivias tax regulations in the third quarter of 2004 we elected to postpone any further work on
the commercialization study. The participation agreement with Repsol and Syntroleum expired at the
end of 2004 and we elected not to renew the participation agreement. We continue to pursue other
opportunities in Bolivia for monetization of the countrys vast natural gas deposits into GTL
fuels. 
 RISK FACTORS We are subject to a number of risks due to the nature of the industry in which we operate, our
reliance on strategies which include technologies that have not been proved on a commercial scale,
the present state of development of our business and the foreign jurisdictions in which we carry on
business. The following factors contain certain forward-looking statements involving risks and 15




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uncertainties. Our actual results may differ materially from the results anticipated in these
forward-looking statements. We cannot guarantee the successful commercialization of our exploration activities. 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 volumes. 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 GTL 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 we do 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. We are not able to guarantee the successful commercial development of Ensyns RTPTMTechnology. To date, no commercial-scale HTL plants have been constructed using the Ensyn RTPTMTechnology and, therefore, the process has not been proven to be financially viable on a
commercial scale. Other developers of competing HTL technologies may have significantly more
financial resources than we do and may be able to use this to obtain a competitive advantage. We may not be able to conclude HTL joint venture or production-sharing contracts using the RTP
TMTechnology. We have signed memoranda of understanding in Iraq and Colombia to study the economic feasibility of
an RTP Technology HTL oil processing facility for specified oil fields in those countries but we
can give no assurances as to when or if we will be able to conclude a joint venture or
production-sharing contract with the governments in those countries or any other countries where we
are now, or will be, seeking HTL project opportunities. Commercialization of our GTL or HTL projects may give rise to claims of infringement upon the
patents or proprietary rights of others. We own licenses to employ Syntroleums GTL and Ensyns RTPTM Technology processes but we
may not become aware of claims of infringement upon the patents or rights of others in these
respective technologies until after we have made a substantial investment in the development and
commercialization of projects utilizing these licensed technologies. Third parties may claim that
the technologies we license have infringed upon past, present or future patented technologies.
Legal actions could be brought against the licensor and us claiming damages and seeking an
injunction that would prevent us from testing or commercializing the affected technologies. If an
infringement action were successful, in addition to potential liability for damages, we and our
licensors could be required to obtain a claiming partys license in order to continue to test or
commercialize the affected technologies. Any required license might not be made available or, if
available, might not be available on acceptable terms, and we could be prevented entirely from
testing or commercializing the affected licensed technology. We may have to expend substantial
resources in litigation defending against the infringement claims of others. Many possible
claimants, such as the major energy companies that have or may be developing proprietary GTL or HTL
technologies competitive with the Syntroleum and RTPTM Technology processes that we
license, may have significantly more resources to spend on litigation. Ensyn has a history of operating losses and may continue to incur losses in the future. Since its inception, Ensyn has invested a significant amount of time and money in the research and
development of new products. Its development expense, including development of licensing fees, was
$0.9 million and $0.6 million for the years ended September 30, 16




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2004 and 2003, respectively. Its total operating expense, including development costs, was $1.8
million and $1.0 million for the years ended September 30, 2004 and 2003, respectively, compared to
total revenue of $0.3 million and $0.7 million, respectively, for such periods. Ensyn had net
losses of $1.2 million and $0.6 million for the years ended September 30, 2004 and 2003,
respectively. Ensyns accumulated deficit as of September 30, 2004 was $14.4 million. If we incur
losses in our application of the RTPTM Technology after completion of the Ensyn
acquisition, this may have an adverse impact on our operating results, which could cause the market
price of our shares to decline. Technological advances
could significantly decrease the cost of upgrading petroleum, and if we are unable to adopt or incorporate technological advances into our operations, the RTPTMTechnology could become uncompetitive or obsolete. We expect that technological advances in the processes and procedures for upgrading heavy oil and
bitumen into lighter, less viscous products will continue to occur. It is possible that those
advances could make the processes and procedures that are presently being utilized by Ensyn (and
which we intend to utilize after the acquisition) less efficient or cause the upgraded product
currently being produced by Ensyn to be of a lesser quality. These advances could also allow
competitors to produce upgraded products at a lower cost than that at which Ensyn is currently able
to produce such products. If we are unable to adopt or incorporate technological advances, our
production methods and processes could be less efficient than those of our competitors, which could
cause RTPTM Technology plants to become uncompetitive. In addition, alternative sources of energy are continually under development. Alternative energy
sources that can reduce reliance on oil and bitumen may be developed, which may decrease the demand
for RTPTM Technology upgraded product. It is also possible that technological advances
in engine design and performance could reduce the use of oil and bitumen, which would lower the
demand for such products. Conflict in the Middle East may hamper our GTL, EOR and HTL 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, EOR and HTL 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 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 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 17




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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 an MOU 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 MOU 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, EOR or HTL project, to 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. 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 18




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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 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 19




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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. As at the date of this annual report, our largest shareholder, Robert M. Friedland, owned
approximately 27% of our common shares. As a result, he 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
shares. 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 and E. Leon Daniel, 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 Our conventional oil and gas, EOR, HTL 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 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. 
 ENVIRONMENTAL PROVISIONS As at December 31, 2004, a $0.7 million provision has been made for future site restoration and
plugging and abandonment of wells in the U.S., which are currently estimated at $1.4 million. We do
not make such a provision for our oil and gas operations in China as the remaining life of our
Dagang production sharing contract is less than the remaining economic life of the field and there
is no obligation on our part to contribute to the future cost to abandon the field and restore the
site. During 2004, we recorded a further provision for future site restoration and plugging and
abandonment of wells of $0.2 million. 20




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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 As at December 31, 2004 we had 137 employees. None of our employees are unionized. Information on our executive officers is presented in Item 10 of this Annual Report on Form 10-K. 
 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 on Form 10-K for information
with respect to our oil and gas producing activities. We have not filed with nor included in
reports to any other U.S. federal authority or agency, any estimates of total proved crude oil or
natural gas reserves since the beginning of the last fiscal year. The following tables set forth, for each of the last three fiscal years, our average sales prices
and average operating costs per unit of production based on our net interest after royalties.
Average operating costs are for lifting costs only and exclude production taxes, allocated
engineering support costs, depletion and depreciation income taxes, interest, selling and
administrative expenses. Average Sales Price
    
    
    Average Operating Costs2004
    
    
    2003
    
    
    2002
    
    
    2004
    
    
    2003
    
    
    2002Crude Oil and Natural Gas ($/Boe)U.S
    
    $
    34.66
    
    
    $
    25.69
    
    
    $
    22.43
    
    
    $
    8.94
    
    
    $
    7.65
    
    
    $
    6.76China
    
    $
    36.11
    
    
    $
    28.41
    
    
    $
    22.30
    
    
    $
    6.04
    
    
    $
    9.31
    
    
    $
    6.49
 The following table sets forth the number of commercially productive wells (both producing
wells and wells capable of production) in which we held a working interest at the end of each of
the last three fiscal years: 2004
    
    
    2003
    
    
    2002Gross(1)
    
    
    Net(2)
    
    
    Gross(1)
    
    
    Net(2)
    
    
    Gross(1)
    
    
    Net(2)U.S.
    
    
    97
    (5)
    
    
    78.9
    (5)
    
    
    77
    
    
    
    60.4
    
    
    
    60
    (3)
    
    
    43.9
    (3)China
    
    
    21
    
    
    
    10.3
    (6)
    
    
    9
    
    
    
    7.4
    
    
    
    9
    (4)
    
    
    7.4
    (4)
   (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.(5)
    
    After the sale of 0.8 net (2 gross) Sledge Hamar wells in December 2004 and the purchase of
8.2 net (9 gross) Knights Landing wells partially in April of 2004 and the remainder
(including an increase in the working interest of the existing wells) in December of 2004.(6)
    
    After giving effect to the 40% farm-in of CITIC to Dagang field. The following two tables set forth, for each of the last three fiscal years, our participation
in the completed drilling of net oil and gas wells: Exploratory Productive2004
    
    
    2003
    
    
    2002U.S.
    
    
    3.4
    
    
    
    
    
    
    
    China
    
    
    
    
    
    
    
    
    
    
    Total
    
    
    3.4
    
    
    
    0
    
    
    
    0
 Dry2004
    
    
    2003
    
    
    2002U.S.
    
    
    5.4
    
    
    
    
    
    
    
    1.7
    (1)China
    
    
    
    
    
    
    
    
    
    
    Total
    
    
    5.4
    
    
    
    0
    
    
    
    1.7
   (1)
    
    Includes 1.5 (3 gross) net exploratory wells drilled in Kentucky during 2001, which were
determined to be dry in 2002. 21




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Development Productive2004
    
    
    2003
    
    
    2002U.S.
    
    
    7.3
    (1)
    
    
    17.0
    
    
    
    8.8China
    
    
    7.9
    
    
    
    
    
    
    
    Total
    
    
    15.2
    
    
    
    17.0
    
    
    
    8.8
 Dry2004
    
    
    2003
    
    
    2002U.S.
    
    
    2.0
    
    
    
    2.0
    
    
    
    China
    
    
    
    
    
    
    
    
    
    
    Total
    
    
    2.0
    
    
    
    2.0
    
    
    
    0
   (1)
    
    Includes 0.3 (1 gross) net producing wells acquired as a result of the farm-in to LAK
Ranch. Wells in Progress At the end of 2004, 2003 and 2002 we had 2.9 (6 gross), 2.8 (5 gross) and 2.3 (5 gross) net wells,
respectively, which were either in the process of drilling or suspended. The following table sets forth our holdings of developed and undeveloped oil and gas acreage as at
December 31, 2004: Developed
    
    
    UndevelopedGross
    
    
    Net
    
    
    Gross
    
    
    NetAcres(1)
    
    
    Acres(2)
    
    
    Acres(1)
    
    
    Acres(2)U.S.
    
    
    16,224
    
    
    
    8,649
    
    
    
    100,315
    
    
    
    38,288China (3)
    
    
    2,289
    
    
    
    1,126
    
    
    
    899,760
    
    
    
    889,567
   (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 properties relates only to
those portions of the field covered by our producing operations and does not include the
remaining portions of the field previously developed by CNPC. The 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, 2004. 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 ofBefore Tax Cash Flows
    
    
    After Tax Cash FlowsOur Share
    
    
    In Thousands of U.S. Dollars
    
    
    In Thousands of U.S. DollarsOil
    
    
    Gas
    
    
    Discounted at:
    
    
    Discounted at:(Mbbl)
    
    
    (MMcf)
    
    
    0%
    
    
    10%
    
    
    15%
    
    
    0%
    
    
    10%
    
    
    15%Net Proved Reserves(1)U.S.
    
    
    1,430
    
    
    
    2,683
    
    
    $
    33,427
    
    
    $
    22,189
    
    
    $
    19,375
    
    
    $
    33,427
    
    
    $
    22,189
    
    
    $
    19,375China
    
    
    7,908
    
    
    
    
    
    
    
    184,311
    
    
    
    114,637
    
    
    
    93,534
    
    
    
    139,603
    
    
    
    88,829
    
    
    
    73,2549,338
    
    
    
    2,683
    
    
    $
    217,738
    
    
    $
    136,826
    
    
    $
    112,909
    
    
    $
    173,030
    
    
    $
    111,018
    
    
    $
    92,629
   (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 on Form 10-K. Special Note to Canadian Investors Ivanhoe is a United States Securities and Exchange Commission (SEC) registrant and files annual
reports on Form 10-K. Accordingly, our reserves estimates and securities regulatory disclosures are
prepared based on 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 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 22




---



##### 



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 forecasted prices;
    the SEC mandates disclosure of proved and proved producing reserves by country only
whereas NI 51-101 requires disclosure of more reserve categories and product types;
    the SEC does not require separate disclosure of proved undeveloped reserves or related
future development costs whereas NI 51-101 requires disclosure of more information
regarding proved undeveloped reserves, related development plans and future development
costs; and
    the SEC leaves the engagement of independent qualified reserves evaluators to the
discretion of a companys board of directors whereas NI 51-101 requires issuers to engage
such evaluators and to file their reports. The foregoing is a general and non-exhaustive description of the principal differences between 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 2004. 
 PART II 
 ITEM 5. MARKET FOR REGISTRANTS COMMON EQUITY AND RELATED STOCKHOLDER MATTERS Market Information Our common shares trade 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 Toronto Stock Exchange for each
quarter during the past two years are as follows: NASDAQ MARKET (IVAN)
(U.S.$) 2004
    
    
    20034th Qtr
    
    
    3rd Qtr
    
    
    2nd Qtr
    
    
    1st Qtr
    
    
    4th Qtr
    
    
    3rd Qtr
    
    
    2nd Qtr
    
    
    1st QtrHigh
    
    
    3.20
    
    
    
    2.33
    
    
    
    3.06
    
    
    
    4.28
    
    
    
    7.55
    
    
    
    3.07
    
    
    
    1.18
    
    
    
    .60Low
    
    
    2.03
    
    
    
    1.22
    
    
    
    2.08
    
    
    
    1.96
    
    
    
    2.52
    
    
    
    .79
    
    
    
    .42
    
    
    
    .50
 TORONTO STOCK EXCHANGE (IE)
(CDN$) 2004
    
    
    20034th Qtr
    
    
    3rd Qtr
    
    
    2nd Qtr
    
    
    1st Qtr
    
    
    4th Qtr
    
    
    3rd Qtr
    
    
    2nd Qtr
    
    
    1st QtrHigh
    
    
    3.90
    
    
    
    3.00
    
    
    
    4.15
    
    
    
    5.49
    
    
    
    10.40
    
    
    
    4.15
    
    
    
    1.60
    
    
    
    .88Low
    
    
    2.56
    
    
    
    1.62
    
    
    
    2.88
    
    
    
    2.63
    
    
    
    3.30
    
    
    
    1.10
    
    
    
    .53
    
    
    
    .77
 On December 31, 2004, the closing prices for our common shares were $2.52 on the NASDAQ
SmallCap Market and Cdn. $3.04 on the Toronto Stock Exchange. 23




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##### 



Exemptions from Certain NASDAQ Marketplace Rules NASDAQ may provide exemptions from certain of its Marketplace Rules to foreign issuers when those
rules 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 received from NASDAQ an exemption from NASDAQs requirement that a majority of our Board of
Directors be comprised of independent directors. 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. We have also received from NASDAQ an exemption from NASDAQs requirement that our shareholders
approve the issuance of more than 20% of our total outstanding common shares in connection with our
proposed acquisition of Ensyn and any related private placement transactions, provided that we
comply with the rules and policies of the Toronto Stock Exchange. The rules and policies of the
Toronto Stock Exchange require us to obtain shareholder approval for the issuance of common shares
in connection with the Ensyn transaction and any related private placements if the aggregate number
of common shares to be issued exceeds 25% of the common shares outstanding immediately prior to the
transaction. Holders of Common Shares As at December 31, 2004, a total of 169,664,911 of our common shares were issued and outstanding
and held by 180 holders of record with an estimated 45,500 additional shareholders whose shares
were held for them in street name or nominee accounts. Dividends We have not paid any dividends on our outstanding common shares since we were incorporated and we
do not anticipate that we will do so in the foreseeable future. The declaration of dividends on our
common shares is, subject to certain statutory restrictions described below, within the discretion
of our Board of Directors based on their assessment of, among other factors, our earnings or lack
thereof, our capital and operating expenditure requirements and our overall financial condition.
Under the Yukon Business Corporations Act, our Board of Directors has no discretion to declare or
pay a dividend on our common shares if they have reasonable grounds for believing that we are, or
after payment of the dividend would be, unable to pay our liabilities as they become due or that
the realizable value of our assets would, as a result of the dividend, be less than the aggregate
sum of our liabilities and the stated capital of our common shares. Exchange Controls and Taxation There is no law or governmental decree or regulation in Canada that restricts the export or import
of capital, or affects the remittance of dividends, interest or other payments to a non-resident
holder of our common shares, other than withholding tax requirements. There is no limitation imposed by the laws of Canada, the laws of the Yukon, 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 2005
is Cdn.$250 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. 24




---



##### 



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, 2004, we issued securities, which were not registered under the
Securities Act of 1933 (the Act), as follows:  
    in February 2004, we issued 5,448,276 special warrants at a price of $2.90 per special
warrant to two institutional investors 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 March 2004. Two common share purchase warrants are exercisable to purchase an
additional common share at $3.00 at any time on or prior to the first anniversary date
following the special warrant date of issue and at $3.20 thereafter until the second
anniversary date of the special warrant date of issue; and
    in March 2004, we issued 1,724,138 special warrants at a price of $2.90 per special
warrant to an 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 March 2004. Two common share purchase warrants are exercisable to purchase an
additional common share at $3.00 at any time on or prior to the first anniversary date
following the special warrant date of issue and at $3.20 thereafter until the second
anniversary date of the special warrant date of issue. 
 ITEM 6. FIVE YEAR SUMMARY OF SELECTED FINANCIAL DATA The selected financial data set forth below are derived from the accompanying financial statements,
which form part of this Annual Report on Form 10-K. The financial statements have been prepared in
accordance with generally accepted accounting principles (GAAP) applicable in Canada, which are
not materially different from GAAP in the U.S. except as noted immediately below in Reconciliation
to U.S. GAAP. See also Item 7 Managements Discussion and Analysis of Financial Condition and
Results of Operations. The following table shows selected financial information for the years indicated: December 31,(stated in thousands of U.S. dollars, except per share amounts)2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000Financial PositionTotal assets
    
    
    118,486
    
    
    
    106,574
    
    
    
    107,088
    
    
    
    104,003
    
    
    
    99,800Long-term debt
    
    
    2,639
    
    
    
    833
    
    
    Nil
    
    Nil
    
    NilShareholders equity
    
    
    103,586
    
    
    
    100,537
    
    
    
    100,548
    
    
    
    96,897
    
    
    
    95,838Common shares outstanding (in thousands)
    
    
    169,665
    
    
    
    161,359
    
    
    
    144,466
    
    
    
    139,267
    
    
    
    126,874Capital investments
    
    
    46,454
    
    
    
    15,391
    
    
    
    18,828
    
    
    
    40,504
    
    
    
    40,827Results of OperationsRevenues
    
    
    17,997
    
    
    
    9,659
    
    
    
    8,437
    
    
    
    9,722
    
    
    
    14,063
    (1)Net income (loss)
    
    
    (20,725
    )(2)
    
    
    (30,179
    )(2)(3)
    
    
    (7,130
    )(2)(3)
    
    
    (21,122
    )(2)
    
    
    5,429Net income (loss) per share   basic
    
    
    (0.12
    )
    
    
    (0.20
    )
    
    
    (0.05
    )
    
    
    (0.16
    )
    
    
    0.05Net income (loss) per share   diluted
    
    
    (0.12
    )
    
    
    (0.20
    )
    
    
    (0.05
    )
    
    
    (0.16
    )
    
    
    0.04
   (1)
    
    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 on Form 10-K.(2)
    
    Includes asset write-downs and provisions for impairment of $16.6 million, $23.3 million,
$2.4 million and $14.0 million for 2004, 2003, 2002 and 2001, respectively. See Notes 4 and 13
to our financial statements under Item 8 in this Annual Report on Form 10-K.(3)
    
    Restated by $0.5 million and $0.3 million in 2003 and 2002, respectively, for a change in
accounting policy to recognize compensation costs using the fair value based method of
accounting for stock options granted to employees and directors after January 1, 2002. See
Notes 2 and 9 to our financial statements under Item 8 of this Annual Report on Form 10-K. 25




---



##### 



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 are as follows:  
    adjustment for the reduction in stated capital in 1999,
    increase in the ascribed value of shares issued for the acquisition of U.S. royalty interests in 1999 and 2000,
    additional impairment provision for our China oil and gas properties in 2001, net of depletion expense,
    reduction in impairment provision for our U.S. oil and gas properties in 2004, net of depletion expense,
    net additional expense from 2001 to 2004 in connection with development costs for our GTL and EOR projects, and
    reduction in the net losses from 2002 to 2004 for stock based compensation accounted
for under the intrinsic value method for U.S. GAAP. For the U.S. GAAP reconciliations, see Note 19 to our financial statements in this Annual
Report on Form 10-K. Had we followed U.S. GAAP, certain selected financial information reported above, in accordance
with Canadian GAAP, would have been reported as follows: Year ended December 31,(stated in thousands of U.S. dollars, except per share amounts)2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000Financial PositionTotal assets
    
    
    105,791
    
    
    
    94,024
    
    
    
    91,921
    
    
    
    90,219
    
    
    
    101,158Shareholders equity
    
    
    90,892
    
    
    
    87,987
    
    
    
    85,279
    
    
    
    83,113
    
    
    
    97,196Results of OperationsNet income (loss)
    
    
    (19,696
    )
    
    
    (27,086
    )
    
    
    (8,202
    )
    
    
    (36,264
    )
    
    
    5,429Net income (loss) per share   basic
    
    
    (0.12
    )
    
    
    (0.18
    )
    
    
    (0.06
    )
    
    
    (0.28
    )
    
    
    0.05Net income (loss) per share  diluted
    
    
    (0.12
    )
    
    
    (0.18
    )
    
    
    (0.06
    )
    
    
    (0.28
    )
    
    
    0.05
 
 ITEM 7. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS TABLE OF CONTENTSPageExecutive Overview of 2004 Results
    
    
    27Financial Results  Year to Year Change in Net Loss
    
    
    27Net Operating Revenues
    
    
    28General and Administrative
    
    
    30Depletion and Depreciation
    
    
    31Write-Down of GTL Investments
    
    
    32Impairment of U.S. Oil and Gas Properties
    
    
    32Capital Investments  2004
    
    
    33Oil and Gas Activities  U.S.
    
    
    33Oil and Gas Activities  China
    
    
    34EOR Activities
    
    
    34GTL Activities
    
    
    34Liquidity and Capital Resources
    
    
    34Contractual Obligations and Commitments
    
    
    35Critical Accounting Principles and Estimates
    
    
    36Impact of New and Pending Canadian GAAP Accounting Standards
    
    
    38Impact of New and Pending U.S. GAAP Accounting Standards
    
    
    39Off Balance Sheet Arrangements
    
    
    40Related Party Transactions
    
    
    40
 THE FOLLOWING SHOULD BE READ IN CONJUNCTION WITH THE CONSOLIDATED FINANCIAL STATEMENTS INCLUDED
IN THIS ANNUAL REPORT ON FORM 10-K. THE CONSOLIDATED FINANCIAL STATEMENTS HAVE BEEN PREPARED IN
ACCORDANCE WITH GAAP IN CANADA. THE IMPACT OF SIGNIFICANT DIFFERENCES BETWEEN CANADIAN AND U.S.
GAAP ON THE FINANCIAL STATEMENTS IS DISCLOSED IN NOTE 19 TO THE CONSOLIDATED FINANCIAL STATEMENTS. OUR DISCUSSION AND ANALYSIS OF OUR OIL AND GAS ACTIVITIES WITH RESPECT TO OIL AND GAS VOLUMES,
RESERVES AND RELATED PERFORMANCE MEASURES IS PRESENTED ON OUR WORKING INTEREST BASIS AFTER
ROYALTIES. NOTE: CANADIAN INVESTORS SHOULD READ THE SPECIAL NOTE TO CANADIAN INVESTORS ON PAGE 22 WHICH
HIGHLIGHTS DIFFERENCES 26




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##### 



BETWEEN OUR RESERVE ESTIMATES AND RELATED DISCLOSURES THAT ARE OTHERWISE
REQUIRED BY CANADIAN REGULATORY AUTHORITIES. Executive Overview of 2004 Results Although our 2004 results improved over those achieved a year ago, we were not profitable in 2004.
Revenue for 2004 increased by 86% to $18.0 million on the strength of an increase in production as
well as higher oil and gas prices. However, this improvement was offset by increased costs related
to our significant business development activities, a $16.3 million impairment of a number of our
unproved and proved U.S. oil and gas properties and professional fees related to our assessment of
the effectiveness of the design and operation of our internal control over financial reporting
pursuant to Section 404 of the Sarbanes-Oxley Act of 2002. Despite cost increases, we achieved
positive cash flow from operations of $4.0 million for the year ended December 31, 2004 compared to
deficits of $1.5 million and $2.1 million for the comparable periods in 2003 and 2002,
respectively. Our single goal continues to be to build our oil and gas reserve base and production. Our strategy
is to do this through the application of technologically innovative methods for oil and gas
recovery. Our most significant activity in this regard, during 2004, is related to our December
2004 agreement to acquire Ensyn and its proprietary RTP Technology. We believe that the
deployment of this RTP Technology can launch us into the forefront of heavy oil production
around the world. The following table sets forth certain selected consolidated data for the past three years: Year ended December
31,(stated in thousands of U.S. dollars, except share amounts)2004
    
    
    2003
    
    
    2002Net loss
    
    
    20,725
    
    
    
    30,179
    
    
    
    7,130Net loss per share
    
    
    0.12
    
    
    
    0.20
    
    
    
    0.05Average annual production (Mboe/d)
    
    
    1,376
    
    
    
    979
    
    
    
    1,020Capital investments
    
    
    46,454
    
    
    
    15,391
    
    
    
    18,828Cash flow (deficit) from operating activities
    
    
    4,032
    
    
    
    (1,522
    )
    
    
    (2,120
    )
 Financial Results - Year to Year Change in Net Loss The following provides an analysis of our changes in net losses for the year ended December 31,
2004 when compared to the same period for 2003 and for the year ended December 31, 2003 when
compared to the same period for 2002: 2004 vs.
    
    
    2003 vs2003
    
    
    2002(stated in thousands of U.S. Dollars)Net Losses for 2003 and 2002, as restated
    
    $
    30,179
    
    
    $
    7,130Favorable (unfavorable) variances:Cash Items:Net Operating Revenues:Production volumes
    
    
    4,534
    
    
    
    (416
    )Oil and gas prices
    
    
    3,442
    
    
    
    1,899Hedge loss
    
    
    250
    
    
    
    (243
    )Less: Operating costs
    
    
    (780
    )
    
    
    (452
    )7,446
    
    
    
    788General and administrative
    
    
    (177
    )
    
    
    (2,091
    )Net interest
    
    
    (36
    )
    
    
    (179
    )Total Cash Variances
    
    
    7,233
    
    
    
    (1,482
    )Non-Cash Items:Depletion and depreciation
    
    
    (3,653
    )
    
    
    (517
    )Stock based compensation
    
    
    (800
    )
    
    
    (165
    )Write downs of GTL investments
    
    
    3,071
    
    
    
    (885
    )Impairment of U.S. oil and gas properties
    
    
    3,650
    
    
    
    (20,000
    )Other
    
    
    (47
    )
    
    
    Total Non-Cash Variances
    
    
    2,221
    
    
    
    (21,567
    )Net Losses for 2004 and 2003
    
    $
    20,725
    
    
    $
    30,179
 Our net loss for 2004 was $20.7 million ($0.12 per share) compared to our net loss in 2003 of
$30.2 million ($0.20 per share) after 27




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##### 



restatement of 2003 for a retroactive change in accounting
policy for stock based compensation (See Notes 2 and 9). The decrease in our net loss from 2003 to
2004 of $9.5 million is due mainly to a $3.7 million reduction in impairment of our U.S. oil and
gas properties, $3.1 million decrease in write-downs of our GTL investments and a $7.4 million
increase in net operating revenues. This is partially offset by a $3.7 million increase in
depletion and depreciation expense and a $1.0 million increase in general administrative expenses
including stock based compensation. The $23.0 million increase in our restated net losses from 2002 to 2003 is due mainly to a $20.0
million impairment of our U.S. oil and gas properties, a $0.9 million increase in write-downs of
our GTL investments, a $0.5 million increase in depletion and depreciation expense and a $2.3
million increase in general and administrative costs including stock based compensation. This is
partially offset by an increase in net operating revenues of $0.8 million, including a $0.2 million
hedge loss for 2003. Significant variances in our net losses are explained in the sections that follow. Net Operating Revenues  
    Production Volumes 2004 vs. 2003 Net production volumes in 2004 increased 41% from 2003 due to 63% and 26% increases in production
volumes in our China and U.S. properties, respectively, resulting in increased revenues of $4.5
million. Net production volumes at the Dagang field increased 46% in 2004 despite the farm-out of 40% of our
interest to Richfirst in June 2004. We commenced development of the Dagang field in late 2003 and
by the end of 2004 we drilled 19 wells of which 16 were completed and placed on production. The
year-end 2004 gross production rate was 1,655 Bopd (774 net Bopd) compared to 505 Bopd at the end
of 2003 (236 net Bopd adjusting for a 40% Richfirst farm-in for comparability to 2004). At year-end
2004, a total of 22 wells were producing at our Dagang field. Additionally, we continue to benefit
from the expanded Daqing development program and the royalty interest we retained after the sale of
our working interest in this field in 2002 as our royalty share of production increased 224% from
2003. Net production volumes in the U.S. increased 26% mainly from the Citrus and Knights Landing fields,
both of which started production in 2004, and our continuing development program at South Midway.
We farmed into the Knights Landing gas field in northern California in February 2004 with a 50%
working interest in 4 producing natural gas wells and in December 2004 improved the potential of
our California properties by increasing our working interest to between 80% and 100% in 12 Knights
Landing natural gas wells capable of production and selling our interest in the Sledge Hamar field.
We are the operator of the Citrus field and currently have a 100% working interest before payout in
three Citrus wells, which were completed and placed on production in 2004. We continue to see
increased production rates from our successful drilling and steaming operations at our South Midway
field where we have drilled 19 producing wells over the last two years. At year end 2004, we were
producing from 95 wells in the South Midway, Spraberry, Citrus, and Knights Landing fields at gross
rates of production of approximately 1,320 Boe/d (920 net Boe/d). The following is a comparison of changes in production volumes for the year ended December 31, 2004
when compared to the same period in 2003: Average Net Boe's
    
    
    Percentage2004
    
    
    2003
    
    
    ChangeChina:Dagang
    
    
    190,309
    
    
    
    130,651
    
    
    
    46
    %Daqing
    
    
    44,626
    
    
    
    13,771
    
    
    
    224
    %234,935
    
    
    
    144,422
    
    
    
    63
    %U.S.:South Midway
    
    
    183,875
    
    
    
    169,858
    
    
    
    8
    %Citrus
    
    
    31,008
    
    
    
    
    
    
    
    100
    %Knights Landing
    
    
    14,786
    
    
    
    
    
    
    
    100
    %Others
    
    
    38,945
    
    
    
    42,962
    
    
    
    -9
    %268,614
    
    
    
    212,820
    
    
    
    26
    %503,549
    
    
    
    357,242
    
    
    
    41
    %
  
    Production Volumes 2003 vs. 2002 Net production volumes in 2003 declined 4% from 2002 due mainly to the sale of our interests in
certain wells in the Spraberry field in the last half of 2002 and in Dagang due to a combination of
factors which occurred during 2003 including well workovers, natural 28




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##### 



declines and the suspension of
one pilot phase well pending conversion to water injection service. Production from South Midway
increased 24% in 2003 primarily due to drilling 15 new wells in the southern expansion in 2003 and
initiation of full-scale cyclic steam enhancement program in May 2002 in the primary area of South
Midway and cyclic steaming of the southern expansion wells in the fourth quarter of 2003. At year-end 2003, we were producing from seven pilot phase wells in the Dagang field at gross rates
of 505 Bopd (236 net Bopd adjusting for a 40% Richfirst farm-in for comparability to 2004) compared
to 599 Bopd at the end of 2002 (280 net Bopd adjusting for a 40% Richfirst farm-in for
comparability to 2004) and 76 wells from the South Midway and Spraberry fields at gross rates of
production of approximately 911 Boe/d (611 net Boe/d). The following is a comparison of changes in production volumes for the year ended December 31, 2003
when compared to the same period in 2002: Average Net Boe's
    
    
    Percentage2003
    
    
    2002
    
    
    ChangeChina:Dagang
    
    
    130,651
    
    
    
    141,257
    
    
    
    -8
    %Daqing
    
    
    13,771
    
    
    
    3,591
    
    
    
    283
    %144,422
    
    
    
    144,848
    
    
    
    0
    %U.S.:South Midway
    
    
    169,858
    
    
    
    136,705
    
    
    
    24
    %Spraberry
    
    
    40,695
    
    
    
    88,598
    
    
    
    -54
    %Others
    
    
    2,266
    
    
    
    1,998
    
    
    
    13
    %212,820
    
    
    
    227,301
    
    
    
    -6
    %357,242
    
    
    
    372,149
    
    
    
    -4
    %
  
    Oil and Gas Prices 2004 vs. 2003 Oil and gas prices increased 32% per Boe in 2004 generating $3.4 million in additional revenue as
compared to 2003. We realized an average of $36.11/Boe from our operations in China during 2004,
which is an increase of $7.70/Boe from 2003 prices and accounts for $1.7 million of our increase in
revenues. From the U.S. operations, we realized an average of $34.66/Boe during 2004, which is an
increase of $8.97/Boe and accounts for $1.7 million of our increased revenues. We entered into costless collar derivatives to hedge our cash flow from the sale of 500 barrels of
oil production per day over two six-month periods starting October 2002 and June 2003. We realized
losses of $0.3 million on these derivative transactions in 2003 but had no derivative contracts in
place during 2004.  
    Oil and Gas Prices 2003 vs. 2002 Oil and gas prices increased 20% per Boe in 2003 generating $1.9 million in additional revenue as
compared to 2002. We realized an average of $28.41/Boe from our operations in China during 2003,
which is an increase of $6.11/Boe from 2002 prices and accounts for $0.9 million of our increase in
revenues. From the U.S. operations, we realized an average of $25.69/Boe during 2003, which is an
increase of $3.26/Boe and accounts for $1.0 million of our increased revenues. As discussed above, we realized losses of $0.3 million on derivative transactions in 2003 compared
to the insignificant losses realized on such transactions during 2002.  
    Operating Costs 2004 vs. 2003 Operating costs for 2004 increased $0.8 million in absolute terms from 2003 but decreased $1.96 on
a per barrel of oil equivalent basis. Operating costs in China, including engineering support, decreased 41% or $5.57 per Boe for 2004
due mainly to an increase in production from the Dagang field in relation to the level of fixed
field operating costs and engineering support required to operate the field and reduced well
workover and power costs during 2004. Operating costs in the U.S., including engineering support and production taxes, increased 8% or

$0.89 per Boe for 2004. Field operating costs increased $1.29/Boe due mainly to an increase in fuel
costs incurred for the cyclic steam operations in the southern expansion of South Midway, increased
costs to treat hydrogen sulfide levels in the gas produced from the South Midway field and the 29




---



##### 



start up of production operations at our Citrus, Knights Landing, and Sledge Hamar fields. This is
partially offset by a reduction in workover costs at our South Midway and Spraberry fields from
2003. Engineering support increased $0.19/Boe due mainly to the start up of production operations
at Citrus, where we are the operator, and also at Knights Landing where we became the operator in
December 2004. Production taxes are down $0.59/Boe due mainly to a retroactive reassessment of
property values at South Midway, which led to a refund of prior ad valorem taxes paid and a
reduction in current assessed values.  
    Operating Costs 2003 vs. 2002 Operating costs for 2003 increased $0.5 million in absolute terms from 2002 and $1.70 on a per
barrel of oil equivalent basis. Operating costs in China, including engineering support, increased 33% or $3.42 per Boe in 2003
mainly due to increased well workover and manpower costs in preparation for the full field
development which started in the fourth quarter of 2003. Operating costs in the U.S., including engineering support and production taxes, increased 5% or
$0.52 per Boe in 2003 due mainly to an increase in fuel costs incurred for the cyclic steam
operations in the southern expansion of South Midway partially offset by a reduction in field
operating costs at the Spraberry field as the wells mature. Production and operating information including oil and gas revenue, operating costs and depletion,
on a per Boe basis, from 2002 to 2004 are detailed below: Year ended December 31,2004
    
    
    2003
    
    
    2002U.S.
    
    
    China
    
    
    Total
    
    
    U.S.
    
    
    China
    
    
    Total
    
    
    U.S.
    
    
    China
    
    
    TotalNet Production:Boe
    
    
    268,614
    
    
    
    234,935
    
    
    
    503,549
    
    
    
    212,820
    
    
    
    144,422
    
    
    
    357,242
    
    
    
    227,301
    
    
    
    144,848
    
    
    
    372,149Boe/day for the year
    
    
    734
    
    
    
    642
    
    
    
    1,376
    
    
    
    583
    
    
    
    396
    
    
    
    979
    
    
    
    623
    
    
    
    397
    
    
    
    1,020
 Per Boe
    
    
    Per Boe
    
    
    Per BoeOil and gas revenue
    
    $
    34.66
    
    
    $
    36.11
    
    
    $
    35.34
    
    
    $
    25.69
    
    
    $
    28.41
    
    
    $
    26.79
    
    
    $
    22.43
    
    
    $
    22.30
    
    
    $
    22.38Operating costs
    
    
    8.94
    
    
    
    6.04
    
    
    
    7.59
    
    
    
    7.65
    
    
    
    9.31
    
    
    
    8.52
    
    
    
    6.76
    
    
    
    6.49
    
    
    
    6.66Production taxes
    
    
    0.44
    
    
    
    
    
    
    
    0.23
    
    
    
    1.03
    
    
    
    
    
    
    
    0.62
    
    
    
    1.21
    
    
    
    
    
    
    
    0.74Engineering support
    
    
    2.38
    
    
    
    2.10
    
    
    
    2.25
    
    
    
    2.19
    
    
    
    4.40
    
    
    
    2.89
    
    
    
    2.38
    
    
    
    3.80
    
    
    
    2.9311.76
    
    
    
    8.14
    
    
    
    10.07
    
    
    
    10.87
    
    
    
    13.71
    
    
    
    12.03
    
    
    
    10.35
    
    
    
    10.29
    
    
    
    10.33Net operating revenue
    
    
    22.90
    
    
    
    27.97
    
    
    
    25.27
    
    
    
    14.82
    
    
    
    14.70
    
    
    
    14.76
    
    
    
    12.08
    
    
    
    12.01
    
    
    
    12.05Depletion
    
    
    16.80
    
    
    
    12.18
    
    
    
    14.64
    
    
    
    10.58
    
    
    
    10.23
    
    
    
    10.44
    
    
    
    8.39
    
    
    
    8.30
    
    
    
    8.35$
    6.10
    
    
    $
    15.79
    
    
    $
    10.63
    
    
    $
    4.24
    
    
    $
    4.47
    
    
    $
    4.32
    
    
    $
    3.69
    
    
    $
    3.71
    
    
    $
    3.70
 General and Administration Our changes in general and administrative expenses for the year ended December 31, 2004 when
compared to the same period for 2003 and for the year ended December 31, 2003 when compared to the
same period for 2002 were as follows: 2004 vs.
    
    
    2003 vs2003
    
    
    2002Favorable (unfavorable) variances:General and administrative
    
    $
    (177
    )
    
    $
    (2,091
    )Stock based compensation
    
    
    (800
    )
    
    
    (165
    )$
    (977
    )
    
    $
    (2,256
    )
 As discussed below in this Item 7 in Critical Accounting Principles and Estimates 
Write-down of Non-Oil and Gas Properties, we incur various costs in the pursuit of GTL and EOR
projects. Such costs incurred prior to signing an MOU, or similar agreement, are considered to be
business development or project identification, are expensed as incurred and are reflected in the
following table as GTL or EOR general and administrative expenses. Additionally, we capitalize a
portion of our general and administrative costs that can be directly related to, and is necessary
to, our capital investment activities. For the years ended December 31, 2004, 2003 and 2002,
general and administrative expenses related directly to oil and gas acquisition, exploration and
development activities, and investments in GTL and EOR projects of $3.8 million, $1.8 million and
$2.6 million, respectively, were capitalized and thus are not included in the following table of
changes in general administrative expenses (including stock based compensation) by segment: 30




---



##### 



2004 vs.
    
    
    2003 vs2003
    
    
    2002Favorable (unfavorable) variances:Oil and Gas Activities:U.S.
    
    $
    1,119
    
    

    $
    (931
    )China
    
    
    216
    
    
    
    (271
    )GTL
    
    
    (140
    )
    
    
    (656
    )EOR
    
    
    (442
    )
    
    
    Corporate
    
    
    (1,730
    )
    
    
    (398
    )$
    (977
    )
    
    $
    (2,256
    )
  
    General and Administrative 2004 vs. 2003 General and administrative expenses related to U.S. operations, before allocations to capital and
operating costs, increased $0.8 million for 2004 primarily due to increased labor costs, including
non-cash stock based compensation. This is offset by increased allocations of general and
administrative to capital investments and operating costs of $1.5 million and $0.4 million,
respectively, as a result of increased levels of exploration and development activities in the U.S
during 2004 and the start up of production operations at Citrus, where we are the operator, and
also at Knights Landing where we became the operator in December 2004. General and administrative expenses related to the China operations, before allocations of costs to
capital and operating costs, increased $0.4 million primarily due to increased labor costs and ramp
up of administrative offices required to support the development and exploration activities
initiated at the end of 2003. This is offset by increased allocations of general and
administrative costs to capital investments and operating costs of $0.5 million and $0.1 million,
respectively, primarily as a result of the development program and increased operations at our
Dagang field. We incurred a higher level of business development costs during 2004 related to identification of
new opportunities for our GTL and HTL technologies particularly in the Middle East and China
resulting in increased general and administrative costs of $0.6 million. Corporate general and administrative expenses increased $1.7 million mainly due to $0.8 million
incurred during 2004 to comply with the provisions of Section 404 of the Sarbanes-Oxley Act of
2002, a $0.8 million increase in non-cash stock based compensation related to the issuance of stock
options and other net increases such as higher costs for directors and officers liability
insurance.  
    General and Administrative 2003 vs. 2002 General and administrative costs, including stock based compensation costs, increased $2.3 million
in 2003 from 2002. General and administrative expenses related to U.S. operations increased $0.9 million compared to
2002. General and administrative expenses before allocations of costs to capital investments and
operating costs increased $0.3 million for 2003 primarily due to increased labor costs including
non-cash stock based compensation. Additionally, allocations of general and administrative costs to
capital investments decreased $0.6 million as a result of decreased levels of exploration and
development activities in the U.S during 2003. General and administrative expenses related to the China operations, before allocations of costs to
capital investments and operating costs, increased $0.3 million primarily due to costs incurred to
explore the possibility of a public listing for Sunwing. We incurred a higher level of business development costs for our GTL initiatives during 2003
primarily related to pursuing new sources of project financing resulting in increased general and
administrative costs of $0.7 million. Corporate general and administrative expenses increased $0.4 million during 2003 mainly due to fees
incurred for the filing of a $100 million Canadian base shelf prospectus and corresponding U.S.
shelf registration statement and increase in insurance costs. Depletion and Depreciation The primary expense in this classification is depletion of the carrying values of our oil and gas
properties in our U.S. and China cost centers over the life of their proved oil and gas reserves as
determined by independent reserve evaluators. For more information on how we calculate depletion
and determine our proved reserves see Critical Accounting Principles and Estimates  Oil and Gas
Reserves and Depletion in this Item 7.  
    Depletion and Depreciation 2004 vs. 2003 31




---



##### 



Depletion and depreciation increased $3.7 million in 2004, which was due to the increase in
depletion rates to $14.64 per Boe in 2004 compared to $10.44 per Boe in 2003. The U.S. depletion rate for 2004 was $16.80 per Boe, a 59% increase from 2003. Despite a $16.3
million impairment of our U.S. oil and gas properties in 2004, our depletion rate increased in 2004
primarily as a result of significant costs of finding and acquiring proved reserves at our Knights
Landing and Citrus fields as measured as at December 31, 2004. We believe we can continue to
develop these fields over the coming year in order to economically increase our reserve base and
improve our operating results. The China depletion rate for 2004 was $12.18 per Boe, a 19% increase from 2003, due mainly to a
downward revision of our share of proved reserves at Dagang as a result of continued increases in
oil prices from 2003 and additional anticipated increases in future development costs. During
periods of increasing oil prices our share of proved oil reserves decreases, as fewer barrels of
oil are required to recover our costs under our production-sharing contract with CNPC.  
    Depletion and Depreciation 2003 vs. 2002 Depletion and depreciation increased $0.5 million in 2003, which was primarily due to the increase
in depletion rates to $10.44 per Boe in 2003 compared to $8.35 per Boe in 2002. The U.S. depletion rate for 2003 was $10.58 per Boe, a 26% increase from 2002, due mainly to an
increase in the carrying value of our evaluated U.S. oil and gas properties primarily in Northwest
Lost Hills, East Texas and North South Forty in the fourth quarter of 2003. The China depletion rate for 2003 was $10.23 per Boe, a 23% increase from 2002, as a result of a
downward revision of our share of proved reserves at Dagang due to increased oil prices in 2003 and
anticipated increases in Dagang future development costs. Write-Down of GTL Investments As discussed below in this Item 7 in Critical Accounting Principles and Estimates  Write-down of
Non-Oil and Gas Properties, for Canadian GAAP we capitalize technical and commercial feasibility
costs incurred for GTL or EOR projects, including studies for the marketability of the projects
products, subsequent to executing an MOU. If no definitive agreement is reached, then the
capitalized costs, which are deemed to have no future value, are written down to our results of
operations with a corresponding reduction in our investments in GTL and EOR assets. For U.S. GAAP,
all such costs are expensed as incurred.  
    Write-Down of GTL Investments 2004 vs. 2003 In the second quarter of 2004, we wrote down our $0.3 million investment in the Oman GTL project as
our opportunity to build a 45,000-barrels per day GTL fuels plant in Oman failed to materialize due
to a lack of sufficient uncommitted gas volumes. This compares to the $3.3 million write-down of
our GTL investments in connection with negotiation costs incurred to construct and operate a GTL
production facility in Qatar, which was terminated in 2003 without reaching a definitive agreement.  
    Write-Down of GTL Investments 2003 vs. 2002 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 compared to a
write-down of $2.4 million in 2002 related to our investment in Syntroleums Sweetwater GTL
project. Impairment of U.S. Oil and Gas Properties As discussed below in this Item 7 in Critical Accounting Principles and Estimates  Impairment of
Proved Oil and Gas Properties, we evaluate each of our cost centers proved oil and gas properties
for impairment on a quarterly basis. If as a result of this evaluation, a cost centers carrying
value exceeds its expected future net cash flows from its proved and probable reserves then a
provision for impairment must be recognized in the results of operations.  
    Impairment of U.S. Oil and Gas Properties 2004 vs. 2003 We impaired our U.S. oil and gas properties by $16.3 million in 2004, compared to an impairment of
$20.0 million in 2003. The impairment for 2004 is due to an evaluation of a number of our proved
properties at the Knights Landing, Citrus and South Midway fields, and a further impairment of our
unproved properties, primarily Northwest Lost Hills. At the Knights Landing gas field, our 2004 drilling resulted in three successful completions and
six dry holes. We plan to use 3-D 32




---



##### 



seismic to improve the discovery rate in this field and well
workovers are planned to increase gas rates and reduce operating costs. At our Citrus field we are
evaluating drilling another horizontal leg in our horizontal well by the second quarter of 2005 to
target the upper Antelope zone located a few hundred feet above the existing horizontal well. In
the southern expansion area at South Midway, we have supplemented the cyclic steam project with a
pilot to test continuous steam injection into two wells. The project began in October 2004 and by
year-end 2004 was beginning to yield increased production in the surrounding wells. The further
impairment of our Northwest Lost Hills prospect reflects the potential farm-out of a portion of our
working interest to one or more partners to fund a test of the well.  
    Impairment of U.S. Oil and Gas Properties 2003 vs. 2002 The $20.0 million impairment for 2003 was due to an increase in the carrying value of our proved
U.S. oil and gas properties primarily in Northwest Lost Hills, East Texas and North South Forty
when compared to the expected future cash flows of our U.S. proved reserves at year end 2003. Such
carrying values 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. Additionally 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 proved U.S. oil and gas
properties. Capital Investments - 2004 Our investments in capital activities in each of the three most recently completed financial years
were as follows: Year ended December 31,2004
    
    
    2003
    
    
    2002Oil and Gas Activities:U.S.
    
    $
    17,428
    
    
    $
    8,386
    
    
    $
    13,305China
    
    
    26,965
    
    
    
    6,213
    
    
    
    3,626GTL
    
    
    95
    
    
    
    792
    
    
    
    1,897EOR
    
    
    1,966
    
    
    
    
    
    
    
    $
    46,454
    
    
    $
    15,391
    
    
    $
    18,828
 Oil and Gas Activities - U.S. We completed the drilling of the first Citrus well, which was spud in December 2003, and drilled
two additional Citrus wells and completed production facilities during 2004 for $5.5 million. We spent $7.1 million on our Knights Landing field during 2004. We farmed-in to the Knights Landing
field in February 2004 by purchasing a 50% working interest in four previous discoveries in the
contract area and funding gas gathering, surface treatment facilities and meters to connect the
four wells to an existing pipeline system. Additionally, we drilled nine new exploratory wells to
earn a 50% working interest after payout in any new discoveries, which resulted in three successful
completions and six dry holes. In December 2004, we reached an agreement with the operator of the
field to purchase its interest in the field, increasing our working interests in the field and 11
existing producing natural gas wells to between 80% and 100%. We invested $2.1 million during 2004 to extend the SAGD pilot program at LAK Ranch including
modifications to the existing facilities for cyclic steaming operations to enable steam injection
in the producing horizontal well, installation of fiber optic temperature recording and artificial
lift equipment on the producing horizontal well and acquisition of ultra high resolution 3-D
seismic needed to better define the optimum reservoir development locations. In 2004, we drilled seven new wells on the South Midway properties for $1.1 million, consisting of
six step-out development locations and one exploratory well. Four of the six development wells
were completed as producers. The exploratory well was unsuccessful and will be held for a future
disposal well. We completed the drilling of the first Sledge Hamar well, which was spud in December 2003, and
drilled one follow up well for $0.4 million. However, the follow up well drilled in April 2004
encountered the Stevens sands below the oil/water contact and tested only water. After evaluating
the production results and other potential hydrocarbon intervals, we concluded that the future
economic potential was unfavorable and, in December 2004, sold our working interest for $0.5
million. We drilled one well at the McCloud River prospect during 2004 for $0.3 million, including prospect
acquisition costs. The initial well resulted in a dry hole. 33




---



##### 



We incurred $0.9 million of lease acquisition costs, including lease rentals, geological and
geophysical and seismic on various prospects primarily in California during 2004, which were
capitalized under the full cost method of accounting. See Critical Accounting Principles and
Estimates  Full Cost Accounting in this Item 7. Oil and Gas Activities  China We incurred $20.0 million in capital investments during 2004 to further our overall development
program at Dagang. We drilled and completed 16 development wells and converted 1 existing well to
water injection service. Three new wells were awaiting completion at the end of 2004 and we
commenced the drilling of 1 well in late December 2004. We incurred $7.0 million during 2004 to complete the acquisition, processing and interpretation of
approximately 540 miles of a 700-mile seismic acquisition program on the Zitong block. We selected
the location of our first exploration well and signed a drilling contract to commence drilling of
the well in the first quarter of 2005. The drilling of a second well, expected in late 2005, will
follow completion of the remaining portion of our seismic acquisition program. EOR Activities Capital investments in EOR related activities for 2004 was $2.0 million, primarily related to Iraqi
EOR project activities. In October 2004, we signed an MOU with the Ministry of Oil of the Government of Iraq to study and
evaluate the shallow Qaiyarah oil field in Iraq. The fields reservoirs contain a large proven
accumulation of 17.1oAPI heavy oil at a depth of about 1,000 feet. We will evaluate the
potential response of the Qaiyarah oil field to the latest in EOR techniques, along with the
potential value that could be added using the Ensyn RTP Technology to produce higher
quality, more valuable crude oil. The work will include an assessment of the oil-in-place in the
reservoirs, and the optimum EOR/HTL methods to establish economically recoverable volumes at the
Qaiyarah oil field. If the evaluation studies indicate development of the field is economically
viable, we will present a development plan and offer a commercial proposal to implement an EOR
program for the Qaiyarah oil field. The Iraqi Ministry of Oil is under no obligation to execute the
project or to enter into formal commercial negotiations at the completion of our study. GTL Activities There was minimal capital investment in GTL projects for 2004. There were no significant changes in
the status of our active GTL projects in Egypt and Bolivia and we continue to pursue definitive
agreements for the construction and operation of GTL facilities in those countries. Liquidity and Capital Resources Sources and Uses of Cash Our net cash and cash equivalents decreased by $5.2 million in 2004. Our 2004 operating activities
provided $4.0 million in cash due to a 41% increase in our production volumes, primarily from
China, and a 32% increase in oil and gas prices from 2003. We raised a net of $22.2 million from
two special warrant financings in the first quarter of 2004 and from the exercise of options during
the year. We raised $14.0 million of cash during 2004 from the farm-out of a 40% working interest
in the Dagang field and the sale of our working interest in the Sledge Hamar field. We completed
the drawdown of our non-revolving line of credit for the development of the South Midway field by
borrowing $4.0 million and we made note payments of $0.7 million during 2004. This was offset by
capital investments, after changes in non-cash working capital, of $43.2 million, as discussed in
this Item 7 Capital Investments  2004, and $2.5 million to acquire a 15% equity interest in
EPIL plus merger expenses of $2.5 million incurred during 2004 to acquire 100% of Ensyn. Our net cash and cash equivalents increased by $10.5 million in 2003 compared to a decrease of $5.7
million in 2002. 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. This was 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. 34




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##### 



Year ended December 31,2004
    
    
    2003
    
    
    2002Cash flow (deficit) from operating activities
    
    $
    4,032
    
    
    $
    (1,522
    )
    
    $
    (2,120
    )Investing ActivitiesCapital investments, after changes in non-cash working capital
    
    
    (43,190
    )
    
    
    (15,928
    )
    
    
    (19,466
    )Proceeds from sale of assets
    
    
    13,958
    
    
    
    
    
    
    
    5,351Investment in Ensyn
    
    
    (5,016
    )
    
    
    (500
    )
    
    
    Other
    
    
    (410
    )
    
    
    (37
    )
    
    
    (65
    )(34,658
    )
    
    
    (16,465
    )
    
    
    (14,180
    )Financing ActivitiesPrivate placements, net of share issue costs
    
    
    20,428
    
    
    
    24,070
    
    
    
    9,964Proceeds from exercise of options and warrants
    
    
    1,723
    
    
    
    3,928
    
    
    
    119Net debt financing
    
    
    3,306
    
    
    
    500
    
    
    
    50025,457
    
    
    
    28,498
    
    
    
    10,583Net Sources (Uses) of Cash
    
    $
    (5,169
    )
    
    $
    10,511
    
    
    $
    (5,717
    )
 Outlook for 2005 Our capital investment budget for 2005 is $79.0 million. Of the total 2005 investment program,
$54.2 million, or 69%, is for continued development of our producing fields at Dagang, South
Midway, Knights Landing and Citrus. Approximately $22.5 million, or 29% of the budget, is for
exploration programs in the U.S., principally in California, and for our exploration commitment in
the Zitong block. The balance of our 2005 budget, or approximately $2.3 million, is for the
continued development of EOR and GTL initiatives around the world.
Additionally, we have agreed to pay $10.0 million in cash and
$75 million in stock to acquire Ensyn and expect to incur
approximately $1.5 million in Merger related expenses during 2005 in order to close the transaction. We plan to seek financing on an
as needed basis, from equity markets, project lenders, joint ventures or other potential financing
sources to complete this capital program and acquisition of Ensyn, to pursue acquisitions of proven and probable reserves
and to deploy our HTL and GTL technologies. In addition, we, together with our 40% partner in the
Dagang project, are in active discussions with European and Chinese lending banks to provide
funding for the development of the Dagang field. 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 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 and Commitments The table below summarizes and cross-references the contractual obligations and commitments that
are reflected in our Consolidated
Balance Sheets and/or disclosed in the accompanying Notes: Payments Due by Year(stated in thousands of U.S. dollars)Total
    
    
    2005
    
    
    2006
    
    
    2007
    
    
    2008
    
    
    After 2008Purchase Agreement:
    
    $
    200
    
    
    $
    100
    
    
    $
    100
    
    
    $
    
    
    
    $
    
    
    
    $
    Consolidated Balance Sheets:Note payable  current portion (Note 8)
    
    
    1,667
    
    
    
    1,667
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Long term debt (Note 8)
    
    
    2,639
    
    
    
    
    
    
    
    1,667
    
    
    
    972
    
    
    
    
    
    
    
    Other Commitments:
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Interest payable (1)
    
    
    302
    
    
    
    186
    
    
    
    99
    
    
    
    17
    
    
    
    
    
    
    
    Lease commitments (Note 17)
    
    
    2,123
    
    
    
    616
    
    
    
    543
    
    
    
    342
    
    
    
    287
    
    
    
    335Zitong exploration commitment (Note 17)
    
    
    12,400
    
    
    
    12,400
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Total
    
    $
    19,331
    
    
    $
    14,969
    
    
    $
    2,409
    
    
    $
    1,331
    
    
    $
    287
    
    
    $
    335
    We have excluded our normal purchase arrangements as they are discretionary and/or being
performed under contracts which are cancelable immediately or with a 30-day notification period. 35




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Critical Accounting Principles and Estimates Our accounting principles are described in Note 2 to Notes to the Consolidated Financial Statements
in Item 8 of this Annual Report on Form 10-K. 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 19 to Notes to the Consolidated Financial Statements in Item 8 of
this Annual Report on Form 10-K. 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 19 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
properties. Under the full cost method, all exploration and development costs associated with lease
and royalty interest acquisition, geological and geophysical activities, carrying charges for
unproved properties, drilling both successful and unsuccessful wells, gathering and production
facilities and equipment, financing, administrative costs directly related to capital projects and
asset retirement costs are capitalized on a country-by-country cost center basis. As at December
31, 2004, the carrying values of our U.S. and China cost centers were $40.8 million and $39.7
million, respectively. The other generally accepted method of accounting for costs incurred for oil and gas properties is
the successful efforts method. Under this method, costs associated with land acquisition and
geological and geophysical activities are expensed in the year incurred and the costs of drilling
unsuccessful wells are expensed upon abandonment. As a consequence of following the full cost method of accounting, we may be more exposed to
potential impairments if the carrying value of a cost centers oil and gas properties exceeds its
estimated future net cash flows than if we followed the successful efforts method of accounting. An
impairment may occur if a cost centers recoverable reserve estimates decrease, oil and natural gas
prices decline or capital, operating and income taxes increase to levels that would significantly
affect its estimated future net cash flows. See Impairment of Proved Oil and Gas Properties
below. Oil and Gas Reserves The process of estimating quantities of reserves is inherently uncertain
and complex. It requires significant judgments and decisions based on available geological,
geophysical, engineering and economic data. These estimates may change substantially as additional
data from ongoing development activities and production performance becomes available and as
economic conditions impacting oil and gas prices and costs change. Our reserve estimates are based
on current production forecasts, prices and economic conditions. The reserve numbers and values
included in this Annual Report on Form 10-K are only estimates and you should not assume that the
present value of our future net cash flows from these estimates is the current market value of our
estimated proved oil and gas reserves. (See Risk Factors) Reserve estimates are critical to many accounting estimates and financial decisions including:  
    determining whether or not an exploratory well has found economically producible
reserves. Such determinations involve the commitment of additional capital to develop the
field based on current estimates of production forecasts, prices and other economic
conditions.
    calculating our unit-of-production depletion rates. Proved reserves are used to
determine rates that are applied to each unit-of-production in calculating our depletion
expense. In 2004, oil and gas depletion of $7.4 million was recorded in depletion and
depreciation expense. If our reserve estimates changed by 10%, our depletion and
depreciation expense for 2004 would have changed by approximately $0.7 million assuming no
other changes to our reserve profile. See Depletion below.
    assessing our proved oil and gas properties for impairment on a quarterly basis.
Estimated future net cash flows used to assess impairment of our oil and gas properties are
determined using proved and probable reserves (1). See Impairment of Proved Oil
and Gas Properties below. Management is responsible for estimating the quantities of proved oil and natural gas reserves and
preparing related disclosures. Estimates and related disclosures are prepared in accordance with
SEC requirements, generally accepted industry practices in the U.S. 36




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as promulgated by the Society
of Petroleum Engineers, and the standards of the COGE Handbook modified to reflect SEC
requirements. Independent qualified reserves evaluators prepare reserve estimates for each property at least
annually and issue a report thereon. The reserve estimates are reviewed by our engineers familiar
with the property and by our operational management. Our CEO and CFO meet with our operational
personnel to review the current reserve estimates and related disclosures in this Annual Report on
Form 10-K and upon their review and approval present the independent qualified reserves evaluators
reserve reports to our Board of Directors with a recommendation for approval. Our Board of
Directors has approved the reserve estimates and related disclosures in this Annual Report on Form
10-K. The estimated discounted future net cash flows from estimated proved reserves included in the
Supplementary Financial Information in this Annual Report on Form 10-K are based on prices and
costs as of the date of the estimate. Actual future prices and costs may be materially higher or
lower. Actual future net cash flows will also be affected by factors such as actual production
levels and timing, and changes in governmental regulation or taxation, and may differ materially
from estimated cash flows. (1) Proved oil and gas reserves are the estimated quantities of natural gas, crude oil,
condensate and natural gas liquids that geological and engineering data demonstrate with reasonable
certainty can be recoverable in future years from known reservoirs under existing economic and
operating conditions. Reservoirs are considered proved if economic producability is supported by
either actual production or a conclusive formation test. Probable reserves are those additional
reserves that are less likely to be recovered than proved reserves. It is equally likely that the
actual remaining quantities recovered will be greater or less than the sum of estimated proved plus
probable reserves. Depletion  As indicated previously our estimate of proved reserves are critical to
calculating our unit-of-production depletion rates. Another critical factor affecting our depletion rate is our determination that an impairment of
unproved oil and gas properties has occurred. Costs incurred on an unproved oil and gas property
are excluded from the depletion rate calculation until it is determined whether proved reserves are
attributable to an unproved oil and gas property or upon determination that an unproved oil and gas
property has been impaired. An unproved oil and gas property would likely be impaired if, for
example, a dry hole has been drilled and there are no firm plans to continue drilling on the
property. Also, the likelihood of partial or total impairment of a property increases as the
expiration of the lease term approaches and there are no plans to drill on the property or to
extend the term of the lease. We assess each of our unproved oil and gas properties for impairment
on a quarterly basis. If we determined that an unproved oil and gas property has been totally or
partially impaired we respectively include all or a portion of the accumulated costs incurred for
that unproved oil and gas property in the calculation of our unit-of  production depletion rate.
As at December 31, 2004, we had $20.4 million and $10.6 million of costs incurred on unproved oil
and gas properties in the U.S. and China, respectively. Our depletion rate is also affected by our estimates of future costs to develop the proved
reserves. We estimate future development costs using quoted prices, historical costs and trends. It
is difficult to predict prices for materials and services required to develop a field particularly
over a period of years with rising oil and gas prices during which there is generally increased

competition for a limited number of suppliers. We update our estimates of future costs to develop
our proved reserves on a quarterly basis. Impairment of Proved Oil and Gas Properties We evaluate each of our cost centers proved oil and
gas properties for impairment on a quarterly basis. The basis for calculating the amount of
impairment is different for U.S. and Canadian GAAP purposes. Effective January 2004, Accounting Guideline 16 Oil and Gas Accounting   Full Cost (AcG 16)
requires recognition and measurement processes to assess impairment of oil and gas properties
(ceiling test). In the recognition of an impairment, the carrying value (1) of a cost
center is compared to the undiscounted future net cash flows of that cost centers proved reserves
using estimates of future oil and gas prices and costs plus the cost of unproved properties that
have been excluded from the depletion calculation. If the carrying value is greater than the value
of the undiscounted future net cash flows of the proved reserves plus the cost of unproved
properties excluded from the depletion calculation, then the amount of the cost centers potential
impairment must be measured. A cost centers impairment loss is measured by the amount its carrying
value exceeds the discounted future net cash flows of its proved and probable reserves using
estimates of future oil and gas prices and costs plus the cost of unproved properties that have
been excluded from the depletion calculation and which contain no probable reserves. The net cash
flows of a cost centers proved and probable reserves are discounted using a risk-free interest
rate. The amount of the impairment loss is recognized as a charge to the results of operations and
a reduction in the net carrying amount of a cost centers oil and gas properties. We provided for
$16.3 million and $20.0 million in ceiling test impairments for our U.S. cost center for the years
ended December 31, 2004 and 2003, respectively. No ceiling test impairments were provided for in
the year ended December 31, 2002. For U.S. GAAP, we follow the requirements of the SECs Regulation S-X Article 4-10(c)4 for
determining the limitation of capitalized costs. Accordingly, the carrying value (1) of
a cost centers oil and gas properties cannot exceed the discounted future net cash flows of its
proved reserves using period-end oil and gas prices and costs plus (i) the cost of properties that
have been excluded from the depletion calculation and (ii) the lower of cost or estimated fair
value of unproved properties included in the depletion calculation less income tax effects related
to differences between the book and tax basis of the properties. The net cash flows of a cost 37




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##### 



centers proved reserves are discounted using ten percent. The amount of the impairment loss is
recognized as a charge to the results of operations and a reduction in the net carrying amount of a
cost centers oil and gas properties. We provided for $15.0 million and $20.0 million in ceiling
test impairments for our U.S. cost center for the years ended December 31, 2004 and 2003,
respectively. No ceiling test impairments were provided for in the year ended December 31, 2002. (1) For Canadian GAAP, the carrying value includes all capitalized costs for each cost center,
including costs associated with asset retirement net of estimated salvage values, unproved
properties and major development projects, less accumulated depletion and ceiling test impairments.
This is essentially the same definition according to Regulation S-X, except that carrying value of
assets should be net of deferred income taxes and costs of major development projects are to be
considered separately for purposes of the ceiling test calculation. Write-down of Non-Oil and Gas Properties We incur various costs in the pursuit of GTL and
EOR projects throughout the world. For Canadian GAAP, such costs incurred prior to signing an MOU,
or similar agreements, are considered to be business development or project identification and are
expensed as incurred. Upon executing an memorandum of understanding to determine the technical and
commercial feasibility of a project, including studies for the marketability of the projects
products, we assume the feasibility and related costs incurred have potential future value, are
probable of leading to a definitive agreement for the exploitation of proved reserves and should be
capitalized. If no definitive agreement is reached, then the capitalized costs, which are deemed to
have no future value, are written down to our results of operations with a corresponding reduction
in our investments in GTL and EOR assets. For the years ended December 31, 2004, 2003 and 2002, we
wrote down $0.3 million, $3.3 million and $2.4 million, respectively, of capitalized negotiation
and feasibility costs associated with our GTL projects which did not result in definitive
agreements. For U.S. GAAP, feasibility, marketing and related costs incurred prior to executing a GTL or EOR
definitive agreement are considered to be research and development and are expensed as incurred.
For the years ended December 31, 2004, 2003 and 2002, we expensed $2.1 million, $0.8 million and
$1.9 million, respectively, of feasibility, marketing and related costs incurred prior to executing
definitive agreements. Impact of New and Pending Canadian GAAP Accounting Standards In December 2002, the Canadian Institute of Chartered Accountants (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, we changed our accounting policy
to capitalize asset retirement costs as part of the carrying value of our oil and gas properties
and adjusted the amount of our site restoration liability to the present value of the liability for
the corresponding asset retirement obligation as of this date. We have adopted the policy without
retroactive adjustment of prior years because implementation of this change had an immaterial
effect on our financial position and results of operations in prior years and in the current
period. In September 2003, the CICA issued 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 properties, 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. Prior to January 2004, we applied hedge accounting to all derivative instruments used to manage
price fluctuations in oil and natural gas prices. Effective January 1, 2004, we adopted CICA
Accounting Guideline 13 (AcG 13), Hedging Relationships. This guideline sets out the criteria
that must be met in order to apply hedge accounting for derivatives. The guideline provides
detailed guidance on the identification, designation, documentation and effectiveness of hedging
relationships for purposes of applying hedge accounting, and the discontinuance of hedge
accounting. Gains and losses on derivative instruments designated and qualifying as hedges under
this guideline are recognized in earnings in the same period as the related hedged item.
Ineffective hedging relationships and hedges not designated in a hedging relationship are carried
at fair value in the statement of financial position, and subsequent
changes in their fair value are recorded in the results of operations. The adoption of this
accounting guideline did not have a material impact on the consolidated financial statements. In July 2002, the CICA approved Section 3870, Stock Based Compensation and Other Stock Based
Payments (S.3870). S.3870 applies to all stock based awards entered into during fiscal years
beginning on or after January 1, 2002. For awards entered into with non-employees on or after
January 1, 2002, S.3870 requires compensation costs to be recognized in the financial statements
over the periods in which the stock options vest using the fair value based method of accounting.
Although earlier implementation was encouraged, S.3870 did not require compensation costs to be
recognized in the financial statements for stock based awards to employees and directors entered
into during fiscal years beginning on or after January 1, 2002 until January 1, 2004. If earlier
implementation was not elected, S.3870 requires a retroactive application of the change in
accounting for such stock based awards entered into between January 1, 2002 and December 31, 2003
with an option to restate the financial statements of prior periods. We 38




---



##### 



implemented S.3870, as it
relates to stock based awards to employees and directors, effective January 1, 2004 with a
restatement of the financial statements of prior periods. In January 2005, the CICA approved Section 1530 Comprehensive Income (S.1530), Section 3855
Financial Instruments  Recognition and Measurement (S.3855) and Section 3865 Hedges
(S.3865) to harmonize financial instrument and hedge accounting with U.S. GAAP and introduce the
concept of comprehensive income. S.1530 requires presentation of certain gains and losses outside
of net income, such as unrealized gains and losses related to hedges or other derivative
instruments. S.3855 establishes standards for recognizing and measuring financial assets and
financial liabilities and non-financial derivatives as required to be disclosed under Section 3861
Financial Instruments Disclosure and Presentation. S.3865 establishes standards for how and when
hedge accounting may be applied. We apply SFAS No. 133 Accounting for Derivative Instruments and
Hedging Activities for U.S. GAAP purposes and will implement S.3865 for Canadian GAAP for hedging
activities. These sections apply to interim and annual financial statements relating to fiscal
years beginning on or after October 1, 2006 and are not expected to have a material impact on our
financial statements. In January 2005, the CICA approved Section 3251 Equity which establishes standards for the
presentation of equity and changes in equity during a reporting period. This section applies to
interim and annual financial statements relating to fiscal years beginning on or after October 1,
2006 and is not expected to have a material impact on our financial statements. The following standards issued by the CICA do not impact us at this time:  
    Section 3861, Financial Instruments Disclosure and Presentation, effective for fiscal
years beginning on or after November 1, 2004.
    Accounting Guideline 15, Consolidation of Variable Interest Entities, effective for
annual and interim periods beginning on or after January 1, 2004. Impact of New and Pending U.S. GAAP Accounting Standards In June 2004, the Financial Accounting Standards Board (FASB) issued an exposure draft of a
proposed statement, Fair Value Measurements to provide guidance on how to measure the fair value
of financial and non-financial assets and liabilities when required by other authoritative
accounting pronouncements. The proposed statement attempts to address concerns about the ability to
develop reliable estimates of fair value and inconsistencies in fair value guidance provided by
current U.S. GAAP, by creating a framework that clarifies the fair value objective and its
application in U.S. GAAP. In addition, the proposal expands disclosures required about the use of
fair value to re-measure assets and liabilities. The standard would be effective for financial
statements issued for fiscal years beginning after June 15, 2005. In September of 2004, the SEC released Staff Accounting Bulletin No. 106, which provides guidance
regarding the interaction of Statement of Financial Accounting Standard No. 143, Accounting for
Asset Retirement Obligations (SFAS 143) with the full cost accounting rules in Article 4-10 of
Regulation S-X. This bulletin clarifies the treatment of assets and liabilities resulting from the
implementation of SFAS 143 on the full cost ceiling test and the calculation of depletion,
depreciation and amortization. We are in compliance with the provisions of Staff Accounting
Bulletin No. 106. In December 2004, the FASB issued a revision to SFAS No. 123, Accounting for Stock Based
Compensation, which supersedes APB No. 25, Accounting for Stock Issued to Employees. This
Statement requires measurement of the cost of employee services received in exchange for an award
of equity instruments based on the fair value of the award on the date of the grant and recognition
of the cost in the results of operations over the period during which an employee is required to
provide service in exchange for the award. No compensation cost is recognized for equity
instruments for which employees do not render the requisite service. We apply APB Opinion No. 25,
as interpreted by FASB Interpretation No. 44, in accounting for awards issued from our stock option
plan and do not recognize compensation costs in our financial statements for stock options issued
to our employees and directors. This statement is effective for the first interim or annual
reporting period that begins after June 15, 2005 and may be implemented on a
modified prospective or retrospective basis. We have elected to implement this statement on a
modified prospective basis starting in the third quarter of 2005. Under the modified prospective
basis we would recognize stock based compensation in our U.S. GAAP results of operations for the
unvested portion of awards outstanding as of July 1, 2005 and for all awards granted after July 1,
2005. The following standards issued by the FASB do not impact us at this time: SFAS No. 151, Inventory Costs  an amendment of ARB No. 43, Chapter 4 effective for inventory
costs incurred during fiscal years beginning after June 15, 2005. 39




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SFAS No. 153, Exchanges of Nonmonetary Assets  an amendment of APB Opinion No. 29 effective for
nonmonetary asset exchanges occurring in fiscal years beginning after June 15, 2005. Off Balance Sheet Arrangements At December 31, 2004 and 2003, 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
on a cost recovery basis. The agreement for the usage of aircraft was terminated in 2003. The costs
incurred in the normal course of business with respect to the above arrangements amounted to $0.9
million each for 2004 and 2003 and $1.2 million for 2002. In addition, a company controlled by a
director provides us with consulting services. Consulting services and out of pocket expenses paid
to this company were $0.7 million for 2004 and $0.4 million each for 2003 and 2002. At year-end,
amounts included in accounts payable under these arrangements totaled $0.1 million in 2004 and 2003
and $0.8 million in 2002. In 2003, we borrowed $1.25 million from a related company controlled by one of our directors. The
loan, plus accrued interest, was repaid in September 2003. 
 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Equity Market Risks 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.
We estimate that we will need approximately $40 million from the equity markets to fund our capital
investment programs for 2005. We can give no assurance that we will be successful in obtaining financing from equity markets as
and when needed. Factors beyond our control may make it difficult or impossible for us to obtain
equity financing on favorable terms or at all. Failure to obtain any required equity financing on
a timely basis may cause us to postpone our development plans, forfeit rights in some or all of our
projects or reduce or terminate some or all of our operations. Commodity Price Risk Commodity price risk related to crude oil prices is one of our most significant market risk
exposures. Crude oil prices and quality differentials are influenced by worldwide factors such as
OPEC actions, political events and supply and demand fundamentals. To a lesser extent we are also
exposed to natural gas price movements. Natural gas prices are generally influenced by oil prices,
North American supply and demand and local market conditions. We estimate that our net income and
cash from operations for 2005 would change $1.0 million and $0.9 million for every $1.00/Bbl change
in WTI prices and $0.50/Mcf in natural gas prices, respectively. We periodically engage in the use of derivatives to hedge our cash flow from operations but have no
hedge contracts in place as at December 31, 2004. See Note 12 to the Consolidated Financial
Statements in Item 8. Decreases in oil and natural gas prices would negatively impact our results of operations as a
direct result of a reduction in revenues but may also do so in the ceiling test calculation for the impairment of our oil and gas
properties. On a quarterly basis, we compare the value of our proved and probable reserves, using
estimated future oil and gas prices (1), to the carrying value of our oil and gas
properties. The ceiling test calculation is sensitive to oil and gas prices and in a period of
declining prices could result in a charge to our results of operations as we experienced in 2001
when we recorded a $14.0 million provision for impairment for Canadian GAAP and an additional $10.0
million for U.S. GAAP mainly due to a decline in oil and gas prices. Decreases in oil and gas
prices from those used in our ceiling test calculation as at December 31, 2004 as discussed above
in Critical Accounting Principles and Estimates  Impairment of Proved Oil and Gas Properties may
result in additional impairment provisions on our U.S. oil and gas properties. (1) The recoverable value of probable reserves is included only for the measurement of the
impairment of the carrying value of oil and gas properties as required under 40




---



##### 



Canadian GAAP but not
for U.S. GAAP. Additionally, U.S. GAAP requires the use of period end oil and gas prices to measure
the amount of the impairment rather than estimated future oil and gas prices as required by
Canadian GAAP. See Critical Accounting Principles and Estimates in Item 7 in this Annual Report
on Form 10-K for the difference between Canadian and U.S. GAAP in calculating the impairment
provision for oil and gas properties. Foreign Currency Rate Risk In the international petroleum industry, most production is bought and sold in U.S. dollars or with
reference to the U.S. dollar. Accordingly, we do not expect to face foreign exchange risks
associated with our production revenues. Most of our business transactions, in the countries in which we operate, are conducted in U.S.
dollars or currencies, such as Chinese renminbi, which are pegged to the U.S. dollar. As a result,
we incurred insignificant foreign currency exchange gains or losses during the three years ended
December 31, 2004. Interest Rate Risk 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 PageReport
of Independent Registered Chartered Accountants
    
    
    42Consolidated Financial StatementsConsolidated Balance Sheets
    
    
    43Consolidated Statements of Loss
    
    
    44Consolidated Statements of Shareholders Equity
    
    
    45Consolidated Statements of Cash Flow
    
    
    46Notes to the Consolidated Financial Statements
    
    
    47Quarterly Financial Data in Accordance with Canadian and U.S. GAAP (Unaudited)
    
    
    67Supplementary
Disclosures About Oil and Gas Production Activities (Unaudited)
    
    
    67
 41




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##### 



REPORT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS To the Shareholders ofIvanhoe Energy Inc.: We have audited the consolidated balance sheets of Ivanhoe Energy Inc. as at December 31, 2004 and
2003 and the consolidated statements of loss and shareholders equity and cash flow for each of the
three years in the period ended December 31, 2004. 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 Canadian generally accepted auditing standards and the
standards of the Public Company Accounting Oversight Board (United States). These 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, 2004 and 2003 and the results of
its operations and its cash flows for each of the three years in the period ended December 31, 2004
in accordance with Canadian generally accepted accounting principles. (signed) Deloitte & Touche LLP Independent Registered Chartered Accountants
Calgary, Alberta, Canada February 11, 2005 COMMENTS BY AUDITORS FOR U.S. READERS ON
CANADA  U.S. REPORTING DIFFERENCES The standards of the Public Company Accounting Oversight Board (United States) require the addition
of an explanatory paragraph (following the opinion paragraph) when there are changes in accounting
principles that have a material effect on the comparability of the Companys financial statements
and 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 (Canadian Institute of Chartered Accountants (CICA)
Handbook Section 3110), stock-based compensation (CICA Handbook Section 3870), and the full cost
method of accounting (CICA Accounting Guideline 16). Our report to the shareholders dated February
11, 2005 is expressed in accordance with Canadian reporting standards, which do not require a
reference to such changes in accounting principles in the auditors report when the changes are
properly accounted for and adequately disclosed in the financial statements. (signed) Deloitte & Touche LLP Independent Registered Chartered Accountants
Calgary, Alberta, Canada February 11, 2005 42




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##### 



IVANHOE ENERGY INC. 
 Consolidated Balance Sheets
 As at December 31,2004
    
    
    2003(restatedNotes 2 and 9)AssetsCurrent AssetsCash and cash equivalents
    
    $
    9,322
    
    
    $
    14,491Accounts receivable (Note 3)
    
    
    5,377
    
    
    
    2,720Prepaid and other current assets
    
    
    812
    
    
    
    40915,511
    
    
    
    17,620Long term assets (Note 5)
    
    
    6,424
    
    
    
    998Oil and gas properties and investments, net (Note 4)
    
    
    96,551
    
    
    
    87,956$
    118,486
    
    
    $
    106,574Liabilities and Shareholders EquityCurrent LiabilitiesAccounts payable and accrued liabilities
    
    $
    9,845
    
    
    $
    4,516Note payable  current portion (Note 6)
    
    
    1,667
    
    
    
    16711,512
    
    
    
    4,683Long term debt (Note 6)
    
    
    2,639
    
    
    
    833Asset retirement obligations (Note 7)
    
    
    749
    
    
    
    521Commitments
and contingencies (Note 17)Shareholders EquityShare capital, issued and outstanding 169,664,911 common shares;December 31, 2003 161,359,339 common shares (Note 8)
    
    
    183,617
    
    
    
    161,075Contributed surplus
    
    
    1,748
    
    
    
    516Accumulated deficit
    
    
    (81,779
    )
    
    
    (61,054
    )103,586
    
    
    
    100,537$
    118,486
    
    
    $
    106,574
 (See accompanying Notes to Consolidated Financial Statements) Approved by the Board: (signed) David R. Martin
    
    (signed) E. Leon DanielDirector
    
    Director
 43




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##### 



IVANHOE ENERGY INC. 
 Consolidated Statements of Loss
 Year ended December 31,2004
    
    
    2003
    
    
    2002(restated Notes 2 and 9)RevenueOil and gas revenue
    
    $
    17,795
    
    
    $
    9,569
    
    
    $
    8,329Interest income
    
    
    202
    
    
    
    90
    
    
    
    10817,997
    
    
    
    9,659
    
    
    
    8,437ExpensesOperating costs
    
    
    5,073
    
    
    
    4,293
    
    
    
    3,841General and administrative
    
    
    9,188
    
    
    
    8,211
    
    
    
    5,955Depletion and depreciation
    
    
    7,482
    
    
    
    3,829
    
    
    
    3,312Interest expense
    
    
    379
    
    
    
    184
    
    
    
    23Write-downs and provision for impairment (Notes 4 and 13)
    
    
    16,600
    
    
    
    23,321
    
    
    
    2,43638,722
    
    
    
    39,838
    
    
    
    15,567Net Loss
    
    $
    20,725
    
    
    $
    30,179
    
    
    $
    7,130Net Loss per share   Basic and Diluted(Note 15)
    
    $
    0.12
    
    
    $
    0.20
    
    
    $
    0.05Weighted Average Number of Shares (in thousands)(Note 15)
    
    
    167,612
    
    
    
    150,154
    
    
    
    142,314
 (See accompanying Notes to Consolidated Financial Statements) 44




---



##### 



IVANHOE ENERGY INC. 
 Consolidated Statements of Shareholders Equity
  Share Capital
    
    
    Contributed
    
    
    AccumulatedShares
    
    
    Amount
    
    
    Surplus
    
    
    Deficit
    
    
    TotalBalance December 31, 2001
    
    
    139,267
    
    
    $
    120,392
    
    
    $
    
    
    
    $
    (23,495
    )
    
    $
    96,897Net loss, as previously reported
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (6,819
    )
    
    
    (6,819
    )Retroactive application of change in accounting
policy for stock based compensation (Notes 2 and 9)
    
    
    
    
    
    
    
    
    
    
    311
    
    
    
    (311
    )
    
    
    Net loss, as restated
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (7,130
    )Shares issued on private placements, net of share
issue costs
    
    
    5,000
    
    
    
    9,964
    
    
    
    
    
    
    
    
    
    
    
    9,964Shares issued on exercise of options
    
    
    163
    
    
    
    119
    
    
    
    
    
    
    
    
    
    
    
    119Shares issued for services
    
    
    201
    
    
    
    387
    
    
    
    
    
    
    
    
    
    
    
    387Elimination of employee loans (Note 8)
    
    
    
    
    
    
    409
    
    
    
    
    
    
    
    
    
    
    
    409Retirement of shares
    
    
    (165
    )
    
    
    (159
    )
    
    
    
    
    
    
    (250
    )
    
    
    (409
    )Balance December 31, 2002 (as restated)
    
    
    144,466
    
    
    
    131,112
    
    
    
    311
    
    
    
    (30,875
    )
    
    
    100,548Net loss, as previously reported
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (29,703
    )
    
    
    (29,703
    )Retroactive application of change in accounting
policy for stock based compensation (Notes 2 and 9)
    
    
    
    
    
    
    
    
    
    
    476
    
    
    
    (476
    )
    
    
    Net loss, as restated
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (30,179
    )Shares issued on private placements, net of share
issue costs
    
    
    12,654
    
    
    
    24,070
    
    
    
    
    
    
    
    
    
    
    
    24,070Shares issued on conversion of debenture (Note 8)
    
    
    2,000
    
    
    
    1,000
    
    
    
    
    
    
    
    
    
    
    
    1,000Shares issued on exercise of warrants
    
    
    250
    
    
    
    425
    
    
    
    
    
    
    
    
    
    
    
    425Shares issued on exercise of options (as restated)
    
    
    1,363
    
    
    
    3,773
    
    
    
    (271
    )
    
    
    
    
    
    
    3,502Shares issued for services
    
    
    626
    
    
    
    695
    
    
    
    
    
    
    
    
    
    
    
    695Balance December 31, 2003, (as restated)
    
    
    161,359
    
    
    
    161,075
    
    
    
    516
    
    
    
    (61,054
    )
    
    
    100,537Net loss
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (20,725
    )
    
    
    (20,725
    )Shares issued on private placements, net of share
issue costs
    
    
    7,173
    
    
    
    20,428
    
    
    
    
    
    
    
    
    
    
    
    20,428Shares issued on exercise of options
    
    
    975
    
    
    
    1,767
    
    
    
    (44
    )
    
    
    
    
    
    
    1,723Shares issued for services
    
    
    158
    
    
    
    347
    
    
    
    
    
    
    
    
    
    
    
    347Stock based compensation
    
    
    
    
    
    
    
    
    
    
    1,276
    
    
    
    
    
    
    
    1,276Balance December 31, 2004
    
    
    169,665
    
    
    $
    183,617
    
    
    $
    1,748
    
    
    $
    (81,779
    )
    
    $
    103,586
 (See accompanying Notes to Consolidated Financial Statements) 45




---



##### 



IVANHOE ENERGY
INC. 
 Consolidated Statements of Cash Flow
  Year ended December 31,2004
    
    
    2003
    
    
    2002(restated Notes 2 and 9)Operating ActivitiesNet loss
    
    $
    (20,725
    )
    
    $
    (30,179
    )
    
    $
    (7,130
    )Items not requiring use of cash:Depletion and depreciation
    
    
    7,482
    
    
    
    3,829
    
    
    
    3,312Write-downs and provision for impairment (Notes 4
and 13)
    
    
    16,600
    
    
    
    23,321
    
    
    
    2,436Stock based compensation (Note 2 and 9)
    
    
    1,276
    
    
    
    476
    
    
    
    311Other
    
    
    47
    
    
    
    
    
    
    
    Changes in non-cash working capital items
    
    
    (648
    )
    
    
    1,031
    
    
    
    (1,049
    )4,032
    
    
    
    (1,522
    )
    
    
    (2,120
    )Investing ActivitiesCapital investments
    
    
    (46,454
    )
    
    
    (15,391
    )
    
    
    (18,828
    )Proceeds from sale of assets (Note 4)
    
    
    13,958
    
    
    
    
    
    
    
    5,351Equity investment and other related costs (Note 5)
    
    
    (5,016
    )
    
    
    (500
    )
    
    
    Other
    
    
    (410
    )
    
    
    (37
    )
    
    
    (65
    )Changes in non-cash working capital items
    
    
    3,264
    
    
    
    (537
    )
    
    
    (638
    )(34,658
    )
    
    
    (16,465
    )
    
    
    (14,180
    )Financing ActivitiesShares issued on private placements, net of share
issue costs
    
    
    20,428
    
    
    
    24,070
    
    
    
    9,964Shares issued on exercise of options and warrants
    
    
    1,723
    
    
    
    3,928
    
    
    
    119Proceeds from notes and advances (Note 6)
    
    
    14,000
    
    
    
    1,750
    
    
    
    500Payments of note payable (Note 6)
    
    
    (694
    )
    
    
    (1,250
    )
    
    
    Redemption of advance payable (Note 6)
    
    
    (10,000
    )
    
    
    
    
    
    
    25,457
    
    
    
    28,498
    
    
    
    10,583Increase (decrease) in cash and cash equivalents,
for the year
    
    
    (5,169
    )
    
    
    10,511
    
    
    
    (5,717
    )Cash and cash equivalents, beginning of year
    
    
    14,491
    
    
    
    3,980
    
    
    
    9,697Cash and cash equivalents, end of year
    
    $
    9,322
    
    
    $
    14,491
    
    
    $
    3,980Supplementary InformationRegarding Non-Cash TransactionsFinancing activities, non-cashShares issued on conversion of debenture (Note 8)
    
    $
    
    
    
    $
    1,000
    
    
    $
    Included in the above are the following:Taxes paid (refunded)
    
    $
    3
    
    
    $
    6
    
    
    $
    (27
    )Interest paid
    
    $
    317
    
    
    $
    96
    
    
    $
    74Changes in non-cash working capital items
Operating Activities:Accounts receivable
    
    $
    (1,949
    )
    
    $
    (201
    )
    
    $
    38Other current assets
    
    
    (403
    )
    
    
    282
    
    
    
    (316
    )Accounts payable and accrued liabilities
    
    
    1,704
    
    
    
    950
    
    
    
    (771
    )(648
    )
    
    
    1,031
    
    
    
    (1,049
    )Investing ActivitiesAccounts receivable
    
    
    (708
    )
    
    
    
    
    
    
    (619
    )Accounts payable and accrued liabilities
    
    
    3,972
    
    
    
    (537
    )
    
    
    (19
    )3,264
    
    
    
    (537
    )
    
    
    (638
    )$
    2,616
    
    
    $
    494
    
    
    $
    (1,687
    )
 (See accompanying Notes to Consolidated Financial Statements) 46




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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 share amounts)
 1. NATURE OF OPERATIONS Ivanhoe Energy Inc., a Canadian company, and its subsidiaries are focused internationally on three
major strategies: 1) conventional exploration and production of oil and gas 2) enhanced oil
recovery (EOR) development projects including the application of heavy-to-light oil (HTL)
upgrading technology and 3) the monetization of stranded gas reserves through a licensed
gas-to-liquids (GTL) technology. Conventional oil and gas operations are currently carried out in
the U.S. and China and GTL, EOR and HTL projects for a number of countries are in various stages. 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 19. 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. Certain items in the 2003 and 2002 financial statements have been reclassified for comparison to
the 2004 presentation. Changes in Accounting Policies Asset Retirement Costs 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. The Canadian Institute of Chartered Accountants (CICA) approved Section 3110, Asset Retirement
Obligations which requires, for fiscal years beginning after January 1, 2004, 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 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 (See Notes 4 and 7). Stock Based Compensation Prior to January 1, 2004, the Company accounted for share options granted to employees and
directors using the intrinsic-value of the stock options. Under this method, compensation costs
were not recognized in the financial statements for stock options granted at market value but
rather disclosure was required, on a pro forma basis, of the impact on net income of using the fair
value at the stock option grant date. The Company recognizes compensation costs in its financial
statements for stock options granted to non-employees after January 1, 2002 based on the fair value
of the stock options at the date granted. The CICA approved Section 3870, Stock Based Compensation and Other Stock Based Payments which
requires, for fiscal years beginning on or after January 1, 2004, compensation costs to be
recognized in the financial statements using the fair value based method of accounting for all
stock options granted after January 1, 2002. Implementation of this change in accounting
policy requires retroactive application with the option of restating financial statements of prior
periods. 47




---



##### 



Accordingly, effective January 1, 2004, the Company changed its accounting policy, for Canadian
GAAP purposes, to recognize compensation costs using the fair value based method of accounting for
stock options granted to employees and directors after January 1, 2002. This change has been
adopted retroactively and the Company has elected to restate the financial statements of prior
periods (See Note 9). The Company uses the Black-Scholes option-pricing model for determining the
fair value of all stock options issued at grant date. Principles of Consolidation These consolidated financial statements include the accounts of Ivanhoe Energy Inc. and its
subsidiaries, all of which are wholly owned. The Company conducts most exploration, development and
production activities in its 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 to the U.S. Dollar at the exchange rate in effect 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 to the U.S. Dollar at rates
approximating exchange rates in effect at the time of the transactions. Exchange gains or losses
resulting from the period-end translation of monetary assets and liabilities denominated in foreign
currencies are reflected in the results of 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, note payable and long term debt approximates the carrying values due to
the immediate or short-term maturity of these financial instruments. Oil and Gas Properties Full Cost Accounting 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 lease and royalty interest acquisition costs, geological and
geophysical expenses, carrying charges for unproved properties, costs of drilling both successful
and unsuccessful wells, gathering and production facilities and equipment, financing,
administrative costs related to capital projects and asset retirement costs. 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 proved oil and gas properties. Proceeds from sales of oil and gas
properties are recorded as reductions in the carrying value of proved oil and gas properties,
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. Depletion The Companys share of costs for proved oil and gas properties accumulated within each cost center,
including a provision for future development costs, are depleted using the unit-of-production
method over the life of the Companys share of estimated remaining proved oil and gas reserves.
Significant development projects and expenditures on unproved properties are excluded from the
depletion calculation until evaluated. Natural gas reserves and production are converted to a
barrels of oil equivalent using a generally recognized industry standard in which six thousand
cubic feet of gas is equal to one barrel of oil. Barrels of oil equivalent 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. Impairment of Proved Oil and Gas Properties 48




---



##### 



Prior to January 2004, impairment of oil and gas properties was based on the amount by which a cost
centers carrying value exceeded its undiscounted future net cash flows from proved reserves using
period-end, non-escalated prices and costs, less an estimate for future general and administrative
expenses, financing costs and income taxes (ceiling test). Effective January 2004, Accounting Guideline 16 Oil and Gas Accounting   Full Cost requires
recognition and measurement processes to assess impairment of oil and gas properties. In the
recognition of an impairment, the carrying value of a cost center is compared to the undiscounted
future net cash flows of that cost centers proved reserves using estimates of future oil and gas
prices and costs plus the cost of unproved properties that have been excluded from the depletion
calculation. If the carrying value is greater than the value of the undiscounted future net cash
flows of the proved reserves plus the cost of unproved properties excluded from the depletion
calculation, then the amount of the cost centers potential impairment must be measured. A cost
centers impairment loss is measured by the amount its carrying value exceeds the discounted future
net cash flows of its proved and probable reserves using estimates of future oil and gas prices and
costs plus the cost of unproved properties that have been excluded from the depletion calculation
and which contain no probable reserves. The net cash flows of a cost centers proved and probable
reserves are discounted using a risk-free interest rate. The amount of the impairment loss is
recognized as a charge to the results of operations and a reduction in the net carrying amount of a
cost centers oil and gas properties. Asset Retirement Costs The Company measures the expected costs required to retire its producing U.S. oil and gas
properties at a fair value which approximates the cost a third party would incur in performing the
tasks necessary to abandon the field and restore the site. The fair value is recognized in the
financial statements at the present value of expected future cash outflows to satisfy the
obligation. The Company does not make such a provision for its oil and gas operations in China as
the remaining life of its Dagang production sharing contract is less than the remaining economic
life of the field and there is no obligation on the Companys part to contribute to the future cost
to abandon the field and restore the site. Asset retirement costs are being depleted using the unit of production method based on estimated
proved reserves and are included with depletion and depreciation expense. The accretion of the
liability for the asset retirement obligation is included with interest expense. Investments in GTL and EOR Projects The Company incurs various costs in the pursuit of GTL and EOR projects throughout the world. Such
costs incurred prior to signing a memorandum of understanding (MOU), or similar agreements, are
considered to be business development or project identification and are expensed as incurred. Upon
executing an MOU to determine the technical and commercial feasibility of a project, including
studies for the marketability for the projects products, the Company assumes the feasibility and
related costs incurred have potential future value, are probable of leading to a definitive
agreement for the exploitation of proved reserves and should be capitalized. If no definitive
agreement is reached, then the projects capitalized costs, which are deemed to have no future
value, are written down to the results of operations with a corresponding reduction in the
investments in GTL and EOR assets. 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. Oil and gas revenue represents the Companys share and is recorded net of royalty
payments to governments and other mineral interest owners. In China, the Company conducts operations jointly with the government of China in accordance with a
production-sharing contract. Under this contract, the Company pays both its share and the
governments share of operating and capital costs. The Company recovers the governments share of
these costs from future revenues or production over the life of the production-sharing contract.
The governments share of operating costs is recorded in operating expense when incurred and
capital costs are recorded in oil and gas properties and expensed to depletion and depreciation in
the year recovered. All recoveries of the governments share of costs are recorded as oil and gas
revenue in the year of recovery. Earnings or Loss Per Share Basic earnings or loss per share is calculated by dividing the net earnings or loss to common
shareholders by the weighted average number of common shares outstanding during the period.
Diluted earnings per share reflects the potential dilution that would occur if 49




---



##### 



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 (See Note 15). The Company does not report diluted loss per share
amounts, as the effect would be antidilutive to the common shareholders. 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 an employee share purchase plan (See Note 9). The Company accounts for equity-based
compensation under this plan using the fair value based method of accounting for all stock
options granted after January 1, 2002. Compensation costs are recognized in the results
of operations over the periods in which the stock options vest for all stock options granted based
on the fair value of the stock options at the date granted. The Company uses the Black-Scholes
option-pricing model for determining the fair value of stock options issued at grant date. As of
the date stock options are granted, the Company estimates a percentage of stock options issued to
employees and directors it expects to be forfeited. Compensation costs are not recognized for stock
option awards forfeited due to a failure to satisfy the service requirement for vesting.
Compensation costs are adjusted for the actual amount of forfeitures in the period in which the
stock options expire. Upon the exercise of stock options, share capital is credited for the fair value of the stock
options at the date granted with a charge to contributed surplus. Consideration paid upon the
exercise of the stock options is also credited to share capital. Compensation expenses are recognized when shares are issued from the stock bonus plan. The employee
share purchase portion of the plan has not yet been activated. Derivative Activities Prior to January 2004, the Company applied hedge accounting to all derivative instruments used to
manage price fluctuations in oil and natural gas prices. Effective January 1, 2004, the Company adopted CICA Accounting Guideline 13 (AcG 13), Hedging
Relationships. This guideline sets out the criteria that must be met in order to apply hedge
accounting for derivatives. The guideline provides detailed guidance on the identification,
designation, documentation and effectiveness of hedging relationships for purposes of applying
hedge accounting, and the discontinuance of hedge accounting. Gains and losses on derivative
instruments designated and qualifying as hedges under this guideline are recognized in earnings in
the same period as the related hedged item. Ineffective hedging relationships and hedges not
designated in a hedging relationship are carried at fair value in the statement of financial
position, and subsequent changes in their fair value are recorded in the results of operations. The
adoption of this accounting guideline did not have a material impact on the consolidated financial
statements (See Note 12). Impact of New and Pending Canadian GAAP Accounting Standards In January 2005, the CICA approved Section 1530 Comprehensive Income (S.1530), Section 3855
Financial Instruments  Recognition and Measurement (S.3855) and Section 3865 Hedges
(S.3865) to harmonize financial instrument and hedge accounting with U.S. GAAP and introduce the
concept of comprehensive income. S.1530 requires presentation of certain gains and losses outside
of net income, such as unrealized gains and losses related to hedges or other derivative
instruments. S.3855 establishes standards for recognizing and measuring financial assets and
financial liabilities and non-financial derivatives as required to be disclosed under Section 3861
Financial Instruments Disclosure and Presentation. S.3865 establishes standards for how and when
hedge accounting may be applied. The Company applies SFAS No. 133 Accounting for Derivative
Instruments and Hedging Activities for U.S. GAAP purposes and will implement S.3865 for Canadian
GAAP for hedging activities. These sections apply to interim and annual financial statements
relating to fiscal years beginning on or after October 1, 2006 and are not expected to have a
material impact on the Companys financial statements. In January 2005, the CICA approved Section 3251 Equity which establishes standards for the
presentation of equity and changes in equity during a reporting period. This section applies to
interim and annual financial statements relating to fiscal years beginning on or after October 1,
2006 and is not expected to have a material impact on the Companys financial statements. The following standards issued by the CICA do not impact the Company at this time: 50




---



##### 




    Section 3861, Financial Instruments Disclosure and Presentation, effective for
fiscal years beginning on or after November 1, 2004.
    Accounting Guideline 15, Consolidation of Variable Interest Entities, effective for
annual and interim periods beginning on or after November 1, 2004. 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 accounts receivable balances and revenues from significant customers: Accounts Receivable as
    
    
    Oil and Gas Revenues for the Yearat December 31,
    
    
    Ended December 31,2004
    
    
    2003
    
    
    2004
    
    
    2003
    
    
    2002U.S. CustomersA
    
    $
    542
    
    
    $
    407
    
    
    $
    6,140
    
    
    $
    4,392
    
    
    $
    2,916B
    
    
    398
    
    
    
    
    
    
    
    1,202
    
    
    
    
    
    
    
    C
    
    
    193
    
    
    
    175
    
    
    
    1,040
    
    
    
    986
    
    
    
    1,764D
    
    
    229
    
    
    
    
    
    
    
    441
    
    
    
    
    
    
    
    E
    
    
    71
    
    
    
    60
    
    
    
    300
    
    
    
    273
    
    
    
    390All others
    
    
    20
    
    
    
    15
    
    
    
    188
    
    
    
    65
    
    
    
    291,453
    
    
    
    657
    
    
    
    9,311
    
    
    
    5,716
    
    
    
    5,099China CustomerA
    
    
    1,982
    
    
    
    950
    
    
    
    8,484
    
    
    
    4,103
    
    
    
    3,2303,435
    
    
    
    1,607
    
    
    
    17,795
    
    
    
    9,819
    
    
    
    8,329Receivables from partners
    
    
    1,652
    
    
    
    947
    
    
    
    
    
    
    
    
    
    
    
    Other receivables
    
    
    290
    
    
    
    166
    
    
    
    
    
    
    
    
    
    
    
    $
    5,377
    
    
    $
    2,720
    
    
    $
    17,795
    
    
    $
    9,819
    
    
    $
    8,329
 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, 2004 and 2003 in the table above include $1.7 million and
$0.9 million, respectively, of costs billed to joint venture partners and advances to partners for
joint operations where the Company is not the operator. 4. OIL AND GAS PROPERTIES AND INVESTMENTS Capital assets categorized by segment are as follows: 51




---



##### 



As at December 31, 2004Oil and GasU.S.
    
    
    China
    
    
    GTL
    
    
    EOR
    
    
    TotalOil and Gas Properties:Proved
    
    $
    81,648
    
    
    $
    35,771
    
    
    $
    
    
    
    $
    
    
    
    $
    117,419Unproved
    
    
    20,447
    
    
    
    10,581
    
    
    
    
    
    
    
    
    
    
    
    31,028102,095
    
    
    
    46,352
    
    
    
    
    
    
    
    
    
    
    
    148,447Accumulated depletion
    
    
    (10,956
    )
    
    
    (6,663
    )
    
    
    
    
    
    
    
    
    
    
    (17,619
    )Accumulated provision for impairment
    
    
    (50,350
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (50,350
    )40,789
    
    
    
    39,689
    
    
    
    
    
    
    
    
    
    
    
    80,478GTL and EOR Investments:GTL master license
    
    
    
    
    
    
    
    
    
    
    10,000
    
    
    
    
    
    
    
    10,000Feasibility studies and other deferred costs
    
    
    
    
    
    
    
    
    
    
    3,793
    
    
    
    2,091
    
    
    
    5,884
    
    
    
    
    
    
    
    13,793
    
    
    
    2,091
    
    
    
    15,884Furniture and equipment
    
    
    417
    
    
    
    84
    
    
    
    
    
    
    
    11
    
    
    
    512Accumulated depreciation
    
    
    (300
    )
    
    
    (22
    )
    
    
    
    
    
    
    (1
    )
    
    
    (323
    )117
    
    
    
    62
    
    
    
    
    
    
    
    10
    
    
    
    189$
    40,906
    
    
    $
    39,751
    
    
    $
    13,793
    
    
    $
    2,101
    
    
    $
    96,551
 As at December 31, 2003Oil and GasU.S.
    
    
    China
    
    
    GTL
    
    
    EOR
    
    
    TotalOil and Gas Properties:Proved
    
    $
    57,545
    
    
    $
    29,201
    
    
    $
    
    
    
    $
    
    
    
    $
    86,746Unproved
    
    
    27,534
    
    
    
    3,639
    
    
    
    
    
    
    
    
    
    
    
    31,17385,079
    
    
    
    32,840
    
    
    
    
    
    
    
    
    
    
    
    117,919Accumulated depletion
    
    
    (6,442
    )
    
    
    (3,804
    )
    
    
    
    
    
    
    
    
    
    
    (10,246
    )Accumulated provision for impairment
    
    
    (34,000
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (34,000
    )44,637
    
    
    
    29,036
    
    
    
    
    
    
    
    
    
    
    
    73,673GTL and EOR Investments:GTL master license
    
    
    
    
    
    
    
    
    
    
    10,000
    
    
    
    
    
    
    
    10,000Feasibility studies and other deferred costs
    
    
    
    
    
    
    
    
    
    
    4,072
    
    
    
    
    
    
    
    4,072
    
    
    
    
    
    
    
    14,072
    
    
    
    
    
    
    
    14,072Furniture and equipment
    
    
    433
    
    
    
    31
    
    
    
    
    
    
    
    
    
    
    
    464Accumulated depreciation
    
    
    (253
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (253
    )180
    
    
    
    31
    
    
    
    
    
    
    
    
    
    
    
    211$
    44,817
    
    
    $
    29,067
    
    
    $
    14,072
    
    
    $
    
    
    
    $
    87,956
 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 years ended December 31, 2004
and 2003, $0.2 million and $0.1 million, respectively, of future asset retirement costs were
capitalized (See Note 2). Costs as at December 31, 2004 and 2003 of $31.0 million and $31.2 million, respectively, related to
unproved oil and gas properties were excluded from the depletable cost centers. For the years ended December 31, 2004 and 2003, general and administrative expenses related
directly to oil and gas acquisition, exploration and development activities, and investments in GTL
and EOR projects of $3.8 million and $1.8 million, respectively, were capitalized. United States The Companys U.S. oil and gas operations are primarily conducted through joint operations with
other oil and gas companies in California, Texas and Wyoming. Costs capitalized in the U.S. cost
center under the full cost method of accounting are as follows: 52




---



##### 



As at December 31,2004
    
    
    2003California
    
    $
    74,155
    
    
    $
    59,386Texas
    
    
    24,239
    
    
    
    24,046Wyoming
    
    
    2,054
    
    
    
    Other
    
    
    1,647
    
    
    
    1,647$
    102,095
    
    
    $
    85,079
 Included in the carrying value for the Companys California properties are $9.2 million of
costs incurred to acquire overriding royalties in various exploration prospects and producing
properties. During 2004, the Company sold its working interest in one of its California producing properties
for $0.5 million. The sale proceeds were credited to the U.S. cost center as the sale did not
significantly alter the depletion rate for the U.S. cost center. The provision for impairment calculated for U.S. oil and gas properties was $16.3 million and $20.0
million for 2004 and 2003, respectively. No provision for impairment of U.S. oil and gas properties
was required for 2002 (See Note 13). China The Company currently holds a production-sharing contract with China National Petroleum Corporation
(CNPC) to develop existing oil properties in the Dagang region. In January 2004, the Company
signed farm-out and joint operating agreements with Richfirst Holdings Limited (Richfirst), a
wholly-owned subsidiary of China International Trust and Development Corporation, to acquire a
forty percent working interest in the Dagang field for an up-front payment of $20.0 million
following receipt of Chinese regulatory approvals in June 2004. Richfirst will have the right to
exchange its working interest in the Dagang field for common shares in the Companys wholly owned
subsidiary, Sunwing Energy Ltd. (Sunwing), should the Company obtain a public listing for
Sunwing, or for the Companys common shares. Richfirsts right to exchange its working interest for
the Companys common shares expires in December 2005. The Company and Richfirst incur 100% of the
costs to earn 82% of the production, before recovery of costs incurred, reverting to a 49% share
post recovery. The carrying value of the Companys China oil and gas properties was reduced by
$13.5 million for the amount of the proceeds associated with the farm-in of Richfirst to the Dagang
field. The reduction in the carrying value did not significantly alter the depletion rate of the
China cost center. The Company held a production-sharing contract to develop existing oil fields in the Daqing region
until the sale of its interest in the field in January 2002. The Company retains an overriding
royalty on future production. The Company also holds a production-sharing contract with CNPC in a contract area, known as the
Zitong block located in the northwestern portion of the Sichuan Basin. Under the terms of the
production-sharing 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. CNPC has the option, at the end of appraisal activities, to participate with the
Company in any proposed field developments, with up to a 51% working interest. Costs capitalized in the China cost center under the full cost method of accounting are as follows: As at December 31,2004
    
    
    2003Dagang Project
    
    $
    32,061
    
    
    $
    25,357Sichuan Basin
    
    
    10,581
    
    
    
    3,639Daqing Project
    
    
    3,710
    
    
    
    3,844$
    46,352
    
    
    $
    32,840
 Gas-to-Liquids The Company owns a master license from Syntroleum Corporation (Syntroleum) permitting the Company
to use their proprietary GTL process in an unlimited number of projects around the world. The
Syntroleum GTL 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. 53




---



##### 



Since 2000, the Company has undertaken detailed project feasibility studies for the construction,
operation and cost of GTL plants in Qatar, Egypt, Oman and Bolivia. In addition, the Company has
conducted marketing, commercialization and transportation feasibility studies. Marketing studies
were conducted for both European and the Asia Pacific regions for GTL diesel and specialty fuels. For the years ended December 31, 2004, 2003 and 2002, the Company wrote down $0.3 million, $3.3
million and $2.4 million, respectively, of capitalized negotiation and feasibility costs associated
with our GTL projects which did not result in definitive agreements. Other costs associated with
feasibility studies and related costs, which are deemed to have future value, 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. Enhanced Oil Recovery In the fourth quarter of 2004, the Company signed memoranda of understanding with the Ministry of
Oil of the Government of Iraq to study and evaluate the shallow Qaiyarah oil field in Iraq and with
Ecopetrol S.A., a public company wholly owned by the Republic of Colombia, for a study of the heavy
crude oil from the Castilla and Chichimene oil fields in Colombia. The $2.1 million of EOR
investments, as at December 31, 2004, include feasibility studies and related costs associated with
these memoranda of understanding and other project activities in these regions. 5. LONG TERM ASSETS During 2004, the Company acquired a 15% equity interest in Ensyn Petroleum International Ltd.
(EPIL) and exclusive rights to use the proprietary Ensyn RTPTM Technology in key
international markets in China, Mongolia, Iraq, Oman and all countries in South America except
Venezuela. In these countries, the Companys rights were to be exclusive for an initial term of
five years until January 2009, subject to extension if and when commercial plants are constructed.
For each project the Company develops using the Ensyn RTPTMTechnology in its exclusive
territories, Ensyn could elect to receive an equity participation in the project for the same
proportionate cost the Company paid. The participation that may be obtained by Ensyn could be no
more than 10%, except for each such project that the Company develops in South America, other than
in Peru, where Ensyn could elect to receive an equity interest equal to 25% of the Companys
interest. Ensyns equity position would offset and eliminate the payment of license fees for use of
the Ensyn RTPTMTechnology in the project. In December 2004, the Company and Ensyn Group Inc. (Ensyn), the parent company of EPIL, announced
the signing of a merger agreement (Merger Agreement) in which Ensyn will be merged with the
Company (Merger) and Ensyn will become a wholly owned subsidiary of the Company. With this
Merger, the Company will gain full ownership of EPIL and its advanced upgrading technology for the
development of heavy oil reserves around the world. Ensyn will spin-off its existing biomass
processing business to its shareholders prior to the closing of this transaction. Under the Merger Agreement, the Company will acquire all of the outstanding shares of Ensyn and all
of the unissued shares of Ensyn common stock issuable upon the future exercise of any purchase
warrants that remain unexercised when the Merger takes effect in exchange for $10 million in cash
and the issuance of Company common shares. The number of Company common shares to be issued will be
based on the weighted, 10-day average of the Companys closing share price on the NASDAQ SmallCap
market prior to the approval of the transaction by Ensyn shareholders. A minimum of 30 million
Company common shares will be issued (See Note 17). The Boards of Directors of both Ivanhoe and Ensyn have approved the Merger. The Merger will require
the approval of Ensyn shareholders and may require the approval of the Companys shareholders,
depending on the number of Company common shares required to be issued. The Merger is also subject
to applicable regulatory approvals and other closing conditions customary in transactions of this
nature. As at December 31, 2004, the costs to acquire the 15% equity interest in EPIL of $3.0 million plus
$2.5 million of costs incurred by the Company associated with the Merger are included in long term
assets. 6. NOTES AND ADVANCE PAYABLE In February 2003, the Company obtained a bank facility for up to $5.0 million to develop the
southern expansion of its South Midway field. The note is repayable over three years starting
August 2004 with interest at 0.5% above the banks prime rate or 3.0% over the
London Inter-Bank Offered rate (LIBOR), at the option of the Company. The note is secured by all
the Companys rights and interests in the South Midway properties. The note balance, as at December
31, 2004 and 2003, was $4.3 million and $1.0 million, respectively, with a six-month fixed LIBOR
rate of 5.25% as at December 31, 2004. The scheduled maturities of the bank note payable as at December 31, 2004 were as follows: 54




---



##### 



2005
    
    $
    1,6672006
    
    
    1,6672007
    
    
    9724,306Less: current portion
    
    
    1,667$
    2,639
 In March 2004, the Company received a $10.0 million advance as part of the $20.0 million
up-front payment due from Richfirst for their farm-in to the Dagang field (See Note 4). Upon
finalization of the farm-in agreement in June 2004, Richfirst elected to apply $10.0 million of the
up-front payment due to the Company against the advance. The Company borrowed $1.25 million from a related party at U.S. prime plus 3%. The unsecured loan
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. The Company has a stand-by loan facility for $6.0 million payable with interest at 8% per annum
upon the earliest of i.) five days following receipt of proceeds from a private placement or public
offering of Company common shares ii.) ninety days following written demand for repayment from
lender or iii.) August 23, 2005. As at December 31, 2004, the Company had not made a drawdown under
the loan (See Note 18). 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 as at December 31, 2004 was
estimated at $1.4 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 from 5%
to 7%. Implementation of the policy resulted in an additional provision for asset retirement of
$0.2 million. For the years ended December 31, 2004 and 2003, $0.2 million and $0.1 million,
respectively, were added to the carrying amount of the asset retirement obligations related to the
restoration and abandonment of the Companys U.S. oil and gas properties as follows: Balance as at December 31, 2002
    
    $
    243Cumulative effect of change in accounting policy
    
    
    155Accretion of liability
    
    
    31Additions
    
    
    92Balance as at December 31, 2003
    
    
    521Accretion of liability
    
    
    48Additions
    
    
    180Balance as at December 31, 2004
    
    $
    749
 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. Private Placements and Share Purchase Warrants Under a private placement in 2002, the Company issued 5.0 million common shares at $2.00, for net
proceeds of $10.0 million. In 2004 and 2003, the Company closed six special warrant financings for net proceeds of $20.4
million and $24.1 million, respectively, to advance its worldwide exploration and production, EOR
and GTL activities, to pay down or restructure certain business indebtedness and for general
working capital purposes. The financings consisted of 17,951,826 special warrants from $1.00 to
$4.00 per special warrant. Each special warrant entitles the holder to acquire one common share and
one common-share purchase warrant, at no additional cost. The net proceeds from the special warrant
financings have been apportioned to the common shares. No amounts have been apportioned to the
purchase warrants. 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: 55




---



##### 



Year of
    
    Price per
    
    
    Number of
    
    
    Remaining
    
    
    Number of
    
    
    First Anniversary
    
    
    Second AnniversarySpecial
    
    Special
    
    
    Purchase
    
    
    Number of
    
    
    Equivalent
    
    
    
    
    
    
    Price per
    
    
    
    
    
    
    Price perWarrant
    
    Warrant
    
    
    Warrants
    
    
    Purchase
    
    
    Common
    
    
    
    
    
    
    Share
    
    
    
    
    
    
    ShareFinancing
    
    (U.S.$)
    
    
    Issued
    
    
    Warrants
    
    
    Shares
    
    
    Date
    
    (U.S.$)
    
    
    Date
    
    (U.S.$)(thousands)2003
    
    $
    1.00
    
    
    
    3,000
    
    
    
    3,000
    
    
    
    1,500
    
    
    
    
    
    
    
    
    
    
    July 3, 2005
    
    $
    1.102003
    
    $
    1.00
    
    
    
    3,000
    
    
    
    3,000
    
    
    
    1,500
    
    
    
    
    
    
    
    
    
    
    August 18, 2005
    
    $
    1.102003
    
    $
    1.70
    
    
    
    3,529
    
    
    
    3,029
    
    
    
    1,515
    
    
    
    
    
    
    
    
    
    
    August 21, 2005
    
    $
    1.872003
    
    $
    4.00
    
    
    
    1,250
    
    
    
    1,250
    
    
    
    1,250
    
    
    
    
    
    
    
    
    
    
    October 31, 2005
    
    $
    4.302004
    
    $
    2.90
    
    
    
    5,449
    
    
    
    5,449
    
    
    
    2,725
    
    
    February 18, 2005
    
    $
    3.00
    
    
    February 18, 2006
    
    $
    3.202004
    
    $
    2.90
    
    
    
    1,724
    
    
    
    1,724
    
    
    
    862
    
    
    March 5, 2005
    
    $
    3.00
    
    
    March 5, 2006
    
    $
    3.2017,952
    
    
    
    17,452
    
    
    
    9,352
 In November 2003, 500 thousand purchase warrants for $1.70 per share were exercised for the
purchase of 250 thousand common shares. Convertible Debenture In June 2003, the $1.0 million unsecured convertible debenture was converted 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 . Share Purchase Loans In 1999 and 2001, the Company loaned $0.4 million to an employee and two directors to facilitate
their exercise of stock options and warrants to purchase 165 thousand 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
thousand 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. 9. STOCK BASED COMPENSATION The Company has an Employees and Directors Equity Incentive Plan under which it can grant stock
options to directors 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. Stock options granted prior to March 1, 1999 vested over a two-year period
and expire ten years from date of issue. Stock options granted after March 1, 1999 vest over four
years and expire five to ten 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, 2004
    
    
    December 31, 2003
    
    
    December 31, 2002Weighted-
    
    
    
    
    
    
    Weighted-
    
    
    
    
    
    
    Weighted-Number
    
    
    Average
    
    
    Number
    
    
    Average
    
    
    Number
    
    
    Averageof Stock
    
    
    Exercise
    
    
    of Stock
    
    
    Exercise
    
    
    of Stock
    
    
    ExerciseOptions
    
    
    Price
    
    
    Options
    
    
    Price
    
    
    Options
    
    
    Price(thousands)
    
    
    (Cdn.$)
    
    
    (thousands)
    
    
    (Cdn.$)
    
    
    (thousands)
    
    
    (Cdn.$)Outstanding at beginning
of year
    
    
    8,949
    
    
    $
    2.64
    
    
    
    10,265
    
    
    $
    2.69
    
    
    
    8,635
    
    
    $
    2.66Granted
    
    
    608
    
    
    $
    2.52
    
    
    
    840
    
    
    $
    4.95
    
    
    
    2,095
    
    
    $
    2.86Exercised
    
    
    (975
    )
    
    $
    2.43
    
    
    
    (1,363
    )
    
    $
    3.39
    
    
    
    (164
    )
    
    $
    1.57Cancelled/forfeited
    
    
    (336
    )
    
    $
    2.96
    
    
    
    (793
    )
    
    $
    4.42
    
    
    
    (301
    )
    
    $
    3.48Outstanding at end of year
    
    
    8,246
    
    
    $
    2.65
    
    
    
    8,949
    
    
    $
    2.64
    
    
    
    10,265
    
    
    $
    2.69Options exercisable at
end of year
    
    
    6,698
    
    
    $
    2.44
    
    
    
    6,974
    
    
    $
    2.20
    
    
    
    7,122
    
    
    $
    2.13
 56




---



##### 



The Company accounts for all stock options granted using the fair value based method of
accounting. This method was adopted retroactively effective January 1, 2004 for stock options
granted to employees and directors after January 1, 2002. Under this method, compensation costs
are recognized in the financial statements over the stock options vesting period using an
option-pricing model for determining the fair value of the stock options at the grant date. The
Company estimates a 20% forfeiture rate for stock options for purposes of calculating the fair
value on the date stock options are granted. Revisions in forfeiture estimates are reflected as a
change in accounting estimate in the period in which the revision occurs. The effect of the accounting change on the net loss, as previously reported, for the years ended
December 31, 2003 and 2002, was an increase of $0.5 million and $0.3 million, respectively. There
is negligible effect on the net loss per share for the periods as previously reported. The
accumulated deficit, as previously reported, as at the beginning of each of the years ended
December 31, 2004 and 2003 has increased $0.8 million and $0.3 million, respectively, to reflect
the retroactive adoption of the fair value based method of accounting for stock options granted to
employees and directors after January 1, 2002. Additionally, 0.3 million stock options granted to
employees and directors after January 1, 2002 were exercised during 2003 resulting in a $0.3
million increase in share capital as at December 31, 2003, as previously reported, with a
corresponding reduction in contributed surplus. For the year ended December 31, 2004, the Company
expensed $1.3 million for stock based compensation, which is included in the results of operations. The foregoing is calculated in accordance with Black-Scholes options pricing model. The weighted
average grant-date fair value of stock options granted during 2004, 2003 and 2002 was Cdn.$1.95,
Cdn.$3.99 and Cdn.$1.65, respectively. The fair value of the stock options granted is estimated
with the following weighted average assumptions for the years presented: 2004
    
    
    2003
    
    
    2002Assumptions used:Risk-free interest rate
    
    
    4.0
    %
    
    
    4.1
    %
    
    
    4.4
    %Dividend yield
    
    
    0.0
    %
    
    
    0.0
    %
    
    
    0.0
    %Volatility factor
    
    
    107.6
    %
    
    
    99.4
    %
    
    
    72.0
    %Expected life (years)
    
    
    4.0
    
    
    
    4.0
    
    
    
    4.0
 The following table summarizes information respecting stock options outstanding and
exercisable as at December 31, 2004: Stock Options Outstanding
    
    Stock Options ExercisableWeighted-AverageRange of
    
    Number
    
    Remaining
    
    Weighted-Average
    
    Number
    
    Weighted-AverageExercise Prices
    
    Outstanding
    
    Contractual Life
    
    Exercise Price
    
    Exercisable
    
    Exercise Price(Cdn.$)
    
    (thousands)
    
    (Years)
    
    (Cdn.$)
    
    (thousands)
    
    (Cdn.$)$0.50 to $2.00
    
    
    4,347
    
    
    
    3.7
    
    
    $
    0.65
    
    
    
    4,031
    
    
    $
    0.56$2.60 to $3.60
    
    
    1,651
    
    
    
    3.0
    
    
    $
    3.09
    
    
    
    860
    
    
    $
    3.14$5.35 to $7.60
    
    
    2,248
    
    
    
    1.7
    
    
    $
    6.17
    
    
    
    1,807
    
    
    $
    6.28$0.50 to $7.60
    
    
    8,246
    
    
    
    3.0
    
    
    $
    2.65
    
    
    
    6,698
    
    
    $
    2.44
 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 were $0.2 million for each of the years ended December 31, 2004 and 2003 and
$0.1 million for the year ended December 31, 2002. 11. SEGMENT INFORMATION The Company has three reportable business segments: Oil and Gas, GTL and EOR. Oil and Gas The Company explores for, develops and produces crude oil and natural gas in the U.S. and in China.
In the U.S., the Companys exploration, development and production activities are primarily
conducted in California and Texas. In China, the Companys development and production activities
are conducted at the Dagang oil field located in Hebei Province and exploration activities in the
Zitong block located in Sichuan Province. GTL The Company holds a master license from Syntroleum to use its proprietary GTL technology to convert
natural gas into synthetic 57




---



##### 



fuels. The master license allows the Company to use Syntroleums
proprietary process in an unlimited number of GTL projects throughout the world to convert natural
gas into an unlimited volume of ultra clean transportation fuels and other synthetic petroleum
products. The Company does not currently own or operate any GTL projects but has entered into
agreements to study the feasibility of GTL plants in Egypt and Bolivia. EOR The Company seeks projects requiring relatively low initial capital outlays to which it can apply
innovative technology and enhanced recovery techniques in developing them. The Company has
exclusive rights to use the proprietary Ensyn RTPTM Technology in key international
markets in China, Mongolia, Iraq, Oman and all countries in South America except Venezuela. In
2004, the Company entered into memoranda of understanding to evaluate the potential response of
specific fields in Iraq and Colombia to the latest in EOR techniques and to determine the value
that could be added to these fields using the Ensyn RTPTM Technology. The Company maintains a corporate office in Canada with its operational office in the U.S. For this
note, any amounts for the corporate office in Canada are included in Corporate.The accounting
policies of the segments are the same as those disclosed in Note 2. Year ended December 31, 2004Oil and GasU.S.
    
    
    China
    
    
    GTL
    
    
    EOR
    
    
    Corporate
    
    
    TotalOil and gas revenue
    
    $
    9,311
    
    
    $
    8,484
    
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    17,795Interest income
    
    
    10
    
    
    
    16
    
    
    
    
    
    
    
    
    
    
    
    176
    
    
    
    2029,321
    
    
    
    8,500
    
    
    
    
    
    
    
    
    
    
    
    176
    
    
    
    17,997Operating costs
    
    
    3,159
    
    
    
    1,914
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    5,073General and administrative
    
    
    990
    
    
    
    960
    
    
    
    1,471
    
    
    
    442
    
    
    
    5,325
    
    
    
    9,188Depletion and depreciation
    
    
    4,594
    
    
    
    2,864
    
    
    
    16
    
    
    
    4
    
    
    
    4
    
    
    
    7,482Interest expense
    
    
    195
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    184
    
    
    
    379Write-downs and provision for impairment
    
    
    16,350
    
    
    
    
    
    
    
    250
    
    
    
    
    
    
    
    
    
    
    
    16,60025,288
    
    
    
    5,738
    
    
    
    1,737
    
    
    
    446
    
    
    
    5,513
    
    
    
    38,722Net (Income) Loss
    
    $
    15,967
    
    
    $
    (2,762
    )
    
    $
    1,737
    
    
    $
    446
    
    
    $
    5,337
    
    
    $
    20,725Capital Investments
    
    $
    17,428
    
    
    $
    26,965
    
    
    $
    95
    
    
    $
    1,966
    
    
    $
    
    
    
    $
    46,454Identifiable Assets (As at December 31, 2004)
    
    $
    49,465
    
    
    $
    44,960
    
    
    $
    13,867
    
    
    $
    2,441
    
    
    $
    7,753
    
    
    $
    118,486
 Year ended December 31, 2003 (as restated, see Notes 2 and 9)Oil and GasU.S.
    
    
    China
    
    
    GTL
    
    
    EOR
    
    
    Corporate
    
    
    TotalOil and gas revenue
    
    $
    5,466
    
    
    $
    4,103
    
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    9,569Interest income
    
    
    19
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    71
    
    
    
    905,485
    
    
    
    4,103
    
    
    
    
    
    
    
    
    
    
    
    71
    
    
    
    9,659Operating costs
    
    
    2,313
    
    
    
    1,980
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    4,293General and administrative
    
    
    2,109
    
    
    
    1,176
    
    
    
    1,331
    
    
    
    
    
    
    
    3,595
    
    
    
    8,211Depletion and depreciation
    
    
    2,321
    
    
    
    1,484
    
    
    
    20
    
    
    
    
    
    
    
    4
    
    
    
    3,829Interest expense
    
    
    115
    
    
    
    27
    
    
    
    
    
    
    
    
    
    
    
    42
    
    
    
    184Write-down and provision for impairment
    
    
    20,000
    
    
    
    
    
    
    
    3,321
    
    
    
    
    
    
    
    
    
    
    
    23,32126,858
    
    
    
    4,667
    
    
    
    4,672
    
    
    
    
    
    
    
    3,641
    
    
    
    39,838Net Loss
    
    $
    21,373
    
    
    $
    564
    
    
    $
    4,672
    
    
    $
    
    
    
    $
    3,570
    
    
    $
    30,179Capital Investments
    
    $
    8,386
    
    
    $
    6,213
    
    
    $
    792
    
    
    $
    
    
    
    $
    
    
    
    $
    15,391Identifiable Assets (As at December 31, 2003)
    
    $
    47,650
    
    
    $
    30,766
    
    
    $
    14,181
    
    
    $
    
    
    
    $
    13,977
    
    
    $
    106,574
 58




---



##### 



Year ended December 31, 2002 (as restated, see Notes 2 and 9)Oil and GasU.S.
    
    
    China
    
    
    GTL
    
    
    EOR
    
    
    Corporate
    
    
    TotalOil and gas revenue
    
    $
    5,099
    
    
    $
    3,230
    
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    8,329Interest income
    
    
    6
    
    
    
    1
    
    
    
    
    
    
    
    
    
    
    
    101
    
    
    
    1085,105
    
    
    
    3,231
    
    
    
    
    
    
    
    
    
    
    
    101
    
    
    
    8,437Operating costs
    
    
    2,351
    
    
    
    1,490
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    3,841General and administrative
    
    
    1,178
    
    
    
    905
    
    
    
    675
    
    
    
    
    
    
    
    3,197
    
    
    
    5,955Depletion and depreciation
    
    
    2,090
    
    
    
    1,206
    
    
    
    13
    
    
    
    
    
    
    
    3
    
    
    
    3,312Interest expense
    
    
    2
    
    
    
    21
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    23Write-down and provision for impairment
    
    
    
    
    
    
    
    
    
    
    2,436
    
    
    
    
    
    
    
    
    
    
    
    2,4365,621
    
    
    
    3,622
    
    
    
    3,124
    
    
    
    
    
    
    
    3,200
    
    
    
    15,567Net Loss
    
    $
    516
    
    
    $
    391
    
    
    $
    3,124
    
    
    $
    
    
    
    $
    3,099
    
    
    $
    7,130Capital Investments
    
    $
    13,305
    
    
    $
    3,626
    
    
    $
    1,897
    
    
    $
    
    
    
    $
    
    
    
    $
    18,828Identifiable Assets (As at December 31, 2002)
    
    $
    62,922
    
    
    $
    25,620
    
    
    $
    17,111
    
    
    $
    
    
    
    $
    1,435
    
    
    $
    107,088
 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 were recognized in the results of operations as
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. For the year ended December 31, 2004 the Company had no hedging activity. There were no hedge
contracts outstanding as at December 31, 2004 and 2003. 13. PROVISION FOR IMPAIRMENT The Company impaired its U.S. oil and gas properties $16.3 million in 2004 due to the evaluation of
a number of its unproved properties, primarily in California, plus the impairment of its producing
fields at Knights Landing, Citrus and the southern expansion at South Midway as costs incurred to
add new reserves exceeded the expected future cash flows from those properties. Prices used in
calculating the expected future cash flows were based on the following benchmark prices adjusted
for gravity, transportation and other factors as required by sales agreements: As at December 31. 2004West TexasIntermediate
    
    
    Henry Hub(per Bbl)
    
    
    (per Mcf)2005
    
    $
    42.00
    
    
    $
    6.202006
    
    $
    40.00
    
    
    $
    6.002007
    
    $
    38.00
    
    
    $
    5.752008
    
    $
    36.00
    
    
    $
    5.502009
    
    $
    34.00
    
    
    $
    5.502010 to 2015
    
    $
    33.00 to $34.50
    
    
    $
    5.50 to $5.75Thereafter
    
    2% per year
    
    2% per year
 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 properties 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 Basin 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 properties. Prices used in calculating the expected future 59




---



##### 



cash flows were based on the following benchmark prices adjusted for gravity, transportation and
other factors as required by sales agreements: As at December 31, 2003West TexasIntermediate
    
    
    Henry Hub(per Bbl)
    
    
    (per Mcf)2004
    
    $
    29.00
    
    
    $
    5.102005
    
    $
    26.00
    
    
    $
    4.502006
    
    $
    25.00
    
    
    $
    4.352007
    
    $
    25.00
    
    
    $
    4.352008
    
    $
    25.00
    
    
    $
    4.352009 to 2014
    
    $
    25.00
    
    
    $
    4.35Thereafter
    
    1.5% per year
    
    1.5% per year
 14. INCOME TAXES The Company and its subsidiaries are required to individually file tax returns in each of the
jurisdictions in which they operate. The provision for income taxes differs from the amount
computed by applying the statutory income tax rate to the net losses before income taxes. The
statutory rate as at December 31, 2004 was 33.6% and 43.2% as at December 31, 2003 and 2002. The
sources and tax effects for the differences were as follows: As at December 31,2004
    
    
    2003
    
    
    2002Tax benefit computed at the combined Canadian federal and
provincial statutory income tax rates
    
    $
    (6,968
    )
    
    $
    (12,832
    )
    
    $
    (2,946
    )Effect of change in effected income tax rates on future tax assets
    
    
    (488
    )
    
    
    
    
    
    
    Foreign net losses affected at lower income tax rates
    
    
    (246
    )
    
    
    3,251
    
    
    
    1,411Expiry of tax loss carry-forwards
    
    
    977
    
    
    
    569
    
    
    
    125Effect of change in foreign exchange rates
    
    
    (3,433
    )
    
    
    (522
    )
    
    
    Stock-based compensation not deductible for income tax purposes
    
    
    375
    
    
    
    
    
    
    
    Tax credit carry-forward
    
    
    (1,094
    )
    
    
    
    
    
    
    Change in prior year estimate of tax loss carry-forwards
    
    
    1,756
    
    
    
    (239
    )
    
    
    (3,090
    )Permanent differences related to U.S. royalty interests acquired
    
    
    1,250
    
    
    
    710
    
    
    
    Other
    
    
    (5
    )
    
    
    170
    
    
    
    (25
    )(7,876
    )
    
    
    (8,893
    )
    
    
    (4,525
    )Valuation allowance
    
    
    7,876
    
    
    
    8,893
    
    
    
    4,525$
    
    
    
    $
    
    
    
    $
    
 Significant components of the Companys future net income tax assets as at December 31 were as
follows: 2004
    
    
    2003Future Income Tax
    
    
    Future Income TaxAssets
    
    
    Liabilities
    
    
    Assets
    
    
    LiabilitiesOil and gas properties and investments
    
    $
    
    
    
    $
    (11,560
    )
    
    $
    
    
    
    $
    (8,393
    )Tax loss carry-forwards
    
    
    58,842
    
    
    
    
    
    
    
    48,893
    
    
    
    Tax credit carry-forward
    
    
    1,094
    
    
    
    
    
    
    
    
    
    
    
    Valuation allowance
    
    
    (48,376
    )
    
    
    
    
    
    
    (40,500
    )
    
    
    $
    11,560
    
    
    $
    (11,560
    )
    
    $
    8,393
    
    
    $
    (8,393
    )
 Due to the uncertainty of utilizing these net income tax assets, the Company has made a
valuation allowance of an equal amount against the potential recoverable amounts. The tax loss carry-forwards in Canada are Cdn. $43.2 million and in the U.S. $73.5 million. The tax
loss carry-forwards in Canada expire between 2005 and 2011 and in the U.S. between 2018 and 2024.
In China, the Company has available for carry-forward against future Chinese income $49.2 million
of cost basis. The loss of approximately Cdn. $55.3 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 and is not included in the future income tax assets
above. 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 60




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##### 



have included the following weighted average items: Year ended December 31,(thousands of shares)2004
    
    
    2003
    
    
    2002Warrants
    
    
    2,107
    
    
    
    556
    
    
    
    Convertible debenture
    
    
    
    
    
    
    499
    
    
    
    1,299Stock options
    
    
    3,796
    
    
    
    3,535
    
    
    
    2,9865,903
    
    
    
    4,590
    
    
    
    4,285
 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,(thousands of shares)2004
    
    
    2003
    
    
    2002Warrants
    
    
    4,082
    
    
    
    140
    
    
    
    Convertible debenture
    
    
    
    
    
    
    306
    
    
    
    Stock options
    
    
    3,669
    
    
    
    3,802
    
    
    
    5,3597,751
    
    
    
    4,248
    
    
    
    5,359
 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 each of the years ended December 31, 2004
and 2003 and $1.2 million for the year ended December 31, 2002. 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 $0.7 million for the year ended December 31, 2004 and $0.4
million for each of the years ended December 31, 2003 and 2002. As at December 31, 2004 and 2003,
amounts included in accounts payable under these arrangements were $0.1 million. 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 6). 17. COMMITMENTS AND CONTINGENCIES Zitong Exploration Commitment 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 CNPC within 30
days, a cash equivalent of the deficiency in the work program. The remaining cost of the minimum
exploration program was estimated to be at least $12.4 million as at December 31, 2004. Northwest Lost Hills Abandonment Contingency 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. Ensyn Acquisition Under the Merger Agreement, the Company will pay $10 million in cash and issue Company common
shares to acquire all the issued and outstanding common shares of Ensyn and all of the unissued
shares of Ensyn common stock issuable upon the future exercise of any purchase warrants that remain
unexercised when the Merger takes effect. The number of Company common shares to be issued will be
the greater of (i) 30 million or (ii) the quotient obtained by dividing $75 million by the weighted
average of the closing prices of the Company common shares on the NASDAQ SmallCap Market over a
period of ten consecutive trading days determined five 61




---



##### 



business days prior to the meeting at which
Ensyns shareholders will be asked to approve the Merger. If the number of Company common shares
to be issued exceeds 42.4 million Company common shares, then the Company shall be required to hold
a meeting at which its shareholders will be asked to approve the issuance of the Company common
shares. The Company may be required to pay Ensyn a termination fee of $2.75 million if it is
required to hold a shareholders meeting to approve the issuance of the Company common shares and
decides not to or holds a required shareholders meeting and the Companys shareholders do not
approve such share issuance. Additionally, the Merger Agreement provides that the Company may be
obligated, under certain circumstances, to reimburse up to $1.0 million of Ensyns expenses related
to the Merger. Other Commitments The Company may provide indemnifications, in the course of normal operations, that are often
standard contractual terms to counterparties in certain transactions such as purchase and sale
agreements. The terms of these indemnifications will vary based upon the contract, the nature of
which prevents the Company from making a reasonable estimate of the maximum potential amounts that
may be required to be paid. The Companys management is of the opinion that any resulting
settlements relating to potential litigation matters or indemnifications would not materially
affect the financial position of the Company. Lease Commitments For the years ended December 31, 2004, 2003 and 2002, the Company expended $0.5 million, $0.5
million and $0.6 million, respectively, on operating leases relating to the rental of office space,
which expire between April 2005 and March 2010. Such leases frequently provide for renewal options
and require the Company to pay for utilities, taxes, insurance and maintenance expenses. As at
December 31, 2004, future net minimum lease payments for operating leases (excluding oil and gas
and other mineral leases) were the following: 2005
    
    $
    6162006
    
    
    5432007
    
    
    3422008
    
    
    2872009
    
    
    287Thereafter
    
    
    48$
    2,123
 18. SUBSEQUENT EVENTS In February 2005, the Company borrowed $6.0 million of the stand-by loan facility and amended the
loan agreement to provide the lender the right to convert, at the lenders election, unpaid
principal and interest during the loan term to the Companys common shares at $2.25 per share (See
Note 6). 19. ADDITIONAL DISCLOSURES REQUIRED UNDER U.S. GENERALLY ACCEPTED ACCOUNTING PRINCIPLES The Companys consolidated financial statements have been prepared in accordance with GAAP as
applied in Canada. In the case of the Company, Canadian GAAP conforms in all material respects with
U.S. GAAP except for certain matters, the details of which are as follows: Consolidated Balance Sheets The application of U.S. GAAP has the following effects on balance sheet items as reported under
Canadian GAAP: Shareholders Equity and Oil and Gas Properties and Investments 62




---



##### 



As at December 31, 2004Oil and Gas
    
    

Shareholders EquityPropertiesand
    
    
    
    
    
    
    Contributed
    
    
    AccumulatedInvestments
    
    
    Share Capital
    
    
    Surplus
    
    
    Deficit
    
    
    TotalCanadian GAAP
    
    $
    96,551
    
    
    $
    183,617
    
    
    $
    1,748
    
    
    $
    (81,779
    )
    
    $
    103,586Adjustment for reduction in stated capital
    
    
    
    
    
    
    74,455
    
    
    
    
    
    
    
    (74,455
    )
    
    
    Adjustment to ascribed value of shares
issued for U.S. royalty interests, net
    
    
    1,358
    
    
    
    1,358
    
    
    
    
    
    
    
    
    
    
    
    1,358Provision for impairment
    
    
    (8,650
    )
    
    
    
    
    
    
    
    
    
    
    (8,650
    )
    
    
    (8,650
    )Depletion adjustments due to differences
in provision for impairment
    
    
    482
    
    
    
    
    
    
    
    
    
    
    
    482
    
    
    
    482GTL and EOR development costs expensed
    
    
    (5,884
    )
    
    
    
    
    
    
    
    
    
    
    (5,884
    )
    
    
    (5,884
    )Adjustment for change in accounting for
stock based compensation
    
    
    
    
    
    
    (300
    )
    
    
    (1,660
    )
    
    
    1,960
    
    
    
    U.S. GAAP
    
    $
    83,857
    
    
    $
    259,130
    
    
    $
    88
    
    
    $
    (168,326
    )
    
    $
    90,892
 As at December 31, 2003Oil and Gas
    
    

Shareholders EquityPropertiesand
    
    
    
    
    
    
    Contributed

    
    
    AccumulatedInvestments
    
    
    Share Capital
    
    
    Surplus
    
    
    Deficit
    
    
    TotalCanadian GAAP
    
    $
    87,956
    
    
    $
    161,075
    
    
    $
    516
    
    
    $
    (61,054
    )
    
    $
    100,537Adjustment for reduction in stated capital
    
    
    
    
    
    
    74,455
    
    
    
    
    
    
    
    (74,455
    )
    
    
    Adjustment to ascribed value of shares
issued for U.S. royalty interests, net
    
    
    1,358
    
    
    
    1,358
    
    
    
    
    
    
    
    
    
    
    
    1,358Provision for impairment
    
    
    (10,000
    )
    
    
    
    
    
    
    
    
    
    
    (10,000
    )
    
    
    (10,000
    )Depletion adjustments due to differences in
provision for impairment
    
    
    166
    
    
    
    
    
    
    
    
    
    
    
    166
    
    
    
    166GTL and EOR development costs expensed
    
    
    (4,074
    )
    
    
    
    
    
    
    
    
    
    
    (4,074
    )
    
    
    (4,074
    )Adjustment for change in accounting for
stock based compensation
    
    
    
    
    
    
    (271
    )
    
    
    (516
    )
    
    
    787
    
    
    
    U.S. GAAP
    
    $
    75,406
    
    
    $
    236,617
    
    
    $
    
    
    
    $
    (148,630
    )
    
    $
    87,987
 Share Capital and Accumulated Deficit In June 1999, the shareholders approved a 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 accumulated deficit such as this is not recognized except
in the case of a quasi reorganization. The effect of this is that under U.S. GAAP, share capital
and accumulated deficit are increased by $74.4 million as at December 31, 2004 and 2003. Oil and Gas Properties and Investments Prior to January 2004, there were certain differences between the full cost method of accounting
for oil and gas properties as applied in Canada and as applied in the U.S. The principal difference
was in the method of performing ceiling test evaluations under the full cost method of accounting
rules. Under Canadian GAAP prior to January 2004, impairment of oil and gas properties was based on
the amount by which a cost centers carrying value exceeded its undiscounted future net cash flows
from proved reserves using period-end, non-escalated prices and costs, less an estimate for future
general and administrative expenses, financing costs and income taxes. As more fully described in
Note 2 Oil and Gas Properties, effective January 2004, Canadian GAAP requires recognition and
measurement processes to assess impairment of oil and gas properties using estimates of future oil
and gas prices and costs plus the cost of unproved properties that have been excluded from the
depletion calculation. In the measurement of the impairment, the future net cash flows of a cost
centers proved and probable reserves are discounted using a risk-free interest rate. For U.S. GAAP purposes, future net cash flows from proved reserves using period-end, non-escalated
prices and costs, are discounted to present value at 10% per annum and compared to the carrying
value of oil and gas properties. The Company performed the ceiling test in accordance with U.S.
GAAP and determined that for 2004 an impairment provision of $15.0 was required on its U.S. oil and
gas properties compared to a $16.3 million impairment provision under Canadian GAAP. For 2001, a
$10.0 million provision for impairment was required, for U.S. GAAP purposes, in connection with the
Companys China oil and gas properties resulting in accumulated net additional impairment
provisions of $8.7 million for U.S. GAAP purposes as at December 31, 2004. There was no
difference in the impairment provisions for 2003 and no impairment provision was required for 2002
under Canadian or U.S. GAAP. 63




---



##### 



The differences in the amount of impairment provisions between Canadian and U.S. GAAP resulted
in a reduction in accumulated depletion of $0.5 million and $0.2 million as at December 31, 2004
and 2003, respectively. As more fully described under Investments in EOR and GTL Projects in Note 2, for Canadian GAAP
the Company capitalizes certain costs incurred for GTL and EOR projects subsequent to executing an
MOU to determine the technical and commercial feasibility of a project, including studies for the
marketability for the projects products. If no definitive agreement is reached, then the projects
capitalized costs, which are deemed to have no future value, are written down and charged to
operations with a corresponding reduction in the investments in GTL and EOR assets. For U.S. GAAP, feasibility, marketing and related costs incurred prior to executing a GTL or EOR
definitive agreement are considered to be research and development and are expensed as incurred.
As at December 31, 2004 and 2003, the Company capitalized $5.9 million and $4.1 million,
respectively, for Canadian GAAP, which was expensed for U.S. GAAP purposes. For U.S. GAAP purposes, the aggregate value attributed to the acquisition of U.S. royalty rights
during 1999 and 2000 was $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. For the year ended December 31, 2004, a ceiling test
impairment of $1.0 million of the U.S. GAAP difference related to royalty rights was recognized in
the results of operations. Consolidated Statements of Loss The application of U.S. GAAP had the following effects on net loss and net loss per share as
reported under Canadian GAAP: Year ended December 31,2004
    
    
    2003
    
    
    2002Net
    
    
    Net Loss
    
    
    Net
    
    
    Net Loss
    
    
    Net
    
    
    Net LossLoss
    
    
    Per Share
    
    
    Loss
    
    
    Per Share
    
    
    Loss
    
    
    Per ShareCanadian GAAP (as restated for 2003 and 2002 see Notes 2 and 9)
    
    $
    20,725
    
    
    $
    0.12
    
    
    $
    30,179
    
    
    $
    0.20
    
    
    $
    7,130
    
    
    $
    0.05Stock based compensation expense
    
    
    (1,173
    )
    
    
    (0.01
    )
    
    
    (476
    )
    
    
    
    
    
    
    (311
    )
    
    
    Provision for impairment
    
    
    (1,350
    )
    
    
    (0.01
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Depletion adjustments due to differences in
provision for impairment
    
    
    (316
    )
    
    
    
    
    
    
    (88
    )
    
    
    
    
    
    
    (78
    )
    
    
    GTL and EOR development costs expensed, net
    
    
    1,810
    
    
    
    0.02
    
    
    
    (2,529
    )
    
    
    (0.02
    )
    
    
    1,461
    
    
    
    0.01U.S. GAAP
    
    $
    19,696
    
    
    
    0.12
    
    
    $
    27,086
    
    
    $
    0.18
    
    
    $
    8,202
    
    
    $
    0.06Weighted Average Number of Shares under U.S. GAAP (in thousands)
    
    
    
    
    
    
    167,612
    
    
    
    
    
    
    
    150,154
    
    
    
    
    
    
    
    142,314
 As discussed under Oil and Gas Properties and Investments in this note, there is a
difference in performing the ceiling test evaluation under the full cost method of accounting
between U.S. and Canadian GAAP. Application of the ceiling test evaluation under U.S. GAAP for
2004, resulted in a lower impairment provision on the Companys U.S. oil and gas properties by $1.3
million and for 2001 required an additional $10.0 million provision for impairment with respect to
the Companys China oil and gas properties. The net increase in impairment provisions resulted in
lower depletion rates for U.S. GAAP purposes and a reduction of $0.3 million in the net loss for
the year ended December 31, 2004 and $0.1 million reductions in the net losses for each of the
years ended December 31, 2003 and 2002. As more fully discussed under Stock Based Compensation in Notes 2 and 9, as of January 1, 2004
the Company changed its accounting policy, for Canadian GAAP, to recognize compensation costs using
the fair value based method of accounting for stock options granted to employees and directors
after January 1, 2002. For U.S. GAAP, the Company continues to apply APB Opinion No. 25, as
interpreted by FASB Interpretation No. 44, in accounting for its stock option plan and does not
recognize compensation costs in its financial statements for stock options issued to employees and
directors. This resulted in a reduction of $1.2 million, $0.5 million and $0.3 million in the net
losses for the years ended December 31, 2004, 2003 and 2002, respectively. As more fully described under Oil and Gas Properties and Investments in this note, for Canadian
GAAP, feasibility, marketing and related costs incurred prior to executing a GTL or EOR definitive
agreement are capitalized and are subsequently written down upon determination that a projects
future value has been impaired. For U.S. GAAP, such costs are considered to be research and
development and are expensed as incurred. For the years ended December 31, 2004 and 2002, the
Company expensed $1.8 million and $1.5 million, respectively, in excess of the Canadian GAAP
write-downs during those corresponding years. For the year ended December 31, 2003, the Company
expensed $2.5 million less for U.S. GAAP than the write-down recognized for Canadian GAAP. 64




---



##### 



Stock Based Compensation Had stock based 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 31,2004
    
    
    2003
    
    
    2002Net loss under U.S. GAAP
    
    $
    19,696
    
    
    $
    27,086
    
    
    $
    8,202Stock-based compensation expense determined under the fair
value based method for employee and director awards
    
    
    1,869
    
    
    
    1,682
    
    
    
    1,885Pro forma net loss under U.S. GAAP
    
    $
    21,565
    
    
    $
    28,768
    
    
    $
    10,087Basic and diluted loss per common share under U.S. GAAP:As reported
    
    $
    0.12
    
    
    $
    0.18
    
    
    $
    0.06Pro forma
    
    $
    0.13
    
    
    $
    0.19
    
    
    $
    0.07Weighted Average Number of Shares under U.S. GAAP (in
thousands)
    
    
    167,612
    
    
    
    150,154
    
    
    
    142,314Stock options granted during the period (thousands)
    
    
    458
    
    
    
    690
    
    
    
    1,870Weighted average exercise price
    
    $
    1.88
    
    
    $
    4.00
    
    
    $
    1.92Weighted average fair value of options granted during the year
    
    $
    1.40
    
    
    $
    2.83
    
    
    $
    1.07
 Stock based compensation for U.S. GAAP was calculated in accordance with the Black Scholes
option-pricing model using the same assumptions as used for Canadian GAAP. Consolidated Statements of Cash Flow As a result of the write-down of GTL and EOR development costs required under U.S. GAAP, the
statement of cash flow as reported would result in a cash surplus from operating activities of $2.0
million for the year ended December 31, 2004 and cash deficiencies from operating activities of
$2.3 million and $4.0 million for the years ended December 31, 2003 and 2002, respectively.
Additionally, capital investments reported under investing activities would be $44.4 million, $14.6
million and $16.9 million for the same periods ended, respectively. Additional U.S. GAAP Disclosures Oil and Gas Properties and Investments The categories of costs included in Oil and Gas Properties and Investments, including the U.S.
GAAP adjustments discussed in this note were as follows: As at December 31, 2004
    
    
    As at December 31, 2003U.S.
    
    
    China
    
    
    GTL
    
    
    Total
    
    
    U.S.
    
    
    China
    
    
    GTL
    
    
    TotalProperty acquisition costs
    
    $
    22,295
    
    
    $
    2,418
    
    
    $
    
    
    
    $
    24,713
    
    
    $
    17,518
    
    
    $
    2,418
    
    
    $
    
    
    
    $
    19,936Royalty rights acquired
    
    
    10,582
    
    
    
    
    
    
    
    
    
    
    
    10,582
    
    
    
    10,582
    
    
    
    
    
    
    
    
    
    
    
    10,582Exploration costs
    
    
    35,120
    
    
    
    8,594
    
    
    
    
    
    
    
    43,714
    
    
    
    31,269
    
    
    
    1,669
    
    
    
    
    
    
    
    32,938Development costs
    
    
    35,456
    
    
    
    35,105
    
    
    
    
    
    
    
    70,561
    
    
    
    27,068
    
    
    
    28,587
    
    
    
    
    
    
    
    55,655GTL master license
    
    
    
    
    
    
    
    
    
    
    10,000
    
    
    
    10,000
    
    
    
    
    
    
    
    
    
    
    
    10,000
    
    
    
    10,000Support equipment and
general property
    
    
    480
    
    
    
    270
    
    
    
    
    
    
    
    750
    
    
    
    433
    
    
    
    196
    
    
    
    
    
    
    
    629103,933
    
    
    
    46,387
    
    
    
    10,000
    
    
    
    160,320
    
    
    
    86,870
    
    
    
    32,870
    
    
    
    10,000
    
    
    
    129,740Accumulated depletion and
depreciation
    
    
    (11,197
    )
    
    
    (6,266
    )
    
    
    
    
    
    
    (17,463
    )
    
    
    (6,696
    )
    
    
    (3,638
    )
    
    
    
    
    
    
    (10,334
    )Provision for impairment
    
    
    (49,000
    )
    
    
    (10,000
    )
    
    
    
    
    
    
    (59,000
    )
    
    
    (34,000
    )
    
    
    (10,000
    )
    
    
    
    
    
    
    (44,000
    )$
    43,736
    
    
    $
    30,120
    
    
    $
    10,000
    
    
    $
    83,857
    
    
    $
    46,174
    
    
    $
    19,232
    
    
    $
    10,000
    
    
    $
    75,406
 U.S. development costs as at December 31, 2004 and 2003 include $0.6 million and $0.4 million,
respectively, of asset retirement costs. As at December 31, 2004, the costs of unproved properties included in oil and gas properties were
as follows: 65




---



##### 



Incurred inPrior toTotal
    
    
    2004
    
    
    2003
    
    
    2002
    
    
    2002Property Acquisition
    
    $
    8,973
    
    
    $
    893
    
    
    $
    673
    
    
    $
    2,055
    
    
    $
    5,352Royalty rights
    
    
    6,851
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    6,851Exploration
    
    
    15,592
    
    
    
    8,949
    
    
    
    1,877
    
    
    
    
    
    
    
    4,766$
    31,416
    
    
    $
    9,842
    
    
    $
    2,550
    
    
    $
    2,055
    
    
    $
    16,969
 The difference from Canadian GAAP in unproved oil and gas properties as at December 31, 2004
was $0.4 million related to the $1.4 million of aggregate value attributed to the acquisition of
U.S. royalty rights during 1999 and 2000 less a $1.0 million ceiling test impairment associated
with these royalty rights recognized for U.S. GAAP during the year ended December 31, 2004. Accounts Payable and Accrued Liabilities The following was the breakdown of accounts payable and accrued liabilities: As at December 31,2004
    
    
    2003Accounts payable and accruals
    
    $
    8,745
    
    
    $
    3,626Accrued salaries and related expenses
    
    
    929
    
    
    
    858Accrued interest
    
    
    11
    
    
    
    2Other accruals
    
    
    160
    
    
    
    30$
    9,845
    
    
    $
    4,516
 Impact of New and Pending U.S. GAAP Accounting Standards In June 2004, the Financial Accounting Standards Board (FASB) issued an exposure draft of a
proposed statement, Fair Value Measurements to provide guidance on how to measure the fair value
of financial and non-financial assets and liabilities when required by other authoritative
accounting pronouncements. The proposed statement attempts to address concerns about the ability to
develop reliable estimates of fair value and inconsistencies in fair value guidance provided by
current U.S. GAAP, by creating a framework that clarifies the fair value objective and its
application in GAAP. In addition, the proposal expands disclosures required about the use of fair
value to re-measure assets and liabilities. The standard would be effective for financial
statements issued for fiscal years beginning after June 15, 2005. In September of 2004, the SEC released Staff Accounting Bulletin No. 106, which provides guidance
regarding the interaction of Statement of Financial Accounting Standard No. 143, Accounting for
Asset Retirement Obligations (SFAS 143) with the full cost accounting rules in Article 4-10 of
Regulation S-X. This bulletin clarifies the treatment of assets and liabilities resulting from the
implementation of SFAS 143 on the full cost ceiling test and the calculation of depletion,
depreciation and amortization. The Company is in compliance with the provisions of Staff
Accounting Bulletin No. 106. In December 2004, the FASB issued a revision to SFAS No, 123, Accounting for Stock Based
Compensation which supersedes APB No. 25, Accounting for Stock Issued to Employees. This
Statement requires measurement of the cost of employee services received in exchange for an award
of equity instruments based on the fair value of the award on the date of the grant and recognition
of the cost in the results of operations over the period during which an employee is required to
provide service in exchange for the award. No compensation cost is recognized for equity
instruments for which employees do not render the requisite service. The Company applies APB
Opinion No. 25, as interpreted by FASB Interpretation No. 44, in accounting for awards issued from
our stock option plan and do not recognize compensation costs in our U.S. GAAP financial statements
for stock options issued to its employees and directors. This statement is effective for the first
interim or annual reporting that begins after June 15, 2005 and maybe implemented on a modified
prospective or retrospective basis. The Company has elected to implement this statement on a
modified prospective basis starting in the third quarter of 2005. Under the modified prospective
basis the Company would recognize stock based compensation in its U.S. GAAP results of operations
for the unvested portion of awards outstanding as of July 1, 2005 and for all awards granted after
July 1, 2005. The following standards issued by the FASB do not impact the Company at this time: SFAS No. 151, Inventory Costsan amendment of ARB No. 43, Chapter 4 effective for inventory costs
incurred during fiscal years beginning after June 15, 2005. SFAS No. 153, Exchanges of Nonmonetary Assetsan amendment of APB Opinion No. 29 effective for
nonmonetary asset exchanges occurring in fiscal years beginning after June 15, 2005. 66




---



##### 



QUARTERLY FINANCIAL DATA IN ACCORDANCE WITH CANADIAN AND U.S. GAAP (UNAUDITED) QUARTER ENDED2004
    
    
    20034th Qtr
    
    
    3rd Qtr
    
    
    2nd Qtr
    
    
    1st Qtr
    
    
    4th Qtr
    
    
    3rd Qtr
    
    
    2nd Qtr
    
    
    1st QtrTotal revenue
    
    $
    6,212
    
    
    $
    4,932
    
    
    $
    3,521
    
    
    $
    3,332
    
    
    $
    2,330
    
    
    $
    2,423
    
    
    $
    2,338
    
    
    $
    2,568Net loss - Canadian GAAP
    
    $
    17,184
    
    
    $
    951
    
    
    $
    1,298
    
    
    $
    1,292
    
    
    $
    23,154
    
    
    $
    1,330
    
    
    $
    4,587
    
    
    $
    1,108Net loss - U.S. GAAP
    
    $
    15,736
    
    
    $
    980
    
    
    $
    1,510
    
    
    $
    1,470
    
    
    $
    23,270
    
    
    $
    1,306
    
    
    $
    1,325
    
    
    $
    1,185Net loss per share - Canadian GAAP
    
    $
    0.09
    
    
    $
    0.01
    
    
    $
    0.01
    
    
    $
    0.01
    
    
    $
    0.15
    
    
    $
    0.01
    
    
    $
    0.03
    
    
    $
    0.01Net loss per share - U.S. GAAP
    
    $
    0.09
    
    
    $
    0.01
    
    
    $
    0.01
    
    
    $
    0.01
    
    
    $
    0.15
    
    
    $
    0.01
    
    
    $
    0.01
    
    
    $
    0.01
 The 2003 quarterly earnings
for Canadian GAAP have been restated to give effect to the
retroactive application of CICA Section 3870  Stock Based Compensation and Other Stock Based
Payments, which is more fully described in Note 2 under Stock Based Compensation. The net losses
in the fourth quarter of 2004, for Canadian and U.S. GAAP, were primarily due to impairment
provisions of $16.3 million and $15.0 million, respectively, for U.S. oil and gas properties. The
net losses in the fourth quarter of 2003, for both Canadian and U.S. GAAP, were primarily due to an
impairment provision of $20.0 million for U.S. oil and gas properties. The net loss under Canadian
GAAP for the second quarter of 2003 included a $3.3 million write-down of costs associated with the
unsuccessful negotiations of a GTL contract in Qatar. For U.S. GAAP, these costs are expensed as
they are incurred. 
 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 2004 and 2003 in the U.S. were based on the estimates by the
independent petroleum engineering firm of Netherland, Sewell & Associates, Inc. The reserves for
2002 in the U.S. were based on estimates by the independent petroleum engineering firms of Joe C.
Neal & Associates and Allan Spivak Engineering. In China, the reserves were based on estimates by
the independent petroleum engineering firm of Gilbert Laustsen Jung Associates Ltd. The Companys net proved and net proved developed oil and gas reserves were as follows: 67




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##### 



Oil (MBbl)
    
    
    Gas (MMcf)U.S.
    
    
    China
    
    
    Total
    
    
    U.S.Net proved reserves, December 31, 2001
    
    
    2,003
    
    
    
    21,795
    
    
    
    23,798
    
    
    
    1,631Extensions and discoveries
    
    
    710
    
    
    
    
    
    
    
    710
    
    
    
    63Production
    
    
    (208
    )
    
    
    (142
    )
    
    
    (350
    )
    
    
    (103
    )Revisions to previous estimates
    
    
    (280
    )
    
    
    (2,601
    )
    
    
    (2,881
    )
    
    
    (101
    )Sales of reserves
    
    
    (441
    )
    
    
    (3,448
    )
    
    
    (3,889
    )
    
    
    (671
    )Net proved reserves, December 31, 2002
    
    
    1,784
    
    
    
    15,604
    
    
    
    17,388
    
    
    
    819Extensions and discoveries
    
    
    480
    
    
    
    
    
    
    
    480
    
    
    
    22Production
    
    
    (202
    )
    
    
    (144
    )
    
    
    (346
    )
    
    
    (50
    )Revisions to previous estimates
    
    
    (499
    )
    
    
    239
    
    
    
    (260
    )
    
    
    (96
    )Net proved reserves, December 31, 2003
    
    
    1,563
    
    
    
    15,699
    
    
    
    17,262
    
    
    
    695Extensions and discoveries
    
    
    240
    
    
    
    
    
    
    
    240
    
    
    
    1,289Purchases of reserves in place
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    819Production
    
    
    (234
    )
    
    
    (235
    )
    
    
    (469
    )
    
    
    (207
    )Revisions to previous estimates
    
    
    (121
    )
    
    
    (1,360
    )
    
    
    (1,481
    )
    
    
    87Sale of reserves
    
    
    (18
    )
    
    
    (6,196
    )
    
    
    (6,214
    )

    
    
    Net proved reserves, December 31, 2004
    
    
    1,430
    
    
    
    7,908
    
    
    
    9,338
    
    
    
    2,683Net proved developed reserves:December 31, 2002
    
    
    1,131
    
    
    
    48
    
    
    
    1,179
    
    
    
    819December 31, 2003
    
    
    1,225
    
    
    
    209
    
    
    
    1,434
    
    
    
    695December 31, 2004
    
    
    1,187
    
    
    
    1,142
    
    
    
    2,329
    
    
    
    2,365
 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 was computed using period end statutory tax rates, costs and prices of $40.25, $30.31 and
$29.04 per barrel of oil in 2004, 2003 and 2002, respectively, and $5.94, $6.13 and $5.30 per Mcf
of gas in 2004, 2003 and 2002, respectively. A discount rate of 10% was applied in determining the
standardized measure of discounted future net cash flows. The Company does not believe that this information reflects the fair market value of its oil and
gas properties. Actual future net cash flows will differ from the presented estimated future net
cash flows in that:  
    future production from proved reserves will differ from estimated production;
    future production 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 were as follows: 2004U.S.
    
    
    China
    
    
    TotalFuture cash inflows
    
    $
    64,357
    
    
    $
    327,481
    
    
    $
    391,838Future development and restoration costs
    
    
    3,063
    
    
    
    84,682
    
    
    
    87,745Future production costs
    
    
    27,867
    
    
    
    58,488
    
    
    
    86,355Future income taxes
    
    
    
    
    
    
    44,708
    
    
    
    44,708Future net cash flows
    
    
    33,427
    
    
    
    139,603
    
    
    
    173,03010% annual discount
    
    
    11,238
    
    
    
    50,774
    
    
    
    62,012Standardized measure
    
    $
    22,189
    
    
    $
    88,829
    
    
    $
    111,018
 68




---



##### 



2003U.S.
    
    
    China
    
    
    TotalFuture cash inflows
    
    $
    48,751
    
    
    $
    478,748
    
    
    $
    527,499Future development and restoration costs
    
    
    2,138
    
    
    
    154,245
    
    
    
    156,383Future production costs
    
    
    22,037
    
    
    
    91,912
    
    
    
    113,949Future income taxes
    
    
    
    
    
    
    61,647
    
    
    
    61,647Future net cash flows
    
    
    24,576
    
    
    
    170,944
    
    
    
    195,52010% annual discount
    
    
    7,466
    
    
    
    89,180
    
    
    
    96,646Standardized measure
    
    $
    17,110
    
    
    $
    81,764
    
    
    $
    98,874
 2002U.S.
    
    
    China
    
    
    TotalFuture cash inflows
    
    $
    52,057
    
    
    $
    461,256
    
    
    $
    513,313Future development and restoration costs
    
    
    4,597
    
    
    
    129,855
    
    
    
    134,452Future production costs
    
    
    16,288
    
    
    
    134,540
    
    
    
    150,828Future income taxes
    
    
    
    
    
    
    52,656
    
    
    
    52,656Future net cash flows
    
    
    31,172
    
    
    
    144,205
    
    
    
    175,37710% annual discount
    
    
    9,687
    
    
    
    84,423
    
    
    
    94,110Standardized measure
    
    $
    21,485
    
    
    $
    59,782
    
    
    $
    81,267
 Changes in standardized measure of discounted future net cash flows as at December 31 in each
of the three most recently completed financial years were as follows: 2004U.S.
    
    
    China
    
    
    TotalSale of oil & gas net of production costs
    
    $
    (6,152
    )
    
    $
    (6,570
    )
    
    $
    (12,722
    )Net changes in pricing and production costs
    
    
    1,015
    
    
    
    56,329
    
    
    
    57,344Sale of reserves
    
    
    (108
    )
    
    
    (21,646
    )
    
    
    (21,754
    )Discoveries and extensions
    
    
    6,779
    
    
    
    
    
    
    
    6,779Purchases of reserves in place
    
    
    3,050
    
    
    
    
    
    
    
    3,050Revisions of previous estimates
    
    
    (1,401
    )
    
    
    (22,847
    )
    
    
    (24,248
    )Net change in income taxes
    
    
    
    
    
    
    (9,107
    )
    
    
    (9,107
    )Net change in future development costs
    
    
    (1,700
    )
    
    
    (14,424
    )
    
    
    (16,124
    )Accretion of discount
    
    
    3,596
    
    
    
    25,330
    
    
    
    28,926Increase (decrease)
    
    
    5,079
    
    
    
    7,065
    
    
    
    12,144Standardized measure, beginning of year
    
    
    17,110
    
    
    
    81,764
    
    
    
    98,874Standardized measure, end of year
    
    $
    22,189
    
    
    $
    88,829
    
    
    $
    111,018
 2003U.S.
    
    
    China
    
    
    TotalSale of oil & gas net of production costs
    
    $
    (3,153
    )
    
    $
    (2,123
    )
    
    $
    (5,276
    )Net changes in pricing and production costs
    
    
    (4,034
    )
    
    
    47,960
    
    
    
    43,926Discoveries and extensions
    
    
    5,712
    
    
    
    (636
    )
    
    
    5,076Revisions of previous estimates
    
    
    (8,957
    )
    
    
    1,604
    
    
    
    (7,353
    )Net change in income taxes
    
    
    
    
    
    
    (9,435
    )
    
    
    (9,435
    )Net change in future development costs
    
    
    2,337
    
    
    
    (14,626
    )
    
    
    (12,289
    )Accretion of discount
    
    
    3,720
    
    
    
    (762
    )
    
    
    2,958Increase (decrease)
    
    
    (4,375
    )
    
    
    21,982
    
    
    
    17,607Standardized measure, beginning of year
    
    
    21,485
    
    
    
    59,782
    
    
    
    81,267Standardized measure, end of year
    
    $
    17,110
    
    
    $
    81,764
    
    
    $
    98,874
 69




---



##### 



2002U.S.
    
    
    China
    
    
    TotalSale of oil & gas net of production costs
    
    $
    (2,748
    )
    
    $
    (1,740
    )
    
    $
    (4,488
    )Net changes in pricing and production costs
    
    
    13,700
    
    
    
    150,510
    
    
    
    164,210Sale of reserves
    
    
    (4,192
    )
    
    
    (43,493
    )
    
    
    (47,685
    )Discoveries and extensions
    
    
    10,135
    
    
    
    (550
    )
    
    
    9,585Revisions of previous estimates
    
    
    (7,661
    )
    
    
    (34,600
    )
    
    
    (42,261
    )Net change in income taxes
    
    
    
    
    
    
    (21,206
    )
    
    
    (21,206
    )Net change in future development costs
    
    
    3,539
    
    
    
    (309
    )
    
    
    3,230Accretion of discount
    
    
    (1,531
    )
    
    
    3,124
    
    
    
    1,593Increase (decrease)
    
    
    11,242
    
    
    
    51,736
    
    
    
    62,978Standardized measure, beginning of year
    
    
    10,243
    
    
    
    8,046
    
    
    
    18,289Standardized measure, end of year
    
    $
    21,485
    
    
    $
    59,782
    
    
    $
    81,267
 Costs incurred in oil and gas property acquisition, exploration, and development activities
were as follows: As at December 31,2004
    
    
    2003
    
    
    2002Property acquisitionProved
    
    $
    3,204
    
    
    $
    
    
    
    $
    Unproved
    
    
    1,572
    
    
    
    650
    
    
    
    913Exploration
    
    
    11,276
    
    
    
    3,148
    
    
    
    10,841Development
    
    
    28,364
    
    
    
    11,181
    
    
    
    5,178$
    44,416
    
    
    $
    14,979
    
    
    $
    16,932
 Development cost additions for the years ended December 31, 2004 and 2003 included $0.2
million and $0.4 million of asset retirement costs, respectively. Depletion, per unit of net production, before provision for impairment were as follows: U.S.Year ended December 31, 2004
    
    $
    16.80Year ended December 31, 2003
    
    $
    10.58Year ended December 31, 2002
    
    $
    8.39ChinaYear ended December 31, 2004
    
    $
    12.18Year ended December 31, 2003
    
    $
    10.23Year ended December 31, 2002
    
    $
    8.30
 The results of operations from producing activities were as follows: 2004
    
    
    2003
    
    
    2002U.S.
    
    
    China
    
    
    Total
    
    
    U.S.
    
    
    China
    
    
    Total
    
    
    U.S.
    
    
    China
    
    
    TotalOil and gas revenue
    
    $
    9,311
    
    
    $
    8,484
    
    
    $
    17,795
    
    
    $
    5,466
    
    
    $
    4,103
    
    
    $
    9,569
    
    
    $
    5,099
    
    
    $
    3,230
    
    
    $
    8,329Operating costs
    
    
    3,159
    
    
    
    1,914
    
    
    
    5,073
    
    
    
    2,313
    
    
    
    1,980
    
    
    
    4,293
    
    
    
    2,351
    
    
    
    1,490
    
    
    
    3,841Depletion
(including
provision for
impairment)
    
    
    19,428
    
    
    
    2,630
    
    
    
    22,058
    
    
    
    22,253
    
    
    
    1,477
    
    
    
    23,730
    
    
    
    1,906
    
    
    
    1,202
    
    
    
    3,108Results of
operations from
producing
activities
    
    $
    (13,276
    )
    
    $
    3,940
    
    
    $
    (9,336
    )
    
    $
    (19,100
    )
    
    $
    646
    
    
    $
    (18,454
    )
    
    $
    842
    
    
    $
    538
    
    
    $
    1,380
 
 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. 
 ITEM 9A. CONTROLS AND PROCEDURES We carried out an evaluation, under the supervision of and with the participation of our
management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness
of the design and operation of our internal control over financial reporting pursuant to the
requirements of the Securities Exchange Act of 1934. Based upon that evaluation, our management,
including the Chief Executive Officer and Chief Financial Officer, concluded that, as at December
31, 2004, because of the issues referenced below, our internal control over financial reporting was
not effective at a reasonable assurance level. Our management, including our Chief 70




---



##### 



Executive
Officer and Chief Financial Officer believe, however, that when fully implemented, remediation
measures will address the internal control deficiencies described below and will allow us to
conclude that our internal control over financial reporting is effective at a reasonable level of
assurance at future filing dates. There were several significant changes in our internal control over financial reporting both during
the year ended December 31, 2004 and since that date. These changes were in direct response to
managements formal assessment of the effectiveness of the design and operation of our internal
control over financial reporting. The Securities Exchange Act of 1934 requires an annual management
report on the effectiveness of our internal control over financial reporting. Our independent
registered chartered accountants must attest to this report. Although we would ordinarily include
such information in our Annual Report on Form 10-K, we meet the eligibility requirements for a
45-day extension for the provision of this report and attestation, as detailed in an exemptive
order by the U.S. Securities and Exchange Commission in November 2004. Because we have elected to
use this extension, this Annual Report on Form 10-K does not include either the management report
or the independent registered chartered accountants attestation. These will instead be included
in an amended Annual Report on Form 10-K that we expect to file in April 2005. Our review to date of our internal control over financial reporting has brought to our attention
two material weaknesses that are discussed below. 1. Information and Communication Information systems produce reports, containing operational, financial and compliance-related
information, that make it possible to run and control the business. Pertinent information must be
identified, captured, and communicated in an effective manner to enable employees to carry out
their responsibilities. These information systems deal not only with internally generated data, but
also with the information about external events necessary to informed business decision-making and
external reporting, such as industry, economic, and regulatory information. Effective communication
also must occur in a broader sense, flowing down, across, and up the organization. Our review of our information and communication procedures identified certain deficiencies. Taken
together, the following deficiencies are considered to constitute a material weakness in internal
control over financial reporting.  
    a weakness in the procedure for the receipt of complaints regarding accounting, internal
accounting controls, or auditing matters.  -
    Section 301 of the Sarbanes-Oxley Act of 2002 requires our Audit Committee to
establish procedures for the confidential, anonymous submission by employees . . .
regarding questionable accounting or auditing matters. Our current complaint procedure,
applicable to both employees and third parties, directs complaints to our Corporate
Secretary, who then advises the appropriate board committee or management member. We do
not believe this procedure provides the requisite anonymity to a reporting employee or
third party. As a result, we have adopted corrective measures that will be in place by
March 31, 2005. An independent firm will handle all complaints, whether from employees
or third parties. In addition, anyone wishing to raise concerns regarding accounting or
auditing matters will be able to do so by means of a secure website.  
    a lack of a formal process to ensure active ongoing communication of employees roles
and responsibilities related to internal control over financial reporting across the
organization.  -
    Although the importance of the safeguarding of our assets and the honest and
accurate recording of information are key parts of our Code of Business Conduct, we do
not formally review these processes with our employees on a regular basis. We will be
formally communicating the roles and responsibilities related to internal control over
financial reporting to all employees as part of our new complaint process noted above.  
    a lack of a formal self-assessment process to monitor and detect control deficiencies
related to internal control over financial reporting.  -
    As part of our responsibilities under Section 404 of the Sarbanes-Oxley Act of
2002, there will be an annual and extensive formal review to monitor and detect control
deficiencies related to internal control over financial reporting.  
    our present fraud or misconduct response plans and policies are informal and do not
provide a written and clear process for employees and external third parties to follow if
they wish to report an issue, including inappropriate management overrides.  -
    We will be formally communicating such plans and policies as part of our new
complaint process noted above. 2. Financial Reporting Process Our review of our financial reporting process identified several deficiencies, principally related
to the lack of formal processes, division of duties and procedures for documentation of various
approvals and reviews. Taken together, these deficiencies are 71




---



##### 



considered to constitute a material
weakness in internal control over financial reporting. Management believes that these procedures
and reviews were properly carried out and that the deficiencies identified during the review
process relate principally to the lack of written evidence that procedures and reviews were
properly completed. Prior to December 31, 2004 and since that date, we have changed many of our
policies and procedures for the documentation of these reviews and procedures and have designed
appropriate document retention policies to provide written evidence of our reviews and procedures. As noted above, upon completion of our assessment of our internal control over financial reporting
we currently expect to conclude that the above described two material weaknesses in our internal
control over financial reporting existed as at December 31, 2004. However, we have not yet
completed our assessment and so there may be other material weaknesses identified. Accordingly, management expects to conclude that our internal control over financial reporting as
at December 31, 2004 is ineffective, and Deloitte & Touche LLP has advised us that they expect
their report on managements assessment of internal control over financial reporting will also
indicate that internal control over financial reporting was ineffective as at December 31, 2004. 
 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. 72




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Name, Age and
    
    Position with
    
    Present Occupation andMunicipality of Residence
    
    the Registrant
    
    Principal Occupation for the Past Five YearsDAVID R. MARTIN, age 73
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 54
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
companies; Chairman and Director, Ivanhoe Mines Ltd. (March 1994
 present)E. LEON DANIEL, age 68
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 72
Bakersfield, California
    
    Director
(since August, 1998)
    
    Retired (1998); Senior Vice President,
Worldwide Exploration, Occidental Petroleum
Corporation (1997-1998)R. EDWARD FLOOD, age 59
Reno, Nevada
    
    Director
(since June, 1999)
    
    Deputy Chairman and Director, Ivanhoe Mines Ltd.
(May 1999  present); Mining Analyst, Haywood
Securities (May, 1999  September 2001);
President, Ivanhoe Mines Ltd. (1995-1999)SHUN-ICHI SHIMIZU, age 64
Tokyo, Japan
    
    Director
(since July, 1999)
    
    Managing Director of C.U.E. Management
Consulting Ltd. (1994  present)HOWARD R. BALLOCH, age 53
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); Director, Methanex
Corporation (December 2004  present); Director,
Zi Corporation (August 2001  present); Director,
Magic Lantern Corporation (December 2003  present)J. STEVEN RHODES, age 53
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 61
Vancouver, British Columbia
    
    Chief Financial Officer
(Since January, 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); Senior President Finance and Chief
Financial Officer of Lions Gate Entertainment Corp.,
(1998 2000)PATRICK CHUA, age 49
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 56
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)
 Each of our directors was elected at our last annual general meeting of shareholders held on
April 29, 2004. 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. 73




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Rhodes replaced Mr. Shun-ichi Shimizu effective March 2, 2004. Mr. Flood, one of our independent
directors, has been determined by the Board of Directors to be an Audit Committee financial expert.
We believe that Mr. Floods prior experience as the chief executive officer of a public traded
mining company, as a member of the management of a U.S. investment fund and as a mining analyst for
a Canadian brokerage firm provides a sufficient basis for considering him 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
controls over financial reporting and for the preparation of consolidated financial statements in
accordance with generally accepted accounting principles in Canada. Our independent registered
chartered accountants 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 in fulfilling its oversight
responsibilities by reviewing the financial information provided to shareholders and others, and
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 registered chartered accountants included in their report on our financial statements. Based solely on a review of the reports furnished to us, we believe that during 2004 all of our
directors, executive officers and 10% shareholders complied with the applicable Canadian
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, consultants, officers
and directors regardless of their position in our organization, at all times and everywhere we do
business. The Code of Business Conduct and Ethics provides that our employees, consultants,
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, consultants, officers and directors. Our Code of Business Conduct and Ethics has
been filed as Exhibit 14.1 to our 2004 Annual Report on Form 10-K. A copy of our Code of Business
Conduct and Ethics may be obtained, without charge, by request to Ivanhoe Energy Inc., 654-999
Canada Place, Vancouver, British Colombia, Canada V6C 3E1, Attention: Investor Relations or by
phone to 604-688-8323. 
 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 our Chief Executive Officer and
Chief Financial Officer as at December 31, 2004, and each of our three most highly compensated
executive officers whose annual compensation exceeded Cdn.$150,000 in the year ended December 31,
2004 (collectively, the Named Executive Officers). During the year ended December 31, 2004, the
aggregate compensation paid to all of our executive officers whose annual compensation exceeded
Cdn.$40,000 was U.S.$1,285,834. Summary Compensation Table The following table sets forth a summary of all compensation paid during the years ending December
31, 2004, 2003 and 2002 to each of the Named Executive Officers. 74




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SUMMARY COMPENSATION TABLE ($U.S.)  Annual Compensation
    
    
    Long Term CompensationAwards
    
    
    PayoutsSecuritiesUnder
    
    
    RestrictedOther
    
    
    Options/
    
    
    Shares orAnnual
    
    
    SARs
    
    
    Restricted
    
    
    
    
    
    All OtherName and
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Compen-
    
    
    Granted
    
    
    Share
    
    
    LTIP
    
    
    Compen-Principal Position
    
    
    Year
    
    
    Salary
    
    
    Bonus(6)
    
    
    sation
    
    
    (#)
    
    
    Units
    
    
    Payouts
    
    
    sation(7)E. Leon Daniel
    
    
    
    2004
    
    
    
    
    300,000
    
    
    
    
    90,000
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    12,792President & Chief Executive
    
    
    
    2003
    
    
    
    
    332,610
    
    
    
    
    81,123
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    9,792Officer(1)
    
    
    
    2002
    
    
    
    
    266,500
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    5,415David R. Martin
    
    
    
    2004
    
    
    
    
    200,000
    
    
    
    
    60,000
    
    
    
    
    
    
    
    -
    
    
    
    
    
    
    
    
    
    
    12,792Chairman(2)
    
    
    
    2003
    
    
    
    
    205,562
    
    
    
    
    54,082
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    9,7922002
    
    
    
    
    253,167
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    7,200Patrick Chua
    
    
    
    2004
    
    
    
    
    144,000
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    

    Executive Vice President(3)
    
    
    
    2003
    
    
    
    
    144,000
    
    
    
    
    32,449
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2002
    
    
    
    
    182,970
    
    
    
    
    
    
    
    
    
    
    
    
    60,000
    
    
    
    
    
    
    
    
    
    Gerald Moench
Executive Vice President(4)
    
    
    
    2004
2003
    
    
    
    
    165,000
150,000
    
    
    
    
    41,250
33,801
    
    
    
    
    
    
    
    

    
    
    
    

    
    
    
    
    
    
2002
    
    
    
    
    152,475
    
    
    
    
    
    
    
    
    
    
    
    
    50,000
    
    
    
    
    
    
    
    
    
    W. Gordon Lancaster
Chief Financial Officer (5)
    
    
    
    2004
    
    
    
    
    200,000
    
    
    
    
    60,000
    
    
    
    
    
    
    
    250,000
    
    
    
    
    
    
    
    
    
    
   (1)
    
    Mr. Daniel was appointed President and Chief Executive Officer in June 1999, and has been
one of our directors since August 1998.(2)
    
    Mr. Martin has been Chairman and one of our directors since August 1998.(3)
    
    Mr. Chua was appointed as an Executive Vice President in June 1999.(4)
    
    Mr. Moench was appointed an Executive Vice President in June 1999.(5)
    
    Mr. Lancaster was appointed Chief Financial Officer effective January 2004.(6)
    
    Bonuses earned are payable in cash and common shares from our Employees and Directors
Equity Incentive Plan at fair market value on the date of approval by the Compensation
Committee.(7)
    
    Our matching contribution to the 401(k) plan, a U.S. defined contribution retirement plan
available to U.S. employees. Long Term Incentive Plan We do not presently have a long-term incentive plan for any of our executive officers, including
our Named Executive Officers. Options and Stock Appreciation Rights (SARs) During the year ended December 31, 2004, Mr. Lancaster received an 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. Although this option was granted during the fourth quarter of 2003 in anticipation
of Mr. Lancasters appointment as Chief Financial Officer, it did not become exercisable by Mr.
Lancaster until January 1, 2004, the date upon which his appointment as Chief Financial Officer
took effect. No other stock options or SARs were granted to our Named Executive Officers in the
year ended December 31, 2004.  Percent of Total
    
    
    
    
    
    
    
    
    Market Value ofSecurities, Under
    
    
    
    Options/ SARs
    
    
    
    
    
    
    
    
    SecuritiesOptions/SARs
    
    
    
    Granted to
    
    
    
    Exercise
    
    
    
    Underlying Options/NEO
    
    
    Granted
    
    
    
    Employees in
    
    
    
    or
    
    
    
    SARs on the Date of
    
    
    
    ExpirationName
    
    
    (#)
    
    
    
    Financial Year
    
    
    
    Base Price ($/Security)
    
    
    
    Grant ($/Security)
    
    
    
    Date(a)
    
    
    (b)
    
    
    
    (c)
    
    
    
    (d)
    
    
    
    (e)
    
    
    
    (f)W. Gordon Lancaster, CFO
    
    
    
    250,000
    
    
    
    
    35.29
    %
    
    
    Cdn. $5.68
    
    
    Cdn. $1,420,000
    
    
    December 31, 2009
 Aggregated Option Exercises During the year ended December 31, 2004, Mr.. Chua exercised 500,000 options at Cdn. $2.50 per
common share and Mr. Moench exercised options for 45,000 common shares at Cdn. $2.50 per common
share. No other Named Executive Officers exercised options in 2004. 75




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Number of Securities
    
    
    Value of Unexercised InUnderlying Unexercised
    
    
    -the-Money Options atShares Acquired
    
    
    
    
    
    
    Options at December 31, 2004
    
    
    December 31, 2004on Exercise
    
    
    Value Realized
    
    
    (#)
    
    
    ($U.S.)Name
    
    (#)
    
    
    ($U.S.)
    
    
    Exercisable/Unexercisable
    
    
    Exercisable/UnexercisableE. Leon Daniel
    
    
    
    
    
    
    
    
    
    
    666,667/0
    
    
    
    351,782/0David R. Martin
    
    
    
    
    
    
    
    
    
    
    3,400,000 / 0
    
    
    
    7,176,334/0Patrick Chua
    
    
    500,000
    
    
    
    417,355
    
    
    
    36,000/24,000
    
    
    
    Gerald Moench
    
    
    45,000
    
    
    
    10,650
    
    
    
    30,000/20,000
    
    
    
    W. Gordon Lancaster
    
    
    
    
    
    
    
    
    
    
    100,000/150,000
    
    
    
    
 Option and SAR Repricings No options or stock appreciation rights were re-priced during the year ended December 31, 2004. Defined Benefit and Actuarial Plan We do not presently provide a pension plan for our employees. However, in 2001 we 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 us 50% starting in 2001 and increasing 10% per year thereafter to a
maximum of 100%. Our matching contributions to the 401(k) Plan were $0.2 million per year for 2004
and 2003 and $0.1 million for 2002. Employment Contracts, Termination of Employment and Change-In-Control Arrangements We have written contracts of employment with Messrs. E. Leon Daniel and W. Gordon Lancaster.
Otherwise, we have 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 we have 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 we 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 our employee benefit programs on
the same basis as all of our other employees. As of January 1, 2004, we entered into an employment contract with Mr. 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 our 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. We 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, Mr. 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. 76




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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 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, 2004, there were 1,045,712 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, 2004, there were 5,139,386 unallocated
shares available to be issued from our Plan. Our Board of Directors has the right to amend, modify or terminate our Plan. However, any amendment
to the 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, 2004, our Compensation Committee consisted of Messrs. R. Edward
Flood, Howard R. Balloch and J. Steven Rhodes. Mr. Rhodes was appointed to the Compensation
Committee on April 29, 2004. Board Compensation Committee Report on Executive Compensation 77




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Our executive compensation program is administered by the Compensation Committee. The members of
the Compensation Committee are all outside, unrelated directors. Following review and approval by
the Compensation Committee, decisions relating to executive compensation are reported to, and
approved by, the full Board of Directors. The Compensation Committee has directed the preparation
of this report and has approved its contents and its submission to shareholders. Our approach to executive compensation program is motivated by a desire to align the interests of
our executive officers as closely as possible with the interests of Ivanhoe and its shareholders as
a whole. In determining the nature and quantum of compensation for our executive officers we are
seeking 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; 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; and to recognize that the successful
implementation of Ivanhoes corporate strategy cannot necessarily be measured, at this stage of its
development, with reference to quantitative measurement criteria of corporate or individual
performance. We take all of these factors into account in formulating our recommendations to the
Board of Directors respecting the compensation to be paid to each of our executive officers. 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 common shares or incentive 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 Compensation Committee is also responsible
for considering grants of equity and equity incentives to non-executive management personnel under
Ivanhoes Plan. 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, including
prevailing industry demand for personnel having comparable skills and performing similar duties,
the compensation the individual could reasonably expect to receive from a competitor and Ivanhoes
ability to pay. We also consider recommendations from outside compensation consultants and use
compensation data obtained from publicly available sources. We believe that the salaries we
currently pay to our executive officers reasonably approximate the median level of most of the
comparative compensation data to which we had access. All of our executive officers are eligible to
receive discretionary bonuses, based upon our subjective assessment of Ivanhoes overall
performance in relation to its ongoing implementation of corporate strategy and achievement of
corporate objectives and of each executive officers contribution to such performance and
achievement. Incentive bonuses awarded for the 2004 fiscal year consisted of 50% cash and 50%
common shares issued at fair market value under the Share Bonus 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, as and when we consider it warranted, recommendations to the Board of
Directors respecting 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 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 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. Although Ivanhoe has, in the past, relied heavily upon incentive stock options to compensate its
executive officers, we do not have a policy of granting additional incentive stock options to our
executive officers on an annual basis. We continue to believe, however, 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. Other factors influencing our recommendations respecting the nature and scope of the
equity compensation and equity incentives to be awarded to our executive officers in a given year
include: awards made in previous years and, particularly in the case of equity incentives, the
number of incentive stock options that remain outstanding and exercisable from grants in previous
years and the exercise price and the remaining exercise term of those outstanding stock options. 78




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With effect as of January 1, 2004, Ivanhoe granted to Mr. Lancaster, the Corporations Chief
Financial Officer, incentive stock options exercisable to purchase up to 250,000 common shares at a
price of Cdn.$5.68 per share. Otherwise, Ivanhoe did not grant any incentive stock options to its
executive officers during 2004. The compensation paid to our Chief Executive Officer for the fiscal year ended December 31, 2004
was based on the same basic factors and criteria used to determine 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 quantitative performance criteria
when setting his compensation. In determining an appropriate level of compensation for our Chief
Executive Officer, we subjectively and qualitatively analyze Ivanhoes overall performance in
relation to its ongoing implementation of corporate strategy and achievement of corporate
objectives and of our Chief Executive Officers contribution to such performance and achievement.
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 Compensation
Committee based on such criteria as the Committee may determine from time to time. We awarded a
bonus of $90,000 to our Chief Executive Officer in respect of the 2004 fiscal year. This bonus
consisted of 50% cash and 50% common shares issued at fair market value under the Share Bonus Plan.
In determining the quantum of our Chief Executive Officers bonus, the principal factor we took
into account were his efforts in generating new project opportunities in Iraq and Colombia and in
negotiating the terms of our proposed acquisition of Ensyn. Submitted on behalf of the Compensation Committee: Mr. Howard R. Balloch
Mr. R. Edward Flood
Mr. J. Steven Rhodes Performance Graph The following graph and table compares the cumulative shareholder return on a $100 investment in
our common shares to a similar investment in companies comprising the S&P/TSX Composite Index,
including dividend reinvestment, for the period from December 31, 1999 to December 31, 2004. (PERFORMANCE GRAPH) 79




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##### 



As at December 31,(Cdn.$)1999
    
    
    2000
    
    
    2001
    
    
    2002
    
    
    2003
    
    
    2004Ivanhoe Energy Inc.
    
    $
    100
    
    
    $
    276
    
    
    $
    83
    
    
    $
    27
    
    
    $
    180
    
    
    $
    113S&P/TSX Composite
Index
    
    $
    100
    
    
    $
    107
    
    
    $
    94
    
    
    $
    82
    
    
    $
    104
    
    
    $
    119
 
 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, 2005. 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)
    
    
    27.44Flat B, 31st FloorPrimrose Court56A Conduit RoadHong KongCommon Shares
    
    Directors and Executive Officers as a Group
    
    
    53,858,498
    (3)
    
    
    30.77(11 persons)
   (1)
    
    Beneficial ownership is determined in accordance with the rules of the SEC 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 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 5,176,667 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 as at February 2, 2005 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 StockOwnership (1)
    
    
    of Class
    
    
    Options Included in (a)Title of Class
    
    Name of Beneficial Owner
    
    (a)
    
    
    (b)
    
    
    (c)Common Shares
    
    David R. Martin
    
    
    4,351,672
    
    
    
    2.51
    
    
    
    3,400,000Common Shares
    
    Robert M. Friedland
    
    
    46,611,725
    (2)
    
    
    27.44
    
    
    
    Common Shares
    
    E. Leon Daniel
    
    
    1,286,163
    
    
    
    0.75
    
    
    
    666,667Common Shares
    
    John A. Carver
    
    
    563,302
    
    
    
    0.33
    
    
    
    250,000Common Shares
    
    R. Edward Flood
    
    
    75,029
    
    
    
    0.04
    
    
    
    50,000Common Shares
    
    Shun-ichi Shimizu
    
    
    98,500
    
    
    
    0.06
    
    
    
    Common Shares
    
    J. Steven Rhodes
    
    
    300,000
    
    
    
    0.18
    
    
    
    300,000Common Shares
    
    W. Gordon Lancaster
    
    
    273,100
    
    
    
    0.16
    
    
    
    250,000Common Shares
    
    Patrick Chua
    
    
    75,300
    
    
    
    0.04
    
    
    
    60,000Common Shares
    
    Gerald Moench
    
    
    73,707
    
    
    
    0.04
    
    
    
    50,000Common Shares
    
    Howard R. Balloch
    
    
    150,000
    
    
    
    0.09
    
    
    
    150,000Common Shares
    
    All directors and executive officers as a group(11 persons)
    
    
    53,858,498
    (3)
    
    
    30.77
    
    
    
    5,176,667
   (1)
    
    Beneficial ownership is determined in accordance with the rules of the SEC 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 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 5,176,667 unissued common shares issuable to directors and senior officers upon
exercise of incentive stock options. Securities Authorized for Issuance under Equity Compensation Plans Our shareholders have approved our 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, 2004: 80




---



##### 



Number of securities remainingNumber of securities to be issued
    
    
    Weighted-average exercise
    
    
    available for future issuance underupon exercise of outstanding options,
    
    
    price of outstanding options,
    
    
    equity compensation plans (excludingPlan category
    
    warrants and rights
    
    
    warrants and rights
    
    
    securities reflected in column (a))(a)
    
    
    (b)
    
    
    (c)Equity compensation
plans approved by
Securityholders
    
    
    8,245,760
    
    
    
    $2.65
    
    
    
    5,139,386Equity compensation
plans not approved
by Securityholders
    
    
    
    
    
    
    
    
    
    
    Total
    
    
    8,245,760
    
    
    
    $2.65
    
    
    
    5,139,386
 
 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Transactions with Management and Others We borrowed $1.25 million from Ivanhoe Capital Finance Ltd., a company wholly owned by Mr. Robert
M. Friedland. The unsecured loan was repaid with accrued interest, at U.S. prime plus 3%, in
September 2003. We 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 party 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, Beijing and Singapore. We also share the costs of employing
administrative and non-executive management personnel at these offices. During the year ended
December 31, 2004, our share of costs for the Vancouver and Singapore offices was $0.9 million and
we were reimbursed $0.3 million by Mr. Friedlands companies for their share of costs for our
Beijing office. During the year ended December 31, 2004, a company controlled by Mr. Shun-ichi Shimizu received
$0.7 million for consulting services and out of pocket expenses. 
 ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES The following table summarizes the aggregate fees billed by Deloitte & Touche LLP: Year ended December 31,Cdn.($000)2004
    
    
    2003Audit Fees (a)
    
    $
    314
    
    
    $
    183Audit Related Fees (b)
    
    
    134
    
    
    
    Tax Fees (c)
    
    
    124
    
    
    
    43$
    572
    
    
    $
    226
  (a)
    Fees for audit services billed in 2004 and 2003 consisted of:  
    Audit of our annual financial statements
    Reviews of our quarterly financial statements
    Comfort letters, statutory and regulatory audits, consents and other services related to
Canadian and U.S. securities regulatory matters
    Review of our internal controls over financial reporting in compliance with the
requirements of the Sarbanes Oxley Act of 2002.  (b)
    Fees for audit related services billed in 2004 consist of financial and tax analysis in
contemplation of our proposed merger with Ensyn Group, Inc.  (c)
    Fees for tax services billed in 2004 and 2003 consisted of tax compliance and tax planning
and advice:  
    Fees for tax compliance services totaled Cdn.$58,000 and Cdn.$36,000 in 2004 and 2003,
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 assistanceii.
    Preparation of expatriate tax returnsiii.
    Assistance with tax return filings in certain foreign jurisdictions  
    Fees for tax planning and advice services totaled Cdn.$66,000 and Cdn.$7,000 in 2004 and
2003, 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: 81




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##### 



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 our management to determine
that they are permitted under the rules and regulations concerning auditor independence promulgated
by 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 us or our subsidiaries to render audit or non-audit
services, the engagement is 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. 
 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 on Form
10-K: (a)
    
    
    1.
    
    
    Financial Statements:Deloitte & Touche LLP Report of Independent Registered Chartered
Accountants on Consolidated Balance Sheets of Ivanhoe Energy
Inc. as at December 31, 2004 and 2003 and Consolidated
Statements of Loss and Shareholders Equity and Cash Flow of
Ivanhoe Energy Inc. for the years ended December 31, 2004, 2003
and 2002Consolidated Balance Sheets of Ivanhoe Energy Inc. as at December
31, 2004 and 2003Consolidated Statements of Loss of Ivanhoe Energy Inc.
for the years ended December 31, 2004, 2003 and 2002Consolidated Statements of Shareholders Equity for the years
ended December 31, 2004, 2003 and 2002Consolidated Statements of Cash Flow of Ivanhoe Energy Inc. for
the years ended December 31, 2004, 2003 and 2002.2.
    
    
    Financial Statement Schedules:Quarterly Financial Data in Accordance with Canadian and U.S.
GAAP (Unaudited)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. as amended May 15, 2001
 82




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##### 



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 PetroChina Company Limited and
Sunwing Energy Ltd. dated March 29, 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 Venture Agreement and Operating Agreement dated July 1,
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)10.6
    
    
    Joint Venture Agreement and Operating Agreement dated October 1,
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)10.7
    
    
    Consulting Agreement dated January 13, 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)10.8
    
    
    Petroleum Contract dated September 19, 2002 between China
National Petroleum Corporation and Pan-China Resources Ltd. 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)10.9
    
    
    Strategic Development Alliance Letter Agreement dated September
26, 2002 between Ivanhoe Energy Inc. 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)10.10
    
    
    Cooperation Agreement between Ensyn Petroleum International Ltd.
and Ivanhoe Energy (USA) Inc. dated May 30, 2003 (Incorporated
by reference to Exhibit 10.14 of Form 10-K filed with the
Securities and Exchange Commission on March 15 , 2004)10.11
    
    
    Employees and Directors Equity Incentive Plan (Incorporated by
reference to Exhibit 10.15 of Form 10-K filed with the
Securities and Exchange Commission on March 15 , 2004)10.12
    
    
    Agreement in Principle for GTL Project Development between
Syntroleum Corporation and the Company dated June 18, 2003
(Incorporated by reference to Exhibit 10.16 of Form 10-K filed
with the Securities and Exchange Commission on March 15 ,
2004)10.13
    
    
    Amendment No. 3 to Master License Agreement between Syntroleum
Corporation and the Company dated July 1, 2003 (Incorporated by
reference to Exhibit 10.17 of Form 10-K filed with the
Securities and Exchange Commission on March 15 , 2004)10.14
    
    
    Heads of Agreement between China International Trust and
Investment Corporation and the Company dated November 18, 2003
(Incorporated by reference to Exhibit 10.19 of Form 10-K filed
with
 83




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##### 



the Securities and Exchange Commission on March 15 , 2004)10.15
    
    
    Stock Purchase and Shareholders Agreement by and among Ensyn
Group, Inc., Ensyn Petroleum International Ltd. and Ivanhoe
Energy (USA) Inc. dated January 15, 2004 (Incorporated by
reference to Exhibit 10.20 of Form 10-K filed with the
Securities and Exchange Commission on March 15 , 2004)10.16
    
    
    LAK Ranch Farm-in Agreement between Derek Resources (USA) Inc.
and Ivanhoe Energy (USA) Inc. dated January 15, 2004
(Incorporated by reference to Exhibit 10.21 of Form 10-K filed
with the Securities and Exchange Commission on March 15 ,
2004)10.17
    
    
    Farm-out Agreement by and among Richfirst Holdings Limited,
Pan-China Resources Limited, Sunwing Energy Ltd. and the Company
dated January 18, 2004 (Incorporated by reference to Exhibit
10.22 of Form 10-K filed with the Securities and Exchange
Commission on March 15 , 2004)10.18
    
    
    Farmout and Exploration Agreement, Knights Landing Starkey Sand
Development Program between Ivanhoe Energy (USA) Inc. and
Nahabedian Exploration Group, LLC dated February 17, 2004
(Incorporated by reference to Exhibit 10.23 of Form 10-K filed
with the Securities and Exchange Commission on March 15 ,
2004)10.19
    
    
    Agreement and Plan of Merger dated December 11, 2004 by and
among Ivanhoe Energy Inc., Ivanhoe Merger Sub, Inc. and Ensyn
Group, Inc. (Incorporated by reference to Exhibit 2.1 of Form
8-K filed with the Securities and Exchange Commission on
December 15 , 2004)10.20
    
    
    Voting Agreement dated December 11, 2004 by and by and among
Ivanhoe Energy Inc, Ensyn Group, Inc. and Robert M. Friedland.
(Incorporated by reference to Exhibit 99.1 of Form 10-K filed
with the Securities and Exchange Commission on December
15 , 2004)10.21
    
    
    Employment Agreement dated April 30, 2002 between Ivanhoe Energy
Inc. and E. Leon Daniel10.22
    
    
    Employment Agreement dated November 25, 2003 between Ivanhoe
Energy Inc. and W. Gordon Lancaster14.1
    
    
    Code of Business Conduct and Ethics (Incorporated by reference
to Exhibit 14.1 of Form 10-K filed with the SEC on March 15,
2004)21.1
    
    
    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(b)
    
    
    
    
    
    
    
    
    
    Reports on Form 8-K:
 December 11, 2004
    
    Agreement and Plan of Merger with Ensyn Group, Inc., a Delaware
corporation
 84




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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 INC.By: /s/ E.

Leon DanielName: E. Leon DanielTitle: President and Chief Executive Officer Dated: March 3, 2005
 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 3, 2005/s/           W. GORDON LANCASTER
W. Gordon Lancaster
    
    Chief Financial Officer
(Principal Financial and
Accounting Officer)
    
    March 3, 2005/s/           DAVID R. MARTIN
David Martin
    
    Chairman of the Board and Director
    
    March 3, 2005/s/           ROBERT M. FRIEDLAND
Robert M. Friedland
    
    Deputy Chairman and Director
    
    March 3, 2005/s/           JOHN A. CARVER
John A. Carver
    
    Director
    
    March 3, 2005/s/           R. EDWARD FLOOD
R. Edward Flood
    
    Director
    
    March 3, 2005/s/           SHUN-ICHI SHIMIZU
Shun-ichi Shimizu
    
    Director
    
    March 3, 2005/s/           HOWARD R. BALLOCH
Howard Balloch
    
    Director
    
    March 3, 2005/s/          J. STEVEN RHODES
J. Steven Rhodes
    
    Director
    
    March 3, 2005
 85




---



##### 



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. as amended May 15, 200110.1
    
    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 PetroChina Company Limited and Sunwing Energy Ltd. dated March 29,
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 Venture Agreement and Operating Agreement dated July 1, 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)10.6
    
    Joint Venture Agreement and Operating Agreement dated October 1, 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)10.7
    
    Consulting Agreement dated January 13, 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)10.8
    
    Petroleum Contract dated September 19, 2002 between China National Petroleum Corporation and
Pan-China Resources Ltd. 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)10.9
    
    Strategic Development Alliance Letter Agreement dated September 26, 2002 between Ivanhoe Energy Inc.
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)10.10
    
    Cooperation Agreement between Ensyn Petroleum International Ltd. and Ivanhoe Energy (USA) Inc. dated
May 30, 2003 (Incorporated by reference to Exhibit 10.14 of Form 10-K filed with the Securities and
Exchange Commission on March 15, 2004)10.11
    
    Employees and Directors Equity Incentive Plan (Incorporated by reference to Exhibit 10.15 of Form
10-K filed with the Securities and Exchange Commission on March 15, 2004)10.12
    
    Agreement in Principle for GTL Project Development between Syntroleum Corporation and the Company
dated June 18, 2003 (Incorporated by reference to Exhibit 10.16 of Form 10-K filed with the
Securities and Exchange Commission on March 15, 2004)10.13
    
    Amendment No. 3 to Master License Agreement between Syntroleum Corporation and the Company dated July
1, 2003 (Incorporated by reference to Exhibit 10.17 of Form 10-K filed with the Securities and
Exchange Commission on March 15, 2004)10.14
    
    Heads of Agreement between China International Trust and Investment Corporation and the Company dated
November 18, 2003 (Incorporated by reference to Exhibit 10.19 of Form 10-K filed with the Securities
and Exchange Commission on March 15, 2004)10.15
    
    Stock Purchase and Shareholders Agreement by and among Ensyn Group, Inc., Ensyn Petroleum
International Ltd. and Ivanhoe Energy (USA) Inc. dated January 15, 2004 (Incorporated by reference to
Exhibit 10.20 of Form 10-K filed with the Securities and Exchange Commission on March 15, 2004)10.16
    
    LAK Ranch Farm-in Agreement between Derek Resources (USA) Inc. and Ivanhoe Energy (USA) Inc. dated
January 15, 2004 (Incorporated by reference to Exhibit 10.21 of Form 10-K filed with the Securities
and Exchange Commission on March 15, 2004)10.17
    
    Farm-out Agreement by and among Richfirst Holdings Limited, Pan-China Resources Limited, Sunwing
Energy Ltd. and the Company dated January 18, 2004 (Incorporated by reference to Exhibit 10.22 of
Form 10-K filed with the Securities and Exchange Commission on March 15, 2004)10.18
    
    Farmout and Exploration Agreement, Knights Landing Starkey Sand Development Program between Ivanhoe
Energy (USA) Inc. and Nahabedian Exploration Group, LLC dated February 17, 2004 (Incorporated by
reference to Exhibit 10.23 of Form 10-K filed with the Securities and Exchange Commission on March
15, 2004)10.19
    
    Agreement and Plan of Merger dated December 11, 2004 by and by and among Ivanhoe Energy Inc., Ivanhoe
Merger Sub, Inc. and Ensyn Group, Inc. (Incorporated by reference to Exhibit 2.1 of Form 8-K filed
with the Securities and Exchange Commission on December 15, 2004)
 90




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Exhibit No.
    
    Description10.20
    
    Voting Agreement dated December 11, 2004 by and by and among Ivanhoe Energy Inc, Ensyn Group, Inc.
and Robert M. Friedland. (Incorporated by reference to Exhibit 99.1 of Form 10-K filed with the
Securities and Exchange Commission on December 15, 2004)10.21
    
    Employment Agreement dated April 30, 2002 between Ivanhoe Energy Inc. and E. Leon Daniel10.22
    
    Employment Agreement dated November 25, 2003 between Ivanhoe Energy Inc. and W. Gordon Lancaster14.1
    
    Code of Business Conduct and Ethics (Incorporated by reference to Exhibit 14.1 of Form 10-K filed
with the SEC on March 15, 2004)21.1
    
    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
 (b) Reports on Form 8-K: December 11, 2004 Agreement and Plan of Merger with Ensyn Group, Inc., a Delaware corporation 91