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

FORM 10-K

OR

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 30, 2003, was $15,802,955. (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 9, 2004, was 9,500,317 shares.

DOCUMENTS INCORPORATED BY REFERENCE

        Portions of the registrant’s Proxy Statement for the 2004 Annual Meeting of Stockholders, expected to be filed on or prior to April 29, 2004, are incorporated by reference into Part III of this Form 10-K.

TABLE OF CONTENTS

Table of Contents

PART I

ITEM 1.    BUSINESS.

GENERAL

        Toreador Resources Corporation, a Delaware corporation (“Toreador,” “we,” “us,” “our,” or the “Company”), is an independent international energy company engaged in oil and natural gas exploration, development, production, leasing and acquisition activities. In January 2004, we sold our U.S. mineral and royalty assets to Black Stone Acquisitions Partners I, L.P. (“Royalty Sale”). We retained all of our working-interest properties. As a result of the sale, our business consists of exploration, acquisition, production and development of oil and natural gas reserves.

        We currently hold interests in developed and undeveloped oil and natural 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. We have been awarded concessions for the Viperesti, Moinesti, and Fauresti blocks in Romania. We also own various working-interest properties in Texas, Kansas, New Mexico, Louisiana 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. Currently, Madison holds interests in approximately 5,043,000 gross acres (3,317,000 net) of developed and undeveloped oil and natural gas properties in the Paris Basin, France, several fields in Turkey and Romania, and the Bonasse Field and Southwest Cedros Peninsula License in Trinidad, West Indies.

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

BUSINESS STRATEGY

        Our strategic focus during 2003 centered on strengthening our balance sheet and reducing our general and administrative expenses through reductions in force and specific cost cuts. Our balance sheet was strengthened by the discharge in full of debt owed on our senior credit facilities ($28.8 million at December 31, 2003). This was accomplished through the application of a majority of our free cash flow to this debt in 2003 and the utilization of a portion of the net proceeds from the Royalty Sale to discharge the remaining amount owed in early 2004. During 2003, we were also able to obtain interests in new strategic international exploration permits and dispose of some underperforming assets that we consider non-strategic. We will continue to seek opportunities to:

DEVELOPMENTS

        DISPOSITIONS

        In January 2004, we consummated the Royalty Sale. We retained all of our working-interest properties. From the approximate $45.0 million cash consideration that we received, we discharged our outstanding credit facilities in full and placed approximately $8.0 million in a tax-deferred escrow account for a possible like-kind exchange. The escrow account is designed to comply with the like-kind exchange provisions of Section 1031 of the Internal Revenue Code of 1986, as amended, which permits the deferral of gains from a sale of assets if specific like-kind exchange criteria are met. We are attempting to acquire working-interests that would comply with the like-kind exchange criteria.

        In 2003, we sold several underperforming oil and natural gas assets for approximately $424,000. All sales were made in private negotiated transactions.

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        We exchanged our interest in Trinidad Exploration and Development, Ltd. for a 1% overriding royalty interest in Trinidad’s Bonasse Field and Southwest Cedros Peninsula License.

        NEW PERMITS

        During 2003, we expanded our international portfolio when the Romanian government awarded us a concession on the Viperesti Block in exchange for a staged work commitment. We are 100% owner and operator of the block that lies in east-central Romania in the southeastern foothills of the Carpathian Mountains. This concession comprises 324,000 gross acres. We believe this block is prospective in the Tertiary formations at depths ranging from 4,500-6,000 feet. In addition, in 2003 the Romanian government granted us an exploration permit on the Moinesti Block and a rehabilitation permit on the Fauresti Block in exchange for our entering into a three-year work program. We are 100% owner and operator of the two blocks. The Moinesti Block covers approximately 300,000 net acres. It is situated about 40 miles north of our Viperesti Block in the foothills of the Carpathian Mountains and is contiguous with eight producing oil fields. We believe the block is prospective in various producing formations from 3,000-16,000 feet. The Fauresti Block covers approximately 1,325 acres. It is located in southwestern Romania about 90 miles west of the Viperesti Block. We believe it offers development opportunities in the Jurassic Dogger formation at depths of approximately 8,000 feet.

        ISSUANCE OF ADDITIONAL SHARES OF SERIES A-1 CONVERTIBLE PREFERRED STOCK

        During 2003, pursuant to private placements we issued 123,000 shares of our Series A-1 Convertible Preferred Stock as follows: (i) in July 2003, 20,000 shares were issued, (ii) in August 2003, 20,000 shares were issued; (iii) in October 2003, 34,000 shares were issued to Mr. William I. Lee, one of our directors, and Wilco Properties, Inc. (“Wilco”), an entity controlled by Mr. Lee; (iv) in December 2003, 42,000 shares were issued; and (v) also in December 2003, 7,000 shares were issued to Wilco. The aggregate proceeds from these sales were $3,075,000. During 2002, we issued 37,000 shares of Series A-1 Convertible Preferred Stock. The Series A-1 Convertible Preferred Stock was sold for $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 when the various issuances occurred. 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 agreements, Toreador granted certain “piggy-back” registration rights relating to the common stock issuable upon conversion of the Series A-1 Convertible Preferred Stock.

        EXPLORATION ACTIVITIES

        TURKEY

        We hold 30 exploration licenses on approximately 2.4 million net acres. A number of producing fields in Iran and Iraq trend in a north by northwesterly direction into southern Turkey through the area encompassing many of our exploration permits.

        We are operator and hold a 49% working-interest in eight permits in the Black Sea. In mid-2004, we plan to drill the Ayazli-1 well, our first exploratory well in the western Black Sea. This well is one of six natural gas prospects that we have identified to date in the area. We anticipate drilling a second offshore exploratory well in 2005.

        We drilled one well on our Thrace Basin permits during 2003 which was a dry hole. In addition, a well drilled in 2002 and tested in 2003 was found to be unproductive and abandoned. Based on the results of exploration activities in this basin, we relinquished exploration permits comprising 469,838 gross acres (204,540 net acres) in 2003.

        ROMANIA

        During 2003, we expanded our international portfolio when the Romanian government awarded us a concession on the Viperesti Block in exchange for a staged work commitment. We are 100% owner and operator of the block that lies in east-central Romania in the southeastern foothills of the Carpathian Mountains. This concession comprises 324,000 gross acres. We believe this block is prospective in the Tertiary formations at depths ranging from 4,500-6,000 feet. In addition, in 2003 the Romanian government granted us an exploration permit on the Moinesti Block and a rehabilitation permit on the Fauresti Block in exchange for our entering into a three-year work program. We are 100% owner and operator of the two blocks. The Moinesti Block covers approximately 300,000 gross and net acres. It is situated about 40 miles north of our Viperesti Block in the foothills of the Carpathian Mountains and is contiguous with eight producing oil fields. We believe the block is prospective in various producing formations from 3,000-16,000 feet. The Fauresti Block covers approximately 1,325 acres. It is located in southwestern Romania about 90 miles west of the Viperesti Block. We believe it offers development opportunities in the Jurassic Dogger formation at depths of approximately 8,000 feet.

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        FRANCE

        We own two exploration permits in France. 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.

        UNITED STATES

        We are participating with a 16.67% working-interest in the West Texas San Andres Oil Recovery 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 the early stages of evaluation with two wells completed in 2003 and a third well completed in early 2004. A fourth well currently is being drilled.

MARKETS AND COMPETITION

        In France, we currently sell all of our oil production to Elf Antar France S.A., the largest purchaser in the area. This production is shipped by truck to an Elf refinery. The oil also can be transported to refineries on the north coast of France via pipeline. Production in Turkey is sold to refineries in the southern part of the country.

        Our domestic oil and natural gas production is sold to various purchasers typically in the areas where the oil or natural gas is produced. Revenues from the sale of oil and natural gas production accounted for 109%, 116% and 89% of our consolidated revenues for the three years ended December 31, 2003, 2002 and 2001, respectively. Generally, we do not refine or process any of the oil and natural 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 natural gas we are capable of producing at current market prices. Most of our oil and natural 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 natural gas is sold to pipeline companies rather than end users.

        The oil and natural 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 permit us to do.

        We also are affected by competition for drilling rigs and the availability of tubular goods and certain other equipment. While the oil and natural 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 natural 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 domestic producing properties for sale to independent oil and natural gas producers. We cannot ensure we will be successful in acquiring any such properties.

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 natural 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.

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        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 of earnings or capital to foreign entities from France, Turkey, Romania, or Trinidad. However, there can be no assurance that any such restrictions or repatriation of earnings or capital from the aforementioned countries or any other country where we may invest will not be imposed in the future.

        Environmental. The oil and natural gas industry is subject to extensive and varying environmental regulations in each of the jurisdictions in which we may operate. Environmental regulations establish standards respecting health, safety and environmental matters and place restrictions and prohibitions on emissions of various substances produced 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 to 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 natural gas production depends upon numerous factors beyond our control. These factors include state and federal regulation of oil and natural 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 natural 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 natural gas well may be “shut-in” due to an oversupply of natural gas or lack of an available natural gas pipeline in the areas in which we may conduct operations. State and federal regulations generally are intended to prevent waste of oil and natural gas, protect rights to produce oil and natural gas between owners in a common reservoir, control the amount of oil and natural gas produced by assigning allowable rates of production, and control contamination of the environment. Pipelines and natural gas plants also are subject to the jurisdiction of various federal, state and local agencies.

        Our natural gas sales are affected by the availability, terms and costs of transportation. The rates, terms and conditions applicable to the interstate transportation of natural 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, the FERC has implemented regulations intended to increase competition within the natural gas industry by making natural gas transportation more accessible to natural gas buyers and sellers on an open-access, nondiscriminatory basis.

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

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        With respect to transportation of natural gas on or across the Outer Continental Shelf (“OCS”), the FERC requires, as a part of its regulation under the Outer Continental Shelf Lands Act (“OCSLA”), that all pipelines provide open and nondiscriminatory access to both owner and non-owner shippers. Although to date the FERC has imposed light-handed regulation on offshore gathering facilities, it has the authority to exercise jurisdiction under the OCSLA over these type of gathering facilities, if necessary, to require nondiscriminatory access by shippers 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 the 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, the FERC requires, as part of its regulation under the OCSLA, that all pipelines provide open and nondiscriminatory access to both owner and non-owner shippers. Accordingly, the FERC has the authority to exercise jurisdiction under the OCSLA, if necessary, to require nondiscriminatory access by shippers to service.

        We conduct operations on federal, state or Indian oil and natural 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 amended its regulations governing the calculation of royalties and the valuation of crude oil produced from federal leases. Among other matters, this rule amended 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 (the “Mineral Act”) prohibits direct or indirect ownership of any interest in federal onshore oil and natural 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 “nonreciprocal” country include ownership or holding or controlling stock in a corporation that holds a federal onshore oil and natural 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 nonreciprocal countries, there are presently no such designations in effect. We own interests in federal onshore oil and natural gas leases. It is possible that some of our stockholders may be citizens of foreign countries, which at some time in the future might be determined to be nonreciprocal under the Mineral Act.

        The pipelines we use to gather and transport our oil and natural gas may be subject to regulation by the Department of Transportation (“DOT”) under the Hazardous Liquids Pipeline Safety Act of 1979, as amended (“HLPSA”). The HLPSA governs the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Where applicable, the HLPSA requires us and other pipeline operators to comply with regulations issued pursuant to HLPSA that are designed to permit access to and allow copying of records and to make certain reports available and provide information as required by the Secretary of Transportation.

        The Pipeline Safety Act of 1992 (the “Pipeline Safety Act”) amends the HLPSA in several important respects. The Pipeline Safety Act requires the Research and Special Programs Administration (“RSPA”) of DOT to consider environmental impacts, as well as its traditional public safety mandate, when developing pipeline safety regulations. In addition, the Pipeline Safety Act mandates the establishment by DOT of pipeline operator qualification rules requiring minimum training requirements for operators, and requires that pipeline operators provide maps and records to RSPA. It also authorizes RSPA to require certain pipeline modifications as well as operational and maintenance changes. We believe our pipelines are in substantial compliance with the HLPSA and the Pipeline Safety Act and their regulations and comparable state laws and regulations where such laws and regulations are applicable. However, we could incur significant expenses if new or additional safety measures are required.

        U.S. 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.

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

        Our domestic activities also are 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 noncompliance 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 (4) 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 requirements 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 natural gas liquids) 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. Such amendments could have a significant impact on our costs or operations.

        RCRA and comparable state and local programs impose requirements on the management, including treatment, storage and disposal, of both 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 we own or lease 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 have not had 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. Adoption of these proposals 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.

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        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. Moreover, we are able to directly control the operations of only the wells that we operate. 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.

        In 2003, DOT through RSPA adopted new requirements for certain shippers of hazardous materials. These have both training and security planning requirements that may apply to our operations. We do not believe that the costs that will be incurred by us for compliance will be significant; but cannot guarantee that potential costs for our operations would not result in material expenditures.

        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 or the extent of liability risks. We are unable to 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 are 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 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 or compliance obligations 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 9, 2004, we employed 36 full-time employees. In June 2003, in order to lower our administrative expenses, we reduced our staff by two engineers, one geologist and one part-time employee. In February 2004, we reduced our staff by two landmen. 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 have good relations with our employees. 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 natural gas producer depends upon our ability to find, develop and acquire additional oil and natural gas reserves that are profitable. If we are unable to conduct successful development activities or acquire properties containing proved reserves, our proved reserves generally will decline as reserves are produced.

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

        Our drilling will involve numerous risks, including the risk that no commercially productive oil or natural 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 natural gas requires greater pre-drilling expenditures than traditional drilling methodologies. While we use advanced technology in our operations, this technology does not allow us to know conclusively prior to drilling a well that oil or natural gas is present or economically producible.

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We Are Exposed to Operating Hazards and Uninsured Risks

        Our operations are subject to the risks inherent in the oil and natural gas industry, including the risks of:

        These events may result in substantial losses to us from:

        As is customary in our industry, we maintain insurance against some, but not all, of these risks. We cannot assure you that our insurance will be adequate to cover these losses or liabilities. We do not carry business interruption insurance. Losses and liabilities arising from uninsured or underinsured events may have a material adverse effect on our financial condition and operations.

        We carry well control insurance for our drilling operations. Our coverage includes blowout protection and liability protection on domestic and international wells.

        The producing wells in which we have an interest occasionally experience reduced or terminated production. These curtailments can result from mechanical failures, contract terms, pipeline and processing plant interruptions, market conditions and weather conditions. These curtailments can last from a few days to many months.

Company Risks

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

        We discharged our credit facilities in January 2004 and have not entered into a new credit facility. However, 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 natural gas properties and businesses. In addition, our pursuit of capital could result in us 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 will depend upon a number of factors, including:

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

        Any Future Indebtedness May Limit Our Financial and Operating Flexibility

        We may seek to obtain additional capital under satisfactory terms and conditions to finance the growth of our business. Any new debt, including short-term borrowing or long-term debt, may have important effects on our future operations, including the following:

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, 2003, our officers and directors as a group held a beneficial interest in approximately 53.14% 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 directors and 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.

We May Not Enter Into a Like-Kind Exchange Which Would Cause Us to Incur Increased Taxes

        We have placed approximately $8.0 million from the Royalty Sale in a tax-deferred escrow account. The escrow account is designed to comply with the like-kind exchange provisions of Section 1031 of the Internal Revenue Code of 1986, as amended, that permits the deferral of gains from a sale of assets if specific like-kind exchange reinvestment criteria are met. While we are attempting to acquire oil and natural gas interests that would comply with the like-kind exchange criteria, there can be no guarantee that we will be able to do so on terms satisfactory to us. If we do not comply with the like-kind exchange criteria, we will not be able to defer any of the taxes on gains from the Royalty Sale, resulting in an additional tax burden of approximately $2.5 million for 2004.

Our Business Exposes Us to Liability and Extensive Regulation on Environmental Matters

        Our operations are subject to numerous federal, state and local laws and regulations controlling the discharge of materials into the environment or otherwise relating to the protection of the environment. Such laws and regulations not only expose us to liability for our own negligence, but may also expose us to liability for the conduct of others or for our actions that were in compliance with all applicable laws at the time those actions were taken.

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

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

Our Marketing of Oil and Natural 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 natural 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 natural 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. Transportation space on the gathering systems and pipelines we utilize is occasionally limited or unavailable due to repairs or improvements to facilities or due to space being utilized by other companies that have priority transportation agreements. Our access to transportation options also can be affected by U.S. federal and state regulation and foreign regulation of oil and natural gas production and transportation, general economic conditions, and changes in supply and demand. These factors and the availability of markets are beyond our control. If market factors dramatically change, the financial impact on our revenues could be substantial and could adversely affect our ability to produce and market oil and natural gas.

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 these countries’ respective governments. There can be no assurances that we will be able to renew any of these permits that expire.

Our Production May Not Offset Hedges, and We May Not Benefit from Price Increases by Hedging

        Occasionally, we may reduce our exposure to the volatility of oil and natural 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 natural gas prices above the fixed amount specified in the hedge.

Investment Risks

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

        Occasionally 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. Even though we have no current credit facilities, we may obtain new credit facilities in the future that would restrict our ability to pay dividends on our common stock. In addition, the terms of 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.

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GLOSSARY OF SELECTED OIL AND NATURAL 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.

        “BOE.” Barrels of oil equivalent. BTU equivalent of six thousand cubic feet (Mcf) of natural gas which is equal to the BTU equivalent of one barrel of oil.

        “BTU.” British Thermal Unit.

        “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.” The present value of proved reserves is an estimate of the discounted future net cash flows from each property at December 31, 2003, or as otherwise indicated. Net cash flow is defined as net revenues, after deducting production and ad valorem taxes, less 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, 2003, 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.

        “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 capable of producing oil or natural gas in economic quantities.

        “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.

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        “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 changes, 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 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.

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.

SEGMENT REPORTING

        See Note 18 in the Notes to Consolidated Financial Statements for financial information by segment.

ITEM 2.    PROPERTIES.

INTERNATIONAL

        FRANCE

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

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        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, the Chuelles and St. Firmin-des-Bois fields in 1961 and the Courtenay Field in 1964. The property currently has 79 producing oil wells. As of December 31, 2003, the Neocomian Fields had net proved reserves of 9,714 MBbl.

        CHARMOTTES

        We own a 100% working-interest in the Charmottes Field, located 60 kilometers southeast of Paris. The property currently has nine producing oil wells. The Charmottes Field initially was developed following the discovery well drilled in 1984. As of December 31, 2003, the Charmottes Field had net proved reserves of 1,261 MBbl.

        COURTENAY EXPLORATION PERMIT

        We are operator and own a 100% working-interest in the Courtenay exploration permit. We plan to drill between three and five exploratory wells in this area during 2004. This permit surrounds the Neocomian Fields.

        TURKEY

        We have interests in the Zeynel and Cendere fields. We also hold interests in 30 exploration licenses in four other geographic regions of Turkey totaling 3.6 million gross acres (2.4 million net acres).

        ZEYNEL

        We have an 8.5% royalty interest in the Zeynel Field, located in south-central Turkey, with net proved reserves of 45 MBbl at December 31, 2003. The Zeynel-18 development well currently is being drilled.

        CENDERE

        We have a 19.6% working-interest in most wells in the Cendere Field located in central Turkey. The property has 16 oil wells currently producing. We had net proved reserves of 847 MBbl in the Cendere Field as of December 31, 2003. No wells were drilled in 2003. We expect the Cendere-20 well will be drilled in mid-2004. A 3D seismic survey is planned for this field in 2004 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 2D seismic data study covering 1,275 KMS of our exploration licenses in the Black Sea. Based on the interpretation of the seismic data in 2003, we plan to drill the Ayazli-1 well in mid-2004. This is our first exploratory well in the western Black Sea offshore Turkey and one of six natural gas prospects we have identified to date in the area. We anticipate drilling a second offshore exploratory well in 2005.

        CENTRAL AND SOUTHEAST EXPLORATION PERMITS

        We hold 21 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 into southern Turkey through the area encompassing many of our exploration permits. As of December 31, 2003, there were no net reserves for the land covered by the central and southeast exploration permits.

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        THRACE BASIN PERMIT

        We have one exploration permit in the Thrace Basin. Located in the European portion of Turkey, the basin is a natural gas play. In this part of the country, natural gas is productive from shallow depths. We could benefit from the area’s infrastructure, which includes a regional pipeline from Bulgaria to Istanbul and gas-fired power plants along the Marmara Sea coast. As of December 31, 2003, there were no net reserves for the area covered by the Thrace Basin permit.

        ROMANIA

        VIPERESTI BLOCK

        During 2003, we expanded our international portfolio when the Romanian government awarded us a concession on the Viperesti Block in exchange for a staged work commitment. We are 100% owner and operator of the block that lies in east-central Romania in the southeastern foothills of the Carpathian Mountains. This concession comprises 324,000 gross acres. We believe this block is prospective in the Tertiary formations at depths ranging from 4,500-6,000 feet.

        MOINESTI AND FAURESTI BLOCKS

        In 2003, the Romanian government also granted us an exploration permit on the Moinesti Block and a rehabilitation permit on the Fauresti Block in exchange for our entering into a three-year work program. We are 100% owner and operator of the two blocks. The Moinesti Block covers approximately 300,000 net acres. It is situated about 40 miles north of our Viperesti Block in the foothills of the Carpathian Mountains and is contiguous with eight producing oil fields. We believe the block is prospective in various producing formations from 3,000-16,000 feet. The Fauresti Block covers approximately 1,325 acres. It is located in southwestern Romania about 90 miles west of the Viperesti Block. We believe it offers development opportunities in the Jurassic Dogger formation at depths of approximately 8,000 feet.

        TRINIDAD, WEST INDIES

        In Trinidad, we own a 1% overriding royalty interest in the Bonasse Field and the Southwest Cedros Peninsula License.

DOMESTIC

        In January 2004, we sold our perpetual oil and natural gas mineral and royalty interests in approximately 2,643,000 gross acres (1,368,000 net acres) primarily located in Alabama, Arkansas, California, Kansas, Michigan, Louisiana, Mississippi and Texas in the Royalty Sale. From the approximate $45.0 million cash consideration that we received, we discharged our outstanding credit facilities and placed approximately $8.0 million in a tax-deferred escrow account for a possible like-kind exchange. The escrow account is designed to comply with the like-kind exchange provisions of Section 1031 of the Internal Revenue Code of 1986, as amended, which permits the deferral of taxes on the gains from a sale of assets if specific like-kind exchange reinvestment criteria are met. We are attempting to acquire working-interests that would comply with the like-kind exchange criteria.

        Currently, we hold working-interests in 906 gross wells (50 net wells) primarily in Texas, Oklahoma, New Mexico, Kansas, and Louisiana.

        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. 7 and No. 8 wells were successfully drilled and completed as oil wells in 2004. This brings the number of producing wells in the field to 11. In early 2004, we also participated in the drilling and abandonment of the Pitchfork-Toreador 22-9 well operated by Hollis R. Sullivan Inc. We maintain a 9.375% working-interest in the field which consists of ten producing wells.

        In West Texas, we own a 16.6% working-interest on 6,000 gross acres where two well were successfully completed in 2003. In early 2004 two additional wells were drilled. The CEGX Jones Estate 31-1 well was drilled and completed and is currently testing. The CEGX Jones Estate 22-1 well is awaiting completion. 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.

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TITLE TO OIL AND NATURAL 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 that cover five producing oil fields in the Paris Basin are:

        Although the French government has no obligation 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 these exploitation leases and exploration licenses by the Turkish government:

        Under Turkish law, “exploitation leases” are generally granted for a period of  20 years and may be renewed upon application for two additional 10-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

        We do not hold title to, but have concessions to, property in Romania that entitles us to explore and produce hydrocarbons. We have not yet established proved reserves on any of these properties. We have two exploration concessions and one exploitation concession. The terms of both the exploration and exploitation concessions are five years from the date the concessions are signed by the ministry. The Viperesti exploration concession has been signed by the ministry and is to expire in 2009.

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      DOMESTIC

        We currently own interests in producing acreage only in the form of working-interests due to the Royalty Sale in January 2004.

        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 natural 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.

        Our properties are generally subject to:

        We believe that none of these burdens either materially detracts from the value of our properties or materially interferes with their use in the operation of our business.

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OIL AND NATURAL GAS RESERVES

        The following table sets forth information about our estimated net proved reserves at December 31, 2002 and 2003 and as adjusted at December 31, 2003 to reflect the Royalty Sale. 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 Natural Gas Producing Activities. No reserve reports have been provided to any governmental agencies.

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        Reserves were estimated using oil and natural gas prices and production and development costs in effect on December 31, 2002 and 2003, without escalation. The reserves were determined using both volumetric and production performance methods. France and Turkey only have oil reserves. 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.

        For additional information concerning our oil and natural gas reserves and estimates of future net revenues attributable thereto, see Note 19 of the Notes to the Consolidated Financial Statements.

PRODUCTIVE WELLS

        The following table shows our gross and net interests in productive oil and natural gas working-interest wells as of December 31, 2003. Productive wells include wells currently producing or capable of production.

ACREAGE

        The following table shows the developed and undeveloped acreage attributable to our ownership as of December 31, 2003.

        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 natural gas regardless of whether or not the acreage contains proved reserves.

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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 and as adjusted to reflect the Royalty Sale in January 2004. 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.

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PRESENT ACTIVITIES

        For the period January 1, 2004 through April 9, 2004, we did not participate in the drilling of any exploratory wells.

OFFICE LEASE

        We occupy approximately 16,327 square feet of office space at 4809 Cole Avenue, Suite 108, Dallas, Texas 75205 under a lease from SVP Cole, 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. Total rental expense for 2003 was approximately $356,000.

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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. Payments totaling $105,000 were made during 2003. The remaining balance due was paid in January 2004.

        Turkish Registered Capital. Under the existing Petroleum Law of Turkey, capital that is invested by foreign companies in projects such as oil and natural 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 the 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. In March 2002, a lower level court ruled in favor of Madison. The ruling was subject to automatic appeal that was heard on December 31, 2002. The appellate court reversed the lower court’s ruling. We have appealed the ruling of the appellate court and are still waiting on a definitive date to be set for the case. The current appeal is the last appeal that can be made by either side in this case. However, we cannot predict the outcome of this matter. If we receive any repatriated capital payments from the Turkish government by December 31, 2004 that was applied for by December 31, 2003, the holders of Madison common stock have the right to receive, in cash or our common stock, 30% of such payments.

        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 calendar 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 March 26, 2004, there were 9,500,317 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 7, 2004 was $4.76. The closing price on the Toronto Stock Exchange on April 7, 2004 was Canadian $6.25.

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. Our Board of Directors plans to continue our policy of holding and investing corporate funds on a conservative basis, so we do not anticipate paying cash dividends on our common stock in the foreseeable future. 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 $360,000, $360,000 and $360,000 were declared, and $450,000, $270,000 and $360,000 were paid for the years ended December 31, 2003, 2002 and 2001, respectively, on the Series A Convertible Preferred Stock. Cash dividends totaling $139,549 and $14,000 were declared for the years ended December 31, 2003 and December 31, 2002 on the Series A-1 Convertible Preferred Stock. Cash dividends totaling $153,549 were paid for the year ended December 31, 2003 on the Series A-1 Convertible Preferred Stock. No cash dividends were paid for the year ended December 31, 2002, on the Series A-1 Convertible Preferred Stock. Future dividends are anticipated to be paid in cash only at a rate of $180,000 per calendar quarter.

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SALES OF UNREGISTERED SECURITIES

        In the fourth quarter of 2003, we issued the following equity securities that were not registered under the Securities Act of 1933, as amended:

        During the fourth quarter of 2003, pursuant to private placements we issued 83,000 shares of our Series A-1 Convertible Preferred Stock as follows: (i) in October 2003, 34,000 shares were issued to Mr. William I. Lee, one of our directors, and Wilco, an entity controlled by Mr. Lee; (ii) in December 2003, 42,000 shares were issued; and (iii) in December 2003, 7,000 shares were issued to Wilco. The aggregate proceeds from these sales were $2,075,000.

        The Series A-1 Convertible Preferred Stock was sold for $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 when the issuances occurred. 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 agreements, Toreador granted certain “piggy-back” registration rights relating to 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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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.

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

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

        Certain of the matters discussed under the captions “Business,” “Properties,” “Legal Proceedings,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and elsewhere in this annual report may constitute “forward-looking” statements for purposes of the 1933 Act, and the Securities Exchange Act of 1934 and, as such, may involve known and unknown risks, uncertainties and other factors that may cause the actual results, performance or achievements of us to be materially different from future results, performance or achievements expressed or implied by such forward-looking statements. When used in this report, the words “anticipates,” “estimates,” “plans,” “believes,” “continues,” “expects,” “projections,” “forecasts,” “intends,” “may,” “might,” “could,” “should,” and similar expressions are intended to be among the statements that identify forward-looking statements. Various factors that could cause the actual results, performance or achievements of us to differ materially from our expectations are disclosed in this report (“Cautionary Statements”), including, without limitation, those statements made in conjunction with the forward-looking statements included under the captions identified above and otherwise herein. All written and oral forward-looking statements attributable to us are expressly qualified in their entirety by the Cautionary Statements.

EXECUTIVE OVERVIEW

        The following financial statement analysis is based on results of operations before the Royalty Sale was consumated in January 2004. Amounts applicable to discontinued operations are detailed in Note 17 of the Notes of Consolidated Financial Statements.

        In 2003, Toreador’s oil and natural gas sales revenues rose 9% to $25.1 million compared with $23.0 million in 2002 primarily due to strong oil and natural gas prices during the year. In 2003, our average oil price per barrel increased 19%, and our average price for natural gas was 56% higher than the year earlier. The increase in revenues was partially offset by a 14% decrease in oil and natural gas production, the result of the natural decline of our existing properties and the sale of various underperforming properties at the end of 2002 and in 2003.

        This favorable pricing environment allowed us to reduce the loss on oil and natural gas production hedges 43%. In addition, we continued to manage the business more efficiently by focusing on management’s objective of reducing general and administrative expenses, which were down 33% in 2003. Depreciation, depletion and amortization also was 22% lower compared with 2002.

        Toreador’s primary focus in 2003 was to aggressively reduce debt and strengthen our balance sheet. During the year, we used $2.8 million of our available cash to reduce the amounts outstanding under the revolving credit facility with Barclays Bank, Plc (the “Barclays Facility”). During 2003, we reduced senior long-term debt, including the current portion, 14% to $28.7 million from $33.4 million at year-end 2002. This debt reduction reduced our 2003 interest expense 23%.

        We closed the Royalty Sale to Black Stone Acquisitions Partners I, L.P. in January 2004. Subsequently, we discharged our two senior borrowing facilities, the Barclays Facility and the Bank of Texas facility (the “Texas Facility”) with a portion of the proceeds from the Royalty Sale.

CRITICAL ACCOUNTING POLICIES

        The process of preparing financial statements in conformity with accounting principles generally accepted in the United States requires us to use estimates and assumptions to determine certain of our assets, liabilities, revenues and expenses. We base these estimates and assumptions upon the best information available to us at the time the estimates or assumptions are made. Our estimates and assumptions could change materially as conditions within and beyond our control change. Accordingly, our actual results could differ materially from our estimates. The most significant estimates made by our management include future net cash flow for purposes of evaluating oil and natural gas properties for impairment, unrealized gains and losses on commodity derivatives, oil and natural gas sales receivable, and valuation of goodwill. The following is a discussion of our critical accounting policies and the related management estimates and assumptions necessary in determining the value of related assets or liabilities. A full description of all of our significant accounting policies is included in Note 2 to our Consolidated Financial Statements included in this annual report.

        We follow the successful efforts method of accounting for our oil and natural gas properties. Under this method, we capitalize the costs of successful wells and expense the costs of dry holes. Accordingly, our operations can be materially impacted if our drilling efforts are unsuccessful. Dry hole costs amounted to $1.3 million in 2003, $1.1 million in 2002 and $1.8 million in 2001. Under the successful efforts method, we must also evaluate our investments in each producing field. If such investments are greater than our estimates of undiscounted future net cash flow, then we must record a charge to impairment for the difference between our investment and the discounted future net cash flow. Accordingly, any year in which oil and/or natural gas prices decline, our operations and financial position could be materially impacted by a charge to impairment. Such charges amounted to $171,000 in 2003, $0.5 million in 2002 and $1.3 million in 2001.

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        Because our primary revenues are from oil and natural gas sales, we are exposed to fluctuations in oil and natural gas commodity prices. We employ a policy of hedging well-defined price risks with oil and natural gas swaps and options, but we do not designate such instruments as hedges for accounting purposes. Because we do not designate our derivatives as hedges, we record them at fair value based on the current price of either the option or swap as quoted on the New York Mercantile Exchange and recognize changes in their fair values in earnings as they occur. Accordingly, our operations and financial position could be materially impacted by changes in the fair values of our hedging instruments. Such changes in the fair values of our hedging instruments are driven by commodity prices. The following summarizes the results of our hedging program:

        We estimate our accrual for oil and natural gas sales receivable by first predicting the volumes we will produce based on recent production trends and, if available, production information provided by our operators. Then we multiply those volumes by the average posted commodity prices for the periods of production, less a differential. The product is our oil and natural gas sales receivable accrual. Our estimates of quantity production or average price could vary from actual quantities produced and prices realized, causing material variations in our financial position and results of operations.

        As a result of our acquisition of Madison, we recorded approximately $5.0 million of goodwill. This goodwill was allocated between reporting units based on the relative value of each unit’s proved reserves. Goodwill was reduced by $2.4 million in 2003 for a corresponding reduction in deferred tax liabilities which resulted from our commitment to fully reinvest in our international subsidiaries. We periodically review the value of goodwill by comparing it with future net cash flow realizable from the properties we acquired in the acquisition of Madison. To the extent that the recorded amount of goodwill plus the carrying value of the oil and natural gas properties is greater than the future net cash flow related to the oil and natural gas properties acquired, we record a charge to goodwill for the difference in the recorded value and our estimate of discounted net cash flow. We noted no impairment indicators related to goodwill for the year ended December 31, 2003.

RECENT ACCOUNTING PRONOUNCEMENTS

        On August 15, 2001, the FASB issued Statement No. 143, Accounting for Asset Retirement Obligations (“Statement 143”). Initiated in 1994 as a project to account for the costs of nuclear decommissioning, the FASB expanded the scope to include similar closure or removal-type costs in other industries that are incurred at any time during the life of an asset. That standard requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. The standard became effective for fiscal years beginning after June 15, 2002. We adopted Statement 143 on January 1, 2003. Upon adoption of Statement 143, we recorded an increase to Property and Equipment and an offsetting entry to Asset Retirement Obligations of approximately $1,690,000 and $1,716,000, respectively, as a result of the Company separately accounting for salvage values and recording the estimated fair value of its plugging and abandonment obligation on the balance sheet. The impact of adopting Statement 143 was determined to be immaterial. We do not expect the effects of adopting Statement 143 to have a material impact on our financial position or results of operations in future years.

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        The following table describes on a pro forma basis the effect on net loss of the asset retirement obligation as if Statement 143 had been adopted on January 1, 2002:

        Effective January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 145, Rescission of FAS Statements No. 4, 44 and 64, Amendment of FAS Statement No. 13, and Technical Corrections (“Statement 145”).  Through the rescission of FAS Statements 4 and 64, Statement 145 eliminates the requirement that gains and losses from extinguishment of debt be aggregated and, if material, be classified as an extraordinary item net of any income tax effect.  Statement 145 made several other technical corrections to existing pronouncements that may change accounting practice.  Adoption of Statement 145 had no impact on the Company’s results of operations or financial position at December 31, 2003.

        In July 2002, the FASB issued Statement No. 146, Accounting for Costs Associated with Exit or Disposal Activities (“Statement 146”). Statement 146 requires that a liability for costs associated with an exit or disposal activity should be initially recognized when it is incurred. Under previous standards, such costs were recognized in the period in which an entity committed to a plan of disposal. Under Statement 146, the costs are recognized in the period when an actual disposal is under way. Examples of costs included under Statement 146 include one-time termination benefits, costs to consolidate or close facilities and costs to relocate employees. Statement 146 is effective for exit or disposal activities initiated after December 31, 2002. On June 17, 2003, Toreador committed to the termination of four employees. Two engineers, one geologist and one part-time employee were terminated in an effort to reduce general and administrative costs. Total severance expense and liability for the year ended December 31, 2003, were approximately $511,000 and $310,000, respectively. The following table provides a reconciliation of the liability:

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        In December 2002, the FASB issued Statement No. 148, Accounting for Stock-Based Compensation – Transition and Disclosure (“Statement 148”). Statement 148 provides alternative methods of transition to the fair value method of accounting proscribed by FASB Statement No. 123, Accounting for Stock-Based Compensation (“Statement 123”). Statement 148 also amends the disclosure provisions of Statement 123 and Accounting Principles Board Opinion No. 28, Interim Financial Reporting, to require disclosure in the summary of significant accounting policies of the effects of an entity’s accounting policy with respect to stock-based employee compensation on reported net income and earnings per share in annual and interim financial statements. Statement 148 does not require companies to account for employee stock options under the fair value method. We do not anticipate adopting the fair value method of accounting for stock-based compensation; however, we have adopted the disclosure provisions of Statement 148 in this filing. Net income would have been adjusted for the pro forma amounts as follows:

        Effective January 1, 2003, the Company adopted Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others (“FIN 45”).  FIN 45 broadens the disclosures to be made by the guarantor about its obligations under certain guarantees. FIN 45 also requires a guarantor to recognize a liability for the fair value of the obligation undertaken in issuing the guarantee at the inception of a guarantee.  Adoption of FIN 45 did not have an impact on the Company’s results of operations or financial position at December 31, 2003.

        In April 2003, the FASB issued Financial Accounting Standards No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities (“Statement 149”).  Statement 149 amends and clarifies the accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under Statement 133, Accounting for Derivative Instruments and Hedging Activities.  Statement 149 is generally effective for contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003. The adoption of this statement did not have an impact on the Company’s results of operations or financial position at December 31, 2003.

        In May 2003, the FASB issued Financial Accounting Standards No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity (“FAS 150”).  FAS 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity.  FAS 150 is generally effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003.  The adoption of this statement’s operational components did not have an impact on the Company’s results of operations or financial position at December 31, 2003.

        In January 2003, the FASB issued Interpretation No. 46, Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51, which was revised and superceded by FASB Interpretation No. 46R in December 2003 (“FIN 46R”). FIN 46R requires the consolidation of certain variable interest entities, as defined.  FIN 46R is effective immediately for special purpose entities and variable interest entities created after December 31, 2003, and must be applied to other variable interest entities no later than December 31, 2004. The Company believes it has no such variable interest entities and as a result FIN 46R will have no impact on its results of operations, financial position or cash flows.

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        The oil and natural gas industry is currently discussing the appropriate balance sheet classification of oil and natural gas mineral rights held by lease or contract. The Company classifies these assets as property, plant, and equipment in accordance with its interpretation of Financial Accounting Standards No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, and common industry practice. There is also a view that these mineral rights are intangible assets as defined in Financial Accounting Standards No. 141 (“Statement 141”), Business Combinations, and, therefore, should be classified separately on the balance sheet as intangible assets. If the accounting for mineral rights held by lease or contract is ultimately changed, we believe that any such reclassification of mineral rights could amount to approximately $7.1 million at December 31, 2003, if we are required to include the purchase price allocated to hydrocarbon reserves obtained in acquisitions of oil and natural gas properties. The determination of this amount is based on our current understanding of this evolving issue and how the provisions of Statement 141 might be applied to oil and natural gas mineral rights. This potential balance sheet reclassification would not affect results of operations or cash flow.

LIQUIDITY AND CAPITAL RESOURCES

        During 2003, cash flow from operations was $6.9 million, compared with $6.4 million for 2002. We continually review the operating results of each of our properties. If there are underperforming properties, we attempt to liquidate them. During 2003, we received $424,000 in proceeds from sales of property and equipment. We anticipate that cash flow from operations during 2004 will be approximately $6.2 million, which will be used for budgeted capital expenditures.

        During 2003, pursuant to private placements we sold 123,000 shares of our Series A-1 Convertible Preferred Stock for an aggregate purchase price of $3,075,000. We have used the net proceeds from the private placements to fund portions of our exploration and development program and for other general corporate purposes.

        At the end of 2003, we had two senior borrowing facilities. The Texas Facility had borrowings outstanding of approximately $17.0 million at December 31, 2003. We discharged the Texas Facility in January 2004 with a portion of the proceeds from the Royalty Sale. During 2003, we made net payments of $1.7 million to reduce the amounts outstanding under the Texas Facility.

        The Barclays Facility had approximately $11.8 million in borrowings outstanding at December 31, 2003. During 2003, we used $2.8 million of our available cash flow to reduce the amounts outstanding under the Barclays Facility. We discharged the Barclays Facility in January 2004 with a portion of the proceeds from the Royalty Sale. Under the terms of the Warrant Buyback Letter dated May 19, 2003, we were required to buy 500,000 outstanding warrants back from Barclays for the sum of $100,000 upon final settlement of the Barclays Facility. Additionally, we were required to make a final settlement payment of $925,000 less the amounts of any payments made to Barclays for interim fees due before the final settlement under the terms of the Settlement Fee Letter dated May 19, 2003. The settlement payment amount after deduction of the interim fees paid to Barclays was approximately $806,000.

        We anticipate that our 2004 capital expenditures budget, excluding any acquisitions we may make, will be approximately $7.0 million. We intend to fund our capital expenditures budget from operating cash flow and cash currently on hand.

        We anticipate spending most of our 2004 capital budget on prospects in our foreign inventory. We anticipate limiting our activity in France to development drilling on our existing properties and exploration work on the Courtenay permit. In Turkey, we anticipate continuing exploration work on several projects, including plans to drill our first exploratory well in the western Black Sea.

        We maintain our excess cash funds in interest-bearing deposits and in marketable securities.

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        We believe that sufficient funds will be available from operating cash flow, cash on hand and future potential financing sources (which may include senior debt, subordinated debt and/or equity ) to meet anticipated capital budget requirements and fund potential acquisitions in 2004. The following table sets forth our contractual obligations at the end of 2003 for the periods shown:

        Through December 31, 2003, we used $2,534,000 of our cash reserves to purchase 721,027 shares of our common stock including 40,000 that were repurchased during 2002 for $180,000. No shares of our common stock were repurchased during 2003. Based on market conditions and cash availability, we intend to repurchase shares of our common stock when we deem appropriate. Such repurchases will be funded from available operating cash flows.

        Dividends on our common stock may be declared and paid out of funds legally available when and as determined by our Board of Directors. Our policy is to hold and invest corporate funds on a conservative basis, and thus we do not anticipate paying cash dividends on our common stock in the foreseeable future. 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. Cash dividends totaling $500,000 were declared and $604,000 were paid for the year ended December 31, 2003. Cash dividends of $374,000 and $360,000 were declared in 2002 and 2001, respectively. Cash dividends of $270,000 and $360,000 were paid in 2002 and 2001, respectively. Future dividends are expected to be paid only in cash at a rate of $180,000 per calendar quarter.

        No stock options were exercised during 2003 or 2002.

RESULTS OF OPERATIONS

        COMPARISON OF YEARS ENDED DECEMBER 31, 2003 AND 2002

        The following financial statement analysis is based on results of operations before the royalty sale was consummated in January 2004. Amounts applicable to discontinued operations are detailed in Note 17 of the Consolidated Financial Statements.

        REVENUES

        Oil and natural gas sales. For the year ended December 31, 2003, oil and natural gas sales revenues were $25.1 million, increasing approximately $2.0 million, or 9%, from $23.1 million for the year ended December 31, 2002. This was due to an increase in the average prices we received for oil and natural gas sales. In 2003, our average oil price per barrel was $26.30 versus $22.08 in 2002. Our average price for natural gas in 2003 was $4.83 per Mcf, compared with $3.10 in 2002. The increase in revenues was offset by a decrease in overall production of 153,000 BOE, or 14%, from 1,069,000 BOE in 2002 to 916,000 BOE in 2003. United States production decreased 90,000 BOE, the result of the natural decline of our existing properties and the sale of miscellaneous underperforming properties at the end of 2002 and during 2003. French production decreased 41,000 BOE, a result of the temporary loss of producing wells during the year. We were unable to complete necessary workover maintenance on these wells in a timely manner due to financial constraints created by the Barclays Facility.

        Gain (loss) on commodity derivatives. We utilize commodity derivative instruments as part of our risk management program and, prior to the repayment of our senior credit facilities in January 2004, we utilized them to comply with the requirements of our senior credit facilities. These transactions are generally structured as either swaps or collar contracts. A swap has the effect of an outright sale at a specific price. A collar has the effect of creating a sale only if a floor or ceiling price is exceeded. These instruments (i) reduce the effect of the price fluctuations of the commodities we produce and sell; and (ii) support our annual capital budgeting and expenditure plans. When we had our senior credit facilities, these instruments protected the amounts required for servicing outstanding debt; and maximized the funds available under these facilities. The trading party that represents the other side of each of these transactions is known as a “counterparty.” The counterparty of our United States transactions is Coral Energy Holdings, L.P., an affiliate of Royal Dutch/Shell. The counterparty of our French transactions was Barclays Capital. Currently we do not have any commodity derivative instruments for our French production. The following table summarizes the results of our risk-management efforts during 2003 and 2002:

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        As noted above, we have structured our commodity derivatives to reduce the effect of price fluctuations of the commodities we produce and sell. As a result, those derivatives decline in value as the underlying commodity prices rise. Any losses incurred on derivatives are offset by higher oil and natural gas sales revenues due to increases in underlying commodity prices. However, under the requirements of Statement of Financial Accounting Standards No. 133 and because we chose not to designate our derivatives as hedges, mark to market loss on the derivatives is generally accrued through earnings prior to the recognition of higher sales prices. See Note 8 in the Notes to Consolidated Financial Statements included in this filing for more details.

        Lease bonuses and rentals. Lease bonuses and rentals decreased $453,000, or 56% from 2002 to 2003, due to reduced leasing activity on the minerals we owned.

        EXPENSES

        Lease operating. Lease operating expenses increased $1.0 million, or 15%, primarily due to the increase in value of the Eurodollar against the U.S. dollar in relation to our French leases. Additionally, U.S. production taxes increased in 2003, a result of the increase in oil and natural gas sales prices discussed above.

        Exploration and acquisition. Exploration and acquisition expense increased $177,000, or 8% from 2002 to 2003, due to increased evaluation activity on our prospects in Turkey.

        Depreciation, depletion and amortization. DD&A decreased $1.1 million, or 22%, compared with 2002 due to decreased production and decreased reserve balances. We calculate depletion on our oil and natural gas properties using the units-of-production method. Current-year production is divided by beginning reserves and then multiplied by the net value of the properties. Production decreased 14% from 2002 and reserves during the same period decreased 3%, resulting in a lower depletion rate for 2003.

        Impairment of oil and natural gas properties. Impairment charged in 2003 amounted to $171,000, compared with $529,000 in 2002, both of which only related to U.S. properties. The decrease in the impairment charge is the result of an increase in year-end pricing offset by a decrease in the value of our reserves. Oil and natural gas prices used to estimate the value of our reserves at December 31, 2002, were $28.00 per barrel and $4.74 per Mcf, compared with $29.25 per barrel and $5.76 per Mcf at December 31, 2003.

        General and administrative. General and administrative expenses decreased $2.5 million, or 32%. The majority of this decrease was the result of the cost increase incurred in connection with the acquisition of Madison that was expensed in 2002. A significant portion of the expenses associated with the Madison acquisition comprised nonrecurring items that were either transaction and transition costs or other one-time expenses. General and administrative costs were also lower in 2003 due to a reduction in personnel costs. One of management’s primary objectives is to continue to reduce expenses.

        OTHER INCOME AND EXPENSE

        Other income and expense resulted in a net expense of $650,000 during 2003 versus $6.0 million for 2002. Net expense decreased $5.3 million, primarily due to losses on property sales in 2002. We incurred losses on property sales of $2.1 million during 2002, compared with a gain of $80,000 in 2003. The remainder of the decrease was a result of foreign currency transaction gains made on payments towards the Barclays Facility and lower interest expense due to the value of the Eurodollar increasing against the U.S. dollar.

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        NET INCOME (LOSS) AVAILABLE TO COMMON SHARES

        During 2003, we had earnings available to common stockholders of $1.9 million, compared with a net loss of $6.5 million for 2002. Improved results for 2003 were due to an increase in foreign currency transaction gains, a reduction in losses on commodity derivatives (oil and natural gas hedges), an increase in oil and natural gas revenues due to higher average prices, and lower general and administrative expenses. In addition, in 2002 we incurred one-time transaction and transition costs related to the Madison acquisition, and the value of our investment in Trinidad Exploration and Development, Ltd. (“TED”) declined.

        OTHER COMPREHENSIVE INCOME

        The most significant element of comprehensive income, other than net income (loss), is foreign currency translation. The functional currency of our operations in France is the Eurodollar, and in Turkey the functional currency is the Turkish Lira. The exchange rates used to translate the financial position of those operations at December 31, 2003, were approximately U.S. $1.26 per Eurodollar and U.S. $0.70 per million Turkish Lira. At December 31, 2002, the exchange rates were U.S. $1.05 per Eurodollar and U.S. $0.62 per million Turkish Lira. These fluctuations caused an unrealized translation gain of $2.2 million in 2003, compared with an unrealized translation gain of $2.2 million in 2002.

        COMPARISON OF YEARS ENDED DECEMBER 31, 2002 AND 2001

        The following financial statement analysis is based on results of operations before the Royalty Sale was consummated in January 2004. Amounts applicable to discontinued operations are detailed in Note 17 of the Notes to the Consolidated Financial Statements.

        REVENUES

        Oil and natural gas sales. For the year ended December 31, 2002, oil and natural gas sales revenues were $23.1 million, increasing approximately $9.1 million, or 65%, from $14.0 million for the year ended December 31, 2001. Oil and natural gas sales revenues from the properties acquired in the Madison acquisition amounted to $11.6 million, while U.S. revenues decreased $2.4 million, or 18%. The decrease in U.S. revenues was the result of both production and price declines. U.S. production decreased 53,000 BOE, or 9%, the result of the natural decline of our existing properties and the sale of miscellaneous underperforming properties during 2002. In 2002, our average oil price per barrel was $22.08 versus $23.39 in 2001. Our average price for natural gas in 2002 was $3.10 per Mcf, compared with $3.76 in 2001.

        Gain (loss) on commodity derivatives. We utilize commodity derivative instruments as part of our risk management program and to comply with the requirements of our senior credit facilities. These transactions are generally structured as either swaps or collar contracts. A swap has the effect of an outright sale at a specific price. A collar has the effect of creating a sale only if a floor or ceiling price is exceeded. These instruments (i) reduce the effect of the price fluctuations of the commodities we produce and sell; (ii) support our annual capital budgeting and expenditure plans; (iii) protect the amounts required for servicing outstanding debt; and (iv) maximize the funds available under our existing credit facilities. The trading party that represents the other side of each of these transactions is known as a “counterparty.” The counterparty of our United States transactions is Coral Energy Holdings, L.P., an affiliate of Royal Dutch/Shell. The counterparty of our French transactions is Barclays Capital. The following table summarizes the results of our risk-management efforts during 2002 and 2001:

        As noted above, we have structured our commodity derivatives to reduce the effect of price fluctuations of the commodities we produce and sell. As a result, those derivatives decline in value as the underlying commodity prices rise. Any losses incurred on derivatives are offset by higher oil and natural gas sales revenues due to increases in underlying commodity prices. However, under the requirements of Statement of Financial Accounting Standards No. 133 and because we chose not to designate our derivatives as hedges, mark to market loss on the derivatives is generally accrued through earnings prior to the recognition of higher sales prices. See Note 8 in the Notes to Consolidated Financial Statements included in this filing for more details.

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        Lease bonuses and rentals. Lease bonuses and rentals increased $216,000, or 36%, due to increases in leasing activity, a result of several wildcat discoveries in and around the minerals we owned in Mississippi.

        EXPENSES

        Lease operating. Lease operating expenses increased $3.4 million, or 104%, due to the operations of the properties we acquired in the Madison acquisition and are commensurate with the increase in operating revenue from the Madison properties. Higher lease operating expenses were offset by decreases in U.S. production taxes, the result of the decline in oil and natural gas sales prices discussed above. In 2002 operating expenses associated with the properties in the Madison acquisition amounted to $4.1 million.

        Exploration and acquisition. Exploration and acquisition expense decreased $385,000, or 15%, due to a reduction in drilling activity, compared with 2001.

        Depreciation, depletion and amortization. DD&A remained relatively unchanged from 2001 at approximately $5.0 million. An increase due to depletion of costs allocated to properties acquired in the Madison acquisition of approximately $1.9 million was offset by a decrease in U.S. depletion of $1.7 million. The decrease in U.S. depletion was the result of higher reserve quantities. We calculate depletion on our oil and natural gas properties using the units-of-production method. Current-year production is divided by beginning reserves and then multiplied by the net value of the properties. Production decreased 9% from 2001, resulting in a lower depletion rate.

        Impairment of oil and natural gas properties. Impairment charged in 2002 amounted to $529,000, compared with $1.3 million in 2001, both of which only related to U.S. properties. The decrease in the impairment charge is the result of an increase in the value of our reserves commensurate with the increase in year-end pricing. Oil and natural gas prices used to estimate the value of our reserves at December 31, 2001, were $17.52 per barrel and $2.71 per Mcf, compared with $28.00 and $4.74 at December 31, 2002.

        General and administrative. General and administrative expenses increased $4.9 million, or 175%. The majority of this increase was the result of the Madison acquisition; however, a significant portion of these expenses comprises nonrecurring items that were either transaction and transition costs or other one-time expenses. General and administrative expense of approximately $2.3 million was directly attributable to the operation of our newly acquired French and Turkish properties. The balance represents the ongoing expenses of the support staff that joined us as a result of the Madison acquisition.

        OTHER INCOME AND EXPENSE

        Other income and expense resulted in a net expense of $6.0 million during 2002 versus $1.8 million for 2001. Net expense increased $4.2 million, primarily due to a decline in the value of our investment in TED, losses on property sales and increased interest expense. During 2002, our interest in TED was reduced from 25.0% to 16.33%. Accordingly, we recorded a charge to equity in earnings of unconsolidated entities of $1.2 million reflecting the valuation of the ultimate amount estimated to be recovered from our investment.

        In addition to the decline in value of our investment in TED, we incurred losses on property sales of $2.1 million during 2002, compared with $0.5 million in 2001. As part of our ongoing program to high grade our property portfolio, we elected to proceed with the sale of several non-economic, non-strategic properties that were underperforming rather than sustain continued operating losses on those properties. Interest expense increased as a result of the revolving credit balances and the convertible debenture assumed in the Madison acquisition.

        NET INCOME (LOSS) AVAILABLE TO COMMON SHARES

        During 2002, we incurred a net loss of $6.5 million, compared with $1.0 million for 2001. Lower results for 2002 were due to losses on commodity derivatives (oil and natural gas hedges), one-time transaction and transition costs related to the Madison acquisition, higher operating costs of the newly combined company after the addition of the Madison exploration staff, the decline in value of our investment in TED and losses on the sales of underperforming properties.

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        OTHER COMPREHENSIVE INCOME

        The most significant element of comprehensive income, other than net income (loss), is foreign currency translation. The functional currency of our operations in France is the Eurodollar, and in Turkey the functional currency is the Turkish Lira. The exchange rates used to translate the financial position of those operations at December 31, 2002, were approximately U.S. $1.05 per Eurodollar and U.S. $0.62 per million Turkish Lira. The exchange rates at December 31, 2001, were U.S. $0.87 per Eurodollar and U.S. $0.69 per million Turkish Lira. These fluctuations caused an unrealized translation gain of $2.2 million in 2002. No charges existed in 2001 because we had no foreign operations during that period.

        SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

        We derived the selected historical financial data in the table below from our unaudited interim consolidated financial statements. The sum of net income per share by quarter may not equal the net income per share for the year due to variations in the weighted average shares outstanding used in computing such amounts. The historical data presented here are only a summary and should be read in conjunction with the consolidated financial statements, related notes and other financial information included elsewhere in this annual report.

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ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

        The risks inherent in our market-sensitive instruments are the potential loss arising from adverse changes in oil and natural gas prices, interest rates and foreign currency exchange rates as discussed below. The sensitivity analysis however, neither considers the effects that such adverse changes may have on overall economic activity nor does it consider additional actions we may take to mitigate our exposure to such changes. Actual results may differ.

        The following quantitative and qualitative information is provided about financial instruments to which we are a party as of December 31, 2003, and from which we may incur future earnings gains or losses from changes in commodity prices. We do not designate our derivatives as hedges; however, we do not enter into derivative or other financial instruments for trading purposes.

        Oil And Natural Gas Prices. We market our oil and natural gas production primarily on a spot market basis. As a result, our earnings could be affected by changes in the prices for these commodities, regulatory matters or demand for the commodities. As market conditions dictate, from time to time we will lock in future oil and natural gas prices using various hedging techniques. We do not use such financial instruments for trading purposes, and we are not a party to any leveraged derivatives. Market risk is estimated as a 10% decrease in the prices of oil and natural gas. Based on our projections for 2004 sales volumes at fixed prices, such a decrease would result in a reduction to oil and natural gas sales revenue of approximately $1.8 million before considering the effect of the natural gas hedging agreements discussed below.

        Foreign Currency Exchange Rates. The functional currency of our French operations is the Eurodollar, and the functional currency of our Turkish operations is the Turkish Lira. While our oil sales are calculated on a U.S. dollar basis, we are exposed to the risk that the values of our French and Turkish assets will decrease and that the amounts of our French and Turkish liabilities will increase. Market risk is estimated as a 10% decrease in the exchange rate for Eurodollars and Turkish Lira to U.S. dollars. Based on the net assets in our French and Turkish operations at December 31, 2003, such a decrease would result in an unrealized loss of approximately $2.9 million due to foreign currency exchange rates.

        Derivative Financial Instruments. We utilize commodity derivative instruments as part of our risk management program and, prior to the repayment of our senior credit facilities in January 2004, we utilized them to comply with the requirements of our senior credit facilities. These transactions are generally structured as either swaps or collar contracts. A swap has the effect of an outright sale at a specific price. A collar has the effect of creating a sale only if a floor or ceiling price is exceeded. These instruments (i) reduce the effect of the price fluctuations of the commodities we produce and sell and (ii) support our annual capital budgeting and expenditure plans. When we had our senior credit facilities, these instruments protected the amounts required for servicing outstanding debt and maximized the funds available under these facilities. The trading party that represents the other side of each of these transactions is known as a “counterparty.” The counterparty of our United States transactions is Coral Energy Holdings, L.P., an affiliate of Royal Dutch/Shell. The counterparty of our French transactions was Barclays Capital. Currently, we do not have any commodity derivative instruments for our French production.

        The following table lists our open natural gas derivative contracts as of December 31, 2003. All contracts are based on NYMEX pricing. We estimated the fair value of the option agreement at December 31, 2003, from quotes by the counterparty representing the amounts we would expect to receive or pay to terminate the agreements on that date. We estimated the fair value of the swap agreement based on the difference between the strike prices and the forward NYMEX discounted prices for each determination period multiplied by the notional volume for each period.

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        See Note 2 of Notes to Consolidated Financial Statements for a description of our accounting procedures followed relative to hedge derivative financial instruments and for specific information regarding the terms of our derivative financial instruments that are sensitive to changes in crude oil and natural gas commodity prices.

ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

        The Reports of Independent Accountants and Consolidated Financial Statements are set forth beginning on page F-1 of this annual report on Form 10-K and are incorporated herein.

        The financial statement schedules have been omitted because they are not applicable or the required information is shown in the Consolidated Financial Statements or the Notes to the Consolidated Financial Statements.

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

        See our Current Report on Form 8-K dated September 26, 2003, and our Current Report on Form 8-K/A dated October 8, 2003, relating to the change of our accountants.

        On September 23, 2003, we dismissed Ernst & Young LLP as our independent accountant and retained Hein + Associates LLP as our independent accountant. The decision to engage Hein + Associates LLP and to dismiss Ernst & Young LLP was approved by our Audit Committee and Board of Directors.

        We did not consult with Hein + Associates LLP with regard to any matter concerning the application of accounting principles to any specific transaction, either completed or proposed, or the type of audit opinion that might be rendered with respect to our financial statements prior to engaging the firm.

        Ernst & Young LLP’s reports on our financial statements for the fiscal years ended December 31, 2002 and 2001, did not contain an adverse opinion or disclaimer of opinion nor were they qualified or modified as to uncertainty, audit scope or accounting principles. During the fiscal years ended December 31, 2002 and 2001, and the subsequent interim period through September 23, 2003, (i) there were no disagreements with Ernst & Young LLP on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedures, which disagreements, if not resolved to the satisfaction of Ernst & Young LLP, would have caused them to make reference to the subject matter of the disagreements in connection with their report and (ii) there were no “reportable events” as defined in Item 304 (a)(1)(v) of Regulation S-K.

ITEM 9A.    CONTROLS AND PROCEDURES.

        The Company’s management, including the Company’s principal executive officer and principal financial officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this Annual Report on Form 10-K. Based upon that evaluation, the Company’s principal executive officer and principal financial officer have concluded that the disclosure controls and procedures were effective, in all material respects, as of the end of the period covered by this Annual Report on Form 10-K.

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        There were no changes in the Company’s internal control over financial reporting that occurred during the Company’s last fiscal quarter that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART III

ITEM 10.    DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.

        Information required by this item relating to our (i) directors, nominees for directors and executive officers, (ii) audit committee, (iii) Code of Ethical Conduct and Business Practices and (iv) compliance with Section 16(a) of the Securities Exchange Act will be set forth under the headings “Election of Directors,” “Executive Officers,” “Committees — Audit Committee,” “Code of Conduct” and “Section 16(a) Beneficial Ownership Reporting Compliance” in our Proxy Statement relating to the 2004 Annual Meeting of Stockholders, that will be filed with the Securities and Exchange Commission on or prior to April 29, 2004, and that is incorporated herein by reference.