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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

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:

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.

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

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

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

Documents incorporated by reference: None

TABLE OF CONTENTS

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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:

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

ABBREVIATIONS

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

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

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

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

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ENFORCEABILITY OF CIVIL LIABILITIES

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

AVAILABLE INFORMATION

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

ITEMS 1 AND 2. BUSINESS AND PROPERTIES

CORPORATE OVERVIEW

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

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

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

HISTORICAL OVERVIEW

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

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

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

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

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

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

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

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

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

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

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

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

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

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

CORPORATE STRATEGY

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

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

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

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

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

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

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

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

OIL AND GAS PROPERTIES

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

California

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

Aera Exploration Agreement

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

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

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South Midway

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

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

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Citrus

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

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

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Northwest Lost Hills

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

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Belgian Anticline

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

Other California Prospects

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North South Forty

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

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

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

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Sledge Hamar

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

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Knights Landing

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

Texas

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Spraberry

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

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East Texas

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

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

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

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

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

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

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

China

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

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Dagang Project

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

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

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

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

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

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Sichuan Basin

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

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

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

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

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

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

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

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

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

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

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CITIC Alliance

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

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

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

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

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

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Daqing Project

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

EOR PROJECTS

Ensyn

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

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

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

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

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

Wyoming

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LAK Ranch

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

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

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

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

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

GAS-TO-LIQUIDS PROJECTS

Syntroleum License

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

Syntroleum Process

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

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

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

GTL Prospects

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

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

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

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project costs, including front-end engineering and design.

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

RISK FACTORS

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

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

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

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

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

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

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

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

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

Crude oil and natural gas prices are volatile.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Our largest shareholder, Robert M. Friedland, owns approximately 29% of our common stock and effectively controls our Board of Directors and determines our policies, business and affairs and the outcome of any corporate transaction or other matter, including mergers, consolidations and the sale of all or substantially all of our assets.

In addition, the concentration of our ownership may have the effect of delaying, deterring or preventing a change in control that otherwise could result in a premium in the price of our common stock.

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

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

COMPETITION

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

ENVIRONMENTAL REGULATIONS

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

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

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

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

GOVERNMENT REGULATIONS

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

EMPLOYEES

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