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Toreador Resources 10-K 2006
e10vk
Table of Contents

 
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON D.C. 20549
FORM 10-K
     
þ   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended: December 31, 2005
OR
     
o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
COMMISSION FILE NUMBER: 0-02517
Toreador Resources Corporation
(Exact name of Registrant as specified in its charter)
     
Delaware   75-0991164
(State or other jurisdiction of incorporation)   (I.R.S. Employer Identification Number)
     
4809 Cole Avenue, Suite 108    
Dallas, Texas   75205
(Address of principal executive office)   (Zip Code)
Registrant’s telephone number, including area code: (214) 559-3933
Securities registered pursuant to Section 12(b) of the Exchange Act: None.
Securities registered pursuant to Section 12(g) of the Exchange 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 if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ
     Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ
     Indicate by check 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 þ No o
     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 a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (check one) Large accelerated filer o Accelerated filer þ Non-accelerated filer o
     Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Exchange Act). Yes o No þ
     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, 2005 was $217,834,420. (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 24, 2006, was 15,561,314 shares.
DOCUMENTS INCORPORATED BY REFERENCE
     Portions of the registrant’s Proxy Statement for the 2006 Annual Meeting of Stockholders, expected to be filed on or prior to April 7, 2006, are incorporated by reference into Part III of this Form 10-K.
 
 

 


 

TABLE OF CONTENTS
             
        Page
           
 
           
  Business and Properties     2  
 
           
  Risk Factors     20  
 
           
  Unresolved Staff Comments     31  
 
           
  Properties (see Item 1. Business and Properties)     31  
 
           
  Legal Proceedings     31  
 
           
  Submission of Matters to a Vote of Security Holders     32  
 
           
           
 
           
  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities     32  
 
           
  Selected Financial Data     33  
 
           
  Management’s Discussion and Analysis of Financial Condition and Results of Operations     34  
 
           
  Quantitative and Qualitative Disclosures About Market Risk     46  
 
           
  Financial Statements and Supplementary Data     47  
 
           
  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure     47  
 
           
  Controls and Procedures     47  
 
           
  Other Information     50  
 
           
           
 
           
  Directors and Executive Officers of the Registrant     50  
 
           
  Executive Compensation     51  
 
           
  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters     51  
 
           
  Certain Relationships and Related Transactions     51  
 
           
  Principal Accountant Fees and Services     51  
 
           
           
 
           
  Exhibits and Financial Statement Schedules     51  
 
           
        52  
 Warrant No. 30
 Computation of Ratio of Earnings to Fixed Charges
 Subsidiaries
 Consent of Hein & Associates LLP
 Consent of LaRoche Petroleum Consultants, Ltd.
 Certification of Chief Executive Officer Pursuant to Section 302
 Certification of Chief Financial Officer Pursuant to Section 302
 Certification of Chief Accounting Officer Pursuant to Section 302
 Certification of CEO, CFO and Chief Accounting Officer Pursuant to Section 906

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PART I
Items 1 and 2. Business and Properties
     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 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. We also focus on prospects where we do not have to compete directly with major integrated or large independent oil and natural gas producers and where extensive geophysical and geological data is available. Our international operations are all located in European Union or European Union candidate countries that we believe have stable governments, have existing transportation infrastructure, 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 offshore and onshore Turkey, Hungary, Romania and France. We also own various non-operating working interest properties primarily in Texas, Kansas, New Mexico, Louisiana and Oklahoma. At December 31, 2005, we held interests in approximately 4.7 million gross acres and approximately 3.8 million net acres, of which 98% is undeveloped. At December 31, 2005, our estimated net proved reserves were 15 million barrels of oil equivalent (MMBOE).
     Historically, our operations have been concentrated in the Paris Basin in France and in south central onshore Turkey. These two regions accounted for 85% of our total proved reserves as of December 31, 2005 and approximately 78% of our total production for the year ended December 31, 2005.
     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.
Recent Developments
     Public Offering
     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 $32.3 million. The proceeds were used to fund the 2005 capital expenditure program and for general corporate purposes.
     Acquisition
     In June 2005, we acquired 100% of Pogo Hungary Ltd, a wholly owned subsidiary of Pogo Producing Company. The purchase price was approximately $9 million.
     Private Placement
     On September 16, 2005, we sold 806,450 shares of our common stock to certain accredited investors pursuant to a private placement. We have used and will use the net proceeds of approximately $23.6 million for general corporate purposes, including the funding of our capital expenditures requirements in 2005 and 2006.
     Convertible Notes
     On September 27 and September 30, 2005, we sold an aggregate principal amount of $86,250,000 of the 5.00% Convertible Senior Notes due 2025. We have used and will use the net proceeds of approximately $82.2 million for general corporate purposes, including the funding of our capital expenditures requirements in 2005 and 2006.

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     Production Structure Issues
     In 2005 two separate incidents occurred, in offshore Turkey in the Black Sea, which resulted in the loss of two caissons and three wells. Both of these incidents were insured and the Company expects to receive reimbursement, from the insurance company for substantially the entire value of the two caissons and three wells, as the replacement wells are redrilled and the new structures are installed.
Drilling and Production Facility Update
     In January, the Charmottes-111H horizontal well was completed as an oil producer in France. The development well is currently producing 400 barrels of oil per day during daylight hours for five days a week. Once the well is connected to a pipeline, which will take place during the second quarter, it is anticipated that production rates will be held to approximately 500 barrels per day to properly manage the reservoir.
     Also in January, a contract was awarded to Momentum Engineering of Dubai, UAE, for the construction and installation of production platforms for the South Akcakoca Sub-basin natural gas project offshore Turkey in the Black Sea. The contract was for two platforms with an option for another two platforms. Based on drilling success, one of the options for an additional platform was exercised in March.
     In February, the Dogu Ayazli-1 exploration well encountered approximately 60 meters of net pay from 12 zones in the Eocene-age Kusuri formation offshore Turkey in the South Akcakoca Sub-basin. During extended testing the well produced over 9.0 million cubic feet per day of natural gas, and was suspended after testing while waiting for installation of a production platform. Subsequently, the Dogu Ayazli-2 was spudded in early March to test the northwest flank of the structure.
     In March, the Akkaya-2 well confirmed the presence of natural gas on the northern flank of the Akkaya prospect in the South Akcakoca Sub-basin. Logs indicated net pay of approximately 21 meters, which was in line with expectations. The well was scheduled to be tested in mid to late March.
     In Romania, a production facility was constructed in the Fauresti field to allow production from the four wells re-entered in 2005 and suspended as gas producers. It is anticipated that permits to sell the gas produced will be awarded in early April 2006. It is our understanding that when we start selling our gas in Romania, we will be the first non-Romanian exploration and production company to do so.
Strategy
     Our business strategy is to grow our oil and natural gas reserves, production volumes and cash flows through drilling internally generated prospects, primarily in the international arena. We also seek complementary acquisitions of new interests in our core geographic areas of operation.
We seek to:
     Target under-explored basins in international regions.
     Our international operations are all located in European Union or European Union candidate countries that we believe have stable governments, have existing transportation infrastructure, have attractive fiscal policies and are net importers of oil and natural gas. We focus on countries where we can establish large acreage positions that we believe offer multi-year investment opportunities and concentrate on prospects where extensive geophysical and geological data is available. Currently, we have international operations in Turkey, Hungary, Romania and France. We believe our concentrated and extensive acreage positions have allowed us to develop the regional expertise needed to interpret specific geological trends and develop economies of scale.
     Maintain a deep inventory of drilling prospects.
     Our South Akcakoca sub-basin gas project is located on approximately 50,000 acres within our approximately 962,000 acre Western Black Sea permits. It is the only area we have explored within these permits and we believe

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there are significant additional drilling opportunities within and outside of the South Akcakoca sub-basin. Similarly, we believe our Hungarian and Romanian positions offer multi-year drilling opportunities.
     Pursue new permits and selective property acquisitions.
     We target incremental acquisitions in our existing core areas through the pursuit of new permits. Our additional growth initiatives include identifying acquisitions of (i) producing properties that will enable us to increase our production and (ii) reserve and acreage positions on favorable economic terms. Generally, we seek properties and acquisition candidates where we can apply our existing technical knowledge base.
     Manage our risk exposure.
     Because exploration projects have a higher degree of risk than development projects, we generally plan to limit our exploratory expenditures to approximately one-half of the total annual capital expenditure budget per year. We have balanced our exploration and development activities to support our overall goal of growing and maintaining a long-lived reserve base. We also expect to make significant investments in seismic data. By equipping our geologists and geophysicists with state-of-the-art seismic information, we intend to increase the number of higher potential prospects we drill. As deemed appropriate, we may enter into joint ventures in order to reduce our risk exposure in exchange for a portion of our interests.
     Maintain operational flexibility.
     Given the volatility of commodity prices and the risks involved in drilling, we remain flexible and may adjust our drilling program and capital expenditure budget. We may defer capital projects in order to seize attractive acquisition opportunities. If certain areas generate higher-than-anticipated returns, we may accelerate drilling in those areas and decrease capital expenditures elsewhere.
     Leverage experienced management, local expertise and technical knowledge.
     We have assembled a management team with considerable technical expertise and industry experience. The members of our management team average more than 25 years of exploration and development experience in over 40 countries. Additionally, we have an extensive team of technical experts and many of these experts are nationals in the countries in which we operate. We believe this provides us with local expertise in our countries of operations.
Turkey
     We established our initial position in Turkey at the end of 2001 through the acquisition of Madison Oil Company. In Turkey, we currently hold interests in 22 exploration and three exploitation permits covering approximately 2.0 million net acres. Our exploration and development program focuses on the following areas:
     Western Black Sea Permits
     We currently are the operator and hold a 36.75% working interest in the Western Black Sea permits, which cover approximately 962,000 gross acres.
     South Akcakoca Sub-Basin
     The South Akcakoca sub-basin is an area of approximately 50,000 acres located in the Western Black Sea, offshore Turkey. We discovered gas in September 2004 with the Ayazli-1 well and since that time have drilled five successful delineation wells, the Akkaya-1, Ayazli-2, Ayazli-3, Dogu Ayazli-1 and Akkaya-2. The Cayagzi-1 delineation well was drilled to total depth and did not encounter hydrocarbons, and was plugged and abandoned. We expect to drill five development wells in 2006, two of which will require a floating rig, and complete the first phase of pipeline and facility construction with production to begin in the second half of 2006. The first phase of infrastructure development includes: setting up four production platforms; laying two sub sea pipelines; constructing the onshore processing facility for the entire sub-basin development; and constructing the onshore pipeline to tie into the national pipeline operated by the Turkish national gas utility.

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     Eregli Sub-Basin
     The Eregli sub-basin is an area of approximately 75,000 acres located in the Western Black Sea, offshore Turkey. We plan to shoot a high resolution 2D seismic survey on the permit in preparation for an exploration program, which we expect to commence in mid-2006. We also plan to drill one exploration well prior to the end of 2006.
     Thrace Black Sea Permits
     The Thrace Black Sea permits are located offshore Turkey in the Black Sea between Bulgarian waters and the Bosporus Straits. We are the operator and hold a 100% working interest in the permit covering 844,000 net acres. In June 2005, HEMA Endustri A.S., a Turkish-based conglomerate, agreed to pay 100% of the first $1.5 million of the geophysical and exploration costs on this acreage to receive an option for a 50% interest in this permit.
     Central Black Sea Permit
     In January 2005, the Turkish government awarded us two additional Black Sea permits located in shallow waters offshore central Turkey comprising approximately 233,000 acres. We will conduct an analysis of existing technical data on these two permits in which we hold a 100% working interest.
     Eastern Black Sea Permit
     We were recently awarded an exploration permit on three blocks in the Black Sea offshore Turkey in the coastal waters to the west northwest of the city of Trabzon. The three blocks total approximately 357,062 acres. We are the operator of and hold 100% working interest in this permit.
     Calgan Permit
     Onshore in south central Turkey, we currently operate and hold a 75% working interest in the Calgan exploration permit, which covers an area of approximately 92,000 net acres. In 2004, we drilled the Calgan-2 exploratory well which encountered oil shows. In October 2005, we drilled a lateral extension and we are currently reviewing the best method to utilize in completing the well. Additionally, we are participants in a development well in the Cendere Field, located east of the Calgan permit, with a 20% working interest.
     Southeast Turkey Permit
     Onshore in southeast Turkey, east southeast of our Calgan permit, we were recently granted an exploration permit on one block of approximately 95,897 acres. The block is west of some existing oil fields. We are operator of and hold 100% working interest in this permit.
Hungary
     We established our initial position in Hungary in June 2005 through the acquisition of Pogo Hungary Ltd. from Pogo Producing Company for $9 million. We currently hold an interest in one exploration permit covering two blocks aggregating approximately 764,000 net acres.
     Szolnok Block
     Two gas wells were drilled by the previous operator in the Szolnok Block, each of which initially tested at over 4 Mmcf per day. We expect to construct a gas processing facility and tie-in pipeline for such wells in 2006, once we complete negotiations and finalize a gas contract with the Hungarian national oil company. In addition, extensive 2D and 3D seismic surveys conducted by the prior owner delineated multiple prospects, and we intend to start exploration drilling on the Szolnok Block in 2006.

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     Tompa Block
     The Tompa Block prospect, where we expect to commence drilling in the first half of 2006, is located in the northeast corner of the Tompa Block, situated between two existing producing fields. Extensive 2D and 3D seismic surveys conducted by the prior owner delineated multiple drilling prospects.
Romania
     We established our initial position in Romania in early 2003 through the award of an exploration permit in the Viperesti block. We hold a 100% interest in one rehabilitation and two exploration permits covering approximately 625,000 acres.
     Viperesti Permit
     We currently are the operator and hold 100% of this exploration permit, covering approximately 324,000 acres.
     Moinesti Permit
     We are the operator and hold 100% of this exploration permit, covering approximately 300,000 acres. We are currently gathering geological and geophysical data and reprocessing seismic data.
     Fauresti Rehabilitation Permit
     We are the operator and hold 100% of this rehabilitation permit covering an existing shut-in oil field covering approximately 1,325 acres. During 2005, we conducted a six-well re-entry program and were successful in converting four of the wells into natural gas and condensate producers. A second five-well re-entry program is planned for 2006.
France
     We established our initial position in France at the end of 2001 through the acquisition of Madison Oil Company. We hold interests in permits covering five producing oil fields in the Paris Basin on approximately 24,261 net acres as well as four exploration permits covering approximately 278,946 net acres.
     Charmottes Field
     We hold a 100% working interest and operate the permit covering the Charmottes Field, which currently has 12 producing oil wells. Operations are being conducted to optimize production on two recently drilled horizontal wells, the Charmottes-108H and the Charmottes-110H.
     Neocomian Complex
     Pursuant to two exploitation permits, we operate and hold a 100% working interest in the permits covering the Neocomian Fields, a group of four oil fields. The complex currently has 81 producing oil wells.
     Courtenay Permit
     We hold a 100% working interest and are the operator of this permit covering approximately 183,000 acres which surrounds the Neocomian Fields. We expect to begin an exploration drilling program on this permit in 2006.
     Nemours Permit
     We hold a 331/3% working interest in this permit covering approximately 47,300 gross acres which is operated by Lundin Petroleum AB. During 2005 oil was discovered in the La Tonnelle-1 exploration well. Further development activity is expected in 2006.

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     Nangis Permit
     We hold a 100% working interest in the approximately 50,000 acre Nagis permit in the northern Paris Basin.
     Aufferville permit
     We hold a 100% working interest and operate this permit covering approximately 33,100 acres.
United States
     We hold non-operating working interests in 943 gross wells (52 net wells) primarily in Texas, Oklahoma, New Mexico, Kansas and Louisiana. We intend to spend approximately $3 million in the United States in 2006.
Title To Oil and Natural Gas Properties
     We do not hold title to any of our international properties, but we have been granted permits by the applicable government entities that allow us, as applicable, to engage in exploration, exploitation and production.
     Turkey
     We have 22 exploration permits covering six geographic regions. The Western Black Sea permits have been extended through 2007, the Calgan permit expires in 2007, the Southeast Turkey and the Eastern Black Sea permits expire in 2008 and the Thrace Black Sea 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 Turkish proved reserves:
                                                 
            At December 31, 2005
    Permit                   Post-Expiration Proved   Percent of Proved
    Expiration   Total Proved Reserves   Reserves   Reserves
Property   Year   (MBbl)   (MMCF)   (MBbl)   (MMCF)   Post-Expiration
Zeynel
    2013  (1)     44               13               30.61 %
Cendere (2 permits)
    2011  (1)     595               216               36.42 %
S Akcakoca Sub-Basin
    2007  (2)             6,477               4,037       62.34 %
 
(1)   Exploitation Permit
 
(2)   Exploration Permit
     Hungary
     We have not yet established proved reserves on any of these properties. We have one exploration permit that expires in 2009.
     Romania
     The Moinesti and Viperesti permits will expire in 2009 and the Fauresti rehabilitation 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

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would be approximately $8 million. We have not yet established proved reserves on the Moinesti and Viperesti permits.
     The following is certain information relating to our Romanian proved reserves, all of which relate to the pre-expiration period of the Fauresti Rehabilitation permit:
                                 
            At December 31, 2005
            Total Proved        
    Permit Expiration   Reserves   Oil   Gas
Property   Year   (MBOE)   (MBbl)   (MMcf)_
Fauresti
    2015       605       24       3,486  
     France
     We hold four French exploration permits: Aufferville, Nemours, Nangis and Courtenay. No proved reserves have been established in these permits. The Nangis permit expiry date has been extended to mid-2006, the Courtenay permit expires in 2006, and the Aufferville and Nemours permits both expire in 2007. The French exploration permits have minimum financial requirements that we expect to meet 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, 2005
            Total Proved   Post-Expiration   Percent of Proved
    Permit Expiration   Reserves   Proved Reserves   Reserves
Property   Year   (MBbl)   (MBbl)   Post-Expiration_
Neocomian Fields
    2011       8,367       6,208       74.22 %
Charmottes Field
    2013       2,611       975       37.34 %
     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.
United States
     We currently own interests in producing acreage only in the form of non-operating working interests due to the sale of our U.S. mineral and royalty interests in January 2004.
Oil and Natural Gas Reserves
     The following table sets forth information about our estimated net proved reserves at December 31, 2005 and 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). We prepared the estimate of standardized measure of proved reserves in accordance with Financial Accounting Standards Board Statement of Financial Accounting Standards No. 69, Disclosures about Oil and Gas Producing Activities. No reserve reports have been provided to any governmental agencies.

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    December 31,  
    2005     2004  
U.S.
               
Proved developed:
               
Oil (MBbl)
    792       775  
Gas (MMcf)
    5,225       4,875  
Total (MBOE)
    1,663       1,587  
Proved undeveloped:
               
Oil (MBbl)
    1       5  
Gas (MMcf)
    70       58  
Total (MBOE)
    12       15  
Discounted present value at 10% (pretax) (in thousands) (1)
  $ 31,299     $ 19,921  
Standardized measure of proved reserves (in thousands)
  $ 22,700     $ 14,141  
 
               
FRANCE
               
Proved developed:
               
Oil (MBbl)
    7,688       7,309  
Proved undeveloped:
               
Oil (MBbl)
    3,290       4,227  
Discounted present value at 10% (pretax) (in thousands) (1)
  $ 164,075     $ 87,276  
Standardized measure of proved reserves (in thousands)
  $ 109,086     $ 54,331  
 
               
TURKEY
               
Proved developed:
               
Oil (MBbl)
    378       360  
Proved undeveloped:
               
Oil (MBbl)
    261       267  
Gas (MMcf)
    6,476        
Total (MBOE)
    1,340       267  
Discounted present value at 10% (pretax) (in thousands) (1)
  $ 17,930     $ 7,945  
Standardized measure of proved reserves (in thousands)
  $ 16,073     $ 6,640  
 
               
ROMANIA
               
Proved developed:
               
Oil (MBbl)
    24        
Gas (MMcf)
    3,486        
Total (MBOE)
    605        
Discounted present value at 10% (pretax) (in thousands) (1)
  $ 11,490     $  
Standardized measure of proved reserves (in thousands)
  $ 10,611     $  
 
               
COMBINED
               
Proved developed:
               
Oil (MBbl)
    8,882       8,444  
Gas (MMcf)
    8,711       4,875  
Total (MBOE)
    10,334       9,256  
Proved undeveloped:
               
Oil (MBbl)
    3,552       4,499  
Gas (MMcf)
    6,546       58  
Total (MBOE)
    4,643       4,509  
Total proved:
               
Oil (MBbl)
    12,434       12,943  
Gas (MMcf)
    15,257       4,933  
Total (MBOE)
    14,977       13,765  
Discounted present value at 10% (pretax) (in thousands) (1)
  $ 224,795     $ 115,142  
Standardized measure of proved reserves (in thousands)
  $ 158,470     $ 75,112  

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(1)   The discounted present value represents the discounted future cash flows attributable to our proved oil and natural gas reserves before income tax, discounted at 10%. Although it is a non-GAAP measure, we believe that the presentation of the discounted present value is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves prior to taking into account corporate future income taxes and our current tax structure. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. The standardized measure of discounted future net cash flows represents the present value of future cash flows attributable to our proved oil and natural gas reserves after income tax, discounted at 10%.
     Reserves were estimated using oil and natural gas prices and production and development costs in effect on December 31, 2005 and 2004, without escalation. The reserves were determined using both volumetric and production performance methods. 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.
Productive Wells
     The following table shows our gross and net interests in productive oil and natural gas wells as of December 31, 2005. Productive wells include wells currently producing or capable of production.
                                                 
    Gross (1)     Net (2)  
    Oil     Gas     Total     Oil     Gas     Total  
United States
    663       280       943       21.89       29.83       51.72  
France
    104             104       103.50             103.50  
Turkey
    15             15       2.94             2.94  
 
(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, 2005.
                                                 
    Developed Acreage     Undeveloped Acreage     Total Acreage  
    Gross     Net     Gross     Net     Gross     Net  
United States
    253,740       37,405       89,581       40,208       343,321       77,613  
France
    24,260       24,260       313,891       282,376       338,151       306,636  
Turkey
    31,730       3,059       2,614,303       1,975,459       2,646,033       1,978,518  
Romania
                625,325       625,325       625,325       625,325  
Hungary
                764,237       764,237       764,237       764,237  
 
                                   
Total
    309,730       64,724       4,407,337       3,687,605       4,717,067       3,752,329  
 
                                   
     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.
Drilling Activity
     The following table shows our drilling activities on a gross and net basis for the years ended 2005, 2004 and 2003.

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    Year ended December 31,  
    2005     2004     2003  
    Gross (1)     Net (2)     Gross (1)     Net (2)     Gross (1)     Net (2)  
UNITED STATES
                                               
Development:
                                               
Gas (3)
    7       0.08       3       0.75       1       0.03  
Oil (4)
    20       0.04       4       0.20       2       0.19  
Abandoned (5)
    2       0.26                            
 
                                   
Total
    29       0.38       7       0.95       3       0.22  
 
                                   
 
                                               
Exploratory
                                               
Gas (3)
    1       0.25                          
Oil (4)
    2       0.45                          
Abandoned (5)
                3       0.5              
 
                                   
Total
    3       0.70       3       0.5              
 
                                   
 
                                               
FRANCE
                                               
Development:
                                               
Oil (4)
    5       5       7       7              
Abandoned (5)
                                   
 
                                   
Total
    5       5       7       7              
 
                                   
 
                                               
Exploratory:
                                               
Oil (4)
    1       0.5                          
Abandoned (5)
                                   
 
                                   
Total
    1       0.5                          
 
                                   
 
                                               
TURKEY
                                               
Development:
                                               
Gas (3) (8)
    4       1.8                          
Abandoned (5)
    1       0.4                          
 
                                   
Total
    5       2.2                          
 
                                   
 
                                               
Exploratory
                                               
Oil (6)
                1       0.75              
Gas (7)
                1       0.40              
Abandoned (5)
                            2       1.30  
 
                                   
Total
                2       1.15       2       1.30  
 
                                   
 
(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.
 
(8)   Includes two wells that are replacement wells for the wells lost when the production structure collapsed.
Net Production, Unit Prices And Costs
     The following table summarizes our oil, natural gas and natural gas liquids production, net of royalties, for the periods indicated. It also summarizes calculations of our total average unit sales prices and unit costs.

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    United                    
    States     France     Turkey     Total  
Year Ended December 31, 2005
                               
Production:
                               
Oil (Bbls)
    60,433       403,991       64,792       529,216  
Daily average (Bbls/Day)
    165       1,107       178       1,450  
Gas (Mcf)
    569,566                   569,566  
Daily average (Mcf/Day)
    1,560                   1,560  
Daily average (BOE/Day)
    425       1,107       178       1,710  
 
                               
Unit prices:
                               
Average oil price ($/Bbl)
  $ 52.37     $ 50.92     $ 43.48     $ 50.17  
Average gas price ($/Mcf)
    7.56                   7.56  
Average equivalent price ($/BOE)
    48.08       50.92       43.48       49.44  
 
                               
Unit costs ($/BOE):
                               
Lease operating
  $ 13.49     $ 15.61     $ 10.96     $ 14.60  
Exploration and acquisition
    8.05       2.50       5.12       4.53  
Depreciation, depletion and amortization
    7.85       5.73       10.91       6.80  
Dry hole cost
                26.84       2.79  
Loss on involuntary conversion of assets
                8.78       0.91  
General and administrative
    33.81       2.32       9.41       10.92  
Interest and other
    0.37       (0.55 )     (5.00 )     (0.73 )
 
                       
Total
  $ 63.57     $ 25.61     $ 67.02     $ 39.82  
 
                       
 
                               
Year Ended December 31, 2004
                               
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
  $ 49.20     $ 19.14     $ 41.63     $ 29.52  
 
                       

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    United                          
    States     France     Turkey     Total     Total (1)  
Year Ended December 31, 2003
                                       
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):
                                       
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 sale of U. S. mineral royalty assets had taken on January 1, 2003.
Office Lease
     We occupy 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 3,218 square feet of office space Paris, France, approximately 9,000 square feet of office in Ankara, Turkey, 3,767 square feet in Bucharest, Romania and 2,896 square feet of office space in Budapest, Hungary. Total rental expense for 2005 was approximately $480,000
Markets and Competition
     In France, we currently sell all of our oil production to Elf Antar France S.A., the largest purchaser in the area. This production is shipped by truck to a nearby Elf refinery. The oil also can be transported to refineries on the north coast of France via pipeline. Production in Turkey is sold to refineries in the southern part of the country.
     Our domestic oil and natural gas production is sold to various purchasers typically in the areas where the oil or natural gas is produced. Generally, we do not refine or process any of the oil and natural gas we produce. We are currently able to sell, under contract or in the spot market through the operator, substantially all of the oil and the natural gas we are capable of producing at current market prices. Most of our oil and natural gas is sold under short-term contracts or contracts providing for periodic adjustments or in the spot market; therefore, our revenue streams are highly sensitive to changes in current market prices. Our natural gas is sold to pipeline companies rather than end users.
     The oil and natural gas industry is highly competitive. We encounter strong competition from other independent operators and from major oil companies in acquiring properties, contracting for drilling equipment and securing trained personnel. Many of these competitors have financial and technical resources and staffs substantially larger than those available to us. As a result, our competitors may be able to pay more for desirable leases, and they may pay more to evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources permit us to do.

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     We also are affected by competition for drilling rigs and the availability of tubular goods and certain other equipment. While the oil and natural gas industry has experienced shortages of drilling rigs and equipment, pipe and personnel in the past, we are not presently experiencing any shortages and do not foresee any such shortages in the near future; however, we are unable to predict how long current market conditions will continue.
     Competition for attractive oil and natural gas producing properties, undeveloped leases and drilling rights is also strong, and we can give no assurance we will be able to compete satisfactorily in acquiring properties. Many major oil companies have publicly indicated their decision to focus on overseas activities. We cannot ensure we will be successful in acquiring any such properties.
Government Regulation
     International
     General
     Our current international exploration activities are conducted in Turkey, Hungary, Romania and France. 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.
     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 1A. Risk Factors” for further information regarding international government regulation.
     Permits and License
     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 1A. Risk Factors” 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 Hungary. 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

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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.
     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”).
     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

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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 Pipeline and Hazardous Materials Safety Administration (“PHMSA”) 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 PHMSA. It also authorizes PHMSA 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.
     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

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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 investors 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.
     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 investors 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.

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Employees
     As of March 24, 2006, we employed 67 full-time employees. None of our employees are represented by unions or covered by collective bargaining agreements. To date, we have not experienced any strikes or work stoppages due to labor problems, and we have good relations with our employees. As needed, we also utilize the services of independent consultants on a contract basis.
Segment Reporting
     See Note 17 in the Notes to Consolidated Financial Statements for financial information by segment.
Internet Address/Availability of Reports
     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 pursuant to Section 13(a) or 15(d) of the Exchange Act are made available free of charge on our website at http://www.toreador.net as soon as reasonably practicable after we electronically file such material with, or otherwise furnish it to, the Securities and Exchange Commission.
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.

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     “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.
     “PROVED RESERVES.” The estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
     “PROVED UNDEVELOPED RESERVES.” The oil and natural gas reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery techniques is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
     “ROYALTY INTEREST.” An interest in an oil and natural gas property entitling the owner to a share of oil and natural gas production free of production costs.
     “STANDARDIZED MEASURE.” Under the Standardized Measure, future cash flows are estimated by applying year-end prices, adjusted for fixed and determinable 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.

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Item 1A. Risk Factors
     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 future 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 capital expenditures budget.
     We retired our senior secured credit facilities in January 2004. Although we have a $25 million reserve-based credit facility secured by our U.S. assets and a $15 million reserve-based credit facility secured by our French assets, our ability to borrow under these facilities is limited because of our borrowing base restrictions. At December 31, 2005, there was $5 million outstanding under the $15 million facility. At December 31, 2005, there were no amounts outstanding under the $25 million facility. As of December 31, 2005, approximately $3 million in additional borrowings was available under the $15 million facility. As of December 31, 2005, approximately $3.3 million in additional borrowings was available under the $25 million facility.
     No assurance can be given that we will have the needed additional capital to fund our growth under these facilities or from existing operations.
     The terms of our indebtedness may restrict our ability to grow.
     Our $15 million facility restricts our ability to incur additional indebtedness because of financial ratios which we must meet. In addition, our $25 million facility restricts the ability of the borrowers, two of our domestic subsidiaries, to incur additional indebtedness because of financial ratios which we must meet.
     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 is 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.
     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.
     In addition, our pursuit of capital could result in the issuance of potentially dilutive equity securities.
     Acquisition prospects may be difficult to assess and may pose additional risks to our operations.
     On a consistent basis, we evaluate and, where appropriate, pursue acquisition opportunities on terms we consider favorable. In particular, we pursue acquisitions of businesses or interests that will complement and allow us

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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. As a result, acquired properties may prove to be worth less than we pay for them.
     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.
     Our business exposes us to liability and extensive regulation on environmental matters.
     Our operations are subject to numerous federal, state, local and foreign 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. We may incur significant costs as a result of environmental accidents, such as oil spills, natural gas leaks,

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ruptures, or discharges of hazardous materials into the environment, including clean-up costs and fines or penalties. Additionally, we may incur significant costs in order to comply with environmental laws and regulations and may be forced to pay fines or penalties if we do not comply.
     A significant portion of our operations is conducted in Turkey, Hungary, Romania and France. 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 or are unable to attract and retain qualified geologists, geophysicists and other technical personnel, 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 Turkey, Hungary, Romania and France, 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.
     Since we do not hold title to our foreign properties but rather hold exploitation and exploration permits granted to us by the applicable foreign governments, the Securities and Exchange Commission may require that a certain portion of proved reserves associated with these permits not be included in our proved reserves.
     Rather than holding title to our foreign properties, we hold exploitation and exploration permits that have been granted to us for a specific time period by the applicable foreign governments. We must apply to have these permits renewed and extended in order to continue our exploration and development rights. Although we have always reported our proved reserves assuming that the permits will be extended in due course, the Securities and Exchange Commission may take the view that our ability to renew and extend our permits past their current expiration dates is not sufficiently certain such that we should not include the reserves that may be produced post expiration in our total proved reserves. Although we have previously been able to provide support to the Securities and Exchange Commission regarding the likelihood of extension, no assurance can be given that the Securities and Exchange Commission will allow us to continue to include these additional reserves in our proved reserves.
     Any future hedging activities may require us to make significant payments that are not offset by sales of production and may prevent us from benefiting from increases in oil or natural gas prices.
     Although we are not currently 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, Euro, New Turkish Lira, Forint and Romanian Lei. We are subject to fluctuations in the value of the U.S. dollar as compared to the Euro, New Turkish Lira, Forint and Romanian Lei respectively. These fluctuations may adversely affect our results of operations.
     We cannot rely on the results of our non-core 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.
Risks Related To Our Industry
     A decline in oil and natural gas prices will 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

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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;
 
    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 from 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 the reserves are produced, and our level of production and cash flows will be adversely affected. Replacing our reserves through exploration or development activities or acquisitions will require significant capital which may not be available to us.
     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.

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     In addition, as a “successful efforts” company, we account for unsuccessful exploration efforts, i.e., the drilling of “dry holes,” as an expense of operations which impacts our earnings. Significant expensed exploration charges in any period would materially adversely affect our earnings for that period and could cause our earnings to be volatile from period to period.
     We are exposed to operating hazards and uninsured risks.
     As noted by the fact that in 2005 we incurred two separate incidents, in offshore Turkey in the Black Sea, which resulted in the loss of two caissons and three wells, 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
 
    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
 
    attorney’s 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 investors 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 turn out 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.
     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

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exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.
     Investors should not assume that the pre-tax net present value of our proved reserves referred to in this annual 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.
Risks Related To Our Common Stock and Notes
     Our stock’s public trading price has been volatile, which may depress the trading price of our common stock.
     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 24, 2006 were $37.25 and $14.80 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. Because the notes are convertible into shares of our common stock at a conversion rate equal to 23.3596 shares of common stock per $1,000 principal amount of notes, volatility in the price of our common stock may depress the trading price of the notes. The risk of volatility and depressed prices of our common stock also applies to holders who receive shares of common stock upon conversion of their notes.
     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 investors to sell their shares of common stock in the public market at any given time at prevailing prices, and the price of our common stock may, therefore, be volatile.
     Numerous factors, including many over which we have no control, may have a significant impact on the market price of our common stock, including, among other things:
    current events affecting the political, economic and social situation in the United States and other countries where we operate;
 
    trends in our industry and the markets in which we operate;
 
    litigation involving or affecting us;
 
    changes in financial estimates and recommendations by securities analysts;
 
    acquisitions and financings by us or our competitors;
 
    quarterly variations in operating results;
 
    volatility in exchange rates between the US dollar and the currencies of the foreign countries in which we operate;
 
    the operating and stock price performance of other companies that investors may consider to be comparable; and
 
    purchases or sales of blocks of our securities.
     In addition, the stock market in recent years has experienced extreme price and trading volume fluctuations that often have been unrelated or disproportionate to the operating performance of individual companies. These broad market fluctuations may adversely affect the price of our common stock, regardless of our operating performance. In addition, sales of substantial amounts of our common stock in the public market, or the perception that those sales may occur, could cause the market price of our common stock to decline. Furthermore, stockholders may initiate securities class action lawsuits if the market price of our stock drops significantly, which may cause us to incur substantial costs and could divert the time and attention of our management.
     These factors, among others, could significantly depress the trading price of the notes and the price of our common stock.

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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 24, 2006, our officers and directors as a group beneficially owned approximately 22.08% of our common stock (including shares issuable upon exercise of stock options 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.
     We do not intend to pay cash dividends on our common stock in the foreseeable future.
     We currently intend to continue our policy of retaining earnings to finance the growth of our business. As a result, 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 the $15 million facility restrict our ability to pay dividends on our common stock. Because we do not anticipate paying cash dividends for the foreseeable future, holders who convert their notes and receive shares of our common stock will not realize a return on their investment unless the trading price of our common stock appreciates, which we cannot assure.
     The notes are unsecured and are subordinated to all of our existing and future secured indebtedness.
     The notes are unsecured and subordinated in right of payment to all of our existing and future secured indebtedness, to the extent of the assets securing such indebtedness, and are effectively subordinated to all liabilities of our subsidiaries, including trade payables. The indenture does not restrict our ability to incur additional debt, including secured debt. As of December 31, 2005, we had no secured indebtedness and our subsidiaries had $5 million of indebtedness and trade payables of approximately $20 million that would effectively rank senior to the notes. Any amounts borrowed under our credit facilities would effectively rank senior to the notes. Currently, we have the ability to borrow approximately an additional $3 million under the $15 million credit facility and approximately $3.3 million under the $25 million reserve-based credit facility secured by our U.S. assets. In the event of our insolvency, bankruptcy, liquidation, reorganization, dissolution or winding up, we may not have sufficient assets to pay amounts due on any or all of the notes then outstanding.
     The notes are effectively subordinated to all liabilities of our subsidiaries.
     Substantially all of our operations are conducted through our subsidiaries. None of our subsidiaries has guaranteed or otherwise become obligated with respect to the notes, and, as a result, the notes are effectively subordinated to all liabilities and other obligations of our subsidiaries. Accordingly, our right to receive assets from any of our subsidiaries upon their liquidation or reorganization, and the right of holders of the notes to participate in those assets, is effectively subordinated to claims of that subsidiary’s creditors, including trade creditors. Even if we were a creditor of any of our subsidiaries, our rights as a creditor would be subordinate to any security interest in the assets of that entity and any indebtedness of that entity senior to that held by us. Statutory, contractual or other restrictions may also limit our subsidiaries’ ability to pay dividends or make distributions, loans or advances to us. In particular, because many of our subsidiaries are located outside the United States, there may be significant tax and other legal restrictions on the ability of those non-U.S. entities to remit money to us. For these reasons, we may not have access to any assets or cash flows of our subsidiaries to make payments on the notes. Additionally, our subsidiaries might borrow funds under our credit facilities, and any of these amounts would effectively rank senior to the notes.
     The increase in the conversion rate applicable to the notes that holders convert in connection with certain fundamental changes may not adequately compensate holders for the lost option time value of their notes as a result of that fundamental change.
     If certain fundamental changes occur before October 1, 2010, we will under certain circumstances increase the conversion rate applicable to certain holders. This increased conversion rate will apply to holders that surrender their notes for conversion from, and including, the effective date of such fundamental change until, and including, the

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close of business on the business day immediately preceding the fundamental change repurchase date corresponding to such fundamental change. The amount of the increase in the conversion rate depends on the date when the fundamental change becomes effective and the applicable price described in this prospectus.
     Although the increase in the conversion rate is designed to compensate holders for the lost option time value of their notes as a result of the fundamental change, the increase in the conversion rate is only an approximation of the lost value and may not adequately compensate holders for the loss. In addition, holders will not be entitled to an increased conversion rate if:
    the fundamental change occurs on or after October 1, 2010;
 
    the applicable price is greater than $75.00 per share or less than $32.93 per share (in each case, subject to adjustment); or
 
    we elect, in the case of a “public acquirer fundamental change,” to change the conversion right in lieu of increasing the conversion rate.
     Our ability to purchase the notes with cash at the investor’s option or upon a fundamental change, may be limited.
     Holders of the notes may require us to purchase all or a portion of their notes for cash at specific times and upon the occurrence of specific circumstances. We cannot assure holders that, if required, we would have sufficient cash or other financial resources at that time or would be able to arrange financing to pay the purchase price of the notes in cash. Our ability to purchase the notes in such circumstances may be limited by law, by regulatory authorities, by the terms of other agreements relating to our indebtedness and by indebtedness and agreements that we may enter into in the future, which may replace, supplement or amend our existing or future indebtedness. In addition, statutory, contractual or other restrictions may also limit our subsidiaries’ ability to pay dividends or make distributions, loans or advances to us. In particular, because many of our subsidiaries are located outside the United States, there may be significant tax and other legal restrictions on the ability of those non-U.S. entities to remit money to us. For these reasons, we may not have access to any assets or cash flows of our subsidiaries to make payments on the notes.
     Future sales or issuances of common stock or the issuance of securities senior to our common stock may depress the trading price of our common stock and the notes.
     Any issuance of equity securities, including the issuance of shares upon conversion of the notes, could dilute the interests of our existing stockholders, including holders who have received shares upon conversion of their notes, and could substantially decrease the trading price of our common stock and the notes. We may issue equity securities in the future for a number of reasons, including to finance our operations and business strategy, to adjust our ratio of debt to equity, to satisfy our obligations upon the exercise of outstanding warrants or options, or upon conversion of preferred stock or debentures, or for other reasons. As of March 24, 2006, there were:
    843,690 shares of our common stock issuable upon exercise of outstanding options, at a weighted average exercise price of $5.09 per share, of which options to purchase 618,390 shares were exercisable;
 
    102,890 shares of our common stock issuable upon exercise of outstanding warrants, at a weighted average exercise price of $19.35 per share, of which 92,890 were exercisable;
 
    450,000 shares of our common stock issuable upon conversion of our Series A-1 Convertible Preferred Stock, at a conversion rate equal to 6.25 shares of common stock per share of Series A-1 Convertible Preferred Stock (subject to certain adjustments for stock splits, stock dividends, mergers or assets distributions);

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    100,000 shares of our common stock issuable upon conversion of our second amended and restated convertible debenture, at a conversion price of $6.75 per share of common stock; and
 
    55,665 shares of our common stock available for future grant under our equity incentive plan.
     The price of our common stock could also be affected by possible sales of our common stock by investors who view the notes as a more attractive means of equity participation in our company and by hedging or arbitrage trading activity that we expect to develop involving our common stock. The hedging or arbitrage could, in turn, affect the trading price of the notes.
     Our leverage may harm our financial condition and results of operations.
     Our total consolidated long-term debt as of December 31, 2005 was approximately $92 million and represented approximately 41% of our total capitalization as of that date. In addition, the indenture for the notes does not restrict our ability to incur additional indebtedness.
     Our level of indebtedness could have important consequences to investors, because:
    it could affect our ability to satisfy our payment obligations under the notes;
 
    a substantial portion of our cash flows from operations will have to be dedicated to interest and principal payments and may not be available for operations, working capital, capital expenditures, expansion, acquisitions or general corporate or other purposes;
 
    it may impair our ability to obtain additional financing in the future;
 
    it may impair our ability to compete with companies that are not as highly leveraged;
 
    it may limit our flexibility in planning for, or reacting to, changes in our business and industry; and
 
    it may make us more vulnerable to downturns in our business, our industry or the economy in general.
     Because we have made only limited covenants in the indenture for the notes, and the terms of the notes do not provide protection against some types of important corporate events, these limited covenants and protections against certain types of important corporate events may not protect holders’ investment.
     The indenture for the notes does not:
    require us to maintain any financial ratios or specific levels of net worth, revenues, income, cash flows or liquidity and, accordingly, does not protect holders of the notes in the event that we experience significant adverse changes in our financial condition or results of operations;
 
    limit our subsidiaries’ ability to incur indebtedness which would effectively rank senior to the notes;
 
    limit our ability to incur indebtedness that is equal in right of payment to the notes;
 
    restrict our subsidiaries’ ability to issue securities that would be senior to the common stock of our subsidiaries held by us;
 
    restrict our ability to repurchase our securities; or

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    restrict our ability to make investments or to pay dividends or make other payments in respect of our common stock or other securities ranking junior to the notes.
     Furthermore, the indenture for the notes contains only limited protections in the event of a change in control. We could engage in many types of transactions, such as certain acquisitions, refinancings or recapitalizations, which could substantially affect our capital structure and the value of the notes and our common stock but would not constitute a “fundamental change” that permits holders to require us to repurchase their notes. For these reasons, potential holders should not consider the covenants in the indenture or the repurchase feature of the notes as a significant factor in evaluating whether to invest in the notes.
     If an active and liquid trading market for the notes does not develop, the market price of the notes may decline and investors may be unable to sell their notes.
     The notes are a new issue of securities for which there is no established trading market. We do not intend to list the notes on any national securities exchange. Accordingly, we do not know if an active trading market will develop for the notes. Even if a trading market for the notes develops, the market may not be liquid. If an active trading market does not develop, investors may be unable to resell their notes or may only be able to sell them at a substantial discount. Future trading prices of the notes will depend on many factors, including our operating performance and financial condition, prevailing interest rates and the market for similar securities.
     Holders of notes are not entitled to any rights with respect to our common stock, but are subject to all changes made with respect to our common stock.
     Holders of notes are not entitled to any rights with respect to our common stock (including, without limitation, voting rights and rights to receive any dividends or other distributions on our common stock), but are subject to all changes affecting our common stock. Holders will have the rights with respect to our common stock only when we deliver shares of common stock, if any, upon conversion of the notes. For example, in the event that an amendment is proposed to our Restated Certificate of Incorporation or bylaws requiring stockholder approval and the record date for determining the stockholders of record entitled to vote on the amendment occurs prior to the delivery of common stock, if any, to holders, holders will not be entitled to vote on the amendment, although holders will nevertheless be subject to any changes in the powers, preferences or special rights of our common stock.
     The conversion rate of the notes may not be adjusted for all dilutive events that may occur.
     We will adjust the conversion rate of the notes for certain events, including, among others:
    the issuance of stock dividends on our common stock;
 
    the issuance of certain rights or warrants;
 
    certain subdivisions and combinations of our capital stock;
 
    the distribution of capital stock, indebtedness or assets; and
 
    certain tender or exchange offers.
     We will not adjust the conversion rate for other events, such as an issuance of common stock for cash or in connection with an acquisition, which may adversely affect the trading price of the notes or our common stock. If we engage in any of these types of transactions, the value of the common stock into which the notes may be convertible may be diluted. There can be no assurance that an event that adversely affects the value of the notes, but does not result in an adjustment to the conversion rate, will not occur.

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     Provisions in our charter documents, the indenture for the notes and Delaware law could discourage an acquisition of us by a third party, even if the acquisition would be favorable to holders of our common stock or the notes.
     If a “change in control” (as defined in the indenture) occurs, holders of the notes will have the right, at their option, to require us to repurchase all or a portion of their notes. In the event of certain “fundamental changes” (as defined in the indenture), we also may be required to increase the conversion rate applicable to notes surrendered for conversion upon the fundamental change. In addition, the indenture for the notes prohibits us from engaging in certain mergers or acquisitions unless, among other things, the surviving entity assumes our obligations under the notes. These and other provisions, including the provisions of our charter documents and Delaware law, could prevent or deter a third party from acquiring us even where the acquisition could be beneficial to holders of our common stock or the notes.
     Certain provisions of our charter documents may adversely impact our stockholders.
     Our charter documents provide our board of directors with the right to issue preferred stock upon such terms and conditions as it deems to be our best interests. The terms of such preferred stock may adversely impact the dividend and liquidation rights of the common stockholders without the approval of the common stockholders.
     Holders of notes may have to pay U.S. federal taxes if we adjust the conversion rate in certain circumstances, even if the investor does not receive any cash.
     We will adjust the conversion rate of the notes for stock splits and combinations, stock dividends, cash dividends and certain other events that affect our capital structure. If we adjust the conversion rate, holders of the notes may be treated as having received a constructive distribution from us, resulting in taxable income to holders of the notes for U.S. federal income tax purposes, even though holders of the notes would not receive any cash in connection with the conversion rate adjustment and even though holders of the notes might not exercise their conversion right. In addition, non-U.S. holders of notes will, in certain circumstances, be deemed to have received a distribution subject to U.S. federal withholding tax requirements.
ITEM 1B. Unresolved Staff Comments
None.
ITEM 2. Properties (see Items 1 and 2. Business and Properties)
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 appeal that was heard in December 2002. The appellate court reversed the lower court’s ruling. All internal Turkish legal proceedings are exhausted and the rejection of the exchange protection award is final. We have appealed the case to the European Court of Human Rights which is a court recognized by Turkey. We cannot predict the outcome of this matter.

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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
     No matters were submitted to a vote of security holders during the quarter ended December 31, 2005.
PART II
Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters
Common Stock
     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.
                 
    High   Low
2005:
               
Fourth quarter
  $ 35.74     $ 20.09  
Third quarter
    37.25       23.78  
Second quarter
    26.86       14.80  
First quarter
    27.32       17.05  
2004:
               
Fourth quarter
  $ 24.37     $ 8.78  
Third quarter
    10.15       6.02  
Second quarter
    7.73       4.67  
First quarter
    6.49       4.06  
     As of March 24, 2006, there were 16,167,274 shares of common stock outstanding and held of record by approximately 740 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 24, 2006 was $29.85.
     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-1 Convertible Preferred Stock are paid on a quarterly basis per the terms of such series. Dividends totaling $186,264, $360,000 and $139,549 were declared for the years ended December 31, 2005, December 31, 2004 and December 31, 2003 on the Series A-1 Convertible Preferred Stock. Cash dividends totaling $261,077, $285,155 and $153,549 were paid for the years ended December 31, 2005, 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 22, 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

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paid in cash only at a rate of $0.5625 per share of Series A-1 Convertible Preferred Stock. On December 31, 2005, there were 72,000 shares of Series A-1 Convertible Preferred Stock outstanding.
     During 2005, there were no equity securities issued pursuant to transactions exempt from the registration requirements under the Securities Act of 1933, as amended, that were not disclosed previously in Current Reports on Form 8-K and Quarterly Reports on Form 10-Q.
     During the fourth quarter 2005, we did not repurchase any of our registered equity securities.
Item 6. Selected Financial Data
     The following selected financial information (which is not covered by the independent auditors’ report) should be read in conjunction with the consolidated financial statements and the notes thereto included in “Item 8. Financial Statements and Supplementary Data.”
                                         
    Years ended December 31,  
    2005     2004     2003     2002     2001  
    (Amounts in thousands, except per share amounts)  
Operating Results:
                                       
Revenues
  $ 30,856     $ 21,028     $ 16,846     $ 15,375     $ 7,963  
Costs and expenses
    (25,310 )     (19,459 )     (15,973 )     (17,897 )     (11,538 )
 
                             
Operating income (loss)
    5,546       1,569       873       (2,522 )     (3,575 )
Other income (expense)
    456       2,335       61       (5,205 )     (974 )
 
                             
Income (loss) before income taxes
    6,002       3,904       934       (7,727 )     (4,549 )
Income tax benefit
    (1,659 )     (3,576 )     (266 )     (2,061 )     (1,802 )
 
                             
Income (loss) from continuing operations, net of tax
    7,661       7,480       1,200       (5,666 )     (2,747 )
Income (loss) from discontinued operations, net of tax
    47       17,539       1,182       (441 )     2,105  
Dividend on preferred shares
    684       714       500       374       360  
 
                             
Net income (loss) available to common shares
  $ 7,024     $ 24,305     $ 1,882     $ (6,481 )   $ (1,002 )
 
                             
Basic income (loss) per share
  $ 0.49     $ 2.54     $ 0.20     $ (0.69 )   $ (0.16 )
 
                             
Diluted income (loss) per share
  $ 0.47     $ 1.97     $ 0.20     $ (0.69 )   $ (0.16 )
 
                             
Weighted average shares outstanding
                                       
Basic
    14,274       9,571       9,338       9,343       6,319  
Diluted
    15,207       12,817       9,347       9,343       6,319  
 
                                       
Balance Sheet Data:
                                       
Working capital (deficit)
  $ 94,795     $ 1,090     $ (14,721 )   $ (7,569 )   $ (879 )
Total property and equipment, net of accumulated depreciation
    134,035       79,667       77,616       71,872       78,028  
Total assets
    263,180       94,974       91,542       86,853       94,454  
Long term debt, including current portion
    92,060       9,022       30,976       26,860       36,874  
Stockholders’ equity
    134,244       63,258       37,322       30,021       33,555  
 
                                       
Cash Flow Data:
                                       
Net cash provided by operating activities
  $ 9,532     $ 94     $ 6,879     $ 6,362     $ 8,856  
Capital expenditures for oil and natural gas property and equipment
    68,010       16,743       3,713       6,178     $ 11,979  

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
     Certain of the matters discussed under the captions “Business and 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. We also focus on prospects where we do not have to compete directly with major integrated or large independent oil and natural gas producers and where extensive geophysical and geological data is available. Our international operations are located in European Union or European Union candidate countries that we believe have stable governments, have transportation infrastructure, 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 Hungary. We also own various working-interest properties primarily in Texas, Kansas, New Mexico, Louisiana and Oklahoma.
     Income available to common shares for 2005 was $7.0 million, or $0.47 per diluted share, compared with income applicable to common shares of $24.3 million, or $1.97 per diluted share, in 2004. Operating income from continuing operations for 2005 was $5.5 million, compared with operating income from continuing operations of $1.6 million in 2004.
     Revenues for the year ended December 31, 2005 were $30.9 million, a 47% increase over 2004 revenues of $21 million.
     In 2005, our oil and natural gas production was 624,144 BOE versus production of 634,180 BOE for 2004. Our average realized oil price per barrel for 2005 was $50.17, a 42.3% increase over the average realized oil price per barrel of $35.24 in 2004. The average realized gas price in 2005 was $7.56 per Mcf, 33.8% higher than the average realized gas price of $5.65 per Mcf in 2004.
     At December 31, 2005, we held interests in approximately 4.7 million gross acres (approximately 3.8 million net acres). For a more detailed description of our properties see “Items 1 and 2. Business and Properties.” At December 31, 2005, our net proved reserves were estimated at approximately 15 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 $32.3 million, which was used to fund our 2005 capital expenditure budget and for general corporate purposes.

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     In June 2005, we acquired 100% of Pogo Hungary Ltd., a wholly owned subsidiary of Pogo Producing Company. The purchase price was approximately $9 million. (See Note 3 to Notes to Consolidated Financial Statements for additional detail.)
     On September 16, 2005, we sold 806,450 shares of our common stock to certain accredited investors pursuant to a private placement. The net proceeds of approximately $23.6 million have been and are being used for general corporate purposes, including the funding of our capital expenditures requirements in 2005 and 2006.
     On September 27, 2005, we sold $75 million of 5% Convertible Senior Notes due October 1, 2025 to qualified institutional buyers pursuant to Rule 144A of the Securities Act of 1933. The Company also granted the initial purchasers the option to purchase an additional $11.25 million aggregate principal amount of Notes to cover over-allotments. The option was exercised on September 30, 2005, which resulted in a total principal amount of $86.25 million and total net proceeds of approximately $82.2 million. The funds have been and are being used for general corporate purposes, including funding a portion of the Company’s 2005 and 2006 exploration and development activities.
     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 And Management’s Estimates
     The discussion and analysis of our financial condition and results of operations is based upon the consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. Our significant accounting policies are described in Note 2 to our consolidated financial statements included in this Form 10-K. We have identified below policies that are of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by management. We analyze our estimates, including those related to oil and natural gas revenues, accounts receivable, oil and natural gas properties, income taxes, derivatives, contingencies and litigation, on a periodic basis and base our estimates on experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates using different assumptions or conditions. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our financial statements:
Successful Efforts Method Of Accounting
     We account for our oil and natural gas exploration and development activities utilizing the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and natural gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but such costs are charged to expense if and when the well is determined not to have found reserves in commercial quantities. In most cases, a gain or loss is recognized for sales of producing properties.
     The application of the successful efforts method of accounting requires management’s judgment to determine the proper designation of wells as either developmental or exploratory, which will ultimately determine the proper

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accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and application of industry experience. Wells may be completed that are assumed to be productive and actually deliver oil and natural gas in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. On occasion, wells are drilled which have targeted geologic structures that are both developmental and exploratory in nature, and in such instances an allocation of costs is required to properly account for the results. Delineation seismic costs incurred to select development locations within a productive oil and natural gas field are typically treated as development costs and capitalized, but often these seismic programs extend beyond the proved reserve areas and therefore management must estimate the portion of seismic costs to expense as exploratory. The evaluation of oil and natural gas leasehold acquisition costs requires management’s judgment to estimate the fair value of exploratory costs related to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.
     The successful efforts method of accounting can have a significant impact on the operational results reported when we enter a new exploratory area in hopes of finding oil and natural gas reserves. The initial exploratory wells may be unsuccessful and the associated costs will be expensed as dry hole costs. Seismic costs can be substantial which will result in additional exploration expenses when incurred.
     Reserve Estimates
     Proved reserves are 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 developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods as well as 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 after testing by a pilot project or after the operation of an installed program has been confirmed through production response that increased recovery will be achieved. Proved undeveloped reserves are 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. Proved undeveloped reserves on undrilled acreage is limited (i) to those drilling units offsetting productive units that are reasonably certain of production when drilled and (ii) to other undrilled units where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. We emphasize that the volume of reserves are estimates that, by their nature are subject to revision. The estimates are made using geological and reservoir data, as well as production performance data. These estimates are reviewed annually and revised, either upward or downward, as warranted by additional performance data. We had a downward reserve revision of 2.4% for the year ended December 31, 2005 and upward reserve revisions of 5.03% and 2.34% of proved reserves during the years ended December 31, 2004 and 2003, respectively. These reserve revisions resulted primarily from improved or a decline in performance from a variety of sources such as an addition to or a reduction in recoveries below or above previously established lowest known hydrocarbon levels, improved or a decline in drainage from natural drive mechanisms, and the realization of improved or declined drainage areas. If the estimates of proved reserves were to decline, the rate at which we record depletion expense would increase.
     Impairment of Oil and Natural Gas Properties
     We review our proved oil and natural gas properties for impairment on an annual basis or whenever events and circumstances indicate a potential decline in the recoverability of their carrying value. We estimate the expected future cash flows from our proved oil and natural gas properties and compare these future cash flows to the carrying value of the oil and natural gas properties to determine if the carrying value is recoverable. If the carrying value exceeds the estimated undiscounted future cash flows, we will adjust the carrying value of the oil and natural gas properties to its fair value in the current period. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, anticipated capital expenditures, and a discount rate commensurate with the risk associated with realizing the expected cash flows projected. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the period. Given the complexities associated with oil and natural gas reserve estimates and the history of price volatility in the oil and natural gas markets, events may arise that will require us to

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record an impairment of our oil and natural gas properties and there can be no assurance that such impairments will not be required in the future nor that they will not be material.
     Future Development And Abandonment Costs
     Future development costs include costs incurred to obtain access to proved reserves, including drilling costs and the installation of production equipment. Future abandonment costs include costs to dismantle and relocate or dispose of our production equipment, gathering systems, wells and related structures and restoration costs of land. We develop estimates of these costs for each of our properties based upon the type of production structure, depth of water, reservoir characteristics, depth of the reservoir, market demand for equipment, currently available procedures and consultations with construction and engineering consultants. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including changing technology, the ultimate settlement amount, inflation factors, credit adjusted discount rates, timing of settlement and changes in the political, legal, environmental and regulatory environment. We review our assumptions and estimates of future abandonment costs on an annual basis. The accounting for future abandonment costs changed on January 1, 2003, with the adoption of SFAS 143. SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.
     Holding all other factors constant, if our estimate of future abandonment costs is revised upward, earnings would decrease due to higher depreciation, depletion and amortization expense. Likewise, if these estimates were revised downward, earnings would increase due to lower depreciation, depletion and amortization expense.
     Income Taxes
     For financial reporting purposes, we generally provide taxes at the rate applicable for the appropriate tax jurisdiction. Because our present intention is to reinvest the unremitted earnings in our foreign operations, we do not provide U.S. income taxes on unremitted earnings of foreign subsidiaries. Management periodically assesses the need to utilize these unremitted earnings to finance our foreign operations. This assessment is based on cash flow projections that are the result of estimates of future production, commodity prices and expenditures by tax jurisdiction for our operations. Such estimates are inherently imprecise since many assumptions utilized in the cash flow projections are subject to revision in the future.
     Management also periodically assesses, by tax jurisdiction, the probability of recovery of recorded deferred tax assets based on its assessment of future earnings estimates. Such estimates are inherently imprecise since many assumptions utilized in the assessments are subject to revision in the future.
     New Accounting Pronouncements
     In December 2004, the FASB issued SFAS No. 123(R), “Share-Based Payment.” SFAS No. 123(R) revises SFAS No. 123, “Accounting for Stock-Based Compensation,” and focuses on accounting for share-based payments for services provided by employee to employer. The statement requires companies to expense the fair value of employee stock options and other equity-based compensation at the grant date. The statement does not require a certain type of valuation model, and either a binomial or Black-Scholes model may be used. During the first quarter of 2005, the Securities and Exchange Commission (SEC) approved a new rule for public companies to delay the adoption of this standard. In April 2005, the SEC took further action to amend Regulation S-X to state that the provisions of SFAS No. 123(R) will be effective beginning with the first annual or interim reporting period of the registrant’s first fiscal year beginning on or after June 15, 2005 for all non-small business issuers. As a result, we will not adopt this SFAS until the first quarter of 2006. At this time, management does not believe that the adoption of SFAS No. 123(R) will materially impact our operating results, nor will there be any impact on our future cash flows.

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     In April 2005, the FASB issued Staff Interpretation No. 19-1 (“FSP 19-1”) “Accounting for Suspended Well Costs”, which provides guidance on the accounting for exploratory well costs and proposes an amendment to FASB Statement No. 19 (“FASB 19”), Financial Accounting and Reporting by Oil and Gas Producing Companies. The guidance in FSP 19-1 applies to enterprises that use the successful efforts method of accounting as described in FASB 19. The guidance in FSP 19-1 will not impact our consolidated financial position, results of operations, or cash flows.
     In May 2005, the FASB issued Statement No. 154 “Accounting Changes and Error Corrections—a replacement of APB Opinion No. 20 and FASB Statement No. 3”. This Statement replaces APB No. 20, Accounting Changes, and FASB Statement No. 3, Reporting Accounting Changes in Interim Financial Statements, and changes the requirements for the accounting for and reporting of a change in accounting principle. This statement applies to all voluntary changes in accounting principle. It also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. ABP No. 20 previously required that most voluntary changes in accounting principle be recognized by including in net income of the period of the change the cumulative effect of changing to the new accounting principle. This Statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. The guidance in this Statement will not impact our consolidated financial position, results of operations, or cash flows.
     On February 16, 2006, the FASB issued Statement 155, “Accounting for Certain Hybrid Instruments- an amendment of FASB Statements No. 133 and 140.” The statement amends Statement 133 to permit fair value measurement for certain hybrid financial instruments that contain an embedded derivative and provides additional guidance on the applicability of Statement 133 and 140 to certain financial instruments and subordinated concentrations of credit risk. The new standard is effective for the first fiscal year that begins after September 16, 2006. We are currently evaluating the impact this new standard will have on the Company.
     LIQUIDITY AND CAPITAL RESOURCES
     This section should be read in conjunction with Notes 9 and 10 to Notes to Consolidated Financial Statements included in this filing.
     Liquidity
     As of December 31, 2005, we had cash on hand of $92.5 million, a current ratio of approximately 4.9 to 1 and a debt (convertible debenture, long-term debt and convertible senior notes) to equity ratio of .69 to 1. For the twelve months ended December 31, 2005, operating income was $5.5 million and capital expenditures, including the acquisition of the Hungarian assets for $9 million, was $68 million.
     On August 31, 2005, we announced a revised capital budget for the last six months of 2005, and a preliminary capital budget for the year ended December 31, 2006. We expect our 2006 capital spending to be approximately $80 million. We believe that our cash flow from operations, net proceeds from our recent private placement, convertible notes offering and available borrowings under our credit facilities will sufficiently fund these capital requirements. We may also use some of these amounts to fund possible acquisitions of properties. We may also seek additional funds if unanticipated capital requirements arise and to fund any potential acquisitions.
     Senior Debt
     On December 23, 2004, we entered into a five-year $15 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 (6.59% total rate at December 31, 2005) depending on the principal outstanding. 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 time all unpaid principal and interest are due. Under the $15 million facility borrowings of approximately $8 million were available at December 31, 2005. The $15 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

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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, 2005, we were in compliance with all covenants.
     On December 30, 2004, we entered into a five-year $25 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% (6.75% total rate at December 31, 2005) 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, 2005, we had approximately an additional $3.3 million available for borrowings. The $25 million facility requires monthly interest payments until January 1, 2009 at which time all unpaid principal and interest are due. The $25 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, 2005, we were in compliance with all covenants.
     Preferred Stock
     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. The Company 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 12,992 shares of common stock (492 inducement shares) to Roger A. Anderson. As of December 31, 2005, there were 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 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.
     5% Convertible Senior Notes Due 2025
     On September 27, 2005, we sold $75 million of Convertible Senior Notes due October 1, 2025 to qualified institutional buyers pursuant to Rule 144A of the Securities Act of 1933. We also granted the initial purchasers the option to purchase an additional $11.25 million aggregate principal amount of notes to cover over-allotments. The option was exercised on September 30, 2005. The total principal amount of notes issued was $86.25 million and total net proceeds were approximately $82.2 million.
     The notes bear interest at a rate of 5% per annum and can be converted into common stock at an initial conversion rate of 23.3596 shares of common stock per $1,000 principal amount of Notes, subject to adjustment (equivalent to a conversion price of approximately $42.81 per share). We may redeem the notes, in whole or in part, on or after October 6, 2008, and prior to October 1, 2010, for cash at a redemption price equal to 100% of the principal amount of notes to be redeemed, plus any accrued and unpaid interest, if the closing price of its common stock exceeds 130% of the conversion price over a specified period. On or after October 1, 2010, we may redeem the notes, in whole or in part, at a redemption price equal to 100% of the principal amount of notes to be redeemed, plus any accrued and unpaid interest, irrespective of the price of its common stock. Holders may convert their notes at any time prior to the close of business on the business day immediately preceding their stated maturity, and holders may, upon the occurrence of certain fundamental changes, and on October 1, 2010, October 1, 2015, and October 1, 2020, require us to repurchase all or a portion of their notes for cash in an amount equal to 100% of the principal amount of such Notes, plus any accrued and unpaid interest.

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     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 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.
     Dividends on our Series A-1 Convertible Preferred Stock are paid quarterly. For the twelve months ended December 31, 2005 dividends totaled $684,314, of which $186,258 was paid in cash and the remaining $498,056 was paid by the issuance of common stock. Cash dividends of $615,000 were paid for the twelve month period ended December 31, 2004.
     The terms of the $15 million reserve-based borrowing facility limit our ability to pay dividends on our common stock to twenty-five percent (25%) of net profit (as defined in the facility agreement), less any dividend amounts paid on our preferred stock.
     Contractual Obligations
     The following table sets forth our contractual obligations in thousands at December 31, 2005 for the periods shown:
                                         
            Less than     One To Three     Three to     More Than  
    Total     One Year     Years     Five Years     Five Years  
Long-term debt
  $ 92,060     $ 810     $ 5,000     $     $ 86,250  
Lease commitments
    1,448       721       727              
 
                             
Total contractual obligations
  $ 93,508     $ 1,531     $ 5,727     $     $ 86,250  
 
                             
Results of Operations
Comparison of Years Ended December 31, 2005 and 2004
                 
    For the Twelve Months Ended December 31,  
    2005     2004  
Production:
               
Oil (MBbls):
               
United States
    60       70  
France
    404       397  
Turkey
    65       73  
 
           
Total
    529       540  
 
           
 
               
Gas (MMcf):
               
United States
    570       568  
France
           
Turkey
           
 
           
Total
    570       568  
 
           
 
               
MBOE:
               
United States
    155       164  
France
    404       397  
Turkey
    65       73  
 
           
Total
    624       634  
 
           
 
               
Average Price:
               
Oil ($/Bbl):
               
United States
  $ 52.37     $ 38.45  
France
    50.92       35.39  
Turkey
    43.48       31.05  
 
           
Total
  $ 50.17     $ 35.24  
 
           
 
               
Gas ($/Mcf):
               
United States
  $ 7.56     $ 5.65  
France
           
Turkey
           
 
           
Total
  $ 7.56     $ 5.65  
 
           
 
               
$/BOE:
               
United States
  $ 48.08     $ 35.83  
France
    50.92       35.39  
Turkey
    43.48       31.05  
 
           
Total
  $ 49.44     $ 35.00  
 
           

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Revenues
     Oil and natural gas sales
     Oil and natural gas sales for the twelve months ended December 31, 2005 were $30.9 million, as compared to $22.4 million for the comparable period in 2004. This increase is primarily due to a significant increase in the average realized price of both oil and natural gas. Production decreased by approximately 10MBOE due primarily to normal declines in the US and in Turkey, offset by a slight increase in France from the results of successful workovers and new drilling.
     The above table compares both volumes and prices received for oil and natural gas for the twelve months ended December 31, 2005 and 2004. Oil and natural gas prices are and probably will continue to be extremely volatile and a significant change will have a material impact on our revenue.
     We had no loss on commodity derivatives for the year ended December 31, 2005, as compared to $1.3 million loss for the comparable period of 2004. We were not party to any hedging contracts as of December 31, 2005.
Costs and expenses
     Lease operating
     Lease operating expense was $9.1 million, or $14.60 per BOE produced for the twelve months ended December 31, 2005, as compared to $6.9 million, or $10.84 per BOE produced for the comparable period in 2004. This increase is primarily due to the workover program in France and a 10,035 BOE decline in production when comparing the twelve months ended December 31, 2005 to 2004.
     Exploration and acquisition
     Exploration and acquisition expense for the twelve months ended December 31, 2005 was $2.8 million, as compared to $3.4 million for the comparable period in 2004. In 2004 we conducted a seismic program in the Black Sea, resulting in an additional $1.8 million of exploration and acquisition cost in 2004. Excluding the cost of the seismic program in 2004, there would have been an increase of $1.2 million in 2005. This increase is primarily due to geological and geophysical studies done on our exploration areas in France and Turkey.
     Dry hole and abandonment
     Dry hole and abandonment cost for the twelve months ended December 31, 2005 was $1.7 million, as compared to no dry hole and abandonment cost for the comparable period of 2004. This increase is due to expensing of the Boyabot # 1 well in Turkey, which did not test sufficient oil and natural gas to be declared commercial.
     Loss on involuntary conversion of assets
     In 2005 we incurred two separate incidents, in offshore Turkey in the Black Sea, which resulted in the loss of two caissons and three wells. Both of these incidents were insured. In December 2005 the Company received notice that the insurance company has reserved $10.6 million (net to the Company) for the potential payment of this claim. As of December 31, 2005 the book value of the wells and caissons was $11.1 million. The difference of $569,000 has been recorded as a loss on the involuntary conversion.
     Depreciation, depletion and amortization.
     For the twelve months ended December 31, 2005 depreciation, depletion and amortization expense was $4.2 million, or $6.80 per BOE produced, as compared to $3.5 million, or $5.58 per BOE produced for the twelve months ended December 31, 2004. This increase is primarily due to increased investments in oil and gas properties and a 10,035 BOE decline in production.

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     General and administrative
     General and administrative expense was $6.8 million for the twelve months ended December 31, 2005, compared with $5.6 million for the comparable period of 2004. The increase is primarily due to costs related to increased staff, Securities and Exchange Commission filings, Sarbanes-Oxley compliance and expensing of stock compensation expense related to the restricted stock granted by the Board of Directors to certain employees and non employee directors.
     Other income and expense
     Other income and expense resulted in income of $456,000 for the twelve months ended December 31, 2005 versus income of $2.3 million for the comparable period in 2004. The decrease was primarily due to a realized $4.8 million foreign currency exchange gain in 2004 that was related to the increase in value of the Eurodollar against the U.S. dollar in connection with the discharge of the Barclays Facility, which was offset by an increase in interest income due to higher cash balances in 2005.
     Discontinued operations
     The following table compares discontinued operations for the twelve months ended December 31, 2005, 2004 and 2003:
                         
    Twelve Months Ended December 31,  
    2005     2004     2003  
    (in thousands)  
Revenues:
                       
Oil and natural gas sales (revenue applicable to periods prior to the effective date of January 1, 2004)
  $ 47     $ 139     $ 6,298  
 
                 
Total revenues
    47       139       6,298  
Costs and expenses:
                       
Lease operating
          (9 )     1,046  
General and administrative
          161       2,222  
Depreciation, depletion and amortization
                679  
Interest
          305       711  
 
                 
Total costs and expenses
          457       4,658  
Gain on sale of properties
          28,711        
 
                 
Income before taxes
    47       28,393       1,640  
Income tax provision
          10,854       458  
 
                 
Income from discontinued operations
  $ 47     $ 17,539     $ 1,182  
 
                 
     Income available to common shares
     For the twelve months ended December 31, 2005, we reported income from continuing operations net of taxes of $7.7 million, compared with $7.5 million for the same period of 2004. For the twelve months ended December 31, 2005 income available to common shares was $7.0 million versus income applicable to common shares of $24.3 million for the year ended December 31, 2004.
     Other comprehensive income
     This item should be read in conjunction with Note 4 to Notes to Consolidated Financial Statements included in this filing.
     The most significant element of comprehensive income, other than net income, is foreign currency translation. As of December 31, 2004, we had accumulated an unrealized gain of $2 million. In the year ended December 31, 2005, we had an unrealized loss of $5.2 million. The functional currency of our operations in France is the Euro, the

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functional currency in Romania is the Lei, in Turkey the functional currency is the New Turkish Lira and in Hungary the functional currency is the Forint. The exchange rate used to translate the financial position of the French, Turkish, Romanian and Hungarian operations at December 31, 2005 was approximately US $1.18 per Euro, 1.35 New Turkish Lira per US Dollar, 35,080 Lei per US Dollar and 214.35 Forint per US Dollar, respectively. The Euro rate at December 31, 2004, was US $1.36 per Euro and US $0.70 per million Turkish Lira. There were no Romanian or Hungarian operations in the year ended December 31, 2004.
Comparison of Years Ended December 31, 2004 and 2003
                         
    For the Twelve Months Ended December 31,  
    2004     2003     2003(1)  
Production:
                       
Oil (MBbls):
                       
United States
    70       190       75  
France
    397       374       374  
Turkey
    73       92       92  
 
                 
Total
    540       656       541  
 
                 
 
                       
Gas (MMcf):
                       
United States
    568       1,561       740  
France
                 
Turkey
                 
 
                 
Total
    568       1,561       740  
 
                 
 
                       
MBOE:
                       
United States
    164       450       200  
France
    397       374       374  
Turkey
    73       92       92  
 
                 
Total
    634       916       666  
 
                 
 
                       
Average Price:
                       
Oil ($/Bbl):
                       
United States
  $ 38.45     $ 28.17     $ 27.89  
France
    35.39       25.76       25.76  
Turkey
    31.05       24.65       24.65  
 
                 
Total
  $ 35.24     $ 26.30     $ 26.02  
 
                 
 
                       
Gas ($/Mcf):
                       
United States
  $ 5.65     $ 4.83     $ 4.74  
France
                 
Turkey
                 
 
                 
Total
  $ 5.65     $ 4.83     $ 4.74  
 
                 
 
                       
$/BOE:
                       
United States
  $ 35.83     $ 28.65     $ 28.05  
France
    35.39       25.76       25.76  
Turkey
    31.05       24.65       24.65  
 
                 
Total
  $ 35.00     $ 27.07     $ 26.47  
 
                 
 
(1)   This column sets forth production and prices for the year ended December 31, 2003, as if the U. S. mineral royalty asset sale had taken place January 1, 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 utilized 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

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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  
 
                 
     As noted above, we had 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.
Costs and expenses
     Lease operating
     Lease operating expenses increased $222,000, or 3%, from 2003 to 2004, 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 $2.2 million, or 62% in 2004. 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.

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     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, or 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 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 a $17.5 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.
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.
     In the quarter ended December 31, 2005 we recorded several income tax related adjustments. We released valuation allowances amounting to approximately $944,000 on our United States net operating loss carryforward due to revising our future projections for our United States operations. In Turkey, we released valuation allowances amounting to $401,000 due to revising our future projections of net taxable income in that country. Additionally, Turkey reduced its enacted income tax rate from approximately 33% to 20%, which resulted in us recording a decrease in deferred tax liabilities of approximately $917,000. We also recorded a $569,000 loss on involuntary conversion of assets due to the two separate incidents, in offshore Turkey in the Black Sea, which resulted in the loss of two caissons and three wells.

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    Three Months Ended
    December   September   June   March
    31,   30,   30,   31,
    (in thousands, except per share data)
For the year ended December 31, 2005:
                               
Total revenues
  $ 8,508     $ 8,770     $ 7,164     $ 6,414  
Total costs and expenses
    7,534       7,085       5,476       5,215  
Net income
    3,202       1,078       1,865       1,563  
Income available to common shares
    3,162       1,037       1,825       1,000  
Basic income per share
    0.20       0.07       0.13       0.08  
Diluted income per share
    0.19       0.07       0.12       0.08  
 
                               
For the year ended December 31, 2004:
                               
Total revenues
  $ 6,401     $ 5,631     $ 5,134     $ 3,862  
Total costs and expenses
    7,021       4,070       3,880       4,489  
Net income (loss)
    (190 )     1,886       1,335       21,986  
Income (loss) attributable to common shares
    (364 )     1,706       1,155       21,806  
Basic income (loss) per share
    (0.04 )     0.18       0.12       2.31  
Diluted income (loss) per share
    (0.03 )     0.15       0.11       1.84  
Off Balance Sheet Arrangements
     We do not have any off-balance sheet arrangements that have or are reasonably likely to have a current or material future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.
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, 2005, 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 2006 sales volumes at fixed prices, such a decrease would result in a reduction to oil and natural gas sales revenue of approximately $4.4 million.
     Foreign Currency Exchange Rates
     The functional currency of our French operations is the Euro. 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 Euros to U.S. dollars. Based on the net assets in our French operations at December 31, 2005, such a decrease would result in an unrealized loss of approximately $5.4 million due to foreign currency exchange rates.

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     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
     Corporate Disclosure Controls
     Evaluation of Disclosure Controls and Procedures
     The Company maintains disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). that are designed to provide reasonable assurance that the information required to be disclosed by us in reports filed under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission.
     We carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this annual report. Based on that evaluation, our Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer concluded that, as a result of the material weaknesses discussed below, our disclosure controls and procedures as of December 31, 2005 were not effective.
     Management’s Annual Report on Internal Control over Financial Reporting
     Our management is responsible for establishing and maintaining adequate internal control over financial reporting as that term is defined in Exchange Act Rule 13a-15(f) and 15d-15(e). Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting principles. Our control environment is the foundation for our system of internal control over financial reporting and is an integral part of our Code of Ethical Conduct and Business Practices and our Code of Ethics for the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer, which sets the tone of our

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Company. Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect our transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of our financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.
     In order to evaluate the effectiveness of our internal control over financial reporting as of December 31, 2005, as required by Section 404 of the Sarbanes-Oxley Act of 2002, our management conducted an assessment, including testing, based on the criteria set forth in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO Framework”). Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. In addition, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.
     Under the supervision and with the participation of our management, including our Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer we conducted an evaluation of the effectiveness of our internal control over financial reporting and, based on that assessment, identified three material weaknesses. A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. During the course of performing the 2005 year end audit, three material weaknesses were identified as follows: 1) the review of sensitive calculations and spreadsheets was insufficient to detect errors in such calculations and spreadsheets; 2) during the audit of the statutory accounts of our French affiliate, several audit adjustments were recorded to the statutory accounts, which affected the tax basis of our French oil and gas properties and 3) information technology system lacks adequate security and access controls resulting in inadequate segregation of duties and thus needs improvement in its global application.
     Based on our assessment, and because of the material weaknesses described above, management has concluded that our internal control over financial reporting was not effective as of December 31, 2005 to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes in accordance with generally accepted accounting principles.
     Hein & Associates LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Company included in this Annual Report on Form 10-K, has issued an audit report on management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005. The report, dated March 23, 2006, which expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an opinion that the Company had not maintained effective internal control over financial reporting as of December 31, 2005 based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) is included below.
     Changes in Internal Controls
     As of September 30, 2005 we reported a material weakness in our internal control over financial reporting due to lack of adequate review of an equity investee’s revenue recognition as reflected in its financial statements. We changed our procedures so that all transactions reported by an our unconsolidated equity investments will be reviewed and analyzed to ensure that the transactions have been properly recorded.
     To address the issues associated with the material weaknesses identified as of December 31, 2005, management has implemented several actions to remedy these material weaknesses and is currently evaluating the implementation of additional procedures that may be necessary to fully remediate the material weaknesses.
     Our control procedures surrounding the use of spreadsheets includes a review of each spreadsheet by a supervisory level employee and/or the Chief Accounting Officer or the Chief Financial Officer, as appropriate.

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During the year-end audit several errors were found in spreadsheets. We believe that the failure of the review process to detect the errors constituted a material weakness. We have instituted procedures whereby a more detailed and thorough review is performed on each calculation and spreadsheet and we are currently evaluating our processes to determine which of these can be automated through our financial reporting systems to decrease our reliance on spreadsheets.
     During the audit of the statutory accounts of our French subsidiary, several audit adjustments were recorded to the statutory accounts, which affected the tax basis of our French oil and gas properties. During the preparation of our deferred tax provision, our French staff failed to consider the statutory audit adjustments in determining the book – tax basis difference, which resulted in an error in our deferred tax provision for France. During the course of performing the year-end audit, our registered independent accounting firm detected the omission of the statutory audit adjustments and we have corrected our French deferred tax provision accordingly. We believe the failure to detect the omission of the statutory audit adjustments was a material weakness in our internal control over financial reporting. We have now implemented procedures to verify that all statutory audit adjustments are reviewed and analyzed to determine the potential impact on the deferred tax provision.
     Our review of the system of controls surrounding the information technology system revealed that 1) several employees could prepare and post entries, leading to a segregation of duties issue; 2) inadequate security over the proper storage of offsite back-up tapes and the periodic review of back-up tapes to ensure their accuracy; 3) security logs generated by the system were not periodically reviewed and terminated employees were not disconnected from the system in a timely manner and 4) several authorized users of our accounting system have access to modules that create additional segregation of duties issues. We believe our deficiencies in security over information technology systems constitute a material weakness. We are in the process of improving each employee’s access to the accounting system, so that no employee can prepare and post an entry and we have changed our procedures so that security logs generated by the system are periodically reviewed. We have improved the logical access to the accounting system. We are also reviewing additional procedures that will further strengthen our control over information technology systems. Management will continue to implement changes that are both organizational and process-focused to improve the control environment.
     Report of Independent Registered Public Accounting Firm
     We have audited management’s assessment, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting, that Toreador Resources Corporation (Toreador) did not maintain effective internal control over financial reporting as of December 31, 2005, because of the effect of the material weaknesses identified in management’s assessment, as follows: 1) the review of sensitive calculations and spreadsheets was insufficient to detect errors in such calculations and spreadsheets; 2) during the audit of the statutory accounts of our French subsidiary, several audit adjustments were recorded to the statutory accounts, which affected the tax basis of our French oil and gas properties and 3) information technology system lacks adequate security and access controls resulting in inadequate segregation of duties and thus needs improvement in its global application; based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Toreador’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the company’s internal control over financial reporting 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
     A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in

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accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
     Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
     A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. The following material weaknesses have been identified and included in management’s assessment. The material weaknesses were 1) the review of sensitive calculations and spreadsheets was insufficient to detect errors in such calculations and spreadsheets; 2) during the audit of the statutory accounts of our French subsidiary, several audit adjustments were recorded to the statutory accounts, which affected the tax basis of our French oil and gas properties and 3) information technology system lacks adequate security and access controls resulting in inadequate segregation of duties and thus needs improvement in its global application. These material weaknesses were considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2005 financial statements, and this report does not affect our report dated March 23, 2005 on those financial statements.
     In our opinion, management’s assessment that Toreador did not maintain effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, because of the effect of the material weaknesses described above on the achievement of the objectives of the control criteria, Toreador has not maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
Hein & Associates LLP
Dallas, Texas
March 23, 2005
ITEM 9B. Other Information.
     None.
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 2006 Annual Meeting of Stockholders, that will be filed with the Securities and Exchange Commission on or prior to April 7, 2006, and that is incorporated herein by reference.

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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 2006 Annual Meeting of Stockholders, that will be filed with the Securities and Exchange Commission on or prior to April 7, 2006, 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 2006 Annual Meeting of Stockholders, that will be filed with the Securities and Exchange Commission on or prior to April 7, 2006, 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 2006 Annual Meeting of Stockholders, that will be filed with the Securities and Exchange Commission on or prior to April 7, 2006, 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 2005 and 2004 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 Hein & Associates LLP and Ernst and Young LLP Related to Fiscal 2005 and 2004” and “Auditors — Pre-Approval Policies” in our Proxy Statement relating to the 2006 Annual Meeting of Stockholders, that will be filed with the Securities and Exchange Commission on or prior to April 7, 2006, 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:
1.   Index to Consolidated Financial Statements, Reports of Independent Registered Public Accounting Firms, Consolidated Balance Sheets as of December 31, 2005 and 2004, Consolidated Statements of Operations for the three years ended December 31, 2005, Consolidated Statements of Changes in Stockholders’ Equity for the three years ended December 31, 2005, Consolidated Statements of Cash Flows for the three years ended December 31, 2005, 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.
 
3.   Exhibits: The exhibits required to be filed by this Item 15 are set forth in the Index to Exhibits accompanying this report.

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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, 2006
 
       
By:
  /s/ G. Thomas Graves III    
 
 
 
   
G. Thomas Graves III, President and Chief Executive Officer

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     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, 2006
/s/ David M. Brewer
 
David M. Brewer
  Director   March 31, 2006
/s/ Herbert L. Brewer
 
Herbert L. Brewer
  Director   March 31, 2006
/s/ Peter L. Falb
 
Peter L. Falb
  Director   March 31, 2006
/s/ Thomas P. Kellogg
 
Thomas P. Kellogg
  Director   March 31, 2006
/s/ William I. Lee
 
William I. Lee
  Director   March 31, 2006
/s/ H.R. Sanders, Jr.
 
H.R. Sanders, Jr.
  Director   March 31, 2006
/s/ Nigel J. B. Lovett
 
Nigel J. B. Lovett
  Director   March 31, 2006
/s/ Nicholas Rostow
 
Nicholas Rostow
  Director   March 31, 2006
/s/ Herbert C. Williamson III
 
Herbert C. Williamson III
  Director   March 31, 2006
/s/ John Mark McLaughlin
 
John Mark Mclaughlin
  Chairman and Director   March 31, 2006
/s/ Douglas W. Weir
 
Douglas W. Weir
  Senior Vice President and Chief Financial Officer   March 31, 2006
/s/ Charles J. Campise
 
Charles J. Campise
  Vice President-Accounting and Chief Accounting Officer   March 31, 2006

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INDEX TO EXHIBITS
         
EXHIBIT        
NUMBER       DESCRIPTION
2.1
    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).
 
       
2.2
    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).
 
       
2.3
    Quota Purchase Agreement between Pogo Overseas Production BV, as Seller, and Toreador Resources Corporation, as Purchaser, dated as of June 7, 2005 (previously filed as Exhibit 2.1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on June 13, 2005, 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 (previously filed as Exhibit 4.1 to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2004, File No. 0-2517, and incorporated herein by reference).
 
       
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 No. 30, issued by Toreador Resources Corporation to Rich Brand amending and replacing Warrant dated July 22, 2004.
 
       
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).
 
       
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).

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EXHIBIT        
NUMBER       DESCRIPTION
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).
 
       
4.17
    Registration Rights Agreement dated September 27, 2005 by and between Toreador Resources Corporation and UBS Securities LLC and the other initial purchasers named in the purchase agreement (previously filed as Exhibit 4.18 to the Registration Statement on Form S-3 (333-129628) filed with the Securities and Exchange Commission on November 10, 2005, File No. 0-2517, and incorporated herein by reference).
 
       
4.18
    Indenture dated as of September 27, 2005 by and between Toreador Resources Corporation and The Bank of New York Trust Company, N.A. (previously filed as Exhibit 4.19 to the Registration Statement on Form S-3 (333-129628) filed with the Securities and Exchange Commission on November 10, 2005, 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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EXHIBIT        
NUMBER       DESCRIPTION
10.2+
    Toreador Royalty Corporation 1990 Stock Option Plan (previously filed as Exhibit 10.2 to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2004, File No. 0-2517, and incorporated herein by reference).
 
       
10.3+
    Amendment to Toreador Royalty Corporation 1990 Stock Option Plan, effective as of May 15, 1997 (previously filed as Exhibit 10.3 to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2004, File No. 0-2517, and incorporated herein by reference).
 
       
10.4+
    Toreador Royalty Corporation Amended and Restated 1990 Stock Option Plan, effective as of September 24, 1998 (previously filed as Exhibit 10.4 to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2004, File No. 0-2517, and incorporated herein by reference).
 
       
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 (previously filed as Exhibit 10.7 to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2004, File No. 0-2517, and incorporated herein by reference).
 
       
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+
    Toreador Resources Corporation 2005 Long-Term Incentive Plan (previously filed as Exhibit 10.1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on May 23, 2005, File No. 0-2517, and incorporated here by reference).
 
       
10.12+
    Form of Employee Restricted Stock Award (previously filed as Exhibit 10.2 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on May 23, 2005, File No. 0-2517, and incorporated here by reference).
 
       
10.13+
    Form of Outside Director Restricted Stock Award (previously filed as Exhibit 10.3 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on May 23, 2005, File No. 0-2517, and incorporated here by reference).
 
       
10.14+
    Form of Indemnification Agreement, dated as of April 25, 1995, between Toreador Royalty Corporation and each of the members of our Board of Directors (previously filed as Exhibit 10.11 to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2004, File No. 0-2517, and incorporated herein by reference).
 
       
10.15
    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).

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EXHIBIT        
NUMBER       DESCRIPTION
10.16
    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).
 
       
10.17
    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).
 
       
10.18
    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).
 
       
10.19
    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).
 
       
10.20
    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).
 
       
10.21
    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).
 
       
10.22
    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).
 
       
10.23
    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).
 
       
10.24
    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).
 
       
10.25
    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).
 
       
10.26
    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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EXHIBIT        
NUMBER       DESCRIPTION
10.27
    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).
 
       
10.28
    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).
 
       
10.29
    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).
 
       
10.30
    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).
 
       
10.31
    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).
 
       
10.32
    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 February 1, 2006, File No. 0-2517, and incorporated herein by reference).
 
       
10.33
    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 February 1, 2006, File No. 0-2517, and incorporated herein by reference).
 
       
10.34
    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).
 
       
10.35
    Warrant to Purchase Common Stock of Toreador Resources Corporation dated July 11, 2005, by and between Toreador Resources Corporation and Natexis Banques Popularis (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 13, 2005, File No. 0-2517, and incorporated herein by reference).
 
       
10.36
    Form of Subscription Agreement for September 16, 2005 Private Placement (previously filed as Exhibit 10.1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on September 22, 2005, File No. 0-2517, and incorporated herein by reference).
 
       
10.37
    Purchase Agreement dated November 22, 2005 by and among Toreador Resources Corporation, UBS Securities LLC and the other initial Purchasers named in Exhibit A attached thereto (previously filed as Exhibit 10.2 to the Registration Statement on Form S-3 (333-129628) filed with the Securities and Exchange Commission on November 10, 2005, File No. 0-2517, and incorporated herein by reference).
 
       
12.1*
    Computation of Ratio of Earnings to Fixed Charges.
 
       
21.1*
    Subsidiaries of Toreador Resources Corporation.
 
       
23.1*
    Consent of Hein & Associates LLP.
 
       
23.2*
    Consent of LaRoche Petroleum Consultants, Ltd.

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Table of Contents

         
EXHIBIT        
NUMBER       DESCRIPTION
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.
 
       
31.3*
    Certification of Chief Accounting 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, Chief Financial Officer and Chief Accounting 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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Item 8. Financial Statements
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

F-1


Table of Contents

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, 2005 and 2004, and the related consolidated statements of operations, changes in stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2005. 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. 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 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, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005 in conformity with United States generally accepted accounting principles.
     We have also audited, in accordance with standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Our report dated March 23, 2006 expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an opinion that the Company had not maintained effective internal control over financial reporting as of December 31, 2005 based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
Hein & Associates LLP
Dallas, Texas
March 23, 2006

F-2


Table of Contents

TOREADOR RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEET
(in thousands)
                 
    December 31,     December 31,  
    2005     2004  
ASSETS
               
Current assets:
               
Cash and cash equivalents
  $ 92,507     $ 4,977  
Accounts receivable
    18,506       2,619  
Income taxes receivable
    4,736       611  
Other
    3,243       1,187  
 
           
Total current assets
    118,992       9,394  
 
           
 
               
Oil and gas properties, net, using successful efforts method of accounting
    134,035       79,667  
Investments in unconsolidated entities
    2,251       1,467  
Goodwill
    2,487       2,487  
Other assets
    5,415       1,659  
 
           
 
  $ 263,180     $ 94,674  
 
           
 
               
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
Current liabilities:
               
Accounts payable and accrued liabilities
  $ 22,479     $ 6,634  
Current portion of long—term debt
          37  
Convertible debenture — related party
    810        
Income taxes payable
    908       1,633  
 
           
Total current liabilities
    24,197       8,304  
 
           
 
               
Long-term accrued liabilities
    1,043       1,136  
Long-term debt
    5,000        
Long-term asset retirement obligation
    2,225       2,331  
Deferred income tax liability
    10,221       10,660  
Convertible senior notes
    86,250        
Convertible subordinated notes
          7,500  
Convertible debenture – related party
          1,485  
 
           
Total liabilities
    128,936       31,416  
 
           
Stockholders’ equity:
               
Preferred stock, Series A-1, $1.00 par value, 4,000,000 shares authorized; liquidation preference of $1,800,000; 72,000 and 154,000 shares issued
    72       154  
Common stock, $0.15625 par value, 30,000,000 shares authorized;16,142,824 and 11,724,146 shares issued
    2,522       1,832  
Additional paid-in capital
    108,001       37,523  
Retained earnings
    31,346       24,323  
Accumulated other comprehensive income (loss)
    (3,261 )     1,960  
Deferred compensation
    (1,902 )      
Treasury stock at cost, 721,027 shares
    (2,534 )     (2,534 )
 
           
Total stockholders’ equity
    134,244       63,258  
 
           
 
  $ 263,180     $ 94,674  
 
           
See accompanying notes to the consolidated financial statements.

F-3


Table of Contents

TOREADOR RESOURCES CORPORATION
CONSOLIDATED STATEMENT OF OPERATIONS
(in thousands, except share data)
                         
    Year ended December 31,  
    2005     2004     2003  
Revenue:
                       
Oil and natural gas sales
  $ 30,856     $ 22,336     $ 17,845  
Loss on commodity derivatives
          (1,322 )     (1,017 )
Lease bonuses and rentals
          14       18  
 
                 
Total revenues
    30,856       21,028       16,846  
 
                 
 
                       
Operating costs and expenses:
                       
Lease operating expense
    9,111       6,873       6,651  
Exploration and acquisition
    2,830       3,402       2,411  
Dry hole and abandonment
    1,739              
Depreciation, depletion and amortization
    4,243       3,538       3,246  
Loss on involuntary conversion of assets
    569              
Impairment of oil and natural gas properties
                171  
General and administrative
    6,818       5,646       3,494  
 
                 
Total operating costs and expenses
    25,310       19,459       15,973  
 
                 
Operating income
    5,546       1,569       873  
 
                       
Other income (expense):
                       
Equity in earnings (loss) of unconsolidated investments
    222       (18 )     22  
Gain (loss) on sale of properties and other assets
    12       (336 )     80  
Foreign currency exchange gain
    148       5,044       979  
Turkish currency remeasurement
          (1,140 )      
Interest and other income
    1,706       396       173  
Interest expense
    (1,632 )     (1,611 )     (1,193 )
 
                 
Total other income
    456       2,335       61  
 
                 
Income from continuing operations before income taxes
    6,002       3,904       934  
Income tax benefit
    (1,659 )     (3,576 )     (266 )
 
                 
Income from continuing operations
    7,661       7,480       1,200  
Income from discontinued operations, net of tax
    47       17,539       1,182  
 
                 
Net income
    7,708       25,019       2,382  
Preferred dividends
    (684 )     (714 )     (500 )
 
                 
Income available to common shares
  $ 7,024     $ 24,305     $ 1,882  
 
                 
 
                       
Basic income per share from:
                       
Continuing operations
  $ 0.49     $ 0.71     $ 0.07  
Discontinued operations
          1.83       0.13  
 
                 
 
  $ 0.49     $ 2.54     $ 0.20  
 
                 
 
                       
Diluted income per share from:
                       
Continuing operations
  $ 0.47     $ 0.60     $ 0.07  
Discontinued operations
          1.37       0.13  
 
                 
 
  $ 0.47     $ 1.97     $ 0.20  
 
                 
 
                       
Weighted average shares outstanding:
                       
Basic
    14,274       9,571       9,338  
Diluted
    15,207       12,817       9,347  
See accompanying notes to the consolidated financial statements.

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TOREADOR RESOURCES CORPORATION
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY
(in thousands)
                                                                                 
                                                    Accumulated                      
    Preferred     Preferred     Common     Common     Additional             Other             Treasury     Total  
    Stock     Stock     Stock     Stock     Paid-in     Retained     Comprehensive     Deferred     Stock     Stockholders’  
    (Shares)     ($)     (Shares)     ($)     Capital     Earnings     Income (loss)     Compensation     ($)     Equity  
Balance at December 31, 2002
    197     $ 197       10,059     $ 1,572     $ 30,510     $ (1,864 )   $ 2,140     $     $ (2,534 )   $ 30,021  
Cash payment of preferred Dividends
                                  (500 )                       (500 )
Issuance of preferred stock
    123       123                   2,952                                 3,075  
Issuance of warrants
                            100                                 100  
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  
 
                                                           
Balance at December 31, 2003
    320       320       10,059       1,572       33,562       18       4,384             (2,534 )     37,322  
Cash payment of preferred dividends
                                  (714 )                             (714 )
Conversion of preferred stock
    (166 )     (166 )     1,037       162       4                                
Conversion of convertible debenture
                100       16       659                               675  
Exercise of stock options
                528       82       2,286                               2,368  
Tax benefit from exercise of stock options
                            1,012                               1,012  
Net income
                                  25,019                         25,019  
Realized gain on foreign transactions
                                        (5,044 )                 (5,044 )
Foreign currency translation adjustment
                                        1,197                   1,197  
Change in deferred tax liabilities
                                        1,423                   1,423  
 
                                                           
Balance at December 31, 2004
    154       154       11,724       1,832       37,523       24,323       1,960             (2,534 )     63,258  
Cash payment of preferred dividends
                                  (187 )                       (187 )
Conversion of preferred stock
    (82 )     (82 )     512       80       2                                
Conversion of notes payable
                915       143       6,270                               6,413  
Conversion of convertible debenture
                100       16       659                               675  
Issuance of common stock
                2,244       350       55,568                               55,918  
Exercise of stock options
                493       77       2,475                               2,552  
Tax benefit of stock option exercises
                            2,557                               2,557  
Exercise of warrants
                20       3       167                               170  
Common shares issued in payment of preferred dividends
                20       3       495       (498 )                        
Issuance of restricted stock
                115       18       2,285                   (2,303 )            
Amortization of deferred stock compensation
                                              401             401  
Net income
                                  7,708                         7,708  
Foreign currency translation adjustment
                                        (5,221 )                 (5,221 )
 
                                                           
Balance at December 31, 2005
    72     $ 72       16,143     $ 2,522     $ 108,001     $ 31,346     $ (3,261 )   $ (1,902 )   $ (2,534 )   $ 134,244  
 
                                                           
See accompanying notes to the consolidated financial statements.

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TOREADOR RESOURCES CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(in thousands)
                         
    Year Ended December 31,  
    2005     2004     2003  
Cash flows from operating activities:
                       
Net income
  $ 7,708     $ 25,019     $ 2,382  
Adjustments to reconcile net income to net cash provided by operating activities:
                       
Depreciation and amortization
    4,243       3,538       3,925  
Amortization of deferred debt issuance cost
          384        
Dry hole and abandonment
    1,739       583       1,271  
Remeasurement of Turkish currency
          1,140        
Loss on involuntary conversion of assets
    569              
Impairment of oil and natural gas properties
                171  
Unrealized gain (losses) on commodity derivatives
          (1,159 )     123  
Gain on sale of properties
          (28,406 )     (120 )
Equity in (earnings) loss of unconsolidated investments
    (222 )     18       (22 )
Stock based compensation
    401              
Realized gains on foreign currency transactions
          (5,044 )      
Other operating activities
    (12 )           39  
(Increase) decrease in accounts and notes receivables
    (20,383 )     960       491  
(Increase) decrease in other assets
    (3,021 )     829       (1,246 )
Increase (decrease) in accounts payable and accrued liabilities
    16,729       (354 )     (318 )
Increase (decrease) in income taxes payable
    (675 )     1,379       757  
Increase (decrease) in deferred income tax liability
    2,456       1,181       (574 )
Other
          26        
 
                 
Net cash provided by operating activities
    9,532       94       6,879  
 
                 
Cash flows from investing activities:
                       
Expenditures for property and equipment
    (68,010 )     (16,743 )     (3,713 )
Proceeds from the sale of properties and equipment
          42,125       424  
Distributions from unconsolidated entities
    191       255        
Proceeds from sale of marketable securities
                48  
Investments in unconsolidated subsidiaries
    (753 )     (1,211 )      
 
                 
Net cash provided by (used in) investing activities
    (68,572 )     24,426       (3,241 )
 
                 
Cash flows from financing activities:
                       
Payment for debt issuance costs
    (4,165 )     (1,239 )      
Net borrowings (repayments) under revolving credit arrangements
    4,963       (28,779 )     (4,544 )
Proceeds from issuance of common stock, net
    58,640       2,368       3,075  
Issuance of warrants
                100  
Proceeds from issuance of notes payable
    86,250       7,500        
Payment of preferred dividends
    (187 )     (714 )     (500 )
 
                 
Net cash provided by (used in) financing activities
    145,501       (20,864 )     (1,869 )
 
                 
Net increase in cash and cash equivalents
    86,461       3,656       1,769  
Effects of foreign currency translation on cash and cash equivalents
    1,069       (1,498 )     74  
Cash and cash equivalents, beginning of period
    4,977       2,819       976  
 
                 
Cash and cash equivalents, end of period
  $ 92,507     $ 4,977     $ 2,819  
 
                 
Supplemental disclosures:
                       
Cash paid during the period for interest
  $ 196     $ 1,736     $ 1,541  
Cash paid during the period for income taxes
    2,690       5,250       629  
See accompanying notes to the consolidated financial statements.

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TOREADOR RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 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 2005 presentation, with no effect on net income.
NOTE 2 — SIGNIFICANT ACCOUNTING POLICIES
     USE OF ESTIMATES
     The preparation of the consolidated financial statements requires management of the Company to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.
     The Company’s estimates of crude oil and natural gas reserves are the most significant. All of the reserve data in this Form 10-K are estimates. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may be different from the quantities of crude oil and natural gas that are ultimately recovered.
     Other items subject to estimates and assumptions include the carrying amounts of property, plant and equipment and goodwill; asset retirement obligations and deferred income tax assets. Actual results could differ significantly 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, substantially all of which exceeds 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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TOREADOR RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
     For the year ended December 31, 2005 and 2004 we had $40 million and $0, respectively, in time deposits bearing interest at 4.06% and maturing on April 7, 2006.
     For the year ended December 31, 2005 and 2004 we had $6.2 million and $4.4 million, respectively, on deposit in foreign banks.
     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, 2005 or 2004. 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 “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 approximate fair value, at December 31, 2005, due to the short-term nature or maturity of the instruments.
     Long-term debt and the convertible debenture approximate fair value based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for debt of the same maturities.
     On December 31, 2005 the convertible senior notes were trading at $84.50, which would equal a fair market value of approximately $72.9 million.
     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 commodity or foreign currency hedges in 2005.
     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, 2005 and 2004, we had no accounts 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, 2005 and 2004, other current assets included $951,000, and $530,000 of inventory, respectively. Those amounts consist of technical equipment and crude oil held in storage tanks. We record inventories at the lower of actual cost or market.

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TOREADOR RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
     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
     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. 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 2005 and 2004, and $171,000 in 2003. The impairments in 2003 were the result of overall decreases in the quantity of reserves on maturing properties.
     ASSET RETIREMENT OBLIGATIONS
     We account for our asset retirement obligations in accordance with Statement No. 143, Accounting for Asset Retirement Obligations (“Statement 143”), which requires us 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, we either settle the obligation for its recorded amount or incur a gain or loss upon settlement.
     The following table summarizes the changes in our asset retirement liability during the years ended December 31, 2005 and 2004:

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TOREADOR RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                 
    2005     2004  
    (in thousands)  
Asset retirement obligation January 1
  $ 2,331     $ 1,789  
Asset retirement accretion expense
    153       127  
Foreign currency exchange gain (loss)
    (297 )     436  
Property additions
    38       39  
Plugging cost
          (37 )
Property sold
          (23 )
 
           
Asset retirement obligation at December 31
  $ 2,225     $ 2,331  
 
           
     GOODWILL
     We account for goodwill in accordance with 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).
     We review annually the value of goodwill recorded or more frequently if impairment indicators arise. We recognized no goodwill impairment during 2005 or 2004. 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, 2005 is approximately $2.5 million.
     REVENUE RECOGNITION
     Our French crude oil production accounts for the majority of our sales. We sell our French crude oil to Elf Antar France S.A. (“ELF”), and recognize the related revenues when the production is delivered to ELF’s refinery, typically via truck. At the time of delivery to the plant, title to the crude oil transfers to ELF. The terms of the contract with ELF state that the price received for oil sold will be the arithmetic mean of all average daily quotations of Dated Brent published in Platt’s Oil Market Wire for the month of production less a specified differential per barrel. The pricing of oil sales is done on the first day of the month following the month of production. In accordance with the terms of the contract, payment is made within six working days of the date of issue of the invoice. The contract with ELF is automatically extended for a period of one year unless either party cancels it in writing no later than six months prior to the beginning of the next year. We periodically review ELF’s payment timing to ensure that receivables from ELF for crude oil sales are collectible.
     We recognize revenue for our remaining production when the quantities are delivered to or collected by the respective purchaser. Title to the produced quantities transfers to the purchaser at the time the purchaser collects or receives the quantities. Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices. The purchasers of such production have historically made payment for crude oil and natural gas purchases within thirty and sixty days of the end of each production month, respectively. We periodically review the difference between the dates of production and the dates we collect payment for such production to ensure that receivables from those purchasers are collectible. All transportation costs are accounted for as a reduction of oil and natural gas sales revenue.

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TOREADOR RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
     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:
                         
    For the Year Ended December 31,
    2005   2004   2003
    (in thousands, except per share data)
Income applicable to common shares, as reported
  $ 7,024     $ 24,305     $ 1,882  
Basic earnings per share reported
    0.49       2.54       0.20  
Diluted earnings per share reported
    0.47       1.97       0.20  
Stock-based compensation costs under the intrinsic value method included in net income reported, net of related tax
                 
Pro-forma stock-based compensation costs under the fair value method, net of related tax
    75       671       249  
Pro-forma income applicable to common shares, as under the fair-value method
    6,949       23,634       1,633  
Pro-forma basic earnings per share under the fair value method
    0.49       2.47       0.17  
Pro-forma diluted earnings per share under the fair value method
    0.46       1.86       0.17  
     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:
                         
    For the Year Ended December 31,
    2005   2004   2003
Dividend yield per share
                 
Volatility
    70.9 %     43 - 54 %     42 %
Risk-free interest rate
    4.0 %     3.3 - 4.6 %     2.8 %
Expected lives
  5 years     3 years     10 years  
     FOREIGN CURRENCY TRANSLATION
     The functional currency of the countries in which we operate is the U.S. dollar in the United States, the Euro in France, the New Turkish Lira in Turkey, the Lei in Romania and the Forint in Hungary. 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.
     Prior to 2004, t he functional currency in Turkey was the Turkish Lira. In 2004, Turkey was deemed to be a highly inflationary economy, and therefore the functional currency was 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

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TOREADOR RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
     In 2005, management made the determination that the economy in Turkey was no longer highly inflationary and the functional currency was changed to the New Turkish Lira. The impact of this change was not material to our financial position or results of operations as of and for the year ended December 31, 2005.
     INCOME TAXES
     We are subject to income taxes in the United States, France, Turkey, Hungary and Romania. 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 reduce the future tax benefits to the amount, 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, 2005 is $10.2 million.
     NEW ACCOUNTING PRONOUNCEMENTS
     In December 2004, the FASB issued SFAS No. 123(R), “Share-Based Payment.” SFAS No. 123(R) revises SFAS No. 123, “Accounting for Stock-Based Compensation,” and focuses on accounting for share-based payments for services provided by employee to employer. The statement requires companies to expense the fair value of employee stock options and other equity-based compensation at the grant date. The statement does not require a certain type of valuation model, and either a binomial or Black-Scholes model may be used. During the first quarter of 2005, the Securities and Exchange Commission (SEC) approved a new rule for public companies to delay the adoption of this standard. In April 2005, the SEC took further action to amend Regulation S-X to state that the provisions of SFAS No. 123(R) will be effective beginning with the first annual or interim reporting period of the registrant’s first fiscal year beginning on or after June 15, 2005 for all non-small business issuers. As a result, we will not adopt this SFAS until the first quarter of 2006. At this time, management does not believe that the adoption of SFAS No. 123(R) will materially impact our operating results, financial position, or our future cash flows.
     In April 2005, the FASB issued FASB Staff Position (FSP) FAS 19-1 “Accounting for Suspended Well Costs.” This staff position amends FASB Statement No. 19 “Financial Accounting and Reporting by Oil and Gas Producing Companies” and provides guidance about exploratory well costs to companies who use the successful efforts method of accounting. The position states that exploratory well costs should continue to be capitalized if: 1) a sufficient quantity of reserves are discovered in the well to justify its completion as a producing well and 2) sufficient progress is made in assessing the reserves and the well’s economic and operating feasibility. If the exploratory well costs do not meet both of these criteria, these costs should be expensed, net of any salvage value. Additional annual disclosures are required to provide information about management’s evaluation of capitalized exploratory well costs. In addition, the Staff Position requires the annual disclosure of: 1) net changes from period to period of capitalized exploratory well costs for wells that are pending the determination of proved reserves, 2) the amount of exploratory well costs that have been capitalized for a period greater than one year after the completion of drilling and 3) an aging of exploratory well costs suspended for greater than one year with the number of wells it related to. Further, the disclosures should describe the activities undertaken to evaluate the reserves and the projects, the information still required to classify the associated reserves as proved and the estimated timing for completing the evaluation. For our disclosures, refer to Note 7 of the Notes to the Consolidated Financial Statements.

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TOREADOR RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
     In May 2005, the FASB issued Statement No. 154 “Accounting Changes and Error Corrections—a replacement of APB Opinion No. 20 and FASB Statement No. 3”. This Statement replaces APB No. 20, Accounting Changes, and FASB Statement No. 3, Reporting Accounting Changes in Interim Financial Statements, and changes the requirements for the accounting for and reporting of a change in accounting principle. This statement applies to all voluntary changes in accounting principle. It also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. ABP No. 20 previously required that most voluntary changes in accounting principle be recognized by including in net income of the period of the change the cumulative effect of changing to the new accounting principle. This Statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. The guidance in this Statement will not impact our consolidated financial position, results of operations, or cash flows.
     On February 6, 2006, the FASB issued Statement 155, “Accounting for Certain Hybrid Instruments- an amendment of FASB Statements No. 133 and 140.” The statement amends Statement 133 to permit fair value measurement for certain hybrid financial instruments that contain an embedded derivative, provides additional guidance on the applicability of Statement 133 and 140 to certain financial instruments and subordinated concentrations of credit risk. The new standard is effective for the first fiscal year that begins after September 16, 2006. As of December 31, 2005 the Company has not entered into nor do we expect to enter into any agreements that would be subject to this Statement.
NOTE 3 — ACQUISITION
     In June 2005, we acquired 100% of Pogo Hungary Ltd., a wholly owned subsidiary of Pogo Producing Company. The results of operations are included in our consolidated financial statements effective with the date of acquisition through December 31, 2005. The purchase price was approximately $9 million and was allocated as follows:
         
    Value Allocated  
Cash and other current assets
  $ 274  
Plant, property and equipment – materials and supplies inventory
    3,128  
Non-producing lease cost
    5,945  
Other assets
    413  
Accounts payable
    (760 )
 
     
Total purchase price allocation
  $ 9,000  
 
     
     The Company made this acquisition because it met the requirements of our long-term strategic plan to seek properties in our existing core areas.
NOTE 4 — COMPREHENSIVE INCOME
The following table presents the components of comprehensive income (loss), net of related tax:
                         
    For the Year Ended December 31,  
    2005     2004     2003  
Net income
  $ 7,708     $ 25,019     $ 2,382  
Foreign currency translation adjustment and other
    (5,221 )     (2,424 )     2,244  
 
                 
Comprehensive income
  $ 2,487     $ 22,595     $ 4,626  
 
                 

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TOREADOR RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
     NOTE 5 — 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 are 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,                
    2005             2004             2003          
    (in thousands, except per share data)          
Basic earnings per share:                                                
Numerator
                                               
Income from continuing operations, net of income tax
  $ 7,661             $ 7,480             $ 1,200          
Income from discontinued operations, net of income tax
    47               17,539               1,182          
 
                                         
Net income
    7,708               25,019               2,382          
Less: dividends on preferred shares
    684               714               500          
 
                                         
Income available to common shares
  $ 7,024             $ 24,305             $ 1,882          
 
                                         
Denominator
                                               
Common shares outstanding
    14,274               9,571               9,338          
Basic earnings per share from:
                                               
Continuing operations
  $ 0.49             $ 0.71             $ 0.07          
Discontinued operations
                  1.83               0.13          
 
                                         
Basic income per share
  $ 0.49             $ 2.54             $ 0.20          
 
                                         
 
Diluted earnings per share:
                                               
Numerator
                                               
Income from continuing operations, net of income tax
  $ 7,661             $ 7,480             $ 1,200          
Income from discontinued operations, net of income tax
    47               17,539               1,182          
 
                                         
Net income
    7,708               25,019               2,382          
Plus: interest on convertible debt, net of related income tax
    100               265               N/A       (1 )
Less: dividends on preferred shares
    (684 )             N/A       (2 )     (500 )        
 
                                         
Income available to common shares
  $ 7,124             $ 25,284             $ 1,882          
 
                                         
Denominator
                                               
Common shares outstanding
    14,274               9,571               9,338          
Common stock options and warrants
    709               523               9          
Conversion of preferred shares
    N/A       (1 )     1,997               N/A       (1 )
Conversion of 7.85% notes payable
    43               410               N/A       (1 )
Conversion of 5.0% notes payable
    N/A       (1 )           (3 )           (3 )
Conversion of debentures
    181               316               N/A       (1 )
 
                                         
Diluted shares outstanding
    15,207               12,817               9,347          
 
                                         
Diluted earnings per share from:
                                               
Continuing operations
  $ 0.47             $ 0.60             $ 0.07          
Discontinued operations
                  1.37               0.13          
 
                                         
Diluted income per share
  $ 0.47             $ 1.97             $ 0.20          
 
                                         

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TOREADOR RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
(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.
 
(3)   5% Senior Convertible Notes were issued on September 27, 2005.
NOTE 6 — ACCOUNTS AND NOTES RECEIVABLE
     Accounts receivable consisted of the following:
                 
    December 31,  
    2005     2004  
    (in thousands)  
Insurance receivable
  $ 10,566     $  
Accrued oil and natural gas sales receivable
    4,872       2,566  
Trade receivables
    1,921       26  
Other receivables
    1,147       27  
 
           
 
  $ 18,506     $ 2,619  
 
           
     The insurance receivable is the amount we expect to receive from the two separate incidents, in offshore Turkey in the Black Sea, which resulted in the loss of two caissons and three wells.
     Accrued oil and natural gas sales receivables are due from either purchasers of oil and gas or operators in oil and natural gas wells for which the Company owns an interest. Oil and natural gas sales are generally unsecured and such amounts are generally due within 30 days after the month of sale.
     Trade receivables are the amounts due from our joint interest partners in our Black Sea operation. These receivables are generally due within 15 days after receipt of monthly joint interest billing.
     Other receivables are accrued interest receivable, at December 31, 2005 on time deposits, value added tax refunds and travel advances to employees.
     We periodically review the collectability of accounts receivable and record a valuation allowance for those accounts which are, in our judgment, unlikely to be collected. We have not had any significant credit losses in the past and we believe our accounts receivable are fully collectable. Accordingly, no allowance for doubtful accounts has been provided. Schedule II, Valuation and Qualifying Accounts, was omitted because there were no allowances or other valuation or qualifying accounts.

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TOREADOR RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 7 — PROPERTIES AND EQUIPMENT
     Oil and Natural Gas Properties consist of the following:
                 
    December 31,  
    2005     2004  
    (in thousands)  
Licenses and concessions
  $ 3,441     $ 3,505  
Non-producing leaseholds
    48,876       11,556  
Producing leaseholds and intangible drilling costs
    93,274       74,847  
Lease and well equipment
    2,197       1,926  
Furniture, fixtures and office equipment
    1,894       1,449  
 
           
 
    149,682       93,283  
Accumulated depreciation, depletion and amortization
    (15,647 )     (13,616 )
 
           
Total oil and natural gas properties
  $ 134,035     $ 79,667  
 
           
     In 2005 two separate incidents occurred, in offshore Turkey in the Black Sea, which resulted in the loss of two caissons and three wells. Both of these incidents were insured. In December 2005 the Company received notice that the insurance company has reserved $10.6 million (net to the Company) for potential payment of this claim. As of December 31, 2005 the book value of the wells and caissons was $11.1 million. The difference of $569,000 has been recorded as a loss on involuntary conversion.
     During 2005 we did not sell any material oil and natural gas properties. In 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.
     The Company capitalizes exploratory well costs until a determination is made that the well has found proved reserves or is deemed noncommercial, in which case the well costs are immediately charged to exploration expense.
     The following table reflects the Company’s capitalized exploratory well activity and does not include amounts that were capitalized and subsequently expensed in the same period:
                         
    December 31,  
    2005     2004     2003  
    (in thousands)  
Capitalized exploratory well cost, beginning of the period
  $ 2,307     $     $  
Additions to capitalized exploratory well costs pending determination of proved reserves
    1,042       2,307        
Reclassified to plant, property and equipment based on determination of proved reserves
    (2,307 )            
 
                 
Capitalized exploratory well costs, end of period
  $ 1,042     $ 2,307     $  
 
                 
     The following table provides an aging of capitalized exploratory well costs (suspended well costs), as of December 31 of each year, based on the date the drilling was completed:
                         
    December 31,  
    2005     2004     2003  
    (in thousands)  
Capitalized exploratory well cost that have been capitalized for a period of one year or less
  $ 1,042     $ 2,307     $  
Capitalized exploratory well cost that have been capitalized for a period greater than one year
                 
 
                 
Balance at the end of the period
  $ 1,042     $ 2,307     $  
 
                 

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TOREADOR RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 8 — INVESTMENTS IN UNCONSOLIDATED SUBSIDIARIES
     In February 2004, we acquired 45% of ePsolutions. Based in Austin, Texas, ePsolutions is a software and energy services company in the electric industry and deregulated energy markets. ePsolutions is the developer of emPower system, a CIS, EDI and Billing solution for energy companies within deregulated energy markets. At December 31, 2005 and 2004 our investment in ePsolutions amounted to $1.3 million and $799,000, respectively. For the years ended December 31, 2005 and 2004 we advanced $753,000 and $1.2 million, respectively, and we recorded equity in the loss of ePsolutions of $238,000 in 2005 and a loss 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, 2005 and 2004, our investment in EnergyNet amounted to $832,000 and $554,000, respectively. We recorded equity in the earnings of EnergyNet of $409,000 in 2005, $279,000 in 2004, and $6,500 in 2003. We recorded a dividend from EnergyNet of $131,250 in 2005 and $131,250 in 2004.
     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 $104,000 and $112,000 at December 31, 2005 and 2004, respectively. We recorded equity in the earnings of Capstone amounting to $51,000 in 2005, $15,000 in 2004 and $15,000 in 2003. We received a distribution of $60,000 in 2005 and $25,000 from Capstone in both 2004 and 2003.
NOTE 9 — LONG-TERM DEBT
     Long-term debt consisted of the following:
                 
    December 31,  
    2005     2004  
    (in thousands)  
Revolving line of credit with Texas Capital Bank, N.A.
  $     $ 37  
Revolving line of credit with Natexis Banques Populaires
    5,000        
Convertible subordinated notes
    86,250        
Convertible debenture-related party
    810       1,485  
 
           
 
    92,060       1,522  
Less: current portion
    (810 )     (37 )
 
           
 
  $ 91,250     $ 1,485  
 
           
     CONVERTIBLE SENIOR NOTES DUE OCTOBER 1, 2025
     On September 27, 2005, we sold $75 million of Convertible Senior Notes due October 1, 2025 (“Notes”) to qualified institutional buyers pursuant to Rule 144A of the Securities Act of 1933. The Company also granted the initial purchasers the option to purchase an additional $11.25 million aggregate principal amount of Notes to cover over-allotments. The option was exercised on September 30, 2005. The total principal amount of Notes issued was $86.25 million and total net proceeds were approximately $82.2 million. We incurred approximately $4.1 million of costs associated with the issuance of the Notes; this cost has been recorded in other assets on the balance sheet and will be recorded to interest expense over the life of the Notes. The net proceeds have been and will be used for general corporate purposes, including funding a portion of the Company’s 2005 and 2006 exploration and development activities.
     The Notes bear interest at a rate of 5% per annum and can be converted into common stock at an initial conversion rate of 23.3596 shares of common stock per $1,000 principal amount of Notes, subject to adjustment (equivalent to a conversion price of approximately $42.81 per share). The Company may redeem the Notes, in whole or in part, on or after October 6, 2008, and prior to October 1, 2010, for cash at a redemption price equal to 100% of the principal amount of Notes to be redeemed, plus any accrued and unpaid interest, if the closing price of its common stock exceeds 130% of the conversion price over a specified period. On or after October 1, 2010, the Company may redeem the Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of

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TOREADOR RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Notes to be redeemed, plus any accrued and unpaid interest, irrespective of the price of its common stock. Holders may convert their Notes at any time prior to the close of business on the business day immediately preceding their stated maturity, and holders may, upon the occurrence of certain fundamental changes, and on October 1, 2010, October 1, 2015, and October 1, 2020, require the Company to repurchase all or a portion of their Notes for cash in an amount equal to 100% of the principal amount of such Notes, plus any accrued and unpaid interest.
     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 (6.59% total rate at December 31, 2005) 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 time all unpaid principal and interest are due. We are subject to a commitment fee of one half (1/2) of the applicable margin, 1.25% as of December 31, 2005, on the available and unused facility borrowings. Under the $15.0 million facility, borrowings of approximately $8.0 million are available at December 31, 2005. 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, 2005, 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% (6.75% total rate at December 31, 2005) 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, 2005, we had approximately $3.3 million available for borrowings. The $25.0 million facility requires monthly interest payments until January 1, 2009 at which time all unpaid principal and interest are due. We are subject to a commitment fee of one-half of one percent (1/2 of 1%) as of December 31, 2005, on the available and unused facility borrowings. The $25 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, 2005, we were in compliance with all covenants.
     REVOLVING LINE OF CREDIT WITH BARCLAYS BANK, PLC
     As part of our acquisition of Madison Oil Company, 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 U. S. mineral royalty asset 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.

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TOREADOR RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
     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 Euros) 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 on the statement of operations for the year ended December 31, 2004.
     CONVERTIBLE SUBORDINATED NOTES
     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% notes 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% notes 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.
     CONVERTIBLE DEBENTURE
     As part of our acquisition of Madison Oil Company, we assumed and amended a convertible debenture (“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. The maturity date remains March 31, 2006. 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. On August 10, 2005, PHD Partners converted $675,000 of the second amended and restated debenture into 100,000 shares of our common stock, resulting in an outstanding principal balance of $810,000 at December 31, 2005. Interest payments made to PHD Partners LP were $73,195, $352,416 and $108,437 in 2005, 2004 and 2003, respectively.

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Table of Contents

TOREADOR RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
     The following table summarizes the principle maturities under our long-term debt arrangements at December 31, 2005:
                                                         
    (In thousands)  
    2006     2007     2008     2009     2010     Thereafter     Total  
Long-term debt
  $ 810     $ 2,000     $     $ 3,000     $     $ 86,250     $ 92,060  
 
                                         
NOTE 10 — CAPITAL
     Toreador had 72,000 and 154,000 shares of nonvoting Series A-1 Convertible Preferred Stock outstanding at December 31, 2005 and 2004, respectively. 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