IVANHOE ENERGY INC - 10-K Annual Report

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.

The aggregate market value of the voting stock held by non-affiliates of the Registrant on June 28, 2002 based on the closing price on the NASDAQ National Market on that date, was $121,378,767.

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 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 3, 2003 was $0.67 ($1.00 = Cdn.$1.485). 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.

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.

Certain statements in this document are “forward-looking statements”. 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 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 Form 10-K Annual Report 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 Form 10-K Annual Report.

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/.

We are an international energy company engaged in the development of gas-to-liquids projects, enhanced recovery and conventional exploration and production. We were incorporated pursuant to the laws of the Yukon Territory, 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.

Ivanhoe Energy Inc. is a company focused on three major strategies: (1) production of clean fuels from natural gas using gas-to-liquids (“GTL”) technology; (2) enhanced oil recovery (“EOR”) and natural gas projects, on a production-sharing basis, with national petroleum companies and (3) conventional exploration and production (“E&P”), primarily natural gas in the U.S.

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 explorations rights with Aera in return for 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 into China by acquiring Sunwing Energy Ltd. (“Sunwing”), an oil and gas E&P company. 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 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 entitles us to use the Syntroleum proprietary process in an unlimited number of GTL projects throughout the world, excluding North America, China and India.

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. Our negotiations with Qatar Petroleum for a development and production-sharing contract are currently at an advanced and detailed stage. See “Gas-to-Liquids Projects”.

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. 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 are waiting further 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”.

Our mission is to increase shareholder value by developing business opportunities in 1) GTL conversion projects using our licensed Syntroleum technology, 2) EOR development projects, and 3) E&P projects. In pursuing these three business development areas, we are focused on achieving a balance in our short, medium and long-term goals. Our long-term priority is on GTL production of ultra clean fuels. Our medium term strategy is to concentrate on natural gas exploration and development. Short term, we are focused on EOR and E&P projects that can be implemented and achieve early production and cash flow. During 2002 these strategies continued to mature and gain focus.

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 Oman to obtain rights to stranded natural gas deposits to use as feedstock for GTL projects.

The cornerstone 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.

Our activities in China also have the potential to contribute to our medium-term growth. 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. Sunwing has established crude oil production at its Dagang project. We remain encouraged by the results achieved in our production program at Dagang and intend to proceed with the development phase once Chinese government authorities approve our development plan. Based on our decision to concentrate on larger projects in China, we decided to dispose of our smaller Daqing project. For a further description of our E&P and EOR projects in the U.S. and China, see “Oil and Gas Properties”.

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.

We hold a non-exclusive master license entitling us to use Syntroleum’s proprietary GTL process in an unlimited number of projects in all areas of the world, other than North America, China and India, with no limit on production volume.

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, 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.

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 includes 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. Under this proposal we intend to produce 121,000 barrels of NGL, such as condensate, propane, butane and ethane and 185,000 barrels of GTL product per day. This proposal would also provide 220,000 barrels of agricultural quality water per day. This proposal contemplates the largest facility of its kind in the world with an estimated total cost of approximately $5 billion. Negotiations with Qatar Petroleum (QP) and the Government of the State of Qatar have been ongoing for several months following the completion of feasibility studies. Technical and financial due diligence has been completed and a Heads of Agreement is being negotiated.

The feasibility studies we have undertaken for Egypt contemplate the natural gas feedstock being purchased, rather than developed, and production capacity in the order of 45,000 barrels per day. The results of the feasibility studies are being utilized during the course of commercial discussions with Egyptian authorities. We are still at the early stages of discussion with the Government of Oman for a GTL project.

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 naphtha. Based on our ongoing commercialization studies and the growing demand for cleaner sources of energy in Japan, we have incorporated a new subsidiary in Japan to facilitate the potential future participation by Japanese companies in the Qatar GTL project. Should we obtain the right to develop this project, we intend to assign up to 5% of our interest to our new Japanese subsidiary, GTL Japan Corporation (“GTLJ”). GTLJ would then invite Japanese companies from the refining and distribution, exploration and production, trading and manufacturing industry sectors to invest in GTLJ. The proceeds raised would be used to fund up to an estimated $250 million of project costs, including front-end engineering and design.

In 2000, we signed a letter of intent to invest $21.0 million to participate as a 13% partner in Syntroleum’s Sweetwater GTL project in Western Australia. The project was a 10,000 barrels per day plant that would produce specialty products such as lubricants, industrial fluids and liquid normal paraffin, as well as synthetic fuels. We made a $2.0 million advance for front-end engineering and other costs. The balance of the investment was subject to a number of conditions, including Syntroleum’s obligation to arrange project financing.

During 2002, the project was cancelled by Syntroleum. In June 2002, we signed a letter of intent with Syntroleum to participate in its U.S. Department of Energy (“DOE”) Fuels Project at a cost of $5.0 million. Our participation is contingent upon our success in signing a GTL

project contract in Qatar. Our cost of participating in the DOE Fuels Project is to be offset by $2.0 million of our investment in Sweetwater.

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 Province in China. Set forth below is a description of our material oil and gas properties.

Over the past five 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. We cannot assure you that any of our other prospects in California will result in the development of commercially viable production.

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. We have a right to a working interest ownership in, and Aera has the right to act as the operator for, any drillable prospects in which Aera elects to participate.

Except for those prospect areas of mutual interest (“AMIs”) previously designated by us and accepted by Aera, our exclusive rights to explore Aera’s properties expired in September 2001. 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. Although the Aera exploration agreement provides that Aera’s working interest in these prospects will range from a minimum of 25% to a maximum of 87.5%, we have negotiated different working interest allocations with Aera. Aera is obliged to assign to us any working interest in the prospect that it does not retain. 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.

The properties covered by the Aera exploration agreement are located in Kern, Kings, Tulare, Fresno, San Benito, Monterey and San Luis Obispo Counties. Using the extensive proprietary seismic and technical databases owned by Aera and supplemented by us, we have identified 30 prospects within 12 prospect AMIs covering approximately 76,000 gross acres. Of the 12 prospect AMIs we have submitted, Area 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.

Our first project under the Aera exploration agreement was in the South Midway field, in which Aera elected not to participate. We therefore own a 100% working interest and a 93% net revenue interest in the project. Aera receives royalties pursuant to our exploration agreement. By the end of 2002, we had drilled 41 wells, 35 of which are producing oil wells. We are currently producing approximately 525 gross barrels per day a slight decline from the peak production level of 625 gross barrels per day achieved in the fourth quarter of 2002. We implemented a full-scale cyclic steam injection project during 2002, which provided for more than a 300 gross barrel per day increase in production levels. Our drilling in the South Midway area has identified additional new pools in the field, and based on this success, we have arranged a $5.0 million credit facility to fund an additional 20 wells and cyclic steam expansion program that is expected to provide additional production volume increases during the second half of 2003.

The second exploratory prospect was a gas test in the Belgian Anticline field area. The well found the prospective gas sands, but they had been partially depleted by other nearby wells.

The third exploration prospect area was at Northwest Lost Hills where we began drilling in August 2001 the Northwest Lost Hills #1-22 well, located in Kern County and operated by Aera. The well lies five miles northwest of, and on a trend with, the Bellevue No. 1 gas discovery drilled by Berkley Petroleum Corp. In the 9,300 gross acres owned and under option encompassing the Northwest Lost Hills prospect, we hold, on average, a 39% working interest. We have a 42% working interest in the NWLH #22-1 well.

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. Testing operations have been suspended while we seek a partner to share the costs of the testing program. Accordingly, the commercial success of this well has not yet been determined.

The next prospect we are likely to drill is in the northern part of the South Belridge area, which we have designated Amethyst. We currently hold a 15% working interest in the prospect. We originally expected to commence drilling the prospect in early 2002, but delayed drilling in order to shoot and evaluate additional seismic data. We have completed interpreting this additional seismic data and expect to begin drilling this prospect during 2003.

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 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. All costs of carrying out the program will be borne equally by Prime and Ivanhoe. The 3-D seismic program is intended to identify prospects for exploration drilling. Once prospects have been identified, each party may elect to participate in a drilling program. We started evaluating the results of the program in the second half of 2001 and to date three drillable prospects have been identified. Our evaluation remains ongoing while we look for potential farm-in candidates for these prospects. Our working interests over this exploration area currently range from 17.5% to 50%.

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 property in the Spraberry Trend of the West Texas Permian Basin in Midland County, Texas. During 2002, after determining that most of the wells producing in the Spraberry Trend contained little upside for reservoir and production enhancements, we elected to sell a majority of our interests in these wells. These sales generated cash proceeds of approximately $3.0 million. We currently have a working interest of 31% in 16 wells and 48% in 4 wells on approximately 1,760 gross acres. We retained our interests in the Apache Flats area because the wells in that area have shown higher levels of daily production. We hold a 40% working interest in 5 wells in Apache Flats on approximately 400 gross acres covered by a farm-out agreement. Following the property sales, we are producing approximately 120 net Boe/d from the 25 wells in West Texas. Discovery is the operator of the West Texas Properties.

We have leased mineral rights in approximately 49,000 gross acres in East Texas under a joint venture with Unocal. Unocal is the operator of the joint venture and will fund the drilling costs for the first several exploration wells to offset the $10.1 million in leasehold, seismic and processing costs we have already incurred. After our respective investments in the joint venture have been equalized, we will share exploration, development and infrastructure costs equally.

In late 2001, and during the first half of 2002, three exploratory wells were drilled. 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. The drilling costs for these wells were carried by our 50% partner, Unocal, as a part of the agreement for their participation. Since mid-2002, our activities in East Texas have been very limited. Early in 2003, we reached an agreement with a third party to further test the potential for natural gas production from the Rodessa and Pettit Sands in two of the wells drilled on the Creslenn Ranch Prospect in Henderson County. We continue to search for third parties to fund our share of exploration in the remaining prospects in East Texas.

In March of 2001, we entered into a joint venture with Hay Exploration, Inc. to explore for natural gas in the Rome Trough of eastern Kentucky. We each held a 50% interest. We identified three prospect areas covering 15,000 net acres and during 2001 we drilled an exploration well in each prospect area. However, based on our assessment that these prospects contain no commercial quantities of gas, we relinquished our participation in these properties to Hay and have no further obligations on these prospects.

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

Our first project in China was Daqing, a production-sharing contract with CNPC, which covered an area of 8,100 gross acres in the Zhaozhou oilfield in Daqing, Heilongjiang Province, China (the “Daqing Project”). We initially undertook the Daqing Project on the expectation that we would be able to acquire rights to additional land blocks. We were unable to acquire the additional blocks necessary to provide critical mass and divested our interest in January 2002 for $2.4 million and a right to an overriding royalty on future production.

Sunwing’s producing asset in China is a 20-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%.

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.

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 period or if we abandon the project earlier.

In 1999, we farmed out a 20% working interest in the Dagang project to Nippon Oil Exploration Limited (“Nippon”) for which Nippon agreed to fund $6.0 million of pilot testing expenditures. At the end of the pilot phase, Nippon elected to relinquish its 20% working interest back to us.

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. Our partner, PetroChina, has approved the program, and has recommended to the Central Government that we be allowed to proceed with the development. We expect to receive this Government approval during the first half of 2003, after which the development phase will commence. The current development program will cost approximately $185.0 million over a three-year period and will involve drilling 115 new wells and reworking an additional 29 of the 82 existing wells.

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 producing 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 of at least $18 million. Upon completion of the first phase, Sunwing must relinquish up to 30% of the Zitong block.

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 and incur minimum expenditures 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 hydrocarbon deposit 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 of the participating interest.

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 formation as those tapped by the existing wells, but Sunwing’s wells must be no closer than 1,000 meters from the existing wells.

In the first quarter of 2003, we established an office in Chengdu, the capital of Sichuan. We 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.

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

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

Sunwing will assist CITIC 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, but the geographical scope of our license does not currently include China.

CITIC 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 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’s 30% participating interest in the project into a 20% equity interest in Sunwing. CITIC 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.

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 potential competitive advantage.

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

We are in advanced negotiations with state-owned QP for a development and production-sharing contract, which is to form the basis for a large GTL project in Qatar. We can give no assurances as to when or if we will be able to conclude such a contract with QP. We are also exploring GTL project opportunities in Egypt and Oman, for which no conclusion has been reached.

A conflict involving Iraq could harm our business in the short to medium term by making it difficult or impossible to continue our pursuit of GTL projects in Qatar and other countries in the Middle East or to obtain financing for projects we do succeed in obtaining. It is impossible to predict if or when a military conflict involving Iraq will occur, how long it will last if it does occur, the economic consequences of the conflict for the energy industry, regionally and globally, and how our business might be affected over the longer term.

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 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.

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 exploitation projects 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 not able 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 not able 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 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 shareholders control our business.

Our directors and executive officers, including Robert M. Friedland, collectively own or have rights to acquire approximately 36% of our common stock and control our Board of Directors and determine 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. 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.

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. The oil and gas industry also competes with other industries in supplying energy, fuel and other needs of consumers. See “Risk Factors.”

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. 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.

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.

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

The following tables set forth, for each of the last three fiscal years, our average sales prices and average operating costs per unit of production. In China for 2000, proceeds from the sale of oil produced were credited to our China cost center due to the stage of development of our projects in China. The average sales price realized on China production in 2000 was $28.26 per bbl. Average operating costs include lifting costs and production taxes, but exclude allocated head office engineering support costs, depreciation, depletion and amortization, royalties, income taxes, interest, selling and administrative expenses.

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


(1)	Gross wells are the total number of wells in which an interest is owned.

(2)	Net wells are the sum of fractional interests owned in gross wells.

(3)	After the sale of 4.4 net (7 gross) Spraberry wells in August 2002 and a 50% working interest, or 6.9 net wells, in our remaining Spraberry wells in October 2002.

(4)	After the sale of 3.4 net (4 gross) Daqing wells in January 2002.

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


x		Annual Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. For the fiscal year ended December 31, 2002.
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


Title of each class		Name of each exchange on which registered

Common Shares, no par value		The Toronto Stock Exchange NASDAQ SmallCap Market


			Page

PART I
	Items 1 and 2	Business and Properties		4
		Corporate Overview		4
		Historical Overview		4
		Corporate Strategy		5
		Gas-to-Liquids Projects		6
		Oil and Gas Properties		7
		Risk Factors		10
		Competition		14
		Environmental Regulations		14
		Government Regulations		14
		Employees		14
		Reserves, Production and Related Information		14
	Item 3	Legal Proceedings		16
	Item 4	Submission of Matters to a Vote of Security Holders		16
PART II
	Item 5	Market for Registrant’s Common Equity and Related Stockholder Matters		16
	Item 6	Selected Financial Data		18
	Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations		19
	Item 7A	Quantitative and Qualitative Disclosures About Market Risk		25
	Item 8	Financial Statements and Supplementary Data		27
	Item 9	Changes In and Disagreements with Accountants on Accounting and Financial Disclosure		48
PART III
	Item 10	Directors and Executive Officers of the Registrant		49
	Item 11	Executive Compensation		50
	Item 12	Security Ownership of Certain Beneficial Owners and Management		56
	Item 13	Certain Relationships and Related Transactions		57
PART IV
	Item 14	Disclosure Controls and Procedures		57
	Item 15	Exhibits, Financial Statement Schedules and Reports on Form 8-K		58


	2002		2001		2000		1999		1998

Closing	$	0.63	$	0.63	$	0.67	$	0.69	$	0.65
Low	$	0.64	$	0.62	$	0.64	$	0.64	$	0.63
High	$	0.64	$	0.67	$	0.70	$	0.69	$	0.71
Average Noon	$	0.63	$	0.65	$	0.67	$	0.67	$	0.67


Boe		= barrel of oil equivalent
Bbl		= barrel
MBbl		= thousand barrels
MMBbl		= million barrels
Bbls/d		= barrels per day
Boe/d		= barrels of oil equivalent per day
MBbls/d		= thousand barrels per day
MMBls/d		= million barrels per day
MMBtu		= million British thermal units
Mcf		= thousand cubic feet
MMcf		= million cubic feet
Mcf/d		= thousand cubic feet per day
MMcf/d		= million cubic feet per day



	Average Sales Price						Average Operating Costs

	2002		2001		2000		2002		2001		2000

Crude Oil and Natural Gas ($/Boe)
U.S.	$	22.43	$	21.93	$	27.52	$	6.76	$	7.28	$	10.00
China	$	22.30	$	24.42		—	$	6.49	$	10.50		—



	Productive

	2002		2001		2000

U.S.		—		—		—
China		—		—		—

Total		0


	*Aera Exploration Agreement*


•	South Midway


•	Belgian Anticline


•	Northwest Lost Hills