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Toreador Resources 10-K 2007
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, 2006
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:
     
Title of each Class:   Name of each exchange on which registered:
     
COMMON STOCK, PAR VALUE
$.15625 PER SHARE
  NASDAQ GLOBAL MARKET
Securities registered pursuant to Section 12(g) of the Exchange Act: None
 
     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 and non-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, 2006 was $317,007,097. (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 8, 2007 was 16,215,829 shares.
DOCUMENTS INCORPORATED BY REFERENCE
     Portions of the registrant’s Proxy Statement for the 2007 Annual Meeting of Stockholders, expected to be filed on or before April 30, 2007, are incorporated by reference into Part III of this Form 10-K
 
 

 


 

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 Summary Sheet: 2007 Director Compensation
 Herbert C. Williamson III Restricted Stock Award Agreement
 Nigel Lovett Restricted Stock Award Agreement
 Nicholas Rostow Restricted Stock Award Agreement
 G. Thomas Graves III Stock Award Agreement
 Security Agreement
 Quota Charge Agreement
 Computation of Ratio of Earnings to Fixed Charges
 Subsidiaries
 Consent of Grant Thornton 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 Chief Executive Officer, Chief Financial Officer 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 (together with its direct and indirect subsidiaries, “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, 2006, we held interests in approximately 5.5 million gross acres and approximately 4.2 million net acres, of which 94.4% is undeveloped. At December 31, 2006, our estimated net proved reserves were 16 million barrels of oil equivalent (MMBOE).
     Historically, our operations have been concentrated in the Paris Basin in France and in south central onshore Turkey and offshore Turkey in the Black Sea. These two regions accounted for 86.9% of our total proved reserves as of December 31, 2006 and approximately 69% of our total production for the year ended December 31, 2006.
     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
     New Secured Revolving Facility
     On December 28, 2006, we entered into a loan and guarantee agreement with International Finance Corporation for our operations in Turkey and Romania. The loan and guarantee agreement provides for two separate facilities, the first of which (the “$10 million facility”) is unsecured and was fully funded on December 28, 2006. The second facility (the “$25 million facility”) is a secured revolving facility which was fully funded on March 2, 2007. The $25 million facility has a current maximum facility amount of $25 million which maximum facility amount will increase to $40 million when the projected total borrowing base amount exceeds $50 million.
     Change in President and Chief Executive Officer
     In January 2007, Mr. G. Thomas Graves III resigned as President and Chief Executive Officer. Following Mr. Graves’ resignation, the Board of Directors elected Mr. Nigel J. B. Lovett to the position of President and Chief Executive Officer. Mr. Lovett has been a member of our Board of Directors since January 2006 and prior to becoming our President and Chief Executive Officer had more than 26 years experience as an investment banker.
     Update on current operations
          Turkey
     Two new gas discoveries, the Guluc-1 well, flowed approximately 17 million cubic feet of gas per day through a 48/64-inch choke at a flowing pressure of approximately 1,180 psi. and the Alapli-1 well tested approximately 6.8 million cubic feet of gas per day through a 32/64-inch choke at a flowing pressure of 1,064 psi.

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     The topsides for the Akkaya production tripod have been set and secured. The next step is to tie the three Akkaya wells into the production manifold and then tie in the offshore pipeline. Once this process is complete, the wells will be ready to be put on production.
     The topsides for the Dogu Ayazli tripod are on location, waiting for seas to moderate before attempting to lift the structure onto the tripod.
          France
     The St. Loup D’Ordon-1 exploration well was drilled to test a Neocomian channel sand to the northeast of Toreador’s Neocomian Field Complex in the Paris Basin. The well did not encounter commercial hydrocarbons and has been plugged and abandoned.
          Romania
     The Naeni-6 well is drilling ahead at approximately 1,460 meters depth after intermediate casing was set and is expected to reach total depth in late March 2006. A rig has been moved onto the Lapos-2 exploration well location and will spud as soon as the necessary permits are granted.
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 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 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

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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 31 exploration and three exploitation permits covering approximately 2.5 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 ten successful delineation wells, The Cayagzi-1 and Kuzey Akkaya-1 delineation wells were drilled to total depth and did not encounter hydrocarbons, and were plugged and abandoned. We have drilled seven development wells, Dogu Ayazlý-1, Akkaya-2, Dogu Ayazlý-2, Akkaya-3, Bayhanlý-1, Akcakoca-3 and Akcakoca-4 in 2006, two of which required a floating rig, and completed the first phase of pipeline and facility construction with production to begin in March or April of 2007. The first phase of infrastructure development includes: setting up three 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.
     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 approximately 325 km. high resolution 2D marine seismic survey on the permit in preparation for an exploration program, which we expect to commence in mid-2007. In February 2007 we spudded the Alapli # 1 well.
     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 50% working interest in the permit covering 422,000 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 in exchange for an option for a 50% interest in this permit. In 2006, we completed approximately 1500 km. 2D marine seismic program and we are currently evaluating the seismic to pick the first drilling location. The first two wells on the Thrace Black Sea permits will be drilled in 2007.

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     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 intend to acquire 240 km. of 2D marine seismic survey in 2007, and we will then conduct a full analysis of existing technical data on these two permits in which we hold a 100% working interest.
     Eastern Black Sea Permit
     We have 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. In early 2007, we completed approximately 90 km. of total 230 km. 2D marine seismic program in 2006. The rest of the program will be completed in mid-2007.
     Buyukdag Permit
     The Buyukdag permits cover approximately 39,450 acres located in Eastern Turkey in which we hold 100% working interest. We have already initiated re-processing of existing 2D seismic data in the permit area and plan to acquire approximately 300 km. 2D onshore seismic survey in 2007.
     Southeast Turkey Permits
          Bakuk
     Onshore in southeast Turkey, at the Syrian border, we were recently granted an exploration permit on one block of approximately 95,897 acres. The block is west of some existing oil and gas fields. We are operator of and hold 100% working interest in this permit. We are reprocessing all 2D seismic data which were acquired by the previous operator prior to drilling an exploration well in the permit area.
          Van
     The Van permit area is surrounded by the most prolific oil fields in southeast Turkey and it covers approximately 965,000 acres. We are currently gathering geological and geophysical data to define prospective structures. We are the operator of and hold a 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 2007, once a gas contract has been concluded. A review of the extensive 2D and 3D seismic surveys, conducted by the prior owner, delineated multiple prospects of which one was drilled in June of 2006. This well was a geophysical and geological success however the inert content exceeded the economic threshold and, therefore, the well was subsequently plugged and abandoned.
     The necessary permits and drilling applications are currently being prepared which should enable the drilling of several additional prospects, each of which is testing a variety of features and concepts – stratigraphic and structural in nature.

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     Tompa Block
     Three exploratory wells and two re-entries were undertaken in the southern Tompa Block prospect. The exploration wells failed to encounter commercial hydrocarbons, however; the data and knowledge gained in the exploration process have escalated several leads to the prospect category. The necessary applications are also being prepared which should enable these prospects to be drilled in the late 2007 or early 2008 timeframe.
     Plans to tie-in the two completed re-entry wells are progressing and first production from the Tompa Block is expected in early 2008. Negotiations for the oil and gas sale contract are well advanced.
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. In December 2006, we spudded the first exploratory well on this prospect the Naeni # 2 bis and in January the well was plugged and abandoned. In February 2007, we spudded the second well the Naeni # 6, the results should be known by the end of the first quarter.
     Moinesti Permit
     We are the operator and hold 100% of this exploration permit, covering approximately 300,000 acres.
     Fauresti Rehabilitation Permit
     We are the operator and hold 100% of this rehabilitation permit. During 2006 we completed the production facility and are currently producing approximately 3.2 MMCFD and 50 BBLS of condensate per day.
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 24,200 net acres as well as three exploration permits covering approximately 232,200 net acres.
     Charmottes Field
     We hold a 100% working interest and operate the permit covering the Charmottes Field, which currently has 9 producing oil wells. The field is produced from two separate reservoirs, one at 1500 meters (4,500 feet) in the fractured limestone of the Dogger and the second one from the Triassic sandstones at 2500 meters (7,500 feet) in the Donnemarie formation. Production is approximately 200 BOPD from both reservoirs
     Neocomian Complex
     Pursuant to two exploitation permits, we operate and hold a 100% working interest in the permits covering the Neocomian Fields, that is comprised of a group of four oil fields. The complex currently has 86 producing oil wells and production is approximately 920 BOPD.
     Courtenay Permit
     We hold a 100% working interest and are the operator of this permit covering approximately 183,000 net acres which surrounds the Neocomian Fields. An exploration well was drilled was February 2007 and was plugged and abandoned.

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     Nemours Permit
     We hold a 331/2% working interest in this permit covering approximately 15,700 net acres which is operated by Lundin Petroleum AB.
     Aufferville Permit
     We hold a 100% working interest and operate this permit covering approximately 33,100 acres. Two exploration wells will be drilled in April 2007 on the Dogger limestone objective to test two distinct prospects.
United States
     We hold non-operating working interests in 990 gross wells (52 net wells) primarily in Texas, Oklahoma, New Mexico, Kansas and Louisiana.
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 to engage in exploration, exploitation and production.
     Turkey
     We have 31 exploration permits covering seven geographic regions. The Western Black Sea permits have been extended through November 2007 and prior to the date of expiration we expect to have completed our minimum work commitment to extend these permits for an additional three to four years. The Southeast Turkey and the Eastern Black Sea permits expire in September 2009, the Thrace Black Sea and the Central Black Sea permits expire in the first quarter of 2009 and the Van and Buyukbey permits expire in May and July 2010, respectively. 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.
     Our Turkish proved reserves are:
                                                 
            At December 31, 2006
    Permit                   Post-Expiration Proved   Percent of Proved
    Expiration   Total Proved Reserves   Reserves   Reserves
Property   Year   (MBbl)   (MMCF)   (MBbl)   (MMCF)   Post-Expiration
Zeynel
    2013 (1)     37               18               48.65 %
Cendere (2 permits)
    2012 (1)     628               223               35.50 %
S Akcakoca Sub-Basin
    2007 (2)             21,425               21,425       100.00 %
 
(1)   Exploitation Permit
 
(2)   Exploration Permit
     Hungary
     We have two exploration permits that expire in March 2009. In 2006, we re-completed two wells that were drilled by the previous operator on the Szolnok Permit. We are currently in the process of connecting the wells to the sales pipeline. Our Hungarian proved reserves are:
                                                 
            At December 31, 2006
    Permit                   Post-Expiration Proved   Percent of Proved
    Expiration   Total Proved Reserves   Reserves   Reserves
Property   Year   (MBbl)   (MMCF)   (MBbl)   (MMCF)   Post-Expiration
Szolnok
    2009       1       950             542       57.05 %

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     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 would be less than $8 million and as of December 31, 2006 we have spent $7.3 million. We have not yet established proved reserves on the Moinesti and Viperesti permits.
     The following is information relating to our Romanian proved reserves, all of which relate to the pre-expiration period of the Fauresti Rehabilitation permit:
                         
            At December 31, 2006
    Permit Expiration   Oil   Gas
Property   Year   (MBbl)   (MMcf)
Fauresti
    2015       41       3,041  
     France
     We hold three French exploration permits: Aufferville, Nemours and Courtenay. No proved reserves have been established in these permits. The Courtenay, Aufferville and Nemours permits expire in 2007, however due to drilling that has been completed or is planned for 2007 we anticipate that we will fulfill our minimum work commitment and anticipate that the permits will automatically be extend for a period of three to four years. 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, 2006
            Total Proved   Post-Expiration   Percent of Proved
    Permit Expiration   Reserves   Proved Reserves   Reserves
Property   Year   (MBbl)   (MBbl)   Post-Expiration
Neocomian Fields
    2011       8,064       5,854       72.60 %
Charmottes Field
    2013       1,564       640       40.92 %
     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 and undeveloped 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, 2006 and 2005. 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,
    2006   2005
U.S.
               
Proved developed:
               
Oil (MBbl)
    699       792  
Gas (MMcf)
    4,068       5,225  
Total (MBOE)
    1,377       1,663  
Proved undeveloped:
               
Oil (MBbl)
    1       1  
Gas (MMcf)
    60       70  
Total (MBOE)
    11       12  
Discounted present value at 10% (pretax) (in thousands) (1)
  $ 19,324     $ 31,299  
Standardized measure of proved reserves (in thousands)
  $ 13,264     $ 21,033  
 
               
FRANCE
               
Proved developed:
               
Oil (MBbl)
    6,770       7,688  
Proved undeveloped:
               
Oil (MBbl)
    2,858       3,290  
Discounted present value at 10% (pretax) (in thousands) (1)
  $ 131,824     $ 164,075  
Standardized measure of proved reserves (in thousands)
  $ 86,190     $ 109,129  
 
               
TURKEY
               
Proved developed:
               
Oil (MBbl)
    405       378  
Proved undeveloped:
               
Oil (MBbl)
    260       261  
Gas (MMcf)
    21,425       6,476  
Total (MBOE)
    3,831       1,340  
Discounted present value at 10% (pretax) (in thousands) (1)
  $ 89,913     $ 17,930  
Standardized measure of proved reserves (in thousands)
  $ 84,3330     $ 15,788  
 
               
ROMANIA
               
Proved developed:
               
Oil (MBbl)
    41       24  
Gas (MMcf)
    3,040       3,486  
Total (MBOE)
    548       605  
Discounted present value at 10% (pretax) (in thousands) (1)
  $ 12,941     $ 11,490  
Standardized measure of proved reserves (in thousands)
  $ 13,388     $ 10,676  
 
               
HUNGARY
               
Proved developed:
               
Oil (MBbl)
    1        
Gas (MMcf)
    950        
Total (MBOE)
    159        
Discounted present value at 10% (pretax) (in thousands) (1)
  $ 2,625     $  
Standardized measure of proved reserves (in thousands)
  $ 970     $  
 
               
COMBINED
               
Proved developed:
               
Oil (MBbl)
    7,916       8,882  
Gas (MMcf)
    8,058       8,711  
Total (MBOE)
    9,259       10,334  
Proved undeveloped:
               
Oil (MBbl)
    3,119       3,552  
Gas (MMcf)
    21,485       6,546  
Total (MBOE)
    6,700       4,643  
Total proved:
               
Oil (MBbl)
    11,035       12,434  
Gas (MMcf)
    29,543       15,257  
Total (MBOE)
    15,959       14,977  
Discounted present value at 10% (pretax) (in thousands) (1)
  $ 256,627     $ 224,795  
Standardized measure of proved reserves (in thousands)
  $ 198,142     $ 156,626  
 
(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%.

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     Reserves were estimated using oil and natural gas prices and production and development costs in effect on December 31, 2006 and 2005, 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, 2006. Productive wells include wells currently producing or capable of production.
                                                 
    Gross (1)   Net (2)
    Oil   Gas   Total   Oil   Gas   Total
United States
    682       308       990       21.04       31.35       52.39  
France
    131             131       130.50             130.50  
Turkey
    15             15       2.65             2.65  
Romania
          5       5             5.00       5.00  
 
(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, 2006.
                                                 
    Developed Acreage   Undeveloped Acreage   Total Acreage
    Gross   Net   Gross   Net   Gross   Net
United States
    254,140       37,503       86,893       39,509       341,033       77,012  
France
    24,260       24,260       263,730       232,215       287,990       256,475  
Turkey
    31,730       3,059       3,495,684       2,465,331       3,527,414       2,468,390  
Romania
                625,325       625,325       625,325       625,325  
Hungary
                764,237       764,237       764,237       764,237  
 
                                               
Total
    310,130       64,822       5,235,869       4,126,617       5,545,999       4,201,439  
 
                                               
     Undeveloped acreage includes only those acres on which wells have not been drilled or completed to permit the production of commercial quantities of oil and natural gas regardless of whether or not the acreage contains proved reserves.

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Drilling Activity
     The following table shows our drilling activities on a gross and net basis for the years ended 2006, 2005 and 2004.
                                                 
    Year ended December 31,
    2006   2005   2004
    Gross (1)   Net (2)   Gross (1)   Net (2)   Gross (1)   Net (2)
UNITED STATES
                                               
Development:
                                               
Gas (3)
    12       0.14       7       0.08       3       0.75  
Oil (4)
    36       0.15       20       0.04       4       0.20  
Abandoned (5)
                2       0.26              
 
                                               
Total
    48       0.29       29       0.38       7       0.95  
 
                                               
 
                                               
Exploratory
                                               
Gas (3)
    5       0.35       1       0.25              
Oil (4)
                2       0.45              
Abandoned (5)
    8       0.99                   3       0.50  
 
                                               
Total
    13       1.34       3       0.70       3       0.50  
 
                                               
 
                                               
FRANCE
                                               
Development:
                                               
Oil (4)
                5       5.00       7       7.00  
Abandoned (5)
                                   
 
                                               
Total
                5       5.00       7       7.00  
 
                                               
 
                                               
Exploratory:
                                               
Oil (4)
                1       0.50              
Abandoned (5)
                                   
 
                                               
Total
                  1       0.50              
 
                                               
 
                                               
TURKEY
                                               
Development:
                                               
Gas (3)
    7       2.57       4       1.80              
Abandoned (5)
    2       0.56       1       0.40              
 
                                               
Total
    9       3.13       5       2.20              
 
                                               
 
                                               
Exploratory
                                               
Oil (6)
                            1       0.75  
Gas (7)
                            1       0.40  
 
                                               
Abandoned (5)
                                   
 
                                               
Total
                            2       1.15  
 
                                               
 
                                               
HUNGARY
                                               
Exploratory
                                               
Abandoned (5)
    1       1.00                          
 
(1)   “Gross” is the number of wells in which we have a working interest.
 
(2)   “Net” is the aggregate obtained by multiplying each gross well by our after payout percentage working interest.
 
(3)   “Gas” means natural gas wells that are either currently producing or are capable of production.
 
(4)   “Oil” means producing oil wells.
 
(5)   “Abandoned” means wells that were dry when drilled and were abandoned without production casing being run.
 
(6)   “Oil” means oil shows were found and temporarily suspended awaiting further work.
 
(7)   “Gas” means gas flow was tested and temporarily suspended awaiting further work.

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Net Production, Unit Prices And Costs
     The following table summarizes our oil, natural gas and natural gas liquids production, net of royalties, for the periods indicated. It also summarizes calculations of our total average unit sales prices and unit costs.
                                         
    United                          
    States     France     Turkey     Romania     Total  
Year Ended December 31, 2006
                                       
Production:
                                       
Oil (Bbls)
    58,449       441,759       68,342       7,728       576,278  
Daily average (Bbls/Day)
    160       1,210       187       21       1,578  
Gas (Mcf)
    489,793                   502,192       991,985  
Daily average (Mcf/Day)
    1,342                   1,376       2,718  
Daily average (BOE/Day)
    384       1,210       199       250       2,043  
Unit prices:
                                       
Average oil price ($/Bbl)
  $ 61.29     $ 61.74     $ 56.10     $ 52.71     $ 60.90  
Average gas price ($/Mcf)
    6.38                   3.57       4.96  
Average equivalent price ($/BOE)
    47.88       61.74       56.10       24.06       53.96  
Unit costs ($/BOE):
                                       
Lease operating
  $ 15.71     $ 16.36     $ 11.60     $ 7.86     $ 14.75  
Exploration and acquisition
    13.44       0.98       11.69       7.09       5.32  
Depreciation, depletion and amortization
    10.92       7.06       10.94       22.85       10.17  
Dry hole cost and impairment of oil and gas properties
    12.40                         4.65  
General and administrative
    43.15       4.31       11.81       6.09       13.25  
 
                             
Total
  $ 95.62     $ 28.71     $ 46.04     $ 43.89     $ 48.14  
 
                             
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             49.86  
Unit costs ($/BOE):
                                       
Lease operating
  $ 13.49     $ 13.34     $ 10.96     $     $ 13.13  
Exploration and acquisition
    8.05       2.50       4.46             4.71  
Depreciation, depletion and amortization
    7.63       8.70       8.44             8.40  
Dry hole cost
                26.84             2.79  
General and administrative
    33.51       2.33       7.22             10.70  
 
                             
Total
  $ 62.68     $ 26.87     $ 54.92     $     $ 39.73  
 
                             
Year Ended December 31, 2004
                                       
Production:
                                       
Oil (Bbls)
    68,129       396,806       73,118             538,053  
Daily average (Bbls/Day)
    187       1,087       200             1,474  
Gas (Mcf)
    546,118                         546,118  
Daily average (Mcf/Day)
    1,496                         1,496  
Daily average (BOE/Day)
    436       1,087       200             1,723  
Unit prices:
                                       
Average oil price ($/Bbl)
  $ 38.87     $ 35.39     $ 31.05     $     $ 35.24  
Average gas price ($/Mcf)
    5.81                         5.81  
Average equivalent price ($/BOE)
    35.44       35.39       31.05             34.90  
Unit costs ($/BOE):
                                       
Lease operating
  $ 11.00     $ 12.31     $ 10.44     $     $ 11.76  
Exploration and acquisition
    8.55       0.36       41.41             7.20  
Depreciation, depletion and amortization
    7.84       5.93       6.93             6.53  
General and administrative
    26.41       3.66       24.74             11.86  
 
                             
Total
  $ 53.80     $ 22.26     $ 83.52     $     $ 37.35  
 
                             

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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 in 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 2006 was approximately $764,000.
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. Oil production in Turkey is sold to refineries in the southern part of the country. Once gas production starts in the Sub Akcakkoca Sub-Basin, the gas will be sold through the national pipeline.
     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.
     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. Since 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

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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 Licenses
     In order to carry out exploration and development of mineral interests or to place these into commercial production, we may require certain licenses and permits from various governmental authorities. There can be no guarantee that we will be able to obtain all necessary licenses and permits that may be required. In addition, such licenses and permits are subject to change and there can be no assurances that any application to renew any existing licenses or permits will be approved. See “Item 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 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

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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 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);

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    Comprehensive Environmental Response, Compensation and Liability Act (CERCLA);
 
    Resource Conservation and Recovery Act (RCRA);
 
    Clean Air Act (CAA); and
 
    Safe Drinking Water Act (SDWA).
     Our domestic activities also are controlled by state regulations promulgated under comparable state statutes. We also are subject to regulations governing the handling, transportation, storage and disposal of naturally occurring radioactive materials that are found in our oil and natural gas operations. Civil and criminal fines and penalties may be imposed for noncompliance with these environmental laws and regulations. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking certain activities, limit or prohibit other activities due to protected areas or species, can impose certain substantial liabilities for the cleanup of pollution, impose certain reporting requirements, and can require substantial expenditures for compliance.
     Under OPA and CWA, our release of oil and hazardous substances into or upon waters of the United States, adjoining shore lines and wetlands and offshore areas could result in our being held responsible for the (1) costs of remediating a release, (2) administrative and civil penalties and/or criminal fines, (3) OPA specified damages such as loss of use and (4) natural resource damages. The extent of liability could be extensive depending upon the circumstances of the release. Liability can be joint and several and without regard to fault. The CWA also may impose permitting requirements for certain discharges of pollutants and requirements to develop Spill Prevention Control and Countermeasure Plans and Facility Response Plans to address potential discharges of oil into or upon waters of the United States and adjoining shorelines.
     CERCLA and comparable state statutes, also known as Superfund laws, can impose joint, several and retroactive liability, without regard to fault or the legality of the original conduct, on specified classes of persons for the release of a “hazardous substance” into the environment. In practice, clean-up costs are usually allocated among various responsible parties. Liability can arise from conditions on properties where operations are conducted and/or from conditions at third-party disposal facilities where wastes from operations were sent. Although CERCLA, as amended, currently exempts petroleum (including oil, natural gas and natural gas liquids) from the definition of hazardous substance, some similar state statutes do not provide such an exemption. Additionally, our operations may involve the use or handling of other materials that may be classified as hazardous substances under CERCLA and similar state statutes. We cannot assure 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.

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     If in the course of our routine oil and natural gas operations, surface spills and leaks, including casing leaks of oil or other materials occur, we may incur penalties and costs for waste handling, remediation and third-party actions for damages. 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 Title III of CERCLA and similar state statutes require us to organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.
Employees
     As of March 8, 2007, we employed 96 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 16 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 Securities Exchange Act of 1934 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.

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     “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.
     “BOPD” Barrels of oil per day.
     “BTU.” British Thermal Unit.
     “DEVELOPMENT WELL” A well drilled within the proved boundaries of an oil or natural gas reservoir with the intention of completing the stratigraphic horizon known to be productive.
     “DISCOUNTED PRESENT VALUE.” The present value of proved reserves is an estimate of the discounted future net cash flows from each property at the specified date, or as otherwise indicated. Net cash flow is defined as net revenues, after deducting production and ad valorem taxes, less future capital costs and operating expenses, but before deducting federal income taxes. The future net cash flows have been discounted at an annual rate of 10% to determine their “present value.” The present value is shown to indicate the effect of time on the value of the revenue stream and should not be construed as being the fair market value of the properties. In accordance with Securities and Exchange Commission rules, estimates have been made using constant oil and natural gas prices and operating costs at the specified date, or as otherwise indicated.
     “DRY HOLE.” A development or exploratory well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.
     “EXPLORATORY WELL” A well drilled to find and produce oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir, or to extend a known reservoir.
     “GROSS ACRES” or “GROSS WELLS.” The total number of acres or wells, as the case may be, in which a working or any type of royalty interest is owned.
     “MBbl.” One thousand Bbls.
     “MBOE.” One thousand BOE.
     “Mcf.” One thousand cubic feet of natural gas.
     “MMcf” One million 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.

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     “PROVED UNDEVELOPED RESERVES.” The oil and natural gas reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery techniques is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
     “ROYALTY INTEREST.” An interest in an oil and natural gas property entitling the owner to a share of oil and natural gas production free of production costs.
     “STANDARDIZED MEASURE.” Under the Standardized Measure, future cash flows are estimated by applying year-end prices, adjusted for fixed and determinable changes, to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end costs to determine pretax cash inflows. Future income taxes are computed by applying the statutory tax rate to the excess inflows over a company’s tax basis in the associated properties.
     Tax credits, net operating loss carryforwards and permanent differences also are considered in the future tax calculation. Future net cash inflows after income taxes are discounted using a 10% annual discount rate to arrive at the Standardized Measure.
     “UNDEVELOPED ACREAGE.” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
     “WORKING INTEREST.” The operating interest (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.
Item 1A. Risk Factors
     Our growth depends on our ability to obtain additional capital and we may not be able to obtain sufficient additional capital to grow our business.
     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.
     Our projected capital expenditures budget for 2007 is estimated at $81.5 million.

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     Currently, we have a $25 million reserve-based credit facility secured by our U.S. assets (the “Texas Capital Facility”); however, our ability to borrow under this facility is limited because of our borrowing base restrictions. At December 31, 2006, there was $5.6 million outstanding under the Texas Capital Facility and approximately $550,000 in additional borrowings were available under the facility. On March 2, 2007, our $15 million reserved-based credit facility was retired from the funds received from the new $25 million facility with the International Finance Corporation. See Note 8 to the Note to the Consolidated Financial Statements.
     On December 28, 2006, we entered a loan and guarantee agreement with International Finance Corporation for our operations in Turkey and Romania. The loan and guarantee agreement provides for two separate facilities, the first of which is the $10 million facility which is unsecured and the second of which is the $25 million facility which is a secured revolving facility. The $25 million facility has a current maximum facility amount of $25 million which maximum facility amount will increase to $40 million when the total borrowing base amount exceeds $50 million.
     We also have outstanding $86.25 million of Convertible Senior Notes due October 1, 2025.
     At December 31, 2006, our debt to equity ratio was .77 to 1, and this ratio and our increased leverage may make it difficult for us to obtain additional funding, especially additional debt.
     No assurance can be given that we will have the needed additional capital to fund our growth under these facilities or from existing operations, including our projected 2007 capital expenditures budget. If we are not able to obtain the additional capital necessary to fund our projected 2007 capital expenditures budget, we currently believe that we will reduce our capital expenditure by approximately $30 to $40 million by delaying exploratory projects until such time as we have the additional capital. We may also seek additional capital by (i) forward selling our crude oil and natural gas production; (ii) obtaining industry partners in our exploratory prospects; (iii) selling our non-core properties; or (iv) a combination of these actions. Ultimately, if we cannot obtain additional capital, we will be required to curtail our operations further by delaying our projects. In addition, we may also experience constraints on our cash available to fund our on-going operations.
     In addition, to the extent that we are not able to obtain additional capital by the incurrence of additional debt, we may need to issue additional equity. Any such issuance of equity could be materially dilutive to our outstanding equity and equity holders. We are currently considering possible issuances of additional equity securities in order to fund our capital expenditures budget for 2007 which equity securities may be sold at a discount to current market prices and may result in substantial dilution to our equity holders.
     The terms of our indebtedness may restrict our ability to grow.
     As noted above, our debt to equity ratio may limit our ability to obtain additional indebtedness. Additionally. our new loan and guarantee agreement with the International Finance Corporation restricts our ability to incur additional indebtedness because of financial ratios that we must meet. Our Texas Capital Facility also restricts the ability of the borrowers, two of our domestic subsidiaries, to incur additional indebtedness because of financial ratios that we must meet.
     Thus, we may not be able to obtain sufficient capital to grow our business, effectuate our business strategy and may lose opportunities to acquire interests in oil and natural gas properties or related businesses because of our inability to fund such growth. If we are unable to secure the necessary capital to fund our 2007 capital expenditure program, we will reduce our budget by $30 to $40 million, by delaying exploratory projects until we have the additional capital.
     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.

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     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 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 us 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.

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     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, 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. Although we recently replaced G. Thomas Graves III when he resigned in January 2007 with Nigel Lovett, there can be no assurance that if we lose the services of one or more of our other executive officers that we will be able to attract and retain qualified management, geologists, geophysicists and other technical personnel. If we are unable to attract and retain qualified management, 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.
     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

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the timing, extent and cost of development and operations. As a result of these third-party operations, we cannot control the timing and volumes of production. Transportation space on the gathering systems and pipelines we utilize is occasionally limited or unavailable due to repairs or improvements to facilities or due to space being utilized by other companies that have priority transportation agreements. Our access to transportation options also can be affected by U.S. federal and state regulation and foreign regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand. These factors and the availability of markets are beyond our control. If market factors dramatically change, the financial impact on our revenues could be substantial and could adversely affect our ability to produce and market oil and natural gas.
     We may not be able to renew our permits 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 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

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generally with technology-related industries, including obsolescence, competition, concentration and the inability to obtain the necessary capital for future growth.
     Failure to maintain effective internal controls could have a material adverse effect on our operations and our stock price.
     We are subject to Section 404 of the Sarbanes-Oxley Act which requires annual management assessment of the effectiveness of our internal control over financial reporting and a report by our independent auditors addressing our internal controls and management’s assessment. Effective internal controls are necessary for us to produce reliable financial reports. If, as a result of deficiencies in our internal controls, we cannot provide reliable financial reports, our business decision process may be adversely affected, our business and operating results could be harmed, we could be deemed in violation of our lending covenants, investors could lose confidence in our reported financial information and the price of our stock could decrease.
     During the evaluation of disclosure controls and procedures for the year ended December 31, 2006, we concluded that our disclosure controls and procedures were not effective in reaching a reasonable level of assurance of achieving management’s desired controls and procedures objectives and that we had material weaknesses in our internal control over financial reporting. There is no guarantee that we will be able to resolve these material weaknesses or avoid have other material weaknesses in the future.
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 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.

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     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.
     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.

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     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 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
     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 8, 2007 were $34.49 and $17.14 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 our Convertible Senior 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 Convertible Senior Notes, volatility in the price of our common stock may depress the trading price of the Convertible Senior 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 Convertible Senior Notes.
     Our common stock is quoted on the Nasdaq Global 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:

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    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 price of our common stock.
     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 8, 2007, our officers and directors as a group beneficially owned approximately 14 % of our common stock (including shares issuable upon exercise of stock options held by officers and directors and upon conversion of our Series A-1 Convertible Preferred Stock held by directors and affiliates of certain directors). Due to their large ownership percentage interest, they may be able 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 our loan and guarantee agreement with the International Finance Corporation 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 Convertible Senior 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.
     We may issue equity securities in the future which may depress the trading price of our common stock and may dilute the interests of our existing stockholders.
     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 .
     Any issuance of equity securities, including the issuance of shares upon conversion of the Convertible Senior Notes, could dilute the interests of our existing stockholders 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 8, 2007, there were:

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    673,870 shares of our common stock issuable upon exercise of outstanding options, at a weighted average exercise price of $5.13 per share, of which options to purchase 660,536 shares were exercisable;
 
    98,760 shares of our common stock issuable upon exercise of outstanding warrants, at a weighted average exercise price of $19.81 per share, of which 98,760 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); and
 
    421,915 shares of our common stock available for future grant under our equity incentive plan.
     Additionally, we are currently considering possible issuances of additional equity securities in order to fund our capital expenditures budget for 2007 which equity securities may be sold at a discount to current market prices and may result in substantial dilution to our equity holders.
     Our leverage may harm our financial condition and results of operations.
     Our total consolidated long-term debt as of December 31, 2006 was approximately $112.8 million and represented approximately .77 of our total capitalization as of that date. Our level of indebtedness could have important consequences to investors, because:
    it could affect our ability to satisfy our payment obligations under our indebtedness;
 
    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.
     Provisions in our charter documents, the indenture for the Convertible Senior 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 Convertible Senior Notes.
     If a “change in control” (as defined in the indenture for the Convertible Senior Notes ) occurs, holders of the Convertible Senior 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 for the Convertible Senior Notes), 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 Convertible Senior 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.

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     Certain provisions of our charter documents may adversely impact our stockholders.
     Our charter documents provide our board of directors the right to issue preferred stock upon such terms and conditions as it deems to be in 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.
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 gain 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.
Black Sea Incidents
     In October 2005, in an incident involving a vessel owned by Micoperi Srl, the Ayazli 2 and Ayazli 3 wells were damaged, and subsequently had to be re-drilled. We and our co-venturers have made a claim in respect of the cost of re-drilling and repeating flow-testing. The amount claimed is presently approximately $10.8 million before interest, subject to adjustment when the actual cost of flow-testing the re-drilled wells is known. In addition, we and our co-venturers have claimed to recover back from Micoperi a sum of about $8.7 million paid to Micoperi under the contract between us, our co-venturers and Micoperi. Micoperi has made a cross-claim for about $6.8 million in respect of sums allegedly due to Micoperi under the contract between us, our co-venturers and Micoperi. Micoperi has also asserted a claim that the arrest of the vessel “MICOPERI 30” at Palermo, Italy was wrongful and have asserted a claim for damages in respect of such allegedly wrongful arrest. We and our co-ventures have received security from Micoperi by way of a letter of undertaking from their insurers, and have provided security to Micoperi in respect of their cross-claims by way of a bank guarantee of $7.8 million. The claims and cross-claims are subject to the jurisdiction of the English Court; however, neither side has yet commenced any court proceedings. All the amounts stated above are gross and our share would be equal to 36.75%. We have accrued our portion of the unpaid invoices and is accounting for the potential receivable from Microperi as a gain contingency. Accordingly, the potential gain has not been recorded.
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, 2006.

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PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Common Stock
     Our shares of common stock, par value $.15625 per share, are traded on the Nasdaq Global Market 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 Global Market (previously known as the 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
2006:
               
Fourth quarter
  $ 27.95     $ 16.83  
Third quarter
    28.84       16.52  
Second quarter
    34.53       24.08  
First quarter
    32.44       20.81  
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  
     As of March 8, 2007, there were 16,215,329 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 Global Market on March 8, 2007 was $23.01.
     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 credit facility with the International Finance Corporation restricts our ability to pay dividends to only those required by law and on the Series A-1 Convertible Preferred Stock.
     Dividends on our Series A-1 Convertible Preferred Stock are paid on a quarterly basis per the terms of such series. Cash dividends totaling $162,000, $186,000 and $714,000 were paid for the years ended December 31, 2006, December 31, 2005 and December 31, 2004, 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 paid in cash only at a quarterly rate of $0.5625 per share of Series A-1 Convertible Preferred Stock. On December 31, 2006, there were 72,000 shares of Series A-1 Convertible Preferred Stock outstanding.
     During 2006, 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 or Quarterly Reports on Form 10-Q.
     During the fourth quarter 2006, we did not repurchase any of our registered equity securities.

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COMPARE 5-YEAR CUMULATIVE TOTAL RETURN
AMONG TOREADOR RESOURCES CORP.,
NASDAQ MARKET INDEX AND HEMSCOTT GROUP INDEX
(PERFORMANCE GRAPH)
ASSUMES $100 INVESTED ON JAN. 01, 2002
ASSUMES DIVIDEND REINVESTED
FISCAL YEAR ENDING DEC. 31, 2006

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Item 6. Selected Financial Data
The following selected financial information (which is not covered by the report of an independent registered public accounting firm) is summarized from our results of operations for the five-year period ended December 31, 2006 and as well as selected consolidated balance sheet data as of December 31, 2006, 2005, 2004, 2003 and 2002 and 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,  
    2006     2005     2004     2003     2002  
    (Amounts in thousands, except per share amounts)  
Operating Results:
                                       
Revenues
  $ 40,387     $ 31,117     $ 21,028     $ 16,240     $ 15,375  
Costs and expenses
    (35,066 )     (24,911 )     (23,502 )     (15,976 )     (17,897 )
 
                             
Operating income (loss)
    5,321       6,206       (2,474 )     264       (2,522 )
Other income (expense) from continuing operations
    843       4,027       (949 )     2,593       (5,205 )
 
                             
Income (loss) before income taxes
    6,214       10,233       (3,423 )     2,857       (7,727 )
Income tax benefit (provision)
    (3,647 )     315       1,153       603       2,061  
 
                             
Income (loss) from continuing operations, net of tax
    2,567       10,548       (2,270 )     3,460       (5,666 )
Income (loss) from discontinued operations, net of tax
    11       47       17,690       1,182       (441 )
Dividends on preferred shares
    (162 )     (684 )     (714 )     (500 )     (374 )
 
                             
Income (loss) available to common shares
  $ 2,416     $ 9,911     $ 14,706     $ 4,142     $ (6,481 )
 
                             
Basic income (loss) available to common shares per share
  $ 0.16     $ 0.69     $ 1.54     $ 0.44     $ (0.69 )
 
                             
Diluted income (loss) available to common shares per share
  $ 0.15     $ 0.65     $ 1.54     $ 0.44     $ (0.69 )
 
                             
Weighted average shares outstanding
                                       
Basic
    15,527       14,213       9,571       9,338       9,343  
Diluted
    15,884       15,140       9,571       9,347       9,343  
 
                                       
Balance Sheet Data:
                                       
Working capital (deficit)
  $ 12,848     $ 91,299     $ (2,728 )   $ (30,022 )   $ (7,569 )
Oil and natural gas properties, net
    251,015       138,158       82,394       79,217       71,872  
Total assets
    317,204       261,814       101,178       95,203       86,853  
Long-term debt, including current portion
    112,800       92,060       9,022       30,976       26,860  
Stockholders’ equity
    147,151       132,359       61,345       39,598       30,021  
Cash Flow Data:
                                       
Net cash provided by (used in) operating activities
  $ 14,104     $ (138 )   $ (8,177 )   $ 11,354     $ 6,362  
Capital expenditures for oil and natural gas property and equipment, including acquisitions
    105,165       58,914       10,911       4,442       6,178  

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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 non-operating working-interest properties primarily in Texas, Kansas, New Mexico, Louisiana and Oklahoma.
     Income available to common shares for 2006 was $2.4 million, or $0.16 per diluted share, compared with income applicable to common shares of $9.9 million, or $0.69 per diluted share, in 2005. Operating income for 2006 was $5.3 million, compared with operating income of $6.2 million in 2005.
     Revenues for the year ended December 31, 2006 were $40.4 million, a 30% increase over 2005 revenues of $31.1 million.
     In 2006, our oil and natural gas production was 741,609 BOE versus production of 624,144 BOE for 2005. Our average realized oil price per barrel for 2006 was $60.90, a 21.4% increase over the average realized oil price per barrel of $50.17 in 2005. The average realized gas price in 2006 was $4.96 per Mcf, 34.4% lower than the average realized gas price of $7.56 per Mcf in 2005.
     At December 31, 2006, we held interests in approximately 5.5 million gross acres (approximately 4.2 million net acres). For a more detailed description of our properties see “Items 1 and 2. Business and Properties.” At December 31, 2006, our net proved reserves were estimated at approximately 16 MMBOE.
     In the second quarter of 2006, we started production in Romania resulting in an additional 91,427 BOE of production for the year.
     In the third and fourth quarter of 2006, we installed the tripods on the Ayazli and Akkaya structures in the Black Sea and currently anticipate commencement of production in April 2007. We will continue to seek opportunities to accelerate our worldwide acquisition and development program by:

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    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 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. 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 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

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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 9% for the year ended December 31, 2006, a downward reserve revision of 2.4% for the year ended December 31, 2005 and an upward reserve revision of 5.0% for the year ended December 31, 2004. 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 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

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adoption of SFAS 143 “Accounting for Asset Retirement Obligations”. 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
     SFAS No. 157, Fair Value Measurement, (“SFAS 157”). This new standard provides guidance for using fair value to measure assets and liabilities. The Financial Accounting Standards Board (“FASB”) believes the standard also responds to investors’ requirement for expanded information about the extent to which companies measure assets and liabilities at fair value, the information used to measure fair value, and the effect of fair value measurements on earnings. SFAS 157 applies whenever other standards require (or permit) assets or liabilities to be measured at fair value but does not expand the use of fair value in any new circumstances. The standard clarifies that for items that are not actively traded, such as certain kinds of derivatives, fair value should reflect the price in a transaction with a market participant, including an adjustment for risk, not just the company’s mark-to-model value. SFAS 157 also requires expanded disclosure of the effect on earnings for items measured using unobservable data. Under SFAS 157, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the principal market for asset or liability or, in the absence of a principal market, the most advantageous market for the asset or liability. In this standard, the FASB clarifies the principle that fair value should be based on the assumptions market participants would use when pricing the asset or liability. In support of this principle, SFAS 157 establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. The fair value hierarchy gives the highest priority to quoted prices in active markets and the lowest priority to unobservable data, for example, the reporting entity’s own data. Under the standard, fair value measurements would be separately disclosed by level within the fair value hierarchy. The provisions of SFAS 157 are effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. Earlier application is encouraged, provided that the reporting entity has not yet issued financial statements for that fiscal year, including any financial statements for an interim period within that fiscal year. We are currently evaluating this statement and have not yet determined the impact of such on our financial statements. We plan to adopt this statement when required at the start of our fiscal year beginning January 1, 2008.
     On December 21, 2006, the FASB issued FSP No. EITF 00-19-2, “Accounting for Registration Payment Arrangements” (FSP EITF 00-19-2), which addresses an issuer’s accounting for registration payment arrangements and specifies that the contingent obligation to make future payments or otherwise transfer consideration under a registration payment arrangement, whether issued as a separate agreement or included as a provision of a financial instrument or other agreement, should be separately recognized and measured in accordance with FASB SFAS No. 5, “Accounting for Contingencies.” FSP EITF 00-19-2 is effective immediately for registration payment

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arrangements and the financial instruments subject to those arrangements that are entered into or modified subsequent to the date of its issuance. For registration payment arrangements and financial instruments subject to those arrangements that were entered into prior to the issuance of FSP EITF 00-19-2, this guidance shall be effective for financial statements issued for fiscal years beginning after December 15, 2006, and interim periods within those fiscal years. We do not expect this standard to have any effect upon adoption, because the Company’s policy has been to accrue such liabilities when they are deemed probable.
     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. We adopted FAS 19-1 as of December 31, 2005.
     FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes — An Interpretation of FASB Statement No. 109, (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109. FIN 48 also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The new FASB standard also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. The evaluation of a tax position in accordance with FIN 48 is a two-step process. The first step is a recognition process whereby the enterprise determines whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more-likely-than-not recognition threshold, the enterprise should presume that the position will be examined by the appropriate taxing authority that has full knowledge of all relevant information. The second step is a measurement process whereby a tax position that meets the more-likely-than-not recognition threshold is calculated to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006. The provisions of FIN 48 are to be applied to all tax positions upon initial adoption of this standard. Only tax positions that meet the more-likely-than-not recognition threshold at the effective date may be recognized or continue to be recognized upon adoption of FIN 48. The cumulative effect of applying the provisions of FIN 48 should be reported as an adjustment to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) in the year of adoption. We plan to adopt this statement at the start of our fiscal year beginning January 1, 2007. We are still determining the impact, if any, that this statement will have on our financial statements.
     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 have determined that the impact on our financial statements will not be material. We have adopted FASB 155 on January 1, 2007.
     On December 16, 2004, FASB issued SFAS No. 153, Exchanges of Nonmonetary Assets, an Amendment of APB Opinion No. 29, Accounting for Nonmonetary Transactions (“ SFAS 153”). This statement amends APB Opinion 29

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to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. Under SFAS 153, if a nonmonetary exchange of similar productive assets meets a commercial-substance criterion and fair value is determinable, the transaction must be accounted for at fair value resulting in recognition of any gain or loss. SFAS 153 is effective for nonmonetary transactions in fiscal periods that begin after June 15, 2005. This standard did not have a material impact on our financial position, results of operations or cash flows.
     SEC Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements (“SAB No. 108”). In September 2006, the Securities and Exchange Commission provided guidance on the consideration of the effects of prior year misstatements in quantifying current year misstatements for the purpose of a materiality assessment. SAB No. 108 establishes a dual approach that requires quantification of financial statement errors based on the effects of the error on each of the company’s financial statements and the related financial statement disclosures. SAB No. 108 is effective for fiscal years ending after November 15, 2006. We adopted SAB No. 108 in 2006. The adoption of this statement did not impact our financial statements.
     In February 2007, the FASB issued Statement 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement 115”. The statement permits entities to chosse to measure certain financial instruments and other items at fair value. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. Unrealized gains and losses on any items for which Toreador elects the fair value measurement option would be reported in earnings. Statement 159 is effective for fiscal years beginning after November 15, 2007. However, early adoption is permitted for fiscal years beginning on or before November 15, 2007, provided Toreador also elects to apply the provisions of Statement 157, “Fair Value Measurements”, at the same time. Toreador is currently assessing the effect, if any, the adoption of Statement 159 will have on its financial statements and related disclosures.
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, 2006, we had cash and cash equivalents and restricted cash of $33.2 million, a current ratio of approximately 1.3 to 1 and a debt (convertible debenture, long-term debt and Convertible Senior Notes) to equity ratio of .77 to 1. For the twelve months ended December 31, 2006, operating income was $5.3 million and capital expenditures were $120.2 million.
     Our preliminary capital expenditure budget (subject to projected available capital) for 2007 is $81.5 million, and we currently plan on funding our 2007 capital expenditure program through (i) funds that have been received from our new credit facilities with the International Finance Corporation; (ii) cash flow from our existing properties, including our Black Sea properties that are anticipated to commence production in April 2007, and (iii) future potential financing sources, including the public or private issuance of debt or equity.
     We are currently considering possible issuances of additional equity securities in order to fund our capital expenditures budget for 2007 which equity securities may be sold at a discount to current market prices and may result in substantial dilution to our equity holders.
     If the cash flow from our operations, including our Black Sea properties, is less than anticipated and or if we are unable to issue additional capital through the issuance of debt or equity, we currently believe that we will reduce our capital expenditures by approximately $30 to $40 million, by delaying exploratory projects until such time as we have additional capital. We may also seek additional capital by (i) forward selling our crude oil and natural gas production; (ii) obtaining industry partners in our exploratory prospects; (iii) selling our non-core properties; or (iv)

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a combination of these actions. We believe such actions will allow us to meet our capital commitments and that as a result we will have sufficient liquidity for the remainder of 2007.
     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 other corporate purposes. The facility bears interest at a floating rate of 2.25-2.75% above LIBOR (7.54% total rate at December 31, 2006) 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 $909,000 were available at December 31, 2006. 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 dividends and require us to meet certain financial requirements. Specifically, we must maintain an interest cost ratio of not less than 4.00 to 1.00, an indebtedness ratio of not less than 1.00 to 1.00, asset life cover ratio of not less than 1.25 to 1.00, a loan life cover ratio equal to or greater than 1.15 to 1.00 and a debt service coverage ratio equal to or greater than 1.10 to 1.00. On March 3, 2007 this facility was retired and replaced by the credit facility with the International Finance Corporation. See Note 8 to the Notes to the Consolidated Financial Statements.
     As a result of not providing Natixis with our unaudited consolidated financial statements for the nine month period ended September 30, 2006 within forty-five (45) days after the end of such quarter, we were in default under the $15 million facility. Until January 16, 2007, Natixis waived such default and any other default under the facility as a result of us not yet providing such financial statements. On January 16, 2007, we filed the Form 10-Q for the quarter ended September 30, 2006 and provided the unaudited consolidated financial statements contained in the Form 10-Q to Natixis which cured the default.
     On March 2, 2007, the facility was retired and all amounts due were paid.
     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% (7.75% total rate at December 31, 2006) and is collateralized by our domestic working interests. The borrowers under this facility are two of our domestic subsidiaries, and the parent entity has guaranteed the obligations. At December 31, 2006, we had $5.6 million outstanding and approximately an additional $550,000 available for borrowings. As of March 8, 2007, we had approximately $5.6 million outstanding and an additional approximately $550,000 available for borrowings. The Texas Capital facility requires monthly interest payments until January 1, 2009 at which time all unpaid principal and interest are due. The Texas Capital 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.
     We were in default under the Texas Capital facility for failing to provide Texas Capital on or before the 60th day after the last day of the fiscal quarter ended September 30, 2006 with a copy of the unaudited consolidated financial statements of Toreador and there was an event of default under the Texas Capital facility for defaulting in the performance or observance of a provision under the Senior Convertible Notes. Texas Capital waived the default and event of default until January 16, 2007. On January 16, 2007, we filed the Form 10-Q for the quarter ended September 30, 2006 and provided the unaudited consolidated financial statements contained in the Form 10-Q to Texas Capital which cured the default.
     New Secured Revolving Facility
     On December 28, 2006, we entered into a loan and guarantee agreement with International Finance Corporation. The loan and guarantee agreement provides for a $25 million facility which is a secured revolving facility with a current maximum facility amount of $25 million which maximum facility amount will increase to $40 million when

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the projected total borrowing base amount exceeds $50 million. The $25 million facility funded on March 2, 2007. The total proceeds received on March 2, 2007 were approximately $25 million, of which $11 million was used to retire the outstanding balance on the $15 million credit facility and the remaining $14 million of funds will be used to finance our capital expenditures in Turkey and Romania. The loan and guarantee agreement also provides for an unsecured $10 million facility which funded on December 28, 2006. As of December 31, 2006 and March 8, 2007, the $10 million facility had $10 million outstanding. All amounts available under the new secured revolving facility have been funded. Both the $25 million facility and the $10 million facility are to fund the our operations in Turkey and Romania.
     Interest accrues on any loans under the $25 million facility at a rate of 2% over the six month LIBOR rate. Interest accrued on the $10 million facility at a rate of 1.5% over the six month LIBOR rate until the $25 million facility funded on March 2, 2007 after which the rate for the $10 million facility was lowered to 0.5% over the six month LIBOR rate. As of December 31, 2006 the interest rate on the $10 million facility was 6.86%. As of March 8, 2007, the interest rate on the $25 million facility was 7.349% and the interest rate on the $10 million facility was 5.849%. Interest is to be paid on each June 15 and December 15.
     On December 31, 2011, the maximum amount available under the $25 million facility begins to decrease by $5 million every six months from $40 million (assuming the projected borrowing base amount exceeds $50 million) until the final portion of the $25 million facility is due on December 15, 2014. On December 15, 2014, $5 million of the $10 million facility is to be repaid with the remaining $5 million being due on June 15, 2015.
     We are to meet the following ratios on a consolidated basis: (i) the life of loan coverage ratio of not less than: (a) 1.2:1.0 in 2006 and 2007; (b) 1.3:1.0 in 2008; and (c) 1.4:1.0 in 2009 and each subsequent year thereafter; (ii) reserve tail ratio of not less than 25%; (iii) adjusted financed debt to EBITDA ratio of not more than 3.0:1.0; (iv) liabilities to tangible net worth ratio of not more than 60:40; and (v) interest coverage ratio of not less than 3.0:1.0.
     We are subject to certain negative covenants, including, but not limited to, the following: (i) except as required by law or to pay the dividends on the Series A-1 Convertible Preferred Stock, paying dividends; (ii) subject to certain exceptions, incurring debt, making guarantees or creating or permitting to exist any liens, (iii) subject to certain exceptions, making or permitting to exist loans or advances to, or deposits, with other persons or investments in any person or enterprise; (iv) subject to certain exceptions, selling, transferring, leasing or otherwise disposing of all or a material part of its borrowing base assets; and (v) subject to certain exceptions, undertaking or permitting any merger, spin-off, consolidation or reorganization.
     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 Convertible Senior Notes to cover over-allotments. The option was exercised on September 30, 2005. The total principal amount of Convertible Senior Notes issued was $86.25 million and total net proceeds were approximately $82.2 million.
     The Convertible Senior 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 Convertible Senior Notes , subject to adjustment (equivalent to a conversion price of approximately $42.81 per share). We may redeem the Convertible Senior 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 Convertible Senior 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 Convertible Senior Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of Convertible Senior Notes to be redeemed, plus any accrued and unpaid interest, irrespective of the price of its common stock. Holders may convert their Convertible Senior 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 Convertible Senior Notes for cash in an amount equal to 100% of the principal amount of such Convertible Senior Notes, plus any accrued and unpaid interest.

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     Due to our restating the consolidated financial statements for the years ended December 31, 2003, 2004 and 2005 and our consolidated financial statements for each of the quarters ended March 31 and June 30, 2006, we did not provide the trustee under the indenture of the Convertible Senior Notes with copies of our annual reports, information, documents and other reports that we are required to file with the Securities and Exchange Commission pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 within thirty (30) days of when such reports are required to be filed with the Securities and Exchange Commission.
     On December 15, 2006, we received a notice from the trustee for failing to provide the trustee with a copy of our Form 10-Q for the nine month period ended September 30, 2006. Since we cured the covenant default within thirty (30) days after receiving the written notice from the trustee, we cured the default and an event of default did not occur.
     The registration rights agreement covering the Convertible Senior Notes provides for a penalty if the registration statement is filed and declared effective but thereafter ceases to be effective (a “Suspension Period”) for an aggregate of forty-five (45) days in any three month period or ninety (90) days in any twelve month period (an “Event Date”). Such penalty calls for an additional 0.25% per annum in interest expense on the aggregate principal amount of the Convertible Senior Notes for the first ninety (90) days following an Event Date and an additional 0.50% per annum in interest expense on the aggregate principal amount of the Convertible Senior Notes thereafter, until such Suspension Period ends upon the registration statement again becoming effective. Because we did not file our Quarterly Report on Form 10-Q for the nine month period ended September 30, 2006 in a timely manner, the registration statement for the Convertible Senior Notes became ineffective and we entered a Suspension Period on November 15, 2006. Such Suspension Period ended on January 23, 2007 when we provided notice that the Form 10-Q had been filed and the Suspension Period was no longer in effect. Because the Suspension Period exceeded forty-five (45) days in any three month period, we will owe approximately $14,375 in additional interest expense. Once we file our Form 10-K for the year ended December 31, 2006, we will again enter a Suspension Period until we can file and have declared effective an amendment to our registration statement on Form S-1. Because of the previous Suspension Period, we will exceed the ninety (90) days in any twelve month period on the twenty first (21st) day following the filing of our Form 10-K and will again begin to accrue additional interest as described above until we can file and have declared effective an amendment to our registration statement on Form S-1.
     Preferred Stock
     On February 22, 2005, 82,000 shares of Series A-1 Convertible Preferred Stock were exchanged for an aggregate of 512,000 shares of our common stock. As of December 31, 2006, 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.
     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 year ended December 31, 2006 dividends totaled $162,000.

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The terms of the loan and guarantee agreement with the International Finance Corporation limit the payment of dividends only to those that are required by law and to dividends associated with our Series A-1 Convertible Preferred Stock.
     Contractual Obligations
The following table sets forth our contractual obligations in thousands at December 31, 2006 for the periods shown:
                                         
            Less than     One To     Four to     More Than  
    Total     One Year     Three Years     Five Years     Five Years  
Long-term debt
  $ 112,800     $ 5,000     $ 6,000     $ 5,500     $ 96,300  
Lease commitments
    1,516       502       365       264       385  
 
                             
Total contractual obligations
  $ 114,316     $ 5,502     $ 6,365     $ 5,764     $ 96,685  
 
                             
Contractual obligations for long-term debt above does not include amounts for interest payments.
Results of Operations
Comparison of Years Ended December 31, 2006 and 2005
                                     
    For the Years Ended December 31,  
    2006     2005         2006     2005  
Production:
                  Average Price:                
Oil (MBbls):
                 
Oil ($/Bbl):
               
United States
    58       60    
United States
  $ 61.29     $ 52.37  
France
    442       404    
France
    61.74       50.92  
Turkey
    68       65    
Turkey
    56.10       43.48  
Romania
    8          
Romania
    52.71        
 
                           
Total
    576       529    
Total
  $ 60.90     $ 50.17  
 
                           
Gas (MMcf):
                 
Gas ($/Mcf):
               
United States
    490       570    
United States
  $ 6.38     $ 7.56  
France
             
France
           
Turkey
             
Turkey
           
Romania
    502          
Romania
    3.57        
 
                           
Total
    992       570    
Total
  $ 4.96     $ 7.56  
 
                           
MBOE:
                 
$/ BOE:
               
United States
    140       155    
United States
  $ 47.88     $ 48.08  
France
    442       404    
France
    61.74       50.92  
Turkey
    68       65    
Turkey
    56.10       43.48  
Romania
    92          
Turkey
    24.06        
 
                           
Total
    742       624    
Total
  $ 53.96     $ 49.86  
 
                           
Revenues
     Oil and natural gas sales
     Oil and natural gas sales for the twelve months ended December 31, 2006 were $40.4 million, as compared to $31.1 million for the comparable period in 2005. This increase is primarily due to a significant increase in the average realized price for oil partially offset by a $2.60 decline in the price realized for natural gas. Production increased by approximately 118 MBOE due primarily to the start of production in Romania and increases in production in Turkey and France that was somewhat offset by lower production in the United States.
     The above table compares both volumes and prices received for oil and natural gas for the twelve months ended December 31, 2006 and 2005. 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 years ended December 31, 2006 and 2005.
Costs and expenses
     Lease operating

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     Lease operating expense was $10.9 million, or $14.75 per BOE produced for the twelve months ended December 31, 2006, as compared to $8.2 million, or $13.13 per BOE produced for the comparable period in 2005. This increase is primarily due to increased operating costs in France, the start of production in Romania and higher costs associated with the age of our fields.
     Exploration expense
     Exploration expense for the twelve months ended December 31, 2006 was $3.9 million, as compared to $2.9 million for the comparable period in 2005. This change is primarily due to increased activity in Hungary and Romania in interpreting data in order to evaluate drilling locations for 2007.
     Dry hole and abandonment
     Dry hole and abandonment cost for the twelve months ended December 31, 2006 was $3.1 million, as compared to $1.7 million in 2005. This is primarily due to the drilling of a dry hole in Hungary.
     Depreciation, depletion and amortization.
     For the twelve months ended December 31, 2006 depreciation, depletion and amortization expense was $7.5 million, or $10.17 per BOE produced, as compared to $5.2 million, or $8.40 per BOE produced for the twelve months ended December 31, 2005. This increase is primarily due to the downward revision of proved reserves in the United States and France of approximately 1.1 MBOE of proved reserves.
     Impairment of oil and natural gas properties
     Impairment charged in 2006 was $345,000 compared to $110,000 in 2005. This increase was primarily due to the downward revisions of proved reserves in the United States.
     General and administrative
     General and administrative expense, not including stock compensation expense, was $7.2 million for the twelve months ended December 31, 2006, compared with $6.3 million for the comparable period of 2005. This increase is primarily due to increased personnel costs of $1.1 million, the Hungarian office which was opened in July 2005 of $310,000 and the costs of restating the financial statements for the years ended December 31, 2003, 2004 and 2005 and the quarters ended March 31, 2006 and June 30, 2006 of approximately $820,000. These were reduced by an increase in the amounts allocated to development projects and exploration expense of approximately $1.7 million
     Stock compensation expense
     Stock compensation expense was $2.7 million for the twelve months ended December 31, 2006, compared with $401,000 for the comparable period of 2005. The increase is due to the restricted stock granted by the Board of Directors to certain employees, consultants and non-employee directors and the expensing of stock options as required by the adoption of SFAS 123 (R).
     Other income and expense
     Other income and expense resulted in income of $0.9 million for the twelve months ended December 31, 2006 versus income of $4 million in 2005. This decrease is primarily due to foreign exchange losses in Hungary and Turkey.

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     Discontinued operations
     On March 12, 2004, pursuant to the terms of an Agreement for Purchase and Sale dated December 17, 2003, Toreador and Tormin, Inc., a wholly owned subsidiary of Toreador, sold their United States mineral and royalty assets to Black Stone Acquisitions Partners I, L.P. The gross consideration was approximately $45 million cash. The effective date of the sale was January 1, 2004.
The results of operations of assets in the United States to be sold as of December 31, 2003 have been presented as discontinued operations in the accompanying consolidated statements of operations. Results for these assets reported as discontinued operations were as follows:
                         
    Twelve Months Ended December 31.  
    2006     2005     2004  
    (in thousands)  
Revenues:
                       
Oil and natural gas sales
  $ 11     $ 63     $ 139  
 
                       
Costs and expenses:
                       
Lease operating
          1       (10 )
Allocated general and administrative
          15       163  
 
                 
Total costs and expenses
          16       153  
Gain on sale of properties
                28,711  
 
                 
Income before taxes
    11       47       28,697  
Income tax provision
                11,007  
 
                 
Income from discontinued operations
  $ 11     $ 47     $ 17,690  
 
                 
     Provision for income taxes
At December 31, 2006, it was “unlikely” that the United States parent entity, Toreador Resources Corporation, would be able to generate sufficient future taxable income to utilize $1.2 million of a $6.3 million net operating loss carryforward. We therefore established a valuation allowance of $1.2 million which resulted in an increase to the provision for income taxes.
     Income available to common shares
     For the twelve months ended December 31, 2006, we reported income from continuing operations net of taxes of $2.6 million, compared with income of $10.5 million for the same period of 2005. For the twelve months ended December 31, 2006 income available to common shares was $2.4 million versus $9.9 million for the year ended December 31, 2005.
     Other comprehensive income

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The most significant element of comprehensive income, other than net income, is foreign currency translation. As of December 31, 2005, we had accumulated an unrealized loss of $3.4 million. In the year ended December 31, 2006, we had an unrealized gain of $7.6 million. The functional currency of our operations in France is the Euro and in Romania, Turkey and Hungary the functional currency is the United States Dollar. The exchange rates used to translate the financial position of the French, Turkish, Romanian and Hungarian operations at December 31, 2006 and 2005 are shown below:
                         
    December 31,        
    2006     2005     2004  
Euro
  $ 1.3170     $ 1.1797     $ 1.3621  
 
                 
 
                       
New Turkish Lira
  $ 0.7065     $ 0.7408     $ 0.7418  
 
                 
 
                       
Romania Lei
  $ 0.3886     $ 0.3508     $  
 
                 
 
                       
Hungarian Forint
  $ 0.0052     $ 0.0047     $  
 
                 
Comparison of Years Ended December 31, 2005 and 2004
                                     
    For the Years Ended December 31,  
    2005     2004         2005     2004  
Production:
                  Average Price:                
Oil (MBbls):
                 
Oil ($/Bbl):
               
United States
    60       68    
United States
  $ 52.37     $ 38.87  
France
    404       397    
France
    50.92       35.39  
Turkey
    65       73    
Turkey
    43.48       31.05  
 
                           
Total
    529       538    
Total
  $ 50.17     $ 35.24  
 
                           
Gas (MMcf):
                 
Gas ($/Mcf):
               
United States
    570       546    
United States
  $ 7.56     $ 5.81  
France
             
France
           
Turkey
             
Turkey
           
 
                           
Total
    570       546    
Total
  $ 7.56     $ 5.81  
 
                           
MBOE:
                 
$/ BOE:
               
United States
    155       159    
United States
  $ 48.08     $ 35.44  
France
    404       397    
France
    50.92       35.39  
Turkey
    65       73    
Turkey
    43.48       31.05  
 
                           
Total
    624       629    
Total
  $ 49.86     $ 34.90  
 
                           
Revenues
     Oil and natural gas sales
Oil and natural gas sales for the twelve months ended December 31, 2005 were $31.1 million, as compared to $22.3 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 5 MBOE due primarily to normal declines in our oil and gas properties in the US and in Turkey, offset by a slight increase in France from the results of successful workovers and new drilling.

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     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 $8.2 million, or $13.13 per BOE produced for the twelve months ended December 31, 2005, as compared to $7.4 million, or $11.76 per BOE produced for the comparable period in 2004. This increase is primarily due to the workover program in France and a 5 MBOE decline in production when comparing the twelve months ended December 31, 2005 to 2004.
     Exploration expense
     Exploration expense for the twelve months ended December 31, 2005 was $2.9 million, as compared to $4.5 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 expense in 2004.
     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.
     Depreciation, depletion and amortization.
     For the twelve months ended December 31, 2005 depreciation, depletion and amortization expense was $5.2 million, or $8.40 per BOE produced, as compared to $4.1 million, or $6.53 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 4,929 BOE decline in production.
     Impairment of oil and natural gas properties
     Impairment charged in 2005 was $110,000 compared to no impairments in 2004. This increase was due to marginal properties in the United States.
     General and administrative
     General and administrative expense was $6.7 million for the twelve months ended December 31, 2005, compared with $7.5 million for the comparable period of 2004. The decrease is primarily due to allocating a portion of Turkey’s cost to the development project and exploration expense of $2.4 million. This decrease is partially offset by an increase in the United States primarily due to increased staff of approximately $121,000, Sarbanes-Oxley compliance of approximately $238,000, legal expenses of $175,000, professional fees of $167,000, data processing fees of $123,000 and expensing of stock compensation expense related to the restricted stock granted by the Board of Directors to certain employees, consultants and non employee directors of approximately $401,000.
     Other income and expense
     Other income and expense resulted in income of $4 million for the twelve months ended December 31, 2005 versus a loss of $790,000 for the comparable period in 2004. The increase was primarily due to a $2.4 million foreign currency exchange gain in 2005 versus a foreign exchange gain of $127,000 in 2004. In 2005 we incurred $1.4 million in interest expense, of which all was capitalized to oil and gas properties, compared to $1.9 million of

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interest expense in 2004, of which $432,000 was capitalized to oil and gas properties. Also in 2005 we recorded interest income of $1.4 million as compared to $515,000 in 2004.
     Income available to common shares
     For the twelve months ended December 31, 2005, we reported income from continuing operations net of taxes of $10.6 million, compared with a loss of $2.3 million for the same period of 2004. For the twelve months ended December 31, 2005 income available to common shares was $9.9 million versus $14.7 million for the year ended December 31, 2004.
     Other comprehensive income
     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 $4.7 million. In the year ended December 31, 2005, we had an unrealized loss of $8.1 million. The primary reason for decrease is due to the strength of the Euro compared to the United States Dollar in 2005. The functional currency of our operations in France is the Euro and in Romania, Turkey and Hungary the functional currency is the United States Dollar.
Selected Quarterly Financial Data (Unaudited)
     We derived the selected historical financial data in the table below from our unaudited interim consolidated financial statements. The sum of net income per share by quarter may not equal the net income per share for the year due to variations in the weighted average shares outstanding used in computing such amounts. The historical data presented here are only a summary and should be read in conjunction with the consolidated financial statements, related notes and other financial information included elsewhere in this annual report.
                                 
    Three Months Ended
    March   June   September   December
    31,   30,   30,   31,
    (in thousands, except per share data)
For the year ended December 31, 2006:
                               
Total revenues
  $ 9,769     $ 10,303     $ 10,726     $ 9,589  
Total costs and expenses
    7,298       7,502       7,418       12,848  
Income (loss) from continuing operations
    3,148       1,573       5,461       (7,615 )
Income (loss) from discontinued operations, net of tax
                11        
Net income (loss)
    3,148       1,573       5,472       (7,615 )
Income (loss) available to common shares
    3,107       1,532       5,432       (7,655 )
Basic income (loss) available to common shares per share
    0.20       0.10       0.35       (0.49 )
Diluted income (loss) available to common shares per share
    0.19       0.09       0.33       (0.49 )
 
                               
For the year ended December 31, 2005 :
                               
Total revenues
  $ 6,676     $ 7,164     $ 8,770     $ 8,507  
Total costs and expenses
    5,281       5,476       7,040       7,114  
Income (loss) from continuing operations
    1,925       1,956       1,351       5,316  
Income (loss) from discontinued operations, net of tax
    10       1       14       22  
Net income (loss)
    1,935       1,957       1,365       5,338  
Income available to common shares
    1,372       1,917       1,324       5,298  
Basic income available to common shares per share
    0.11       0.14       0.09       0.35  
Diluted income available to common shares per share
    0.10       0.13       0.09       0.32  
     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.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk
     The risks inherent in our market-sensitive instruments are the potential loss arising from adverse changes in oil and natural gas prices, interest rates and foreign currency exchange rates as discussed below. The sensitivity analysis however, neither considers the effects that such adverse changes may have on overall economic activity nor does it consider additional actions we may take to mitigate our exposure to such changes. Actual results may differ.
     The following quantitative and qualitative information is provided about financial instruments to which we are a party as of December 31, 2006, 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 2007 sales volumes at fixed prices, such a decrease would result in a reduction to oil and natural gas sales revenue of approximately $7 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, 2006, such a decrease would result in an unrealized loss of approximately $8.1 million due to foreign currency exchange rates.
     Derivative Financial Instruments
     We utilize commodity derivative instruments as part of our risk management program and, prior to the repayment of our senior credit facilities in January 2004, we utilized them to comply with the requirements of our senior credit facilities. These transactions are generally structured as either swaps or collar contracts. A swap has the effect of an outright sale at a specific price. A collar has the effect of creating a sale only if a floor or ceiling price is exceeded. These instruments (i) reduce the effect of the price fluctuations of the commodities we produce and sell and (ii) support our annual capital budgeting and expenditure plans. When we had our senior credit facilities that required these instruments, 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 policies followed relative to 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 Report of Independent Registered Public Accounting Firm 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.

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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
     We maintain disclosure controls and procedures (as defined in Rules 13a-15(f) and 15d-15(e) under the Securities Exchange Act of 1934) 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 amended 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, 2006 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 Securities Exchange Act of 1934 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 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, 2006, 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 in connection with preparation of the annual report on Form 10-K for the year ended December 31, 2006. As a result of these assessments, various material weaknesses were identified. 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 are the basis for our conclusion at December 31, 2006:
    We did not maintain an effective control environment and our financial and accounting organization was not adequate to support our financial reporting requirements. The involvement of corporate personnel in

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      the reporting of foreign transactions and operations was not sufficient to accurately capture and record such activity and we did not maintain a sufficient complement of personnel with an appropriate level of accounting knowledge, experience and training in the application of generally accepted accounting principles consistent with the level and complexity of our operations. The Company also did not have an adequate review and approval process for recorded journal entries and changes made to the general ledger.
 
    Our accounting and financial reporting systems and procedures were not sufficiently designed to ensure consistent and complete application of our accounting policies and to prepare financial statements in accordance with generally accepted accounting principles. This includes not only the sufficiency of our review of sensitive calculations, reconciliations and spreadsheets but also the preparation and processing of financial accounting information.
     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, 2006 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.
     Grant Thornton 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, 2006. The report, dated March 16, 2007, 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, 2006 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
     There were no changes in our internal control over financial reporting during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
     Management is currently evaluating the implementation of procedures that may be necessary to fully remediate the material weaknesses described above. Management is in the process of making the following changes to its system of internal controls.
    Improving the computerized integrated financial reporting system. This will automate the manual processes that are causing errors in spreadsheets and sensitive calculations.
 
    Hiring additional experienced accounting staff to allow for improved segregation of duties and a more thorough review, by senior financial personnel, of the financial statements and underlying supporting documentation.
 
    Providing additional training to our accounting staff and acquiring other accounting resources to improve our financial reporting.
 
    Formally documenting our accounting policies and procedures.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Shareholders
Toreador Resources Corporation
We have audited management’s assessment, included in the accompanying “Management’s Annual Report on Internal Control Over Financial Reporting,” that Toreador Resources Corporation and subsidiaries (the “Company”) did not maintain effective internal control over financial reporting as of December 31, 2006, because of the effect of material weakness identified in management’s assessment, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is

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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 opinions.
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 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 weakness has been identified and included in management’s assessment.
    The Company did not maintain an effective control environment and its financial and accounting organization was not adequate to support its financial reporting requirements. The involvement of corporate personnel in the reporting of foreign transactions and operations was not sufficient to accurately capture and record such activity and it did not maintain a sufficient complement of personnel with an appropriate level of accounting knowledge, experience and training in the application of generally accepted accounting principles consistent with the level and complexity of its operations. The Company also did not have an adequate review and approval process for recorded journal entries and changes made to the general ledger.
 
    The Company’s accounting and financial reporting systems and procedures were not sufficiently designed to ensure consistent and complete application of its accounting policies and to prepare financial statements in accordance with generally accepted accounting principles. This includes not only the sufficiency of review of sensitive calculations, reconciliations and spreadsheets but also the preparation and processing of financial accounting information.
These material weakness were considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2006 financial statements, and this report does not affect our report dated March 16, 2007, which expressed an unqualified opinion on those financial statements.
In our opinion, management’s assessment that the Company did not maintain effective internal control over financial reporting as of December 31, 2006, 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. Also in our opinion, because of the effect of the material weakness described above on the achievement of the objectives of the control criteria, the Company has not maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
/s/ GRANT THORNTON LLP
Dallas, Texas
March 16, 2007
ITEM 9B. Other Information.
     None.

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PART III
ITEM 10. Directors, Executive Officers of the Registrant and Corporate Governance.
     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 in our Proxy Statement relating to the 2007 Annual Meeting of Stockholders, that will be filed with the Securities and Exchange Commission on or prior to April 30, 2007, and that is incorporated herein by reference.
ITEM 11. Executive Compensation.
     Information required by this item relating to executive compensation will be set forth in our Proxy Statement relating to the 2007 Annual Meeting of Stockholders, that will be filed with the Securities and Exchange Commission on or prior to April 30, 2007, 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 relating to (i) security ownership of certain beneficial owners and management and (ii) securities authorized for issuance under equity compensation plans will be set forth in our Proxy Statement relating to the 2007 Annual Meeting of Stockholders, that will be filed with the Securities and Exchange Commission on or prior to April 30, 2007, and that is incorporated herein by reference.
ITEM 13. Certain Relationships and Related Transactions, and Director Independence.
     Information required by this item relating to (i) certain business relationships and related transactions with management and (ii) other related parties and director independence will be set forth in our Proxy Statement relating to the 2007 Annual Meeting of Stockholders, that will be filed with the Securities and Exchange Commission on or prior to April 30, 2007, 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 2006 and 2005 and (ii) audit committee’s pre-approval policies and procedures for audit and non-audit services, will be set in our Proxy Statement relating to the 2007 Annual Meeting of Stockholders, that will be filed with the Securities and Exchange Commission on or prior to April 30, 2007, and that is incorporated herein by reference.

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PART IV
ITEM 15. Exhibits and 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 Firm, Consolidated Balance Sheets as of December 31, 2006 and 2005, Consolidated Statements of Operations and Comprehensive Income for the three years in the period ended December 31, 2006, Consolidated Statements of Changes in Stockholders’ Equity for each of the three years in the period ended December 31, 2006, Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 2006, 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.
Exhibits: The exhibits required to be filed by this Item 15 are set forth in the Index to Exhibits accompanying this report.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Form 10-K to be signed on its behalf by the undersigned, thereunto duly authorized.
TOREADOR RESOURCES CORPORATION
         
     
March 16, 2007  /s/ Nigel J. B. Lovett    
  Nigel J. B. Lovett, President and Chief Executive Officer   
   
 
     KNOW ALL MEN BY THESE PRESENTS, that each of the undersigned officers and directors of Toreador Resources Corporation hereby constitutes and appoints Nigel J.B. Lovett 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/ Nigel J.B. Lovett
 
Nigel J.B. Lovett
  President, Chief Executive Officer and Director   March 16, 2007
/s/ Alan Bell
 
Alan Bell
  Director   March 16, 2007
/s/ David M. Brewer
 
David M. Brewer
  Director   March 16, 2007
/s/ Herbert L. Brewer
 
Herbert L. Brewer
  Director   March 16, 2007
/s/ Peter L. Falb
 
Peter L. Falb
  Director   March 16, 2007
/s/ William I. Lee
 
William I. Lee
  Director   March 16, 2007

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SIGNATURE   CAPACITY IN WHICH SIGNED   DATE
/s/ John Mark McLaughlin
 
John Mark Mclaughlin
  Chairman and Director   March 16, 2007
/s/ Nicholas Rostow
 
Nicholas Rostow
  Director   March 16, 2007
/s/ H.R. Sanders, Jr.
 
H.R. Sanders, Jr.
  Director   March 16, 2007
/s/ Herbert Williamson
 
Herbert Williamson
  Director   March 16, 2007
/s/ Douglas W. Weir
 
Douglas W. Weir
  Senior Vice President and Chief Financial Officer   March 16, 2007
/s/ Charles J. Campise
 
Charles J. Campise
  Vice President-Accounting and Chief Accounting Officer   March 16, 2007

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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 (previously filed as Exhibit 4.3 to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2005, File No. 0-2517, and incorporated herein by reference).
       
 
4.4    
Registration Rights Agreement, effective November 1, 2002, among Toreador Resources Corporation and persons party thereto (previously filed as Exhibit 4.5 to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2002, File No. 0-2517, and incorporated herein by reference).
       
 
4.5    
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).

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EXHIBIT        
NUMBER       DESCRIPTION
4.6    
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).
       
 
4.7    
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).
       
 
4.8    
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).
       
 
4.9    
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).
       
 
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).

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EXHIBIT        
NUMBER       DESCRIPTION
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 herein by reference).
       
 
10.12+    
Amendment to 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 12, 2006, File No. 0-2517, and incorporated herein by reference).
       
 
10.13+    
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 herein by reference).
       
 
10.14+    
Form of 2005 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 herein by reference).
       
 
10.15+    
Form of 2006 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 12, 2006, File No. 0-2517, and incorporated herein by reference).
       
 
10.16+    
Summary Sheet: 2006 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).
       
 
10.17+    
Summary Sheet: 2006 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).
       
 
10.18+    
Summary of Amendment to Restricted Stock Award Agreement of Thomas P. Kellogg, dated April 6, 2006 (previously filed as Exhibit 10.1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on April 12, 2006, File No. 0-2517, and incorporated herein by reference).
       
 
10.19+    
Summary Sheet: 2005 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).
       
 
10.20+    
Summary Sheet: 2006 Non-Employee Director Equity Compensation (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 12, 2006, File No. 0-2517, and incorporated herein by reference).

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EXHIBIT        
NUMBER       DESCRIPTION
10.21+*    
Summary Sheet: 2007 Director Compensation.
       
 
10.22+    
Michael FitzGerald Employee Restricted Stock Award Agreement dated May 30, 2006 (previously filed as Exhibit 10.1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on June 5, 2006, File No. 0-2517, and incorporated herein by reference).
       
 
10.23+    
Ed Ramirez Employee Restricted Stock Award Agreement dated May 30, 2006 (previously filed as Exhibit 10.2 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on June 5, 2006, File No. 0-2517, and incorporated herein by reference).
       
 
10.24+    
Michael J. FitzGerald Change in Control Agreement dated November 8, 2006 (previously filed as Exhibit 10.1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on November 15, 2006, File No. 0-2517, and incorporated herein by reference).
       
 
10.25+*    
Herbert C. Williamson III Restricted Stock Award Agreement dated November 8, 2006.
       
 
10.26+*    
Nigel Lovett Restricted Stock Award Agreement dated November 8, 2006.
       
 
10.27+*    
Nicholas Rostow Restricted Stock Award Agreement dated November 8, 2006.
       
 
10.28+    
Letter Agreement by and between Toreador Resources Corporation and G. Thomas Graves III, dated January 25, 2007 (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 26, 2007, File No. 0-2517, and incorporated herein by reference).
       
 
10.29+    
Summary Sheet: 2007 Nigel Lovett’s Annual Base Salary (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 26, 2007, File No. 0-2517, and incorporated herein by reference).
       
 
10.30+    
Summary Sheet: 2007 Executive Officer 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 January 31, 2007, File No. 0-2517, and incorporated herein by reference).
       
 
10.31+*    
G. Thomas Graves III Stock Award Agreement dated January 25, 2007.
       
 
10.32+    
Summary Sheet: 2007 Short-Term Incentive Compensation 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 February 12, 2007, File No. 0-2517, and incorporated herein by reference).
       
 
10.33+    
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).

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EXHIBIT        
NUMBER       DESCRIPTION
10.34    
Contract for the Supply of Crude Oil from the Parisian Basin, effective January 1, 1997, between Elf Antwar France and Midland Madison Petroleum Company (n/k/a Madison Energy France) (previously filed as Exhibit 10.14 to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2001, File No. 0-2517, and incorporated herein by reference).
       
 
10.35    
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).
       
 
10.36    
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).
       
 
10.37    
Credit Agreement, dated December 30, 2004, by and among Toreador Resources Corporation, Toreador Acquisition Corporation, Toreador Exploration and Production, Inc. and Texas Capital Bank, N.A. (previously filed as Exhibit 10.1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on January 3, 2005, File No. 0-2517, and incorporated herein by reference).
       
 
10.38    
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).
       
 
10.39    
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).
       
 
10.40    
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).
       
 
10.41    
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).
       
 
10.42      
Loan and Guarantee Agreement dated December 28, 2006 by and among Toreador Resources Corporation, as Guarantor, Toreador Turkey Ltd. as Borrower and Guarantor, Toreador Romania Ltd, a Borrower and Guarantor, Madison Oil France SAS, as Borrower and Guarantor, Toreador Energy France S.C.S., as Borrower and Guarantor, Toreador International Holding L.L.C., as Guarantor, and International Finance 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 January 4, 2007, File No. 0-2517, and incorporated herein by reference).
       
 
10.43*      
Security Agreement dated February 21, 2007 (signed by Toreador Resources on February 27, 2007) by and between Toreador Resources Corporation, as Assignor, and International Finance Corporation, as Assignee.

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EXHIBIT        
NUMBER       DESCRIPTION
10.44*      
Quota Charge Agreement dated February 28, 2007 by and between Toreador Resources Corporation, as Charger, and International Finance Corporation, as Chargee.
       
 
12.1*    
Computation of Ratio of Earnings to Fixed Charges.
       
 
16.1      
Letter on Change in Certifying Accountant from Hein &Associates LLP dated May 25, 2006 (previously filed as Exhibit 16.1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on May 26, 2006, File No. 0-2517, and incorporated herein by reference).
       
 
21.1*    
Subsidiaries of Toreador Resources Corporation.
       
 
23.1*    
Consent of Grant Thornton LLP
       
 
23.2*    
Consent of LaRoche Petroleum Consultants, Ltd.
       
 
24.1*    
Power of Attorney (included as part of the signature page).
       
 
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

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Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
Toreador Resources Corporation
We have audited the accompanying consolidated balance sheets of Toreador Resources Corporation (a Delaware Corporation) and subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of operations and comprehensive income, changes in stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2006. 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 that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Toreador Resources Corporation and subsidiaries as of December 31, 2006 and 2005 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 2 to the consolidated financial statements, effective January 1, 2006, the Company changed its method of accounting for stock-based compensation to conform to Statement of Financial Accounting Standards No. 123 (R), Share-Based Payment.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Toreador Resources Corporation and subsidiaries’ internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 16, 2007, expressed an unqualified opinion on management’s assessment of the effectiveness of internal control over financial reporting and an adverse opinion on the effectiveness of internal control over financial reporting.
/s/ Grant Thornton LLP
Dallas, Texas
March 16, 2007

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TOREADOR RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
(in thousands, except share and per share data)
                 
    December 31,  
    2006     2005  
ASSETS
               
Current assets:
               
Cash and cash equivalents
  $ 12,664     $ 53,113  
Restricted cash
    20,504        
Short-term investments
          40,000  
Accounts receivable
    9,547       8,162  
Income taxes receivable
    1,260       4,453  
Other
    8,445       6,537  
 
           
Total current assets
    52,420       112,265  
 
           
 
               
Oil and natural gas properties, net, using successful efforts method of accounting
    251,015       138,158  
Investments in unconsolidated entities
    2,659       2,251  
Goodwill
    4,551       4,195  
Other assets
    6,559       4,945  
 
           
 
  $ 317,204     $ 261,814  
 
           
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
Current liabilities:
               
Accounts payable and accrued liabilities
  $ 33,827     $ 19,248  
Current portion of long-term debt
    5,000        
Convertible debenture — related party
          810  
Income taxes payable
    745       908  
 
           
Total current liabilities
    39,572       20,966  
 
           
 
               
Long-term accrued liabilities
    394       1,410  
Long-term debt, net of current portion
    21,550       5,000  
Long-term asset retirement obligations
    5,125       3,630  
Deferred income tax liabilities
    17,162       12,199  
Convertible subordinated notes
    86,250       86,250  
 
           
Total liabilities
    170,053       129,455  
 
           
Commitments and contingencies
               
Stockholders’ equity:
               
Preferred stock, Series A-1, $1.00 par value, 4,000,000 shares authorized; liquidation preference of $1,800; 72,000 shares issued
    72       72  
Common stock, $0.15625 par value, 30,000,000 shares authorized;16,655,511 and 16,142,824 shares issued
    2,602       2,522  
Additional paid-in capital
    111,708       108,001  
Retained earnings
    31,980       29,564  
Accumulated other comprehensive income (loss)
    3,323       (3,364 )
Deferred compensation
          (1,902 )
Treasury stock at cost, 721,027 shares
    (2,534 )     (2,534 )
 
           
Total stockholders’ equity
    147,151       132,359  
 
           
 
  $ 317,204     $ 261,814  
 
           
See accompanying notes to the consolidated financial statements

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Table of Contents

TOREADOR RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(in thousands, except per share data)
                         
    Year ended December 31,  
    2006     2005     2004  
Revenue:
                       
Oil and natural gas sales
  $ 40,387     $ 31,117     $ 22,336  
Loss on commodity derivatives
                (1,322 )
Lease bonuses and rentals
                14  
 
                 
Total revenue
    40,387       31,117       21,028  
 
                 
Operating costs and expenses:
                       
Lease operating expense
    10,941       8,198       7,399  
Exploration expense
    3,946       2,940       4,530  
Dry hole and abandonment
    3,099       1,738        
Depreciation, depletion and amortization
    7,544       5,245       4,110  
Impairment of oil and natural gas properties
    345       110        
General and administrative
    9,829       6,680       7,463  
(Gain) loss on sale of properties and other assets
    (638 )     (12 )     159  
 
                 
Total operating costs and expenses
    35,066       24,899       23,661  
 
                 
Operating income (loss)
    5,321       6,218       (2,633 )
Other income (expense):
                       
Equity in earnings (loss) of unconsolidated investments
    401       222       (18 )
Foreign currency exchange gain (loss)
    (605 )     2,386       127  
Interest and other income
    1,988       1,407       515  
Interest expense
    (891 )           (1,414 )
 
                 
Total other income (expense)
    893       4,015       (790 )
 
                 
Income (loss) from continuing operations before income taxes
    6,214       10,233       (3,423 )
Income tax benefit (provision)
    (3,647 )     315       1,153  
 
                 
Income (loss) from continuing operations
    2,567       10,548       (2,270 )
Income from discontinued operations
    11       47       17,690  
 
                 
Net income
    2,578       10,595       15,420  
Preferred dividends
    (162 )     (684 )     (714 )
 
                 
Income available to common shares
  $ 2,416     $ 9,911     $ 14,706  
 
                 
Basic income available to common shares per share from:
                       
Continuing operations
  $ 0.16     $ 0.69     $ (0.31 )
Discontinued operations
                1.85  
 
                 
 
  $ 0.16     $ 0.69     $ 1.54  
 
                 
 
                       
Diluted income available to common shares per share from:
                       
Continuing operations
  $ 0.15     $ 0.65     $ (0.31 )
Discontinued operations
                1.85  
 
                 
 
  $ 0.15     $ 0.65     $ 1.54  
 
                 
 
                       
Weighted average shares outstanding:
                       
Basic
    15,527       14,213       9,571  
Diluted
    15,884       15,140       9,571  
Statement of Comprehensive Income
                       
Net income
  $ 2,578     $ 10,595     $ 15,420  
Foreign currency translation adjustments
    6,687       (8,080 )     2,885  
 
                 
Comprehensive income
  $ 9,265     $ 2,515     $ 18,305  
 
                 
See accompanying notes to the consolidated financial statements.

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TOREADOR RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
(in thousands)
                                                                                 
                                                    Accumulated                      
    Preferred     Preferred     Common     Common     Additional             Other     Treasury             Total  
    Stock     Stock     Stock     Stock     Paid-in     Retained     Comprehensive     Stock     Deferred     Stockholders’  
    (Shares)     ($)     (Shares)     ($)     Capital     Earnings     Income (loss)     ($)     Compensation     Equity  
Balance at December 31, 2003
    320     $ 320       10,059     $ 1,572     $ 33,462     $ 4,947     $ 1,831     $ (2,534 )   $     $ 39,598  
Cash payment of preferred dividends
                                  (714 )                       (714 )
Issuance of stock options for professional services
                            58                               58  
Conversion of preferred stock
    (166 )     (166 )     1,037       162       4                                
Conversion of convertible debenture
                100       16       659                               675  
Exercise of stock options
                528       82       2,228                               2,310  
Tax benefit of stock option exercises
                            1,113                               1,113  
Net income
                                  15,420                         15,420  
Foreign currency translation adjustment
                                        2,885                   2,885  
 
                                                           
Balance at December 31, 2004
    154       154       11,724       1,832       37,524       19,653       4,716       (2,534 )           61,345  
Cash payment of preferred dividends
                                  (186 )                       (186 )
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, net of issuance costs
                2,244       350       55,568                               55,918  
Exercise of stock options
                493       77       2,475                               2,552  
Issuance of warrants
                            60                               60  
Tax benefit of stock option exercises
                            2,557                               2,557  
Exercise of warrants
                20       3       107                               110  
Common shares issued in payment of preferred dividends
                20       3       495       (498 )                        
Issuance of restricted stock
                115       18       2,284                         (2,302 )      
Amortization of deferred stock compensation
                                                    400       400  
Net income
                                  10,595                         10,595  
Foreign currency translation adjustment
                                        (8,080 )                 (8,080 )
 
                                                           
Balance at December 31, 2005
    72       72       16,143       2,522       108,001       29,564       (3,364 )     (2,534 )     (1,902 )     132,359  
Transfer deferred compensation to additional paid-in capital
                            (1,902 )                       1,902        
Cash payment of preferred dividends
                                    (162 )                       (162 )
Conversion of convertible debenture
                120       19       791                               810  
Exercise of stock options
                175       27       839                               866  
Issuance of restricted stock
                214       33       (33 )                              
Exercise of warrants
                4       1       33                               34  
Issuance of warrants
                            883                               883  
Tax benefit of stock option exercises
                            293                               293  
Stock option expense
                            66                               66  
Amortization of deferred stock compensation
                            2,737                               2,737  
Net income
                                    2,578                         2,578  
Foreign currency translation adjustments
                                        6,687                   6,687  
 
                                                           
Balance at December 31, 2006
    72     $ 72       16,656     $ 2,602     $ 111,708     $ 31,980     $ 3,323     $ (2,534 )   $     $ 147,151  
 
                                                           
See accompanying notes to the consolidated financial statements.

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TOREADOR RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
                         
    Year Ended December 31  
    2006     2005     2004  
Cash flows from operating activities:
                       
Net Income
  $ 2,578     $ 10,595     $ 15,420  
Adjustments to reconcile net income to net cash provided by (used in) operating activities
                       
Depreciation and amortization
    7,544       5,245       4,110  
Amortization of deferred debt issuance cost
                383  
Issuance of warrants to non-employee
    107                  
Impairment of oil and natural gas properties
    345       110        
Dry hole and abandonment costs
    3,099       1,738        
Deferred income taxes
    2,642       93       2,556  
Unrealized gain on commodity derivatives
                (1,159 )
Gain on sale of properties and equipment
    (638 )     (12 )     (28,552 )
Equity in (earnings) loss of unconsolidated investments
    (401 )     (222 )     18  
Stock-based compensation
    2,803       400       58  
Gain on sale of marketable securities
                20  
Change in operating assets and liabilities, net of acquisitions
                       
Increase in accounts receivable
    (1,027 )     (4,304 )     (520 )
Increase in income taxes receivable
    (655 )     (4,453 )      
Increase in other assets
    (4,596 )     (9,740 )     (931 )
Increase in accounts payable and accrued liabilities
    (1,322 )     1,097       (360 )
Increase (decrease) in income taxes payable
    3,625       (685 )     780  
 
                 
Net cash provided by (used in) operating activities
    14,104       (138 )     (8,177 )
 
                 
Cash flows from investing activities:
                       
Expenditures for property and equipment
    (105,165 )     (50,163 )     (10,911 )
Restricted cash
    (20,504 )            
Net cash for acquisitions
          (8,751 )      
Proceeds from the sale of properties and equipment
    1,672       29       42,125  
Distributions from unconsolidated entities
    250       191       255  
Sale (purchase) of short-term investments
    40,000       (40,000 )      
Investments in unconsolidated entities
    (257 )     (754 )     (1,210 )
 
                 
Net cash provided by (used in) investing activities
    (84,004 )     (99,448 )     (99,448 )
 
                 
Cash flows from financing activities:
                       
Repayment of revolving credit facilities
    (5,000 )     (4,848 )     (28,816 )
Net borrowings (repayments) under revolving credit arrangements
    26,550       9,811       37  
Exercise of stock options
    866       2,552       2,310  
Proceeds from the exercise of warrants
    34       170        
Proceeds from issuance of common stock, net of issuance cost of $3,940
          55,918        
Tax benefit related to stock options
    293              
Proceeds from issuance of notes payable
          86,250       7,500  
Payment of preferred dividends
    (162 )     (186 )     (714 )
 
                 
Net cash provided by (used in) financing activities
    22,581       149,667       (19,683 )
 
                 
Net increase (decrease) in cash and cash equivalents
    (47,319 )     50,081       2,399  
Effects of foreign currency translation on cash and cash equivalents
    6,870       (1,945 )     (241 )
Cash and cash equivalents, beginning of year
    53,113       4,977       2,819  
 
                 
Cash and cash equivalents, end of year
  $ 12,664     $ 53,113     $ 4,977  
 
                 
Supplemental disclosures:
                       
Cash paid during the period for interest, net of interest capitalized
  $     $     $ 1,304  
Cash paid during the period for income taxes
  $ 2,414     $ 2,690     $ 5,250  
Non-cash investing and financing activities
                       
Conversion of preferred stock to common stock
          82       166  
Conversion of notes payable to common stock
          6,413        
Conversion of convertible debentures to common stock
    810       675       675  
Common shares issued for preferred dividends
          498        
See accompanying notes to the consolidated financial statements.

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TOREADOR RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 — DESCRIPTION OF BUSINESS
     Toreador Resources Corporation (“Toreador”) is an independent energy company engaged in foreign (France, Turkey, Romania and Hungary) 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.
     BASIS OF PRESENTATION
     Toreador consolidates all of its majority-owned subsidiaries (collectively, “we,” “us,” “our,” or the “Company”). All 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.
     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 ($41.9 million net of transaction costs) 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. Certain prior-year amounts have been reclassified to conform to the 2006 presentation. See further discussion in Note 15 to the consolidated financial statements.
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 estimates used. All of the reserve data in the Form 10-K for the year ended December 31, 2006 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 oil and natural gas properties, goodwill, asset retirement obligations and deferred income tax assets. Actual results could differ significantly from those estimates.
     CASH AND CASH EQUIVALENTS AND SHORT-TERM INVESTMENTS
     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.
     As of December 31, 2005 we had $40 million in time deposits bearing interest at 2.87%. Upon maturity in 2006, we transferred these funds to our operating account.
     As of December 31, 2006 and 2005 we had $11.2 million and $6.5 million, respectively, on deposit in foreign banks.

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     RESTRICTED CASH
     Restricted cash consists of $11.5 million held by a bank in the form of certificates of deposit as collateral for a “Stand-by Letter of Credit” required by the contractor for the installation on the offshore pipeline in the Black Sea; $7.8 million deposit used to secure a bank “Letter of Guarantee” that was issued as required under the mediation proceedings with Micoperi, Srl. and $1.2 million is a compensating cash balance as required by our credit facility with Natexis Bank. The total amount of $20.5 million is 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, 2006 or 2005. 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.
     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.
     FINANCIAL INSTRUMENTS
     The carrying amounts of financial instruments including cash and cash equivalents, short-term investments, accounts receivable, accounts payable and accrued liabilities approximate fair value, at December 31, 2006 and 2005, due to the short-term nature or maturity of the instruments.
     Long-term debt approximated 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, 2006 the convertible subordinate notes which had a book value of $86.25 million, were trading at $1,005.80, which would equal a fair market value of approximately $86.8 million.
     DERIVATIVE FINANCIAL INSTRUMENTS
     In 2004, we used 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, in 2004 we periodically entered into oil and natural gas swap and option agreements that fixed the price of oil and natural gas sales within ranges determined acceptable at the time we execute the contracts. Losses from these financial instruments totaled $63,000 in 2004. We did not enter into any commodity contracts in 2006 or 2005.
     In 2006, we purchased and sold 6 foreign currency forward contracts for Turkish Lira, two foreign currency forward contracts for Euros and two call options to purchase Euros.The contracts were purchased primarily to protect our exposure to foreign exchange changes in France and Turkey. When these contracts were settled we recognized a loss of approximately $464,000 that was recorded to foreign exchange gain (loss) on the Statement of Operations.
     We are exposed to credit losses on derivative financial instruments 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, 2006 and 2005, we had no receivables from counterparties.

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     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, 2006 and 2005, other current assets included $1.2 million, and $951,000 of inventory, respectively. Those amounts consist of tubular goods and crude oil held in storage tanks. Inventories are stated at the lower of actual cost or market based on the average cost method.
     ADVANCES PAID TO VENDORS
     At December 31, 2006 and 2005, other current assets included $3.8 million and $1.4 million of payments made to vendors in advance of performing the services or receiving the equipment.
     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. 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 above.
     We capitalize interest on major projects that require an extended period of time to complete. Interest capitalized in 2006, 2005 and 2004 was $4.3 million, $1.4 million, and $432,000, respectively.
     We record furniture, fixtures and equipment at cost.
     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 furniture, fixtures and equipment 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”). 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 $345,000 in 2006, $110,000 in 2005 and zero in 2004.
     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.

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     The following table summarizes the changes in our asset retirement liability during the years ended December 31, 2006 and 2005:
                 
    2006     2005  
    (in thousands)  
Asset retirement obligation January 1
  $ 3,630     $ 3,291  
Asset retirement accretion expense
    246       204  
Foreign currency exchange (gain) loss
    325       (407 )
Change in estimates
    61        
Property additions
    875       542  
Property dispositions
    (12 )      
 
           
Asset retirement obligation at December 31
  $ 5,125     $ 3,630  
 
           
     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 not 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 are amortized over their useful lives. At December 31, 2006 and 2005, we did not have any intangible assets that did not have an indefinite life.
     We review annually the value of goodwill recorded or more frequently if impairment indicators arise. We recognized no goodwill impairment during 2006, 2005 or 2004. Goodwill was reduced by $1.5 million and $1.6 million in 2004 and 2005, respectively, 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. Goodwill was also adjusted $356,000 in 2006 and $211,000 in 2005 for the foreign currency translation adjustment. The balance of goodwill at December 31, 2006 and 2005 is approximately $4.6 million and $4.2 million, respectively.
     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. In 2006, 2005 and 2004 sales to ELF represents approximately 67%, 66% and 63%, respectively, of the Company’s total revenue and approximately 20% and 23% of the Company’s accounts receivable at December 31, 2006 and 2005, respectively.
     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. Taxes associated with production are classified as lease operating expense.

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     STOCK-BASED COMPENSATION
     In December 2004, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 123 (revised 2004), “Share Based Payment,” (SFAS 123R). SFAS 123R establishes the accounting for transactions in which an entity pays for employee services in share-based payment transactions. SFAS 123R requires companies to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. The fair value of employee share options and similar instruments is estimated using option-pricing models adjusted for the unique characteristics of those instruments. That cost is recognized over the period during which an employee is required to provide service in exchange for the award. The Company adopted SFAS 123R effective January 1, 2006, using the modified-prospective transition method. Under this method, compensation cost is recognized for awards granted and for awards modified, repurchased or cancelled in the period after adoption. Compensation cost is also recognized for the unvested portion of awards granted prior to adoption. Prior year financial statements are not restated. The Company’s results for the year ended December 31, 2006, include an additional compensation expense of $65,916, that is included in general and administrative expenses relating to the adoption of SFAS 123R. Additionally, upon adoption of SFAS 123R, excess tax benefits related to stock option exercises of $293,000 were presented as a cash inflow from financing activities.
     Prior to adoption of SFAS 123 R, the Company accounted for stock based compensation plans under APB Opinion No. 25 “Accounting for Stock Issued to Employees.” Compensation cost related to stock options issued to employees was recorded only if the grant-date market price of the underlying stock exceeded the exercise price. The following table illustrates the effect on income available to common shares and earnings available to common shares per share if a fair value based method had been applied to all awards.
                 
    For the Year Ended December 31,
    2005   2004
    (in thousands, except per share data)
Income available to common shares, as reported
  $ 9,911     $ 14,706  
Basic earnings available to common shares per share reported
    0.69       1.54  
Diluted earnings available to common shares per share reported
    0.65       1.54  
Pro-forma stock-based compensation costs under the fair value method, net of related tax
    82       833  
Pro-forma income available to common shares, as under the fair-value method
    9,829       13,873  
Pro-forma basic earnings available to common shares per share under the fair value method
    0.69       1.45  
Pro-forma diluted earnings available to common shares per share under the fair value method
    0.65       1.45  
     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
Dividend yield per share
           
Volatility
    70.9 %     44 %
Risk-free interest rate
    4.0 %     4.58 %
Expected lives
  5 years   3 years
     FOREIGN CURRENCY TRANSLATION
     The functional currency of the countries in which we operate is the U.S. dollar in the United States, Turkey, Romania and Hungary and the Euro in France. Gains and losses resulting from the translations of Euros into U.S. dollars are included in other comprehensive income for the current period. Gains and losses resulting from the transactions in the New Turkish Lira in Turkey, the Lei in Romania and the Forint in Hungary are included in income available to common shares for the current period. We periodically review the operations of our entities to

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ensure the functional currency of each entity is the currency of the primary economic environment in which we operate.
     INCOME TAXES
     We are subject to income taxes in the United States, France, 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. All interest and penalties related to income tax is charged to general and administrative expense. 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. We made a commitment to be fully reinvested in our international subsidiaries.
     LEGAL FEES
     We do not accrue for estimated legal fees or other related costs when accruing for loss contingencies, rather they are expensed as incurred.
     DEFERRED DEBT ISSUE COST
     Deferred debt issue costs are amortized on a straight line basis, which approximates the effective interest method over the term of the loan as a component of interest expense.
     NEW ACCOUNTING PRONOUNCEMENTS
     SFAS No. 157, Fair Value Measurement, (“SFAS 157”). This new standard provides guidance for using fair value to measure assets and liabilities. The Financial Accounting Standards Board (“FASB”) believes the standard also responds to investors’ requirement for expanded information about the extent to which companies measure assets and liabilities at fair value, the information used to measure fair value, and the effect of fair value measurements on earnings. SFAS 157 applies whenever other standards require (or permit) assets or liabilities to be measured at fair value but does not expand the use of fair value in any new circumstances. The standard clarifies that for items that are not actively traded, such as certain kinds of derivatives, fair value should reflect the price in a transaction with a market participant, including an adjustment for risk, not just the company’s mark-to-model value. SFAS 157 also requires expanded disclosure of the effect on earnings for items measured using unobservable data. Under SFAS 157, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the principal market for asset or liability or, in the absence of a principal market, the most advantageous market for the asset or liability. In this standard, the FASB clarifies the principle that fair value should be based on the assumptions market participants would use when pricing the asset or liability. In support of this principle, SFAS 157 establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. The fair value hierarchy gives the highest priority to quoted prices in active markets and the lowest priority to unobservable data, for example, the reporting entity’s own data. Under the standard, fair value measurements would be separately disclosed by level within the fair value hierarchy. The provisions of SFAS 157 are effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. Earlier application is encouraged, provided that the reporting entity has not yet issued financial statements for that fiscal year, including any financial statements for an interim period within that fiscal year. We are currently evaluating this statement and have not yet determined the impact of such on our financial statements. We plan to adopt this statement when required at the start of our fiscal year beginning January 1, 2008.
     On December 21, 2006, the FASB issued FSP No. EITF 00-19-2, “Accounting for Registration Payment Arrangements” (FSP EITF 00-19-2), which addresses an issuer’s accounting for registration payment arrangements and specifies that the contingent obligation to make future payments or otherwise transfer consideration under a registration payment arrangement, whether issued as a separate agreement or included as a provision of a financial instrument or other agreement, should be separately recognized and measured in accordance with FASB SFAS No.

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5, “Accounting for Contingencies.” FSP EITF 00-19-2 is effective immediately for registration payment arrangements and the financial instruments subject to those arrangements that are entered into or modified subsequent to the date of its issuance. For registration payment arrangements and financial instruments subject to those arrangements that were entered into prior to the issuance of FSP EITF 00-19-2, this guidance shall be effective for financial statements issued for fiscal years beginning after December 15, 2006, and interim periods within those fiscal years. We do not expect this standard to have any effect upon adoption because the Company’s policy has been to accrue such liabilities when they are deemed probable.
     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. We adopted FAS 19-1 as of December 31, 2005.
     FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes — An Interpretation of FASB Statement No. 109, (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109. FIN 48 also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The new FASB standard also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. The evaluation of a tax position in accordance with FIN 48 is a two-step process. The first step is a recognition process whereby the enterprise determines whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more-likely-than-not recognition threshold, the enterprise should presume that the position will be examined by the appropriate taxing authority that has full knowledge of all relevant information. The second step is a measurement process whereby a tax position that meets the more-likely-than-not recognition threshold is calculated to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006. Earlier application is permitted as long as the enterprise has not yet issued financial statements, including interim financial statements, in the period of adoption. The provisions of FIN 48 are to be applied to all tax positions upon initial adoption of this standard. Only tax positions that meet the more-likely-than-not recognition threshold at the effective date may be recognized or continue to be recognized upon adoption of FIN 48. The cumulative effect of applying the provisions of FIN 48 should be reported as an adjustment to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) in the year of adoption. We plan to adopt this statement when required at the start of our fiscal year beginning January 1, 2007. We are still determining the impact, if any, that this statement will have on our financial statements.
     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 have determined that the impact on our financial statements will not be material. We have adopted FASB 155 on January 1, 2007.

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     On December 16, 2004, FASB issued SFAS No. 153, Exchanges of Nonmonetary Assets, an Amendment of APB Opinion No. 29, Accounting for Nonmonetary Transactions (“ SFAS 153”). This statement amends APB Opinion 29 to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. Under SFAS 153, if a nonmonetary exchange of similar productive assets meets a commercial-substance criterion and fair value is determinable, the transaction must be accounted for at fair value resulting in recognition of any gain or loss. SFAS 153 is effective for nonmonetary transactions in fiscal periods that begin after June 15, 2005. This standard did not have a material impact on our financial position, results of operations or cash flows.
     SEC Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements (“SAB No. 108”). In September 2006, the Securities and Exchange Commission (SEC) provided guidance on the consideration of the effects of prior year misstatements in quantifying current year misstatements for the purpose of a materiality assessment. SAB No. 108 establishes a dual approach that requires quantification of financial statement errors based on the effects of the error on each of the company’s financial statements and the related financial statement disclosures. SAB No. 108 is effective for fiscal years ending after November 15, 2006. We adopted SAB No. 108 in 2006. The adoption of this statement did not impact our financial statements.
     In February 2007, the FASB issued Statement 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement 115”. The statement permits entities to chosse to measure certain financial instruments and other items at fair value. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. Unrealized gains and losses on any items for which Toreador elects the fair value measurement option would be reported in earnings. Statement 159 is effective for fiscal years beginning after November 15, 2007. However, early adoption is permitted for fiscal years beginning on or before November 15, 2007, provided Toreador also elects to apply the provisions of Statement 157, “Fair Value Measurements”, at the same time. Toreador is currently assessing the effect, if any, the adoption of Statement 159 will have on its financial statements and related disclosures.
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 from the date of acquisition. Our results of operations would not have been different than reported and, therefore, we have not provided any pro forma disclosures. The purchase price was approximately $9 million, which was settled in cash and was allocated as follows (in thousands):
         
    Value  
    Allocated  
Cash and other current assets
  $ 254  
Plant, property and equipment — materials and supplies inventory
    3,141  
Non-producing lease cost
    5,822  
Other assets
    259  
Accounts payable
    (476 )
 
     
Total purchase price allocation
  $ 9,000  
 
     

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NOTE 4 — 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 are 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,  
    2006     2005     2004  
    (in thousands, except per share data)  
Basic earnings per share:
                       
Numerator
                       
Income (loss) from continuing operations, net of income tax
  $ 2,567     $ 10,548     $ (2,270 )
Less: dividends on preferred shares
    162       684       714  
 
                 
Income (loss) from continuing operations, net of tax
    2,405       9,864       (2,984 )
Income from discontinued operations, net of tax
    11       47       17,690  
 
                 
Income available to common shares
  $ 2,416     $ 9,911     $ 14,706  
 
                 
Denominator
                       
Common shares outstanding
    15,527       14,213       9,571  
Basic earnings available to common shares per share from:
                       
Continuing operations
  $ 0.16     $ 0.69     $ (0.31 )
Discontinued operations
                1.85  
 
                 
Basic income per share
  $ 0.16     $ 0.69     $ 1.54  
 
                 
Diluted earnings per share:
                       
Numerator
                       
Income (loss) from continuing operations, net of income tax
  $ 2,567     $ 10,548     $ (2,270 )
Less: dividends on preferred shares
    162       684       714  
Add: interest on convertible debentures
            73        
 
                   
Income (loss) from continuing operations, net of tax
    2,405       9,937       (2,984 )
Income (loss) from discontinued operations, net of tax
    11       47       17,690  
 
                 
 
  $ 2,416     $ 9,984     $ 14,706  
 
                 
Denominator
                       
Common shares outstanding
    15,527       14,213       9,571  
Stock options, restricted stock and warrants
    357       746     (2)
Conversion of preferred shares
    (1)     (1)     (2)
Conversion of 7.85% notes payable (4)
          (1)     (2)
Conversion of 5.0% notes payable (3)
    (1)     (1)     (3)
Conversion of debentures
    (1)     181       (2)
 
                 
Diluted shares outstanding
    15,884       15,140       9,571  
 
                 
Diluted earnings available to common shares per share from:
                       
Continuing operations
  $ 0.15     $ 0.65     $ (0.31 )
Discontinued operations
                1.85  
 
                 
Diluted income per share
  $ 0.15     $ 0.65     $ 1.54  
 
                 
Anti-dilutive securities not included above are as follows:
                       
Stock options, restricted stock and warrants
                523  
Preferred shares
    450       524       1,997  
7.85% notes payable (4)
          43       410  
Debentures
    26             316  
5% notes payable (3)
    2,015       552        
 
(1)   Conversion of these securities would be antidilutive; therefore, there are no dilutive shares.
 
(2)   Conversion of these securities would be antidilutive in 2004 due to operating losses, therefore, are not included for the calculation of diluted earnings per share in 2004.
 
(3)   5% Senior Convertible Notes were issued on September 27, 2005.
 
(4)   7.85% Notes Payable were issued in July 2004 and subsequently exchanged in January 2005

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NOTE 5 — ACCOUNTS RECEIVABLE
     Accounts receivable consisted of the following:
                 
    December 31,  
    2006     2005  
    (in thousands)  
Accrued oil and natural gas sales receivables
  $ 4,209     $ 5,608  
Trade receivables
    3,394       2,142  
Other accounts receivable
    1,944       412  
 
           
 
  $ 9,547     $ 8,162  
 
           
     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 and amounts due from contractors where we have paid for supplies on their behalf. These receivables are generally due within 15 days after receipt of monthly joint interest billing or they are offset against invoices from contractors when billed.
     Other receivables are accrued interest receivable, at December 31, 2006 and 2005 on time deposits, value added tax refunds and travel advances to employees.
NOTE 6 — OIL AND NATURAL GAS PROPERTIES
     Oil and Natural Gas Properties consist of the following:
                 
    December 31,  
    2006     2005  
    (in thousands)  
Licenses and concessions
  $ 3,895     $ 3,879  
Non-producing leaseholds
    149,481       64,521  
Producing leaseholds and intangible drilling costs
    139,761       102,855  
Furniture, fixtures and office equipment
    3,183       2,365  
 
           
 
    296,320       173,620  
Accumulated depreciation, depletion and amortization
    (45,305 )     (35,462 )
 
           
Total oil and natural gas properties
  $ 251,015     $ 138,158  
 
           
     The Company capitalizes exploratory well costs until a determination is made that the well has found proved reserves or is deemed noncommercial, in the latter 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  
    2006     2005  
    (in thousands)  
Capitalized exploratory well cost, beginning of the year
  $ 1,042     $ 2,307  
Additions to capitalized exploratory well costs pending determination of proved reserves
    4,400       1,042  
Reclassified to oil and natural gas properties based on determination of proved reserves
    (186 )     (2,307 )
 
           
Capitalized exploratory well costs, end of year
  $ 5,256     $ 1,042  
 
           

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     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  
    2006     2005  
    (in thousands)  
Capitalized exploratory well cost that have been capitalized for a period of one year or less
  $ 4,400     $ 1,042  
Capitalized exploratory well cost that have been capitalized for a period greater than one year
    856        
 
           
Balance at the end of the year
  $ 5,256     $ 1,042  
 
           
     Included in the capitalized exploratory cost are three wells located in the United States, two wells in Hungary and two wells in Romania. We anticipate that the results of all these wells will be known by December 31, 2007.
NOTE 7 — INVESTMENTS IN UNCONSOLIDATED ENTITIES
     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, 2006 and 2005 our investment in ePsolutions amounted to $1.5 million and $1.3 million, respectively. For the years ended December 31, 2006 and 2005 we advanced $257,000 and $759,000, respectively, and we recorded equity in the loss of ePsolutions of $70,000 in 2006, a loss 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, 2006 and 2005, our investment in EnergyNet amounted to $997,000 and $832,000, respectively. We recorded equity in the earnings of EnergyNet of $340,000 in 2006, $409,000 in 2005 and $279,000 in 2004. We received a dividend from EnergyNet of $175,000 in 2006, $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 $160,000 and $104,000 at December 31, 2006 and 2005, respectively. We recorded equity in the earnings of Capstone amounting to $131,000 in 2006, $51,000 in 2005 and $15,000 in 2004. We received a distribution from capstone of $75,000 in 2006, $60,000 in 2005 and $25,000 in 2004.
NOTE 8 — LONG-TERM DEBT
     Long-term debt consisted of the following:
                 
    December 31,  
    2006     2005  
    (in thousands)  
Revolving line of credit with Texas Capital Bank, N.A
  $ 5,550     $  
Revolving line of credit with Natexis Banques Populaires
    11,000       5,000  
Secured revolving facility with the International Finance Corporation
    10,000        
Convertible senior notes
    86,250       86,250  
Convertible debenture — related party
          810  
 
           
 
    112,800       92,060  
Less: current portion
    (5,000 )     (810 )
 
           
 
  $ 107,800     $ 91,250  
 
           
     CONVERTIBLE SENIOR NOTES DUE OCTOBER 1, 2025
     On September 27, 2005, we issued $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

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$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; these costs have been recorded in other assets on the balance sheet and are being amortized to interest expense using the straight-line interest rate method over the term of the Notes. The net proceeds were 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 in an event of a fundamental change, as defined, (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 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.
     Due to our restating the consolidated financial statements for the years ended December 31, 2003, 2004 and 2005 and our consolidated financial statements for each of the quarters ended March 31 and June 30, 2006, we did not provide the trustee under the indenture of the Convertible Senior Notes with copies of our annual reports, information, documents and other reports that we are required to file with the Securities and Exchange Commission pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 within thirty (30) days of when such reports are required to be filed with the Securities and Exchange Commission.
     On December 15, 2006, we received a notice from the trustee for failing to provide the trustee with a copy of our Form 10-Q for the nine month period ended September 30, 2006. Since we cured the covenant default within thirty (30) days after receiving the written notice from the trustee, we cured the default and an event of default did not occur.
     The registration rights agreement covering the Notes provides for a penalty if the registration statement is filed and declared effective but thereafter ceases to be effective (a “Suspension Period”) for an aggregate of forty-five (45) days in any three month period or ninety (90) days in any twelve month period (an “Event Date”). Such penalty calls for an additional 0.25% per annum in interest expense on the aggregate principal amount of the Notes for the first ninety (90) days following an Event Date and an additional 0.50% per annum in interest expense on the aggregate principal amount of the Notes thereafter, until such Suspension Period ends upon the registration statement again becoming effective. Because we did not file our Quarterly Report on Form 10-Q for the nine month period ended September 30, 2006 in a timely manner, the registration statement for the Convertible Senior Notes became ineffective and we entered a Suspension Period on November 15, 2006. Such Suspension Period ended on January 23, 2007 when we provided notice that the Form 10-Q had been filed and the Suspension Period was no longer in effect. Because the Suspension Period exceeded forty-five (45) days in any three month period, we will owe approximately $14,375 in additional interest expense. Once we file our Form 10-K for the year ended December 31, 2006, we will again enter a Suspension Period until we can file and have declared effective an amendment to our registration statement on Form S-1. Therefore, we have accrued a liability of $53,168 at December 31, 2006, which represents 90 days of additional interest at 0.25%. Because of the previous Suspension Period, we will exceed the ninety (90) days in any twelve month period on the twenty first (21st) day following the filing of our Form 10-K and will again begin to accrue additional interest as described above until we can file and have declared effective an amendment to our registration statement on Form S-1.
     REVOLVING LINE OF CREDIT WITH NATIXIS 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 other corporate purposes. The facility bears interest at a floating rate of 2.25-2.75% above LIBOR (8.125% at

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December 31, 2006) 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. The Company 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, 2006, on the available and unused facility borrowings. Under the $15.0 million facility, at December 31, 2006, borrowings of approximately $909,000 were available and $11 million was outstanding. 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 a result of not providing Natixis with our unaudited consolidated financial statements for the nine month period ended September 30, 2006 within forty-five (45) days after the end of such quarter, we were in default under the $15 million facility. Until January 16, 2007, Natixis waived such default and any other default under the facility as a result of us not yet providing such financial statements. On January 16, 2007, we filed the Form 10-Q for the quarter ended September 30, 2006 and provided the unaudited consolidated financial statements contained in the Form 10-Q to Natixis which cured the default.
     On March 2, 2007, the facility was retired and all amounts due were paid.
     SECURED REVOLVING FACILITY WITH THE INTERNATIONAL FINANCE CORPORATION
On December 28, 2006, we guaranteed the obligations of certain of our direct and indirect subsidiaries in a loan and guarantee agreement with International Finance Corporation. The loan and guarantee agreement provides for the $25 million loan facility which is a secured revolving facility with a current maximum facility amount of $25 million which maximum facility amount will increase to $40 million when the projected total borrowing base amount exceeds $50 million. The $25 million facility was funded on March 2, 2007. The loan and guarantee agreement also provides for a $10 million facility. As of December 31, 2006 and March 8, 2007, the $10 million facility has $10.0 million outstanding. All amounts available under the new secured revolving facility have been funded. Both the $25 million facility and $10 million facility are to fund the our operations in Turkey and Romania.
Interest accrues on any loans under the A loan facility at a rate of 2% over the six month LIBOR rate. Interest accrued on the $10 million facility at a rate of 1.5% over the six month LIBOR rate until the $25 million facility was funded after which the rate for the $10 million facility was lowered to 0.5% over the six month LIBOR rate. As of December 31, 2006, the interest rate on the $10 million facility was 6.86%. As of March 8, 2007, the interest rate on the $10 million facility was 5.849% and the interest rate on the $25 million facility was 7.349%. Interest is to be paid on each June 15 and December 15.
The $25 million facility provided the following: (i) the lender has a first ranking security interest (a) in certain proceeds, receivables and contract rights relating to and from the sale of oil or gas production in France, Turkey and Romania and (b) in funds held in certain bank accounts; (ii) the lender has an assignment of all rights and claims to any compensation or other special payments in respect of all concessions other than those arising in the normal course of operations payable by the government of Turkey and Romania; and (iii) the lender has a first ranking pledge (a) by Toreador International Holding, LLC of all its shares in the borrowers; (b) by Madison Oil France SAS of all its shares in Toreador France; and (c) by the Company of all its shares in Toreador International Holding, LLC.
     On December 31, 2011, the maximum amount available under the $25 million facility begins to decrease by $5 million every six months from $40 million (assuming the projected borrowing base amount exceeds $50 million) until the final portion of the $25 million facility is due on December 15, 2014. On December 15, 2014, $5 million of the $10 million facility is to be repaid with the remaining $5 million being due on June 15, 2015.

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     The Company is required to meet the following ratios on a consolidated basis: (i) the life of loan coverage ratio of not less than: (a) 1.2:1.0 in 2006 and 2007; (b) 1.3:1.0 in 2008; and (c) 1.4:1.0 in 2009 and each subsequent year thereafter; (ii) reserve tail ratio of not less than 25%; (iii) adjusted financed debt to EBITDA ratio of not more than 3.0:1.0; (iv) liabilities to tangible net worth ratio of not more than 60:40; and (v) interest coverage ratio of not less than 3.0:1.0.
     The obligors are subject to certain negative covenants, including, but not limited to, the following: (i) subject to certain exceptions, paying dividends; (ii) subject to certain exceptions, incurring debt, making guarantees or creating or permitting to exist any liens, (iii) subject to certain exceptions, making or permitting to exist loans or advances to, or deposits, with other persons or investments in any person or enterprise; (iv) subject to certain exceptions, selling, transferring, leasing or otherwise disposing of all or a material part of its borrowing base assets; and (v) subject to certain exceptions, undertaking or permitting any merger, spin-off, consolidation or reorganization.
     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% (7.75% total rate at December 31, 2006) and is collateralized by our domestic working interests. The borrowers under this facility are two of our domestic subsidiaries, and the Company has guaranteed the obligations. At December 31, 2006, we had approximately $450,000 available for borrowings and the outstanding amount was $5.6 million. The Texas Capital facility requires monthly interest payments until January 1, 2010 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, 2006, on the available and unused facility borrowings. The Texas Capital 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.
     We were in default under the Texas Capital facility for failing to provide Texas Capital on or before the 60th day after the last day of the fiscal quarter ended September 30, 2006 with a copy of the unaudited consolidated financial statements of Toreador and there was an event of default under the Texas Capital facility for defaulting in the performance or observance of a provision under the Senior Convertible Notes. Texas Capital waived the default and event of default until January 16, 2007. On January 16, 2007, we filed the Form 10-Q for the quarter ended September 30, 2006 and provided the unaudited consolidated financial statements contained in the Form 10-Q to Texas Capital which cured the default.
     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 provided the conversion notice to the holders of the 7.85% notes to require the holders 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 the required conversion date. On or prior to January 20, 2005, all of our 7.85% convertible subordinated notes due June 30, 2009 (with a carrying value, net of unamortized loan fees of $6.4 million) were exchanged for an aggregate of 914,634 shares of our common stock and an aggregate cash payment for interest of approximately $85,000 which is included in interest expense in 2005.

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     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 the Company’s right under certain circumstances to force a conversion of the principal into shares of Toreador common stock and eliminate the Company’s ability to repay principal prior to maturity. The maturity date remained March 31, 2006. At the holder’s option, the second amended and restated convertible debenture could 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 debent