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Article by DailyStocks_admin    (07-10-08 08:41 AM)

Filed with the SEC from June 26 to July 2:

Toreador Resources (TRGL)
MatlinPatterson Capital Management, which has 2,200,599 shares (10.8%), suggested the Dallas energy company be sold. Original Filings

BUSINESS OVERVIEW

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 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. At December 31, 2007, we held interests in approximately 5.9 million gross acres and approximately 4.8 million net acres, of which 99.4% are undeveloped. At December 31, 2007, our estimated net proved reserves were 13.3 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 99% of our total proved reserves as of December 31, 2007 and approximately 82.8% of our total production for the year ended December 31, 2007.

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

Turkey

In the South Akcakoca Sub-basin project (SASB) located offshore Turkey in the Black Sea, the tie-in of the Ayazli platform is finished and production is expected to begin from that platform by mid-March 2008. As of March 14, 2008 production from the Akkaya and Dogu Ayazli platforms is approximately 16 million cubic feet of gas per day (MMCFD) with the Ayazli platform expected to add another 15 MMCFD of production. The February 2008 wellhead price for natural gas from the SASB is approximately $10.21 per thousand cubic feet of gas (MCF) and is expected to be increased to over $11.00 per MCF in May by a mandated rise in the price charged for uninterruptible gas supply to industrial customers in Turkey by BĂ–TAĹž, the Turkish state pipeline operator.

Toreador is currently evaluating several offers for a portion of its working interest in the SASB and expects to receive another offer in early April. The evaluation process is expected to conclude soon after the receipt of the offer in April and public filings will be made should one of the offers be accepted. Currently Toreador holds a 36.75% working interest in the South Akcakoca Sub-basin and the eight adjacent offshore exploration blocks. The operator is TPAO, the Turkish national oil company which holds a 51% working interest, with the remaining 12.25% working interest held by Stratic Energy Corporation.

Hungary

Preparations are being made for the drilling of two exploration wells in Toreador’s Szolnok exploration block. As previously disclosed, four joint venture partners are providing approximately $10 million in capital for the drilling of two wells and a 3-D seismic program in return for a 75% working interest in the Szolnok block. Toreador is the operator and is being carried for its 25% working interest to the casing point in the two wells and the 3-D survey. It is anticipated that the first well will spud and the 3-D survey will commence in April. The second well will immediately follow the first.

Another joint venture in Hungary is expected to be completed before the end of March 2008 with a private European oil and gas company to drill and test a delineation well in Toreador’s Tompa exploration block. The well will be drilled in an updip location to evaluate a deep gas play that was first detected by two wells drilled in the late 1980’s by OKGT (the former Hungarian state oil company) and the U.S. Geological Survey. The wells produced gas in drill stem tests from a conglomerate encountered below 3,200 meters depth in the northwestern corner of the Tompa block. The proposed terms of the joint venture are for the partner to drill, case and test a well projected to cost up to $16 million in return for a 75% interest in the Tompa block. Toreador will be carried for the first well and retain a 25% working interest in the block.

Romania

In the fourth quarter of 2007 we completed a 2D seismic survey of approximately 252 sq. km. in the Moinesti and Viperesti license areas. The data is currently being processed and final interpretation should be finalized in the second quarter of 2008.

Strategy

Our business strategy is to grow our oil and natural gas reserves, production volumes and cash flows through drilling internally generated prospects. 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 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 have changed our strategy to farmout all seismic and exploration drilling. We will attempt to secure partners to pay for all seismic and drilling costs up to casing point. Our plan is for industry partners to pay for 100% of all exploratory costs in order to earn a 50%-75% working interest.

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.

Our Properties

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 34 exploration and one exploitation permit covering approximately 3 million net acres. Our exploration and development program focuses on the following areas:

Western Black Sea Permits

The Turkish national oil company, TPAO, currently is the operator, and we hold a 36.75% working interest in the Western Black Sea permits, which cover approximately 961,550 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 14 additional 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. During 2007 we drilled Akcakoca-3, Akcakoca-4, Guluc, Alap 1 -1 and Bati Eskikale-1 wells, the first three of which required a floating rig, and completed the first phase of pipeline and facility construction with first production commencing in May 2007. The first phase of infrastructure development included: setting up three production platforms; laying a sub-sea pipeline; 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 acquired approximately 325 km. of high resolution 2D marine seismic survey on the permit in preparation for an exploration program.

Thrace Black Sea Permits

The Thrace Black Sea permits are located offshore Turkey in the Black Sea between Bulgarian waters and the Bosphorus Straits. We are the operator and hold a 50% working interest in the permit covering 844,382 gross 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. of 2D marine seismic program. The Karaburun #1 was drilled as a dry hole in 2007.

Sea of Marmara Permit

We have an exploration permit on three blocks in the Marmara Sea offshore Turkey to the south of the city of Tekirdag. The three blocks total approximately 364,448 acres. We are the operator and hold 100% working interest in this permit.

Central Black Sea Permits

In August 2007, the Turkish government awarded us an additional offshore permit located in shallow waters offshore central Turkey to supplement our two permits in the same district. Altogether the three permits cover approximately 329,204 acres. We intend to acquire 1000 km. of 2D marine seismic survey in 2008, and we will then conduct a full analysis of existing technical data on these three 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 the fourth quarter of 2006, we completed approximately 90 km. of 2D seismic data. The rest of the 1,000 km program is scheduled to be completed in mid-2008.

Van Permit

The Van permit area is in Eastern Turkey and covers approximately 964,629 acres. We have been gathering geological and geophysical data to define prospective structures. We have already initiated re-processing of existing 2D seismic data in the permit area and plan to acquire approximately 300 km. of 2D onshore seismic survey in 2008. We are the operator of and hold a 100% working interest in this permit.

Adiyaman Permits

The Adiyaman permits, in which we hold a 100% working interest, cover approximately 39,450 acres located in southeast Turkey. We have already initiated re-processing of existing 2D seismic data in the permit area.

Bakuk Permit

Onshore in southeast Turkey, at the Syrian border, we have an exploration permit on one block of approximately 95,897 acres. The block is west of some existing oil and gas fields. We are the operator of and hold a 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.

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

During 2006 and 2007, extensive historic 2D seismic was reprocessed and interpreted. The review is ongoing but to date, has delineated multiple leads and prospects mainly on the northwestern and southern parts of the exploration area. A farm-out valued at $10 million was completed in December 2007 and includes the drilling of two exploration wells and acquiring 170 sq. km. of 3D plus 50 km of 2D seismic. The drilling is expected to commence in the first half of 2008 whereas the seismic program is planned for the second quarter of 2008. Permit applications have been submitted for the primary work program whereas further permit applications are currently being prepared which should enable the drilling of several additional prospects in 2009, each of which will test a variety of features and concepts both stratigraphic and structural in nature. Two gas wells were drilled by the previous operator in the Szolnok Block, each of which initially tested at over 4 Mmcf per day. Several production options are currently being investigated.

Tompa Block

In the first quarter of 2007 the Company completed an exploration and re-entry development program that was initiated in the second half of 2006. The exploration wells failed to encounter commercial hydrocarbons; however, the re-entry wells were successful. We are currently evaluating the most economical way to proceed in commencing production from the re-entry wells. The farm-out process currently is in process and as such, it is expected that an exploratory well may be drilled in late 2008 or early 2009.

Romania

We established our initial position in Romania in early 2004 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% interest in 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 2007 the well was plugged and abandoned. In February 2007, we spudded the second well, the Naeni #6 well, which was drilled to a total depth of 1,657 meters and was plugged and abandoned as a dry hole after logging. The third well in a multi-well exploration program planned for 2007 and 2008, the Lapos-2, was spudded in the Company’s Viperesti block in April and was plugged and abandoned as a dry hole. We have acquired approximately 107 sq km of new 2D seismic, a project that was completed in September 2007. Processing and interpretation of the 2D data is in progress.

Moinesti Permit

We are the operator and hold 100% of this exploration permit, covering approximately 300,000 acres. We have acquired approximately 145 km. of new 2D seismic, a project that was completed in November 2007. Processing and interpretation of the 2D data is in progress.

Fauresti Rehabilitation Permit

We are the operator and hold 100% of this rehabilitation permit. 5.0 sq. km. of 3D seismic survey over the Fauresti lease has been acquired. Processing and interpretation of the 3D acquired data is in progress.

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 24,260 net acres as well as seven exploration permits covering approximately 454,800 net acres.

Charmottes Field

We hold a 100% working interest and operate the permit covering the Charmottes Field, which currently has 7 producing oil wells. The field is produced from two separate reservoirs, one at 1,500 meters (4,500 feet) in the fractured limestone of the Dogger formation and the second one from the Triassic sandstones at 2,500 meters (7,500 feet) in the Donnemarie formation. Production is approximately 150 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, which is comprised of a group of four oil fields. The complex currently has 80 producing oil wells and production is approximately 890 BOPD.

Courtenay Permit

We hold a 100% working interest and are the operator of this permit covering approximately 93,159 net acres which surrounds the Neocomian Fields. An exploration well was drilled in February 2007 to test a Neocomian sand objective and was plugged and abandoned.

Nemours Permit

We hold a 50% working interest in this permit covering approximately 23,635 net acres which is operated by Lundin Petroleum AB.

Aufferville Permit

We hold a 100% working interest and operate this permit covering approximately 33,111 acres. An exploration well was drilled in April 2007 that did not encounter commercial hydrocarbon and was declared a dry hole. Seismic data is being reprocessed and reinterpreted to generate new prospects maps. Several leads remain to be tested on this acreage.

Rigny Permit

We hold a 100% working interest and operate this permit covering approximately 82,779 acres. The existing seismic lines representing around 1000 km have been reprocessed and may lead to drillable prospect in the coming years.

Joigny Permit

We hold a 100% working interest and operate this permit covering approximately 33,100 acres. Geophysical and geological work is being done now to identify drillable prospects in the shallow Cretaceous and Jurassic section.

Malesherbes Permit

We hold a 100% working interest and operate this permit covering approximately 65,902 acres. The existing seismic lines representing around 900 km have been reprocessed to identify drillable Dogger prospects in the Jurassic section, analogous to the Itteville field and located immediately north of this acreage.

Mairy Permit

We hold a 30% working interest in this permit covering approximately 32,914 acres and operated by Lundin Petroleum A.B. The seismic data will be reprocessed during 2008 to identify and confirm two prospects in the Triassic Rhaetic sands, the primary play in this area of the Paris Basin.

United States

On September 1, 2007, we completed the sale of our U.S. oil and gas properties for approximately $19.1 million.

Title to Oil and Natural Gas Properties

We do not hold title to any of our 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 34 exploration permits covering seven Petroleum Districts. The Western Black Sea permits have been extended through to November 2010. The Bakuk permit and the Eastern Black Sea permits expire in September 2009. The Thrace Black Sea licenses expire in June 2008 and these will be extended by a further two years. The Central Black Sea license will be extended from the first quarter of 2009 for a further two years. The Van and Adiyaman permits expire in May and July, 2010, respectively, and the Sea of Marmara permit expires in late 2011.

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. In the opinion of Toreador’s Turkish counsel, Gunel & Kaya, a holder of an exploration permit that has had a discovery made on such exploration permit area and who applies for an exploitation permit in accordance with Turkish petroleum law shall be granted an exploitation permit for any area or areas covered by the exploration permit up to one-half of the exploration permit area. Therefore, in the opinion of Gunel & Kaya, upon application for an exploitation permit, the exploration permit covering the area of the South Akcakoca Sub-Basin in which the gas discovery was made will be converted into an exploitation permit with an initial period of 20 years.

In addition, the Cendere exploitation permits are in their initial 20 year period and are eligible for renewal for up to two periods of 10 years each. In the opinion of Gunel & Kaya, renewal applications for exploitation permits will be granted to those holders who have production of economical quantities of petroleum and comply fully with the obligations under the Turkish petroleum law. There is a long and clear track record of extending exploitation permits as since 1998, there have been at least 48 renewals of exploitation permits, with a majority of those renewals occurring since 2001, and as of March 6, 2008, an application for renewal of an exploitation permit has never been denied and at least 69 conversions of exploration permits to exploitation permits have been granted and as of March 6, 2008, an application for conversion of an exploration permit to an exploitation permit has never been denied. However, there can be no assurance that our exploration permit will be converted into an exploitation permit or that our exploitation permits will be renewed.

CEO BACKGROUND

Alan D. Bell

Until his retirement in June 2006, Mr. Bell was the director of Ernst & Young LLP’s energy practice in the Southwest U.S. area. He started his career with Ernst & Young in 1973 and has extensive experience in the international oil and gas industry in Africa, Australia, Europe and the Middle East. He is also a director for Dune Energy. Mr. Bell earned a master’s degree in business from Tulane University and a bachelor’s degree in petroleum engineering from the Colorado School of Mines and is a certified public accountant licensed in Texas.

David M. Brewer

Mr. David Brewer co-founded Madison Oil Company in 1993, has been a director of Madison Oil Company since 1993, and was President of Madison Oil Company from 1993 to 2000. He has been an investor and entrepreneur since 2000. Formerly, he was an attorney with the New York firm of Cravath, Swaine & Moore and with Union Pacific Corporation.

Peter L. Falb

Mr. Falb is a Principal of Dane, Falb, Stone & Co., Inc., a Boston-based registered investment advisor since 1977, a Professor of Applied Mathematics, Brown University and the Managing Director of the F-Co. Holdings Companies.

Nigel J. Lovett

Mr. Lovett has served as President and Chief Executive Officer of Toreador since January 25, 2007. From May 2003 to January 25, 2007, he was the Managing Partner of Horsley Partners, LLC, his own investment and advisory firm. From 1998 until May 2003, he worked on private equity transactions and mergers and acquisitions advisory work for RP&C International. From 1986 until 1998, he worked with Lehman Brothers in a number of positions, including head of Lehman Brothers’ Asian investment banking and a manager of Lehman’s global banking business.

John Mark McLaughlin

Mr. McLaughlin is Chairman of the Board of Directors of Toreador. Since 1954, he has been and is currently an attorney in private practice in San Angelo, Texas. He is President of Double-M Ranch Ltd., a family-owned Texas limited partnership, and Chairman of the Board of Texas State Bank, San Angelo, Texas. He served as President of Toreador from April 1997 to July 1998.

Nicholas Rostow

In March 2006, Mr. Rostow was appointed University Counsel and Vice Chancellor for Legal Affairs of the State University of New York (SUNY). Also, he is a tenured Professor at SUNY and a University Fellow at SUNY’s Levin Graduate Institute of International Relations and Commerce. In August 2005, he joined The Research Foundation of SUNY as Senior Counsel. From October 2001 until August 2005, he was General Counsel and Senior Policy Adviser to the U.S. Permanent Representative to the United Nations. Prior to October 2001, he was the Charles H. Stockton Chair in International Law at the U.S. Naval War College. From 1999 until 2000, he was the Staff Director of the Senate Select Committee on Intelligence and from 1998 until 1999 he was Counsel and Deputy Staff Director of the House Select Committee on Military/Commercial Concerns. Previously, he was Special Assistant for National Security Affairs to Presidents Reagan and George H.W. Bush and Legal Adviser to the National Security Council under National Security Advisers Colin L. Powell and Brent Scowcroft.

Herbert C. Williamson III

Mr. Williamson is a private investor and has significant oil and gas experience with a strong focus on international activities. From July 2001 to June 2002, he was a part-time consultant to Petrie Parkman and Company for new business development. From April 1999 through July 2001 he was a Director and interim Chief Financial Officer of Merlon Petroleum. From October 1998 through April 1999 he was a Director and Chief Financial Officer of Seven Seas Petroleum. From 1995 through 1998 he was a Director in the Energy Group of Credit Suisse. From 1985 until 1995, he was Vice Chairman and Executive Vice President at Parker & Parsley Petroleum. He is also a director of Westside Energy.

MANAGEMENT DISCUSSION FROM LATEST 10K

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 focus on 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 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.

Loss available to common shares for 2007 was $74.6 million, or a loss of $4.07 per diluted share, compared with income applicable to common shares of $2.4 million, or $0.15 per diluted share, in 2006. Operating loss for 2007 was $57.4 million, compared with operating income of $3.6 million in 2006.

Revenues for the year ended December 31, 2007 were $41.7 million, a 25% increase over 2006 revenues of $33.3 million.

In 2007, our oil and natural gas production was 724,324 BOE versus production of 741,609 BOE for 2006. Our average realized oil price per barrel for 2007 was $66.50, a 9% increase over the average realized oil price per barrel of $60.86 in 2006. The average realized gas price in 2007 was $7.00 per Mcf, 96% greater than the average realized gas price of $3.57 per Mcf in 2006.

For the twelve months ended December 31, 2007, we drilled three dry holes in Romania, two in Hungary, two in France and one in Turkey which resulted in an expense of $21.8 million and had a significant impact on income from operations and income available to common shares.

In 2007, we recorded an impairment of proved property in Romania totaling $13.4 million, due to one gas well watering out and another under performing based on previous projections. This non-cash charge had a significant impact on income from operations and income available to common shares.

For the twelve months ended December 31, 2007, we recorded a loss on foreign currency exchange of $26.3 million. This loss is due to the weakening of the U.S. Dollar as compared to the New Turkish Lira, Romanian Lei and the Hungarian Forint. In these countries the U.S. Dollar is the functional currency and foreign exchange translation gains and losses are charged to earnings.

In 2007, we recorded a $3.5 million gain on the sale of all our unconsolidated equity investments; ePsolutions, EnergyNet and Capstone Royalty.

In September 2007, we closed on the sale of all of our oil and natural gas properties located in the United States. The sales price was $19.1 million which resulted in a pre-tax gain of $9.2 million.

At December 31, 2007, we held interests in approximately 5.9 million gross acres (approximately 4.8 million net acres). For a more detailed description of our properties see “Items 1 and 2. Business and Properties.” At December 31, 2007, our net proved reserves were estimated at approximately 13.3 MMBOE.

Operations Update

Turkey

In the South Akcakoca Sub-basin project (SASB) located offshore Turkey in the Black Sea, the tie-in of the Ayazli platform is finished and production is expected to begin from that platform mid-March 2008. As of March 14, 2008, production from the Akkaya and Dogu Ayazli platforms is approximately 16 million cubic feet of gas per day (MMCFD) with the Ayazli platform expected to add another 15 MMCFD of production. The February 2008 wellhead price for natural gas from the SASB is approximately $10.21 per thousand cubic feet of gas (MCF) and is expected to be increased to over $11.00 per MCF in May by a mandated rise in the price charged for uninterruptible gas supply to industrial customers in Turkey by BĂ–TAĹž, the Turkish state pipeline operator.

Toreador is currently evaluating several offers for a portion of its working interest in the SASB and expects to receive another offer in early April. The evaluation process is expected to conclude soon after the receipt of the offer in April and public filing will be made should one of the offers be accepted. Currently Toreador holds a 36.75% working interest in the South Akcakoca Sub-basin and the eight adjacent offshore exploration blocks. The operator is TPAO, the Turkish national oil company which holds a 51% working interest, with the remaining 12.25% working interest held by Stratic Energy Corporation.

Hungary

Preparations are being made for the drilling of two exploration wells in Toreador’s Szolnok exploration block. As previously disclosed, four joint venture partners are providing approximately $10 million in capital for the drilling of two wells and a 3-D seismic program in return for a 75% working interest in the Szolnok block. Toreador is the operator and is being carried for its 25% working interest to the casing point in the two wells and the 3-D survey. It is anticipated that the first well will spud and the 3-D survey will commence in April. The second well will immediately follow the first.

Another joint venture in Hungary is expected to be completed before the end of March 2008 with a private European oil and gas company to drill and test a delineation well in Toreador’s Tompa exploration block. The well is to be drilled in an updip location to evaluate a deep gas play that was first detected by two wells drilled in the late 1980’s by OKGT (the former Hungarian state oil company) and the U.S. Geological Survey. The wells produced gas in drill stem tests from a conglomerate encountered below 3,200 meters depth in the northwestern corner of the Tompa block. The proposed terms of the joint venture are for the partner to drill, case and test a well projected to cost up to $16 million in return for a 75% interest in the Tompa block. Toreador will be carried for the first well and retain a 25% working interest in the block.

Romania

In the fourth quarter of 2007 we completed a 2D seismic survey of approximately 252 sq. km. in the Moinesti and Viperesti license areas. The data is currently being processed and final interpretation should be finalized in the second quarter of 2008.

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.

As of December 31, 2007, we had no suspended costs associated with exploratory costs that had been capitalized for a period of one year or less.

As of December 31, 2007, we had no suspended costs associated with exploratory costs that had been capitalized for a period of greater than one year.

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 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 are 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. These reserve revisions result 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.

For the year ended December 31, 2007, we had a downward reserve revision of 4.8% on a BOE basis. This was comprised of a 42.6% decline in the natural gas reserves and a 10.8% increase in oil reserves. This downward revision was due to the following factors: (i) in Hungary, due to the small volume of gas we were unable to secure a gas contract which caused a deletion of previously booked, technical recoverable reserves of 159 MBOE; (ii) in Romania, one gas well watered out and another is under performing based on previous projections resulting in a downward revision of 305.6 MBOE; (iii) in the South Akcakoca Sub-Basin in Turkey, new pressure information and early performance data refined the geological interpretation resulting in a downward revision of 1,369.4 MBOE. These downward revisions were partially offset by improved performance in the Neocomian Field in France and the Cendere Field in Turkey.

For the year ended December 31, 2006, we had a downward reserve revision of 9%. This downward revision was due to the following factors: (i) in the Charmottes Field in France, several high volume producing wells experienced rapidly increasing water production which caused performance declines resulting in a downward revision of 921 MBO; (ii) in Romania, two gas wells watered out after producing for short periods of time resulting in a downward revision of 197 MBOE; (iii) in the South Akcakoca Sub-Basin, due to new drilling, a previous geological interpretation was refined resulting in a downward revision of 192 MBOE, and (iv) there was a downward revision of 73 MBOE due to a decline in prices. These downward revisions were partially offset by upward revisions of 187 MBOE due to performance revisions over several fields, none of which individually contributed a significant portion of this upward revision.

For the year ended December 31, 2005, we had a downward reserve revision of 2.4% or 510 MBOE. The overall downward revision of 510 MBOE was primarily due to the decrease of 1,000 MBO in oil reserves in the Neocomian Field in France where new drilling diminished the estimated reserves in several existing proved undeveloped reserves and cause the removal of several proved undeveloped reserve locations which was partially offset primarily by new drilling in the Charmottes Field where a successful horizontal well established additional reserves of 438 MBO in an existing field, and by an upward revision of 52 MBOE due to an increase in prices.

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 to be incurred to obtain access to proved reserves, including drilling costs and the installation of production equipment. Future abandonment costs include costs to dismantle and relocate or dispose of our production equipment, gathering systems, wells and related structures and restoration costs of land. We develop estimates of these costs for each of our properties based upon the type of production structure, depth of water, reservoir characteristics, depth of the reservoir, market demand for equipment, currently available procedures and consultations with construction and engineering consultants. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including changing technology, the ultimate settlement amount, inflation factors, credit adjusted discount rates, timing of settlement and changes in the political, legal, environmental and regulatory environment. We review our assumptions and estimates of future abandonment costs on an annual basis. The accounting for future abandonment costs changed on January 1, 2003, with the adoption of SFAS 143 “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.

Derivatives

We periodically utilize derivatives instruments such as futures and swaps for purposes of hedging our exposure to fluctuations in the price of crude oil sales. In accordance with SFAS No. 133, Accounting for “Derivative Instruments and Hedging Activities,” 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. We determine the fair value of futures and swap contracts based on the difference between their fixed contract price and the underlying market price at the determination date. The realized and unrealized gains and losses on derivatives are recorded as a derivative fair value gain or loss in the income statement.

Foreign Currency Translation

The functional currency for Turkey, Romania and Hungary is the United States Dollar and in France the functional currency is the Euro. Translation gains or losses resulting from 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. Translation gains and losses resulting from transactions in Euros are included in other comprehensive income for the current period. We periodically review the operations of our entities to ensure the functional currency of each entity is the currency of the primary economic environment in which we operate.

In October 2007, we made a change in accounting method regarding intercompany account receivables due from our subsidiaries in Turkey, Romania and Hungary. Pursuant to a Board of Directors resolution, we expect to be repaid the intercompany account receivable from our subsidiaries in Turkey, Romania and Hungary in the foreseeable future. Due to this resolution subsequent to October 1, 2007, the change in the intercompany account receivable balance will be reflected in current earnings, as a foreign exchange gain or loss rather than accumulated other comprehensive income. See Note 2 — Foreign Currency Translation.

New Accounting Pronouncements

In September 2006, Statement of Financial Accounting Standards (SFAS) No. 157, Fair Value Measurements , was issued. SFAS No. 157 provides guidance for using fair value to measure assets and liabilities. It applies whenever other standards require or permit assets or liabilities to be measured at fair value but it does not expand the use of fair value in any new circumstances. In November 2007, the effective date was deferred for all non-financial assets and liabilities, except those that are recognized or disclosed at fair value on a recurring basis. The provisions of SFAS No. 157 that were not deferred are effective for financial statements issued for fiscal years beginning after November 15, 2007. We are currently assessing the effect, if any, the adoption of Statement 157 will have on our financial statements and related disclosures.

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 choose 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 we elect the fair value measurement option would be reported in earnings. Statement 159 is effective for fiscal years beginning after November 15, 2007. We are currently assessing the effect, if any, the adoption of Statement 159 will have on our financial statements and related disclosures.

In December 2007, SFAS No. 141R, Business Combinations, was issued. Under SFAS No. 141R, a company is required to recognize the assets acquired, liabilities assumed, contractual contingencies, and any contingent consideration measured at their fair value at the acquisition date. It further requires that research and development assets acquired in a business combination that have no alternative future use to be measured at their acquisition-date fair value and then immediately charged to expense, and that acquisition-related costs are to be recognized separately from the acquisition and expensed as incurred. Among other changes, this statement also requires that “negative goodwill” be recognized in earnings as a gain attributable to the acquisition, and any deferred tax benefits resultant in a business combination are recognized in income from continuing operations in the period of the combination. SFAS No. 141R is effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning after December 15, 2008. The effect of adopting SFAS No. 141R has not been determined.

In December 2007, SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51, was issued. SFAS No. 160 amends ARB 51 to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary, which is sometimes referred to as minority interest, is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. Among other requirements, this statement requires consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interest. It also requires disclosure, on the face of the consolidated income statement, of the amounts of consolidated net income attributable to the parent and to the noncontrolling interest. SFAS No. 160 is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2008. The effect of adopting SFAS No. 160 is not expected to have an effect on our reported financial position or earnings.


Results of Operations

Comparison of Years Ended December 31, 2007 and 2006

Revenues

Oil and natural gas sales

Oil and natural gas sales for the twelve months ended December 31, 2007 were $41.7 million, as compared to $33.3 million for the comparable period in 2006. This increase is due to 1) the increase in the average realized price for oil and natural gas, $3.6 million and 2) Turkish gas sales which were not in production in 2006, $7.8 million. This was partially offset by a reduction in total oil production of 59 MBbls or $3 million. Total production increased by approximately 122 MBOE due primarily to the start of production in Turkey gas resulting in 151 MBOE and a full year production in Romania resulting in an additional 32 MBOE. This was partially offset by a decline in French and Turkey oil production of 61 MBOE.

The above table compares both volumes and prices received for oil and natural gas for the twelve months ended December 31, 2007 and 2006. 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.

Costs and expenses

Lease operating

Lease operating expense was $12.6 million, or $17.46 per BOE produced for the twelve months ended December 31, 2007, as compared to $8.7 million, or $14.52 per BOE produced for the comparable period in 2006. This increase is primarily due to increased operating costs in France due to the age of the fields, increased operating costs in offshore Turkey due primarily to fixed operating costs for three tripods of which two were on production, increased operating expense in Romania due to increased workover cost incurred to increase production and the decline in value of the U.S. Dollar.

Exploration expense

Exploration expense for the twelve months ended December 31, 2007 was $14.7 million, as compared to $3.9 million for the comparable period in 2006. This change is primarily due to the 2D seismic survey that was done in Romania during the third quarter and increased interpretation of existing seismic in order to prepare prospects for farmout consideration.

Dry hole and abandonment

Dry hole and abandonment cost for the twelve months ended December 31, 2007 was $21.8 million, as compared to $1.7 million in 2006. During 2007 we drilled two dry holes in France ($3.8 million), three dry holes in Romania ($10 million), two dry holes in Hungary ($3.5 million) and one dry hole in Turkey ($4.5 million). In the comparable period for 2006 we drilled one dry hole in Hungary for $1.7 million.

Depreciation, depletion and amortization.

For the twelve months ended December 31, 2007, depreciation, depletion and amortization expense was $21.3 million, or $29.36 per BOE produced, as compared to $6.3 million, or $10.43 per BOE produced for the twelve months ended December 31, 2006. This increase is primarily due to offshore Turkey starting production in May 2007 resulting in an additional $9.4 million in depreciation, depletion and amortization, an increase in Romania of $4.6 million due to a full year of production and a decline in proved reserves and a $1 million increase in France due primarily to the decline in the value of the U.S. Dollar.

Impairment of oil and natural gas properties

Impairment charged in 2007 was $13.4 million compared to zero in 2006. This increase was due to the downward revisions of proved reserves in the Fauresti Field in Romania. At December 31, 2007 the cash flow before income tax and the discounted future cash flows attributable to our proved oil and natural gas reserves before income tax, and discounted at 10% attributable to the 134 MBOE, in Romania, was $1.2 million and $1.1 million, respectively, and the net book value of asset was $14.5 million. This resulted in an impairment charge of $13.4 million.

General and administrative

General and administrative expense, not including stock compensation expense and amounts due the former President and CEO, was $12.2 million for the twelve months ended December 31, 2007, compared with $6.8 million for the comparable period of 2006. This increase is primarily due to $2.6 million 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, (accounting, legal and printing), the 2006 audit of approximately $1.1 million, a $1.8 million reduction in the amount of capitalized general and administrative costs incurred in Turkey in association with our Black Sea project, since it is now on production, increased professional fees for engineering and recruiters of $213,000 and increased travel costs of $353,000.

Stock compensation expense

Stock compensation expense was $2.9 million for the twelve months ended December 31, 2007, compared with $2.7 million for the comparable period of 2006. 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).

Cost incurred related to the resignation of former President and Chief Executive Officer

In January 2007, Mr. G. Thomas Graves III resigned as President and Chief Executive Officer. The Separation Agreement between Mr. Graves and the Company called for the immediate vesting of all restricted stock grants which resulted in an expense of $1.1 million and two years of salary and one year of bonus of $1.1 million.

Loss on oil and gas derivative contracts

Loss on oil and gas derivative contracts represents the net realized loss on derivative financial instruments and fluctuates based on changes in the fair value of underlying commodities. We entered into futures and swap contracts for approximately 15,000 Bbls per month for the months of June 2007 through December 2008 and subsequently sold all contracts as of September 30, 2007. This resulted in a net derivative fair value loss of $1 million for the twelve months ended December 31, 2007. We were not a party to any derivative contracts in the comparable period of 2006.

Gain on the sale of properties and other assets

For the twelve months ended December 31, 2007, we recorded a gain on the sale of the properties and other assets of $3.2 million, which was primarily attributable to the gain on the sale of our unconsolidated investments. A gain of $436,000 was recorded in the comparable period of 2006.

Foreign currency exchange gain (loss)

We recorded a loss on foreign currency exchange of $26.3 million for the twelve months ended December 31, 2007 compared with $605,000 loss for the comparable period of 2006. This loss is primarily due to the weakening of the U.S. Dollar as compared to the New Turkish Lira, Romanian Lei and the Hungarian Forint. In these countries the U.S. Dollar is the functional currency and foreign exchange translation gains and losses are charged to earnings.

Interest and other income

Interest and other income was $1.8 million for the period ended December 31, 2007 as compared with $2 million in the comparable period of 2006. For the twelve months ended December 31, 2006, our average cash balance was larger than our average cash balance for the twelve months ended December 31, 2007, which resulted in less interest income in the current period.

Interest expense, net of interest capitalization

Interest expense was $4.3 million for the twelve months ended December 31, 2007, as compared to $891,000 for the comparable period of 2006. The increase in interest expense is primarily due to expensing the deferred loan fees on the Natixis facility of $184,000 and the Texas Capital Bank facility of $108,000, since these facilities were paid off in the first quarter of 2007 and the increased debt level for the twelve months ended December 31, 2007 as compared to the comparable period in 2006.

Discontinued operations

On September 1, 2007, we sold all of our working interest properties located in the United States for $19.1 million which resulted in a pre-tax gain of $9.2 million. Prior year financial statements for 2006 and 2005 have been adjusted to present the operations of the U.S. properties as a discontinued operation. The assets and liabilities of the discontinued operations are presented separately under the caption “Oil and gas properties held for resale” and “ Asset retirement obligations, oil and gas properties held for sale,” respectively, in the Balance Sheet as of December 31, 2006. The revenues received and the costs incurred after the effective date are due to adjustments made by the operator prior to the effective date of the sale. We do not have any involvement with the properties sold.

MANAGEMENT DISCUSSION FOR LATEST QUARTER

RESULTS OF OPERATIONS

COMPARISON OF THE THREE MONTHS ENDED MARCH 31, 2008 AND 2007

Revenue

Oil and natural gas sales

Oil and natural gas sales for the three months ended March 31, 2008 were $14 million, as compared to $6.8 million for the comparable period in 2007. This increase is primarily due to natural gas production from offshore Turkey ($3.2 million), which began in May 2007, the increase in price received for our French production ($3.9 million), price increase for oil production in Turkey ($582,000) and the increase in price received from Romanian production ($141,000). This resulted in an additional $7.8 million in revenue. This was partially offset by a decline in total oil production of 9 MBbls and a decline in Romanian gas production of 59 MMcf for a total of 19 MBOE’s which resulted in a decrease in revenue of $600,000.

The above table compares both volumes and prices received for oil and natural gas for the three months ended March 31, 2008 and 2007. Oil and natural gas prices are and will continue to be extremely volatile and a significant change will have a material impact on our revenue.

Costs and expenses

Lease operating

Lease operating expense was $3.5 million, or $18.92 per BOE produced for the quarter ended March 31, 2008, as compared to $2.3 million, or $15.80 per BOE produced for the comparable period in 2007. The $1.1 million increase is primarily due to offshore Turkey starting production in May 2007 and workovers performed on wells in France and Romania in the first quarter of 2008.

Exploration expense

Exploration expense for the first quarter of 2008 was $1 million, as compared to $2 million in the first quarter of 2007. This decrease is due primarily to our farmout efforts that were started in the fourth quarter of 2007.

Depreciation, depletion and amortization

First quarter 2008 depreciation, depletion and amortization expense was $6.9 million or $37.65 per BOE produced, as compared to $2.1 million, or $14.00 per BOE produced for the first quarter of 2007. This increase is primarily due to offshore Turkey starting production in May 2007 resulting in an additional $5.4 million in depreciation, depletion and amortization and a decrease in Romania of $600,000 due primarily to the impairment recorded at December 31, 2007.

Dry hole expense

For three months ended March 31, 2008, we recorded zero dry hole expense, as compared to $8.2 million, which included one dry hole in France of $1 million, two dry holes in Romania totaling $4.6 million and two dry holes in Hungary totaling $2.6 million in the comparable period of 2007. This decrease is due to the strategic decision to no longer drill 100% exploratory wells or fund 100% seismic programs on exploratory acreage. We have begun a systematic process of farming out our exploratory prospects to industry partners. The terms of farm outs have been and will generally be structured so that the farmee will pay 100% of all seismic costs and drill an exploratory well to casing point in order to earn a 50%-75% working interest in the prospect or concession.

General and administrative

General and administrative expense, not including stock compensation expense, was $3.9 million for the first quarter of 2008 compared with $3.3 million for the first quarter of 2007. The increase is primarily due to a reduction in the amount of capitalized general and administrative costs incurred in Turkey in association with our Black Sea project, since it is now on production.

Stock compensation expense

Stock compensation expense was $659,000 for the first quarter of 2008 compared with $905,000 for the first quarter of 2007. This decrease is due to the vesting of higher priced restricted stock during 2007.

Cost incurred related to the resignation of former President and Chief Executive Officer

For the three months ended March 31, 2008 we had zero costs associated with the resignation of the former President and Chief Executive Officer, as compared to $2.2 million in the comparable period of 2007.

Loss on oil and gas derivative contracts

Foreign currency exchange gain (loss)

We recorded a gain on foreign currency exchange of $1.2 million for the first quarter of 2008 compared with a gain of $1 million for the first quarter of 2007. This increased gain is primarily due to a change in accounting method regarding intercompany account receivables due from our subsidiaries in Turkey, Romania and Hungary. Pursuant to a Board of Directors resolution, we expect to be repaid the intercompany account receivable from our subsidiaries in Turkey, Romania and Hungary in the foreseeable future. Due to this resolution subsequent to October 1, 2007, the change in the intercompany accounts receivable balance will be reflected in current earnings, as a foreign exchange gain or loss rather than accumulated other comprehensive income.

Interest and other income

Interest and other income was $281,000 in the first quarter of 2008 as compared with income of $513,000 in the comparable period of 2007. In the quarter ended March 31, 2007, our average cash balance was larger than our average cash balance for the quarter ended March 31, 2008, which resulted in less interest income in the current period.

Interest expense, net of interest capitalized

Interest expense was $2.2 million for the three months ended March 31, 2008, as compared to $595,000 for the comparable period of 2007. The increase in interest expense is primarily due to a reduction in the amount of interest that could be capitalized due to the assets in Turkey commencing production in May 2007. Included in interest expense for the quarter ending March 31, 2008, is $701,625 of additional compensation due to the IFC related to the prior year. This amount should have been recognized as additional interest expense in the prior year. Although the amount may be considered material to the financial results for the quarter ended March 31, 2008, management does not believe that the correction of the error in the current period will have a material effect on the financial results for the year ended December 31, 2008. Also included in interest expense this quarter is a quarterly estimate of $175,250 of the fee to be paid in 2009 relating to 2008 operations.

Discontinued operations

On September 1, 2007, we sold all of our working interest properties located in the United States for $19.1 million which resulted in a pre-tax gain of $9.2 million. Prior year financial statements for 2007 have been adjusted to present the operations of the U.S. properties as a discontinued operation. The revenues received and the costs incurred after the effective date are due to adjustments made by the operator prior to the effective date of the sale. We do not have any involvement with the properties sold.


Other comprehensive income

The most significant element of comprehensive income, other than net income, is foreign currency translation. For the three months ended March 31, 2008, we had accumulated an unrealized income of $5.1 million, as compared to an unrealized income of $4.2 million for the comparable period in 2007. The primary reason for the increase is due to the weakening of the US Dollar compared to the Euro.

The functional currency of our operations in France is the Euro.

Off-balance sheet arrangements

We have no off-balance sheet arrangements that have or are reasonably likely to have a current or future material effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

CONF CALL

Stewart Yee

Thank you operator and welcome everyone to the Toreador Resources first quarter 2008 earnings and operations update. My name is Stewart Yee and I am the Vice President of Investor Relations.

Joining me today are Nigel Lovett, President and Chief Executive Officer and Mike FitzGerald, Executive Vice President of Exploration and Production. Also present is Charles Campise, Senior Vice President of Finance and Accounting and Chief Accounting Officer. We have a few prepared remarks and then we will open the phone lines for questions.

Before we continue, I would like to remind everyone that this call is being recorded and that today’s call may include forward-looking statements that are subject safe-harbor provisions. I would also like to remind everyone that there are important risk factors which can be found in our filings with the Securities and Exchange Commission that may cause results to be materially different from any forward-looking statements in this call.

I will now introduce Nigel Lovett, President and CEO. Nigel?

Nigel J. B. Lovett

Thank you. Good morning everybody or in Europe, good afternoon. The financial data that was released this morning on our first quarter results, while still disappointing, gives you the first signs of positive change in our cash flow generating capacity and earnings, certainly in relation to the results in each of last years four quarters.

This improvement was despite the fact that Turkish gas production was only renewed gradually through the second half of the quarter after last November’s accident. Incidentally, I hope that a number of you also recognized that that production was restored more quickly than our press releases had projected. That too I consider to be a positive change from an era when we fell short on many of our projections.

Let me comment briefly on certain aspects of our first quarter results. Our revenues benefited greatly from continued stable French oil production at ever rising prices. Our smaller Turkish oil production has also become more material as prices there have risen. Turkish gas production has finally become a more meaningful contributor although the rising U.S. dollar has deprived us of some of the recent increases in the Turkish lira denominated pricing of gas.

Our G&A expenses included well over $1.5 million of non recurring items, most of which relate to year end costs that are not accrued on a quarterly basis but charged off when paid. These include stock and cash bonuses, accounting, engineering and legal fees.

I would also point out that no G&A was capitalized this past quarter in relation to ongoing exploration and development programs. In last year’s first quarter some $200 million was capitalized.

We are very sensitive to G&A costs and I would simply remind you that when comparing one company’s G&A costs with another, it is important to look at gross costs, the four amounts capitalized or charged to others. We look at them on a gross basis because that is the cash cost regardless of how the accounting treatment might work.

In that same regard, I also want to explain the big increase in interest expense in the quarter. This year’s number includes $870,000 associated with an annual interest charge or fee payable to our lender, the IFC, over and above our regular interest rate. Last year’s interest expense number reflected no such charge and was further reduced by $800,000 of interest that was capitalized. This year no interest was capitalized.

Accounting treatment involving capitalization can distort the picture of underlying performance which is why cash flow is so critical as a real measurement measure of performance. Our cash flow from operations or EBITDAX was over $6 million this quarter and this was well in excess of our capital expenditures. This was our best quarterly cash flow level since before 2006. It was also the first quarter in some years where cash flow has covered capital expenditures. Our cash position today is several million dollars higher than the March 31st level.

Our strategy, as it relates to risk management and financial discipline, requires three key things, all of which you can now see we are doing or moving towards. First, we will live within our means from a cash standpoint, at least on an annual basis if not in each specific quarter.

Second, we hope to reduce our exposure to our offshore Turkish Black Sea Gas Play which has been more than challenging and will require higher cost deeper water exploration wells in the future. This Play has involved and will involve more risk than we believe we should be bearing.

We are, therefore, in the final stages of due diligence and negotiation with a large Turkish company for a partial divestiture of our working interest. I must add that there can, of course, be no assurance that any such transaction can be agreed, approved by the respective boards, or closed. Thirdly, we will farm out our exploration program for the foreseeable future.

And this is at a good point to pass over to Mike FitzGerald who can tell you more about that.

Michael J. FitzGerald

Thank you, Nigel. I would like to take this opportunity to review the activity in our various countries overseas. In France, as Nigel has mentioned, steady production continues in the Neocomiab and Charmottes Fields, yielding excellent cash flow due to the ongoing steady production and the high price of oil. Exploration prospects on three of our permits have been delineated and are in the process of being shown to other companies with the view to bringing them in to drill in near future.

Three additional applications that we have put in to the French government requesting have closed without any additional top filing and we are hopeful that in the coming months they will be granted and allow us to pursue a new Play that we have in mind.

In Hungary, as the press release mentions, the second well on our Szolnok Block is currently drilling toward a planned total depth of 1400 meters. Additionally, on the Tompa prospect, operations and preparation continue targeting the Deep Gas prospect that will be drilled in the latter part of this year.

Seismic work is ongoing on the Szolnok Block also.

In Romania, geological and geophysical work continues on refining our understanding and defining exploration prospects on our two exploration Blocks and on additional development potential in our Fauresti Field. Potential partners have contacted the company and our coming in to see the various data packages with a view toward bringing companies in to drill on all three of these Blocks.

In Turkey, we now have production off of all three of our tripods. We also have continuing oil production from the Cendere oil field and the development potential of Cendere, especially in light of the increasing oil prices, is again being studied with a view toward seeing if additional drilling can take place on Cendere to enhance the production even more.

Farm out efforts continue on our exploration acreage of which we have considerable in Turkey. Two farm outs have taken place and others are in the process of being worked on. At a time when although we only have one exploration well drilling, it sometimes is misleading to think that exploration is not going on. In actuality it is during these times when drilling is not primarily on our list that the most of the exploration work, the GNG work, can actually go forward full steam.

I would like to thank all of our technicians in the overseas offices for the hard work they have been putting in, finding prospects, finding partners to join with us, and thank all of our investors for their patience while we continue toward finding additional oil and gas reserves. Thank you very much.

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