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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON D.C. 20549

FORM 10-K

(Mark One)

[X]		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the fiscal year ended: December 31, 2002

OR

[    ]		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the transition period from                      to

COMMISSION FILE NUMBER: 0-02517

Toreador Resources Corporation
(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code: (214) 559-3933

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

Securities 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. YES X   NO

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

     Indicate by check mark whether the registrant is an accelerated filer (as defined in Securities Exchange Act Rule 12b-2) YES     NO X

     The aggregate market value of the voting common equity of the registrant held by non-affiliates, computed by reference to the closing sales price of such stock, as of June 28, 2002 was $15,297,502. (For purposes of determination of the aggregate market value, only directors, executive officers and 10% or greater stockholders have been deemed affiliates.)

     The number of shares outstanding of the registrant’s common stock, par value $.15625, as of April 10, 2003, was 9,337,517 shares.

DOCUMENTS INCORPORATED BY REFERENCE

     Portions of the registrant’s Proxy Statement for the 2003 Annual Meeting of Stockholders, expected to be filed on or prior to April 30, 2003, are incorporated by reference into Part III of this Form 10-K.

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PART I

ITEM 1. BUSINESS.

GENERAL

     Toreador Resources Corporation, a Delaware corporation, is an independent international energy company engaged in oil and gas exploration, development, production, leasing and acquisition activities. We principally conduct our business through: (i) the exploration for, and the acquisition and development of, oil and natural gas reserves, and (ii) our ownership of perpetual mineral and royalty interests in approximately 2,643,000 gross (1,368,000 net) acres. We currently hold interests in foreign developed and undeveloped oil and gas properties in the Paris Basin, France, the Cendere and Zeynel Fields in Turkey and the Bonasse Field and Southwest Cedros Peninsula License in Trinidad, West Indies. Our domestic properties include 766,000 gross (461,000 net) acres located in the Texas Panhandle and West Texas. In Alabama, Mississippi and Louisiana, we own 1,775,000 gross (876,000 net) acres. We also own various royalty interests in Arkansas, California, Kansas and Michigan covering 102,000 gross (31,000 net) acres. We also own various working interest properties in Texas, Kansas, New Mexico and Oklahoma. For a more detailed description of our properties please see “Item 2. Properties.”

     We were incorporated in 1951 and were formerly known as Toreador Royalty Corporation.

     On December 31, 2001, we completed the acquisition of Madison Oil Company, an independent international exploration and production company, that is now a wholly owned subsidiary. Madison holds interests in approximately 5,043,000 gross acres (3,317,000 net acres) of developed and undeveloped oil and gas properties in the Paris Basin, France, several fields in Turkey, Romania and the Bonasse Field and Southwest Cedros Peninsula License in Trinidad, West Indies.

     See “Glossary of Selected Oil and Gas Oil Terms” at the end of this Item 1 for a definition of certain terms used in this annual report.

BUSINESS STRATEGY

     Our strategic focus during 2002 centered on strengthening our balance sheet through the aggressive repayment of debt, increasing proved reserves, increasing product sales and the disposition of non-strategic assets. The principal elements of the 2002 strategy were:

	•		Reduce the debt owed on our two senior credit facilities through the application of the majority of our free cash flow.
	•		Increase proved reserves with exploration and development drilling.
	•		Increase product sales with improved operating techniques in the Paris Basin.
	•		Disposal of under performing non-strategic assets.

DEVELOPMENTS DURING 2002

     ACQUISITIONS AND MERGERS

     In 2002, we acquired Wilco Turkey Ltd (“WTL”) from Wilco Properties, Inc. (“WPI”). WTL’s primary asset is an interest (ranging from 52.5% to 87.5%) in exploration licenses covering 2.2 million acres in the Thrace Basin and in the central and southeast areas of Turkey. We also acquired from F-Co Holdings Kandamis (“F-Co”) additional interests (ranging from 7.5% to 12.5%) in the same exploration licenses. The purpose of the acquisition was to obtain, explore and possibly develop the acreage covered by the licenses. The acreage in the Thrace Basin is adjacent to or near the acreage we held prior to the acquisition of WTL. In exchange for all of the outstanding common stock of WTL, we have agreed to give WPI an overriding royalty interest in any successful wells we drill on the acreage covered by the exploration licenses we acquired. We have also agreed to give F-Co, in exchange for its interest in the acreage, an overriding royalty interest in any successful wells we drill on the acreage. As of the acquisition date, there were no outstanding liabilities associated with WTL. We did not convey value to WPI or F-Co on the acquisition date, or assume any liabilities; therefore, the fair value of the transaction was zero. We have allocated no value to the assets acquired from WTL and F-Co. WPI is controlled by William I. Lee, a director and shareholder, and F-Co is owned by Peter L. Falb, a director and shareholder.

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     DISPOSAL OF UNDER PERFORMING NON-STRATEGIC ASSETS

     In 2002, we sold several non-strategic oil and gas assets for approximately $4.6 million. Of that amount, approximately 40 percent (40%) of the funds received were captured through the use of the auction Internet site (www.energynet.com) owned by EnergyNet.com, Inc. (a 35%-owned affiliate). The remaining funds were obtained through private negotiated sales.

     ISSUANCE OF SERIES A-1 CONVERTIBLE PREFERRED STOCK

     On November 1, 2002, pursuant to a private placement we issued $925,000 of Series A-1 Convertible Preferred Stock to certain of our directors or entities controlled by certain of our directors.

     The Series A-1 Convertible Preferred Stock is governed by a certificate of designation. The Series A-1 Convertible Preferred Stock was sold for a face value of $25.00 per share, and pays an annual cash dividend of $2.25 per share that results in an annual yield of 9.0%. At the option of the holder, the Series A-1 Convertible Preferred Stock may be converted into common shares at a price of $4.00 per common share. The $4.00 conversion price was higher than the market price of our common stock at the time of issuance. The Series A-1 Convertible Preferred Stock is redeemable at our option, in whole or in part, at any time on or after November 1, 2007. The optional redemption price per share is the sum of (1) $25.00 per share of the Series A-1 Convertible Preferred Stock plus (2) any accrued unpaid dividends, and such sum is multiplied by a declining multiplier. The multiplier is 105% until October 31, 2008, 104% until October 31, 2009, 103% until October 31, 2010, 102% until October 31, 2011, 101% until October 31, 2012, and 100% thereafter. In connection with the securities purchase agreement, the parties entered into a registration rights agreement effective November 1, 2002, among Toreador and the persons party thereto which provides for the registration of the common stock issuable upon conversion of the Series A-1 Convertible Preferred Stock.

     EXPLORATION ACTIVITIES

     TURKEY

     Turkish Permits. We hold 35 exploration licenses on 2.7 million net acres. A number of producing fields in Iran and Iraq trend in a north by northwesterly direction and wrap into southern Turkey through the area encompassing many of our exploration permits. Overall, our net exploration permit position increased 35% in terms of total net acres from December 31, 2001.

     Black Sea Permits. During 2002, we completed a 2D seismic study covering 1,250 kilometers on four of our eight contiguous permits in the Black Sea. Based on the interpretation of the data we have identified at least six gas prospects in the shallow-water western Black Sea. We are operator and hold a 49% working interest in the eight permits.

     Thrace Basin Permits. We drilled two wells on our Thrace Basin permits during 2002. The first well was dry, and the second awaits completion of testing. We own a 100% working interest in the well awaiting completion and we held a 50% working interest in the dry hole.

     ROMANIA

     In early 2003, we expanded our international portfolio when the Romanian government awarded the company a concession for the Viperesti Block in exchange for a staged work commitment. We are a 100% owner and operator of the block that lies in an oil-rich region in east-central Romania in the southeastern foothills of the Carpathian Mountains. Viperesti, which spans 324,000 acres, is surrounded by and on trend with many sizable oil fields to the southwest and northeast. The block is prospective in the Tertiary formations at depths ranging from 4,500-6,000 feet.

     FRANCE

     Nangis and Courtenay Permits. We were awarded two new exploration permits in 2002. The Nangis permit expires in 2005, and the Courtenay permit expires in 2006. The French exploration permits have minimum financial requirements that must be met during their terms. If such obligations are not met, the permits could be subject to forfeiture.

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     UNITED STATES

     West Texas San Andres Oil Recovery Project. We are participating with a 16.67% working interest in this project utilizing horizontal drilling techniques in the San Andres formation at a true vertical depth of 5,000 feet. The project, covering approximately 6,000 acres, is in its early stage of evaluation with one well completed and the second well currently being drilled.

     Bethel Dome Prospect. We participated in the drilling of the second exploratory well drilled on this prospect with a 5.86% working interest. The well is currently being completed in the Travis Peak formation at a depth of 10,100 feet.

MARKETS AND COMPETITION

     In France, we currently sell all of our production to Elf Antar France S.A., the largest purchaser in the area. This production is shipped by truck to Elf’s refinery. Alternative markets are available by pipeline to refineries on the north coast of France. Production in Turkey is sold to refineries in the southern part of the country.

     Our domestic oil and gas production is sold to various purchasers typically in the areas where the oil or gas is produced. Revenues from the sale of oil and gas production accounted for 116%, 89% and 98% of our consolidated revenues for the three years ended December 31, 2002, 2001 and 2000, respectively. Generally, we do not refine or process any of the oil and gas we produce. We are currently able to sell, under contract or in the spot market through the operator, substantially all of the oil and the gas we are capable of producing at current market prices. Substantially all of our oil and gas is sold under short-term contracts or contracts providing for periodic adjustments or in the spot market; therefore, our revenue streams are highly sensitive to changes in current market prices. Our gas is sold to pipeline companies as opposed to end users.

     The oil and gas industry is highly competitive. We encounter strong competition from other independent operators and from major oil companies in acquiring properties, contracting for drilling equipment and securing trained personnel. Many of these competitors have financial and technical resources and staffs substantially larger than those available to us. As a result, our competitors may be able to pay more for desirable leases, and they may pay more to evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources will permit us to do.

     We are also affected by competition for drilling rigs and the availability of tubular goods and certain other equipment. While the oil and gas industry has experienced shortages of drilling rigs and equipment, pipe and personnel in the past, we are not presently experiencing any shortages and do not foresee any such shortages in the near future; however, we are unable to predict how long current market conditions will continue.

     Competition for attractive oil and gas producing properties, undeveloped leases and drilling rights is also strong, and we can give no assurance we will be able to compete satisfactorily in acquiring properties. Many major oil companies have publicly indicated their decision to focus on overseas activities and have been actively marketing certain producing properties for sale to independent oil and gas producers. We cannot ensure we will be successful in acquiring any such properties.

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REGULATION

     INTERNATIONAL

     General. Our current international exploration activities are conducted in France, Turkey, Romania and Trinidad. Such activities are affected in varying degrees by political stability and government regulations relating to foreign investment and the oil and gas industry. Changes in these regulations or shifts in political attitudes are beyond our control and may adversely affect our businesses. Operations may be affected in varying degrees by government regulations with respect to restrictions on production, price controls, export controls, income taxes, expropriation of property, environmental legislation and mine safety.

     Government Regulation. Our current or future operations, including exploration and development activities on our properties, require permits from various governmental authorities, and such operations are and will be governed by laws and regulations governing prospecting, development, production, exports, taxes, labor standards, occupational health, waste disposal, toxic substances, land use, environmental protection and other matters. Compliance with these requirements may prove to be difficult and expensive. See “Item 1. Business – Risk Factors – Company Risks” for further information regarding international government regulation.

     Permits and Licenses. In order to carry out exploration and development of mineral interests or to place these into commercial production, we may require certain licenses and permits from various governmental authorities. There can be no guarantee that we will be able to obtain all necessary licenses and permits that may be required. In addition, such licenses and permits are subject to change and there can be no assurances that any application to renew any existing licenses or permits will be approved. See “Item 1. Business – Risk Factors – Company Risks” for further information regarding our foreign permits and licenses.

     Repatriation of Earnings. Currently, there are no restrictions on the repatriation from France or Turkey of earnings or capital to foreign entities. However, there can be no assurance that any such restrictions or repatriation of earnings or capital from France, Turkey or any other country where we may invest will not be imposed in the future.

     Environmental. The oil and gas industry is subject to extensive and varying environmental regulations in each of the jurisdictions in that we may operate. Environmental regulations establish standards respecting health, safety and environmental matters and place restrictions and prohibitions on emissions of various substances projected concurrently with oil and natural gas. These regulations can have an impact on the selection of drilling locations and facilities, potentially resulting in increased capital expenditures. In addition, environmental legislation may require those wells and production facilities be abandoned and sites reclaimed to the satisfaction of local authorities. We are committed to complying with environmental and operation legislation wherever we operate.

     DOMESTIC

     General. The availability of a ready market for oil and gas production depends upon numerous factors beyond our control. These factors include state and federal regulation of oil and gas production and transportation, as well as regulations governing environmental quality and pollution control, state limits on allowable rates of production by a well or proration unit, the amount of oil and gas available for sale, the availability of adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels. For example, a productive gas well may be “shut-in” due to an oversupply of gas or lack of an available gas pipeline in the areas in which we conduct operations. State and federal regulations generally are intended to prevent waste of oil and gas, protect rights to produce oil and gas between owners in a common reservoir, control the amount of oil and gas produced by assigning allowable rates of production, and control contamination of the environment. Pipelines and gas plants also are subject to the jurisdiction of various federal, state and local agencies.

     Our sales of natural gas are affected by the availability, terms and costs of transportation. The rates, terms and conditions applicable to the interstate transportation of gas by pipelines are regulated by the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act (“NGA”), as well as under Section 311 of the Natural Gas Policy Act (“NGPA”). Since 1985, FERC has implemented regulations intended to increase competition within the gas industry by making gas transportation more accessible to gas buyers and sellers on an open-access, non-discriminatory basis.

     Our sales of oil are also affected by the availability, terms and costs of transportation. The rates, terms, and conditions applicable to the interstate transportation of oil by pipelines are regulated by FERC under the Interstate Commerce Act. FERC has implemented a simplified and generally applicable rate-making methodology for interstate oil pipelines to fulfill the requirements of Title VIII of the Energy Policy Act of 1992 comprised of an indexing system to establish ceilings on interstate oil pipeline rates. The FERC has

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announced several important transportation-related policy statements and rule changes, including a statement of policy and final rule issued February 25, 2000 concerning alternatives to its traditional cost-of-service rate-making methodology to establish the rates interstate pipelines may charge for their services. The final rule revises FERC’s pricing policy and current regulatory framework to improve the efficiency of the market and further enhance competition in natural gas markets.

     With respect to transportation of natural gas on or across the Outer Continental Shelf (“OCS”), FERC requires, as a part of its regulation under the Outer Continental Shelf Lands Act (“OCSLA”) that all pipelines provide open and non-discriminatory access to both owner and non-owner shippers. Although to date FERC has imposed lenient regulation on offshore gathering facilities, it has the authority to exercise jurisdiction under the OCSLA over such gathering facilities, if necessary, to require non-discriminatory access to service. For those facilities transporting natural gas across the OCS that are not considered to be gathering facilities, the rates, terms and conditions applicable to this transportation are regulated by FERC under the NGA and NGPA, as well as the OCSLA. With respect to the transportation of oil and condensate on or across the OCS, FERC requires, as part of its regulation under the OCSLA, that all pipelines provide open and non-discriminatory access to both owner and non-owner shippers. Accordingly, FERC has the authority to exercise jurisdiction under the OCSLA, if necessary, to require non-discriminatory access by shippers to service.

     We conduct operations on federal, state or Indian oil and gas leases. Such operations must comply with numerous regulatory restrictions, including various nondiscrimination statutes, royalty and related valuation requirements, and certain of such operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by the Bureau of Land Management (“BLM”), Minerals Management Service (“MMS”), or other appropriate federal or state agencies.

     Our OCS leases in federal waters are administered by the MMS and require compliance with detailed MMS regulations and orders. The MMS has promulgated regulations implementing restrictions on various production-related activities, including restricting the flaring or venting of natural gas. Under certain circumstances, the MMS may require any operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect our financial condition and operations. On March 15, 2000, the MMS issued a final rule effective June 1, 2000, that amends its regulations governing the calculation of royalties and the valuation of crude oil produced from federal leases. Among other matters, this rule amends the valuation procedure for the sale of federal royalty oil by eliminating posted prices as a measure of value and relying instead on arm’s length sales prices and spot market prices as market value indicators. Because we generally sell our production to third parties and royalties on production from federal leases are paid on the basis of these sales, it is not anticipated that this final rule will have any substantial impact on us.

     The Mineral Leasing Act of 1920 (“Mineral Act”) prohibits direct or indirect ownership of any interest in federal onshore oil and gas leases by a foreign citizen of a country that denies “similar or like privileges” to citizens of the United States. Such restrictions on citizens of a “non-reciprocal” country include ownership or holding or controlling stock in a corporation that holds a federal onshore oil and gas lease. If this restriction is violated, the corporation’s lease can be canceled in a proceeding instituted by the United States Attorney General. Although the regulations of the BLM (which administers the Mineral Act) provide for agency designations of non-reciprocal countries, there are presently no such designations in effect. We own interest in federal onshore oil and gas leases. It is possible that our stockholders may be citizens of foreign countries, which at some time in the future might be determined to be non-reciprocal under the Mineral Act.

     Federal and State Taxation. Federal and state governments may propose tax initiatives that affect us. We are unable to determine what effect, if any, future proposals would have on product demand or our results of operations.

     Environmental Regulation. Exploration, development and production of oil and gas, including operation of saltwater injection and disposal wells, are subject to various federal, state and local environmental laws and regulations. Such laws and regulations can increase the costs of planning, designing, installing and operating oil and gas wells. Our domestic activities are subject to a variety of environmental laws and regulations, including, but not limited to:

	•		Oil Pollution Act of 1990 (OPA);
	•		Clean Water Act (CWA);
	•		Comprehensive Environmental Response, Compensation and Liability Act (CERCLA);
	•		Resource Conservation and Recovery Act (RCRA);
	•		Clean Air Act (CAA); and
	•		Safe Drinking Water Act (SDWA).

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     Our domestic activities are also controlled by state regulations promulgated under comparable state statutes. We also are subject to regulations governing the handling, transportation, storage and disposal of naturally occurring radioactive materials that are found in our oil and natural gas operations. Civil and criminal fines and penalties may be imposed for non-compliance with these environmental laws and regulations. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking certain activities, limit or prohibit other activities due to protected areas or species, can impose certain substantial liabilities for the cleanup of pollution, impose certain reporting requirements, and can require substantial expenditures for compliance.

     Under OPA and CWA, our release of oil and hazardous substances into or upon waters of the United States, adjoining shore lines and wetlands, and offshore areas could result in our being held responsible for the (1) costs of remediating a release, (2) administrative and civil penalties and/or criminal fines, (3) OPA specified damages such as loss of use, and for natural resource damages. The extent of liability could be extensive depending upon the circumstances of the release. Liability can be joint and several and without regard to fault. The CWA also may impose permitting obligations for certain discharges of pollutants and requirements to develop Spill Prevention Control and Countermeasure Plans and Facility Response Plans to address potential discharges of oil into or upon waters of the United States and adjoining shorelines.

     CERCLA and comparable state statutes, also known as Superfund laws, can impose joint, several and retroactive liability, without regard to fault or the legality of the original conduct, on specified classes of persons for the release of a “hazardous substance” into the environment. In practice, cleanup costs are usually allocated among various responsible parties. Liability can arise from conditions on properties where operations are conducted and/or from conditions at third-party disposal facilities where wastes from operations were sent. Although CERCLA, as amended, currently exempts petroleum (including oil, natural gas and NGLs) from the definition of hazardous substance, some similar state statutes do not provide such an exemption. Additionally, our operations may involve the use or handling of other materials that may be classified as hazardous substances under CERCLA and similar state statutes. We cannot assure you that the exemption will be preserved in any future amendments of the act.

     RCRA and comparable state and local programs impose requirements on the management, including treatment, storage and disposal, of hazardous and nonhazardous solid wastes. Although we believe we have utilized operating and waste disposal practices that were standard in the industry at the time, hydrocarbons or other solid wastes may have been disposed or released on or under the properties owned or leased by us or on or under locations where such wastes have been taken for disposal. In addition, many of these properties have been owned or operated by third parties. We had no control over such parties’ treatment of hydrocarbons or other solid wastes and the manner in which such substances may have been disposed or released. We generate hazardous and nonhazardous solid waste in our routine operations. From time to time, proposals have been made that would reclassify certain oil and natural gas wastes, including wastes generated during pipeline, drilling and production operations, as “hazardous wastes” under RCRA, which would make these solid wastes subject to much more stringent handling, transportation, storage, disposal and clean-up requirements. This development could have a significant impact on our operating costs. While state laws vary on this issue, state initiatives to further regulate oil and natural gas wastes could have a similar impact on our operations.

     Oil and natural gas exploration and production, and possibly other activities, have been conducted at the majority of our properties by previous owners and operators. Materials from these operations remain on some of the properties and in some instances require remediation. In some instances we have agreed to indemnify the sellers of producing properties from whom we have acquired reserves against certain liabilities for environmental claims associated with the properties. We do not believe the costs to be incurred by us for compliance and remediating previously or currently owned or operated properties will be material, but we cannot guarantee that potential costs would not result in material expenditures.

     If in the course of our routine oil and natural gas operations, surface spills and leaks, including casing leaks of oil or other materials occur, we may incur penalties and costs for waste handling, remediation and third-party actions for damages. Notwithstanding our lack of control over wells owned by us but operated by others, the failure of the operator to comply with applicable environmental regulations may, in certain circumstances, be attributable to us and may create legal liabilities for us.

     We do not anticipate that we will be required in the near future to expend amounts that are material in relation to our total capital expenditures program by reason of environmental laws and regulations, but inasmuch as these laws and regulations are frequently changed and interpreted, we are unable to predict the ultimate cost of compliance. We cannot assure you that more stringent laws and regulations protecting the environment will not be adopted or that we will not incur material expenses in complying with environmental laws and regulations in the future. If substantial liabilities to third parties or governmental entities were incurred, the payment of such claims may reduce or eliminate the funds available for project investment or result in loss of our properties. Although we maintain insurance coverage we consider to be customary in the industry, we are not fully insured against all of these risks, either because

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insurance is not available or because of high premium costs. Accordingly, we may be subject to liability or may lose substantial portions of properties due to hazards that cannot be insured against or have not been insured against due to prohibitive premium costs or for other reasons. The imposition of any of these liabilities on us may have a material adverse effect on our financial condition and results of operations.

     OSHA and Other Regulations. We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under the Title III of CERCLA and similar state statutes require us to organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

EMPLOYEES

     As of April 10, 2003, we employed approximately 40 full-time employees. None of our employees are represented by unions or covered by collective bargaining agreements. To date, we have not experienced any strikes or work stoppages due to labor problems, and we consider our relations with our employees to be good. As needed, we also utilize the services of independent consultants on a contract basis.

RISK FACTORS

     There are various risks involved in owning our common stock, including those described below.

Industry Risks

Continued Financial Success Depends on Our Ability to Acquire Additional Reserves in the Future

     Our future success as an oil and gas producer depends upon our ability to find, develop and acquire additional oil and gas reserves that are profitable. If we are unable to conduct successful development activities or acquire properties containing proved reserves, our proved reserves will generally decline as reserves are produced.

We Face Numerous Drilling Risks in Finding Commercially Productive Oil and Gas Reservoirs

     Our drilling will involve numerous risks, including the risk that no commercially productive oil or gas reservoirs will be encountered. We may incur significant expenditures for the identification and acquisition of properties and for the drilling and completion of wells. The cost of drilling, completing and operating wells is often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including unexpected drilling conditions, pressure or irregularities in formations, equipment failures or accidents, weather conditions and shortages or delays in the delivery of equipment. In addition, any use by us of 3D seismic and other advanced technology to explore for oil and gas requires greater pre-drilling expenditures than traditional drilling methodologies.

Company Risks

Our High Levels of Indebtedness May Limit Our Financial and Operating Flexibility and We May Not Be Able to Repay Our Indebtedness

     At December 31, 2002, our debt-to-equity ratio was 1.89:1.00. We may incur additional indebtedness in the future as we continue to execute our acquisition and exploration strategy and as a means of refinancing our existing capital structure.

     Our long-term debt as of December 31, 2002, was $26.9 million. The level of indebtedness will have important effects on our future operations, including:

	•		A substantial portion of our cash flow will be used to pay interest and principal on debt and will not be available for other purposes.
	•		Covenants contained in our revolving credit facility with Bank of Texas, N.A. (the “Texas Facility”) will require us to meet certain financial tests (including a debt coverage ratio of 1.25 to 1.0 and a current ratio of 1.0 to 1.0) and other

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			restrictive covenants, such as an inability to sell properties mortgaged to our lender if the sale of such properties exceeds 10% of our borrowing base or an inability to incur any indebtedness in an amount greater than $1,000,000 other than indebtedness incurred in the ordinary course of business, may affect our flexibility in planning for, and reaction to, changes in our business, including possible acquisition activities.
	•		A default under either of our current credit facilities would permit the lender to accelerate repayments of the loan and to foreclose on the collateral securing the loan, including a substantial portion of our oil and gas properties.
	•		Our ability to refinance existing debt or to obtain additional financing for capital expenditures and other purposes may be limited.
	•		We may be more leveraged than our competitors, which may place us at a competitive disadvantage.
	•		We may be unable to adjust rapidly to changing market conditions.

      Additionally, under one of our credit facilities, due to a change in direction by the lender and various technical defaults, we have agreed, among other items, to make principal payments of at least $400,000 on a monthly basis in subsequent months until the facility is paid in full. We are seeking to refinance this facility. However, no assurance can be given that we will be able to refinance this facility and if we are unable to do so, our cash flow will be impacted, along with our ability to fund our capital requirements and acquisitions of additional oil and gas interests. In addition, to the extent we are unable to refinance the facility, we may be required to sell our French properties to discharge this facility. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources" for further information.

     These considerations may make us more vulnerable than a less-leveraged competitor in the event of a downturn in our business or general economic conditions.

A Large Percentage of Our Common Stock Is Owned by Our Officers and Directors and Such Stockholders May Control Our Business and Affairs

     At December 31, 2002, our officers and directors, as a group, held a beneficial interest in approximately 52% of our common stock (including shares issuable upon exercise of stock options for common stock, conversion of our Series A and A-1 Convertible Preferred Stock held by affiliates of certain directors and conversion of Madison’s amended and restated convertible debenture). The officers and directors control our business and affairs; due to their large ownership percentage, they may remain entrenched in their positions.

A Significant Portion of Our Operations is Conducted in France and Turkey and We Also Own Interests in Romania and Trinidad. Therefore, We Are Subject to Political, Economic Risks and other Uncertainties

     We have international operations and are subject to the following foreign issues and uncertainties that may adversely affect our operations:

	•		The risk of expropriation, nationalization, war, revolution, border disputes, renegotiation or modification of existing contracts, and import, export and transportation regulations and tariffs;
	•		Taxation policies, including royalty and tax increases and retroactive tax claims;
	•		Exchange controls, currency fluctuations and other uncertainties arising out of foreign government sovereignty over international operations;
	•		Laws and policies of the United States affecting foreign trade, taxation and investment;
	•		The possibility of being subjected to the exclusive jurisdiction of foreign courts in connection with legal disputes and the possible inability to subject foreign persons to the jurisdiction of courts in the United States; and
	•		The possibility of restrictions on repatriation of earnings or capital from foreign countries.

Our Growth Depends on our Ability to Obtain Additional Capital under Satisfactory Terms and Conditions

     Our growth requires substantial capital on a continuing basis. We may be unable to obtain additional capital under satisfactory terms and conditions. Thus, we may lose opportunities to acquire oil and gas properties and businesses. In addition, our pursuit of additional capital could result in incurring additional indebtedness or issuing and adding potentially dilutive equity securities. We also may utilize the capital currently expected to be available for our present operations. The amount and timing of our future capital requirements, if any, will depend upon a number of factors, including:

	•		Drilling costs;
	•		Transportation costs;
	•		Equipment costs;
	•		Marketing expenses;
	•		Oil and gas prices;
	•		Staffing levels and competitive conditions; and
	•		Any purchases or dispositions of assets.

     Our failure to obtain any required additional financing could materially and adversely affect our growth, cash flow and earnings.

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Our Marketing of Oil and Gas Production Principally Depends upon Facilities Operated by Others, and These Operations May Change and Have a Material Adverse Effect on our Marketing

     Our marketing of oil and gas production principally depends upon facilities operated by others. The operations of those facilities may change and have a material adverse effect on our marketing of oil and gas production. In addition, we rely upon third parties to operate many of our properties and may have no control over the timing, extent and cost of development and operations. As a result of these third-party operations, we cannot control the timing and volumes of production.

We May Not Be Able to Renew Our Permits

     We do not hold title to properties in France, Turkey or Romania, but have exploration and production permits granted by the respective governments. There can be no assurances that we will be able to renew any of these permits that expire.

We May Not Have Production to Offset Hedges and We May Not Benefit From Price Increases by Hedging

     We may, from time to time, reduce our exposure to the volatility of oil and gas prices by hedging a portion of our production. In a typical hedge transaction, we will have the right to receive from the counterparty to the hedge the excess of the fixed price specified in the hedge over a floating price based on a market index, multiplied by the quantity hedged. If the floating price exceeds the fixed price, we will be required to pay the counterparty this difference multiplied by the quantity hedged. In such case, we will be required to pay the difference regardless of whether we have sufficient production to cover the quantities specified in the hedge. Significant reductions in production at times when the floating price exceeds the fixed price could require us to make payments under the hedge agreements even though such payments are not offset by sales of production. Hedging also could prevent us from receiving the full advantage of increases in oil or gas prices above the fixed amount specified in the hedge.

Investment Risks

Due to the Restrictions Placed on Us by Our Credit Facility and our Outstanding Shares of Preferred Stock, We Do Not Expect to Pay Cash Dividends in the Near Future

     From time to time, we have paid cash dividends on our common stock. However, we do not anticipate paying cash dividends on our common stock in the foreseeable future. Our credit facilities and our outstanding shares of preferred stock restrict our ability to pay dividends on our common stock. Therefore, our common stock is not a suitable investment for persons requiring current income.

GLOSSARY OF SELECTED OIL AND GAS TERMS

     “2D” or “2D Seismic.” An exploration method of sending energy waves or sound waves into the earth and recording the wave reflections to indicate the type, size, shape, and depth of subsurface rock formations. 2D seismic provides two-dimensional pictures.

     “3D” or “3D Seismic.” An exploration method of sending energy waves or sound waves into the earth and recording the wave reflections to indicate the type, size, shape, and depth of subsurface rock formations. 3D seismic provides three-dimensional pictures.

     “Bbl.” One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.

     “BBL/D.” Barrels per day.

     “Bcf.” One billion cubic feet of natural gas.

     “BOE.” Barrel of oil equivalent converting six Mcf of natural gas to one barrel of oil.

     “DEVELOPMENT WELL.” A well drilled within the proved boundaries of an oil or natural gas reservoir with the intention of completing the stratigraphic horizon known to be productive.

     “DISCOUNTED PRESENT VALUE (PRETAX).” The present value of proved reserves is an estimate of the discounted future net cash flows from each property at December 31, 2002, or as otherwise indicated. Net cash flow is defined as net revenues less, after

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deducting production and ad valorem taxes, future capital costs and operating expenses, but before deducting federal income taxes. The future net cash flows have been discounted at an annual rate of 10% to determine their “present value.” The present value is shown to indicate the effect of time on the value of the revenue stream and should not be construed as being the fair market value of the properties. In accordance with Securities and Exchange Commission rules, estimates have been made using constant oil and natural gas prices and operating costs at December 31, 2002, or as otherwise indicated.

     “DRY HOLE.” A development or exploratory well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

     “EXPLORATORY WELL.” A well drilled to find and produce oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir, or to extend a known reservoir.

     “GROSS ACRES” or “GROSS WELLS.” The total number of acres or wells, as the case may be, in which a working or any type of royalty interest is owned.

     “KMS.” Kilometers.

     “MBbl.” One thousand Bbls.

     “MBOE.” One thousand BOE.

     “Mcf.” One thousand cubic feet of natural gas.

     “MMBl.” One million Bbls of oil and other liquid hydrocarbons.

     “MMBOE.” One million BOE.

     “NET ACRES.” The sum of the fractional working or any type of royalty interests owned in gross acres.

     “PRODUCING WELL” or “PRODUCTIVE WELL.” A well that is producing oil or natural gas or that is capable of production.

     “PROVED DEVELOPED RESERVES.” The oil and natural gas reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and natural gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

     “PROVED RESERVES.” The estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

     “PROVED UNDEVELOPED RESERVES.” The oil and natural gas reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery techniques is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

     “ROYALTY INTEREST.” An interest in an oil and natural gas property entitling the owner to a share of oil and natural gas production free of production costs.

     “STANDARDIZED MEASURE.” Under the Standardized Measure, future cash flows are estimated by applying year-end prices, adjusted for fixed and determinable escalations, to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end costs to determine pretax cash inflows. Future

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income taxes are computed by applying the statutory tax rate to the excess inflows over a company’s tax basis in the associated properties.

     Tax credits, net operating loss carryforwards and permanent differences also are considered in the future tax calculation. Future net cash inflows after income taxes are discounted using a 10% annual discount rate to arrive at the Standardized Measure.

     “UNDEVELOPED ACREAGE.” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

     “WORKING INTEREST.” The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production, subject to all royalties, overriding royalties and other burdens, and to all exploration, development and operational costs including all risks in connection therewith.

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ITEM 2. PROPERTIES.

INTERNATIONAL

     FRANCE

     We own and operate five producing oil fields in the Paris Basin, France. Four of those are located within the Neocomian Field complex and one in the Charmottes area.

     NEOCOMIAN FIELDS

     Pursuant to two production permits, we own a 100% working interest in the Neocomian Fields, a group of four oil accumulations located approximately 120 kilometers southeast of Paris. The Chateau Renard Field was discovered in 1958, Chuelles and St. Firmin-des-Bois in 1961 and Courtenay in 1964. The property currently has 78 producing oil wells. As of December 31, 2002, the Neocomian Fields had net proved reserves of 9,847 MBbl.

     CHARMOTTES

     We own a 100% working interest in the Charmottes Field, located 60 kilometers southeast of Paris. The property has nine oil wells of which eight are currently producing. The Charmottes Field was initially developed following the discovery well drilled in 1984. As of December 31, 2002, the Charmottes Field had net proved reserves of 1,396 MBbl.

     TURKEY

     In Turkey, we have interests in the Zeynel and Cendere Fields. We also hold interests in 35 exploration licenses in four other geographic regions of Turkey totaling 4.1 million gross acres (2.7 million net).

     ZEYNEL

     We have an 8.5% royalty interest in the Zeynel Field, located in south-central Turkey, with net proved reserves of 70 MBbl at December 31, 2002. The Zeynel #15 development well was drilled and completed in 2002. In late 2002, the East Hasancik-1 well was drilled by the operator on a new field in the Zeynel permit. The well was an oil discovery and is expected be deepened to other objectives in 2003. We hold a 6.75% royalty interest in the new field.

     CENDERE

     We have an approximate 19.6% working interest in the Cendere Field, that is located in central Turkey. The property has 16 oil wells currently producing. We had net proved reserves of 902 MBbl in the Cendere Field as of December 31, 2002. The Cendere 19 well was drilled and completed as a producer in 2002. A 3D seismic survey is planned for this field in 2003 to identify new drilling locations.

     BLACK SEA PERMITS

     We are operator and hold a 49% working interest in eight permits covering 962,000 gross acres (471,000 net). During 2002, we completed a seismic study covering 1,275 KMS of 2D Seismic data over our exploration licenses in the Black Sea. Based on the interpretation of the seismic data, we plan to drill two wells during early 2004.

     CENTRAL AND SOUTHEAST EXPLORATION PERMITS

     We hold 26 exploration licenses in the central and southeast portions of Turkey. A number of producing fields in Iran and Iraq trend in a north by northwesterly direction and wrap into southern Turkey through the area encompassing many of our exploration permits. As of December 31, 2002, there were no net reserves for the land covered by the Central and Southeast Exploration Permits.

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     THRACE BASIN PERMITS

     In the Thrace Basin, located in the European portion of Turkey, we have a 50% interest in three exploration permits and a 25% interest in one permit. The Thrace Basin has shown potential for natural gas. In this part of the country, gas is productive from shallow depths. With a pipeline through the region from Bulgaria to Istanbul and gas-fired power plants on the coast along the Marmara Sea, we could benefit from the area’s existing infrastructure. Based on the interpretation of the data from a previous seismic survey, we drilled two wells during 2002. The first well was dry, and the second awaits completion of testing. As of December 31, 2002, there were no net reserves for the land covered by the Thrace Basin Permits.

     ROMANIA

     In early 2003, we expanded our international portfolio when the Romanian government awarded the company a concession for the Viperesti Block in exchange for a staged work commitment. We are a 100% owner and operator of the block that lies in an oil-rich region in east-central Romania in the southeastern foothills of the Carpathian Mountains. Viperesti, which spans 324,000 acres, is surrounded by and on trend with many sizable oil fields to the southwest and northeast. The block is prospective in the Tertiary formations at depths ranging from 4,500-6,000 feet.

     During a five-year exploration period, we plan to acquire and assimilate geological and geophysical data, analyze seismic information and re-enter one of several previously drilled wells on the block. Subsequently, we could drill one or more exploration wells.

     TRINIDAD, WEST INDIES

     In Trinidad, all of our operations are conducted by and licenses are held through Trinidad Exploration and Development, Ltd. (“TED”), of which we are now a 11.28% owner. During late 2002, TED drilled the Rapso-1 well on Trinidad’s Southwest Peninsula Block, exploring the sands in the Tertiary Morne L’Enfer, Forest and Cruse formations. Work on the Rapso-1 well has been suspended and is waiting for further testing. Toreador has determined not to participate in future exploration on the block. Consequently, Toreador’s interest in TED has been diluted to 11.28% and will be diminished further as TED pursues its drilling program.

     The Rapso-1 is an oil prospect that explored the sands in the Tertiary Morne L’Enfer, Forest, and Middle and Lower Cruse formations. Work on the Rapso-1 has been suspended, and the well awaits testing. Additional drilling on the block is under evaluation.

     The Southwest Peninsula Block comprises about 45,000 prospective acres onshore and offshore southwest Trinidad. It is about nine miles from the Venezuelan coast and on trend with sizable oil fields in Venezuela and onshore Trinidad. TED is operator of the license area and holds a 72.5% working interest in the block. The Petroleum Company of Trinidad & Tobago Ltd., the Trinidadian national oil company, holds the remaining 27.5% interest.

DOMESTIC

     We own perpetual oil and gas mineral and royalty interests in approximately 2,643,000 gross (1,368,000 net) acres primarily located in Alabama, Arkansas, California, Kansas, Michigan, Louisiana, Mississippi and Texas. The majority of mineral leasing activity occurs on the acreage we own in Mississippi and Texas.

     We also hold working interests in 927 gross wells (53 net) primarily in Texas, Oklahoma, New Mexico, Kansas, Louisiana, and Arkansas.

     We are participating in the completion of the Walton Gas Unit 2-2 well located on the 1,000-acre Walton Gas Unit prospect. Part of the larger Bethel Dome Project in Anderson County in east Texas, the exploratory well has been drilled to a total depth of 10,100 feet and producing casing set to total depth. Completion operations, including flow testing, continue. Toreador has a 5.86% interest in the well and any subsequent offset development-well locations.

     We continued our participation in the development of the Silver Spur (Tannehill) Field located in Dickens County, Texas on company owned minerals. The Hollis R. Sullivan Inc. Pitchfork-Toreador “22” No. 6 well was successfully drilled and completed as an oil well. Early in 2003 we also participated in the drilling and completion of the Hollis R. Sullivan Inc. Pitchfork-Toreador “22” No. 7 well. This brings the number of producing wells in field to nine. Toreador maintains a 9.375% working interest with a combined 16.875% revenue interest in the field.

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     In Oktibbeha County, Mississippi, there has been increased mineral-leasing activity on in the Black Warrior Basin’s Deep Knox gas play. Since the Maben Field was discovered in 1976, only one well was producing until additional wells were drilled in the late 1990’s. Now there are 11 producing wells in the Maben Field, the result of new seismic and drilling technology. Recent geologic studies show the Deep Knox play extends in a northwest/southeast trend, covering 11 additional counties in Mississippi and three counties in Alabama.

     In Jefferson Davis County, Mississippi, operators completed 13 wells on our mineral holdings in the Selma Chalk formation using new fracturing techniques, improving production from the Gwinville Field in 2002. We anticipate additional activity and higher production levels continuing in 2003 in this area where Toreador holds significant mineral interests.

     In West Texas, Toreador owns a 16.6% working interest on 6,000 gross acres where one well was successfully completed and a second well is being completed. The operator is using horizontal multi-lateral drilling techniques in the San Andres formation to expose more of the reservoir and increase total fluid recovery.

TITLE TO OIL AND GAS PROPERTIES

     INTERNATIONAL

     FRANCE

     We do not hold title to properties in France but have been granted exploration and production permits by the French government. We have two French exploration permits, Nangis and Courtenay. There are no proved reserves associated with these permits. The Nangis permit expires in 2005, and the Courtenay permit expires in 2006. The French exploration permits have minimum financial requirements that must be met during their terms. If such obligations are not met, the permits could be subject to forfeiture.

     The French production permits covering five producing oil fields in the Paris Basin follow:

     Although the French government has the option to renew production permits, we believe it will renew such production permits so long as we, the license holder, demonstrate financial and technical capabilities and establish the studies used in defining the work schedule. However, there can be no assurance that we will be able to renew any permits that expire.

     TURKEY

     We do not hold title to properties in Turkey but have been granted exploitation leases and exploration licenses by the Turkish government:

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     Under Turkish law, “exploitation leases” are generally granted for a period of 20 years and may be renewed upon application for two additional ten-year periods. “Exploration licenses” are generally granted for four-year terms and may be extended for two additional two-year terms, provided that drilling obligations stipulated under Turkish law are satisfied. If an exploration license is extended for development as an exploitation lease, the period of the exploration license(s) is counted towards the 20-year exploitation lease.

     ROMANIA

     In early 2003, we expanded our international portfolio when the Romanian government awarded the company a concession for the Viperesti Block in exchange for a staged work commitment. We are a 100% owner and operator of the block that lies in an oil-rich region in east-central Romania in the southeastern foothills of the Carpathian Mountains. Viperesti, which spans 324,000 acres, is surrounded by and on trend with many sizable oil fields to the southwest and northeast. The block is prospective in the Tertiary formations at depths ranging from 4,500-6,000 feet.

     During a five-year exploration period, we plan to acquire and assimilate geological and geophysical data, analyze seismic information and re-enter one of several previously drilled wells on the block. Subsequently, we could drill one or more exploration wells.

     DOMESTIC

     We have acquired interests in producing and non-producing acreage in the form of working interests, perpetual fee mineral interests, royalty interests and overriding royalty interests. Substantially all of our property interests are leased to third parties. The leases grant the lessee the right to explore for and extract oil and gas from specified areas. Consideration for a lease usually consists of a lump-sum payment (i.e., bonus) and a fixed annual charge (i.e., delay rental) prior to production (unless the lease is paid up) and, once production has been established, a royalty based generally upon the proceeds from the sale of oil and gas. Once wells are drilled, a lease generally continues so long as production of oil and gas continues. In some cases, leases may be acquired in exchange for a commitment to drill or finance the drilling of a specified number of wells to predetermined depths. We receive annual delay rentals from lessees of certain properties in order to prevent the leases from being terminated. Title to leasehold properties is subject to royalty, overriding royalty, carried, net profits and other similar interests and contractual arrangements customary in the oil and gas industry, and to liens incident to operating agreements, liens relating to amounts owed to the operator, liens for current taxes not yet due and other encumbrances.

     As is common industry practice, we conduct little or no investigation of title at the time we acquire undeveloped properties, other than a preliminary review of local mineral records. However, we do conduct title investigations and, in most cases, obtain a title opinion of local counsel before commencement of drilling operations. We believe that the methods we utilize for investigating title prior to acquiring any property are consistent with practices customary in the oil and gas industry and that such practices are adequately designed to enable us to acquire good title to such properties. Some title risks, however, cannot be avoided, despite the use of customary industry practices.

     We own oil and gas mineral and royalty interests in approximately 16,000 gross acres in Louisiana. Unlike the other states where we own perpetual minerals, the laws in Louisiana are such that the minerals prescribe to the surface owner after 10 years have passed without any production or drilling on said lands. Because we do not own the surface rights in any of the properties that were acquired in December 1998, we do not maintain many of our mineral rights if production ceases for 10 years.

     Our properties are generally subject to:

	•		Customary royalty and overriding royalty interests;
	•		Liens incident to operating agreements and
	•		Liens for current taxes and other burdens and minor encumbrances, easements and restrictions.

     We believe that none of these burdens either materially detracts from the value of our properties or materially interfere with their use in the operation of our business. Substantially all of our domestic properties are pledged as collateral under the Texas Facility.

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OIL AND GAS RESERVES

     The following table sets forth information about our estimated net proved reserves at December 31, 2002 and 2001. LaRoche Petroleum Consultants, Ltd., an independent petroleum engineering firm in Dallas, Texas, prepared the estimates of proved developed reserves, proved undeveloped reserves and discounted present value (pretax). We prepared the estimate of standardized measure of proved reserves in accordance with Financial Accounting Standards Board Statement of Financial Accounting Standards No. 69, “Disclosures about Oil and Gas Producing Activities.” No reserve reports have been provided to any governmental agency.

     Reserves were estimated using oil and gas prices and production and development costs in effect on December 31, 2002 and 2001, without escalation. The reserves were determined using both volumetric and production performance methods. France and Turkey have oil reserves only. Proved reserves are those estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. THE VALUES REPORTED MAY NOT NECESSARILY REFLECT THE FAIR MARKET VALUE OF THE RESERVES.

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     For additional information concerning our oil and gas reserves and estimates of future net revenues attributable thereto, see Note 18 of the Notes to the Consolidated Financial Statements.

PRODUCTIVE WELLS

     The following table sets forth our gross and net interests in productive oil and gas wells as of December 31, 2002. Productive wells include wells currently producing or currently capable of production.

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ACREAGE

     The following table sets forth the developed and undeveloped acreage attributable to our ownership as of December 31, 2002.

     Undeveloped acreage includes only those leased acres on which wells have not been drilled or completed to permit the production of commercial quantities of oil and gas regardless of whether or not the acreage contains proved reserves.

DRILLING ACTIVITIES

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NET PRODUCTION, UNIT PRICES AND COSTS

     The following table summarizes our oil, natural gas and natural gas liquids production, net of royalties, for the periods indicated. It also summarizes calculations of our total average unit sales prices and unit costs. Because we consummated our acquisition of Madison on December 31, 2001, the table excludes information related to Madison’s operations for 2001 and 2000.

PRESENT ACTIVITIES

     For the period January 1, 2003 through April 10, 2003, we did not participate in drilling any exploratory wells.

OFFICE LEASE

     We occupy approximately 18,746 square feet of office space at 4809 Cole Avenue, Suite 108, Dallas, Texas 75205 under a lease from Chalk Stream Properties, L.P. We also occupy approximately 1,377 square feet of office space at 13/15 Boulevard de la Madeleine, 75001 Paris, France leased from Societe la Madeleine, and approximately 621 square feet of office space at 9400 N. Central Expressway, Suite 1209, Dallas, Texas 75231. Total rental expense for 2002 was approximately $362,000.

INTERNET ADDRESS

     We make available electronically, free of charge through our Internet website address (www.toreador.net), our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed with the Securities and Exchange Commission (the "SEC") pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after we electronically file such material with the SEC. These reports are directly accessible on the Internet at www.sec.gov/edgar/searchedgar/webusers.htm.

ITEM 3. LEGAL PROCEEDINGS.

     Karak Petroleum. Madison and its wholly-owned subsidiary, Trans-Dominion Holdings Ltd., were named as defendants in a complaint filed in Alberta, Canada, in 1999. The complaint arose from a dispute between Karak Petroleum, a subsidiary of Trans-Dominion Holdings, and the operator of an exploratory well in Pakistan in 1994 in which Karak was a joint interest partner. The plaintiffs alleged that they were owed approximately $500,000. On August 7, 2002, we reached an agreement with the plaintiffs in this matter. Under the terms of the agreement, we agreed to pay the plaintiffs $400,000 for full release of liability. Written documentation reflecting the foregoing was finalized on August 29, 2002. The agreement required that we remit the $400,000 in two installments. The first installment of $50,000 was paid on August 29, 2002, and the remaining $350,000 was recorded as a liability and was to be paid by February 3, 2003. In February 2003, the plaintiffs agreed to accept the $350,000 in monthly installments payable at the beginning of each month beginning February 2003.

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     Turkish Registered Capital. Under the existing Petroleum Law of Turkey, capital which is invested by foreign companies for projects such as oil and gas exploration can be registered with the General Directorate of Petroleum Affairs, thereby qualifying for protection against adverse changes in the exchange rate between the time of the initial investment and the time such capital is repatriated out of Turkey. Since 1997 the Turkish government has suspended such protection for repatriated capital. As holder of more than $50 million of registered capital, we have filed suit in Turkey to attempt to restore the exchange rate protections afforded under the law. No amounts are accrued related to this contingency. Pursuant to the terms of the acquisition agreement, holders of Madison common stock have the right to receive, in cash or our common stock, 30% of certain potential payments that may be received from the Turkish government for the protection of repatriated capital. In March 2002 a lower level court ruled in favor of Madison. The ruling was subject to automatic appeal that was heard in December 2002. We are currently awaiting the ruling on the appeal. However, we cannot predict the outcome of this matter.

     Trinidad Arbitration. At December 31, 2001, we held a 25% interest in Trinidad Exploration and Development, Ltd. (“TED”), a Trinidad company engaged in oil and gas exploration. Until August 2000, TED was a wholly-owned subsidiary of Madison, at which time Madison sold a 75% interest to another company. Under the terms of the sale, the buyer was required to fund $4.0 million in costs of drilling and exploration before Madison was required to contribute additional amounts in accordance with its 25% shareholding. During 2001, TED was primarily engaged in a seismic program to conduct exploration on a license interest in the Southwest Peninsula of Trinidad. In late August, Madison received an initial billing for capital contributions to fund the ongoing exploration. The operator claimed, however, that Madison did not make timely payments and that Madison’s interest in TED should be reduced from 25% to 12.5%. On September 18, 2002, we received a ruling from the American Arbitration Association related to this matter. The arbitrator ruled that certain payments by Toreador’s subsidiary were delinquent, and, according to the terms of the shareholders agreement, Toreador’s interest in TED has been reduced from 25% to 16.33%. Since the ruling, our interest has been further reduced to 11.28%, the result of our non-participation in certain capital and operating costs incurred by TED.

     From time to time, we are named as a defendant in other legal proceedings arising in the normal course of business. In our opinion, the final judgment or settlement, if any, that may be awarded with any suit or claim would not have a material adverse effect on our financial position.

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

     None

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PART II

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

MARKET INFORMATION

     Our shares of common stock, par value $.15625 per share, are traded on the Nasdaq National Market System under the trading symbol “TRGL” and are traded on the Toronto Stock Exchange under the symbol “TRX”. The following table sets forth the high and low sale prices per share for the common stock for each quarterly period during the past two fiscal years as reported by Nasdaq based upon quotations that reflect inter-dealer prices, without retail mark-up, mark-down or commission and may not necessarily represent actual transactions.

HOLDERS AND CLOSING PRICE

     As of April 10, 2003, there were 9,337,517 shares of common stock outstanding and held of record by approximately 890 holders (inclusive of those brokerage firms, clearing houses, banks and other nominee holders, holding common stock for clients, with all such nominees being considered as one holder).

     The closing price of the common stock on the Nasdaq National Market System on April 10, 2003 was $2.85. The closing price on the Toronto Stock Exchange on April 10, 2003 was Canadian $4.17.

DIVIDENDS

     Dividends on the common stock may be declared and paid out of funds legally available when and as determined by our board of directors. We paid cash dividends totaling $52,000 during 2000. Our board of directors plans to continue our policy of holding and investing corporate funds on a conservative basis, and thus we do not anticipate paying cash dividends on our common stock in the foreseeable future. In addition, under the terms of the Texas Facility described in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation – Liquidity and Capital Resources,” we are prohibited from paying dividends on the common stock without prior consent from Bank of Texas, National Association (other than dividends payable in shares of common stock). The terms of our Series A Convertible Preferred Stock and our Series A-1 Convertible Preferred Stock prohibit us from paying dividends on the common stock without the approval of the holders of a majority of the then outstanding shares of the Series A Convertible Preferred Stock and the Series A-1 Convertible Preferred Stock.

     Dividends on our Series A Convertible Preferred Stock and our Series A-1 Convertible Preferred Stock are paid on a quarterly basis per the terms of each series. Cash dividends totaling $374,000, $360,000 and $360,000 were declared, and $270,000, $360,000 and $360,000 were paid for the years ended December 31, 2002, 2001 and 2000, respectively, on the Series A Convertible Preferred Stock. Cash dividends totaling $14,000 were declared for the year ended December 31, 2002 on the Series A-1 Convertible Preferred Stock. Future dividends will be paid in cash only at a rate of $110,813 per calendar quarter. We are prohibited from paying dividends over $100,000 on the preferred stock without the consent from Bank of Texas, National Association.

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SALES OF UNREGISTERED SECURITIES

     In the fourth quarter of 2002, we issued the following equity securities that were not registered under the Securities Act of 1933, as amended:

     On November 1, 2002, pursuant to a private placement we issued $925,000 of Series A-1 Convertible Preferred Stock to certain of our directors and entities controlled by certain of our directors.

     The Series A-1 Convertible Preferred Stock is governed by a certificate of designation. The Series A-1 Convertible Preferred Stock was sold for a face value of $25.00 per share, and pays an annual cash dividend of $2.25 per share that results in an annual yield of 9.0%. At the option of the holder, the Series A-1 Convertible Preferred Stock may be converted into common shares at a price of $4.00 per common share. The $4.00 conversion price was higher than the market price of our common stock at the time of issuance. The Series A-1 Convertible Preferred Stock is redeemable at our option, in whole or in part, at any time on or after November 1, 2007. The optional redemption price per share is the sum of (1) $25.00 per share of the Series A Convertible Preferred Stock plus (2) any accrued unpaid dividends, and such sum is multiplied by a declining multiplier. The multiplier is 105% until October 31, 2008, 104% until October 31, 2009, 103% until October 31, 2010, 102% until October 31, 2011, 101% until October 31, 2012, and 100% thereafter. In connection with the securities purchase agreement, the parties entered into a registration rights agreement effective November 1, 2002, among Toreador and the persons party thereto which provides for the registration of the common stock issuable upon conversion of the Series A-1 Convertible Preferred Stock.

     The sale of the Series A-1 Convertible Preferred Stock was effected in reliance upon the exemption from securities registration afforded by the provisions of Section 4(2) of the Securities Act of 1933, as amended, and Regulation D as promulgated by the Securities and Exchange Commission under the Securities Act of 1933, as amended.

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Table of Contents

ITEM 6. SELECTED FINANCIAL DATA.

     The following table summarizes certain selected financial data with respect to our financial condition and results of operations for the periods indicated. The selected financial data should be read in conjunction with the financial statements and related notes set forth in “Item 8. Financial Statements and Supplementary Data” of this Part II.