Toreador Resources 10K 2004 Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON D.C. 20549

FORM 10-K

(Mark One)

x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the fiscal year ended: December 31, 2004

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

COMMISSION FILE NUMBER: 0-02517

Toreador Resources Corporation

(Exact name of registrant as specified in its charter)

DELAWARE

(State or other jurisdiction of

incorporation or organization)

75-0991164

(I.R.S. Employer

Identification No.)

4809 COLE AVENUE

SUITE 108

DALLAS, TEXAS

(Address of principal executive offices)

75205

(Zip Code)

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:

	Title of each Class:	Name of each exchange on which registered:
COMMON STOCK, PAR VALUE $.15625 PER SHARE			NASDAQ NATIONAL MARKET SYSTEM

_______________________________

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. o.

Indicate by check mark whether the registrant is an accelerated filer (as defined in Securities Exchange Act Rule 12b-2)

YES o

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, 2004 was $40,670,512. (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 March 30, 2005, was 14,050,197 shares.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s Proxy Statement for the 2005 Annual Meeting of Stockholders, expected to be filed on or prior to April 29, 2005, are incorporated by reference into Part III of this Form 10-K.

		Page
PART I		2

ITEM 1	BUSINESS	2

ITEM 2	PROPERTIES	19

ITEM 3	LEGAL PROCEEDINGS	29

ITEM 4	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	29

PART II		30

ITEM 5	MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	30

ITEM 6	SELECTED FINANCIAL DATA	32

ITEM 7	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	34

ITEM 7A	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	46

ITEM 8	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	46

ITEM 9	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	46

ITEM 9A	CONTROLS AND PROCEDURES	46

PART III		47

ITEM 10	DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT	47

ITEM 11	EXECUTIVE COMPENSATION	47

ITEM 12	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	47

ITEM 13	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS	47

ITEM 14	PRINCIPAL ACCOUNTANT FEES AND SERVICES	47

PART IV		47

ITEM 15	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	47

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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. Our strategy is to increase our oil and natural gas reserves through a balanced combination of exploratory drilling, development and exploitation projects and acquisitions. We primarily focus on international exploration activities in countries where we can establish large acreage positions. In addition, we target our operations in countries that we believe have stable governments, have attractive fiscal policies and are net-importers of oil and natural gas.

We currently hold interests in permits granting us the right to explore and develop oil and natural gas properties in the Paris Basin, France; onshore and offshore Turkey; onshore Romania; and offshore Trinidad, West Indies. On February 16, 2005, we sold 1,437,500 shares of our common stock pursuant to a public offering at a price to the public of $24.25 per share. The sale resulted in net proceeds of approximately $32.6 million. In January 2004, we sold our U.S. mineral and royalty assets to Black Stone Acquisition Partners I, L.P. (“Royalty Sale”), but retained our working interest properties. These properties primarily are located in Texas, Kansas, New Mexico, Louisiana and Oklahoma. At December 31, 2004, we held interests in approximately 4.4 million gross acres (approximately 3.3 million net acres). For a more detailed description of our properties please see “Item 2. Properties.” At December 31, 2004, our estimated net proved reserves were 13.8 million barrels of oil equivalent (MMBOE).

Incorporated in 1951, we were formerly known as Toreador Royalty Corporation.

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

BUSINESS STRATEGY

Our 2004 strategy continued to focus 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. We entered into two new facilities in late 2004 as discussed below.

During 2004, we also obtained interests in new strategic international exploration permits.

We will continue to seek opportunities to accelerate our worldwide acquisition and development program by:

•		Exploiting existing properties and developing existing reserves.
•		Implementing a balanced program of exploration, development and exploitation, thereby managing our risk exposure.
•		Pursuing new permits and selective property acquisitions under terms that include:

- High-impact exploration concessions in core geographic areas primarily located in the Euro-Eastern Mediterranean region; and

		- Established producing properties that offer potentially significant additions to our asset base.
•	Maintaining operational flexibility by adjusting our drilling program and capital expenditure budget during the year when necessary.

DEVELOPMENTS

PUBLIC OFFERING

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CONVERSIONS/EXCHANGES

On February 22, 2005, 82,000 shares of our Series A-1 Convertible Preferred Stock were exchanged for an aggregate of 512,500 shares of Toreador common stock pursuant to the terms thereof and an additional 20,164 shares of our common stock which were issued as an inducement to convert such shares of Series A-1 Convertible Preferred Stock.

On or prior to January 20, 2005, all of our outstanding 7.85% convertible subordinated notes due June 30, 2009 ($7.5 million aggregate principal amount) were exchanged for an aggregate of 914,634 shares of our common stock pursuant to the terms thereof and an aggregate cash payment (in lieu of interest) of approximately $85,000.

On or prior to December 31, 2004, all 160,000 shares of our Series A Convertible Preferred Stock were converted into an aggregate of 1,000,000 shares of Toreador common stock pursuant to the terms thereof, 6,000 shares of our Series A-1 Convertible Preferred Stock were converted into an aggregate of 37,500 shares of Toreador common stock pursuant to the terms thereof and $675,000 principal amount of the second amended and restated convertible debenture was converted into 100,000 shares of Toreador common stock pursuant to the terms thereof.

BORROWING FACILITIES

On December 23, 2004, we entered into a five-year $15.0 million reserve-based borrowing facility with a French lender. In February 2005, we received approval for the facility from the French government. This facility bears interest at a floating rate of 2.25-2.75% above LIBOR depending on the amount of outstanding principal and has a flexible amortization schedule linked to the borrowing base. This facility is secured by certain of our French assets, including contracts relating to our rights and interests in our French fields, our direct and indirect equity interests in certain of our subsidiaries and payments received from the sale of our French production. The borrower under this facility is a French subsidiary and Toreador has guaranteed the obligations (along with certain other of our U.S. and French subsidiaries). At March 30, 2005, there were no amounts outstanding under this facility, and we had approximately $8.0 million available for borrowings.

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 2004, we sold several underperforming oil and natural gas assets for approximately $274,000. All sales were made in private negotiated transactions.

NEW PERMITS

TURKEY

In 2004, we acquired a 100% working interest in six exploration permits covering approximately 844,000 acres in the Thrace

region between Bulgaria and the Bosporus Straits. The majority of the acreage covered by these permits is in shallow water depths of

300 feet or less. In addition, in January 2005 we acquired a 100% working interest in two exploration permits totaling 233,000 acres

offshore central Turkey.

FRANCE

In 2004, we acquired the 33,100-acre Aufferville exploration permit. We are the operator and have a 100% working interest in this permit, which offers leads in the deeper Jurassic Dogger formation and is prospective in the Triassic formation. We also were

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granted a non-operating 33.33% interest in the 37,300-acre Nemours exploration permit. This permit offers leads in the deeper Jurassic Dogger formation and is prospective in the Triassic formation.

EXPLORATION ACTIVITIES

TURKEY

We hold interests in 24 exploration permits totaling 2.88 million gross acres (2.15 million net acres).

• Calgan Permit. We are the operator and hold a 75% working interest in the Calgan exploration permit. In 2004, we drilled the Calgan-2 exploratory well in south central Turkey. The well encountered oil shows. Additional work on the well has been suspended while we reprocess seismic data. Based on the information processed from the seismic data, we expect to sidetrack the well by mid-2005. We have not determined the direction and length of the lateral extension.

• Western Black Sea Permits. We are operator and hold a 36.75% working interest in eight exploration permits encompassing more than 962,000 gross acres (353,500 net acres). We drilled the Ayazli-1 exploratory well and discovered natural gas in mid-2004. The well was our first exploratory well in the area and is one of six natural gas prospects we have identified to date. We plan a consecutive three-well appraisal program. If this program is successful, the wells will be completed and suspended as future producers. We will have the option of drilling up to five additional wells during 2005.

• Thrace Black Sea Permits. In 2004, we acquired a 100% working interest in six exploration permits covering approximately 844,000 acres in the Thrace region between Bulgaria and the Bosporus Straits. The majority of the acreage covered by these permits is in shallow water depths of 300 feet or less.

• Central Black Sea Permits. In addition, in January 2005, we acquired a 100% working interest in two exploration permits totaling 233,000 acres offshore central Turkey.

• Sinop Permits. We hold a 100% working interest in six exploration permits covering 718,500 acres in north central Turkey. Three wells were drilled in the 1980's that were subsequently abandoned due to the lack of a natural gas market in the area at the time. We anticipate restoring one of the wells in 2005. If suspended, we plan to drill an offset well in late 2005.

FRANCE

We own working interests in four exploration permits:

• Courtenay Permit. We are operator and own a 100% working interest in the Courtenay exploration permit, which surrounds the Neocomian Fields. During the second half of 2005, we expect to drill up to six exploratory wells on the 183,000-acre Courtenay permit. A geochemical study that will supplement existing geophysical and subsurface data is nearing completion. Our geological and geophysical analysis indicates the Neocomian producing trend continues onto this permit.

• Aufferville Permit. In 2004, we acquired the 33,100-acre Aufferville exploration permit. We are the operator and have a 100% working interest in this permit, which offers leads in the deeper Jurassic Dogger formation and is prospective in the Triassic formation.

• Nemours Permit. In 2004, we were granted a non-operating 33.33% interest in the 37,300-acre Nemours exploration permit. This permit offers leads in the deeper Jurassic Dogger formation and is prospective in the Triassic formation.

• Nangis Permit. We own a 100% working interest in the 50,000-acre Nangis permit in the northern Paris Basin.

We also have applied for new exploration permits on two blocks adjoining the Courtenay permit and one block adjoining the Aufferville permit.

ROMANIA

• Viperesti Permit. We are the 100% owner and operator of this exploration permit that lies in east-central Romania in the southeastern foothills of the Carpathian Mountains. This permit comprises 324,000 acres. We believe this permit is prospective in the Tertiary formations at depths ranging from 4,500-16,000 feet. We anticipate re-entering a well on this permit and will continue to gather geological and geophysical information, as well as reprocess seismic data.

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• Moinesti Permit. We are the 100% owner and operator of the Moinesti exploration permit. This permit covers approximately 300,000 acres. It is situated about 60 kilometers north of the Viperesti permit in the foothills of the Carpathian Mountains and is contiguous with eight producing oil fields. We believe the permit is prospective in various producing formations from 3,000-16,000 feet. We will continue to gather geological and geophysical information and reprocess seismic data on this permit.

UNITED STATES

During the second half of 2004, the first exploratory well on the Hosston sands prospect in southern Mississippi, the Hickman 4-7, was drilled to a total depth of 14,775 feet and exhibited no gas shows. Consequently, the well was plugged and abandoned. We held a 10% working interest in the well.

MARKETS AND COMPETITION

In France, we currently sell 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 areas where the oil or natural gas is produced. Revenues from the sale of oil and natural gas production accounted for 106%, 109% and 116% of our consolidated revenues for the three years ended December 31, 2004, 2003 and 2002, 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 in the spot market or under short-term contracts or contracts providing for periodic adjustments; therefore, our revenue streams are highly sensitive to changes in 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. The oil and natural gas industry is currently experiencing shortages of drilling rigs and equipment, pipe and personnel due to the high commodity prices which may have an adverse effect on our drilling program. 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 business. 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 on 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. 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.

Our oil sales 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 that includes an indexing system to establish ceilings on interstate oil pipeline rates.

With respect to transportation of natural gas on or across the Outer Continental Shelf (“OCS”), the Outer Continental Shelf Lands Act (“OSCLA”) that all pipelines provide open and nondiscriminatory access to both owner and nonowner shippers. On October 10, 2003, the U.S. Court of Appeals for the District of Columbia Circuit issued an opinion that severely circumscribes the FERC’s authority under the OCSLA. The court found that OCSLA confers upon the Secretary of the Interior, not the FERC, general authority to enforce open access conditions as to natural gas and oil pipelines and gathering systems.

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According to the court’s ruling, the FERC retains authority under the NGA to enforce open access transportation conditions over natural gas pipeline facilities on the OCS, and under limited conditions over natural gas gathering facilities owned directly or indirectly by natural gas pipeline companies. However, the FERC has no authority under the NGA to enforce open access conditions on gathering facilities owned by companies that are not affiliated with natural gas pipeline companies, and no authority under the Interstate Commerce Act (“ICA”) to regulate oil pipelines that lie wholly on the OCS. In response to the court’s opinion, on April 12, 2004 the Minerals Management Service (“MMS”) of the Department of Interior (“DOI”) issued an Advanced Notice of Proposed Rulemaking (“ANOPR”) requesting comments to assist it in potentially amending its regulations regarding how the DOI should ensure that pipelines and gathering systems transporting oil and natural gas under permits, licenses, easements or rights-of-way across the OCS provide open and non-discriminatory access to both owner and non-owner shippers under OCSLA. Various parties filed comments in response to the ANOPR. The MMS has not yet issued a follow-up Notice of Proposed Rulemaking. It is not clear what regulatory regime the MMS will impose to enforce open access transportation on the OCS under OCSLA, nor what impact any particular regulatory regime may have upon our ability to obtain transportation of our natural gas and condensate products to markets.

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:

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

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, clean-up 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.

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.

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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 March 30, 2005, we employed 45 full-time employees. In February 2004, as a result of the Royalty Sale, 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

The volatility of the oil and natural gas industry may have an adverse impact on our operations

Our revenues, cash flows and profitability are substantially dependent upon prevailing prices for oil and natural gas. In recent years, oil and natural gas prices and, therefore, the level of drilling, exploration, development and production, have been extremely volatile. Any significant or extended decline in oil or natural gas prices will have a material adverse effect on our business, financial condition and results of operations and could impair access to future sources of capital. Volatility in the oil and natural gas industry results from numerous factors over which we have no control, including:

• the level of oil and natural gas prices, expectations about future oil and natural gas prices and the ability of international cartels to set and maintain production levels and prices;

• the cost of exploring for, producing and transporting oil and natural gas;

• the domestic and foreign supply of oil and natural gas;

• domestic and foreign governmental regulation;

• the level and price of foreign oil and natural gas transportation;

• available pipeline and other oil and natural gas transportation capacity;

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• weather conditions;

• international political, military, regulatory and economic conditions;

• the level of consumer demand;

• the price and the availability of alternative fuels;

• the effect of worldwide energy conservation measures; and

• the ability of oil and natural gas companies to raise capital.

Significant declines in oil and natural gas prices for an extended period may:

• impair our financial condition, liquidity, ability to finance planned capital expenditures and results of operations;

• reduce the amount of oil and natural gas that we can produce economically;

• cause us to delay or postpone some of our capital projects;

• reduce our revenues, operating income and cash flow; and

• reduce the carrying value of our oil and natural gas properties.

No assurance can be given that current levels of oil and natural gas prices will continue. We expect oil and natural gas prices, as well as the oil and natural gas industry generally, to continue to be volatile.

Continued financial success depends on our ability to replace our 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. Oil and natural gas are depleting assets, and production from oil and natural gas or properties declines as reserves are depleted with the rate of decline depending on reservoir characteristics. If we are unable to conduct successful exploration or development activities or acquire properties containing proved reserves, our proved reserves generally will decline as reserves are produced, and our level of production and cash flows will be adversely affected.

We face numerous 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.

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:

• fire, explosions and blowouts;

• pipe failure;

• abnormally pressured formations; and

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• environmental accidents such as oil spills, natural gas leaks, ruptures or discharges of toxic gases, brine or well fluids into the environment (including groundwater contamination).

These events may result in substantial losses to us from:

• injury or loss of life;

• severe damage to or destruction of property, natural resources and equipment;

• pollution or other environmental damage;

• clean-up responsibilities;

• regulatory investigation;

• penalties and suspension of operations; or

• attorneys’ fees and other expenses incurred in the prosecution or defense of litigation.

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.

Reserve estimates depend on many assumptions that may prove to be inaccurate

Any material inaccuracies in these reserve estimates or underlying assumptions could materially affect the quantities and present values of our reserves. The process of estimating natural gas and oil reserves is complex. It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves shown in this annual report. In order to prepare these estimates we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. The process also requires economic assumptions relating to matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Therefore, estimates of oil and natural gas reserves are inherently imprecise.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and pre-tax net present value of reserves shown in this annual report. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

You should not assume that the pre-tax net present value of our proved reserves referred to in this report is the current market value of our estimated oil and natural gas reserves. We base the pre-tax net present value of future net cash flows from our proved reserves on prices and costs on the date of the estimate. Actual future prices, costs, and the volume of produced reserves may differ materially from those used in the pre-tax net present value estimate.

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COMPANY RISKS

Our growth depends on our ability to obtain additional capital

Effectuation of our business strategy will require substantial capital expenditures. In order to fund our growth, we will need to obtain additional capital. The amount and timing of our future capital requirements will depend upon a number of factors, including:

• drilling results and costs;

• transportation costs;

• equipment costs and availability;

• marketing expenses;

• oil and natural gas prices;

• requirements and commitments under existing permits;

• staffing levels and competitive conditions; and

• any purchases or dispositions of assets.

Our ability to raise additional capital will depend on the results of our operations and the status of various capital and industry markets at the time we seek such capital. Our failure or inability to obtain any required additional financing on favorable terms could materially and adversely affect our growth, cash flow and earnings, including our ability to meet our 2005 capital expenditures budget.

We discharged our senior secured credit facilities in January 2004. Although we have entered into a $25.0 million reserve-based borrowing facility secured by our U.S. assets and a $15.0 million reserve-based borrowing facility secured by our French assets, our ability to borrow under these facilities is limited because of borrowing base restrictions. At March 30, 2005 there were no outstanding amounts under the $25.0 million facility, and we had approximately $3.3 million available for borrowings. At March 30, 2005 there were no outstanding amounts under the $15.0 million facility, and we had approximately $8.0 million available for borrowings.

No assurance can be given that we will have the needed additional capital to fund our growth under these facilities, from the net proceeds of any public or private debt or equity offering or otherwise.

The terms of our indebtedness may restrict our ability to grow

Our $15.0 million facility restricts our ability to incur additional indebtedness. In addition, our $25.0 million facility restricts the ability of the borrowers, two of our domestic subsidiaries, to incur additional indebtedness. Thus, we may not be able to obtain sufficient capital to grow our business and we may lose opportunities to acquire interests in oil and natural gas properties or related businesses because of our inability to fund such growth.

Our ability to comply with the restrictions and covenants of our indebtedness in the future is uncertain and would be affected by the levels of cash flow from our operations and events or circumstances beyond our control. Our failure to comply with any of the restrictions and covenants could result in a default, which could permit the lender to accelerate repayments and foreclose on the collateral securing the indebtedness.

In addition, our pursuit of capital could result in the issuance of potentially dilutive equity securities. Any additional future indebtedness may limit our financial and operating flexibility in a manner similar to and potentially more restrictive than the facilities discussed above. We also may utilize the capital currently expected to be available from our present operations to fund other opportunities.

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Acquisition prospects may be difficult to assess and may pose additional risks to our operations

We evaluate and, where appropriate, pursue acquisition opportunities on terms we consider favorable. In particular, we expect to pursue acquisitions of businesses or interests that will complement and allow us to expand our exploration activities; however, currently, we have no binding commitments related to any acquisitions. The successful acquisition of interests in oil and natural gas properties requires an assessment of:

• recoverable reserves;

• exploration potential;

• future oil and natural gas prices;

• operating costs;

• potential environmental and other liabilities and other factors; and

• permitting and other environmental authorizations required for our operations.

In connection with such an assessment, we would expect to perform a review of the subject properties that we believe to be generally consistent with industry practices. Nonetheless, the resulting conclusions are necessarily inexact and their accuracy inherently uncertain, and such an assessment may not reveal all existing or potential problems, nor will it necessarily permit a buyer to become sufficiently familiar with the properties to fully assess their merits and deficiencies. Inspections may not always be performed on every platform or well, and structural and environmental problems are not necessarily observable even when an inspection is undertaken.

Future acquisitions could pose numerous additional risks to our operations and financial results, including:

• problems integrating the purchased operations, personnel or technologies;

• unanticipated costs;

• diversion of resources and management attention from our core business;

• entry into regions or markets in which we have limited or no prior experience; and

• potential loss of key employees, particularly those of any acquired organization.

Competition in the oil and natural gas industry is intense, and many of our competitors have greater financial, technological and other resources than we do

We operate in the highly competitive areas of oil and natural gas exploration, development, production, leasing, and acquisition activities. The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. We face intense competition from independent, technology-driven companies as well as from both major and other independent oil and natural gas companies in each of the following areas:

• seeking to acquire desirable producing properties or new leases for future exploration;

• marketing our oil and natural gas production;

• integrating new technologies; and

• seeking to acquire the equipment and expertise necessary to develop and operate our properties.

Many of our competitors have financial, technological and other resources substantially greater than ours, and some of them are fully integrated oil and natural gas companies. These companies may be able to pay more for development prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Further, these companies may enjoy technological advantages and may be able to implement new technologies more rapidly than we can. Our ability to develop and exploit our oil and natural gas properties and to acquire additional properties in the future will depend upon our ability to successfully conduct operations, implement advanced technologies, evaluate and select suitable properties and consummate transactions in this highly competitive environment.

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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, Turkey and Romania. Therefore, we are subject to political and economic risks and other uncertainties

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

• the risk of expropriation, nationalization, war, revolution, border disputes, renegotiation or modification of existing contracts, and import, export and transportation regulations and tariffs;

• taxation policies, including royalty and tax increases and retroactive tax claims;

• exchange controls, currency fluctuations and other uncertainties arising out of foreign government sovereignty over international operations;

• laws and policies of the United States affecting foreign trade, taxation and investment;

• the possibility of being subjected to the exclusive jurisdiction of foreign courts in connection with legal disputes and the possible inability to subject foreign persons to the jurisdiction of courts in the United States; and

• the possibility of restrictions on repatriation of earnings or capital from foreign countries.

Terrorist activities may adversely affect our business

Terrorist activities, including events similar to those of September 11, 2001, or armed conflict involving the United States or any other country in which we hold interests, may adversely affect our business activities and financial condition. If events of this nature occur and persist, the resulting political and social instability could adversely affect prevailing oil and natural gas prices and cause a reduction in our revenues. In addition, oil and natural gas production facilities, transportation systems and storage facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our operations is destroyed or damaged. Costs associated with insurance and other security measures may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

We are highly dependent upon key personnel

Our continued success is dependent to a significant degree upon the services of our executive officers and upon our ability to attract and retain qualified personnel who are experienced in the various phases of our business. If we lose the services of one or more of our executive officers, our business, financial condition, results of operations or the market value of our common stock could be materially adversely affected. We do not maintain key man life insurance for any of our executive officers.

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.

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We may not be able to renew our permits or obtain new ones

We do not hold title to properties in France, Turkey or Romania, but have exploration and exploitation permits granted by these countries' respective governments. There can be no assurance that we will be able to renew any of these permits when they expire, convert exploration permits into exploitation permits or obtain additional permits in the future.

Our production may not offset hedges, and we may not benefit from price increases by hedging

Although we currently are not a party to a hedging transaction, 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.

Our operations are subject to currency fluctuation risks

We currently have operations involving the U.S. dollar, the Euro and the Turkish Lira. We are subject to fluctuations in the value of the U.S. dollar as compared to the Euro and the Turkish Lira, respectively. These fluctuations may adversely affect our results of operations.

We cannot rely on the results of our noncore assets in the future

We have made equity investments in technology-related businesses that, although related to the energy industry, are not part of our core strategy. Although we have obtained a return of some of our initial investments and have received earnings from these investments during various periods, there can be no assurance that we will be able to obtain any future returns from these investments. Additionally, these investments are subject to the risks associated generally with technology-related industries, including obsolescence, competition, concentration and the inability to obtain the necessary capital for future growth.

If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results. As a result, current and potential stockholders could lose confidence in our financial reporting, which would harm our business and the trading price of our stock.

In the audit of our financial statements for the year ended December 31, 2004, our auditors, Hein & Associates LLP, discovered certain internal control deficiencies that constituted material weaknesses as defined in Statement of Auditing Standards No. 60 and may also constitute material weaknesses in our disclosure controls. As a result of the findings, we have implemented a course of action reasonably assured to remediate these material weaknesses. However, we cannot be certain that our course of action will ensure that we will not have any future material weaknesses. Any future material weaknesses could harm our operating results or cause us to fail to meet our reporting obligations and could cause investors to lose confidence in our reported financial information, thereby having a negative effect on the trading price of our stock.

INVESTMENT RISKS

Our common stock has experienced, and may continue to experience, price volatility and low trading volume

Our stock price is subject to significant volatility. Overall market conditions, in addition to other risks and uncertainties described in this "Risk Factors" section and elsewhere in this annual report, may cause the market price of our common stock to fall. We participate in a price sensitive industry, which often results in significant volatility in the market price of common stock irrespective of company performance. As a result, our high and low closing stock prices for the twelve months ended March 30, 2005 were $26.96 and $4.74 respectively. Fluctuations in the price of our common stock may be exacerbated by conditions in the energy and oil and natural gas industries or conditions in the financial markets generally.

Our common stock is quoted on the Nasdaq National Market under the symbol "TRGL." However, daily trading volumes for our common stock are, and may continue to be, relatively small compared to many other publicly traded securities. It may be difficult for you to sell your shares in the public market at any given time at prevailing prices, and the price of our common stock may, therefore, be volatile.

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A large percentage of our common stock is owned by our officers and directors, and such stockholders may control our business and affairs

At March 30, 2005, our officers and directors as a group held a beneficial interest in approximately 33.4% of our common stock (including shares issuable upon exercise of stock options for common stock held by officers and directors, upon conversion of our Series A-1 Convertible Preferred Stock held by directors and affiliates of certain directors and upon conversion of the second amended and restated convertible debenture held by an affiliate of a director). The officers and directors control our business and affairs. Due to their large ownership percentage interest, they may be able to remain entrenched in their positions.

Due to the restrictions placed on us by our outstanding shares of preferred stock and the $15.0 million facility, we do not expect to pay cash dividends in the near future

We do not anticipate paying cash dividends on our common stock in the foreseeable future. In addition, the terms of our outstanding shares of preferred stock and our $15.0 million facility 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

“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 the specified date, 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 the specified date, 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.

“MBbl.” One thousand Bbls.

“MBOE.” One thousand BOE.

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

“MMBOE.” One million BOE.

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

“PERMIT.” An area onshore or offshore that comprises a contiguous acreage, or leasehold, position on which an operator drills exploratory and/or development wells. Sometimes designated as a “lease” or “block.”

“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.

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

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

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

“SPUD.” To begin to drill a well.

“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 (not necessarily as operator) 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 or furnished 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 15 in the Notes to Consolidated Financial Statements for financial information by segment.

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ITEM 2.

PROPERTIES.

INTERNATIONAL

France

We own permits covering and operate five producing oil fields in the Paris Basin.

• Charmottes Field. We own a 100% working interest in the permit covering the Charmottes Field located 60 kilometers southeast of Paris. The property currently has ten producing oil wells. The Charmottes Field initially was developed following the discovery well drilled in 1984. In the second quarter of 2004, we successfully drilled the Charmottes-109 horizontal development well. The Charmottes-108 was drilled in January 2005 and tubing was set on March 8, 2005. The well will be tested and completed after the Charmottes-110 has been drilled. The Charmottes-110 well was started on March 15, 2005. The completion of the construction of expanded production facilities in the field will accommodate these two wells and the Charmottes-109 well. If the horizontal wells are successful, we anticipate drilling up to four more in late 2005 and 2006. During 2005 we expect to drill a well in the Donnmarie formation.

• Neocomian Complex. Pursuant to two exploitation permits, we are operator and own a 100% working interest in the permits covering the Neocomian Fields, a group of four oil reservoirs 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. During 2004, three development wells and three sidetrack wells were drilled and completed; an extensive workover program was also completed. In 2005, we have scheduled a multi-well development program in the fields.

We also own working interests in four exploration permits.

• Nangis Permit. We are the operator and own a 100% working interest in the 50,000-acre Nangis permit in the northern Paris Basin.

We also have applied for new exploration permits on two blocks adjoining the Courtenay permit and one block adjoining the Aufferville permit.

Turkey

We hold interests in 24 exploration permits and three exploitation permits in five geographic regions of Turkey totaling 2.91 million gross acres (2.27 million net acres).

• Zeynel Field. Through an exploitation permit, we have an 8.5% royalty interest in the Zeynel Field located in south central Turkey.

• Cendere Field. Through two exploitation permits, we have a 19.6% non-operating working interest in most of the wells located in the Cendere Field in central Turkey. This acreage has 16 oil wells currently producing. A 3D seismic survey to identify new drilling prospects is currently being conducted.

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• Central Black Sea Permits. In addition, in January 2005, we acquired a 100% working interest in two exploration permits totaling 233,000 acres offshore central Turkey.

• Sinop Permits. We hold a 100% working interest in six exploration permits covering 718,500 acres in north central Turkey. Three wells were drilled in the 1980's that were subsequently abandoned due to the lack of a natural gas market in the area at the time. We anticipate reentering one of the wells in 2005. If successful, we plan to drill an offset well later in 2005.

Romania

• Fauresti Rehabilitation Permit. We are the 100% owner and operator of the Fauresti rehabilitation permit. This permit covers approximately 1,325 acres. It is located in southwestern Romania about 140 kilometers west of the Viperesti permit. We believe it offers development opportunities in the Jurassic Dogger formation at depths of approximately 8,000 feet. In early 2005, we re-entered one well on this permit. We anticipate re-entering several additional wells and drilling up to two new development wells on this permit in 2005.

Trinidad, West Indies

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

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.

Currently, we hold working interests in 913 gross wells (51 net wells) primarily in Texas, Oklahoma, New Mexico, Kansas and Louisiana. During the second half of 2004, the first exploratory well on the Hosston sands prospect in southern Mississippi, the Hickman 4-7, was drilled to a total depth of 14,775 feet and exhibited no gas shows. Consequently, the well was plugged and abandoned. We held a 10% working interest in the well.

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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 exploitation permits by the French government. We hold four French exploration permits: Aufferville, Nemours, Nangis and Courtenay. No proved reserves have been established in these permits. The Nangis permit expires in 2005, the Courtenay permit expires in 2006, and the Aufferville and Nemours permits expire in 2007. 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 exploitation permits that cover five producing oil fields in the Paris Basin are:

		At December 31, 2004
Property	Permit Expiration Year	Total Proved Reserves (MBbl)	Post-Expiration Proved Reserves (MBbl)	Percent of Proved Reserves Post-Expiration
Neocomian Fields	2011	9,731	7,239	74.39%
Charmottes Field	2013	1,805	755	41.83%

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

TURKEY

We do not hold title to properties in Turkey but have been granted exploitation and exploration permits by the Turkish government. We have 24 exploration permits covering five geographic regions. There are no proved reserves associated with these permits. The Western Black Sea permits and the Sinop permits expire in 2005; however, we anticipate undertaking drilling operations on these permits which will entitle us to extend them with governmental approval for at least three years. The Calgan permit expires in 2007 and the Thrace Black Sea permits and the Central Black Sea permits expire in 2009. Onshore exploration permits are granted for four-year terms and may be extended for two additional two-year terms, and offshore exploration permits are granted for six-year terms and may be extended for two additional three-year terms, provided that drilling obligations stipulated under Turkish law are satisfied. Under Turkish law, exploitation permits are generally granted for a period of 20 years and may be renewed upon application for two additional 10-year periods. If an exploration permit is extended for development as an exploitation permit, the period of the exploration permit is counted toward the 20-year exploitation permit.

The following is certain information relating to our three Turkish exploitation permits:

		At December 31, 2004
Property	Permit Expiration Year	Total Proved Reserves (MBbl)	Post-Expiration Proved Reserves (MBbl)	Percent of Proved Reserves Post-Expiration
Zeynel	2010	48	6	12.5%
Cendere (2 permits)	2011	579	186	32.12%

ROMANIA

We do not hold title to property in Romania, but have permits that entitle us to explore and produce hydrocarbons. We have not yet established proved reserves on any of these properties. We have two exploration permits and one rehabilitation permit. The Moinesti and Viperesti permits will expire in 2009. The Fauresti permit will expire in 2015. If, prior to the expiration of our Romanian permits, we have not completed the minimum exploration program required by the permits, we must pay the estimated costs of such exploration program to the Romanian government. If we were required to make such payments to the Romanian government, we estimate that the aggregate amount would be approximately $8.0 million.

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DOMESTIC

We currently own interests in producing acreage only in the form of working interests.

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:

• Customary royalty and overriding royalty interests;

• Liens incident to operating agreements; and

• Liens for current taxes and other burdens and minor encumbrances, easements and restrictions.

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

OIL AND NATURAL GAS RESERVES

The following table sets forth information about our estimated net proved reserves (i) at December 31, 2003, (ii) as adjusted at December 31, 2003 to reflect the sale of U.S. mineral and royalty interests in January 2004 and (iii) at December 31, 2004. 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). No reserve reports have been provided to any governmental agencies.

	December 31,
		2004	2003 ⁽¹⁾	2003
U.S.
Proved developed:
Oil (MBbl)		775	724	1,709
Gas (MMcf)		4,875	5,803	11,158
Total (MBOE)		1,587	1,691	3,568
Proved undeveloped:
Oil (MBbl)		5	33	129
Gas (MMcf)		58	124	124
Total (MBOE)		15	54	149
Discounted present value at 10% (pretax) (in thousands)		$ 19,921	$ 19,808	$ 50,283
Standardized measure of proved reserves (in thousands)		$ 14,141	$ 15,179	$ 36,580

FRANCE
Proved developed:
Oil (MBbl)		7,309	6,571	6,571
Proved undeveloped:
Oil (MBbl)		4,227	4,404	4,404
Discounted present value at 10% (pretax) (in thousands)		$ 87,276	$ 57,654	$ 57,654

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Standardized measure of proved reserves (in thousands)	$ 54,331	$ 42,631	$ 42,631

TURKEY
Proved developed:
Oil (MBbl)	360	583	583
Proved undeveloped:
Oil (MBbl)	267	309	309
Discounted present value at 10% (pretax) (in thousands)	$ 7,945	$ 8,134	$ 8,134
Standardized measure of proved reserves (in thousands)	$ 6,640	$ 5,518	$ 5,518

COMBINED
Proved developed:
Oil (MBbl)	8,444	7,878	8,863
Gas (MMcf)	4,875	5,803	11,158
Total (MBOE)	9,256	8,845	10,723
Proved undeveloped:
Oil (MBbl)	4,499	4,746	4,842
Gas (MMcf)	58	124	124
Total (MBOE)	4,509	4,767	4,863
Discounted present value at 10% (pretax) (in thousands)	$ 115,142	$ 85,596	$ 116,071
Standardized measure of proved reserves (in thousands)	$ 75,112	$ 63,328	$ 84,729

__________

(1) Proved reserves calculated as if the Royalty Sale had been effective on December 31, 2003.

Reserves were estimated using oil and natural gas prices and production and development costs in effect on December 31, 2003 and 2004, 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 16 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, 2004. Productive wells include wells currently producing or capable of production.

	Gross (1)			Net (2)
	OIL	GAS	TOTAL	OIL	GAS	TOTAL
United States	641	272	913	21.40	29.50	50.90
France	98	–	98	98.00	–	98.00
Turkey	17	–	17	2.92	–	2.92

__________

(1)	“Gross” refers to wells in which we have a working-interest.
(2)	“Net” refers to the aggregate of our percentage working interest in gross wells before royalties, before or after payout, as appropriate.

ACREAGE

The following table shows the developed and undeveloped acreage attributable to our ownership as of December 31, 2004.

	Developed Acreage		Undeveloped Acreage		Total Acreage
	Gross	Net	Gross	Net	Gross	Net
United States	253,420	37,325	83,703	39,028	337,123	76,353
France	24,261	24,261	303,948	278,946	328,209	303,207
Turkey	31,730	3,045	2,879,874	2,271,705	2,911,604	2,274,750
Romania	–	–	775,325	625,325	775,325	625,325
Total	309,411	64,631	4,042,850	3,215,004	4,352,261	3,279,635

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

The following table shows our drilling activities on a gross and net basis for the years ended 2004, 2003 and 2002.

	Year ended December 31,
	2004		2003		2002
	Gross (1)	Net (2)	Gross (1)	Net (2)	Gross (1)	Net (2)
UNITED STATES
Development:
Gas (3)	3	0.75	1	0.03	–	–
Oil (4)	4	0.20	2	0.19	1	0.09
Abandoned (5)	–	–	–		1	0.20
Total	7	0.95	3	0.22	2	0.29
Exploratory
Gas (3)	–	–	–	–	1	0.11
Oil (4)	–	–	–	–	1	0.25
Abandoned (5)	3	0.5	–	–	2	0.33
Total	3	0.5	–	–	4	0.69

FRANCE
Development:
Oil (4)	7	7	–	–	–	–
Abandoned (5)	–	–	–	–	–	–
Total	7	7	–	–	–	–

TURKEY
Development:
Oil (4)	–	–	–	–	1	0.20
Abandoned (5)	–	–	–	–	–	–
Total	–	–	–	–	1	0.20
Exploratory
Oil (6)	1	0.75	–	–	–	–
Gas (7)	1	0.40	–	–	–	–
Abandoned (5)	–	–	2	1.30	1	0.50
Total	2	1.15	2	1.30	1	0.50

________

(1)	"Gross" is the number of wells in which we have a working interest.
(2)	"Net" is the aggregate obtained by multiplying each gross well by our after payout percentage working interest.
(3)	"Gas" means natural gas wells that are either currently producing or are capable of production.
(4)	"Oil" means producing oil wells.
(5)	"Abandoned" means wells that were dry when drilled and were abandoned without production casing being run.
(6)	"Oil" means oil shows were found and temporarily suspended awaiting further work.
(7)	"Gas" means gas flow was tested and temporarily suspended awaiting further work.

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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.

	Year Ended December 31, 2004
	United States	France	Turkey	Total
Production:
Oil (Bbls)	69,649	396,806	73,118	539,573
Daily average (Bbls/Day)	191	1,087	200	1,478
Gas (Mcf)	567,639	–	–	567,639
Daily average (Mcf/Day)	1,555	–	–	1,555
Daily average (BOE/Day)	450	1,087	200	1,737

Unit prices:
Average oil price ($/Bbl)	$ 38.45	$ 35.39	$ 31.05	$ 35.24
Average gas price ($/Mcf)	5.65	–	–	5.65
Average equivalent price ($/BOE)	$ 35.83	$ 35.39	$ 31.05	$ 35.00

Unit costs ($/BOE):
Lease operating	$ 10.66	$ 10.98	$ 10.44	$ 10.84
Exploration and acquisition	8.29	0.36	25.90	5.35
Depreciation, depletion and amortization	7.88	3.97	9.11	5.58
Impairment of oil and natural gas properties	0.04	–	–	0.01
General and administrative	22.01	2.97	11.76	8.91
Interest and other	0.32	0.86	(15.58)	(1.17)
Total	$ 49.19	$ 19.14	$ 41.63	$ 29.52

	Year Ended December 31, 2003
	United States	France	Turkey	Total	Total⁽¹⁾
Production:
Oil (Bbls)	190,118	373,999	91,680	655,797	541,467
Daily average (Bbls/Day)	521	1,025	251	1,797	1,483
Gas (Mcf)	1,561,380	–	–	1,561,380	739,941
Daily average (Mcf/Day)	4,278	–	–	4,278	2,027
Daily average (BOE/Day)	1,234	1,025	251	2,510	1,821

Unit prices:
Average oil price ($/Bbl)	$ 28.17	$ 25.76	$ 24.65	$ 26.30	$ 26.02
Average gas price ($/Mcf)	4.83	–	–	4.83	4.74
Average equivalent price ($/BOE)	$ 28.65	$ 25.76	$ 24.65	$ 27.07	$ 26.47

Unit costs ($/BOE):

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Lease operating	$ 5.72	$ 11.47	$ 9.04	$ 8.40	$ 10.01
Exploration and acquisition	2.53	—	13.86	2.63	3.63
Depreciation, depletion and amortization	4.49	3.63	5.97	4.28	4.88
Impairment of oil and natural gas properties	0.38	—	—	0.19	0.26
General and administrative	7.90	2.17	9.15	5.68	4.49
Interest and other	2.50	(1.60)	1.33	0.71	(0.26)
Total	$ 23.52	$ 15.67	$ 39.35	$ 21.89	$ 23.01

________

(1)	This column sets forth production and other information for the year ended December 31, 2003, as if the Royalty Sale had taken place on January 1, 2003.

	Year Ended December 31, 2002
		United States	France	Turkey	Total
Production:
Oil (Bbls)		238,210	415,165	113,799	767,174
Daily average (Bbls/Day)		653	1,137	312	2,102
Gas (Mcf)		1,812,203	—	—	1,812,203
Daily average (Mcf/Day)		4,965	—	—	4,965
Daily average (BOE/Day)		1,480	1,137	312	2,929

Unit prices:
Average oil price ($/Bbl)		$ 22.59	$ 22.14	$ 20.85	$ 22.08
Average gas price ($/Mcf)		3.10	—	—	3.10
Average equivalent price ($/BOE)		$ 20.34	$ 22.14	$ 20.85	21.09

Unit costs ($/BOE):
Lease operating		$ 4.79	$ 7.80	$ 7.52	$ 6.25
Exploration and acquisition		4.14	—	—	2.09
Depreciation, depletion and amortization		5.88	3.14	4.86	4.70
Impairment of oil and natural gas properties		0.98	—	—	0.49
General and administrative		10.00	2.76	10.28	7.22
Interest and other		8.62	3.02	0.66	5.59
Total		$ 34.41	$ 16.72	$ 23.32	$ 26.34

PRESENT ACTIVITIES

For the period January 1, 2005 through March 30, 2005, we participated in the drilling of three exploratory wells. The Charmottes 108 well in France was drilled and will be tested after drilling is completed on the Charmottes 110. The drilling of the Charmottes 110 began on March 18, 2005. The Cowherd #1 in Texas, of which we hold a 17% nonoperated working interest, was drilled and will be tested in April 2005. The Fauresti #179 well in Romania was reentered and is currently suspended until further testing is done. There were a total of 4 gross wells and 3.17 net wells drilled during this period.

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 2004 was approximately $324,000.

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ITEM 3.

LEGAL PROCEEDINGS.

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 Toreador. The ruling was subject to automatic appeal that was heard in December 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 final determination. We have also appealed the case to the European Court. We cannot predict the outcome of this matter.

Other. 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, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

Our shares of common stock, par value $.15625 per share, are traded on the Nasdaq National Market System under the trading symbol “TRGL.” 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 National Market based upon quotations that reflect inter-dealer prices, without retail mark-up, mark-down or commission and may not necessarily represent actual transactions.

2004	High	Low
First Quarter	$ 6.49	$ 4.06
Second Quarter	7.73	4.67
Third Quarter	10.15	6.02
Fourth Quarter	24.37	8.78

2003	High	Low
First Quarter	$ 2.80	$ 1.91
Second Quarter	3.49	2.21
Third Quarter	3.05	2.33
Fourth Quarter	4.65	2.25

As of March 30, 2005, there were 14,050,197 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 March 30, 2005 was $18.13.

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, retaining earnings to finance the growth of our business. Therefore, we do not anticipate paying cash dividends on our common stock in the foreseeable future. The terms of 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-1 Convertible Preferred Stock. In addition, the terms of the $15.0 million credit facility limit our ability to pay dividends on our common stock to twenty-five percent (25%) of net profits (as defined in the facility agreement) less any amounts paid as dividends on our preferred stock.

Dividends on our Series A Convertible Preferred Stock were paid on a quarterly basis per the terms of such series. Cash dividends totaling $354,000, $360,000 and $360,000 were declared, and $330,000, $450,000 and $270,000 were paid for the years ended December 31, 2004, 2003 and 2002, respectively, on the Series A Convertible Preferred Stock. On or before December 31, 2004, all shares of the Series A Convertible Preferred Stock were converted into common shares. There will be no future dividend payments on Series A Convertible Preferred Stock.

Dividends on our Series A-1 Convertible Preferred Stock are paid on a quarterly basis per the terms of such series. Cash dividends totaling $360,000, $139,549 and $14,000 were declared for the years ended December 31, 2004, December 31, 2003 and December 31, 2002 on the Series A-1 Convertible Preferred Stock. Cash dividends totaling $285,155 and $153,549 were paid for the years ended December 31, 2004 and December 31, 2003, on the Series A-1 Convertible Preferred Stock. On December 31, 2004, 6,000 shares of Preferred Stock were converted into 37,500 common shares. On February 23, 2005, 82,000 shares of the Series A-1 Convertible Preferred Stock were exchanged into 532,664 common shares. Future dividends are anticipated to be paid in cash only at a rate of $0.5625 per share of Series A-1 Convertible Preferred Stock. On March 29, 2005, there were 72,000 shares of Series A-1 Convertible Preferred Stock outstanding.

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From September 30, 2004 through March 30, 2005, the following equity securities were issued pursuant to transactions that were exempt from the registration requirements under the Securities Act of 1933, as amended (for further information regarding issuances of securities during 2004, see Consolidated Statement of Changes in Stockholders Equity included in the consolidated financial statements):

On or before December 31, 2004, all 160,000 shares of our Series A Convertible Preferred Stock were converted pursuant to the terms thereof by the holders of such preferred stock into 1,000,000 shares of our common stock pursuant to the exemption from registration provided by Section 3(a)(9) of the Securities Act of 1933, as amended, 6,000 shares of our Series A-1 Convertible Preferred Stock were converted pursuant to the terms thereof by John Mark McLaughlin into 37,500 shares of our common stock pursuant to the exemption from registration provided by Section 3(a)(9) of the Securities Act of 1933, as amended, and $675,000 principal amount of our second amended and restated convertible debenture was converted pursuant to the terms thereof by PHD Partners, LP into 100,000 shares of our common stock pursuant to the exemption from registration provided by Section 4(2) of the Securities Act of 1933, as amended.

Pursuant to the terms of the 7.85% Convertible Subordinated Notes that we issued on July 22, 2004, we had the right to force the conversion of such notes into shares of our common stock on February 22, 2005, provided that the closing price of our common stock on the Nasdaq National Market System for each of the 30 consecutive trading days preceding January 22, 2005 was greater than $14.35 per share. On January 13, 2005, we offered the option to the noteholders to exchange their notes for the aggregate number of shares of our common stock issuable upon conversion of each of their notes and that portion of interest payable pursuant to the Notes that would otherwise have been payable to the noteholders through February 22, 2005 absent conversion of their notes prior to such date. Between January 13, 2005 and January 20, 2005, all the noteholders exchanged the $7.5 million principal amount of the notes into an aggregate of 914,634 shares of common stock at the $8.20 per share of common stock conversion price set forth in the notes pursuant to the exemption from registration provided by Section 3(a)(9) of the Securities Act of 1933, as amended, plus cash in the aggregate amount of approximately $85,000.

On February 3, 2005, we issued 3,200 shares of our common stock to RP&C International (Guernsey) Limited upon exercise of a warrant granted on July 22, 2004. The warrant had an exercise price of $8.20 per share of common stock. The shares of common stock issued were issued pursuant to the exemption from registration provided by Section 4(2) of the Securities Act of 1933, as amended, and Regulation D promulgated thereunder.

On February 21, 2005, in connection with the $15.0 million facility, we agreed to grant to Natexis Banques Populaires on or prior to April 21, 2005, options to purchase 50,000 shares of our common stock at an exercise price equal to the rolling average price of our common stock as reported on the NASDAQ Composite Transactions for the ten consecutive trading days immediately preceding the date of issuance of the options, plus fifteen percent (15%). It is currently contemplated that the options will be issued pursuant to the exemption from registration provided by Section 4(2) of the Securities Act of 1933, as amended.

We offered each holder of our Series A-1 Convertible Preferred Stock the opportunity to convert such shares into shares of our common stock pursuant to the terms of conversion of the Series A-1 Convertible Preferred Stock. In addition, we offered additional shares of common stock as an inducement for the holders to convert their shares of Series A-1 Convertible Preferred Stock at a time when we could not mandatorily redeem such shares and in lieu of dividends that would otherwise accrue until such mandatory redemption date. On February 22, 2005, pursuant to this offer, we issued 389,754 shares of common stock (14,754 inducement shares) to James R. Anderson, 129,918 shares of common stock (4,918 inducement shares) to Karen Anderson and 12,942 shares of common stock (492 inducement shares) to Roger A. Anderson. All the shares issued upon conversion were issued at the conversion price of $4.00 per share pursuant to the terms of the Series A-1 Convertible Preferred Stock. The shares of common stock were issued pursuant to the exemption from registration provided by either Section 3(a)(9) and/or Section 4(2) of the Securities Act of 1933, as amended. We also entered into Registration Rights Agreements with each of James R. Anderson, Karen Anderson and Roger A. Anderson relating to the inducement shares which agreements grant the holders of such inducement shares certain “piggy-back” registration rights relating to the resale of such inducement shares.

On February 22, 2005, we issued 7,080 shares of our common stock to Shimmerlik Corporate Communications, Inc. upon exercise of a warrant dated December 31, 2001, which was issued in connection with the acquisition of Madison Oil Company as a replacement for a warrant Shimmerlik previously held covering shares of common stock of Madison Oil Company. The shares of common stock were issued pursuant to the exemption from registration provided by Section 4(2) of the Securities Act of 1933, as amended.

During the fourth quarter 2004, we did not repurchase any of our registered equity securities.

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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.

	Year ended December 31,
	2004	2003	2002	2001	2000⁽¹⁾
	(in thousands, except per share data)
INCOME STATEMENT DATA:
Revenues:
Oil and natural gas sales	$ 22,336	$ 17,845	$ 17,456	$ 7,937	$ 13,164
Gain (loss) on commodity derivatives	(1,322)	(1,017)	(2,150)	26	(135)
Lease bonuses and rentals	14	18	69	—	472
Total revenues	21,028	16,846	15,375	7,963	13,501
Costs and expenses:
Lease operating	6,873	6,651	6,071	2,589	2,325
Exploration and acquisition	3,402	2,411	2,234	2,619	309
Depreciation, depletion and amortization	3,538	3,246	3,797	3,510	2,439
Impairment of oil and natural gas properties	—	171	525	1,237	—
General and administrative	5,646	3,494	5,270	1,583	2,273
Total costs and expenses	19,459	15,973	17,897	11,538	7,346
Operating income (loss)	1,569	873	(2,522)	(3,575)	6,155
Other income (expense)
Equity in earnings of unconsolidated investments	(18)	22	(1,186)	(206)	(54)
Gain (loss) on sale of properties and other assets	(336)	80	(2,143)	(510)	354
Foreign currency exchange gain	5,044	979	—	—	—
Turkish currency remeasurement	(1,140)	—	—	—	—
Interest and other income (expense)	396	173	(184)	163	71
Interest expense	(1,611)	(1,193)	(1,692)	(421)	(1,409)
Total other income (expense)	2,335	61	(5,205)	(974)	(1,038)
Income (loss) before income taxes	3,904	934	(7,727)	(4,549)	5,117
Provision (benefit) for income taxes	(3,576)	(266)	(2,061)	(1,802)	1,764
Income (loss) from continuing operations, net of tax	7,480	1,200	(5,666)	(2,747)	3,353
Income (loss) from discontinued operations, net of tax	17,539	1,182	(441)	2,105	—
Dividend on preferred shares	714	500	374	360	360
Net income (loss) attributable to common shares	$ 24,305	$ 1,882	$ (6,481)	$ (1,002)	$ 2,993
Basic income (loss) per share	$ 2.54	$ 0.20	$ (0.69)	$ (0.16)	$ 0.54
Diluted income (loss) per share	$ 1.97	$ 0.20	$ (0.69)	$ (0.16)	$ 0.50
Weighted average shares outstanding
Basic	9,571	9,338	9,343	6,319	5,522
Diluted	12,817	9,347	9,343	6,319	6,691
CASH FLOW DATA:
Net cash provided by operating activities	$ 94	$ 6,879	$ 6,362	$ 8,856	$ 6,144
Capital expenditures for oil and natural gas property and equipment	16,743	(3,713)	(6,178)	(11,979)	(2,353)
BALANCE SHEET DATA:
Working capital (deficit)	$ 1,090	$ (14,721)	$ (7,569)	$ (879)	$ 3,178
Oil and natural gas properties, net	79,667	77,616	71,872	78,028	34,630
Total assets	94,674	91,542	86,853	94,454	40,325
Long-term debt	—	—	26,860	36,874	15,244
Stockholder's equity	63,258	37,322	30,021	33,555	20,261

________

(1)	The amounts for 2000 have not been adjusted to reflect discontinued operations for properties sold in January 2004 as part of the Royalty Sale.

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ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITIONS
	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 Securities Act of 1933, 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 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 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

We are an independent international energy company engaged in oil and natural gas exploration, development, production, leasing and acquisition activities. Our strategy is to increase our oil and natural gas reserves through a balanced combination of exploratory drilling, development and exploitation projects and acquisitions. We primarily focus on international exploration activities in countries where we can establish large acreage positions. In addition, we target our operations in countries that we believe have stable governments, have attractive fiscal policies and are net-importers of oil and natural gas.

We currently hold interests in permits granting us the right to explore and develop oil and natural gas properties in the Paris Basin, France; onshore and offshore Turkey; onshore Romania; and offshore Trinidad, West Indies. We also own various working-interest properties primarily in Texas, Kansas, New Mexico, Louisiana and Oklahoma.

On January 14, 2004, we sold our U.S. mineral and royalty interests for approximately $45.0 million. Approximately $28.7 million of the net proceeds were used to discharge our two senior secured credit facilities. After taking into account taxes and fees associated with the sale, approximately $6.0 million remaining proceeds were added to our working capital. As a result of discharging our two senior secured credit facilities, we were able to strengthen our balance sheet and implement our long-term strategy of focusing on (i) generating grow of oil and natural gas reserves, production volumes and cash flows through drilling internally generated prospects, primarily in the international arena and (ii) seeking complementary acquisitions of new interests in our core geographic areas of operation.

Income applicable to common shares for 2004 was $24.3 million, or $1.97 per diluted share, compared with income applicable to common shares of $1.9 million, or $0.20 per diluted share, in 2003. A noncash currency translation adjustment of $1.1 million was incurred during the fourth quarter of 2004 as a result of a GAAP requirement that we use the U.S. dollar as the functional currency for our Turkish operations rather than the Turkish Lira, as previously was the case. The functional currency is required because Turkey is considered a highly inflationary operating environment under applicable accounting rules. The increased level of our capital expenditures in Turkey during 2004 warranted this currency adjustment. Audit adjustments subsequent to the March 8, 2005 earnings resulted in a decrease in Income applicable to common shares of approximately $260,000, or $0.02 per diluted share. The adjustments were necessary in order to adjust the foreign depletion calculation and to defer revenue recognition of an unconsolidated investee's revenue.

Operating income from continuing operations for 2004 was $1.6 million, which included a nonrecurring charge for seismic costs of $1.8 million for the Black Sea’s South Akcakoca sub-basin. Although the seismic survey was part of the area’s development program after our natural gas discovery there in 2004, a strict interpretation of successful efforts accounting pronouncements necessitated the immediate expensing of these seismic costs rather than capitalizing them.

Revenues for the full year 2004 were $21.0 million, a 25% increase over full-year 2003 revenues of $16.8 million.

In 2004, our oil and natural gas production was 634,000 BOE versus production of 665,000 BOE for 2003. Our average realized oil price per barrel for 2004 was $35.24, a 35% increase over the average realized oil price per barrel of $26.02 in 2003. The average realized gas price in 2004 was $5.65 per Mcf, 19% higher than the average realized gas price of $4.74 per Mcf in 2003.

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At December 31, 2004, we held interests in approximately 4.4 million gross acres (approximately 3.3 million net acres). For a more detailed description of our properties please see “Item 2. Properties.” At December 31, 2004, our estimated net proved reserves were 13.8 MMBOE.

On February 16, 2005, we sold 1,437,500 shares of our common stock pursuant to a public offering at a price to the public of $24.25 per share. The sale resulted in net proceeds of approximately $32.6 million, which will be used to fund our 2005 capital expenditure budget and for other general corporate purposes.

We will continue to seek opportunities to accelerate our worldwide acquisition and development program by:

•		Exploiting existing properties and developing existing reserves.
•	Implementing a balanced program of exploration, development and exploitation, thereby managing our risk exposure.
•		Pursuing new permits and selective property acquisitions under terms that include:

- High-impact exploration concessions in core geographic areas primarily located in the Euro-Eastern Mediterranean region; and

		- Established producing properties that offer potentially significant additions to our asset base.
•	Maintaining operational flexibility by adjusting our drilling program and capital expenditure budget during the year when necessary.

CRITICAL ACCOUNTING POLICIES

USE OF ESTIMATES

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

BASIS OF CONSOLIDATION

Toreador consolidates all of its majority-owned subsidiaries. All material intercompany accounts and transactions are eliminated in consolidation. We account for our investments in entities in which we hold less than a majority interest under the equity method.

CASH AND CASH EQUIVALENTS

Cash and cash equivalents include cash on hand, amounts due from banks and all highly liquid investments with original maturities of three months or less. We maintain our cash in bank deposit accounts, which, at times, may exceed federally insured limits. We have not experienced any losses in such accounts and believe we are not exposed to any significant risk of loss.

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CONCENTRATION OF CREDIT RISK AND ACCOUNTS RECEIVABLE

Financial instruments that potentially subject us to a concentration of credit risk consist principally of cash, accounts receivable, and our hedging and derivative financial instruments. We place our cash with high credit quality financial institutions. We sell oil and natural gas to various customers. Historically, we have not experienced any losses related to accounts receivable, and accordingly, we do not believe an allowance for doubtful accounts is warranted either at December 31, 2004 or 2003. Substantially all of our accounts receivable are due from purchasers of oil and natural gas. We place our hedging and derivative financial instruments with financial institutions and other firms that we believe have high credit ratings. For a discussion of the credit risks associated with our hedging activities, please see "Critical Accounting Policies -- Derivative Financial Instruments” below.

FINANCIAL INSTRUMENTS

The carrying amounts of financial instruments including cash and cash equivalents, short-term investments, accounts receivable, marketable securities, accounts payable and accrued liabilities, long-term debt, and the convertible debenture approximate fair value, unless otherwise stated, as of December 31, 2004 and 2003.

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DERIVATIVE FINANCIAL INSTRUMENTS

We use various swap and option contracts to (i) reduce the effect of the volatility of price changes on the commodities we produce and sell; and (ii) support our annual capital budgeting and expenditure plans. In order to accomplish this objective, we periodically enter into oil and natural gas swap and option agreements that fix the price of oil and natural gas sales within ranges determined acceptable at the time we execute the contracts. We may also, from time to time, enter into hedges of foreign currency. Losses from these hedges totaled $63,000 in 2004. We did not enter into any foreign currency hedges in 2003.

We are exposed to credit losses in the event of nonperformance by the counterparties to our financial instruments. We anticipate, however, that such counterparties will be able to fully satisfy their obligations under the contracts. We do not obtain collateral or other security to support financial instruments subject to credit risk but we monitor the credit standing of the counterparties. At December 31, 2004 and 2003, we had no amounts receivable from our counterparties.

We have elected not to designate the derivative financial instruments to which we are a party as hedges, and accordingly, we record such contracts at fair value and recognize changes in such fair value in current earnings as they occur.

INVENTORIES

At December 31, 2004 and 2003, other current assets included $530,000 and $854,000 of inventory, respectively. Those amounts consist of technical equipment and crude oil held in storage tanks. We record equipment inventories at the lower of actual cost or market. Crude oil held in tanks in priced at market.

OIL AND NATURAL GAS PROPERTIES

We follow the successful efforts method of accounting for our oil and natural gas exploration and development expenditures. Under this method, costs of successful exploratory wells and all development wells are capitalized. Costs to drill exploratory wells that do not find proved reserves are expensed. In the absence of a determination as to whether the reserves that have been found can be classified as proved, we carry the costs of drilling such exploratory wells as an asset for no more than one year following completion of drilling. If after that year has passed, a determination that proved reserves have been found cannot be made, we will assume that the well is impaired, and charge the cost to expense. Significant costs associated with the acquisition of oil and natural gas properties are capitalized. Upon sale or abandonment of units of property or the disposition of miscellaneous equipment, the cost is removed from the asset account, net of the accumulated depreciation or depletion, and the gain or loss is credited to or charged against operations.

Maintenance and repairs are charged to expense; betterments of property are capitalized and depreciated as described below.

DEPRECIATION, DEPLETION AND AMORTIZATION

We provide depreciation, depletion and amortization of our investment in producing oil and natural gas properties on the units-of-production method based upon independent reserve engineers' estimates of recoverable oil and natural gas reserves from the property. Depreciation expense for fixed assets is generally calculated on a straight-line basis based upon estimated useful lives of three to seven years.

IMPAIRMENT OF ASSETS

We evaluate producing property costs for impairment and reduce such costs to fair value if the sum of expected undiscounted future cash flows is less than net book value pursuant to Statement of Financial Accounting Standard No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets (“Statement 144”). On January 1, 2002 we adopted Statement 144. At December 31, 2003, we had properties held for sale of $13.2 million. These assets were sold for approximately $45.0 million cash in January 2004. We assess impairment of non-producing leasehold costs and undeveloped mineral and royalty interests periodically on a property-by-property basis. We charge any impairment in value to expense in the period incurred. We incurred impairment losses on our United States oil and natural gas producing properties of zero in 2004, $171,000 in 2003, and $525,000 in 2002. The impairments in 2003 were the result of overall decreases in the quantity of reserves on maturing properties. The impairments in 2002 were the result of several properties depleting faster than expected. There were no properties with individually significant impairments, nor was there any particular group of properties that were impaired.

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ASSET RETIREMENT OBLIGATIONS

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 $1,716,000 and $1,690,000, 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.

The following tables describe on a pro forma basis the effect of our asset retirement on net loss and liability as if Statement 143 had been adopted on January 1, 2002:

	2004	2003
	(in thousands)
Asset retirement obligation January 1	$ 1,789	$ 1,690
Asset retirement accretion expense	127	105
Plus: foreign currency exchange gain	436	—
Plus property additions	39	—
Less: plugging cost	(37)	(5)
Less: property sold	(23)	(1)
Asset retirement obligation at December 31	$ 2,331	$ 1,789

Asset retirement obligations are recorded as current or non-current liabilities based on our estimate of plugging and abandonment dates of the related wells.

	Year Ended December 31, 2002
	(in thousands, except per share data)
Net loss, reported		$ (6,481)
Less: retirement obligation accretion expense		116
Plus: depreciation on salvage value		—
Net loss pro forma		$ (6,597)

Loss per share:
As reported
Basic		$ (0.69)
Diluted		$ (0.69)

Pro forma
Basic		$ (0.70)
Diluted		$ (0.70)

GOODWILL

On January 1, 2002, we adopted Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets (“Statement 142”). Under Statement 142, goodwill and indefinite-lived intangible assets are no longer amortized but are reviewed annually (or more frequently if impairment indicators arise) for impairment. Separable intangible assets that are not deemed to have an indefinite life will continue to be amortized over their useful lives (but with no maximum life).

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Prior to our acquisition of Madison Oil Company, we had no goodwill, so the adoption of this standard had no impact on our financial position or results of operations. As the result of adopting Statement 142, we will review annually the value of goodwill recorded as a result of the acquisition Madison, or more frequently if impairment indicators arise. We recognized no goodwill impairment during 2004 or 2003. Goodwill was reduced by $929,000 in 2004 for a corresponding reduction in deferred tax liabilities which resulted from ]the recognition of prior Madison Oil Company net operating losses that were reserved at the date of acquisition. At the end of 2003, we made a commitment to be fully reinvested in our international subsidiaries. Accordingly, we reversed the deferred tax liability originally booked as a result of the acquisition of Madison Oil Company against goodwill in the amount of $2.4 million. This amount represented the tax effect of the difference between the financial reporting and tax basis of the net assets of Madison Oil Company at the time of the acquisition. The balance of goodwill at December 31, 2004 is approximately $2.5 million.

REVENUE RECOGNITION

We account for natural gas revenues using the sales method. Under this method, sales are recorded on all production we sell regardless of our ownership interest in the respective property. Imbalances result when sales differ from the seller's net revenue interest in the particular property's reserves and are tracked to reflect the Company's balancing position. At December 31, 2004, 2003 and 2002, the imbalance and related value were immaterial.

STOCK-BASED COMPENSATION

Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation ("Statement 123"), encourages, but does not require, the adoption of a fair value-based method of accounting for employee stock-based compensation transactions. We have elected to apply the provisions of Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees ("Opinion 25"), and related interpretations, in accounting for our employee stock-based compensation plans. Under Opinion 25, compensation cost is measured as the excess, if any, of the quoted market price of our stock at the date of the grant above the amount an employee must pay to acquire the stock.

Had compensation costs for employees under our two stock-based compensation plans been determined based on the fair value at the grant dates under those plans consistent with the method proscribed by Statement 123, our net income (loss) and earnings (loss) per share would have been reduced to the pro forma amounts listed below:

	2004	2003	2002
	(in thousands except per share data)
Net income (loss), applicable to common shares, as reported	$ 24,305	$ 1,882	$ (6,481)
Basic earnings (loss) per share reported	2.54	0.20	(0.69)
Diluted earnings (loss) per share reported	1.97	0.20	(0.69)
Stock-based compensation costs under the intrinsic value method included in net income (loss) reported, net of related tax	—	—	—
Pro-forma stock-based compensation costs under the fair value method, net of related tax	1,049	249	432
Pro-forma income (loss) applicable to common shares, as under the fair-value method	23,256	1,633	(6,913)
Pro-forma basic earnings (loss) per share under the fair value method	2.43	0.17	(0.74)
Pro-forma diluted earnings (loss) per share under the fair value method	1.89	0.17	(0.74)

The fair value of each option granted is estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions:

	2004	2003	2002
Dividend yield per share	—	—	—
Volatility	43 - 54%	42%	34%
Risk-free interest rate	3.3 – 4.6%	2.8%	2.8%
Expected lives	3 years	10 years	10 years

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FOREIGN CURRENCY TRANSLATION

The functional currency of the countries in which we operate is the U.S. dollar in the United States, the Eurodollar in France and the U.S. dollar in Turkey. Gains and losses resulting from the translations of local currencies into U.S. dollars are included in other comprehensive income for the current period. We periodically review the operations of our entities to ensure the functional currency of each entity is the currency of the primary economic environment in which we operate.

INCOME TAXES

We are subject to income taxes in the United States, France, and Turkey. The current provision for taxes on income consists primarily of income taxes based on the tax laws and rates of the countries in which operations were conducted during the periods presented. We compute our provision for deferred income taxes using the liability method. Under the liability method, deferred income tax assets and liabilities are determined based on differences between financial reporting and income tax basis of assets and liabilities and are measured using the enacted tax rates and laws. The measurement of deferred tax assets is adjusted by a valuation allowance, if necessary, to recognize the future tax benefits to the extent, based on available evidence it is more likely than not deferred tax assets will be realized. Goodwill was reduced by $929,000 in 2004 for a corresponding reduction in deferred tax liabilities which resulted from the recognition of prior Madison Oil Company net operating losses. At the end of 2003, we made a commitment to be fully reinvested in our international subsidiaries. Accordingly, we have reversed the deferred tax liability originally booked as a result of the acquisition of Madison Oil Company against goodwill in the amount of $2.4 million. This amount represented the tax effect of the difference between the financial reporting and tax basis of the net assets of Madison Oil Company at the time of the acquisition. The balance of the deferred tax liability at December 31, 2004 is $10.7 million.

NEW ACCOUNTING PRONOUNCEMENTS

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. On February 2, 2004, we committed to the termination of two landmen as a result of the Royalty Sale in January 2004. Total severance expense and liability for the year ended December 31, 2004, were approximately $172,000 and zero, respectively. The following table provides a reconciliation of the liability:

Exit Cost or Disposal Activity		Amount
		(in thousands)
Employee severance liability June 17, 2003		$ 511
Cost incurred		—
Adjustments		—
Less: Payroll payments		(201)
Severance liability December 31, 2003		$ 310

Cost incurred		172
Adjustments		—
Less: Payroll Payments		(482)
Severance liability December 31, 2004		$ —

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In December 2004, the FASB revised Financial Accounting Standard No. 123, Accounting for Stock Based Compensation. This statement supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees, and its related implementation guidance. This statement establishes standards for the accounting of transactions in which an entity exchanges its equity instruments for goods or services. This statement focuses primarily on the accounting for transactions in which an entity obtains employee services in exchange for its equity instruments. The statement is effective for interim quarters beginning after June 15, 2005. We do not expect that the adoption of this statement will have a significant impact on our future results of operations or financial position.

In November 2004, the FASB issued Financial Accounting Standard No. 151 on Inventory Costs. This statement amends guidance set forth in ARB No. 43, Chapter 4, Inventory Pricing to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs, and wasted material (spoilage). The statement is effective for fiscal years beginning after June 15, 2005. The adoption of this statement will not have an impact on our future results of operations or financial position.

RESULTS OF OPERATIONS

COMPARISON OF YEARS ENDED DECEMBER 31, 2004 AND 2003

REVENUES

Oil and natural gas sales. For the year ended December 31, 2004, oil and natural gas sales revenues were $22.3 million, increasing approximately $4.5 million, or 25%, from $17.8 million for the year ended December 31, 2003. This was due to an increase in the average prices we received for oil and natural gas sales. In 2004, our average oil price per barrel was $35.24 versus $26.02 in 2003. Our average price for natural gas in 2004 was $5.65 per Mcf, compared with $4.74 in 2003. The increase in revenues was offset by a 5% decrease in overall production of 31,000 BOE from 665,000 BOE in 2003 to 634,000 BOE in 2004. Production in the United States decreased 35,000 BOE, the result of the natural decline of our existing properties and the loss of production on the Vermillion 175 #1. Turkish production decreased by 19,000 BOE due to the natural decline of existing properties and the loss of production on the Cendere #12 well. French production increased 23,000 BOE, a result of the workover program and the addition of the Charmottes 109 during the year.

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 production. The following table summarizes the results of our risk-management efforts during 2004 and 2003:

	2004	2003	Variance
	(in thousands)
Changes in fair value	$ 1,159	$ (365)	$ 1,524
Realized gain (loss)	(2,481)	(1,956)	(525)
Net	$ (1,322)	$ (2,321)	$ 999

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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.

EXPENSES

Lease operating. Lease operating expenses increased $222,000, or 3%, primarily due to the increase in workover costs on our French properties.

Exploration and acquisition. Exploration and acquisition expense increased $991,000, or 41%, from 2003 to 2004, due to the December 2004 seismic program in the Black Sea of Turkey.

Depreciation, depletion and amortization. Depreciation, depletion and amortization increased $292,000, or 9%, compared with 2003 due to decreased reserve balances in Turkey. 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.

Impairment of oil and natural gas properties. Impairment charged in 2004 amounted to zero, compared with $171,000 in 2003. The decrease in the impairment charge is the result of an increase in year-end reserves. Oil and natural gas prices used to estimate the value of our reserves at December 31, 2003, were $27.87 per barrel and $5.90 per Mcf, respectively, compared with $37.55 per barrel and $5.99 per Mcf, respectively, at December 31, 2004.

General and administrative. General and administrative expenses increased $2.5 million, or 84%. The majority of this increase was the result of actual 2003 costs totaling $2.2 million being allocated to discontinued operations. The remaining increase of $300,000 was the result of the final settlement of a severance claim in France.

OTHER INCOME AND EXPENSE

Other income and expense resulted in a net income addition of $2.3 million during 2004 versus $61,000 for 2003. The increase was a result of foreign currency transaction gains of $5.0 million primarily on payments towards the facility we had with Barclays Bank, plc (the “Barclays Facility”). Equity in earnings of unconsolidated subsidiaries had a loss of $18,000 for 2004 compared with a gain of $22,000 for 2003. The decrease was the result of negative earnings from our interest in ePsolutions. Gains were partially offset by a $1.1 million charge for the remeasurement of Turkish currency. The remeasurement was required due to the material nature of our capital expenditures in Turkey. Turkey has been classified as highly-inflationary but the effect in prior years was considered immaterial. The functional currency in Turkey will be the U.S. dollar as long as the country is considered highly-inflationary.

NET INCOME (LOSS) AVAILABLE TO COMMON SHARES

During 2004, we had earnings available to common stockholders of $24.3 million, compared with $1.9 million for 2003. Improved results for 2004 were largely due to an $18.2 million net gain on the sale of U.S. mineral and royalty properties. In addition, we received a benefit from income taxes of $3.6 million compared to $266,000 in 2003. The increase was mainly the result of utilizing net operating loss carryforwards from prior years.

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 in 2004 was the U.S. dollar and in 2003 was the Turkish Lira. The exchange rate used to translate the financial position of the French operations at December 31, 2004, was approximately U.S. $1.36 per Eurodollar. At December 31, 2003, the exchange rates were U.S. $1.26 per Eurodollar and U.S. $0.70 per million Turkish Lira. These fluctuations caused an unrealized translation gain of $1.2 million in 2004, compared with an unrealized translation gain of $2.2 million in 2003.

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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 14 of the Notes to 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 14% decrease in overall production of 153,000 BOE from 1,069,000 BOE in 2002 to 916,000 BOE in 2003. Production in the United States 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 was 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:

	2003	2002	Variance
	(in thousands)
Changes in fair value	$ (365)	$(2,029)	$ 1,664
Realized gain (loss)	(1,956)	(2,015)	59
Net	$(2,321)	$(4,044)	$ 1,723

Lease bonuses and rentals. Lease bonuses and rentals decreased 56%, or $453,000, 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. Depreciation, depletion and amortization 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.

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Impairment of oil and natural gas properties. Impairment charged in 2003 amounted to $171,000, compared with $525,000 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, respectively, compared with $29.25 per barrel and $5.76 per Mcf, respectively, 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 Oil Company that was expensed in 2002. A significant portion of the expenses associated with the Madison Oil Company 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.

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 Oil Company acquisition, and the value of our investment in Trinidad Exploration and Development, Ltd. 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.

LIQUIDITY AND CAPITAL RESOURCES

LIQUIDITY

Capital expenditures in 2004 were approximately $16.7 million. During 2004, we funded our capital expenditure requirements from cash flow and the $7.5 million we received from the private placement of our 7.85% convertible subordinated notes due June 30, 2009.

We currently expect that our 2005 capital expenditure budget will be approximately $46.0 million which will be spent principally on exploration and development activities, primarily in France, Turkey and Romania. We believe that a significant portion of this amount will be spent to appraise and develop the South Akcakoca gas project in Turkey's Western Black Sea. We also may acquire other producing oil and natural gas properties requiring additional capital.

To fund these capital expenditure requirements, we expect to receive future cash flow through production from existing producing properties and new producing properties that may be discovered through exploration, along with development properties added to existing fields.

In addition, in February 2005, we sold 1,437,500 shares of our common stock in a public offering. The net proceeds of our offering (approximately $32.6 million) will be used, in addition to our cash flow from production and available borrowings, to fund our 2005 capital expenditure budget and for other general corporate purposes, including possible acquisitions. We believe that sufficient funds will be available from operating cash flow, cash on hand, available borrowings under existing facilities, other facilities that we may enter into, the February 2005 public offering and any future public or private issuances of debt or equity securities to meet anticipated capital budget requirements and fund potential acquisitions in 2005.

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SENIOR DEBT

We have entered into a five-year $15.0 million reserve-based borrowing facility with a French lender to finance the development of our existing French fields, acquisitions of new fields, general working capital and our corporate purposes. The facility bears interest at a floating rate of 2.25-2.75% above LIBOR depending on the principal outstanding. The facility is collateralized by certain of our French assets, including contracts relating to our rights and interests in our French fields, our direct and indirect equity interests in certain of our subsidiaries and payments received from the sale of our French production. Toreador and certain of its U.S. and French subsidiaries have each guaranteed the obligations under the facility. Under the $15.0 million facility, at March 30, 2005, there were no amounts outstanding and borrowings of approximately $8.0 million were available. The $15.0 million facility contains various affirmative and negative covenants. These covenants, among other things, limit additional indebtedness, the sale of assets, change of control and management, limitations on the distribution of stock dividends and require us to meet certain financial requirements. Specifically, we must maintain an interest cost ratio of not less than 4.00 to 1.00, an indebtedness ratio of not less than 1.00 to 1.00, asset life cover ratio of not less than 1.25 to 1.00, a loan life cover ratio equal to or greater than 1.15 to 1.00 and a debt service coverage ratio equal to or greater than 1.10 to 1.00.

On December 30, 2004, we entered into a five-year $25.0 million reserve-based borrowing facility with a U.S. lender in order to finance the development and acquisition of oil and natural gas interests both domestically and internationally and for working capital purposes. The facility bears interest at a rate of prime less 0.5% and is collateralized by our domestic working interests. At March 30, 2005, there were no amounts outstanding under this facility and borrowings of approximately $ 3.3 million were available. The $25.0 million facility contains various affirmative and negative covenants. These covenants, among other things, limit additional indebtedness, the sale of assets, change of control and management and require us to meet certain financial requirements. Specifically, we must maintain a current ratio of 1.25 to 1.00 (exclusive of amounts due under revolving credit arrangements) and an interest coverage ratio of not less than 3.00 to 1.00. As of December 31, 2004, we were in compliance with all covenants.

PREFERRED STOCK

Toreador had 160,000 shares of nonvoting Series A Convertible Preferred Stock outstanding at September 30, 2004. At the option of the holder, the Series A Convertible Preferred Stock was convertible into common shares at a price of $4.00 per common share (conversion amounted to 1,000,000 Toreador common shares). At any time on or after December 1, 2004, we had the option to redeem for cash any or all shares of Series A Convertible Preferred Stock. On December 6, 2004, we gave a notice of redemption to the holders of the Series A Convertible Preferred Stock. All 160,000 shares of Series A Convertible Preferred Stock were converted into an aggregate of 1,000,000 shares of our common stock on or prior to December 31, 2004.

Toreador had 154,000 shares of nonvoting Series A-1 Convertible Preferred Stock outstanding at December 31, 2004. On February 22, 2005, 82,000 shares of Series A-1 Convertible Preferred Stock were exchanged for an aggregate of 532,664 shares of our common stock. As of March 30, 2005, there are 72,000 shares of Series A-1 Convertible Preferred Stock outstanding. 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 (conversion would amount to 450,000 Toreador common shares). The Series A-1 Convertible Preferred Stock accrues dividends at an annual rate of $2.25 per share payable quarterly in cash. At any time on or after November 1, 2007, we may elect to redeem for cash any or all shares of Series A-1 Convertible Preferred Stock. 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.

CONVERTIBLE DEBENTURES/NOTES

Prior to the acquisition of Madison Oil Company, Madison Oil Company was party to a convertible debenture in the amount of approximately $2.2 million payable to PHD Partners LP and due on March 31, 2006. The general partner of PHD Partners LP is a corporation wholly-owned by David M. Brewer, a director and significant stockholder of Toreador. The original debenture bore interest at 10% per annum. As of March 31, 2004, the debenture was amended and restated to bear interest at 6% per annum, eliminate Madison Oil Company's right under certain circumstances to force a conversion of the principal into shares of Toreador common stock and eliminate Madison Oil Company's ability to repay principal prior to maturity. At the holder's option, the second amended and restated convertible debenture can be converted into Toreador common stock at a conversion price of $6.75 per share. At March 30, 2005, the outstanding principal amount of the second amended and restated convertible debenture was approximately $1.5 million. We have 219,962 shares of common stock reserved for issuance related to the conversion of the second amended and restated convertible debenture.

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In July 2004, we sold to certain institutional investors pursuant to a private offering $7.5 million aggregate principal amount of 7.85% convertible subordinated notes due June 30, 2009. We used the net proceeds of the offering to accelerate our oil development program in France's Paris Basin and for general corporate purposes. The 7.85% convertible subordinated notes due June 30, 2009 bore interest at the rate of 7.85% per annum and were convertible into shares of Toreador common stock at a conversion price of $8.20 per share. Toreador had the right to cause the 7.85% convertible subordinated notes due June 30, 2009 to be converted on or after February 22, 2005, if the closing price of Toreador's common stock was greater than $14.35 for the 30 consecutive trading days prior to the date of Toreador's conversion notice. On January 13, 2005, we offered the option to the holders of the 7.85% convertible subordinated notes due June 30, 2009 to exchange their notes for the aggregate number of shares of our common stock issuable upon conversion of each of their notes and that portion of interest payable pursuant to the notes that would otherwise have been payable to the holders through February 22, 2005 absent conversion of the notes prior to such date. On or prior to January 20, 2005, all of our 7.85% convertible subordinated notes due June 30, 2009 were exchanged for an aggregate of 914,634 shares of our common stock and an aggregate cash payment (in lieu of interest) of approximately $85,000.

DIVIDEND AND INTEREST REQUIREMENTS

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-1 Convertible Preferred Stock also 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-1 Convertible Preferred Stock. The terms of the $15.0 million facility limit our ability to pay dividends on our common stock to twenty-five percent (25%) of net profits (as defined in the facility agreement) less any amounts paid as dividends on our preferred stock.

Dividends on our Series A Convertible Preferred Stock were and dividends on our Series A-1 Convertible Preferred Stock are paid quarterly. Cash dividends totaling $615,000 and $604,000 were paid for the twelve-month periods ended December 31, 2004 and 2003, respectively. As a result of the conversion on or prior to December 31, 2004 of all 160,000 shares of Series A Convertible Preferred Stock, future dividends will be paid in cash only on the Series A-1 Convertible Preferred Stock at the rate of $0.5625 per share per full calendar quarter. Interest on the 7.85% convertible subordinated notes due June 30, 2009 was paid quarterly. Interest paid on the 7.85% convertible subordinated notes due June 30, 2009 as of December 31, 2004 was $263,303.

CONTRACTUAL OBLIGATIONS

The following table sets forth our contractual obligations in thousands at December 31, 2004 for the periods shown:

		Due Within
	Total	1 Year	2 - 3 Years	4 - 5 Years	After 5 Years
Debt⁽¹⁾	$ 8,985	$ —	$ 1,485	$ 7,500	$ –
Leases	1,032	399	633	—	–

Total	$ 10,017	$ 399	$ 2,118	$ 7,500	$ –

__________

(1)

We have recently entered into two new borrowing facilities. At March 30, 2005, there are no amounts outstanding under either facility. However, on March 30, 2005, approximately $8.0 million was available for borrowings under the $15.0 million facility and approximately $3.3 million was available for borrowings under the $25.0 million facility.

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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.

		Three Months Ended
		December 31,	September 30,	June 30,	March 31,
		(in thousands, except per share data)
Year ended December 31, 2004:
Total revenues		$ 6,401	$ 5,631	$ 5,134	$ 3,862
Impairment of oil and natural gas properties		—	—	—	—
Total costs and expenses		7,020	4,070	3,880	4,489
Net income (loss)		(188)	1,886	1,335	21,986
Income (loss) attributable to common shares		(362)	1,706	1,155	21,806
Basic income (loss) per share		(0.04)	0.18	0.12	2.31
Diluted income (loss) per share		(0.04)	0.15	0.11	1.84

	Year ended December 31, 2003:
Total revenues		$ 3,237	$ 5,620	$ 3,582	$ 4,408
Impairment of oil and natural gas properties		171	—	—	—
Total costs and expenses		4,256	4,257	3,881	3,580
Net income (loss)		(61)	1,071	556	815
Income (loss) attributable to common shares		(214)	946	445	704
Basic income (loss) per share		(0.02)	0.10	0.05	0.08
Diluted income (loss) per share		(0.02)	0.09	0.05	0.07

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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, 2004, 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 2005 sales volumes at fixed prices, such a decrease would result in a reduction to oil and natural gas sales revenue of approximately $3.3 million.

Foreign Currency Exchange Rates. The functional currency of our French operations is the Eurodollar. While our oil sales are calculated on a U.S. dollar basis, we are exposed to the risk that the values of our French assets will decrease and that the amounts of our French liabilities will increase. Market risk is estimated as a 10% decrease in the exchange rate for Eurodollars to U.S. dollars. Based on the net assets in our French operations at December 31, 2004, such a decrease would result in an unrealized loss of approximately $3.2 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.” Currently, we do not have any commodity derivative instruments for our production.

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 Registered Public Accounting Firms 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.

None.

ITEM 9A.

CONTROLS AND PROCEDURES.

Evaluation of Disclosure Controls and Procedures

An evaluation was performed under the supervision and with the participation of our management, including our chief executive officer and chief financial officer, of the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the "Exchange Act")) as of the end of the period covered by this report. Based on the evaluation and communications from Hein & Associates LLP to our Audit Committee in March 2004, our chief executive officer and chief financial officer concluded that the Company's disclosure controls and procedures were not effective in reporting, on a timely basis, information required to be disclosed by the Company in the reports that the Company files or submits under the Exchange Act, and this Annual Report on Form 10-K, due to internal control deficiencies relating to the limited review of sensitive calculations prepared by our controller, the failure to establish review procedures to detect errors in the calculation of foreign depletion, the lack of adequate review and challenge of investee's revenue recognition as reflected in investee's unconsolidated financial statements and the failure of the Compensation Committee to prepare timely written minutes from meetings occurring in 2004.

Hein & Associates LLP advised the Audit Committee that each of these internal control deficiencies constitutes material weaknesses as defined in Statement of Auditing Standards No. 60. Certain of these internal control weaknesses may also constitute material weaknesses in our disclosure controls. Due to these material weaknesses, the Company, in preparing its financial statements for the year ended December 31, 2004, performed additional disclosure procedures relating to these items to ensure that such financial statements were stated fairly in all material respects in accordance with U.S. generally accepted accounting principles.

Changes in Internal Control over Financial Reporting

There were no changes in the Company's internal control over financial reporting identified in connection with the evaluation of internal control 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.

However, given the subsequent identification of the above material weaknesses, the Company has implemented a course of action reasonably assured to remediate these material weaknesses. This course of action includes: the decision to hire a Vice President of Accounting in the near future in order to (i) provide focused manpower to strengthen our review procedures, (ii) oversee all sensitive calculations and (iii) oversee the controls of all persons reporting to the Vice President of Accounting; documenting and enforcing existing policies and procedures and establishing new processes regarding review of financial information, including oversight of foreign depletion calculations; implementing a new policy that would require independent audits of certain material unconsolidated subsidiaries; and establishing additional procedures for the timely preparation of committee meeting minutes.

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ITEM 9B.

OTHER INFORMATION.

None.

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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, (iv) changes in procedures by which security holders may recommend nominees to our board of directors, and (v) 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,” “Nominations to the Board of Directors – Consideration of Stockholder Recommendations of Director Candidates” and “Section 16(a) Beneficial Ownership Reporting Compliance” in our Proxy Statement relating to the 2005 Annual Meeting of Stockholders, that will be filed with the Securities and Exchange Commission on or prior to April 29, 2005, and that is incorporated herein by reference.

ITEM 11.

EXECUTIVE COMPENSATION.

Information required by this item relating to executive compensation will be set forth under the heading “Executive Compensation and Other Transactions” in our Proxy Statement relating to the 2005 Annual Meeting of Stockholders, that will be filed with the Securities and Exchange Commission on or prior to April 29, 2005, and that is incorporated herein by reference.

ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
	AND RELATED STOCKHOLDER MATTERS.

Information required by this item will be set forth under the heading “Securities Authorized for Issuance Under Equity Compensation Plans” and “Security Ownership of Certain Beneficial Owners and Management” in our Proxy Statement relating to the 2005 Annual Meeting of Stockholders, that will be filed with the Securities and Exchange Commission on or prior to April 29, 2005, and that is incorporated herein by reference.

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

Information required by this item relating to certain business relationships and related transactions with management and other related parties will be set forth under the heading “Certain Relationships and Related Transactions” in our Proxy Statement relating to the 2005 Annual Meeting of Stockholders, that will be filed with the Securities and Exchange Commission on or prior to April 29, 2005, and that is incorporated herein by reference.

ITEM 14.

PRINCIPAL ACCOUNTANT FEES AND SERVICES.

The information relating to (i) fees billed to the Company by the independent public accountants for services in 2004 and 2003 and (ii) audit committee’s pre-approval policies and procedures for audit and non-audit services, will be set forth under the headings “Auditors - Fees Paid to Ernst & Young LLP and Hein & Associates LLP Related to Fiscal 2004 and 2003” and “Auditors - Pre-Approval Policies” in our Proxy Statement relating to the 2005 Annual Meeting of Stockholders, that will be filed with the Securities and Exchange Commission on or prior to April 29, 2005, and that is incorporated herein by reference.

PART IV

ITEM 15.		EXHIBITS, FINANCIAL STATEMENT SCHEDULES.
	(a)	The following documents are filed as part of this report:

Index to Consolidated Financial Statements, Reports of Independent Registered Public Accounting Firms, Consolidated Balance Sheets as of December 31, 2004 and 2003, Consolidated Statements of Operations for the three years ended December 31, 2004, Consolidated Statements of Changes in Stockholders’ Equity for the three years ended December 31, 2004, Consolidated Statements of Cash Flows for the three years ended December 31,

2004, and Notes to Consolidated Financial Statements

2.	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 Consolidated Financial Statements.

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Exhibits:

1.1

Underwriting Agreement, dated February 10, 2005, between Toreador Resources Corporation and Morgan Keegan & Co., Inc. (previously filed as Exhibit 1.1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on February 11, 2005, File No. 0-2517, and incorporated herein by reference).

2.1*

Certificate of Ownership and Merger, effective June 5, 2000, merging Toreador Resources Corporation into Toreador Royalty Corporation.

2.2

Agreement and Plan of Merger, dated as of October 3, 2001, between Toreador Resources Corporation and Madison Oil Company (previously filed as Exhibit 2.1 to Toreador Resources Corporation Registration Statement on Form S-4, No. 333-72314, filed on October 26, 2001, and incorporated herein by reference).

2.3

Agreement for Purchase and Sale, dated December 17, 2003, by and among Toreador Resources Corporation and Tormin, Inc., as Sellers, and Black Stone Acquisitions Partners I, L.P., as Buyer (previously filed as Exhibit 2.1 to Toreador Resources Corporation Current Report on Form 8-K filed on January 15, 2004, File No. 0-2517, and incorporated herein by reference).

3.1

Restated Certificate of Incorporation, of Toreador Resources Corporation (previously filed as Exhibit 3.1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on March 29, 2005, File No. 0-2517, and incorporated herein by reference).

3.2

Third Amended and Restated Bylaws of Toreador Resources Corporation (previously filed as Exhibit 3.2 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on March 29, 2005, File No. 0-2517, and incorporated herein by reference).

4.1*

Settlement Agreement, dated June 25, 1998, among the Gralee Persons, the Dane Falb Persons and Toreador Royalty Corporation.

4.2

Warrant, dated July 22, 2004, issued by Toreador Resources Corporation to Nigel Lovett (previously filed as Exhibit 4.14 to Toreador Resources Corporation Registration Statement on Form S-3 filed with the Securities and Exchange Commission on August 20, 2004, File No. 0-2517, and incorporated herein by reference).

4.3

Warrant, dated July 22, 2004, issued by Toreador Resources Corporation to Rich Brand (previously filed as Exhibit 4.13 to Toreador Resources Corporation Registration Statement on Form S-3 filed with the Securities and Exchange Commission on August 20, 2004, File No. 0-2517, and incorporated herein by reference).

4.4

Registration Rights Agreement, effective February 22, 2005, between Toreador Resources Corporation and James R. Anderson (previously filed as Exhibit 4.1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on February 24, 2005, File No. 0-2517, and incorporated herein by reference).

4.5

Registration Rights Agreement, effective February 22, 2005, between Toreador Resources Corporation and Karen Anderson (previously filed as Exhibit 4.2 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on February 24, 2005, File No. 0-2517, and incorporated herein by reference).

4.6

Registration Rights Agreement, effective February 22, 2005, between Toreador Resources Corporation and Roger A. Anderson (previously filed as Exhibit 4.3 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on February 24, 2005, File No. 0-2517, and incorporated herein by reference).

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4.7

Registration Rights Agreement, effective November 1, 2002, among Toreador Resources Corporation and persons party thereto (previously filed as Exhibit 4.5 to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2002, File No. 0-2517, and incorporated herein by reference).

4.8

Registration Rights Agreement, dated July 26, 2003, between Toreador Resources Corporation and James R. Anderson (previously filed as Exhibit 4.7 to Toreador Resources Corporation Quarterly Report on Form 10-Q for the quarter ended June 30, 2003, File No. 0-2517, and incorporated herein by reference).

4.9

Registration Rights Agreement, dated August 13, 2003, between Toreador Resources Corporation and Karen Anderson (previously filed as Exhibit 4.8 to Toreador Resources Corporation Quarterly Report on Form 10-Q for the quarter ended September 30, 2003, File No. 0-2517, and incorporated herein by reference).

4.10

Registration Rights Agreement, dated October 20, 2003, between Toreador Resources Corporation and William I. Lee and Wilco Properties, Inc. (previously filed as Exhibit 4.9 to Toreador Resources Corporation Quarterly Report on Form 10-Q for the quarter ended September 30, 2003, File No. 0-2517, and incorporated herein by reference).

4.11

Registration Rights Agreement, dated December 15, 2003, between Toreador Resources Corporation and James R. Anderson (previously filed as Exhibit 4.9 to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2003, File No. 0-2517, and incorporated herein by reference).

4.12

Registration Rights Agreement, dated December 15, 2003, between Toreador Resources Corporation and Roger A. Anderson (previously filed as Exhibit 4.10 to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2003, File No. 0-2517, and incorporated herein by reference).

4.13

Registration Rights Agreement, dated December 22, 2003, between Toreador Resources Corporation and Wilco Properties Inc (previously filed as Exhibit 4.11 to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2003, File No. 0-2517, and incorporated herein by reference).

4.14

Registration Rights Agreement, dated July 20, 2004, between Toreador Resources Corporation and the Investors party thereto (previously filed as Exhibit 4.1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on July 23, 2004, File No. 0-2517, and incorporated herein by reference).

4.15

Registration Rights Agreement, dated July 22, 2004, between Toreador Resources Corporation and the Investors party thereto (previously filed as Exhibit 4.9 to Toreador Resources Corporation Registration Statement on Form S-3 filed with the Securities and Exchange Commission on August 20, 2004, File No. 0-2517, and incorporated herein by reference).

4.16

Warrant, dated July 22, 2004, issued by Toreador Resources Corporation to RP&C International (Securities), Inc. (previously filed as Exhibit 4.12 to Toreador Resources Corporation Registration Statement on Form S-3 filed with the Securities and Exchange Commission on August 20, 2004, File No. 0-2517, and incorporated herein by reference).

10.1+

Employment letter agreement between Madison Oil Company and Michael J. FitzGerald dated September 10, 2001 (previously filed as Exhibit 10.1 to Toreador Resources Corporation Quarterly Report on Form 10-Q for the quarter ended March 31, 2002, File No. 0-2517, and incorporated herein by reference).

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10.2*+

Toreador Royalty Corporation 1990 Stock Option Plan

10.3*+

Amendment to Toreador Royalty Corporation 1990 Stock Option Plan, effective as of May 15, 1997.

10.4*+

Toreador Royalty Corporation Amended and Restated 1990 Stock Option Plan, effective as of September 24, 1998.

10.5+

Amendment Number One to Toreador Resources Corporation Amended and Restated 1990 Stock Option Plan (previously filed as Exhibit 10.1 to Toreador Resources Corporation Quarterly Report on Form 10-Q for the quarter ended June 30, 2002, File No. 0-2517, and incorporated herein by reference).

10.6+

Amendment Number Two to Toreador Resources Corporation Amended and Restated 1990 Stock Option Plan (previously filed as Exhibit 10.4 to Toreador Resources Corporation Quarterly Report on Form 10-Q for the quarter ended June 30, 2002, File No. 0-2517, and incorporated herein by reference).

10.7*+

Toreador Royalty Corporation 1994 Non-Employee Director Stock Option Plan, as amended.

10.8+

Toreador Resources Corporation Amended and Restated 1994 Non-employee Director Stock Option Plan (previously filed as Exhibit 10.2 to Toreador Resources Corporation Quarterly Report on Form 10-Q for the quarter ended June 30, 2002, File No. 0-2517, and incorporated herein by reference).

10.9+

Toreador Resources Corporation 2002 Stock Option Plan (previously filed as Exhibit 10.16 to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2001, File No. 0-2517, and incorporated herein by reference).

10.10+

Amendment Number One to the Toreador Resources Corporation 2002 Stock Option Plan (previously filed as Exhibit 10.5 to Toreador Resources Corporation Quarterly Report on Form 10-Q for the quarter ended June 30, 2002, File No. 0-2517, and incorporated herein by reference).

10.11*+

Form of Indemnification Agreement, dated as of April 25, 1995, between Toreador Royalty Corporation and each of the members of our Board of Directors.

10.12

Contract for the Supply of Crude Oil from the Parisian Basin, effective January 1, 1997, between Elf Antwar France and Midland Madison Petroleum Company (n/k/a Madison Energy France) (previously filed as Exhibit 10.14 to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2001, File No. 0-2517, and incorporated herein by reference).

10.13

Second Amended and Restated Convertible Debenture, dated March 31, 2004, between Madison Oil Company and PHD Partners L.P. (previously filed as Exhibit 10.2 to Toreador Resources Corporation Quarterly Report on Form 10-Q for the year ended March 31, 2004, File No. 0-2517, and incorporated herein by reference).

10.14

Subordinated Revolving Credit Agreement, dated as of October 3, 2001, between Madison Oil Company and Toreador Resources Corporation (previously filed as Exhibit 2.2 to Toreador Resources Corporation Registration Statement on Form S-4, No. 333-72314, filed on October 26, 2001, and incorporated herein by reference).

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10.15

Subordinated Revolving Credit Note, dated as of October 3, 2001, between Toreador Resources Corporation and Madison Oil Company (previously filed as Exhibit 2.3 to Toreador Resources Corporation Registration Statement on Form S-4, No. 333-72314, filed on October 26, 2001, and incorporated herein by reference).

10.16

Securities Purchase Agreement, effective November 1, 2002, among Toreador Resources Corporation and persons party thereto (previously filed as Exhibit 10.24 to Toreador Resources Corporation Current Report on Form 10-K for the year ended December 31, 2002, File No. 0-2517, and incorporated herein by reference).

10.17

Securities Purchase Agreement, dated October 20, 2003, between Toreador Resources Corporation and William I. Lee and Wilco Properties, Inc. (previously filed as Exhibit 10.5 to Toreador Resources Corporation Quarterly Report on Form 10-Q for the quarter ended September 30, 2003, File No. 0-2517, and incorporated herein by reference).

10.18

Securities Purchase Agreement, dated December 15, 2003, between Toreador Resources Corporation and James R. Anderson (previously filed as Exhibit 10.20 to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2003, File No. 0-2517, and incorporated herein by reference).

10.19

Securities Purchase Agreement, dated December 15, 2003, between Toreador Resources Corporation and Roger A. Anderson (previously filed as Exhibit 10.21 to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2003, File No. 0-2517, and incorporated herein by reference).

10.20

Securities Purchase Agreement, dated December 22, 2003, between Toreador Resources Corporation and Wilco Properties, Inc. (previously filed as Exhibit 10.22 to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2003, File No. 0-2517, and incorporated herein by reference).

10.21

Master Qualified Escrow Agreement by and among Toreador Resources Corporation, Bank of Texas and Petroleum Strategies, Inc., dated January 9, 2004 (previously filed as Exhibit 10.1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on January 28, 2004, File No. 0-2517, and incorporated herein by reference).

10.22

Letter Agreement, dated August 11, 2004, by and between Toreador Resources Corporation and David M. Brewer (previously filed as Exhibit 10.6 to Toreador Resources Corporation Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, File No. 0-2517, and incorporated herein by reference).

10.23

Reserve Base Revolving Facility Agreement, dated December 23, 2004, by and among Toreador Resources Corporation, Madison Energy France, Madison Oil France, Madison Oil Company Europe and Natexis Banques Populaires and the other Lenders party thereto (previously filed as Exhibit 10.1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on December 29, 2004, File No. 0-2517, and incorporated herein by reference).

10.24

Credit Agreement, dated December 30, 2004, by and among Toreador Resources Corporation, Toreador Acquisition Corporation, Toreador Exploration and Production, Inc. and Texas Capital Bank, N.A. (previously filed as Exhibit 10.1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on January 3, 2005, File No. 0-2517, and incorporated herein by reference).

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10.25

Guaranty, dated December 30, 2004, executed by Toreador Resources Corporation in favor of Texas Capital Bank, N.A. (previously filed as Exhibit 10.2 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on January 3, 2005, File No. 0-2517, and incorporated herein by reference).

10.26

Securities Purchase Agreement, dated July 26, 2003, between Toreador Resources Corporation and James R. Anderson (previously filed as Exhibit 10.8 to Toreador Resources Corporation Quarterly Report on Form 10-Q for the quarter ended June 30, 2003, File No. 0-2517, and incorporated herein by reference).

10.27

Securities Purchase Agreement, dated August 13, 2003, between Toreador Resources Corporation and Karen Anderson (previously filed as Exhibit 10.4 to Toreador Resources Corporation Quarterly Report on Form 10-Q for the quarter ended September 30, 2003, File No. 0-2517, and incorporated herein by reference).

10.28

7.85% Convertible Subordinated Note due June 30, 2009, dated July 22, 2004, executed by Toreador Resources Corporation (previously filed as Exhibit 10.2 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on July 23, 2004, File No. 0-2517, and incorporated herein by reference).

10.29

Purchase Agreement, dated July 20, 2004, by and among Toreador Resources Corporation and the Investors party thereto (previously filed as Exhibit 10.1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on July 23, 2004, File No. 0-2517, and incorporated herein by reference).

10.30

Summary Sheet: Executive Officer Annual Base Salaries (previously filed as Exhibit 10.1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on March 29, 2005, File No. 0-2517, and incorporated herein by reference).

10.31

Summary Sheet: Short-Term Incentive Compensation Plan (previously filed as Exhibit 10.2 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on March 29, 2005, File No. 0-2517, and incorporated herein by reference).

10.32

Summary Sheet: Director Compensation (previously filed as Exhibit 10.3 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on March 29, 2005, File No. 0-2517, and incorporated herein by reference).

16.1

Letter on Change in Certifying Accountant from Ernst and Young LLP, dated September 26, 2003 (previously filed as Exhibit 16.1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on September 26, 2003, File No. 0-2517, and incorporated herein by reference).

16.2

Letter on Change in Certifying Accountant from Ernst and Young LLP, dated October 8, 2003 (previously filed as Exhibit 16.1 to Amendment No. 1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on October 8, 2003, File No. 0-2517, and incorporated herein by reference).

21.1*

Subsidiaries of Toreador Resources Corporation.

23.1*

Consent of Ernst & Young LLP.

23.2*

Consent of Hein & Associates LLP.

23.3*

Consent of LaRoche Petroleum Consultants, Ltd.

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24.1*

Power of Attorney (See Signatures in Part IV).

31.1*

Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*

Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1*

Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

_______________

*	Filed herewith
+	Management contract or compensatory plan

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

TOREADOR RESOURCES CORPORATION

Date: March 31, 2005

By:	/s/ G. Thomas Graves III

G. Thomas Graves III, President and Chief Executive Officer

Table of Contents

KNOW ALL MEN BY THESE PRESENTS, that each of the undersigned officers and directors of Toreador Resources Corporation hereby constitutes and appoints G. Thomas Graves III and Douglas W. Weir, or either of them (with full power to each of them to act alone), his true and lawful attorneys-in-fact and agents, with full power of substitution, for him and on his behalf and in his name, place and stead, in any and all capacities, to sign, execute and file any and all amendments (including post-effective amendments) to this Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys, and each of them, full power and authority to do so and perform each and every act and thing requisite and necessary to be done in and about the premises in order to effectuate the same as full to all intents and purposes as he himself might or could do if personally present, thereby ratifying and confirming all that said attorneys-in-fact and agents, or either of them, or their or his substitute or substitutes, may lawfully do or cause to be done.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates as indicated therein.

SIGNATURE	CAPACITY IN WHICH SIGNED	DATE

/s/ G. Thomas Graves III G. Thomas Graves III	President, Chief Executive Officer and Director	March 31, 2005

/s/ David M. Brewer David M. Brewer	Director	March 31, 2005

/s/ Herbert L. Brewer Herbert L. Brewer	Director	March 31, 2005

/s/ Peter L. Falb Peter L. Falb	Director	March 31, 2005

/s/ Thomas P. Kellogg Thomas P. Kellogg	Director	March 31, 2005

/s/ William I. Lee William I. Lee	Director	March 31, 2005

/s/ H.R. Sanders, Jr. H.R. Sanders, Jr.	Director	March 31, 2005

/s/ John Mark McLaughlin John Mark Mclaughlin	Chairman and Director	March 31, 2005

/s/ Douglas W. Weir Douglas W. Weir	Senior Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)	March 31, 2005

EXHIBIT

NUMBER DESCRIPTION

1.1	– Underwriting Agreement, dated February 10, 2005, between Toreador Resources Corporation and Morgan Keegan & Co., Inc. (previously filed as Exhibit 1.1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on February 11, 2005, File No. 0-2517, and incorporated herein by reference).
2.1*	– Certificate of Ownership and Merger, effective June 5, 2000, merging Toreador Resources Corporation into Toreador Royalty Corporation.
2.2	– Agreement and Plan of Merger, dated as of October 3, 2001, between Toreador Resources Corporation and Madison Oil Company (previously filed as Exhibit 2.1 to Toreador Resources Corporation Registration Statement on Form S-4, No. 333-72314, filed on October 26, 2001, and incorporated herein by reference).
2.3	– Agreement for Purchase and Sale, dated December 17, 2003, by and among Toreador Resources Corporation and Tormin, Inc., as Sellers, and Black Stone Acquisitions Partners I, L.P., as Buyer (previously filed as Exhibit 2.1 to Toreador Resources Corporation Current Report on Form 8-K filed on January 15, 2004, File No. 0-2517, and incorporated herein by reference).
3.1	– Restated Certificate of Incorporation of Toreador Resources Corporation (previously filed as Exhibit 3.1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on March 29, 2005, File No. 0-2517, and incorporated herein by reference).

3.2	– Third Amended and Restated Bylaws of Toreador Resources Corporation (previously filed as Exhibit 3.2 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on March 29, 2005, File No. 0-2517, and incorporated herein by reference).
4.1*	– Settlement Agreement, dated June 25, 1998, among the Gralee Persons, the Dane Falb Persons and Toreador Royalty Corporation.
4.2	– Warrant, dated July 22, 2004, issued by Toreador Resources Corporation to Nigel Lovett (previously filed as Exhibit 4.14 to Toreador Resources Corporation Registration Statement on Form S-3 filed with the Securities and Exchange Commission on August 20, 2004, File No. 0-2517, and incorporated herein by reference).

4.3	– Warrant, dated July 22, 2004, issued by Toreador Resources Corporation to Rich Brand (previously filed as Exhibit 4.13 to Toreador Resources Corporation Registration Statement on Form S-3 filed with the Securities and Exchange Commission on August 20, 2004, File No. 0-2517, and incorporated herein by reference).
4.4	– Registration Rights Agreement, effective February 22, 2005, between Toreador Resources Corporation and James R. Anderson (previously filed as Exhibit 4.1 to Toreador Resources Corporation Current Report on Form

8-K filed with the Securities and Exchange Commission on February 24, 2005, File No. 0-2517, and incorporated herein by reference).

4.5	– Registration Rights Agreement, effective February 22, 2005, between Toreador Resources Corporation and Karen Anderson (previously filed as Exhibit 4.2 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on February 24, 2005, File No. 0-2517, and incorporated herein by reference).
4.6	– Registration Rights Agreement, effective February 22, 2005, between Toreador Resources Corporation and Roger A. Anderson (previously filed as Exhibit 4.3 to Toreador Resources Corporation Current Report on Form

8-K filed with the Securities and Exchange Commission on February 24, 2005, File No. 0-2517, and ncorporated herein by reference).

EXHIBIT

NUMBER DESCRIPTION

4.7	– Registration Rights Agreement, effective November 1, 2002, among Toreador Resources Corporation and persons party thereto (previously filed as Exhibit 4.5 to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2002, File No. 0-2517, and incorporated herein by reference).
4.8	– Registration Rights Agreement, dated July 26, 2003, between Toreador Resources Corporation and James R. Anderson (previously filed as Exhibit 4.7 to Toreador Resources Corporation Quarterly Report on Form 10-Q for the quarter ended June 30, 2003, File No. 0-2517, and incorporated herein by reference).
4.9	– Registration Rights Agreement, dated August 13, 2003, between Toreador Resources Corporation and Karen Anderson (previously filed as Exhibit 4.8 to Toreador Resources Corporation Quarterly Report on Form 10-Q for the quarter ended September 30, 2003, File No. 0-2517, and incorporated herein by reference).
4.10	– Registration Rights Agreement, dated October 20, 2003, between Toreador Resources Corporation and William I. Lee and Wilco Properties, Inc. (previously filed as Exhibit 4.9 to Toreador Resources Corporation Quarterly Report on Form 10-Q for the quarter ended September 30, 2003, File No. 0-2517, and incorporated herein by reference).
4.11	– Registration Rights Agreement, dated December 15, 2003, between Toreador Resources Corporation and James R. Anderson (previously filed as Exhibit 4.9 to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2003, File No. 0-2517, and incorporated herein by reference).
4.12	– Registration Rights Agreement, dated December 15, 2003, between Toreador Resources Corporation and Roger A. Anderson (previously filed as Exhibit 4.10 to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2003, File No. 0-2517, and incorporated herein by reference).
4.13	– Registration Rights Agreement, dated December 22, 2003, between Toreador Resources Corporation and Wilco Properties Inc (previously filed as Exhibit 4.11 to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2003, File No. 0-2517, and incorporated herein by reference).

4.14	– Registration Rights Agreement, dated July 20, 2004, between Toreador Resources Corporation and the Investors party thereto (previously filed as Exhibit 4.1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on July 23, 2004, File No. 0-2517, and incorporated herein by reference).
4.15	– Registration Rights Agreement, dated July 22, 2004, between Toreador Resources Corporation and the Investors party thereto (previously filed as Exhibit 4.9 to Toreador Resources Corporation Registration Statement on Form S-3 filed with the Securities and Exchange Commission on August 20, 2004, File No. 0-2517, and incorporated herein by reference).
4.16	– Warrant, dated July 22, 2004, issued by Toreador Resources Corporation to RP&C International (Securities), Inc. (previously filed as Exhibit 4.12 to Toreador Resources Corporation Registration Statement on Form S-3 filed with the Securities and Exchange Commission on August 20, 2004, File No. 0-2517, and incorporated herein by reference).
10.1+	– Employment letter agreement between Madison Oil Company and Michael J. FitzGerald dated September 10, 2001 (previously filed as Exhibit 10.1 to Toreador Resources Corporation Quarterly Report on Form 10-Q for the quarter ended March 31, 2002, File No. 0-2517, and incorporated herein by reference).
10.2*+	–Toreador Royalty Corporation 1990 Stock Option Plan.

EXHIBIT

NUMBER DESCRIPTION

10.3*+	– Amendment to Toreador Royalty Corporation 1990 Stock Option Plan, effective as of May 15, 1997.
10.4*+	– Toreador Royalty Corporation Amended and Restated 1990 Stock Option Plan, effective as of September 24, 1998.
10.5+	– Amendment Number One to Toreador Resources Corporation Amended and Restated 1990 Stock Option Plan (previously filed as Exhibit 10.1 to Toreador Resources Corporation Quarterly Report on Form 10-Q for the quarter ended June 30, 2002, File No. 0-2517, and incorporated herein by reference).
10.6+	– Amendment Number Two to Toreador Resources Corporation Amended and Restated 1990 Stock Option Plan (previously filed as Exhibit 10.4 to Toreador Resources Corporation Quarterly Report on Form 10-Q for the quarter ended June 30, 2002, File No. 0-2517, and incorporated herein by reference).
10.7*+	– Toreador Royalty Corporation 1994 Non-Employee Director Stock Option Plan.
10.8+	– Toreador Resources Corporation Amended and Restated 1994 Non-employee Director Stock Option Plan (previously filed as Exhibit 10.2 to Toreador Resources Corporation Quarterly Report on Form 10-Q for the quarter ended June 30, 2002, File No. 0-2517, and incorporated herein by reference).
10.9+	– Toreador Resources Corporation 2002 Stock Option Plan (previously filed as Exhibit 10.16 to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2001, File No. 0-2517, and incorporated herein by reference).
10.10+	– Amendment Number One to the Toreador Resources Corporation 2002 Stock Option Plan (previously filed as Exhibit 10.5 to Toreador Resources Corporation Quarterly Report on Form 10-Q for the quarter ended June 30, 2002, File No. 0-2517, and incorporated herein by reference).
10.11*+	– Form of Indemnification Agreement, dated as of April 25, 1995, between Toreador Royalty Corporation and each of the members of our Board of Directors.
10.12	– Contract for the Supply of Crude Oil from the Parisian Basin, effective January 1, 1997, between Elf Antwar France and Midland Madison Petroleum Company (n/k/a Madison Energy France) (previously filed as Exhibit 10.14 to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2001, File No. 0-2517, and incorporated herein by reference).
10.13	– Second Amended and Restated Convertible Debenture, dated March 31, 2004, between Madison Oil Company and PHD Partners LP (previously filed as Exhibit 10.2 to Toreador Resources Corporation Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, File No. 0-2517, and incorporated herein by reference).
10.14	–Subordinated Revolving Credit Agreement, dated as of October 3, 2001, between Madison Oil Company and Toreador Resources Corporation (previously filed as Exhibit 2.2 to Toreador Resources Corporation Registration Statement on Form S-4, No. 333-72314, filed on October 26, 2001, and incorporated herein by reference).
10.15	–Subordinated Revolving Credit Note, dated as of October 3, 2001, between Toreador Resources Corporation and Madison Oil Company (previously filed as Exhibit 2.3 to Toreador Resources Corporation Registration Statement on Form S-4, No. 333-72314, filed on October 26, 2001, and incorporated herein by reference).
10.16	–Securities Purchase Agreement, effective November 1, 2002, among Toreador Resources Corporation and persons party thereto (previously filed as Exhibit 10.24 to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2002, File No. 0-2517, and incorporated herein by reference).

EXHIBIT

NUMBER DESCRIPTION

10.17	– Securities Purchase Agreement, dated October 20, 2003, between Toreador Resources Corporation and William I. Lee and Wilco Properties, Inc. (previously filed as Exhibit 10.5 to Toreador Resources Corporation Quarterly Report on Form 10-Q for the quarter ended September 30, 2003, File No. 0-2517, and incorporated herein by reference).
10.18	– Securities Purchase Agreement, dated December 15, 2003, between Toreador Resources Corporation and James R. Anderson (previously filed as Exhibit 10.20 to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2003, File No. 0-2517, and incorporated herein by reference).
10.19	– Securities Purchase Agreement, dated December 15, 2003, between Toreador Resources Corporation and Roger A. Anderson (previously filed as Exhibit 10.21 to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2003, File No. 0-2517, and incorporated herein by reference).
10.20	– Securities Purchase Agreement, dated December 22, 2003, between Toreador Resources Corporation and Wilco Properties, Inc. (previously filed as Exhibit 10.22 to Toreador Resources Corporation Annual Report on Form

10-K for the year ended December 31, 2003, File No. 0-2517, and incorporated herein by reference).

10.21	– Master Qualified Escrow Agreement by and among Toreador Resources Corporation, Bank of Texas and Petroleum Strategies, Inc., dated January 9, 2004 (previously filed as Exhibit 10.1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on January 28, 2004, File No. 0-2517, and incorporated herein by reference).
10.22	– Letter Agreement, dated August 11, 2004, by and between Toreador Resources Corporation and David M. Brewer (previously filed as Exhibit 10.6 to Toreador Resources Corporation Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, File No. 0-2517, and incorporated herein by reference).
10.23	– Reserve Base Revolving Facility Agreement, dated December 23, 2004, by and among Toreador Resources Corporation, Madison Energy France, Madison Oil France, Madison Oil Company Europe and Natexis Banques Populaires and the other Lenders party thereto (previously filed as Exhibit 10.1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on December 29, 2004, File No. 0-2517, and incorporated herein by reference).
10.24	– Credit Agreement, dated December 30, 2004, by and among Toreador Resources Corporation, Toreador Acquisition Corporation, Toreador Exploration and Production, Inc.and Texas Capital Bank, N.A. (previously filed as Exhibit 10.1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on January 3, 2005, File No. 0-2517, and incorporated herein by reference).
10.25	– Guaranty, dated December 30, 2004, executed by Toreador Resources Corporation in favor of Texas Capital Bank, N.A. (previously filed as Exhibit 10.2 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on January 3, 2005, File No. 0-2517, and incorporated herein by reference).
10.26	– Securities Purchase Agreement, dated July 26, 2003, between Toreador Resources Corporation and James R. Anderson (previously filed as Exhibit 10.8 to Toreador Resources Corporation Quarterly Report on Form 10-Q for the quarter ended June 30, 2003, File No. 0-2517, and incorporated herein by reference).
10.27	– Securities Purchase Agreement, dated August 13, 2003, between Toreador Resources Corporation and Karen Anderson (previously filed as Exhibit 10.4 to Toreador Resources Corporation Quarterly Report on Form 10-Q for the quarter ended September 30, 2003, File No. 0-2517, and incorporated herein by reference).

EXHIBIT

NUMBER DESCRIPTION

10.28	– 7.85% Convertible Subordinated Note due June 30, 2009, dated July 22, 2004, executed by Toreador Resources Corporation (previously filed as Exhibit 10.2 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on July 23, 2004, File No. 0-2517, and incorporated herein by reference).
10.29	– Purchase Agreement, dated July 20, 2004, by and among Toreador Resources Corporation and the Investors party thereto (previously filed as Exhibit 10.1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on July 23, 2004, File No. 0-2517, and incorporated herein by reference).
10.30	– Summary Sheet: Executive Officer Base Annual Salaries (previously filed as Exhibit 10.1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on March 29, 2005, File No. 0-2517, and incorporated herein by reference).
10.31	– Summary Sheet: Short-Term Incentive Compensation Plan (previously filed as Exhibit 10.2 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on March 29, 2005, File No. 0-2517, and incorporated herein by reference).
10.32	– Summary Sheet: Director Compensation (previously filed as Exhibit 10.3 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on March 29, 2005, File No. 0-2517, and incorporated herein by reference).
16.1	– Letter on Change in Certifying Accountant from Ernst and Young LLP, dated September 26, 2003 (previously filed as Exhibit 16.1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on September 26, 2003, File No. 0-2517, and incorporated herein by reference).
16.2	– Letter on Change in Certifying Accountant from Ernst and Young LLP, dated October 8, 2003 (previously filed as Exhibit 16.1 to Amendment No. 1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on October 8, 2003, File No. 0-2517, and incorporated herein by reference).
21.1*	– Subsidiaries of Toreador Resources Corporation.
23.1*	– Consent of Ernst & Young LLP.
23.2*	– Consent of Hein & Associates LLP.
23.3*	– Consent of LaRoche Petroleum Consultants, Ltd.
24.1*	– Power of Attorney (See Signatures in Part IV).
31.1*	– Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	– Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	– Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

_______________

*	Filed herewith
+	Management contract or compensatory plan

TOREADOR RESOURCES CORPORATION

ITEM 8

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

		Page
Reports of Independent Registered Public Accounting Firms		F-2

Financial Statements

Consolidated Balance Sheets as of December 31, 2004 and 2003		F-4

Consolidated Statements of Operations for each of the three years in the period ended
December 31, 2004		F-5

Consolidated Statements of Changes in Stockholders' Equity for each of the three years in the
period ended December 31, 2004		F-6

Consolidated Statements of Cash Flows for each of the three years in the period ended
December 31, 2004		F-7

Notes to Consolidated Financial Statements		F-9

F-1

TOREADOR RESOURCES CORPORATION

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

Toreador Resources Corporation

We have audited the accompanying consolidated balance sheets of Toreador Resources Corporation and subsidiaries (the “Company”) as of December 31, 2004 and 2003, and the related consolidated statements of operations, changes in stockholders’ equity and cash flows for each of the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. The Company has determined that it is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes assessing the accounting principles used and significant estimates made by management as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2004 and 2003, and the results of its operations and its cash flows for the years then ended in conformity with United States generally accepted accounting principles.

Hein & Associates LLP

Dallas, Texas

March 8, 2005

F-2

TOREADOR RESOURCES CORPORATION

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders of Toreador Resources Corporation:

We have audited the accompanying consolidated statements of operations, stockholders' equity and cash flows of Toreador Resources Corporation for the year ended December 31, 2002. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated results of Toreador Resources Corporation operations and their cash flows for the year ended December 31, 2002, in conformity with U.S. generally accepted accounting principles.

Ernst & Young LLP

Dallas, Texas

April 11, 2003

F-3

TOREADOR RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS

	December 31,
	2004	2003
ASSETS	(in thousands, except per share data)
Current assets:
Cash and cash equivalents	$ 4,977	$ 2,819
Accounts and notes receivable	3,230	4,053
Royalty properties held for sale	—	13,157
Other	1,187	2,863
Total current assets	9,394	22,892

Oil and natural gas properties, net, using the
successful efforts method of accounting	79,667	64,459

Investments in unconsolidated entities	1,467	529
Goodwill	2,487	3,293
Other assets	1,659	369
Total assets	$ 94,674	$ 91,542
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$ 6,634	$ 6,881
Unrealized losses on commodity derivatives	—	1,159
Current portion of long-term debt	37	28,816
Income taxes payable	1,633	757
Total current liabilities	8,304	37,613

Long-term accrued liabilities	1,136	958
Long-term asset retirement obligation	2,331	1,698
Deferred tax liability	10,660	11,791
Convertible subordinated notes	7,500	—
Convertible debenture	1,485	2,160
Total liabilities	31,416	54,220

Commitments and contingencies (See Note 12)	—	—

Stockholders' equity:
Preferred stock, Series A & A-1, $1.00 par value, 4,000,000
shares authorized; liquidation preference of $3,850,000 and $8,000,000; 154,000 and 320,000 shares issued	154	320
Common stock, $0.15625 par value, 30,000,000
shares authorized; 11,724,146 and 10,058,544 shares issued	1,832	1,572
Capital in excess of par value	37,523	33,562
Retained earnings	24,323	18
Accumulated other comprehensive income	1,960	4,384
	65,792	39,856
Treasury stock at cost:
721,027 shares	(2,534)	(2,534)
Total stockholders' equity	63,258	37,322
Total liabilities and stockholder's equity	$ 94,674	$ 91,542

See accompanying notes to the consolidated financial statements.

F-4

TOREADOR RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year ended December 31,
	2004	2003	2002
	(in thousands, except per share data)
Revenues:
Oil and natural gas sales	$ 22,336	$ 17,845	$ 17,456
Loss on commodity derivatives	(1,322)	(1,017)	(2,150)
Lease bonuses and rentals	14	18	69
Total revenues	21,028	16,846	15,375

Costs and expenses:
Lease operating	6,873	6,651	6,071
Exploration and acquisition	3,402	2,411	2,234
Depreciation, depletion and amortization	3,538	3,246	3,797
Impairment of oil and natural gas properties	—	171	525
Reduction in force	172	511	—
General and administrative	5,474	2,983	5,270
Total costs and expenses	19,459	15,973	17,897

Operating income (loss)	1,569	873	(2,522)

Other income (expense)
Equity in earnings (loss) of unconsolidated investments	(18)	22	(1,186)
Gain (loss) on sale of properties and other assets	(336)	80	(2,143)
Foreign currency exchange gain	5,044	979	437
Turkish currency remeasurement	(1,140)	—	—
Other income (expense)	396	173	(621)
Interest expense	(1,611)	(1,193)	(1,692)
Total other income (expense)	2,335	61	(5,205)

Income (loss) from continuing operations before income taxes	3,904	934	(7,727)
Benefit from income taxes	(3,576)	(266)	(2,061)
Income (loss) from continuing operations, net of income taxes	7,480	1,200	(5,666)
Income (loss) from discontinued operations, net of income taxes (See Note 14)	17,539	1,182	(441)
Income (loss)	25,019	2,382	(6,107)
Dividends on preferred shares	714	500	374
Net income (loss) applicable to common shares	$ 24,305	$ 1,882	$ (6,481)

Basic income (loss) per share from:
Continuing operations	$ 0.71	$ 0.07	$ (0.65)
Discontinued operations	1.83	0.13	(0.04)
	$ 2.54	$ 0.20	$ (0.69)

Diluted income (loss) per share from:
Continuing operations	$ 0.60	$ 0.07	$ (0.65)
Discontinued operations	1.37	0.13	(0.04)
	$ 1.97	$ 0.20	$ (0.69)

Weighted average shares outstanding
Basic	9,571	9,338	9,343
Diluted	12,817	9,347	9,343

See accompanying notes to the consolidated financial statements.

F-5

TOREADOR RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

	Preferred Stock	Common Stock	Capital in Excess of Par Value	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Treasury Stock	Total Stockholders' Equity
	(in thousands)
Balance at December 31, 2001	160	1,572	29,593	4,617	(33)	(2,354)	33,555
Issuance of preferred stock	37	-	854	-	-	-	891
Payment of preferred dividends	-	-	-	(374)	-	-	(374)
Purchase of treasury stock	-	-	-	-	-	(180)	(180)
Other	-	-	63	-	-	-	63
Comprehensive loss:
Net loss	-	-	-	(6,107)	-	-	(6,107)
Foreign currency translation adjustment	-	-	-	-	2,228	-	2,228
Change in fair value of available-
for-sale securities	-	-	-	-	(62)	-	(62)
Losses reclassified to net loss	-	-	-	-	7	-	7
Total comprehensive loss							(3,934)
Balance at December 31, 2002	197	1,572	30,510	(1,864)	2,140	(2,534)	30,021
Issuance of preferred stock	123	-	2,952	-	-	-	3,075
Payment of preferred dividends	-	-	-	(500)	-	-	(500)
Issuance of warrants	-	-	100	-	-	-	100
Comprehensive income:
Net income	-	-	-	2,382	-	-	2,382
Foreign currency translation adjustment	-	-	-	-	2,206	-	2,206
Change in fair value of available-
for-sale securities	-	-	-	-	8	-	8
Losses reclassified to net income	-	-	-	-	30	-	30
Total comprehensive income							4,626
Balance at December 31, 2003	$ 320	$ 1,572	$ 33,562	$ 18	$ 4,384	$ (2,534)	$ 37,322
Issuance of preferred stock	-	-	-	-	-	-	-
Payment of preferred dividends	-	-	-	(714)	-	-	(714)
Conversion of preferred stock	(166)	162	4	-	-	-	-
Conversion of convertible debenture	-	16	659	-	-	-	675
Issuance of common stock	-	82	2,286	-	-	-	2,368
Tax benefit from exercise of stock options	-	-	1,012	-	-	-	1,012
Comprehensive income:
Net income	-	-	-	25,019	-	-	25,019
Realized gain on foreign currency transactions	-	-	-	-	(5,044)	-	(5,044)
Foreign currency translation adjustment	-	-	-	-	1,197		1,197
Change in tax deferred liabilities	-	-	-	-	1,423	-	1,423
Total comprehensive income							22,595
Balance at December 31, 2004	$ 154	$ 1,832	$ 37,523	$ 24,323	$ 1,960	$ (2,534)	$ 63,258

See accompanying notes to the consolidated financial statements.

F-6

TOREADOR RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year ended December 31,
	2004	2003	2002
	(in thousands)
Cash flows from operating activities:
Net income (loss)	$ 25,019	$ 2,382	$ (6,107)
Adjustments to reconcile net income (loss) to
net cash provided by operating activities:
Depreciation, depletion and amortization	3,538	3,925	5,034
Amortization of deferred debt issuance cost	384	—	—
Remeasurement of Turkish currency	1,140	—	—
Impairment of oil and natural gas properties	—	171	529
Loss (gain) on sale of properties	(28,406)	(120)	2,129
Dry holes and abandonments	583	1,271	1,084
Realized gain of foreign currency transactions	(5,044)	—	—
Unrealized gains (losses) on commodity derivatives	(1,159)	123	2,029
Equity in (earnings) loss of unconsolidated investments	18	(22)	1,186
Other operating activities	—	39	65
Cash flows (used by) from operating activities before changes
in working capital	(3,927)	7,769	5,949
Decrease (increase) in operating assets:
Accounts and notes receivable	960	(21)	(266)
Income taxes receivable	—	512	(512)
Other current assets	1,260	(1,321)	(13)
Other assets	(431)	75	124
Increase (decrease) in operating liabilities:
Accounts payable and accrued liabilities	(354)	(318)	2,615
Income taxes payable	1,379	757	(279)
Deferred tax liabilities	1,181	(574)	(1,319)
Other	26	—	63
Net cash provided by (used in) operating activities	94	6,879	6,362

Cash flows from investing activities:
Expenditures for oil and natural gas properties	(16,743)	(3,713)	(6,178)
Proceeds from the sale of oil and natural gas properties	42,125	424	4,628
Purchase of marketable securities	—	—	(51)
Proceeds from sale of marketable securities	—	48	253
Distributions from unconsolidated entities	255	—	—
Investment in and advances to unconsolidated entities, net	(1,211)	—	(320)
Net cash provided by (used in) investing activities	24,426	(3,241)	(1,668)

See accompanying notes to the consolidated financial statements.

F-7

TOREADOR RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)

Cash flows from financing activities:
Payment for debt issuance costs	(1,239)	—	(175)
Borrowings under revolving credit arrangements	136	3,384	4,686
Repayments under revolving credit arrangements	(28,915)	(7,928)	(10,825)
Proceeds from issuance of stock, net	2,368	3,075	891
Purchase of treasury stock	—	—	(180)
Issuance of warrants	—	100	—
Proceeds from issuance of notes payable	7,500	—	—
Payment of preferred dividends	(714)	(500)	(270)
Net cash used in financing activities	(20,864)	(1,869)	(5,873)
Net increase (decrease) in cash and cash equivalents	3,656	1,769	(1,179)
Effects of foreign currency on cash and cash equivalents	(1,498)	74	—
Cash and cash equivalents, beginning of period	2,819	976	2,155
Cash and cash equivalents, end of period	$ 4,977	$ 2,819	$ 976

Supplemental disclosure of cash flow information:
Cash paid during the period for interest	$ 1,736	$ 1,541	$ 2,089
Cash paid during the period for income taxes	5,250	629	(128)

See accompanying notes to the consolidated financial statements.

F-8

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.	BASIS OF PRESENTATION AND DESCRIPTION OF BUSINESS

Toreador Resources Corporation (“Toreador,” “we,” “us,” “our,” or the “Company”) is an independent energy company engaged in foreign and domestic oil and natural gas exploration, development, production, leasing and acquisition activities. The accompanying consolidated financial statements are presented in U.S. dollars and in accordance with accounting principles generally accepted in the United States.

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. From the approximate $45.0 million cash consideration that we received, we discharged our outstanding credit facilities. The financial results for those assets sold are classified as discontinued operations in the accompanying financial statements. Please see further discussion in Note 14 to the consolidating financial statements.

BASIS OF PRESENTATION

The accompanying consolidated financial statements and related footnotes are presented in U.S. dollars and in accordance with accounting principles generally accepted in the United States. Certain prior-year amounts have been reclassified to conform to the 2004 presentation, with no effect on net income.

2.	SIGNIFICANT ACCOUNTING POLICIES

USE OF ESTIMATES

BASIS OF CONSOLIDATION

CASH AND CASH EQUIVALENTS

CONCENTRATION OF CREDIT RISK AND ACCOUNTS RECEIVABLE

FINANCIAL INSTRUMENTS

F-9

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2.	SIGNIFICANT ACCOUNTING POLICIES (continued)

DERIVATIVE FINANCIAL INSTRUMENTS

INVENTORIES

OIL AND NATURAL GAS PROPERTIES

We follow the successful efforts method of accounting for oil and natural gas exploration and development expenditures. Under this method, costs of successful exploratory wells and all development wells are capitalized. Costs to drill exploratory wells that do not find proved reserves are expensed. In the absence of a determination as to whether the reserves that have been found can be classified as proved, we carry the costs of drilling such exploratory wells as an asset for no more than one year following completion of drilling. If, after that year has passed, a determination that proved reserves have been found cannot be made, we will assume that the well is impaired, and charge the cost to expense. Significant costs associated with the acquisition of oil and natural gas properties are capitalized. Upon sale or abandonment of units of property or the disposition of miscellaneous equipment, the cost is removed from the asset account, net of the accumulated depreciation or depletion and the gain or loss is credited to or charged against operations.

Maintenance and repairs are charged to expense; betterments of property are capitalized and depreciated as described below.

DEPRECIATION, DEPLETION AND AMORTIZATION

We provide depreciation, depletion and amortization of our investment in producing oil and natural gas properties on the units-of-production method, based upon independent reserve engineers' estimates of recoverable oil and natural gas reserves from the property. Depreciation expense for fixed assets is generally calculated on a straight-line basis based upon estimated useful lives of three to seven years.

IMPAIRMENT OF ASSETS

F-10

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2.	SIGNIFICANT ACCOUNTING POLICIES (continued)

ASSET RETIREMENT OBLIGATIONS

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 $1,716,000 and $1,690,000, 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.

The following tables describe on a pro forma basis our asset retirement liability as if Statement 143 had been adopted on January 1, 2002:

	2004	2003
	(in thousands)
Asset retirement obligation January 1	$ 1,789	$ 1,690
Asset retirement accretion expense	127	105
Plus: foreign currency exchange gain	436	—
Plus property additions	39	—
Less: plugging cost	(37)	(5)
Less: property sold	(23)	(1)
Asset retirement obligation at December 31	$ 2,331	$ 1,789

Asset retirement obligations are recorded as current or non-current liabilities based on our estimate of plugging and abandonment dates of the related wells. The following table describes, on a pro forma basis, the impact of adopting Statement 143 if such adoption occured on January 1, 2002.

	Year Ended December 31,2002
	(in thousands, except per share data)
Net loss, reported	$ (6,481)
Less: retirement obligation accretion expense	116
Plus: depreciation on salvage value	—
Net loss pro forma	$ (6,597)

Loss per share:
As reported
Basic	$ (0.69)
Diluted	$ (0.69)

Pro forma
Basic	$ (0.70)
Diluted	$ (0.70)

GOODWILL

F-11

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2.	SIGNIFICANT ACCOUNTING POLICIES (continued)

As the result of adopting Statement 142, we will review annually the value of goodwill recorded as a result of the acquisition Madison Oil Company, or more frequently if impairment indicators arise. We recognized no goodwill impairment during 2004 or 2003. Goodwill was reduced by $929,000 in 2004 for a corresponding reduction in deferred tax liabilities which resulted from the recognition of prior Madison Oil Company net operating losses that were reserved at the date of acquisition. At the end of 2003, we made a commitment to be fully reinvested in our international subsidiaries. Accordingly, we reversed the deferred tax liability originally booked as a result of the acquisition of Madison Oil Company against goodwill in the amount of $2.4 million. This amount represented the tax effect of the difference between the financial reporting and tax basis of the net assets of Madison Oil Company at the time of the acquisition. The balance of goodwill at December 31, 2004 is approximately $2.5 million.

REVENUE RECOGNITION

STOCK-BASED COMPENSATION

	2004	2003	2002
	(in thousands, except per share data)
Net income (loss), applicable to common shares, as reported	$ 24,305	$ 1,882	$ (6,481)
Basic earnings (loss) per share reported	2.54	0.20	(0.69)
Diluted earnings (loss) per share reported	1.97	0.20	(0.69)
Stock-based compensation costs under the intrinsic value method included in net income (loss) reported, net of related tax	—	—	—
Pro-forma stock-based compensation costs under the fair value method, net of related tax	1,049	249	432
Pro-forma income (loss) applicable to common shares, as under the fair-value method	23,256	1,633	(6,913)
Pro-forma basic earnings (loss) per share under the fair value method	2.43	0.17	(0.74)
Pro-forma diluted earnings (loss) per share under the fair value method	1.89	0.17	(0.74)

The fair value of each option granted is estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions:

	2004	2003	2002
Dividend yield per share	—	—	—
Volatility	43 – 54%	42%	34%
Risk-free interest rate	3.3 – 4.6%	2.8%	2.8%
Expected lives	3 years	10 years	10 years

F-12

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2.	SIGNIFICANT ACCOUNTING POLICIES (continued)

FOREIGN CURRENCY TRANSLATION

currency of the primary economic environment in which we operate.

The functional currency in Turkey has been the Turkish lira historically. Turkey is deemed to be a highly inflationary economy, which is why the functional currency has now been changed to the U.S. dollar. The activity level and capital spent in Turkey was immaterial to the overall operations until the last quarter of 2004. Accordingly, we did not convert the functional currency to the U.S. dollar until the fourth quarter of 2004 even though Turkey’s economy has been highly inflationary for several years.

INCOME TAXES

We are subject to income taxes in the United States, France, and Turkey. The current provision for taxes on income consists primarily of income taxes based on the tax laws and rates of the countries in which operations were conducted during the periods presented. We compute our provision for deferred income taxes using the liability method. Under the liability method, deferred income tax assets and liabilities are determined based on differences between financial reporting and income tax basis of assets and liabilities and are measured using the enacted tax rates and laws. The measurement of deferred tax assets is adjusted by a valuation allowance, if necessary, to recognize the future tax benefits to the extent, based on available evidence it is more likely than not deferred tax assets will be realized. Goodwill was reduced by $929,000 in 2004 for a corresponding reduction in deferred tax liabilities which resulted from the recognition of prior Madison Oil Company net operating losses. At the end of 2003, we made a commitment to be fully reinvested in our international subsidiaries. Accordingly, in 2003 we reversed the deferred tax liability originally booked as a result of the acquisition of Madison Oil Company against goodwill in the amount of $2.4 million. This amount represented the tax effect of the difference between the financial reporting and tax basis of the net assets of Madison Oil Company at the time of the acquisition. The balance of the deferred tax liability at December 31, 2004 is $10.7 million.

REDUCTION IN FORCE

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. On February 2, 2004, we committed to the termination of two landmen as a result of the Royalty Sale in January 2004. The following table provides a reconciliation of the liability:

Exit Cost or Disposal Activity		Amount
		(in thousands)
Employee severance liability June 17, 2003		$ 511
Cost incurred		—
Adjustments		—
Less: Payroll payments		(201)
Severance liability December 31, 2003		$ 310

Cost incurred		172
Adjustments		—
Less: Payroll payments		(482)
Severance liability December 31, 2004		$ —

F-13

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2. SIGNIFICANT ACCOUNTING POLICIES (continued)

NEW ACCOUNTING PRONOUNCEMENTS

F-14

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

3.	EARNINGS PER SHARE

In accordance with the provisions of FASB Statement of Financial Accounting Standards No. 128, Earnings per Share (“Statement 128”), basic earnings per share is computed on the basis of the weighted-average number of common shares outstanding during the periods. Diluted earnings per share is computed based upon the weighted-average number of common shares plus the assumed issuance of common shares for all potentially dilutive securities.

	Year ended December 31,
	2004		2003		2002
	(in thousands, except per share data)
Basic earnings (loss) per share:
Numerator
Net income (loss) from continuing operations, net of income tax	$ 7,480		$ 1,200		$ (5,666)
Income from discontinued operations, net of income tax	17,539		1,182		(441)
Net income (loss)	25,019		2,382		(6,107)
Less: dividends on preferred shares	714		500		374
Net income (loss) applicable to common shares	$ 24,305		$ 1,882		$ (6,481)

Denominator
Common shares outstanding	9,571		9,338		9,343

Basic earnings (loss) per share from:
Continuing operations	$ 0.71		$ 0.07		$ (0.65)
Discontinued operations	1.83		0.13		(0.04)
Net income (loss) per share applicable to
common shares	$ 2.54		$ 0.20		$ (0.69)

Diluted earnings (loss) per share:
Numerator
Net income (loss) from continuing operations, net of income tax	$ 7,480		$ 1,200		$ (5,666)
Income from discontinued operations, net of income tax	17,539		1,182		(441)
Net income (loss)	25,019		2,382		(6,107)
Plus: interest on convertible debt	265		N/A	(1)	N/A	(1)
Less: dividends on preferred shares	N/A	(2)	500		374
Net income (loss) applicable to common shares	$ 25,284		$ 1,882		$ (6,481)

Denominator
Common shares outstanding	9,571		9,338		9,343
Common stock options and warrants	523		9		N/A	(1)
Conversion of preferred shares	1,997		N/A	(1)	N/A	(1)
Conversion of notes payable	410		N/A	(1)	N/A	(1)
Conversion of debentures	316		N/A	(1)	N/A	(1)
Diluted shares outstanding	12,817		9,347		9,343

Diluted earnings (loss) per share from:
Continuing operations	$ 0.60		$ 0.07		$ (0.65)
Discontinued operations	1.37		0.13		(0.04)
Net income (loss) per share applicable to
common shares	$ 1.97		$ 0.20		$ (0.69)

__________

(1) Conversion of these securities would be antidilutive therefore there are no dilutive shares.
(2) Conversion of preferred shares would be dilutive therefore we assume no dividends would have been paid.

F-15

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

4.	ACCOUNTS AND NOTES RECEIVABLE

Accounts and notes receivable consist of the following:

	December 31,
	2004	2003
	(in thousands)
Accrued oil and natural gas sales receivable	$ 2,566	$ 3,978
Taxes receivable	611	—
Trade receivables	26	46
Other receivables	27	29
	$ 3,230	$ 4,053

5.	PROPERTIES AND EQUIPMENT

Oil and Natural Gas Properties consist of the following:

	December 31,
	2004	2003
	(in thousands)
Licenses and concessions	$ 3,505	$ 3,407
Non-producing leaseholds	11,556	3,675
Producing leaseholds and intangible drilling costs	74,847	64,372
Lease and well equipment	1,926	2,052
Furniture, fixtures and office equipment	1,449	1,093
	93,283	74,599
Accumulated depreciation, depletion and amortization	(13,616)	(10,140)
	79,667	64,459
Royalty properties held available for sale, net (See Note 14)	—	13,157
Total oil and natural gas properties	$ 79,667	$ 77,616

During 2004, we sold various properties and equipment for $42.1 million (net of closing costs) resulting in a gain of $28.4 million before tax. During 2003, we sold various properties and equipment for $424,000 (net of closing costs) resulting in a gain of $120,000 before tax.

6.	INVESTMENTS IN UNCONSOLIDATED SUBSIDIARIES

In February 2004, we acquired 45% of ePsolutions. Based in Austin, Texas, ePsolutions is a software and energy services company driven by a professional team with over 40 years of combined experience in the electric industry and deregulated energy markets. ePsolutions is the developer of emPower system, a powerful CIS, EDI and Billing solution for energy companies within deregulated energy markets.

F-16

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

6. INVESTMENTS IN UNCONSOLIDATED SUBSIDIARIES, continued

At December 31, 2004 our investment in ePsolutions amounted to $799,000. We recorded equity in the loss of ePsolutions of $312,000 in 2004.

In July 2000, we acquired 35% of EnergyNet.com, Inc. (“EnergyNet”), an Internet based oil and natural gas property auction company. At December 31, 2004 and 2003, our investment in EnergyNet amounted to $554,000 and $406,000, respectively. We recorded equity in the gain/(loss) of EnergyNet of $279,000 in 2004, $6,500 in 2003, and ($64,000) in 2002.

In April 2000, we acquired a 50% interest in Capstone Royalty, LLC (“Capstone”), a joint venture formed to acquire mineral interests at county auctions in west Texas and develop those interests. Our investment in Capstone amounted to $112,000 and $123,000 at December 31, 2004 and 2003, respectively. We recorded equity in the earnings of Capstone amounting to $15,000 in 2004, $15,000 in 2003 and zero in 2002. We received a distribution of $25,000 from Capstone in both 2003 and 2002.

As part of our acquisition of Madison Oil Company (see Note 10), we acquired a 25% interest in Trinidad Exploration and Development, Ltd. (“TED”). TED is involved in oil exploration in the Southwest Cedros Peninsula of Trinidad. Our investment in TED amounted to $2,652,000 at December 31, 2002 before any impairment. In addition to our investment in TED, we also had a note receivable of $500,000 from TED. During 2002, we were unsuccessful in our arbitration case against TED’s majority shareholder, and our interest was diluted from 25% to 16.33%. Due to the reduction in our ownership, we recorded a charge of approximately $920,000 in 2003 as equity in earnings of unconsolidated investments, reflecting the diminished valuation of the ultimate amount estimated to be recovered from our investment. Additionally, we evaluated our ability to collect our receivable from TED and reserved 50% of the receivable, or $250,000. During 2003, our interest in TED was converted from an equity interest to a 1% overriding royalty interest. Accordingly, our investment in TED, the note receivable and the related contra receivable were reclassified as oil and natural gas properties in 2003. Our investment in TED amounted to zero at December 31, 2004.

F-17

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

7.	LONG-TERM DEBT

Long-term debt consists of the following:

	December 31,
	2004	2003
	(in thousands)
Revolving line of credit with Bank of Texas, N.A.	$ —	$ 17,016
Revolving line of credit with Barclays Bank, PLC	—	11,800
Revolving line of credit with Texas Capital Bank, N.A.	37	—
	37	28,816
Less: current portion	(37)	(28,816)
	$ —	$ —

REVOLVING LINE OF CREDIT WITH NATEXIS BANQUES POPULAIRES

On December 23, 2004, we entered into a five-year $15.0 million reserve-based borrowing facility with a French lender to finance the development of our existing French fields, acquisitions of new fields, general working capital and our corporate purposes. The facility bears interest at a floating rate of 2.25-2.75% above LIBOR (2.40% at December 31, 2004) depending on the principal outstanding. The facility is collateralized by certain of our French assets, including contracts relating to our rights and interests in our French fields, our direct and indirect equity interests in certain of our subsidiaries and payments received from the sale of our French production. Toreador and certain of its U.S. and French subsidiaries have each guaranteed the obligations under the facility. This facility will require monthly interest payments until December 23, 2009, at which times all unpaid principal and interest are due. The $15.0 million facility contains various affirmative and negative covenants. These covenants, among other things, limit additional indebtedness, the sale of assets, change of control and management, limitations on the distribution of stock dividends and require us to meet certain financial requirements. Specifically, we must maintain an interest cost ratio of not less than 4.00 to 1.00, an indebtedness ratio of not less than 1.00 to 1.00, asset life cover ratio of not less than 1.25 to 1.00, a loan life cover ratio equal to or greater than 1.15 to 1.00 and a debt service coverage ratio equal to or greater than 1.10 to 1.00. As of December 31, 2004, we were in compliance with all covenants.

REVOLVING LINE OF CREDIT WITH TEXAS CAPITAL BANK, N.A.

On December 30, 2004, we entered into a five-year $25.0 million reserve-based borrowing facility with Texas Capital Bank, N.A. in order to finance the development and acquisition of oil and natural-gas interests both domestically and internationally and for working capital purposes. The facility bears interest at a rate of prime less 0.5% (5.25% at December 31, 2004) and is collateralized by our domestic working interests. The borrowers under this facility are two of our domestic subsidiaries, and Toreador has guaranteed the obligations. At December 31, 2004, we had approximately $3.3 million available for borrowings. The $25.0 million facility requires monthly interest payments until January 1, 2019 at which time all unpaid principal and interest are due. The $25.0 million facility contains various affirmative and negative covenants. These covenants, among other things, limit additional indebtedness, the sale of assets, change of control and management and require us to meet certain financial requirements. Specifically, we must maintain a current ratio of 1.25 to 1.00 (exclusive of amounts due under revolving credit arrangements) and an interest coverage ratio of not less than 3.00 to 1.00. As of December 31, 2004, we were in compliance with all covenants.

REVOLVING LINE OF CREDIT WITH BANK OF TEXAS, N.A.

On February 16, 2001, we entered into a $75.0 million credit agreement with Bank of Texas, National Association (the “Texas Facility”) that was to mature on February 16, 2006. The majority of our United States oil and natural gas properties were pledged as collateral under the Texas Facility. At the end of 2003, the Texas Facility had borrowings outstanding of approximately $17.0 million. We discharged the Texas Facility in January 2004 with a portion of the proceeds from the Royalty Sale.

F-18

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

7. LONG TERM DEBT, continued

REVOLVING LINE OF CREDIT WITH BARCLAYS BANK, PLC

As part of our acquisition of Madison Oil Company (see Note 10), we assumed a revolving credit facility with Barclays Bank, Plc (the “Barclays Facility”) that was to mature on December 31, 2005 and was secured by the production from our French properties. We had $11.8 million outstanding at December 31, 2003 under the Barclays Facility. 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 totaling $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.

When we repaid the Barclays Facility in January 2004, we realized a foreign currency translation gain of approximately $5.0 million (3.9 million Eurodollars) which was previously included in accumulated other comprehensive income (loss) in stockholders' equity at December 31, 2003. The gain is reflected in other income (expense) as foreign currency exchange gain in the statement of operations for the year ended December 31, 2004.

CONVERTIBLE SUBORDINATED NOTES

CONVERTIBLE DEBENTURE

As part of our acquisition of Madison Oil Company, we assumed and amended a convertible debenture payable to PHD Partners LP. The general partner of PHD Partners LP is a corporation wholly owned by David M. Brewer, a director and significant stockholder of Toreador. The amended and restated Debenture used to bear interest at 10% per annum and was due on March 31, 2006. At the holders' option, the amended and restated debenture could be converted into common stock at a ratio of $6.75 per share. We originally had 319,962 common shares reserved for issuance related to the conversion of the amended and restated debenture. As of March 31, 2004, the amended and restated debenture was amended and restated to bear interest at 6% per annum, eliminate Madison Oil Company's right under certain circumstances to force a conversion of the principal into shares of Toreador common stock and eliminate Madison Oil Company's ability to repay principal prior to maturity. At the holder's option, the second amended and restated convertible debenture can be converted into Toreador common stock at a conversion price of $6.75 per share. In December 2004, PHD Partners LP converted $675,000 of the second amended and restated debenture into 100,000 shares of our common stock. As a result, at December 31, 2004, the outstanding principal amount of the second amended and restated convertible debenture was approximately $1.5 million. We have 219,962 shares of common stock reserved for issuance related to the conversion of the second amended and restated convertible debenture. Interest payments made to PHD Partners LP were $352,416, $108,437 and $149,992 in 2004, 2003 and 2002, respectively.

8. CAPITAL

Toreador had 160,000 shares of nonvoting Series A Convertible Preferred Stock outstanding at December 31, 2003 and 2002. In accordance with Section 6 of the terms and conditions of the Preferred Stock, Toreador gave notice that it would redeem all outstanding shares of its Preferred Stock at 2:00 p.m. Central time on December 31, 2004 at the price of $26.81 per share which amount included all accrued and unpaid dividends from the last dividend payment date through the Redemption Date. Dividends on the Preferred Stock ceased to accrue and all rights of holders of the Preferred Stock terminated as of the Redemption Date. All Series A Convertible Preferred Stock was converted into common shares at a price of $4.00 per common share (conversion would amount to 1,000,000 Toreador common shares). The Series A Convertible Preferred Stock accrued dividends at an annual rate of $2.25 per share payable quarterly in cash.

We issued 37,000 shares of Series A-1 Convertible Preferred Stock in November 2002 and 123,000 shares of Series A-1 Convertible Preferred Stock during 2003. 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 (conversion would amount to 1,000,000 Toreador common shares). The Series A-1 Convertible Preferred Stock accrues dividends at an annual rate of $2.25 per share payable quarterly in cash. At any time on or after November 1, 2007, we may elect to redeem for cash any or all shares of Series A-1 Convertible Preferred Stock. 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. On December 31, 2004, 6,000 shares of Series A-1 Convertible Preferred Stock were converted into 37,500 shares of our common stock pursuant to the terms of the Series A-1 Convertible Preferred Stock.

As part of our acquisition of Madison Oil Company we issued warrants for the purchase of 111,509 shares of our common stock. Currently there are 4,130 warrants at $8.05 that expire in July 2010, 11,800 warrants at $5.37 that expire in August 2010 and 7,080 warrants at $4.30 that expire in November 2010. The 88,499 remaining warrants expired in 2002.

F-19

9. INCOME TAXES

The Company's provision (benefit) for income taxes consists of the following (see Note 14 for discontinued operations):

	Year ended December 31,
	2004			2003			2002
	(in thousands)
Current:
U.S. Federal		$ 7,122			$ 95			$ (425	)
U.S. State		1,010			108			48
Foreign		(611	)		689			1,912
Deferred:
U.S. Federal		(243	)		(10	)		(1,871	)
U.S. State		—			(1	)		(170	)
Foreign		—			(689	)		(1,729	)

		$ 7,278			$ 192			$ (2,235	)


The tax provision (benefit) has been allocated between continuing operations and discontinued operations as follows:

Provision (benefit) allocated to:

Continuing Operations		$ (3,576	)		$ (266	)		(2,061	)
Discontinued Operations		10,854			458			(174	)

		$ 7,278			$ 192			$ (2,235	)

The primary reasons for the difference between tax expense at the statutory federal income tax rate and our provision for income taxes were:

	Year ended December 31,
	2004			2003			2002
	(in thousands)
Statutory tax at 34%	$	10,838		$	875		$	(2,836	)
Rate differential on foreign operations		169			50			8
Use of NOL carryforwards		(4,486	)		(523	)		–
State income tax, net		1,010			71			(81	)
Release of tax reserve		(554	)		–			–
Adjustments to valuation allowance		503			450			553
Other		(202	)		(731	)		121

	$	7,278		$	192		$	(2,235	)

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities as of December 31, 2004 and 2003 were as follows:

	December 31,
	2004		2003
	(in thousands)
Deferred tax assets:
Net operating loss carryforward - United States	$ 1,454		$ 1,888
Net operating loss carryforward - Foreign	1,511		2,954
Unrealized loss on derivative financial instruments	—		429
Other	100		88

Gross deferred tax assets	3,065		5,359
Valuation allowance	(522	)	(3,787	)

Net deferred tax assets	2,543		1,572

Deferred tax liabilities:
Leasehold costs - United States	(574	)	(541	)
Leasehold costs - Foreign	(11,161	)	(9,875	)
Intangible drilling and development costs	(457	)	(396	)
Lease and well equipment	(381	)	(115	)
Investments in foreign subsidiaries	—		126
Unrealized foreign currency translation gains	(518	)	(1,941	)
Other	(112	)	(621	)

Gross deferred tax liabilities	(13,203	)	(13,363	)

Net deferred tax liabilities	$ (10,660	)	$ (11,791	)

F-20

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

9. INCOME TAXES (continued)

Our acquisition of Madison Oil Company resulted in a net deferred tax liability of $10.2 million due to the difference between the book and tax basis of the assets acquired and the benefit of net operating loss carryforwards. At December 31, 2004, Toreador had the following carryforwards available to reduce future taxable income (in thousands):

Jurisdiction	Expiry	Amount

United States	2010 – 2021	$ 3,930
France	Unlimited	2,683
Turkey	2005 – 2008	1,689

The utilization of our United States net operating loss carryforwards is limited to $391,000 per year pursuant to a prior change of control. Accordingly, we established a valuation allowance of $789,000, with a tax effect of $292,000, for our estimate of the net operating loss carryforwards that will expire before we can utilize them. Realization of net operating loss carryforwards depends on our ability to generate taxable income within the carryforward period.

The utilization of our Turkish net operating loss carryforwards depends on our ability to generate taxable income during the carryforward period. We have recorded a valuation allowance of approximately $689,000, with a tax effect of $230,000, for our estimates of the net operating loss carryforwards that will expire before we can utilize them.

10.	BENEFIT PLANS

We have a 401(k) retirement savings plan. Employees are eligible to defer portions of their salaries, limited by Internal Revenue Service regulations. Employer matches are discretionary, and are determined annually by the board of directors. Such discretionary matches amounted to $75,000 in 2004, zero in 2003, and $34,000 in 2002.

F-21

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

11.	STOCK COMPENSATION PLANS

We have granted stock options to key employees and directors of Toreador as described below.

In May 1990, we adopted the 1990 Stock Option Plan (“1990 Plan”). The 1990 Plan, as amended and restated, provides for grants of up to 1,000,000 stock options to employees and directors at exercise prices greater than or equal to market on the date of the grant.

In December 2001, we adopted the 2002 Stock Option Plan (“2002 Plan”). The 2002 Plan provides for grants of up to 500,000 stock options to employees and directors at exercise prices greater than or equal to market on the date of the grant.

In September 1994, we adopted the 1994 Non-employee Director Stock Option Plan (“1994 Plan”). The 1994 Plan, as amended and restated, provides for grants of up to 500,000 stock options to non-employee directors of Toreador at exercise prices greater than or equal to market on the date of the grant.

The Board of Directors grants options under our plans periodically. Generally, option grants are exercisable in equal increments over a three-year period, and have a maximum term of 10 years. However, the 2004 stock grants were immediately vested.

A summary of stock option transactions is as follows:

	2004		2003		2002
	SHARES	WEIGHTED AVERAGE EXERCISE PRICE	SHARES	WEIGHTED AVERAGE EXERCISE PRICE	SHARES	WEIGHTED AVERAGE EXERCISE PRICE
Outstanding at
January 1	1,515,940	$4.43	1,434,106	$4.57	1,143,440	$4.56
Granted	442,700	5.78	120,000	3.10	361,000	4.63
Exercised	(528,102)	4.34	—	—	—	—
Forfeited	(83,848)	4.78	(38,166)	5.54	(70,334)	5.13
Outstanding at
December 31	1,346,690	$4.91	1,515,940	$4.43	1,434,106	$4.57
Exercisable at
December 31	1,186,646	$5.06	1,102,172	$4.48	936,410	$4.42

For stock options granted the following table represents the weighted-average exercise prices and the weighted-average fair value based upon whether or not the exercise price of the option was greater than, less than or equal to the market price of the stock on the grant date:

			WEIGHTED-AVERAGE	WEIGHTED-AVERAGE
YEAR	OPTION TYPE	SHARES	EXERCISE PRICE	FAIR VALUE
2004	Exercise price greater than market price	352,700	$ 5.50	$ 1.60
	Exercise price equal to market price	90,000	6.89	2.50

2003	Exercise price equal to market price	120,000	3.10	1.12

2002	Exercise price greater than market price	206,000	4.96	1.51
	Exercise price equal to market price	145,000	4.08	1.93

F-22

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

11.	STOCK COMPENSATION PLANS (continued)

The following table summarizes information about the fixed price stock options outstanding at December 31, 2004:

Exercise Price	Number Outstanding	Number Exercisable	Weighted Average Remaining Contractual Life in Years
$ 2.270	14,750	14,750	0.07
2.500	10,000	10,000	0.03
2.750	45,000	45,000	0.12
3.000	15,000	15,000	0.06
3.100	120,000	40,000	0.72
3.120	10,940	10,940	0.05
3.875	15,000	15,000	0.06
4.120	120,000	80,000	0.64
4.510	20,000	13,334	0.10
4.960	70,000	70,000	0.49
5.000	404,933	373,222	1.38
5.500	365,067	365,067	2.16
5.750	31,000	31,000	0.13
5.950	85,000	83,333	0.40
13.660	20,000	20,000	0.14
$ 4.911	1,346,690	1,186,646	6.55

At December 31, 2004, there were 125,208 remaining shares available for grant under the plans collectively.

12. COMMITMENTS AND CONTINGENCIES

We lease our office space under non-cancelable operating leases, expiring during 2006 and 2007. We also sublease portions of the leased space to one related party and two unrelated parties under non-cancelable sub-leases that expire on June 30, 2006. The following is a schedule of minimum future rentals under our non-cancelable operating leases, giving effect to the non-cancelable sub-leases, as of December 31, 2004 (in thousands):

2005		$ 399
2006		404
2007		229
2008		—
		1,032
Less: minimum rents from subleases		158
		$ 874

Net rent expense totaled $324,000 in 2004, $356,000 in 2003, and $362,000 in 2002.

F-23

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

12. COMMITMENTS AND CONTINGENCIES (continued)

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 Oil Company. The ruling was subject to automatic appeal that was heard in December 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 final determination. We have also appealed the case to the European Court. We cannot predict the outcome of this matter.

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, which may be awarded with any suit or claim would not have a material adverse effect on our financial position.

13. RELATED PARTY TRANSACTIONS

On June 14, 2004, we issued stock options for 29,500 shares of our common stock to David M. Brewer. Mr. Brewer currently serves as a director for Toreador. The options were in payment to Mr. Brewer for consulting services related to our international activities. The options were granted pursuant to the Toreador Resources Corporation 2002 Stock Option Plan. The exercise price is $5.50 per share. The options expire no later than 10 years from the date of issuance. We recorded a charge to general and administrative costs of $58,000 in 2004.

William I. Lee, a director of the Company, is also Chairman of the Board and majority owner of Wilco Properties, Inc (“Wilco”). We entered into a technical services agreement with Wilco effective February 1, 1999 whereby we provided accounting and geological management services for a monthly fee of $7,250. On June 1, 2002, we terminated the agreement, but continued to provide limited services to Wilco during the transition and charged Wilco a reduced monthly fee through the end of 2002. We recorded reductions to general and administrative expense of $47,250 in 2002 related to this agreement. We had receivables from Wilco related to this arrangement amounting to $11,000 at December 31, 2002. The Company also subleases office space to Wilco pursuant to a sub-lease agreement. We recorded reductions to rent expense totaling $45,000 in 2004, $47,000 in 2003, and $40,000 in 2002 related to the sublease with Wilco. We have an informal agreement with Wilco under which one of the two companies incurs, on behalf of the other, certain miscellaneous expenses that are subsequently reimbursed by the other company. We had amounts receivable related to this arrangement of $2,000, $1,500 and $5,000 at December 31, 2004, 2003 and 2002, respectively.

On November 1, 2002, pursuant to a private placement we issued $925,000 of Series A-1 Convertible Preferred Stock to certain of our directors or entities controlled by certain of our directors. In connection with the securities purchase agreements, Toreador entered into a registration rights agreement effective November 1, 2002, among Toreador and the purchasers which provides for the registration of the common stock issuable upon conversion of the Series A-1 Convertible Preferred Stock. During 2003, pursuant to private placements we issued 41,000 shares of our Series A-1 Convertible Preferred Stock for the total amount of $1,025,000 to William I. Lee and Wilco as follows: (i) in October 2003, 34,000 shares were issued to William I. Lee and Wilco, an entity controlled by Mr. Lee; and (ii) in December 2003, 7,000 shares were issued to Wilco. The Series A-1 Convertible Preferred Stock is governed by a certificate of designation. The Series A-1 Convertible Preferred Stock was sold for a face value of $25.00 per share, and pays an annual cash dividend of $2.25 per share that results in an annual yield of 9.0%. At the option of the holder, the Series A-1 Convertible Preferred Stock may be converted into common shares at a price of $4.00 per common share. The $4.00 conversion price was higher than the market price of our common stock at the time of issuances. The Series A-1 Convertible Preferred Stock is redeemable at our option, in whole or in part, at any time on or after November 1, 2007. The optional redemption price per share is the sum of (1) $25.00 per share of the Series A Convertible Preferred Stock plus (2) any accrued unpaid dividends, and such sum is multiplied by a declining multiplier. The multiplier is 105% until October 31, 2008, 104% until October 31, 2009, 103% until October 31, 2010, 102% until October 31, 2011, 101% until October 31, 2012, and 100% thereafter. In connection with the securities purchase agreements entered into with William I. Lee and Wilco, 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.

In 2002, we acquired Wilco Turkey Ltd (“WTL”) from Wilco. WTL’s primary asset is an interest (ranging from 52.5% to 87.5%) in exploration licenses covering 2.2 million acres in the Thrace Basin and in the central and southeast areas of Turkey. We also acquired from F-Co Holdings Kandamis (“F-Co”) additional interests (ranging from 7.5% to 12.5%) in the same exploration licenses. The purpose of the acquisition was to obtain, explore and possibly develop the acreage covered by the licenses. The acreage in the Thrace Basin is adjacent to or near the acreage we held prior to the acquisition of WTL. In exchange for all of the outstanding common stock of WTL, we have agreed to give Wilco an overriding royalty interest in any successful wells we drill on the acreage covered by the exploration licenses we acquired.

F-24

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

13. RELATED PARTY TRANSACTIONS, continued

We have also agreed to give F-Co, in exchange for its interest in the acreage, an overriding royalty interest in any successful wells we drill on the acreage. As of the acquisition date, there were no outstanding liabilities associated with WTL. We did not convey value to Wilco or F-Co on the acquisition date, or assume any liabilities; therefore, the fair value of the transaction was zero. We have allocated no value to the assets acquired from WTL and F-Co. Wilco is controlled by William I. Lee, a director and stockholder, and F-Co are partially owned by Peter L. Falb, a director and stockholder.

We own a 35% interest in EnergyNet.com, Inc., an Internet based oil and natural gas property auction company. We paid commissions on property sales to EnergyNet totaling zero during 2004 and 2003 and approximately $369,000 during 2002.

F-25

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

14. DISCONTINUED OPERATIONS

On January 14, 2004, pursuant to the terms of an Agreement for Purchase and Sale dated December 17, 2003, Toreador and Tormin, Inc., a wholly owned subsidiary of Toreador, sold their United States mineral and royalty assets to Black Stone Acquisitions Partners I, L.P. The gross consideration was approximately $45.0 million cash. The effective date of the sale was January 1, 2004. The net book value of these assets at December 31, 2003 has been reclassified from oil and natural gas properties to assets held available-for-sale on the balance sheet. Assets held available-for-sale consist of the following:

December 31,
		2003
(in thousands)
Undeveloped mineral and royalty interests		$ 7,269
Producing royalty interests		12,332
Royalty properties held available for sale		19,601
Less accumulated depreciation, depletion, and amortization		(6,444)
Royalty properties held available-for-sale, net		$ 13,157

The results of operations of assets in the United States to be sold as of December 31, 2003 have been presented as discontinued operations in the accompanying consolidated statements of operations. Prior year results have also been reclassified to report the results of operations of the assets to be sold as discontinued operations. Results for these assets reported as discontinued operations were as follows:

	Year ended December 31,
	2004	2003	2002
	(in thousands)
Revenues:
Oil and natural gas sales	$ 139	$ 7,261	$ 5,613
Lease bonuses and rentals	—	341	743
Loss on commodity derivatives	—	(1,304)	(1,894)
Total revenues	139	6,298	4,462
Costs and expenses:
Lease operating	(9)	1,046	609
Depreciation, depletion and amortization	—	679	1,237
Impairment of oil and natural gas properties	—	—	4
Allocated general and administrative	161	2,222	2,452
Interest expense	305	711	775
Total costs and expenses	457	4,658	5,077
Gain on sale of properties	28,711	—	—
Income (loss) before taxes	28,393	1,640	(615)
Income tax provision (benefit)	10,854	458	(174)
Income (loss) from discontinued operations (U.S.)	$ 17,539	$ 1,182	$ (441)

F-26

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

15. INFORMATION ABOUT OIL AND NATURAL GAS PRODUCING ACTIVITIES AND OPERATING SEGMENTS

We have operations in only one industry segment, the oil and natural gas exploration and production industry. We are structured along geographic operating segments or regions. As a result, we have reportable operations in the United States, France and Turkey. Geographic operating segment income tax expenses have been determined based on statutory rates existing in the various tax jurisdictions where we have oil and natural gas producing activities.

The following tables provide the geographic operating segment data required by Statement of Financial Accounting Standards No. 131, Disclosure about Segments of an Enterprise and Related Information. The United States segment data for the years ended December 31, 2004, 2003, and 2002 includes discontinued operations sold in January 2004 through the Royalty Sale (see Note 14).

F-27

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

15. INFORMATION ABOUT OIL AND NATURAL GAS PRODUCING ACTIVITIES AND OPERATING SEGMENTS (continued)

	United States⁽¹⁾		France		Turkey		Total
	(in thousands)
As of and for the year ended December 31, 2004
Revenues:
Oil and natural gas sales	$ 6,024		$ 14,042		$ 2,270		$ 22,336
Loss on commodity derivatives	(1,322	)	–		–		(1,322	)
Lease bonuses and rentals	14		–		–		14

Total revenues	4,716		14,042		2,270		21,028

Costs and expenses:
Lease operating	1,751		4,359		763		6,873
Exploration and acquisition	1,367		141		1,894		3,402
Depreciation, depletion and amortization	1,295		1,577		666		3,538
Reduction in force	172		–		–		172
General and administrative	3,436		1,178		860		5,474

Total costs and expenses	8,021		7,255		4,183		19,459


Operating income (loss)	(3,305	)	6,787		(1,913	)	1,569

Other income (expense)
Equity in earnings of unconsolidated investments	(18	)	–		–		(18	)
Gain (loss) on sale of properties and other assets	(336	)	–		–		(336	)
Foreign currency exchange gain	–		5,044		–		5,044
Other income (expense)	52		343		(1,139	)	(744	)
Interest expense	(569	)	(945	)	(97	)	(1,611	)

Total other income (expense)	(871	)	4,442		(1,236	)	2,335


Income (loss) before income taxes	(4,176	)	11,229		(3,149	)	3,904
Benefit for income taxes	2,965		611		–		3,576

Income (loss) from continuing operations, net of tax	$ (1,211	)	$ 11,840		$ (3,149	)	$ 7,480


Selected assets:
Oil and natural gas properties	$ 19,480		$ 53,630		$ 20,173		$ 93,283
Accumulated depreciation, depletion, and amortization	(7,082	)	(4,632	)	(1,902	)	(13,616	)

Oil and natural gas properties, net	$ 12,398		$ 48,998		$ 18,271		$ 79,667

Investments in unconsolidated entities	$ 1,467		$ –		$ –		$ 1,467

Goodwill	$ –		$ 1,575		$ 912		$ 2,487

Total assets	$ 97,008		$ 43,384		$ 8,194		$ 148,586


Expenditures for additions to long-lived assets:
Property acquisition costs	$ –		$ –		$ –		$ –
Development costs	345		4,403		446		5,194
Exploration costs	488		2,089		8,678		11,255
Other	121		–		173		294

Total expenditures for long lived assets	$ 954		$ 6,492		$ 9,297		$ 16,743

__________

(1) Amounts reflect reclassifications to discontinued operations.

F-28

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

15. INFORMATION ABOUT OIL AND NATURAL GAS PRODUCING ACTIVITIES AND OPERATING SEGMENTS (continued)

	United States⁽¹⁾		France		Turkey		Total
	(in thousands)
As of and for the year ended December 31, 2003 Revenues:
Oil and natural gas sales	$ 5,953		$ 9,633		$ 2,259		$ 17,845
Loss on commodity derivatives	(302	)	(715	)	–		(1,017	)
Lease bonuses and rentals	18		–		–		18

Total revenues	5,669		8,918		2,259		16,846


Costs and expenses:
Lease operating	1,532		4,290		829		6,651
Exploration and acquisition	1,140		–		1,271		2,411
Depreciation, depletion and amortization	1,341		1,358		547		3,246
Impairment of oil and natural gas properties	171		–		–		171
Reduction in force	511		–		–		511
General and administrative	1,334		810		839		2,983

Total costs and expenses	6,029		6,458		3,486		15,973


Operating income (loss)	(360	)	2,460		(1,227	)	873

Other income (expense)
Equity in earnings of unconsolidated investments	22		–		–		22
Gain on sale of properties and other assets	80		–		–		80
Foreign currency exchange gain	979		–		–		979
Other income (expense)	(795	)	1,090		(122	)	173
Interest expense	(703	)	(490	)	–		(1,193	)

Total other income (expense)	(417	)	600		(122	)	61


Income (loss) before income taxes	(777	)	3,060		(1,349	)	934
Benefit for income taxes	266		–		–		266

Income (loss) from continuing operations, net of tax	$ (511	)	$ 3,060		$ (1,349	)	$ 1,200


Selected assets:
Oil and natural gas properties	$ 19,704		$ 42,917		$ 11,978		$ 74,599
Accumulated depreciation, depletion, and amortization	(6,284	)	(2,678	)	(1,178	)	(10,140	)

Oil and natural gas properties, net	$ 13,420		$ 40,239		$ 10,800		$ 64,459

Investments in unconsolidated entities	$ 529		$ –		$ –		$ 529

Goodwill	$ 929		$ 1,452		$ 912		$ 3,293

Total assets	$ 69,085		$ 46,918		$ 13,132		$129,135


Expenditures for additions to long-lived assets:
Property acquisition costs	$ –		$ –		$ –		$ –
Development costs	615		2,127		–		2,742
Exploration costs	–		–		971		971
Other	–		–		–		–

Total expenditures for long lived assets	$ 615		$ 2,127		$ 971		$ 3,713

__________

(1) Amounts reflect reclassifications to discontinued operations.

F-29

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

15. INFORMATION ABOUT OIL AND NATURAL GAS PRODUCING ACTIVITIES AND OPERATING SEGMENTS (continued)

	United States⁽¹⁾		France		Turkey		Total
	(in thousands)
As of and for the year ended December 31, 2002
Revenues:
Oil and natural gas sales	$ 5,893		$ 9,190		$ 2,373		$ 17,456
Loss on commodity derivatives	(332	)	(1,818	)	–		(2,150	)
Lease bonuses and rentals	69		–		–		69

Total revenues	5,630		7,372		2,373		15,375

Costs and expenses:
Lease operating	1,977		3,237		857		6,071
Exploration and acquisition	2,234		–		–		2,234
Depreciation, depletion and amortization	1,942		1,302		553		3,797
Impairment of oil and natural gas properties	525		–		–		525
General and administrative	2,951		1,147		1,172		5,270

Total costs and expenses	9,629		5,686		2,582		17,897


Operating income (loss)	(3,999	)	1,686		(209	)	(2,522	)

Other income (expense)
Equity in loss of unconsolidated investments	(1,186	)	–		–		(1,186	)
Loss on sale of properties and other assets	(2,143	)	–		–		(2,143	)
Foreign currency exchange gain	437		–		–		437
Other expense	(374	)	(247	)	–		(621	)
Interest expense	(612	)	(1,005	)	(75	)	(1,692	)

Total other expense	(3,878	)	(1,252	)	(75	)	(5,205	)


Income (loss) before income taxes	(7,877	)	434		(284	)	(7,727	)
Benefit (provision) for income taxes	2,244		(183	)	–		2,061

Income (loss) from continuing operations, net of tax	$ (5,633	)	$ 251		$ (284	)	$ (5,666	)


Selected assets:
Oil and natural gas properties	$ 17,419		$ 36,568		$ 10,791		$ 64,778
Accumulated depreciation, depletion, and amortization	(5,135	)	(1,302	)	(553	)	(6,990	)

Oil and natural gas properties, net	$ 12,284		$ 35,266		$ 10,238		$ 57,788

Investments in unconsolidated entities	$ 2,239		$ –		$ –		$ 2,239

Goodwill	$ 3,342		$ 1,213		$ 912		$ 5,467

Total assets	$ 69,967		$ 39,702		$ 11,724		$ 121,393


Expenditures for additions to long-lived assets:
Property acquisition costs	$ –		$ –		$ –		$ –
Development costs	291		1,882		–		2,173
Exploration costs	583		–		3,102		3,685
Other	320		–		–		320

Total expenditures for long lived assets	$ 1,194		$ 1,882		$ 3,102		$ 6,178

__________

(1) Amounts reflect reclassifications to discontinued operations.

F-30

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

15. INFORMATION ABOUT OIL AND NATURAL GAS PRODUCING ACTIVITIES AND OPERATING SEGMENTS (continued)

The following table reconciles the total assets for reportable segments to consolidated assets.

	December 31,
	2004	2003
	(in thousands)

Total assets for reportable segments	$ 148,586	$ 129,135
Elimination of intersegment receivables and investments	(53,912)	(37,593)
Total consolidated assets	$ 94,674	$ 91,542

F-31

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

16. SUPPLEMENTAL OIL AND NATURAL GAS RESERVES AND STANDARDIZED MEASURE INFORMATION (UNAUDITED)

We retain an independent engineering firm to provide annual year-end estimates of our future net recoverable oil and natural gas reserves. Estimated proved net recoverable reserves we have shown below include only those quantities that we can expect to be commercially recoverable at prices and costs in effect at the balance sheet dates under existing regulatory practices and with conventional equipment and operating methods. Proved developed reserves represent only those reserves that we may recover through existing wells. Proved undeveloped reserves include those reserves that we may recover from new wells on undrilled acreage or from existing wells on which we must make a relatively major expenditure for recompletion or secondary recovery operations.

Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of oil and natural gas properties. Estimates of fair value should also consider probable reserves, anticipated future oil and natural gas prices, interest rates, changes in development and production costs and risks associated with future production. Because of these and other considerations, any estimate of fair value is necessarily subjective and imprecise.

	United States		France		Turkey		Total
	Oil (MBbl)	Gas (MMcf)	Oil (MBbl)	Gas (MMcf)	Oil (MBbl)	Gas (MMcf)	Oil (MBbl)	Gas (MMcf)
PROVED RESERVES
December 31, 2001	2,006	12,923	8,272	—	936	—	11,214	12,923
Revisions of previous estimates	450	1,531	3,136	—	149	—	3,735	1,531
Extensions, discoveries, and other additions	84	1,300	250	—	1	—	335	1,300
Sale of reserves	(415)	(1,811)	—	—	—	—	(415)	(1,811)
Production	(238)	(1,822)	(415)	—	(114)	—	(767)	(1,822)
December 31, 2002	1,887	12,121	11,243	—	972	—	14,102	12,121
Revisions of previous estimates	133	758	106	—	12	—	251	758
Extensions, discoveries, and other additions	11	365	—	—	—	—	11	365
Sale of reserves	(3)	(401)	—	—	—	—	(3)	(401)
Production	(190)	(1,561)	(374)	—	(92)	—	(656)	(1,561)
December 31, 2003	1,838	11,282	10,975	—	892	—	13,705	11,282
Revisions of previous estimates	114	(574)	956	—	(190)	—	880	(574)
Extensions, discoveries, and other additions	—	143	—	—	—	—	—	143
Sale of reserves	(1,103)	(5,400)	—	—	—	—	(1,103)	(5,400)
Production	(69)	(518)	(395)	—	(75)	—	(539)	(518)
December 31, 2004	780	4,933	11,536	—	627	—	12,943	4,933

PROVED DEVELOPED RESERVES
December 31, 2002	1,749	11,987	7,388	—	766	—	9,903	11,987
December 31, 2003	1,709	11,158	6,571	—	583	—	8,863	11,158
December 31, 2004	775	4,875	7,309	—	360	—	8,444	4,875

F-32

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

16.	SUPPLEMENTAL OIL AND NATURAL GAS RESERVES AND STANDARDIZED MEASURE INFORMATION (UNAUDITED)

(continued)

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND NATURAL GAS RESERVES

We have summarized the standardized measure of discounted future net cash flows related to our proved oil and natural gas reserves. We have based the following summary on a valuation of proved reserves using discounted cash flows based on year-end prices, costs and economic conditions and a 10% discount rate. The additions to proved reserves from purchase of reserves in place and new discoveries and extensions could vary significantly from year to year; additionally, the impact of changes to reflect current prices and costs of proved reserves in prior years could also be significant. Accordingly, you should not view the information presented below as an estimate of the fair value of our oil and natural gas properties, nor should you consider the information indicative of any trends.

	United States	France	Turkey	Total
	(in thousands)
*As of December 31, 2002*
Future cash inflows	$ 109,720	$331,739	$ 28,143	$469,602
Future production costs	25,933	135,706	10,132	171,771
Future development costs	353	14,595	1,470	16,418
Future income tax expense	25,194	58,717	5,417	89,328

Future net cash flows	58,240	122,721	11,124	192,085
10% annual discount for estimated
timing of cash flows	23,622	69,878	3,541	97,041

Standardized measure of discounted future
net cash flows related to proved reserves	$ 34,618	$ 52,843	$ 7,583	$ 95,044

*As of December 31, 2003*
Future cash inflows	$121,802	$303,691	$ 23,412	$448,905
Future production costs	28,173	141,351	8,735	178,259
Future development costs	352	17,443	1,960	19,755
Future income tax expense	29,610	45,819	4,143	79,572

Future net cash flows	63,667	99,078	8,574	171,319
10% annual discount for estimated
timing of cash flows	27,087	56,447	3,056	86,590

Standardized measure of discounted future
net cash flows related to proved reserves	$ 36,580	$ 42,631	$ 5,518	$ 84,729

*As of December 31, 2004*
Future cash inflows	$62,256	$432,828	$ 20,919	$516,003
Future production costs	25,432	182,574	7,861	215,867
Future development costs	164	25,902	1,470	27,536
Future income tax expense	10,385	72,183	1,691	84,259

Future net cash flows	26,275	152,169	9,897	188,341
10% annual discount for estimated
timing of cash flows	12,134	97,838	3,257	113,229

Standardized measure of discounted future
net cash flows related to proved reserves	$ 14,141	$ 54,331	$ 6,640	$ 75,112

The prices of oil and natural gas at December 31, 2004, 2003, and 2002 used in the above table, were $37.55, $27.87 and $29.30 per Bbl of oil, respectively, and $5.99, $5.90 and $4.62 per Mcf of natural gas, respectively.

F-33

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

16.	SUPPLEMENTAL OIL AND NATURAL GAS RESERVES AND STANDARDIZED MEASURE INFORMATION (UNAUDITED)

(continued)

CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH RELATING TO PROVED OIL AND NATURAL GAS RESERVES

The following are the principal sources of change in the standardized measure:

	United States	France	Turkey	Total
	(in thousands)
Balance at December 31, 2001	25,759	20,887	2,928	49,574
Sales of oil and natural gas, net	(8,920)	(5,953)	(1,516)	(16,389)
Net changes in prices and production costs	22,575	33,426	6,733	62,734
Extensions and discoveries	3,770	1,479	26	5,275
Revisions of previous quantity estimates	8,174	20,698	1,746	30,618
Net change in income taxes	(8,422)	(17,752)	(2,327)	(28,501)
Accretion of discount	2,576	2,089	293	4,958
Sales of reserves	(6,441)	-	-	(6,441)
Other	(4,453)	(2,030)	(300)	(6,783)
Balance at December 31, 2002	34,618	52,844	7,583	95,045
Sales of oil and natural gas, net	(10,636)	(5,343)	(1,430)	(17,409)
Net changes in prices and production costs	7,978	(13,108)	(1,718)	(6,848)
Extensions and discoveries	981	-	-	981
Revisions of previous quantity estimates	3,209	839	212	4,260
Net change in income taxes	(2,381)	5,571	1,032	4,222
Accretion of discount	3,462	5,284	758	9,504
Sales of reserves	(61)	-	-	(61)
Other	(590)	(3,456)	(919)	(4,965)
Balance at December 31, 2003	$ 36,580	$ 42,631	$ 5,518	$ 84,729
Sales of oil and natural gas, net	(4,273)	(9,514)	(1,520)	(15,307)
Net changes in prices and production costs	(4,264)	28,408	2,450	26,594
Net change on future development costs	77	(4,962)	119	(4,766)
Extensions and discoveries	309	-	-	309
Revisions of previous quantity estimates	229	8,065	(2,712)	5,582
Preciously estimated development costs incurred	45	4,296	316	4,657
Net change in income taxes	7,922	(17,922)	1,310	(8,690)
Accretion of discount	4,321	6,019	761	11,101
Sales of reserves	(25,020)	-	-	(25,020)
Other	(1,785)	(2,690)	398	(4,077)
Balance at December 31, 2004	$ 14,141	$ 54,331	$ 6,640	$ 75,112

F-34

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Toreador Resources (TRGL) Inactive 10-K2004 FY Annual report

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