Toreador Resources (TRGL) 10-K 2007 FY Annual report

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, 2007
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)
13760 Noel Road #1100 Dallas, Texas	75240 (Zip Code)
(Address of principal executive office)

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 ofRegulation 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 thisForm 10-K or any amendment to thisForm 10-K.  o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o	Accelerated filer þ	Non-accelerated filer o	Smaller reporting Company o
	Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined byRule 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 29, 2007 was $189,009,675. (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 14, 2008 was 19,944,943 shares.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s Proxy Statement for the 2008 Annual Meeting of Stockholders, expected to be filed on or before April 29, 2008, are incorporated by reference into Part III of thisForm 10-K

TABLE OF CONTENTS

			Page
PART I
	Item 1 and 2.	Business and Properties		1
	Item 1A.	Risk Factors		17
	Item 1B.	Unresolved Staff Comments		26
	Item 2.	Properties (see Item 1. Business and Properties)		26
	Item 3.	Legal Proceedings		26
	Item 4.	Submission of Matters to a Vote of Security Holders		27
PART II
	Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		28
	Item 6.	Selected Financial Data		30
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		31
	Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		49
	Item 8.	Financial Statements and Supplementary Data		49
	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		50
	Item 9A.	Controls and Procedures		50
	Item 9B.	Other Information		52
PART III
	Item 10.	Directors, Executive Officers and Corporate Governance		52
	Item 11.	Executive Compensation		52
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		52
	Item 13.	Certain Relationships and Related Transactions and Director Independence		52
	Item 14.	Principal Accountant Fees and Services		52
PART IV
	Item 15.	Exhibits and Financial Statement Schedules		53
SIGNATURES				54
Registration Rights Agreement
First Amendment to Registration Rights Agreement
Legal Opinion of Gunel & Kaya
Amendment Number One to Amended and Restated 1990 Stock Option Plan
Amendment Number Two to Amended and Restated 1990 Stock Option Plan
Amended and Restated 1994 Non-employee Director Stock Option Plan
2002 Stock Option Plan
Amendment Number One to the 2002 Stock Option Plan
Contract for the Supply of Crude Oil
First Amendment to Registration Rights Agreement
Summary Sheet - 2008 Charles J. Campise Annual Base Salary
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 Senior Vice President - Finance & Accouting and Chief Accounting Officer Pursuant to Section 302
Certification of Chief Executive Officer and Senior Vice President - Finance & Accounting and Chief Accounting Officer Pursuant to Section 906
Letter from Hungarian Mining Bureau

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 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 BÖTAŞ, 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 a3-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 the3-D survey. It is anticipated that the first well will spud and the3-D survey will commence in April. The second well will immediately follow the first.

1

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

2

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, Alap1-1 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.

3

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

4

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.

5

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

6

additional10-year periods. If an exploration permit is extended for development as an exploitation permit, the period of the exploration permit is counted toward the20-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.

Our Turkish proved reserves are:

				At December 31, 2007
								Post-Expiration				Percent of
	Permit							Proved				Proved
	Expiration			Total Proved Reserves				Reserves				Reserves
Property	Year			(MBbl)		(MMCF)		(MBbl)		(MMCF)		Post-Expiration
Cendere (2 permits)		2012	(1)		1,049		—		659		—		62.82	%
S Akcakoca Sub-Basin		2010	(2)		—		12,939		—		7,043		54.43	%

(1)	Exploitation Permit
(2)	Exploration Permit

Hungary

We have two exploration permits that expire in March 2009. In 2006, we re-completed one well that was drilled by the previous operator on the Tompa exploration permit. We are currently evaluating the most economical way to proceed in commencing production from the re-entry wells.

Under Hungarian mining law, if we provide the Hungarian mining authority with a closing report accounting for the results of our exploration on the Tompa exploration permit area and such closing report is approved, for one year after March 2009, we will have the exclusive right to apply for a mining plot designation. If upon timely application for a mining plot designation, we met the requirements of Hungarian mining law for a mining plot designation, the Hungarian mining authority must grant us the mining plot. We anticipate applying for a mining plot covering the relevant area within the Tompa exploration permit within the one year exclusivity period beginning in March 2009 and providing the Hungarian mining authority with the required information to obtain the mining plot designation for the relevant area.

There is a long and clear track record of exploration permits being converted into mining plot designations. Based on information provided by the Hungarian Mining Bureau, since 1991 when MOL (MOL Hungarian Oil and Gas Public Limited Company), formerly the Hungarian state oil company, became a private company, there have been at least 72 mining plots requested, all of which were granted except for eight due to non-compliance to the request for additional information, the lack of a final exploration report, the lack of an environmental license or due to regional incompatibility with the mining rights of another entity. There can be no assurance that we will be able to convert our exploration permit into a mining plot designation.

We currently do not have proved reserves in Hungary.

7

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, 2007 we have spent $22 million for the construction of a gas processing facility and the re-entry of previously non-producing wells. 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:

	Permit		At December 31, 2007
	Expiration		Oil		Gas
Property	Year		(MBbl)		(MMcf)
Fauresti		2015		6		772

France

We hold seven French exploration permits: Aufferville, Nemours, Courtenay, Rigny, Joigny, Malesherbes and Mairy. No proved reserves have been established in these permits. Each of the French exploration permits expires in 2010. 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.

Under French mining law, exploitation permits can be extended by successive prolongations, with each prolongation not to exceed 25 years and such extensions are not subject to competitive bidding or public inquiry. Although the French government has no obligation to renew exploitation permits, based on conversations with the French mining authority, 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.

There is a long and clear track record of extending permits in France. Our subsidiaries have been operating in France since 1993 and have never been denied any exploration or exploitation permit for which they have applied or been denied any extension for which they have applied. Since 2001, our subsidiaries that operate in France have had six permits extended. However, there can be no assurance that we will be able to renew our exploitation permits.

The French exploitation permits that cover five producing oil fields in the Paris Basin are:

			At December 31, 2007
	Permit		Total Proved		Post-Expiration		Percent of Proved
	Expiration		Reserves		Proved Reserves		Reserves
Property	Year		(MBbl)		(MBbl)		Post-Expiration
Neocomian Fields		2011		8,437		7,032		83.29	%
Charmottes Field		2013		1,525		805		52.79	%

8

Oil and Natural Gas Reserves

The following table sets forth information about our estimated net proved reserves at December 31, 2007 and 2006 for our foreign properties. We sold our U.S. oil and gas properties on September 1, 2007. LaRoche Petroleum Consultants, Ltd. (“LaRoche”), 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 (“FASB) Statement of Financial Accounting Standards No. 69,Disclosures about Oil and Gas Producing Activities.No reserve reports have been provided to any governmental agencies.

	December 31,
	2007		2006
TURKEY
Proved developed:
Oil (MBbl)		808		405
Gas (MMcf)		4,248		—
Total (MBOE)		1,516		405
Proved undeveloped:
Oil (MBbl)		241		260
Gas (MMcf)		8,691		21,424
Total (MBOE)		1,689		3,831
Discounted present value at 10% (pretax) (in thousands)(1)	$	89,376	$	89,913
Standardized measure of proved reserves (in thousands)	$	84,048	$	84,330
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
ROMANIA
Proved developed:
Oil (MBbl)		6		41
Gas (MMcf)		772		3,040
Total (MBOE)		134		548
Discounted present value at 10% (pretax) (in thousands)(1)	$	1,110	$	12,941
Standardized measure of proved reserves (in thousands)	$	1,110	$	13,389
FRANCE
Proved developed:
Oil (MBbl)		7,170		6,770
Proved undeveloped:
Oil (MBbl)		2,798		2,858
Discounted present value at 10% (pretax) (in thousands)(1)	$	262,605	$	131,824
Standardized measure of proved reserves (in thousands)	$	174,211	$	86,190
COMBINED
Proved developed:
Oil (MBbl)		7,984		7,217
Gas (MMcf)		5,020		3,990
Total (MBOE)		8,822		7,882
Proved undeveloped:
Oil (MBbl)		3,039		3,118
Gas (MMcf)		8,691		21,425
Total (MBOE)		4,488		6,689
Total proved:
Oil (MBbl)		11,023		10,335
Gas (MMcf)		13,711		25,415
Total (MBOE)		13,308		14,571
Discounted present value at 10% (pretax) (in thousands)(1)	$	353,091	$	237,303
Standardized measure of proved reserves (in thousands)	$	259,369	$	184,878

(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

9

presentation of the discounted present value is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves prior to taking into account corporate future income taxes and our current tax structure. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. The standardized measure of discounted future net cash flows represents the present value of future cash flows attributable to our proved oil and natural gas reserves after income tax, discounted at 10%.

Reserves were estimated using oil and natural gas prices and production and development costs in effect on December 31, 2007 and 2006, 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.

Approximately 34% of our proved reserves are classified as proved undeveloped (PUD) as determined by the LaRoche 2007 reserve report. These reserves were identified from 30 (PUD) locations as part of LaRoche’s geological and reservoir engineering studies of our hydrocarbon producing assets.

The first 24 PUD locations are direct offsets to our existing French production in the Paris basin. Fault blocks have been mapped containing recoverable hydrocarbons that because of a lack of wellbores have typically underperformed from the existing waterflood. Additional wellbores will be drilled starting in 2009 to improve the recovery efficiency of the trapped hydrocarbons in these fault blocks.

Three other PUD locations were identified from our non-operated, onshore Cendere field in Turkey. Since we are not the operator of the Cendere field, we have no control of the timing or the success of any field operations. However, we are planning to review the additional development and expansion opportunities across the entire field with the operator in mid 2008.

The remaining PUD locations were identified from our 2007 drilling program in the Western Black Sea offshore Turkey. We intend to commence recompletion operations in late 2009 as part of a Phase II development plan for the Akcakoca area. This development plan is being prepared by a third party engineering firm and is expected to be finished in the spring of 2008.

The successful conversion of these PUD reserves into proved developed reserves is dependent upon the following:

•  Our ability to secure related oilfield equipment and services on a timely and competitive basis. Presently, there is great demand for and often extensive delays in securing oilfield equipment and services at any price. No assurance can be given that the requisite oilfield equipment and services can be secured in a timely and competitive manner.

•  Projections for proved undeveloped reserves are largely based on their analogy to similar producing properties and to volumetric calculations. Reserve projections based on analogy are subject to change due to subsequent changes in the analogous properties.

Productive Wells

The following table shows our gross and net interests in productive oil and natural gas wells as of December 31, 2007. Productive wells include wells currently producing or capable of production.

	Gross(1)						Net(2)
	Oil		Gas		Total		Oil		Gas		Total
Turkey		15		—		15		2.65		—		2.65
Romania		—		5		5		—		5.00		5.00
France		131		—		131		130.50		—		130.50

(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.

10

Acreage

The following table shows the developed and undeveloped acreage attributable to our ownership as of December 31, 2007.

	Developed Acreage				Undeveloped Acreage				Total Acreage
	Gross		Net		Gross		Net		Gross		Net
France		24,260		24,260		555,236		454,800		579,496		479,060
Turkey		7,858		1,554		3,956,590		2,929,240		3,964,448		2,930,794
Romania		1,325		1,325		624,000		624,000		625,325		625,325
Hungary		—		—		764,237		764,237		764,237		764,237
Total		33,443		27,139		5,900,063		4,772,277		5,933,506		4,799,416

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.

Drilling Activity

The following table shows our international drilling activities on a gross and net basis for the years ended 2007, 2006 and 2005.

	Year Ended December 31,
	2007				2006				2005
	Gross(1)		Net(2)		Gross(1)		Net(2)		Gross(1)		Net(2)
TURKEY
Development:
Gas(3)		—		—		7		2.57		4		1.80
Abandoned(4)		—		—		2		0.56		1		0.40
Total		—		—		9		3.13		5		2.20
Exploratory
Oil(5)		—		—		—		—		—		—
Gas(6)		3		1.00		—		—		—		—
Abandoned(4)		1		.50		—		—		—		—
Total		4		1.50		—		—		—		—
HUNGARY
Exploratory
Abandoned(4)		2		2.00		1		1.00		—		—
ROMANIA
Exploratory
Gas(3)		—		—		—		—		—		—
Oil(7)		—		—		—		—
Abandoned(4)		3		3.00		—		—		—		—
Total		3		3.00		—		—		—		—

11

	Year Ended December 31,
	2007				2006				2005
	Gross(1)		Net(2)		Gross(1)		Net(2)		Gross(1)		Net(2)
FRANCE
Development:
Oil(7)		—		—		—		—		5		5.00
Abandoned(4)		—		—		—		—		—		—
Total		—		—		—		—		5		5.00
Exploratory:
Oil(7)		—		—		—		—		1		0.50
Abandoned(4)		2		2.00		—		—		—		—
Total		2		2.00		—		—		1		0.50

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

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 for France, Turkey and Hungary. It also summarizes calculations of our total average unit sales prices and unit costs. We sold our U.S. oil and gas properties on September 1, 2007.

	France		Turkey		Romania		Total
Year Ended December 31, 2007
Production:
Oil (Bbls)		383,341		65,686		9,594		458,621
Daily average (Bbls/Day)		1,050		180		26		1,256
Gas (Mcf)		—		904,927		689,290		1,594,217
Daily average (Mcf/Day)		—		2,479		1,888		4,367
Daily average (BOE/Day)		1,050		593		341		1,984
Unit prices:
Average oil price ($/Bbl)	$	67.49	$	61.98	$	57.59	$	66.50
Average gas price ($/Mcf)		—		8.60		4.90		7.00
Average equivalent price ($/BOE)		67.49		54.77		31.55		57.51
Unit costs ($/BOE):
Lease operating	$	19.17	$	12.18	$	21.42	$	17.46
Exploration and acquisition		2.23		11.83		51.83		20.36
Depreciation, depletion and amortization		10.80		46.49		54.05		29.36
Dry hole cost and impairment of oil and gas properties		10.04		20.74		189.16		48.74
General and administrative		7.39		17.18		4.32		23.91
Total	$	49.63	$	108.42	$	320.78	$	139.83

12

	France		Turkey		Romania		Total
Year Ended December 31, 2006
Production:
Oil (Bbls)		441,759		68,342		7,728		517,829
Daily average (Bbls/Day)		1,210		187		21		1,418
Gas (Mcf)		—		—		502,192		502,192
Daily average (Mcf/Day)		—		—		1,376		1,376
Daily average (BOE/Day)		1,210		199		250		1,659
Unit prices:
Average oil price ($/Bbl)	$	61.74	$	56.10	$	52.71	$	60.86
Average gas price ($/Mcf)		—		—		3.57		3.57
Average equivalent price ($/BOE)		61.74		56.10		24.06		55.37
Unit costs ($/BOE):
Lease operating	$	16.36	$	11.60	$	7.86	$	14.52
Exploration and acquisition		0.98		11.69		7.09		6.55
Depreciation, depletion and amortization		7.06		10.94		22.85		10.43
Dry hole cost and impairment of oil and gas properties		—		—		—		2.83
General and administrative		4.31		11.81		6.09		15.78
Total	$	28.71	$	46.04	$	43.89	$	50.11
Year Ended December 31, 2005
Production:
Oil (Bbls)		403,991		64,792		—		468,783
Daily average (Bbls/Day)		1,107		178		—		1,285
Unit prices:
Average oil price ($/Bbl)	$	50.92	$	43.48	$	—	$	49.89
Unit costs ($/BOE):
Lease operating	$	13.34	$	10.96	$	—	$	13.01
Exploration and acquisition		2.50		4.46		—		6.27
Depreciation, depletion and amortization		8.70		8.44		—		9.16
Dry hole cost		—		26.84		—		3.71
General and administrative		2.33		7.22		—		13.71
Total	$	26.87	$	57.92	$	—	$	45.86

Office Lease

We occupy 23,297 square feet of office space at 13760 Noel Rd., Suite 1100, Dallas, Texas 75240. The lease for this space became effective on October 1, 2007 and is for seven years, and the average monthly rental is $33,005 per month for the term of the lease. 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 2007 was approximately $828,590.

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. Our Turkish gas is sold through the national pipeline.

13

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. Presently, there is great demand for and often extensive delays in securing oilfield equipment and services at any price. No assurance can be given that the requisite oilfield equipment and services can be secured in a timely and competitive manner.

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 exploration activities are conducted in Turkey, Hungary, Romania and France. Such activities are affected in varying degrees by political stability and government regulations relating to foreign investment and the oil and natural gas industry. Changes in these regulations or shifts in political attitudes are beyond our control and may adversely affect our business. Operations may be affected in varying degrees by government regulations with respect to restrictions on production, price controls, export controls, income taxes, expropriation of property, environmental legislation and mine safety.

Government Regulation

Our current or future operations, including exploration and development activities on our properties, require permits from various governmental authorities, and such operations are and will be governed by laws and regulations governing prospecting, development, production, exports, taxes, labor standards, occupational health, waste disposal, toxic substances, land use, environmental protection and other matters. Compliance with these requirements may prove to be difficult and expensive. See “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 “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.

14

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

We sold our U.S. oil and gas properties on September 1, 2007, and the purchaser assumed certain obligations pursuant to the purchase agreement; however, we could be held liable for obligations that occurred prior to the sale of the U.S. oil and gas properties.

Employees

As of March 12, 2008, we employed 95 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 believe that 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 onForm 10-K, Quarterly Reports onForm 10-Q, Current Reports onForm 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 athttp://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

“2D” or“2D SEISMIC.” An exploration method of sending energy waves or sound waves into the earth and recording the wave reflections to indicate the type, size, shape, and depth of subsurface rock formations. 2D seismic provides a two dimensional representation along the profile of the line as it was shot. 2D surveys are measured in kilometers or miles.

“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 lines are shot very close together, this allows for the ability for computers to generate seismic profiles in any direction and form 3D surfaces. 3D surveys are measured in square kilometers or square miles.

“Bbl.” One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.

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

“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.

15

“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 exploratoryand/or development wells. Sometimes designated as a “lease” or “block.”

“PRODUCING WELL” or“PRODUCTIVE WELL.”A well that is capable of producing oil or natural gas in economic quantities.

“PROVED DEVELOPED RESERVES.” The oil and natural gas reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and natural gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

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

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

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

16

“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

Risks Related To Our Company

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 budgets.

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, 2007 our debt to equity ratio was .71 to 1, and this ratio and our increased leverage may make it difficult for us to obtain additional funding, especially additional debt.

17

No assurance can be given that we will have the needed additional capital to fund our future growth under these facilities or from existing 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.

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 loan and guarantee agreement with the International Finance Corporation restricts our ability 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.

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 facility discussed above.

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.

18

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

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

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

•  marketing our oil and natural gas production;

•  integrating new technologies; and

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

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

Our business exposes us to liability and extensive regulation on environmental matters.

Our operations are subject to 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, includingclean-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.

All of our operations are 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.

19

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. In January 2007, we replaced G. Thomas Graves III when he resigned with Nigel Lovett. The duties of our former Chief Financial Officer, Douglas Weir, have been assumed by Nigel Lovett and Charles Campise. 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, including a chief executive officer, a chief financial officer, geologists, geophysicists and other technical personnel, our business, financial condition, results of operations or the market value of our common stock could be materially adversely affected.

We may not be able to renew our permits or obtain new ones which could reduce our proved reserves.

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. Approximately 71% of our proved reserves are estimated to be recovered after the expiration of the applicable permit, as of December 31, 2007. 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. If we cannot renew some or all of these permits when they expire or convert exploration permits into exploitation permits, we will not be able to include the proved reserves associated with the permit.

Since we do not hold title to our properties but rather hold exploitation and exploration permits granted to us by the applicable 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 properties, we hold exploitation and exploration permits that have been granted to us for a specific time period by the applicable governments. We must apply to have these permits renewed and extended in order to continue our exploration and development rights. Although we have always reported our proved reserves assuming that the permits will be extended in due course, the Securities and Exchange Commission may take the view that our ability to renew and extend our permits past their current expiration dates is not sufficiently certain such that we should not include the reserves that may be produced post expiration in our total proved reserves. Although we have previously been able to provide support to the Securities and Exchange Commission regarding the likelihood of extension, no assurance can be given that the Securities and Exchange Commission will allow us to continue to include these additional reserves in our proved reserves.

Any future hedging activities may require us to make significant payments that are not offset by sales of production and may prevent us from benefiting from increases in oil or natural gas prices.

Although we are not currently a party to a hedging transaction, occasionally we may reduce our exposure to the volatility of oil and natural gas prices by hedging a portion of our production. In a typical hedge transaction, we will have the right to receive from the counterparty to the hedge the excess of the fixed price specified in the hedge over a floating price based on a market index, multiplied by the quantity hedged. If the floating price exceeds the fixed price, we will be required to pay the counterparty this difference multiplied by the quantity hedged. In such case, we

20

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.

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 an 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, 2007, 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 in our internal control over financial reporting. There is no guarantee that we will be able to resolve these material weaknesses or avoid 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;

21

•  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;

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

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

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

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

Continued financial success depends on our ability to replace our reserves in the future.

Our future success as an oil and natural gas producer depends upon our ability to find, develop and acquire additional oil and natural gas reserves that are profitable. Oil and natural gas are depleting assets, and production from oil and natural gas from properties declines as reserves are depleted with the rate of decline depending on reservoir characteristics. If we are unable to conduct successful exploration or development activities or acquire properties containing proved reserves, our proved reserves generally will decline as the reserves are produced, and our level of production and cash flows will be adversely affected. Replacing our reserves through exploration or development activities or acquisitions will require significant capital which may not be available to us.

We face numerous risks in finding commercially productive oil and natural gas reservoirs.

Our drilling will involve numerous risks, including the risk that no commercially productive oil or natural gas reservoirs will be encountered. We may incur significant expenditures for the identification and acquisition of properties and for the drilling and completion of wells. The cost of drilling, completing and operating wells is often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including unexpected drilling conditions, pressure or irregularities in formations, equipment failures or accidents, weather conditions and shortages or delays in the delivery of equipment.

In addition, any use by us of 3D seismic and other advanced technology to explore for oil and natural gas requires greater pre-drilling expenditures than traditional drilling methodologies. While we use advanced technology in our operations, this technology does not allow us to know conclusively prior to drilling a well that oil or natural gas is present or economically producible.

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.

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).

22

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; and

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

As is customary in our industry, we maintain insurance against some, but not all, of these risks. We cannot assure investors that our insurance will be adequate to cover these losses or liabilities. We do not carry business interruption insurance. Losses and liabilities arising from uninsured or underinsured events may have a material adverse effect on our financial condition and operations. We carry well control insurance for our drilling operations. Our coverage includes blowout protection and liability protection on 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. As discussed above, in November 2007 production in the South Akcakoca Sub-basin project in the Black Sea offshore Turkey was shut down by the system operator due to damage to the pipeline spur. Underwater inspection revealed that the Akkaya pipeline spur had been separated at a pipeline flange and displaced approximately 20 feet from its original location. The likely cause was that a fishing boat, which was trawling through the exclusion zone around the platform, lifted the pipeline and caused the separation. In February 2008 natural gas production resumed in the South Akcakoca Sub-Basin natural gas project. Current production of approximately 15 MMcF of gas per day is from four wells. The Akkaya-1A, which was producing from a small zone low in the well, is currently shut-in and scheduled to be reentered as soon as equipment is available to start production from a previously perforated upper zone in the well.

Reserve estimates depend on many assumptions that may turn out to be inaccurate.

Any material inaccuracies in our 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 thisForm 10-K. 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 thisForm 10-K. 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 thisForm 10-K 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.

23

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 prospectus, 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 12, 2008 were $23.22 and $5.79, respectively. Fluctuations in the price of our common stock may be exacerbated by conditions in the energy and oil and natural gas industries or conditions in the financial markets generally.

Our common stock is quoted on the Nasdaq 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:

•  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 12, 2008, our executive officers and directors as a group beneficially owned approximately 16.39% of our common stock (including shares issuable upon exercise of stock options or warrants held by officers and directors). Due to their large ownership percentage interest, they may be able remain entrenched in their positions.

24

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 loan and guarantee agreement with the International Finance Corporation restrict our ability to pay dividends on our common stock.

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 debentures, or for other reasons. As of March 12, 2008, there were:

•  338,170 shares of our common stock issuable upon exercise of outstanding options, at a weighted average exercise price of $4.85 per share, of which options to purchase 334,837 shares were exercisable;

•  98,760 shares of our common stock issuable upon exercise of outstanding warrants, at a weighted average exercise price of $19.82 per share, all of which were exercisable;

•  2,014,766 shares of our common stock issuable upon conversion of our Convertible Senior Notes; and

•  257,587 shares of our common stock available for future grant under our equity incentive plan.

Our leverage may harm our financial condition and results of operations.

Our total consolidated long-term debt as of December 31, 2007 was approximately $116.3 million and represented approximately .71 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.

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.

25

These and other provisions, including the provisions of our charter documents and Delaware law, could prevent or deter a third party from acquiring us even where the acquisition could be beneficial to holders of our common stock or the notes.

Certain provisions of our charter documents may adversely impact our stockholders.

Our charter documents provide our board of directors 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 has refused to rule on the case. All appeals have now been exhausted and the rejection of the exchange protection award is final in all jurisdictions.

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 5.9 million Euros, currently valued at $8.7 million, paid to Micoperi under the contract between us, our co-venturers and Micoperi. Micoperi has made a cross-claim for about 5.1 million Euros, currently valued at $7.5 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 5.9 million Euros, currently valued at $8.7 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 are accounting for the potential receivable from Micoperi as a gain contingency. Accordingly, the potential gain has not been recorded.

David M. Brewer

On March 12, 2008, we agreed in principle to make a payment of $97,500 to the J&D Madison Foundation, a private charitable foundation managed by David Brewer, one of our directors, in settlement of claims he made against the Company arising from an alleged prior agreement by G. Thomas Graves III, the former President and

26

Chief Executive Officer, to pay him $150,000 per year for three years as a consulting fee. We are working on finalizing a release agreement with Mr. Brewer. In 2007, Mr. Brewer brought to the attention of the Company correspondence from Mr. Graves in which, on behalf of the Company, Mr. Graves had promised to provide Mr. Brewer with certain consulting payments that had been previously agreed to by Mr. Graves in connection with the acquisition of Madison Oil Company, but never paid. In this letter, Mr. Graves stated that there was an oral, binding commitment of the Company to pay these amounts to Mr. Brewer. Mr. Brewer presented the letter to the Company and requested payments pursuant to this correspondence. Upon receiving a copy of this correspondence, certain members of the Board of Directors discussed with Mr. Brewer the facts giving rise to this request for payments and asked certain members of the Audit Committee of the Company to review this matter further, whereupon these certain members of the Audit Committee hired special counsel to assist them in the review and provide them with advice. These members of the Audit Committee determined that there were questions regarding this commitment to pay (including a failure to obtain approval from the Board of Directors for any such payment) and there were valid reasons not to pay these amounts to Mr. Brewer. Subsequently, on February 11, 2008, counsel to Mr. Brewer sent a demand letter to the Company requesting payment of these amounts. The Board of Directors discussed this matter and determined that it was in the best interests of the Company and its stockholders to compromise and settle this matter with Mr. Brewer, whereupon the settlement amount was agreed to in exchange for a release by Mr. Brewer of all claims against the Company and for him stepping down as Chairman of the Nominating and Corporate Governance Committee. In connection with this settlement, the Company does not admit that these amounts are owing or that Mr. Brewer has a valid claim for these consulting fees. Mr. Brewer and his father, both of whom are directors, did not participate in the Board of Directors approval of this settlement. Mr. Brewer has indicated that these funds will be distributed by the foundation for educational, medical research or social welfare purposes.

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, 2007.

27

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 retailmark-up, mark-down or commission and may not necessarily represent actual transactions.

	High		Low
2007:
Fourth quarter	$	12.13	$	5.69
Third quarter		15.71		9.75
Second quarter		19.41		12.44
First quarter		28.29		17.42
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

As of March 12, 2008, there were 19,944,943 shares of common stock outstanding and held of record by approximately 439 holders (inclusive of those brokerage firms, clearing houses, banks and other nominee holders, holding common stock for clients, with each such nominee being considered as one holder).

The closing price of the common stock on the Nasdaq Global Market on March 12, 2008 was $7.97.

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. In addition, the terms of the loan and guarantee agreement with the International Finance Corporation restrict our ability to pay dividends to only those required by law and on theSeries A-1 Convertible Preferred Stock, which series is no longer outstanding.

Until theSeries A-1 Convertible Preferred Stock was no longer outstanding on December 31, 2007, dividends on ourSeries A-1 Convertible Preferred Stock were paid on a quarterly basis per the terms of such series. Cash dividends totaling $162,000, $162,000 and $186,000 were paid for the years ended December 31, 2007, December 31, 2006, and December 31, 2005, respectively, on theSeries 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 theSeries A-1 Convertible Preferred Stock were exchanged into 532,664 common shares. In December 2007, the remaining 72,000 shares of theSeries A-1 Convertible Preferred Stock were converted into 450,000 shares of common stock.

During 2007, 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 onForm 8-K or Quarterly Reports onForm 10-Q.

During the fourth quarter 2007, we did not repurchase any of our registered equity securities.

28

Below is a line graph comparing the5-year cumulative total stockholder return on our common stock with the Nasdaq Market Index and the Hemscott Group Index for oil and gas companies:

COMPARISON OF5-YEAR CUMULATIVE TOTAL RETURN
AMONG TOREADOR RESOURCES CORP.,
NASDAQ MARKET INDEX AND HEMSCOTT GROUP INDEX

ASSUMES $100 INVESTED ON DEC. 31, 2002

ASSUMES DIVIDEND REINVESTED

FISCAL YEAR ENDING DEC. 31, 2007

29

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, 2007 and as well as selected consolidated balance sheet data as of December 31, 2007, 2006, 2005, 2004 and 2003 and should be read in conjunction with the consolidated financial statements and the notes thereto included herewith.

The results of operations of assets in the United States have been presented as discontinued operations in the accompanying consolidated statements of operations.

	Years Ended December 31,
	2007			2006			2005			2004			2003
	(Amounts in thousands, except per share amounts)
Operating Results:
Revenues	$	41,691		$	33,328		$	23,411		$	15,041		$	11,572
Costs and expenses		(99,088	)		(29,741	)		(21,504	)		(20,329	)		(13,493	)
Operating income (loss)		(57,397	)		3,587			1,907			(5,288	)		(1,921	)
Other income (expense)		(28,745	)		893			4,015			(790	)		2,593
Income (loss) from continuing operations before income taxes		(86,142	)		4,480			5,922			(6,078	)		672
Income tax benefit (provision)		4,676			(3,005	)		1,911			2,194			1,369
Income (loss) from continuing operations, net of tax		(81,466	)		1,475			7,833			(3,884	)		2,041
Income from discontinued operations, net of tax		7,045			1,103			2,762			19,304			2,601
Dividends on preferred shares		(162	)		(162	)		(684	)		(714	)		(500	)
Income (loss) available to common shares	$	(74,583	)	$	2,416		$	9,911		$	14,706		$	4,142
Basic income (loss) available to common shares per share	$	(4.07	)	$	0.16		$	0.69		$	1.54		$	0.44
Diluted income (loss) available to common shares per share	$	(4.07	)	$	0.15		$	0.66		$	1.54		$	0.44
Weighted average shares outstanding
Basic		18,358			15,527			14,213			9,571			9,338
Diluted		18,358			15,884			15,140			9,571			9,347
Balance Sheet Data:
Working capital	$	9,644		$	14,388		$	101,977		$	11,113		$	(6,108	)
Oil and natural gas properties, net		271,951			241,099			127,480			69,644			55,126
Total assets		323,111			317,204			261,814			94,674			95,203
Long-term debt, including current portion		116,250			112,800			92,060			9,022			30,976
Stockholders’ equity		163,825			147,151			132,359			63,250			39,598
Cash Flow Data:
Net cash provided by (used in) operating activities	$	(25,348	)	$	14,104		$	(138	)	$	(8,177	)	$	11,354
Capital expenditures for oil and natural gas property and equipment, including acquisitions		88,815			105,165			50,163			15,985			2,933

30

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 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.

31

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 BÖTAŞ, 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 a3-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 the3-D survey. It is anticipated that the first well will spud and the3-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

32

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 thisForm 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

33

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.

34

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.

35

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.

LIQUIDITY AND CAPITAL RESOURCES

This section should be read in conjunction with Notes 8 and 9 to Notes to Consolidated Financial Statements included in this filing.

36

Liquidity

As of December 31, 2007, we had cash and cash equivalents and restricted cash of $23.5 million, a current ratio of approximately 1.5 to 1 and a debt (long-term debt and Convertible Senior Notes) to equity ratio of .71 to 1. For the twelve months ended December 31, 2007, we had an operating loss of $57.4 million and capital expenditures, excluding capitalized interest and changes in accounts payable, were $71 million. The restricted cash relates to a letter of credit relating to the dispute with Micoperi regarding the October 2005 well issues in the Black Sea and a letter of credit to secure additional permits in Hungary.

On March 23, 2007, we closed a $45 million private placement of equity. In the transaction, we issued an aggregate of 2,710,843 shares of common stock to six institutional investors, providing us with $45 million of gross proceeds at closing. We also granted the investors warrants to purchase an additional $8.1 million aggregate amount of common stock within the next30-day period. On April 23, 2007, two of the institutional investors exercised their warrants for an aggregate of 326,104 additional shares of common stock, providing us with approximately $5.4 million of gross proceeds. The net proceeds from the private placement totaled approximately $48 million and were used to help fund our 2007 exploration and development activities.

On June 14, 2007, the Board of Directors authorized management to sell all oil and gas properties in the United States. The sale of these properties completed the divestiture of the company’s non-core domestic assets and allows us to focus exclusively on our international operations. The sale was closed on September 1, 2007. The sales price was $19.1 million and resulted in a pre-tax gain of $8.6 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 captions “Oil and gas properties held for resale” and “Asset retirement obligations, oil and gas properties held for sale” respectively, in the Balance Sheet for the year ended December 31, 2006.

In connection with the private placement, we entered into a Registration Rights Agreement with the investors. The Registration Rights Agreement provided that we would file a registration statement with the Securities and Exchange Commission covering the resale of the common stock within 60 days after the closing date. If the registration statement was not filed with the Securities and Exchange Commission within such time, we had to pay 1.0% of the aggregate purchase price, an additional 1.0% on the one month anniversary of the 60th day after closing if the registration statement had not been filed by such date and an additional 2.0% of the aggregate purchase price for each 30 day period after the one month anniversary if the registration statement was not filed by such date. We filed the registration statement with the Securities and Exchange Commission on May 8, 2007. If the registration statement was not declared effective by the Securities and Exchange Commission within 150 days after the closing date, we had to pay 1.0% of the aggregate purchase price, an additional 1.0% on the one month anniversary of the 150th day after the closing if the registration statement had not been declared effective by the Securities and Exchange Commission by such date and an additional 2.0% of the aggregate purchase price for each 30 day period after the one month anniversary if the registration statement was not declared effective by such date. The registration statement was declared effective July 26, 2007. Now that the registration statement has been declared effective by the Securities and Exchange Commission, if, subject to certain exceptions, future sales cannot be made pursuant to the registration statement, we must pay 1.0% of the aggregate purchase price on the date sales cannot be made pursuant to the registration statement, an additional 1% on the one month anniversary of the date sales are not permitted under the registration statement if sales are not permitted under the registration statement by such date and an additional 2.0% of the aggregate purchase price for each 30 day period after the one month anniversary if sales under the registration statement are not permitted by such date. Any one month or 30 day periods during which we cure the violation will cause the payment for such period to be made on a pro rata basis. As a result of the change in the resale restrictions under Rule 144, effective February 15, 2008, we amended the Registration Rights Agreement to provide that we do not have to keep the registration statement effective if the holders of the shares covered by the Registration Rights Agreement can sell all of the shares pursuant to Rule 144.

Beginning in the fourth quarter of 2007, we made a strategic decision to no longer drill 100% exploratory wells or fund 100% seismic programs on exploratory acreage. We began 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

37

the farmee will pay 100% of all seismic costs and drill an exploratory well to casing point in order to earn a50%-75% working interest in the prospect or concession.

We believe that our French oil production will generate sufficient free cash flow to cover all our costs and contribute to our share of development capital expenditures in the Black Sea. We believe that our Turkish cash flow, given our restoration of production following a November 2007 shipping accident, will provide the balance of those development expenditures and more. Our 2008 capital expenditure budget is $27.5 million which is the Company’s share of estimated Phase II development costs in the Black Sea.

We believe we will have sufficient cash flow from operations to meet all of our 2008 obligations. However, if the cash flow from our operations is less than anticipated and if we have used up our cash and drawn down our credit facility we may also seek additional capital by (i) forward selling our crude oil and natural gas production; (ii) selling our interest in prospects and or licenses; (iii) selling down our working interest in properties; or (iv) a combination of these actions in addition to issuing new debt or equity securities 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 2008.

We will operate the Company, at a minimum, through 2009 in this manner. We will not incur costs to keep a permit or license in effect, but rather we will manage the Company’s resources so that only the areas that meet certain economic hurdles will be considered. We believe that this philosophy will not only strengthen the Company’s financial position in the short term, but will also ensure the Company’s position for the future.

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 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 with Natixis Banques Populaires and the remaining $14 million of funds was 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 In September 2007, we repaid $5 million of the $25 million facility after the sale of the oil and natural gas properties in the United States were sold. Both the $25 million facility and the $10 million facility are to fund our operations in Turkey and Romania. As of December 31, 2007, the International Finance Corporation has reduced our borrowing base under both loans to $30 million from $35 million. Until the next redetermination date, the Company has no additional borrowing capacity under these facilities. We do not believe that the loss of $5 million in the borrowing base will materially effect our business strategy for 2008 and 2009.

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, 2007 the interest rate on the $10 million facility was 5.329% and 6.829% on the $25 million facility. 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 EBITDAX 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. At December 31, 2007, we were not in compliance with the interest rate coverage ratio of not less than 3.0:1.0; the actual ratio was 2.8:1.0. The International Finance Corporation has granted us a temporary waiver for the interest coverage ratio provided we maintain EBITDAX to net interest expense ratio of 2.7:1.0 until July 2, 2008

38

and EBITDA to net interest expense ratio of a least 2.7:1.0 during the remaining period of the waiver effectiveness. The waiver is effective until March 8, 2009.

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 theSeries A-1 Convertible Preferred Stock, which is no longer outstanding, 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.

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 were required to be filed 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 were 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 ourForm 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 or not being required to be effective pursuant to the registration rights agreement. Because we did not file our Quarterly Report onForm 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

39

Suspension Period ended on January 23, 2007 when we provided notice that theForm 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 paid approximately $14,375 in additional interest expense. On March 16, 2007, the date we filed ourForm 10-K for the year ended December 31, 2006 we again entered a Suspension Period until all the Convertible Senior Notes became eligible for sale pursuant to Rule 144(k) on September 30, 2007. On October 1, 2007, $155,000 was deposited with the trustee for the Convertible Senior Notes as the penalty for any holders of the Notes who were eligible on October 1, 2007 to receive a pro rate portion of such payment. Such eligible holders had to have registered their Convertible Senior Notes on the registration statement and still held those Notes on October 1, 2007. Through March 12, 2008, we had released $4,043 of the penalty deposit to eligible holders of Convertible Senior Notes.

Preferred Stock

On February 22, 2005, 82,000 shares ofSeries 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 ofSeries A-1 Convertible Preferred Stock outstanding. At the option of the holder, theSeries A-1 Convertible Preferred Stock could be converted into common shares at a price of $4.00 per common share. TheSeries A-1 Convertible Preferred Stock accrued dividends at an annual rate of $2.25 per share payable quarterly in cash. At any time on or after November 1, 2007, we had the right to redeem for cash any or all shares ofSeries A-1 Convertible Preferred Stock. In December 2007 the 72,000 shares ofSeries A-1 Convertible Preferred Stock were converted into 450,000 shares of common stock.

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.

Dividends on ourSeries A-1 Convertible Preferred Stock were paid quarterly. For the year ended December 31, 2007 dividends totaled $162,000.

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 ourSeries A-1 Convertible Preferred Stock, which is no longer outstanding.

Contractual Obligations

The following table sets forth our contractual obligations in thousands at December 31, 2007 for the periods shown:

			Less Than		One to		Four to		More Than
	Total		One Year		Three Years		Five Years		Five Years
Long-term debt	$	116,250	$	—	$	—	$	—	$	116,250
Lease commitments		4,110		795		1,695		578		1,042
Total contractual obligations	$	120,360	$	795	$	1,695	$	578	$	117,292

Contractual obligations for long-term debt above does not include amounts for interest payments.

We were not in compliance with certain financial covenants relating to the loan with the International Finance Corporation. We obtained a waiver through March 8, 2009. Accordingly, the amount is shown in the above table as maturing in accordance with the original terms of the loan facility.

In conjunction with FIN 48, we have no certainty as to when unrecognized tax benefits of $326,000 will become due.

40

Results of Operations

Comparison of Years Ended December 31, 2007 and 2006

	For the Years Ended December 31,
	2007		2006			2007		2006
Production:					Average Price:
Oil (MBbls):					Oil ($/Bbl):
France		383		442	France		67.49		61.74
Turkey		66		68	Turkey		61.98		56.10
Romania		10		8	Romania		57.59		52.71
Total		459		518	Total	$	66.50	$	60.86
Gas (MMcf):					Gas ($/Mcf):
Turkey		905		—	Turkey		8.60		—
Romania		689		502	Romania		4.90		3.57
Total		1,594		502	Total	$	7.00	$	3.57
MBOE:					$/ BOE:
France		383		442	France		67.49		61.74
Turkey		217		68	Turkey		54.77		56.10
Romania		124		92	Turkey		31.55		24.06
Total		724		602	Total	$	57.51	$	55.37

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

41

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

42

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.

43

The results of operations of assets in the United States that were sold in September 2007 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.
	2007			2006			2005
	(In thousands)
Revenues:
Oil and natural gas sales	$	4,489		$	7,070		$	7,767
Costs and expenses:
Lease operating		1,592			2,200			2,096
Exploration expense		105
Impairment of oil and gas properties		—			345			109
Depreciation, depletion and amortization		611			1,265			950
Dry hole costs		103			1,393			—
Allocated general and administrative		325			324			266
Gain on sale of properties		(9,244	)		(202	)		(12	)
Total costs and expenses		(6,508	)		5,325			3,409
Income before taxes		10,997			1,745			4,358
Income tax provision		(3,952	)		(642	)		(1,596	)
Income from discontinued operations	$	7,045		$	1,103		$	2,762

Provision for income taxes

At December 31, 2007, it was unlikely that the United States parent entity, Toreador Resources Corporation, would be able to generate sufficient future taxable income to utilize $21.7 million in net operating loss carryforwards. We therefore established a valuation allowance of $7.4 million which resulted in an increase to the provision for income taxes. In addition, we established a $5 million valuation allowance to reflect the likelihood that additional tax income of $14.5 million would not be generated to offset future temporary tax differences in the amount of $14.5 million.

Income (Loss) available to common shares

For the twelve months ended December 31, 2007, we reported a loss from continuing operations net of taxes of $81.5 million, compared with income of $1.5 million for the same period of 2006. For the twelve months ended December 31, 2007 we recorded a loss available to common shares of $74.6 million versus income available to common shares of $2.4 million for the year ended December 31, 2006.

Other comprehensive income

The most significant element of comprehensive income, other than net income, is foreign currency translation. As of December 31, 2007, we had an unrealized gain of $38.4 million as compared to an unrealized gain of $6.7 million in 2006. The reason for the increase in the unrealized gain is due to the weakening of the United States dollar compared to the currencies in countries in which we operate. 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

44

exchange rates used to translate the financial position of the French, Turkish, Romanian and Hungarian operations at December 31, 2007, 2006 and 2005 are shown below:

	December 31,
	2007		2006		2005
Euro	$	1.4721	$	1.3170	$	1.1797
New Turkish Lira	$	0.8574	$	0.7065	$	0.7408
Romania Lei	$	0.4076	$	0.3886	$	0.3508
Hungarian Forint	$	0.0058	$	0.0052	$	0.0047

In October 2007, we changed our 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.

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):
France		442		404	France		61.74		50.92
Turkey		68		65	Turkey		56.10		43.48
Romania		8		—	Romania		52.71		—
Total		518		469	Total	$	60.86	$	49.89
Gas (MMcf):					Gas ($/Mcf):
Romania		502		—	Romania		3.57		—
Total		502		—	Total	$	3.57	$	—
MBOE:					$/BOE:
France		442		404	France		61.74		50.92
Turkey		68		65	Turkey		56.10		43.48
Romania		92		—	Turkey		24.06		—
Total		602		469	Total	$	55.37	$	49.89

Revenues

Oil and natural gas sales

Oil and natural gas sales for the twelve months ended December 31, 2006 were $33.3 million, as compared to $23.4 million for the comparable period in 2005. This increase is primarily due to a significant increase in the average realized price for oil. Production increased by approximately 133 MBOE due primarily to the start of production in Romania and increases in production in Turkey and France.

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.

45

Costs and expenses

Lease operating expense

Lease operating expense was $8.7 million, or $14.52 per BOE produced for the twelve months ended December 31, 2006, as compared to $6.1 million, or $13.01 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 $1.7 million due to one dry hole in Hungary, as compared to $1.7 million for one dry hole in Turkey in 2005.

Depreciation, depletion and amortization

For the twelve months ended December 31, 2006 depreciation, depletion and amortization expense was $6.3 million, or $10.43 per BOE produced, as compared to $4.3 million, or $9.16 per BOE produced for the twelve months ended December 31, 2005. This increase is primarily due to the downward revision of proved reserves in France of approximately 0.9 MBOE of proved reserves.

General and administrative expense

General and administrative expense, not including stock compensation expense, was $6.8 million for the twelve months ended December 31, 2006, compared with $6 million for the comparable period of 2005. This increase is primarily due to increased personnel costs of $1.1 million, the costs associated with the Hungarian office which was opened in July 2005 totaling $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 $400,000 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.

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 $8.6 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

46

resale” and“Asset retirement obligations, oil and gas properties held for sale,” respectively, in the Balance Sheet as of December 31, 2006.

The results of operations of assets in the United States that were sold in January 2004 and September 2007 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
	(In thousands)
Revenues:
Oil and natural gas sales	$	7,070		$	7,767
Costs and expenses:
Lease operating		2,200			2,096
Impairment of oil and gas properties		345			109
Depreciation, depletion and amortization		1,265			950
Dry hole costs		1,393			—
Allocated general and administrative		324			266
Gain on sale of properties		(202	)		(12	)
Total costs and expenses		5,325			3,409
Income before taxes		1,745			4,358
Income tax provision		(642	)		(1,596	)
Income from discontinued operations	$	1,103		$	2,762

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 $1.5 million, compared with income of $7.8 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

The most significant element of comprehensive income, other than net income, is foreign currency translation. For the year ended December 31, 2006, we had an unrealized gain of $6.7 million, as compared to an unrealized loss of $8.1 million in 2005. The reason for the change in unrealized income is due to the strength of the U.S. dollar compared to the Euro in 2006.

47

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
Euro	$	1.3170	$	1.1797
New Turkish Lira	$	0.7065	$	0.7408
Romania Lei	$	0.3886	$	0.3508
Hungarian Forint	$	0.0052	$	0.0047

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 31,			June 30,			September 30,			December 31,
	(In thousands, except per share data)
For the year ended December 31, 2007:
Total revenues	$	6,821		$	9,962		$	12,400		$	12,508
Total costs and expenses		16,147			35,368			39,161			32,481
Loss from continuing operations, net of tax		(9,326	)		(25,406	)		(26,761	)		(19,973	)
Income from discontinued operations, net of tax		551			359			6,021			114
Net loss		(8,775	)		(25,047	)		(20,740	)		(19,859	)
Loss available to common shares		(8,816	)		(25,087	)		(20,780	)		(19,900	)
Basic loss available to common shares per share		(0.55	)		(1.32	)		(1.09	)		(1.05	)
Diluted loss available to common shares per share		(0.55	)		(1.32	)		(1.09	)		(1.05	)
For the year ended December 31, 2006 :
Total revenues	$	8,149		$	8,445		$	8,835		$	7,899
Total costs and expenses		5,454			7,571			3,686			15,142
Income (loss) from continuing operations		2,695			874			5,149			(7,243	)
Income (loss) from discontinued operations, net of tax		453			699			323			(372	)
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	)

48

Off Balance Sheet Arrangements

We do not have any off-balance sheet arrangements that have or are reasonably likely to have a current or material future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

Item 7A.   Quantitative and Qualitative Disclosures About Market Risk

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

The following quantitative and qualitative information is provided about financial instruments to which we are a party as of December 31, 2007, 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 2008 sales volumes at fixed prices, such a decrease would result in a reduction to oil and natural gas sales revenue of approximately $7.5 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, 2007, such a decrease would result in an unrealized loss of approximately $6.8 million due to foreign currency exchange rates.

Derivative Financial Instruments

At times we utilize commodity derivative instruments as part of our risk management program. 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.”

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 onpage F-1 of this annual report onForm 10-K and are incorporated herein.

49

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

ITEM 9.   Changes In And Disagreements With Accountants On Accounting And Financial Disclosure.

None.

Item 9A.   Controls and Procedures

Corporate Disclosure Controls

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures (as defined inRules 13a-15(e) and15d-15(e) under the Securities Exchange Act of 1934, as amended) 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 and Senior Vice President — Finance & Chief Accounting Officer of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this annual report. Based on that evaluation, our Chief Executive Officer and Senior Vice President — Finance & Chief Accounting Officer concluded that our disclosure controls and procedures as of December 31, 2007 were not effective as described below.

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, as amended,Rules 13a-15(f) and15d-15(f). 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, 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 U.S. 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, 2007, 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 inInternal Control — Integrated Frameworkissued 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 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 onForm 10-K for the year ended December 31, 2007. As a result of these assessments, one material weakness was identified. A material weakness is a control deficiency,

50

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.

•  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 weakness described above, management has concluded that our internal control over financial reporting was not effective as of December 31, 2007 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 our consolidated financial statements included in this annual report on Form 10-K for the year ended December 31, 2007, has issued an attestation report on our internal control over financial reporting as of December 31, 2007, which is included in Item 8. “Financial Statements”.

Changes in Internal Controls

In the quarter ended December 31, 2007, we had the following changes in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting:

•  We hired an international accounting and financial reporting consultant, to review the accounting function both domestically and internationally.

•  We re-assigned an employee as an assistant to our Compliance Manager.

•  We assigned the Payroll Manager the responsibility to clerically check theForm 10-K andForm 10-Q for accuracy.

•  We established a new procedure for the 2007 year end close where each foreign accounting manager came to Dallas to offer assistance with the 2007 audit.

•  We established a new procedure that both the foreign accounting managers and branch managers certify that the financial statements do not contain any material misstatements.

•  We continued the automation of our foreign sub-consolidations. We expect this project to be completed in the second quarter of 2008.

51

ITEM 9B.   Other Information.

None.

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 2008 Annual Meeting of Stockholders, that will be filed with the Securities and Exchange Commission on or prior to April 29, 2008, 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 2008 Annual Meeting of Stockholders, that will be filed with the Securities and Exchange Commission on or prior to April 29, 2008, 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 2008 Annual Meeting of Stockholders, that will be filed with the Securities and Exchange Commission on or prior to April 29, 2008, 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 2008 Annual Meeting of Stockholders, that will be filed with the Securities and Exchange Commission on or prior to April 29, 2008, 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 2007 and 2006 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 2008 Annual Meeting of Stockholders, that will be filed with the Securities and Exchange Commission on or prior to April 29, 2008, and that is incorporated herein by reference.

52

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, 2007 and 2006, Consolidated Statements of Operations and Comprehensive Income for the three years in the period ended December 31, 2007, Consolidated Statements of Changes in Stockholders’ Equity for each of the three years in the period ended December 31, 2007, Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 2007, and Notes to Consolidated Financial Statements.

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

3. Exhibits:  The exhibits required to be filed by this Item 15 are set forth in the Index to Exhibits accompanying this report.

53

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused thisForm 10-K to be signed on its behalf by the undersigned, thereunto duly authorized.

TOREADOR RESOURCES CORPORATION

/s/  Nigel J. Lovett

Nigel J. Lovett,

President and Chief Executive Officer

March 17, 2008

KNOW ALL MEN BY THESE PRESENTS, that each of the undersigned officers and directors of Toreador Resources Corporation hereby constitutes and appoints Nigel J. Lovett and Charles J. Campise, 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 thisForm 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. Lovett Nigel J. Lovett	President, Chief Executive Officer and Director	March 17, 2008
/s/  Alan Bell Alan Bell	Director	March 17, 2008
/s/  David M. Brewer David M. Brewer	Director	March 17, 2008
/s/  Herbert L. Brewer Herbert L. Brewer	Director	March 17, 2008
/s/  Peter L. Falb Peter L. Falb	Director	March 17, 2008
/s/  John Mark Mclaughlin John Mark Mclaughlin	Chairman and Director	March 17, 2008
/s/  Nicholas Rostow Nicholas Rostow	Director	March 17, 2008

54

Signature	Capacity in Which Signed	Date
/s/  H.R. Sanders, Jr. H.R. Sanders, Jr.	Director	March 17, 2008
/s/  Herbert Williamson Herbert Williamson	Director	March 17, 2008
/s/  Charles J. Campise Charles J. Campise	Sr. Vice President-Finance & Accounting and Chief Accounting Officer	March 17, 2008

55

INDEX TO EXHIBITS

Exhibit
Number			Description
	2	.1	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 onForm 8-K filed on January 15, 2004, FileNo. 0-2517, and incorporated herein by reference).
	2	.2	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 onForm 8-K filed with the Securities and Exchange Commission on June 13, 2005, FileNo. 0-2517, and incorporated herein by reference).
	2	.3	Agreement for Purchase and Sale among Toreador Resources Corporation, Toreador Exploration & Production Inc. and Toreador Acquisition Corporation, as Sellers, and RTF Realty Inc., as Buyer dated August 2, 2007. (Certain of the exhibits and schedules have been omitted from this filing. An exhibit to the exhibit and schedules is contained in the Agreement for Purchase and Sale and the omitted exhibits and schedules are available to the Securities and Exchange Commission upon request) (previously filed as Exhibit 10.1 to Toreador Resources Corporation Current Report onForm 8-K filed on August 6, 2007, FileNo. 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 onForm 8-K filed with the Securities and Exchange Commission on March 29, 2005, FileNo. 0-2517, and incorporated herein by reference).
	3	.2	Fourth Amended and Restated Bylaws of Toreador Resources Corporation (previously filed as Exhibit 3.1 to Toreador Resources Corporation Current Report onForm 8-K filed with the Securities and Exchange Commission on November 13, 2007, FileNo. 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 onForm 10-K for the year ended December 31, 2004, FileNo. 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 onForm S-3 filed with the Securities and Exchange Commission on August 20, 2004, FileNo. 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 onForm 10-K for the year ended December 31, 2005, FileNo. 0-2517, and incorporated herein by reference).
	4	.4*	Registration Rights Agreement, effective November 1, 2002, among Toreador Resources Corporation and persons party thereto.
	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 onForm 10-Q for the quarter ended September 30, 2003, FileNo. 0-2517, and incorporated herein by reference).
	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 onForm 10-K for the year ended December 31, 2003, FileNo. 0-2517, and incorporated herein by reference).
	4	.7	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 onForm S-3(333-129628) filed with the Securities and Exchange Commission on November 10, 2005, FileNo. 0-2517, and incorporated herein by reference).

56

Exhibit
Number			Description
	4	.8	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 onForm S-3(333-129628) filed with the Securities and Exchange Commission on November 10, 2005, FileNo. 0-2517, and incorporated herein by reference).
	4	.9	Registration Rights Agreement dated March 21, 2007 by and among Toreador Resources Corporation and the Buyers listed therein (previously filed as Exhibit 4.1 to Toreador Resources Corporation Current Report onForm 8-K filed on March 22, 2007, FileNo. 0-2571, and incorporated herein by reference).
	4	.10	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 onForm 8-K filed with the Securities and Exchange Commission on July 13, 2005, FileNo. 0-2517, and incorporated herein by reference).
	4	.11*	First Amendment to Registration Rights Agreement dated as of February 15, 2008 by and among Toreador Resources Corporation, Capital Ventures International and Goldman, Sachs & Co.
	5	.1*	Legal Opinion of Gunel & Kaya.
	10	.1+	Toreador Royalty Corporation 1990 Stock Option Plan (previously filed as Exhibit 10.2 to Toreador Resources Corporation Annual Report onForm 10-K for the year ended December 31, 2004, FileNo. 0-2517, and incorporated herein by reference).
	10	.2+	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 onForm 10-K for the year ended December 31, 2004, FileNo. 0-2517, and incorporated herein by reference).
	10	.3+	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 onForm 10-K for the year ended December 31, 2004, FileNo. 0-2517, and incorporated herein by reference).
	10	.4*+	Amendment Number One to Toreador Resources Corporation Amended and Restated 1990 Stock Option Plan.
	10	.5*+	Amendment Number Two to Toreador Resources Corporation Amended and Restated 1990 Stock Option Plan.
	10	.6+	Toreador Royalty Corporation 1994 Non-Employee Director Stock Option Plan, as amended (previously filed as Exhibit 10.7 to Toreador Resources Corporation Annual Report onForm 10-K for the year ended December 31, 2004, FileNo. 0-2517, and incorporated herein by reference).
	10	.7*+	Toreador Resources Corporation Amended and Restated 1994 Non-employee Director Stock Option Plan.
	10	.8*+	Toreador Resources Corporation 2002 Stock Option Plan.
	10	.9*+	Amendment Number One to the Toreador Resources Corporation 2002 Stock Option Plan.
	10	.10+	Toreador Resources Corporation 2005 Long-Term Incentive Plan (previously filed as Exhibit 10.1 to Toreador Resources Corporation Current Report onForm 8-K filed with the Securities and Exchange Commission on May 23, 2005, FileNo. 0-2517, and incorporated herein by reference).
	10	.11+	Amendment to Toreador Resources Corporation 2005 Long-Term Incentive Plan (previously filed as Exhibit 10.1 to Toreador Resources Corporation Current Report onForm 8-K filed with the Securities and Exchange Commission on May 12, 2006, FileNo. 0-2517, and incorporated herein by reference).
	10	.12+	Form of Employee Restricted Stock Award (previously filed as Exhibit 10.2 to Toreador Resources Corporation Current Report onForm 8-K filed with the Securities and Exchange Commission on May 23, 2005, FileNo. 0-2517, and incorporated herein by reference).
	10	.13+	Form of 2005 Outside Director Restricted Stock Award (previously filed as Exhibit 10.3 to Toreador Resources Corporation Current Report onForm 8-K filed with the Securities and Exchange Commission on May 23, 2005, FileNo. 0-2517, and incorporated herein by reference).

57

Exhibit
Number			Description
	10	.14+	Form of 2006 Outside Director Restricted Stock Award (previously filed as Exhibit 10.3 to Toreador Resources Corporation Current Report onForm 8-K filed with the Securities and Exchange Commission on May 12, 2006, FileNo. 0-2517, and incorporated herein by reference).
	10	.15+	Summary Sheet: 2006 Executive Officer Annual Base Salaries (previously filed as Exhibit 10.1 to Toreador Resources Corporation Current Report onForm 8-K filed with the Securities and Exchange Commission on February 1, 2006, FileNo. 0-2517, and incorporated herein by reference).
	10	.16+	Summary Sheet: 2006 Short Term Incentive Compensation Plan (previously filed as Exhibit 10.2 to Toreador Resources Corporation Current Report onForm 8-K filed with the Securities and Exchange Commission on February 1, 2006, FileNo. 0-2517, and incorporated herein by reference).
	10	.17+	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 onForm 8-K filed with the Securities and Exchange Commission on April 12, 2006, FileNo. 0-2517, and incorporated herein by reference).
	10	.18+	Summary Sheet: 2005 Director Compensation (previously filed as Exhibit 10.3 to Toreador Resources Corporation Current Report onForm 8-K filed with the Securities and Exchange Commission on March 29, 2005, FileNo. 0-2517, and incorporated herein by reference).
	10	.19+	Summary Sheet: 2006 Non-Employee Director Equity Compensation (previously filed as Exhibit 10.2 to Toreador Resources Corporation Current Report onForm 8-K filed with the Securities and Exchange Commission on May 12, 2006, FileNo. 0-2517, and incorporated herein by reference).
	10	.20+	Summary Sheet: 2007 Director Compensation (previously filed as Exhibit 10.21 to Toreador Resources Corporation Annual Report onForm 10-K for the year ended December 31, 2006, FileNo. 0-2517, and incorporated herein by reference).
	10	.21+	Michael FitzGerald Employee Restricted Stock Award Agreement dated May 30, 2006 (previously filed as Exhibit 10.1 to Toreador Resources Corporation Current Report onForm 8-K filed with the Securities and Exchange Commission on June 5, 2006, FileNo. 0-2517, and incorporated herein by reference).
	10	.22+	Ed Ramirez Employee Restricted Stock Award Agreement dated May 30, 2006 (previously filed as Exhibit 10.2 to Toreador Resources Corporation Current Report onForm 8-K filed with the Securities and Exchange Commission on June 5, 2006, FileNo. 0-2517, and incorporated herein by reference).
	10	.23+	Michael J. FitzGerald Change in Control Agreement dated November 8, 2006 (previously filed as Exhibit 10.1 to Toreador Resources Corporation Current Report onForm 8-K filed with the Securities and Exchange Commission on November 15, 2006, FileNo. 0-2517, and incorporated herein by reference).
	10	.24+	Herbert C. Williamson III Restricted Stock Award Agreement dated November 8, 2006 (previously filed as Exhibit 10.25 to Toreador Resources Corporation Annual Report onForm 10-K for the year ended December 31, 2006, FileNo. 0-2517 and incorporated herein by reference).
	10	.25+	Nigel Lovett Restricted Stock Award Agreement dated November 8, 2006 (previously filed as Exhibit 10.26 to Toreador Resources Corporation Annual Report onForm 10-K for the year ended December 31, 2006, FileNo. 0-2517 and incorporated herein by reference).
	10	.26+	Nicholas Rostow Restricted Stock Award Agreement dated November 8, 2006 (previously filed as Exhibit 10.27 to Toreador Resources Corporation Annual Report onForm 10-K for the year ended December 31, 2006, FileNo. 0-2517 and incorporated herein by reference).
	10	.27+	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 onForm 8-K filed with the Securities and Exchange Commission on January 26, 2007, FileNo. 0-2517, and incorporated herein by reference).
	10	.28+	Summary Sheet: 2007 Nigel Lovett’s Annual Base Salary (previously filed as Exhibit 10.2 to Toreador Resources Corporation Current Report onForm 8-K filed with the Securities and Exchange Commission on January 26, 2007, FileNo. 0-2517, and incorporated herein by reference).
	10	.29+	Summary Sheet: 2007 Executive Officer Base Salaries (previously filed as Exhibit 10.1 to Toreador Resources Corporation Current Report onForm 8-K filed with the Securities and Exchange Commission on January 31, 2007, FileNo. 0-2517, and incorporated herein by reference).

58

Exhibit
Number			Description
	10	.30+	G. Thomas Graves III Stock Award Agreement dated January 25, 2007 (previously filed as Exhibit 10.31 to Toreador Resources Corporation Annual Report onForm 10-K for the year ended December 31, 2006, FileNo. 0-2517, and incorporated herein by reference).
	10	.31+	Summary Sheet: 2007 Short-Term Incentive Compensation Plan (previously filed as Exhibit 10.1 to Toreador Resources Corporation Current Report onForm 8-K filed with the Securities and Exchange Commission on February 12, 2007, FileNo. 0-2517, and incorporated herein by reference).
	10	.32+	Employment Agreement of Nigel Lovett dated March 14, 2007 (previously filed as Exhibit 10.33 to Toreador Resources Corporation Registration Statement onForm S-1 filed with the Securities and Exchange Commission on May 8, 2007,No. 333-142731, and incorporated herein by reference).
	10	.33+	Employment Agreement of Michael FitzGerald dated March 14, 2007 (previously filed as Exhibit 10.34 to Toreador Resources Corporation Registration Statement onForm S-1/A filed with the Securities and Exchange Commission on July 23, 2007,No. 333-142731, and incorporated herein by reference).
	10	.34+	Employment Agreement of Douglas Weir dated March 14, 2007 (previously filed as Exhibit 10.35 to Toreador Resources Corporation Registration Statement onForm S-1/A filed with the Securities and Exchange Commission on July 23, 2007,No. 333-142731, and incorporated herein by reference).
	10	.35+	Employment Agreement of Edward Ramirez dated March 14, 2007 (previously filed as Exhibit 10.36 to Toreador Resources Corporation Registration Statement onForm S-1 filed with the Securities and Exchange Commission on May 8, 2007,No. 333-142731, and incorporated herein by reference).
	10	.36+	Employment Agreement of Charles Campise dated March 14, 2007 (previously filed as Exhibit 10.37 to Toreador Resources Corporation Registration Statement onForm S-1 filed with the Securities and Exchange Commission on May 8, 2007,No. 333-142731, and incorporated herein by reference).
	10	.37+	Edward Ramirez Change in Control Agreement dated November 7, 2006 (previously filed as Exhibit 10.38 to Toreador Resources Corporation Registration Statement onForm S-1 filed with the Securities and Exchange Commission on May 8, 2007,No. 333-142731, and incorporated herein by reference).
	10	.38	Securities Purchase Agreement dated March 21, 2007 by and among Toreador Resources Corporation and the Buyers listed therein (previously filed as Exhibit 10.1 to Toreador Resources Corporation Current Report onForm 8-K filed on March 22, 2007, FileNo. 0-2157, and incorporated herein by reference).
	10	.39+	Separation and Mutual Release Agreement by and between G. Thomas Graves III and Toreador Resources Corporation dated April 17, 2007 (previously filed as Exhibit 10.1 to Toreador Resources Corporation Current Report onForm 8-K filed on April 20, 2007, FileNo. 0-2157, and incorporated herein by reference).
	10	.40+	Form of Amendment to Form of 2005 Outside Director Restricted Stock Award (previously filed as Exhibit 10.41 to Toreador Resources Corporation Registration Statement onForm S-1 filed with the Securities and Exchange Commission on May 8, 2007,No. 333-142731, and incorporated herein by reference).
	10	.41+	Increase in Salaries of Michael FitzGerald and Edward Ramirez effective May 1, 2007 (previously filed as Exhibit 10.42 to Toreador Resources Corporation Registration Statement onForm S-1 filed with the Securities and Exchange Commission on May 8, 2007,No. 333-142731, and incorporated herein by reference).
	10	.42+	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 onForm 10-K for the year ended December 31, 2004, FileNo. 0-2517, and incorporated herein by reference).
	10	.43*	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) .
	10	.44	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 onForm S-3(333-129628) filed with the Securities and Exchange Commission on November 10, 2005, FileNo. 0-2517, and incorporated herein by reference).

59

Exhibit
Number			Description
	10	.45	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 onForm 8-K filed with the Securities and Exchange Commission on January 4, 2007, FileNo. 0-2517, and incorporated herein by reference).
	10	.46	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 (previously filed as Exhibit 10.43 to Toreador Resources Corporation Annual Report onForm 10-K for the year ended December 31, 2006, FileNo. 0-2517, and incorporated herein by reference).
	10	.47	Quota Charge Agreement dated February 28, 2007 by and between Toreador Resources Corporation, as Charger, and International Finance Corporation, as Chargee (previously filed as Exhibit 10.44 to Toreador Resources Corporation Annual Report onForm 10-K for the year ended December 31, 2006, FileNo. 0-2517, and incorporated herein by reference).
	10	.48+	Summary Sheet — 2007 Charles J. Campise Annual Base Salary (previously filed as Exhibit 10.1 to Toreador Resources Corporation Current Report onForm 8-K filed with the Securities and Exchange Commission on June 18, 2007, FileNo. 0-2517, and incorporated herein by reference).
	10	.49+	Form of 2007 Outside Director Restricted Stock Award Agreement (previously filed as Exhibit 10.56 to Toreador Resources Corporation Registration Statement onForm S-1/A filed with the Securities and Exchange Commission on July 23, 2007,No. 333-142731, and incorporated herein by reference).
	10	.50	Amendment No. 1 dated August 9, 2007 to Loan and Guarantee Agreement dated December 28, 2006 between Toreador Resources Corporation, Toreador Turkey Ltd., Toreador Romania Ltd., Madison Oil France SAS, Toreador Energy France S.C.S., Toreador International Holding Limited Liability Company and Toreador International Finance Corporation (previously filed as Exhibit 10.1 to Toreador Resources Corporation Quarterly Report onForm 10-Q for the quarter ended September 30, 2007, FileNo. 0-2517, and incorporated hereby by reference).
	10	.51	Form of Amendment to Restricted Stock Award Agreement for Employees (November 2007) (previously filed as Exhibit 10.1 to Toreador Resources Corporation Current Report onForm 8-K filed on January 25, 2008, FileNo. 0-2517, and incorporated herein by reference.
	10	.52	Form of Restricted Stock Award Agreement for Employees (November 2007) (previously filed as Exhibit 10.2 to Toreador Resources Corporation Current Report onForm 8-K filed on January 25, 2008, FileNo. 0-2517, and incorporated herein by reference.
	10	.53*+	Summary Sheet — 2008 Charles J. Campise Annual Base Salary.
	10	.54*+	Form of Amendment to Restricted Stock Agreement for Outside Directors (January 2008).
	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 onForm 8-K filed with the Securities and Exchange Commission on May 26, 2006, FileNo. 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.
	23	.3*	Consent of Gunel & Kaya, contained in Exhibit 5.1.
	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 Senior Vice President — Finance & Accounting and Chief Accounting Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

60

Exhibit
Number			Description
	32	.1*	Certification of Chief Executive Officer and Senior Vice President — Finance & Accounting 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.
	99	.1	French Ministry Documentation (previously filed as Exhibit 99.1 to Toreador Resources Corporation Amended Annual Report onForm 10-K/A for the year ended December 31, 2006, FileNo. 0-2517, and incorporated herein by reference).
	99	.2	Summary of Hungarian Mining Law (previously filed as Exhibit 99.2 to Toreador Resources Corporation Amended Annual Report onForm 10-K/A for the year ended December 31, 2006, FileNo. 0-2517, and incorporated herein by reference).
	99	.3	Portions of Hungarian Mining Act (previously filed as Exhibit 99.3 to Toreador Resources Corporation Amended Annual Report onForm 10-K/A for the year ended December 31, 2006, FileNo. 0-2517, and incorporated herein by reference).
	99	.4	Portions of Governmental Decree Implementing the Hungarian Mining Act (previously filed as Exhibit 99.4 to Toreador Resources Corporation Amended Annual Report onForm 10-K/A for the year ended December 31, 2006, FileNo. 0-2517, and incorporated herein by reference).
	99	.5*	Letter from Hungarian Mining Bureau dated August 13, 2007.

*	Filed herewith
+	Management contract or compensatory plan

61

Item 8.   Financial Statements

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firm		F-2
Financial Statements		F-5
Consolidated Balance Sheets as of December 31, 2007 and 2006		F-5
Consolidated Statements of Operations and Comprehensive Income (Loss) for each of the three years in the period ended December 31, 2007		F-6
Consolidated Statements of Changes in Stockholders’ Equity for each of the three years in the period ended December 31, 2007		F-7
Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 2007		F-8
Notes to Consolidated Financial Statements		F-9

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Shareholders

Toreador Resources Corporation

We have audited Toreador Resources Corporation (a Delaware Corporation) and subsidiaries’ (the “Company”) internal control over financial reporting as of December 31, 2007, based on criteria established inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying “Management’s Annual Report on Internal Control Over Financial Reporting.” Our responsibility is to express an opinion on 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, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in 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 deficiency, or combination of control deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis. The following material weakness has been identified and included in management’s assessment.

•  The Company’s accounting and financial reporting systems and procedures were not sufficiently designed to ensure consistent and complete application of 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

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, 2007, based on criteria established inInternal Control — Integrated Frameworkissued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Toreador Resources Corporation and subsidiaries as of December 31, 2007 and 2006, and the related statements of operations and comprehensive income (loss), changes in stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2007. The

F-2

material weakness identified above was considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2007 financial statements, and this report does not affect our report dated March 17, 2008, which expressed an unqualified opinion on those financial statements.

/s/  GRANT THORNTON LLP

Houston, Texas

March 17, 2008

F-3

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 (the “Company”) as of December 31, 2007 and 2006, and the related consolidated statements of operations and comprehensive income (loss), changes in stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2007. 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 financial statements referred to above present fairly, in all material respects, the financial position of Toreador Resources Corporation and subsidiaries as of December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the consolidated financial statements, the Company changed its method of accounting for unrecognized tax benefits as of January 1, 2007, in connection with the adoption of FASB Interpretation No. 48,Accounting for Uncertainty in Income Taxes: an interpretation of FASB Statement No. 109. Also, 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. 123R,Share-Based Payment.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2007, based on criteria established inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO)and our report dated March 17, 2008 expressed an adverse opinion thereon.

/s/ GRANT THORNTON LLP

Houston, Texas

March 17, 2008

F-4

TOREADOR RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS

	December 31,
	2007			2006
	(In thousands, except share and per share data)
ASSETS
Current assets:
Cash and cash equivalents	$	12,721		$	12,664
Restricted cash		—			12,734
Accounts receivable, net of allowance of $120,000 and $0		12,340			9,547
Income taxes receivable		—			1,260
Oil and natural gas properties held for resale		—			9,916
Other		3,912			8,445
Total current assets		28,973			54,566
Oil and natural gas properties, net, using successful efforts method of accounting		271,951			241,099
Investments in unconsolidated entities		—			2,659
Investments		500			—
Restricted cash		10,818			7,770
Goodwill		4,942			4,551
Other assets		5,927			6,559
	$	323,111		$	317,204
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	18,280		$	33,827
Deferred lease payable		183			—
Current portion of long-term debt		—			5,000
Fair value of oil and gas derivatives		192			—
Asset retirement obligations, oil and gas properties held for sale		—			606
Income taxes payable		674			745
Total current liabilities		19,329			40,178
Long-term accrued liabilities		522			394
Deferred lease payable		478			—
Long-term debt, net of current portion		30,000			21,550
Asset retirement obligations		7,339			4,519
Deferred income tax liabilities		15,368			17,162
Convertible subordinated notes		86,250			86,250
Total liabilities		159,286			170,053
Commitments and contingencies
Stockholders’ equity:
Preferred stock,Series A-1, $1.00 par value, 4,000,000 shares authorized; liquidation preference of $1,800; 0 and 72,000 shares issued		—			72
Common stock, $0.15625 par value, 30,000,000 shares authorized; 20,566,470 and 16,655,511 shares issued		3,214			2,602
Additional paid-in capital		163,955			111,708
Retained earnings (Accumulated deficit)		(42,564	)		31,980
Accumulated other comprehensive income		41,754			3,323
Treasury stock at cost, 721,027 shares		(2,534	)		(2,534	)
Total stockholders’ equity		163,825			147,151
	$	323,111		$	317,204

See accompanying notes to the consolidated financial statements

F-5

TOREADOR RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)

	Year Ended December 31,
	2007			2006			2005
	(In thousands, except per share data)
Revenue:
Oil and natural gas sales	$	41,691		$	33,328		$	23,411
Operating costs and expenses:
Lease operating expense		12,644			8,741			6,102
Exploration expense		14,742			3,946			2,940
Dry hole and abandonment		21,840			1,706			1,738
Depreciation, depletion and amortization		21,257			6,279			4,295
Impairment of oil and natural gas properties		13,446			—			—
General and administrative		17,313			9,505			6,429
Loss on oil and gas derivative contracts		1,005			—			—
Gain on sale of properties and other assets, net		(3,159	)		(436	)		—
Total operating costs and expenses		99,088			29,741			21,504
Operating income (loss)		(57,397	)		3,587			1,907
Other income (expense):
Equity in earnings of unconsolidated investments		22			401			222
Foreign currency exchange gain (loss)		(26,305	)		(605	)		2,386
Interest and other income		1,829			1,988			1,407
Interest expense		(4,291	)		(891	)		—
Total other income (expense)		(28,745	)		893			4,015
Income (loss) from continuing operations before income taxes		(86,142	)		4,480			5,922
Income tax benefit (provision)		4,676			(3,005	)		1,911
Income from continuing operations		(81,466	)		1,475			7,833
Income from discontinued operations, net of tax		7,045			1,103			2,762
Net income (loss)		(74,421	)		2,578			10,595
Preferred dividends		(162	)		(162	)		(684	)
Income (loss) available to common shares	$	(74,583	)	$	2,416		$	9,911
Basic income (loss) available to common shares per share from:
Continuing operations	$	(4.45	)	$	0.09		$	0.50
Discontinued operations		0.38			0.07			0.19
	$	(4.07	)	$	0.16		$	0.69
Diluted income (loss) available to common shares per share from:
Continuing operations	$	(4.45	)	$	0.08		$	0.47
Discontinued operations		0.38			0.07			0.18
	$	(4.07	)	$	0.15		$	0.65
Weighted average shares outstanding:
Basic		18,358			15,527			14,213
Diluted		18,358			15,884			15,140
Statement of Comprehensive Income (Loss)
Net income (loss)	$	(74,421	)	$	2,578		$	10,595
Foreign currency translation adjustments		38,431			6,687			(8,080	)
Comprehensive income (loss)	$	35,990		$	9,265		$	2,515

See accompanying notes to the consolidated financial statements

F-6

TOREADOR RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

														Retained			Accumulated
	Preferred			Preferred			Common		Common		Additional			Earnings			Other			Treasury						Total
	Stock			Stock			Stock		Stock		Paid-in			(Accumulated			Comprehensive			Stock			Deferred			Stockholders’
	(Shares)			($)			(Shares)		($)		Capital			deficit)			Income (loss)			($)			Compensation			Equity
	(In thousands)
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, net of forfeitures		—			—			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
Cash payment of preferred dividends		—			—			—		—		—			(162	)		—			—			—			(162	)
Exercise of stock options		—			—			321		50		1,574			—			—			—			—			1,624
Issuance of restricted stock		—			—			103		16		(16	)		—			—			—			—			—
Issuance of common stock		—			—			3,037		476		49,937			—			—			—			—			50,413
Stock option expense		—			—			—		—		49			—			—			—			—			49
Amortization of deferred stock compensation		—			—			—		—		3,982			—			—			—			—			3,982
Adoption of FIN 48		—			—			—		—		—			(45	)		—			—			—			(45	)
Conversion of preferred stock to common stock		(72	)		(72	)		450		70		2			—			—			—			—			—
Net loss		—			—			—				—			(74,421	)		—			—			—			(74,421	)
Foreign currency translation adjustments		—			—			—		—		—			—			38,431			—			—			38,431
Tax effect of restricted stock		—			—			—		—		(316	)		—			—			—			—			(316	)
Payment of equity issuance costs		—			—			—		—		(2,965	)		—			—			—			—			(2,965	)
Other		—			—			—		—		—			84			—			—			—			84
Balance at December 31, 2007		—			—			20,567	$	3,214	$	163,955		$	(42,564	)	$	41,754		$	(2,534	)		—		$	163,825

See accompanying notes to the consolidated financial statements

F-7

TOREADOR RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31
	2007			2006			2005
	(In thousands)
Cash flows from operating activities:
Net Income (loss)	$	(74,421	)	$	2,578		$	10,595
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Depreciation and amortization		21,868			7,544			5,245
Amortization of deferred debt issuance cost		612			—			—
Issuance of warrants to non-employee		—			107			—
Impairment of oil and natural gas properties		13,446			345			110
Dry hole and abandonment costs		21,840			3,099			1,738
Deferred income taxes		(3,425	)		2,642			93
Unrealized loss on commodity derivatives		192			—			—
Loss (Gain) on sale of properties and equipment		343			(638	)		(12	)
Gain on the sale of discontinued operations		(9,244	)		—			—
Equity in earnings of unconsolidated investments		(22	)		(401	)		(222	)
Stock-based compensation		4,031			2,803			400
Gain on sale of unconsolidated investments		(3,502	)		—			—
Change in operating assets and liabilities, net of acquisitions
Increase in accounts receivable		(2,455	)		(1,027	)		(4,304	)
Increase (decrease) in income taxes receivable		715			(655	)		(4,453	)
Increase (decrease) in other current assets		4,880			(4,596	)		(9,740	)
Increase (decrease) in accounts payable and accrued liabilities		(1,862	)		(1,322	)		1,097
Increase in lease payable		661			—			—
Increase in other assets		118			—			—
Increase (decrease) in income taxes payable		439			3,625			(685	)
Net cash provided by (used in) operating activities		(25,786	)		14,104			(138	)
Cash flows from investing activities:
Expenditures for property and equipment		(90,644	)		(105,165	)		(50,163	)
Restricted cash		10,636			(20,504	)		—
Net cash for acquisitions		—			—			(8,751	)
Proceeds from the sale of properties and equipment		21,002			1,672			29
Distributions from unconsolidated entities		60			250			191
Sale (purchase) of short-term investments		(500	)		40,000			(40,000	)
Sale of investments in unconsolidated entities		6,123			(257	)		(754	)
Net cash used in investing activities		(53,323	)		(84,004	)		(99,448	)
Cash flows from financing activities:
Repayment of revolving credit facilities		—			(5,000	)		(4,848	)
Net borrowings under revolving credit arrangements		3,450			26,550			9,811
Exercise of stock options		1,624			866			2,552
Proceeds from the exercise of warrants		—			34			170
Proceeds from issuance of common stock, net of issuance cost of $2,965		47,448			—			55,918
Tax benefit related to stock options		—			293			—
Proceeds from issuance of notes payable		—			—			86,250
Payment of preferred dividends		(162	)		(162	)		(186	)
Net cash provided by financing activities		52,360			22,581			149,667
Net increase (decrease) in cash and cash equivalents		(26,749	)		(47,319	)		50,081
Effects of foreign currency translation on cash and cash equivalents		26,806			6,870			(1,945	)
Cash and cash equivalents, beginning of year		12,664			53,113			4,977
Cash and cash equivalents, end of year	$	12,721		$	12,664		$	53,113
Supplemental disclosures:
Cash paid during the period for interest, net of interest capitalized	$	2,927		$	—		$	—
Cash paid during the period for income taxes	$	2,761		$	2,414		$	2,690
Non-cash investing and financing activities
Conversion of preferred stock to common stock		72			—			82
Conversion of notes payable to common stock		—			—			6,413
Conversion of convertible debentures to common stock		—			810			675
Common shares issued for preferred dividends		—			—			498

See accompanying notes to the consolidated financial statements

F-8

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) 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.

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 theForm 10-K for the year ended December 31, 2007 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, 2007 and 2006 we had $10.7 million and $11.2 million, respectively, on deposit in foreign banks.

RESTRICTED CASH

Restricted cash consists of an $8.7 million deposit used to secure a bank “Letter of Guarantee” that was issued as required under the mediation proceedings with Micoperi, Srl. and $2.1 million for a letter of credit to secure additional permits in Hungary. The total amount of $10.7 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 multiple customers. At December 31, 2007 an allowance

F-9

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

for doubtful accounts of $120,000 was established for accounts receivable in Romania. An allowance for doubtful accounts did not exist at December 31, 2006. 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, net of allowance for doubtful accounts, are fully collectable.

FINANCIAL INSTRUMENTS

The carrying amounts of financial instruments including cash and cash equivalents, short-term investments, accounts receivable, accounts payable, derivative financial instruments and accrued liabilities approximate fair value, at December 31, 2007 and 2006, 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, 2007 the convertible subordinate notes which had a book value of $86.25 million, were trading at $810.00, which would equal a fair market value of approximately $70 million.

DERIVATIVE FINANCIAL INSTRUMENTS

We periodically utilize derivatives instruments such as futures and swaps for purposes of hedging our exposure to fluctuations in the price of crude oil and natural gas sales. We entered into futures and swap contracts with FC Stone, counter party for approximately 15,000 Bbls per month for the months of June 2007 through December 2008. When actual commodity prices exceeded the fixed price provided by these contracts, we paid this excess to FC Stone, and when actual commodity prices were below the contractually provided fixed price, we received this difference from FC Stone. We subsequently sold all of these contracts as of September 30, 2007 which resulted in a realized net loss of $813,000.

As of December 31, 2007 we had the following open commodity derivative contract with Total Oil Trading SA:

Type	Period	Barrels		Floor		Ceiling
Collar	January 1 — March 31, 2008		48,000	$	84.75	$	92.75

As of December 31, 2007, we recorded a net unrealized loss of $192,000 on the above open derivative contract. For the year ended December 31, 2007 we recognized a total derivative fair value loss of $1 million. We were not a party to any commodity contracts in the comparable period of 2006 or 2005

In 2006, we purchased and sold 6 foreign currency forward contracts for New 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 currency 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, 2007 and 2006, we had no receivables from counterparties.

F-10

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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, 2007 and 2006, other current assets included $2.5 million and $1.2 million 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, 2007 and 2006, other current assets included zero and $3.8 million, respectively, 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 2007, 2006 and 2005 was $3.7 million, $4.3 million, and $1.4 million, 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 afield-by-field basis. We charge any impairment in value to expense in the period incurred. In 2007 we incurred impairment losses of $13.4 million on our Romanian oil and natural gas producing properties.

ASSET RETIREMENT OBLIGATIONS

We account for our asset retirement obligations in accordance with Statement No. 143, “Accounting for Asset Retirement Obligations” (“Statement 143”), which requires us to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is

F-11

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, we either settle the obligation for its recorded amount or incur a gain or loss upon settlement.

The following table summarizes the changes in our asset retirement liability during the years ended December 31, 2007 and 2006:

	2007		2006
	(In thousands)
Asset retirement obligation January 1	$	4,519	$	3,078
Asset retirement accretion expense		462		225
Foreign currency exchange (gain) loss		394		334
Change in estimates		1,964		37
Property additions		—		845
Asset retirement obligation at December 31	$	7,339	$	4,519

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, 2007 and 2006, 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 2007, 2006 or 2005. Goodwill was reduced by $1.6 million in 2005 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 $391,000 in 2007 and $356,000 in 2006 for the foreign currency translation adjustment. The balance of goodwill at December 31, 2007 and 2006 is approximately $4.9 million and $4.6 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 2007, 2006 and 2005 sales to ELF represents approximately 62%, 67% and 66%, respectively, of the Company’s total revenue and approximately 21% and 20% of the Company’s accounts receivable at December 31, 2007 and 2006, respectively. No collateral is required against the current outstanding accounts receivable balance from ELF.

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

F-12

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

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
	(In thousands, except
	per share data)
Income available to common shares, as reported	$	9,911
Basic earnings available to common shares per share reported		0.69
Diluted earnings available to common shares per share reported		0.65
Pro-forma stock-based compensation costs under the fair value method, net of related tax		82
Pro-forma income available to common shares, as under the fair-value method		9,829
Pro-forma basic earnings available to common shares per share under the fair value method		0.69
Pro-forma diluted earnings available to common shares per share under the fair value method		0.65

F-13

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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
Dividend yield per share		—
Volatility		70.9	%
Risk-free interest rate		4.0	%
Expected lives		5 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 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. The impact of this change results in a foreign exchange gain of $5.9 million for the year ended December 31, 2007, which is included in the consolidated statements of operations.

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.

Effective January 1, 2007, we adopted the provisions of FASB Interpretation (FIN) No. 48,Accounting for Uncertainty in Income Taxes — An Interpretation of FASB Statement No. 109. FIN No. 48 clarifies financial statement recognition and disclosure requirements for uncertain tax positions taken or expected to be taken in a tax return. Financial statement recognition of the tax position is dependent on an assessment of a 50% or greater likelihood that the tax position will be sustained upon examination, based on the technical merits of the position. Any interest and penalties related to uncertain tax positions are recorded as interest expense and general and administrative expense, respectively. The adoption of FIN No. 48 did not have a significant effect on our reported financial position or earnings. See Note 9.

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.

F-14

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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. Deferred debt issue costs totaled approximately of $4,652,000 and $5,117,000 net of accumulated amortization of $552,000 and $361,000 as of December 31, 2007 and 2006, respectively.

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. The adoption of SFAS No. 157, effective January 1, 2008, did not have a significant effect on our reported financial position or earnings.

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, but it is not expected to have a significant effect on our reported financial position or earnings

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.

F-15

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

NOTE 3 — EARNINGS PER SHARE

In accordance with the provisions of FASB Statement of Financial Accounting Standards No. 128,“Earnings per Share”(“Statement 128”), basic earnings per share 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,
	2007			2006			2005
	(In thousands, except per share data)
Basic earnings per share:
Numerator
Income (loss) from continuing operations, net of income tax	$	(81,466	)	$	1,475		$	7,833
Less: dividends on preferred shares		162			162			684
Income (loss) from continuing operations, net of tax		(81,628	)		1,313			7,149
Income from discontinued operations, net of tax		7,045	��		1,103			2,762
Income available to common shares	$	(74,583	)	$	2,416		$	9,911
Denominator
Common shares outstanding		18,358			15,527			14,213
Basic earnings available to common shares per share from:
Continuing operations before cumulative effect of change in accounting principle	$	(4.45	)	$	0.09		$	0.50
Discontinued operations		0.38			0.07			0.19
Basic income per share	$	(4.07	)	$	0.16		$	0.69
Diluted earnings per share:
Numerator
Income (loss) from continuing operations, net of income tax	$	(81,466	)	$	1,475		$	7,833
Less: dividends on preferred shares		162			162			684
Add: interest on convertible debentures		—			—			73
Income (loss) from continuing operations, net of tax		(81,628	)		1,313			7,222
Income (loss) from discontinued operations, net of tax		7,045			1,103			2,762
	$	(74,583	)	$	2,416		$	9,984
Denominator
Common shares outstanding		18,358			15,527			14,213
Stock options, restricted stock and warrants		—			357			746
Conversion of preferred shares		—	(1)		—	(1)		—	(1)
Conversion of 7.85% notes payable(3)		—			—			—	(1)
Conversion of 5.0% notes payable(2)		—	(1)		—	(1)		—	(1)
Conversion of debentures		—	(1)		—	(1)		181
Diluted shares outstanding		18,358			15,884			15,140
Diluted earnings available to common shares per share from:
Income (loss) before cumulative effect of change in accounting principle, net of tax	$	(4.45	)	$	0.08		$	0.47
Discontinued operations		0.38			0.07			0.18
Diluted income per share	$	(4.07	)	$	0.15		$	0.65
Anti-dilutive securities not included above are as follows:
Stock options, restricted stock and warrants		148			—			—
Preferred shares		450			450			524
7.85% notes payable(3)		—			—			43
Debentures		—			26			—
5% notes payable(2)		2,015			2,015			552

(1) Conversion of these securities would be antidilutive; therefore, there are no dilutive shares.

F-16

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(2)	5% Senior Convertible Notes were issued on September 27, 2005.
(3)	7.85% Notes Payable were issued in July 2004 and subsequently exchanged in January 2005

NOTE 4 — ACCOUNTS RECEIVABLE

Accounts receivable consisted of the following:

	December 31,
	2007		2006
	(In thousands)
Oil and natural gas sales receivables, net of allowance of $120,000 and $0	$	3,154	$	4,209
Trade receivables		2,182		3,394
Joint interest billing		2,163		—
Recoverable VAT		4,221		—
Other accounts receivable		620		1,944
	$	12,340	$	9,547

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 at December 31, 2007 and 2006 consist of accrued interest receivable on time deposits, value added tax refunds and travel advances to employees.

NOTE 5 — OIL AND NATURAL GAS PROPERTIES

Oil and natural gas properties consist of the following:

	December 31,
	2007			2006
	(In thousands)
Licenses and concessions	$	3,591		$	3,895
Non-producing leaseholds		184,067			149,168
Producing leaseholds and intangible drilling costs		154,437			121,794
Furniture, fixtures and office equipment		3,370			3,183
		345,465			278,044
Accumulated depreciation, depletion and amortization		(73,514	)		(36,945	)
Total oil and natural gas properties	$	271,951		$	241,099

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.

F-17

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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
	2007			2006
	(In thousands)
Capitalized exploratory well cost, beginning of the year	$	5,256		$	1,042
Additions to capitalized exploratory well costs pending determination of proved reserves		—			4,400
Reclassified to dry hole costs		(5,256	)		—
Reclassified to oil and natural gas properties based on determination of proved reserves		—			(186	)
Capitalized exploratory well costs, end of year	$	—		$	5,256

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
	2007		2006
	(In thousands)
Capitalized exploratory well cost that have been capitalized for a period of one year or less	$	—	$	4,400
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

NOTE 6 — 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, 2007 and 2006 our investment in ePsolutions amounted to zero and $1.5 million, respectively. For the years ended December 31, 2007 and 2006 we advanced zero and $257,000, respectively, and we recorded equity in ePsolutions of $41,000 in 2007, a loss of $70,000 in 2006 and a loss of $238,000 in 2005. In April 2007, we sold our interest in ePsolutions to ePsolutions for $3.9 million and recorded a gain on the sale of $2.3 million.

In July 2000, we acquired 35% of EnergyNet.com, Inc. (“EnergyNet”), an Internet based oil and natural gas property auction company. At December 31, 2007 and 2006, our investment in EnergyNet amounted to zero and $997,000, respectively. We recorded equity in the loss of EnergyNet of $45,000 in 2007, earnings of $340,000 in 2006 and earnings of $409,000 in 2005. We received a dividend from EnergyNet of zero in 2007, $175,000 in 2006 and $131,250 in 2005. In April 2007, we sold our interest in EnergyNet.com to EnergyNet.com for $2 million and recorded a gain on the sale of $1.1 million.

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 zero and $160,000 at December 31, 2007 and 2006, respectively. We recorded equity in the earnings of Capstone amounting to $26,000 in 2007, $131,000 in 2006 and $51,000 in 2005. We received a distribution from Capstone of $60,000 in 2007, $75,000 in 2006 and $60,000 in 2005. In April 2007, we sold our interest in Capstone Royalty, LLC to Capstone Royalty, LLC for $250,000 and recorded a gain on the sale of $124,000.

F-18

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

NOTE 7 — LONG-TERM DEBT

Long-term debt consisted of the following:

	December 31,
	2007		2006
	(In thousands)
Revolving line of credit with Texas Capital Bank, N.A.	$	—	$	5,550
Revolving line of credit with Natixis Banques Populaires		—		11,000
Secured revolving facility with the International Finance Corporation		30,000		10,000
Convertible senior notes		86,250		86,250
		116,250		112,800
Less: current portion		—		(5,000	)
	$	116,250	$	107,800

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 $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 ourForm 10-Q for the nine month period ended September 30, 2006. Since we cured the covenant default within

F-19

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 or not being required to be effective pursuant to the registration rights agreement. Because we did not file our Quarterly Report onForm 10-Q for the nine month period ended September 30, 2006 in a timely manner, the registration statement for the 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 theForm 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 paid approximately $14,375 in additional interest expense. On March 16, 2007, the date we filed ourForm 10-K for the year ended December 31, 2006, we again entered a Suspension Period until all the Notes became eligible for sale pursuant to Rule 144(k) on September 30, 2007. On October 1, 2007, $155,000 was deposited with the trustee for the Notes as the penalty for any holders of the Notes who were eligible on October 1, 2007 to receive a pro rate portion of such payment. Such eligible holders had to have registered their Notes on the registration statement and still held those Notes on October 1, 2007. Through March 12, 2008, we had released $4,043 of the penalty deposit to eligible holders of Notes.

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 bore interest at a floating rate of 2.25-2.75% above LIBOR (8.053% at March 2, 2007) depending on the principal outstanding. The facility was 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 were each guaranteed the obligations under the facility. This facility required monthly interest payments until December 23, 2009, at which time all unpaid principal and interest were to be due. We were 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, limited additional indebtedness, the sale of assets, change of control and management, limitations on the distribution of stock dividends and required us to meet certain financial requirements. Specifically, we had to 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 theForm 10-Q for the quarter ended September 30, 2006 and provided the unaudited consolidated financial statements contained in theForm 10-Q to Natixis which cured the default.

On March 2, 2007, the facility was retired and all amounts due were paid.

F-20

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 which was funded on December 28, 2006. In September 2007, we repaid $5 million on the $25 million facility from proceeds received on the U.S. oil and gas property sale. As of December 31, 2007, the International Finance Corporation has reduced our borrowing base under both loans to $30 million from $35 million. Until the next redetermination date, the Company has no additional borrowing capacity under these facilities. Both the $25 million facility and $10 million facility are to fund 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 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, 2007, the interest rate on the $10 million facility was 5.329% and the interest rate on the $25 million facility was 6.829%. 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.

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 EBITDAX 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. On August 9, 2007, the covenant requirements were amended to replace the adjusted financial debt to EBITDA ratio not being more than 3.0:1.0 with the adjusted financial debt to EBITDAX ratio not being more than 3.0:1.0 and the definition of interest coverage ratio was adjusted to include EBITDAX instead of EBITDA for calculation purposes. At December 31, 2007, we were not in compliance with the interest rate coverage ratio of not less than 3.0:1.0; the actual ratio was 2.8:1.0. The International Finance Corporation has granted the Company a temporary waiver for the interest coverage ratio provided the Company maintains EBITDAX to net interest expense ratio of 2.7:1.0 until July 2, 2008 and EBITDA to net interest expense ratio of a least 2.7:1.0 during the remaining period of the waiver effectiveness. The waiver is effective until March 8, 2009.

We 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,

F-21

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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. On March 30, 2007, the Texas Capital facility was retired and all amounts due were paid. The facility bore interest at a rate of prime less 0.5% (7.75% total rate at March 30, 2007) and was collateralized by our domestic working interests. The borrowers under this facility were two of our domestic subsidiaries, and the Company has guaranteed the obligations. The Texas Capital facility required monthly interest payments until January 1, 2010 at which time all unpaid principal and interest were to be due. The Texas Capital facility contained various affirmative and negative covenants. These covenants, among other things, limited additional indebtedness, the sale of assets, change of control and management and required us to meet certain financial requirements. Specifically, we had to 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 theForm 10-Q for the quarter ended September 30, 2006 and provided the unaudited consolidated financial statements contained in theForm 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.

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

F-22

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 debenture into 100,000 shares of our common stock. As a result, at December 31, 2004 the outstanding principal amount of the second amended and restated convertible debenture was approximately $1.5 million. On August 10, 2005, PHD Partners converted $675,000 of the second amended and restated debenture into 100,000 shares of our common stock, resulting in an outstanding principal balance of $810,000 at December 31, 2005. In February 2006, PHD Partners LP converted the $135,000 of the second amended and restated debenture into 19,962 shares of our common stock and in March 2006, PHD Partners converted the remaining balance of $675,000 of the second amended and restated debenture into 100,000 shares of our common stock. Interest payments made to PHD Partners LP were zero, $9,682 and $73,195 in 2007, 2006 and 2005, respectively.

The following table summarizes the principal maturities under our long-term debt arrangements at December 31, 2007, (in thousands):

	2008		2009		2010		2011		2012		Thereafter		Total
Long-term debt	$	—	$	—	$	—	$	—	$	—	$	116,250	$	116,250

We were not in compliance with certain financial covenants relating to the loan with the International Finance Corporation. We obtained a waiver through March 8, 2009. Accordingly, the amount is shown in the above table as maturing in accordance with the original terms of the loan facility.

NOTE 8 — CAPITAL

On March 23, 2007, we closed a $45 million private placement of equity. In the transaction, we issued an aggregate of 2,710,843 shares of common stock to six institutional investors, providing us with $45 million of gross proceeds at closing. We also granted the investors the right to purchase an additional $8.1 million aggregate amount of common stock within the next30-day period. On April 24, 2007, two of the institutional investors exercised their warrants for an aggregate of 326,104 additional shares of common stock, providing us with approximately $5.4 million of gross proceeds. The net proceeds from the private placement totaled approximately $47 million and were used to help fund our 2007 exploration and development activities.

In connection with the private placement, we entered into a Registration Rights Agreement with the investors. The Registration Rights Agreement provided that we would file a registration statement with the Securities and Exchange Commission covering the resale of the common stock within 60 days after the closing date. If the registration statement was not filed with the Securities and Exchange Commission within such time, we had to pay 1.0% of the aggregate purchase price, an additional 1.0% on the one month anniversary of the 60th day after closing if the registration statement had not been filed by such date and an additional 2.0% of the aggregate purchase price for each 30 day period after the one month anniversary if the registration statement was not filed by such date. We filed the registration statement with the Securities and Exchange Commission on May 8, 2007. If the registration statement was not declared effective by the Securities and Exchange Commission within 150 days after the closing date, we had to pay 1.0% of the aggregate purchase price, an additional 1.0% on the one month anniversary of the 150th day after the closing if the registration statement had not been declared effective by the Securities and Exchange Commission by such date and an additional 2.0% of the aggregate purchase price for each 30 day period after the one month anniversary if the registration statement was not declared effective by such date. The registration statement was declared effective July 26, 2007. Now that the registration statement has been declared effective by the Securities and Exchange Commission, if, subject to certain exceptions, future sales cannot be made pursuant to the registration statement after 60 days has elapsed, we must pay 1.0% of the aggregate purchase price on the date sales cannot be made pursuant to the registration statement, an additional 1% on the one month

F-23

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

anniversary of the date sales are not permitted under the registration statement if sales are not permitted under the registration statement by such date and an additional 2.0% of the aggregate purchase price for each 30 day period after the one month anniversary if sales under the registration statement are not permitted by such date. Any one month or 30 day periods during which we cure the violation will cause the payment for such period to be made on a pro rata basis. As a result of the change in the resale restrictions under Rule 144, effective February 15, 2008, we amended the Registration Rights Agreement to provide that we do not have to keep the registration statement effective if the holders of the shares covered by the Registration Rights Agreement can sell all of the shares pursuant to Rule 144.

The Company accounts for registration rights agreements containing a contingent obligation to make future payments or otherwise transfer consideration under a registration payment arrangement, in accordance withEITF IssueNo. 00-19-2, “Accounting for Registration Payment Arrangements”. Under this approach, the contingent obligation to make future payments or otherwise transfer consideration under a registration payment arrangement shall be recognized and measured separately in accordance with“FAS No. 5, Accounting for Contingencies” and “FASB Interpretation No. 14, Reasonable Estimation of the Amount of a Loss”.

Toreador had zero and 72,000 shares of nonvotingSeries A-1 Convertible Preferred Stock outstanding at December 31, 2007 and 2006. At the option of the holder, theSeries A-1 Convertible Preferred Stock may be converted into common shares at a price of $4.00 per common share (conversion would have amounted to 450,000 Toreador common shares at December 31, 2007). TheSeries A-1 Convertible Preferred Stock accrued dividends at an annual rate of $2.25 per share payable quarterly in cash. At any time on or after November 1, 2007, we had the right to redeem for cash any or all shares ofSeries A-1 Convertible Preferred Stock. The optional redemption price per share was the sum of (1) $25.00 per share of theSeries A-1 Convertible Preferred Stock plus (2) any accrued unpaid dividends, and such sum is multiplied by a declining multiplier. The multiplier is 105% until October 31, 2008, 104% until October 31, 2009, 103% until October 31, 2010, 102% until October 31, 2011, 101% until October 31, 2012, and 100% thereafter. In December 2007, all the Series A-1 Convertible Preferred Stock was converted into common shares.

On February 22, 2005, 82,000 shares of ourSeries A-1 Convertible Preferred Stock were exchanged for an aggregate of 512,500 shares of Toreador common stock pursuant to an offer made by the Company to each holder of itsSeries A-1 Convertible Preferred Stock. Each holder was given the opportunity to convert such shares of Preferred Stock into shares of common stock of the Company pursuant to the terms of conversion of the Preferred Stock. In addition the Company offered additional shares of common stock as an inducement for the holders to convert the Preferred Stock at a time when the Company could not mandatorily redeem the Preferred Stock and in lieu of dividends that would otherwise accrue until such mandatory redemption date to the terms thereof and an additional 20,164 shares of our common stock which were issued as an inducement to convert such shares ofSeries A-1 Convertible Preferred Stock. Fair market value of common stock on the date of issue was $24.70 per share.

On July 22, 2004, we issued warrants for the purchase of 40,000 shares of our common stock at $8.20 per share. The warrant was issued pursuant to the terms of the letter agreement dated July 19, 2004. At December 31, 2006 there were 36,400 warrants outstanding all of which expire July 22, 2009. We recognized $58,410 in expense relating to the issuance of the warrants.

On July 11, 2005, we issued warrants for the purchase of 50,000 shares of our common stock at $27.40 per share. The warrant was issued pursuant to the terms of the Fee Letter, dated February 21, 2005, between the Company, Natexis Banques Populaires and Madison Energy France. At December 31, 2006 all 50,000 warrants were outstanding and expire on December 23, 2009. In 2005 and 2006, we recognized $836,000 in expense relating to the issuance of the warrants.

On January 3, 2006, we issued warrants for the purchase of 10,000 shares of our common stock at $27.65 per share. The warrant was issued pursuant to the terms of the Engagement Letter, dated January 3, 2006, between the

F-24

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Company and ParCon Consulting. At December 31, 2006 all 10,000 warrants were outstanding and expire on January 3, 2011. We recognized $106,800 in expense relating to the issuance of the warrants.

On February 16, 2005, we sold 1,437,500 shares of our common stock pursuant to a public offering at a price to the public of $24.25 per share. The sale resulted in net proceeds of approximately $32.3 million.

On September 16, 2005, we sold 806,450 shares of our common stock to certain accredited investors pursuant to a private placement. The sale resulted in net proceeds of approximately $23.6 million.

NOTE 9 — INCOME TAXES

The Company’s provision (benefit) for income taxes consists of the following at December 31:

	2007			2006			2005
	(In thousands)
Current:
U.S. Federal	$	(31	)	$	(581	)	$	(2,421	)
U.S. State		323			(7	)		46
Foreign		2,409			1,156			1,140
Deferred:
U.S. Federal		(32	)		135			1,383
U.S. State		—			—			—
Foreign		(3,393	)		2,944			(463	)
	$	(724	)	$	3,647		$	(315	)
The tax provision (benefit) has been allocated between continuing operations and discontinued operations as follows:
Provision (benefit) allocated to:
Continuing operations	$	(4,676	)	$	3,005		$	(1,911	)
Discontinued operations		3,952			642			1,596
	$	(724	)	$	3,647		$	(315	)

F-25

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

	2007			2006			2005
	(In thousands)
Statutory tax at 34%	$	(25,549	)	$	2,113		$	3,501
Rate differences related to foreign operations		6,479			584			(2,967	)
Use of NOL carryforwards		—			(121	)		—
Reduction in Turkish net operating loss		—			143			—
State income tax, net		213			(5	)		(148	)
Foreign currency gain (loss) not taxable in foreign jurisdictions		4,497			265			(857	)
Release of tax reserve		—			—			(49	)
Effect of rate changes in foreign countries		—			(1,062	)		—
Adjustments to valuation allowance		14,172			1,846			(385	)
Use of percentage depletion		—			—			(98	)
Use of capital loss carryover		—			—			(90	)
Other		(537	)		(116	)		778
	$	(724	)	$	3,647		$	(315	)

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities as of December 31, 2007 and 2006 were as follows:

	December 31,
	2007			2006
	(In thousands)
Deferred tax assets:
Net operating loss carryforward — United States	$	8,620		$	2,150
Net operating loss carryforward — State		135			—
Net operating loss carryforward — Foreign		12,265			7,002
Restricted stock		689			835
Impairment — Foreign		4,571			—
Other		475			416
Gross deferred tax assets		26,755			10,403
Valuation allowance		(20,900	)		(6,609	)
Net deferred tax assets		5,855			3,794
Deferred tax liabilities:
Differences in oil and gas property capitalization and depletion methods— United States		—			(1,337	)
Differences in oil and gas property capitalization and depletion methods— Foreign		(20,768	)		(19,064	)
Unrealized foreign currency translation gains— United States		(455	)		(501	)
Other					(54	)
Gross deferred tax liabilities		(21,223	)		(20,956	)
Net deferred tax liabilities	$	(15,368	)	$	(17,162	)

F-26

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

At December 31, 2007, Toreador had the following carryforwards available to reduce future taxable income (in thousands):

Jurisdiction	Expiry		Amount
United States — Federal		2010 — 2022	$	25,353
United States — State		2020		3,400
Hungary		Unlimited		37,650
Turkey		2008 — 2012		26,999
France		Unlimited		2,523

Realization of net operating loss carryforwards depends on our ability to generate taxable income within the carryforward period. Due to uncertainty related to the Company’s ability to generate taxable income in the respective countries sufficient to realize all of our deferred tax assets we have recorded the following valuation allowances:

	December 31,
	2007		2006
	(In thousands)
United States	$	8,755	$	1,241
Turkey		—		16
Hungary		6,024		4,604
France		841		748
	$	15,620	$	6,609

Future net operating loss carryforwards for which a valuation allowance has been provided will be realized when taxable income amounts below are generated in the following countries:

	Required
	Taxable Income
United States	$	25,353
Turkey		26,999
Hungary		37,650
France		2,523

A portion of the Hungarian net operating loss was acquired in a purchase, therefore realization of $25 million of the Hungarian net operating loss will be credited to oil and natural gas properties rather than a credit to income tax expense.

Under APB 23, we have elected to treat our foreign earnings as permanently reinvested outside the US and are not providing US tax expense on those earnings. However, Romania has a US branch which is not permanently reinvested outside the US. Consequently the US tax on its earnings is reflected in consolidated income tax expense at the US tax rate of 34%.

We adopted FIN No. 48,“Accounting for Uncertainty in Income Taxes”, on January 1, 2007. As a result of the adoption the Company recognized an increase in the liability for unrecognized tax benefits of approximately $45,000, which was accounted for as a decrease to the January 1, 2007 balance of retained earnings. As of the date of adoption and after the impact of recognizing the increase in liability noted above, our unrecognized tax benefits totaled approximately $357,000, the disallowance of which would not materially affect the effective income tax rate. There are no tax positions for which a material change in the unrecognized tax benefit liability is reasonably possible in the next 12 months.

F-27

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

We recognize potential accrued interest and penalties related to unrecognized tax benefits within our global operations in income tax expense. In conjunction with the adoption of FIN 48, we recognized approximately $28,000 for the accrual of interest and penalties at January 1, 2007 which is included as a component of $357,000 unrecognized tax benefit noted above. During the year 2007 we recognized $22,000 in potential interest and penalties associated with uncertain tax positions. To the extent interest and penalties are not assessed with respect to uncertain tax positions, amounts accrued will be reduced and reflected as a reduction of the overall income tax provision.

The following table summarizes the changes in our liability for unrecognized tax benefits for the year ended December 31, 2007:

	Unrecognized
	Tax Benefits
Unrecognized tax benefit at January 1, 2007	$	357
Accrued interest expense		22
Release of closed tax year		(53	)
Unrecognized tax benefit at December 31, 2007	$	326

We have not paid any significant interest or penalties associated with our income taxes, but classify both interest expense and penalties as part of our income tax expense. We have no certainty as to when the unrecognized tax benefits will become due.

The Company files several state and foreign tax returns, many of which remain open for examination for five years.

NOTE 10 — BENEFIT PLANS

We have a 401(k) retirement savings plan. Employees are eligible to defer portions of their salaries, limited by Internal Revenue Service regulations. The Company is subject to the 3% safe harbor rule and contributed $115,000 in 2007. Discretionary employer matches are determined annually by the board of directors and such discretionary matches amounted to $112,500 in 2007, $74,000 in 2006 and $52,000 in 2005.

NOTE 11 — STOCK COMPENSATION PLANS

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

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

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

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

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

F-28

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

A summary of stock option transactions is as follows:

	2007					2006					2005
				Weighted					Weighted					Weighted
				Average					Average					Average
				Exercise					Exercise					Exercise
	Shares			Price		Shares			Price		Shares			Price
Outstanding at January 1		673,870		$	5.13		858,940		$	5.07		1,346,690		$	4.91
Granted		—			—		—			—		20,000			16.90
Exercised		(320,700	)		5.06		(175,070	)		4.95		(492,750	)		5.18
Forfeited		(15,000	)		13.18		(10,000	)		3.10		(15,000	)		3.10
Outstanding at December 31		338,170			4.85		673,870			5.13		858,940			5.07
Exercisable at December 31		334,837			4.73		660,536			4.90		827,274			5.27

The intrinsic value of the options exercised in 2007 was $5.3 million. For the year ended December 31, 2007, 2006 and 2005 we received cash from stock option exercises of $1.6 million $866,000 and $2.6 million, respectively and the Company recognized a tax benefit related to exercises of stock options of $0 in 2007, $293,000 in 2006 and $2.5 million in 2005. During 2007, 3,334 shares vested having a fair value on the date of vesting of approximately $45,380. As of December 31, 2007, the total compensation cost related to nonvested stock options not yet recognized is approximately $18,685. This amount will be recognized as compensation expense over the next 5 months.

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

					Weighted-
					Average		Weighted-
					Exercise		Average
Year		Option Type	Shares		Price		Fair Value
	2005	Exercise price equal to market price		20,000	$	16.90	$	7.31

F-29

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table summarizes information about the fixed price stock options outstanding at December 31, 2007:

											Weighted Average
	Number Outstanding					Number Exercisable					Remaining
			Intrinsic					Intrinsic			Contractual
Exercise Price	Shares		Value			Shares		Value			Life in Years
			(In thousands)					(In thousands)
$ 2.75		45,000	$	191			45,000	$	191			0.73
3.00		5,000		20			5,000		20			1.42
3.10		60,000		233			60,000		233			4.69
3.12		4,420		17			4,420		17			2.72
3.88		5,000		16			5,000		16			1.83
4.12		50,000		144			50,000		144			4.05
4.51		20,000		50			20,000		50			4.13
4.96		30,000		61			30,000		61			6.39
5.50		86,250		129			86,250		129			5.91
5.95		15,000		16			15,000		16			3.38
13.75		7,500		(51	)		7,500		(51	)		6.88
16.90		10,000		(99	)		6,667		(66	)		7.39
		338,170	$	727			334,837	$	760			4.13

At December 31, 2007, there were 120,208, remaining shares available for grant under the plans collectively.

In May 2005, stockholders approved the Toreador Resources Corporation 2005 Long-Term Incentive Plan (the “Plan”). The Plan, as amended, authorizes the issuance of up to 750,000 shares of the Company’s common stock to key employees, key consultants and outside directors of the Company. The Board of Directors has authorized a total of 328,385 shares of restricted stock be granted to employees and non-employee directors. The compensation cost is measured by the difference between the quoted market price of the stock at the date of grant and the price, if any, to be paid by an employee and is recognized as expense over the period the recipient performs related services. The restricted stock grants vest over a one to four year period depending on the grant and the average price of the stock on the date of the grants was $24.53 for the year ended December 31, 2007. Stock compensation expense of $3.9 million and $2.7 million is included in the Statement of Operations for the years ended December 31, 2007 and 2006, which represents the cost recognized from the date of the grants through December 31, 2007 and 2006. During 2007, 168,633 shares vested having a fair value of approximately $3.4 million on the date of vesting. As of December 31, 2007, the total compensation cost related to nonvested restricted stock grants not yet recognized is approximately $4.1 million. This amount will be recognized as compensation expense over the next 29 months.

In January 2007, 55,900 shares of restricted stock grants awarded to the former President and CEO, were immediately vested and resulted in an expense of $1.1 million.

For the years ended December 31, 2007 and 2006 we recognized a current tax benefit related to restricted stock grants of approximately $0 and $362,000 and a deferred tax benefit of approximately $1.3 million and $561,000, respectively.

F-30

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table summarizes the changes in outstanding restricted stock grants along with their related grant-date fair values for the year ended December 31, 2007:

				Weighted Average
				Grant-Date
	Shares			Fair Value
Non-vested at January 1, 2007		287,920		$	26.63
Shares granted		141,895			24.53
Shares vested		(168,633	)		26.07
Shares forfeited		(38,583	)		26.04
Non-vested at December 31, 2007		222,599		$	25.91

NOTE 12 — COMMITMENTS AND CONTINGENCIES

We lease our office space under non-cancelable operating leases, expiring during 2008 through 2014. We also subleased portions of the leased space to one related party and two unrelated parties under non-cancelable sub-leases which expired on June 30, 2006. The following is a schedule of minimum future rentals under our non-cancelable operating leases as of December 31, 2007 (in thousands):

2008	$	795
2009		553
2010		568
2011		574
2012		578
Thereafter		1,042
	$	4,110

Net rent expense totaled $828,590 in 2007, $699,000 in 2006 and $354,000 in 2005.

In conjunction with FIN 48, we have no certainty as to when the unrecognized tax benefits of $326,000 will become due.

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 claim is currently approximately 8.2 million Euros, valued at $12.7 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 5.9 million Euros, currently valued at $8.7 million, paid to Micoperi under the contract between us, our co-venturers and Micoperi. Micoperi has made a cross-claim for about 5.1 million Euros, currently valued at $7.5 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 5.9 million Euros, currently valued at $8.7 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 are accounting for the potential receivable from Micoperi as a gain contingency. Accordingly, the potential gain has not been recorded.

David M. Drewer.  On March 12, 2008, we agreed in principle to make a payment of $97,500 to the J&D Madison Foundation, a private charitable foundation managed by David Brewer, one of our directors, in settlement

F-31

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

of claims he made against the Company arising from an alleged prior agreement by G. Thomas Graves III, the former President and Chief Executive Officer, to pay him $150,000 per year for three years as a consulting fee. We are working on finalizing a release agreement with Mr. Brewer. In 2007, Mr. Brewer brought to the attention of the Company correspondence from Mr. Graves in which, on behalf of the Company, Mr. Graves had promised to provide Mr. Brewer with certain consulting payments that had been previously agreed to by Mr. Graves in connection with the acquisition of Madison Oil Company, but never paid. In this letter, Mr. Graves stated that there was an oral, binding commitment of the Company to pay these amounts to Mr. Brewer. Mr. Brewer presented the letter to the Company and requested payments pursuant to this correspondence. Upon receiving a copy of this correspondence, certain members of the Board of Directors discussed with Mr. Brewer the facts giving rise to this request for payments and asked certain members of the Audit Committee of the Company to review this matter further, whereupon these certain members of the Audit Committee hired special counsel to assist them in the review and provide them with advice. These members of the Audit Committee determined that there were questions regarding this commitment to pay (including a failure to obtain approval from the Board of Directors for any such payment) and there were valid reasons not to pay these amounts to Mr. Brewer. Subsequently, on February 11, 2008, counsel to Mr. Brewer sent a demand letter to the Company requesting payment of these amounts. The Board of Directors discussed this matter and determined that it was in the best interests of the Company and its stockholders to compromise and settle this matter with Mr. Brewer, whereupon the settlement amount was agreed to in exchange for a release by Mr. Brewer of all claims against the Company and for him stepping down as Chairman of the Nominating and Corporate Governance Committee. In connection with this settlement, the Company does not admit that these amounts are owing or that Mr. Brewer has a valid claim for these consulting fees. Mr. Brewer and his father, both of whom are directors, did not participate in the Board of Directors approval of this settlement. Mr. Brewer has indicated that these funds will be distributed by the foundation for educational, medical research or social welfare purposes.

From time to time, we are named as a defendant in other legal proceedings arising in the normal course of business. In our opinion, the final judgment or settlement, if any, which may be awarded with any suit or claim would not have a material adverse effect on our financial position.

NOTE 13 — RELATED PARTY TRANSACTIONS

William I. Lee (deceased), was a former director of the Company and the majority owner of Wilco Properties, Inc (“Wilco”). The Company subleased office space to Wilco pursuant to a sub-lease agreement that expired on July 1, 2007. We recorded reductions to rent expense totaling $25,000 in 2007, $50,000 in 2006 and $48,000 in 2005 related to the sublease with Wilco. We had an informal agreement with Wilco under which one of the two companies incurred, on behalf of the other, certain miscellaneous expenses that are subsequently reimbursed by the other company. We had amounts receivable related to this arrangement of zero, zero and $146 at December 31, 2007, 2006 and 2005, respectively.

On November 1, 2002, pursuant to a private placement we issued $925,000 ofSeries A-1 Convertible Preferred Stock to certain of our directors or entities controlled by certain of our directors. In connection with the securities purchase agreements, Toreador entered into a registration rights agreement effective November 1, 2002, among Toreador and the purchasers which provided for the registration of the common stock issuable upon conversion of theSeries A-1 Convertible Preferred Stock. During 2003, pursuant to private placements we issued 41,000 shares of ourSeries A-1 Convertible Preferred Stock for the total amount of $1,025,000 to William I. Lee and Wilco as follows: (i) in October 2003, 34,000 shares were issued to William I. Lee and Wilco, an entity controlled by Mr. Lee; and (ii) in December 2003, 7,000 shares were issued to Wilco. TheSeries A-1 Convertible Preferred Stock was governed by a certificate of designation. TheSeries A-1 Convertible Preferred Stock was sold for a face value of $25.00 per share, and paid an annual cash dividend of $2.25 per share that result in an annual yield of 9.0%. At the option of the holder, theSeries A-1 Convertible Preferred Stock could be converted into common shares at a price of $4.00 per common share. The $4.00 conversion price was higher than the market price of our common stock at the time of issuances. TheSeries A-1 Convertible Preferred Stock was redeemable at our option, in whole or in part, at

F-32

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

any time on or after November 1, 2007. The optional redemption price per share was the sum of (1) $25.00 per share of theSeries A-1 Convertible Preferred Stock plus (2) any accrued unpaid dividends, and such sum is multiplied by a declining multiplier. The multiplier was 105% until October 31, 2008, 104% until October 31, 2009, 103% until October 31, 2010, 102% until October 31, 2011, 101% until October 31, 2012, and 100% thereafter. In connection with the securities purchase agreements entered into with William I. Lee and Wilco, Toreador granted certain “piggy-back” registration rights relating to the common stock issuable upon conversion of theSeries A-1 Convertible Preferred Stock. The sale of theSeries A-1 Convertible Preferred Stock was effected in reliance upon the exemption from securities registration afforded by the provisions of Section 4(2) of the Securities Act of 1933, as amended, and Regulation D as promulgated by the Securities and Exchange Commission under the Securities Act of 1933, as amended. In December 2007, all theSeries A-1 Convertible Preferred Stock was converted into common shares.

NOTE 14 — DISCONTINUED OPERATIONS

On June 14, 2007, the Board of Directors authorized management to sell all oil and gas properties in the United States. The sale of these properties completed the divestiture of the company’s non-core domestic assets and allows us to focus exclusively on our international operations. The sale was closed on September 1, 2007. The sales price was $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 captions “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 table below compares discontinued operations for the year ended December 31, 2007, 2006 and 2005:

	Year Ended December 31,
	2007			2006			2005
Revenue:
Oil and natural gas sales	$	4,489		$	7,070		$	7,767
Operating costs and expenses:
Lease operating expense		1,592			2,200			2,096
Exploration expense		105			—			—
Depreciation, depletion and amortization		611			1,265			950
Dry hole expense		103			1,393			—
Impairment		—			345			109
General and administrative expense		325			324			266
Gain on sale of properties and other assets		(9,244	)		(202	)		(12	)
Total operating costs and expenses		(6,508	)		5,325			3,409
Operating income		10,997			1,745			4,358
Income tax provision		(3,952	)		(642	)		(1,596	)
Income from discontinued operations	$	7,045		$	1,103		$	2,762

NOTE 15 — INFORMATION ABOUT OIL AND NATURAL GAS PRODUCING ACTIVITIES AND OPERATING SEGMENTS

We have operations in only one industry segment, the oil and natural gas exploration and production industry. We are structured along geographic operating segments or regions. As a result, we have reportable operations in the United States (Corporate Headquarters), Western Europe (France) and Eastern Europe (Hungary, Romania and

F-33

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Turkey). Geographic operating segment income tax expenses have been determined based on statutory rates existing in the various tax jurisdictions where we have oil and natural gas producing activities.

We allocate a portion of certain United States based employees salaries to our foreign subsidiaries. The amount allocated is based on an estimate of the time that employee has spent working on that on that subsidiary. We periodically review these percentages to make sure that our assumptions are valid.

The following tables provide the geographic operating segment data required by Statement of Financial Accounting Standards No. 131, “Disclosure about Segments of an Enterprise and Related Information”. The United States segment data for the years ended December 31, 2007, 2006, and 2005 has been adjusted to reflect the sale of oil and natural gas properties in the United States as of September 1, 2007 (see Note 15).

	United
	States			France			Turkey			Hungary			Romania			Total
							(In thousands)
For the year ended December 31, 2007
Revenues:
Oil and natural gas sales	$	34		$	25,873		$	11,857		$	—		$	3,927		$	41,691
Costs and expenses:
Lease operating		—			7,344			2,644			—			2,656			12,644
Exploration expense		2,668			855			2,568			2,224			6,427			14,742
Depreciation, depletion and amortization		265			4,137			10,088			65			6,702			21,257
Dry hole cost		—			3,847			4,500			3,484			10,009			21,840
Impairment of oil and gas properties		—			—			—			—			13,446			13,446
General and administrative		9,675			2,832			3,727			543			536			17,313
(Gain) loss on sale of properties and other assets		(3,155	)		—			(4	)		—			—			(3,159	)
Loss on sale of futures contracts		1,005			—			—			—			—			1,005
Total costs and expenses		10,458			19,015			23,523			6,316			39,776			99,088
Operating income (loss)		(10,424	)		6,858			(11,666	)		(6,316	)		(35,849	)		(57,397	)
Other income (expense)		(1,914	)		(470	)		(23,495	)		(2,562	)		(304	)		(28,745	)
Income (loss) before income taxes		(12,338	)		6,388			(35,161	)		(8,878	)		(36,153	)		(86,142	)
Benefit (provision) for income taxes		3,692			(2,290	)		3,274			—			—			4,676
Income (loss) from continuing operations, net of tax	$	(8,646	)	$	4,098		$	(31,887	)	$	(8,878	)	$	(36,153	)	$	(81,466	)
Selected assets:
Properties and equipment	$	3,905		$	115,666		$	185,844		$	15,968		$	24,082		$	345,465
Accumulated depreciation, depletion, and amortization		(928	)		(37,660	)		(12,342	)		(376	)		(22,208	)		(73,514	)
Oil and natural gas properties, net	$	2,977		$	78,006		$	173,502		$	15,592		$	1,874		$	271,951
Goodwill	$	—		$	4,059		$	883		$	—		$	—		$	4,942
Total assets	$	298,949		$	83,683		$	31,417		$	693		$	(29,271	)	$	385,471
Expenditures for additions to long-lived assets:
Property acquisition costs	$	—		$	—		$	—		$	—		$	—		$	—
Development costs		—			—			59,086			1,672			2,381			63,139
Exploration costs		—			3,847			4,500			3,484			10,009			21,840
Other		398			—			36			—			115			549
Total expenditures for long-lived assets	$	398		$	3,847		$	63,622		$	5,156		$	12,505		$	85,528

F-34

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	United
	States			France			Turkey			Hungary			Romania			Total
							(In thousands)
For the year ended December 31, 2006
Revenues:
Oil and natural gas sales	$	20		$	27,274		$	3,834		$	—		$	2,200		$	33,328
Costs and expenses:
Lease operating		—			7,229			793			—			719			8,741
Exploration expense		1,883			432			799			184			648			3,946
Depreciation, depletion and amortization		264			3,119			748			59			2,089			6,279
Dry hole cost		—			—			—			1,706			—			1,706
General and administrative		5,720			1,905			807			516			557			9,505
(Gain) loss on sale of properties and other assets		—			—			(436	)		—			—			(436	)
Total costs and expenses		7,867			12,685			2,711			2,465			4,013			29,741
Operating income (loss)		(7,847	)		14,589			1,123			(2,465	)		(1,813	)		3,587
Other income (expense)		3,186			187			(1,055	)		(1,484	)		59			893
Income (loss) before income taxes		(4,661	)		14,776			68			(3,949	)		(1,754	)		4,480
Benefit (provision) for income taxes		1,020			(4,256	)		231			—			—			(3,005	)
Income (loss) from continuing operations, net of tax	$	(3,641	)	$	10,520		$	299		$	(3,949	)	$	(1,754	)	$	1,475
Selected assets:
Oil and natural gas properties	$	3,620		$	99,751		$	137,499		$	15,334		$	21,840		$	278,044
Accumulated depreciation, depletion, and amortization		(1,271	)		(30,439	)		(2,893	)		(283	)		(2,059	)		(36,945	)
Oil and natural gas properties, net	$	2,349		$	69,312		$	134,606		$	15,051		$	19,781		$	241,099
Investments in unconsolidated entities	$	2,659		$	—		$	—		$	—		$	—		$	2,659
Goodwill	$	—		$	3,632		$	919		$	—		$	—		$	4,551
Total assets	$	251,422		$	80,574		$	35,209		$	7,745		$	4,638		$	379,588
Expenditures for additions to long-lived assets:
Development costs	$	—		$	15,931		$	86,222		$	1,759		$	6,943		$	110,855
Exploration costs		—			—			—			6,249			7,320			13,569
Other		283			127			228			83			111			832
Total expenditures for long-lived assets	$	283		$	16,058		$	86,450		$	8,091		$	14,374		$	125,256

F-35

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	United
	States			France			Turkey			Hungary			Romania			Total
							(In thousands)
For the year ended December 31, 2005
Revenues:
Oil and natural gas sales	$	22		$	20,572		$	2,817		$	—		$	—		$	23,411
Costs and expenses:
Lease operating		—			5,392			710			—			—			6,102
Exploration expense		1,250			1,011			289			237			153			2,940
Depreciation, depletion and amortization		235			3,513			547			—			—			4,295
Dry hole cost		—			—			1,738			—			—			1,738
General and administrative		4,955			941			468			20			45			6,429
Total costs and expenses		6,440			10,857			3,752			257			198			21,504
Operating income (loss)		(6,418	)		9,715			(935	)		(257	)		(198	)		1,907
Other income (expense)		383			(347	)		2,873			(33	)		1,139			4,015
Income (loss) before income taxes		(6,035	)		9,368			1,938			(290	)		941			5,922
Benefit (provision) for income taxes		2,588			77			(754	)		—			—			1,911
Income (loss) from continuing operations, net of tax	$	(3,447	)	$	9,445		$	1,184		$	(290	)	$	941		$	7,833
Selected assets:
Oil and natural gas properties	$	3,389		$	83,627		$	51,724		$	9,728		$	7,431		$	155,899
Accumulated depreciation, depletion, and amortization		(1,056	)		(24,992	)		(2,146	)		(225	)		—			(28,419	)
Oil and natural gas properties, net	$	2,333		$	58,635		$	49,578		$	9,503		$	7,431		$	127,480
Investments in unconsolidated entities	$	2,251		$	—		$	—		$	—		$	—		$	2,251
Goodwill	$	—		$	3,276		$	919		$	—		$	—		$	4,195
Total assets	$	244,783		$	57,221		$	11,853		$	541		$	1,328		$	315,726
Expenditures for additions to long-lived assets:
Property acquisition costs	$	—		$	—		$	—		$	9,096		$	—		$	9,096
Development costs		—			19,065			27,900			—			7,114			54,079
Other		192			111			236			279			—			818
Total expenditures for long-lived assets	$	192		$	19,176		$	28,136		$	9,375		$	7,114		$	63,993

(1) Amounts reflect reclassifications to discontinued operations.

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

	December 31,
	2007			2006
	(In thousands)
Total assets for reportable segments	$	385,471		$	379,588
Elimination of intersegment receivables and investments		(62,360	)		(62,384	)
Total consolidated assets	$	323,111		$	317,204

F-36

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

NOTE 16 — Subsequent Event

On February 20, 2008 we entered into the following commodity derivative contracts with Total Oil Trading SA:

Type	Period	Barrels		Floor		Ceiling
Collar	April 1 – 30, 2008		16,000	$	92.25	$	100.25
Collar	May 1 – 31, 2008		16,000	$	92.25	$	100.25
Collar	June 1 – 30, 2008		16,000	$	92.25	$	100.25
Collar	July 1 – 31, 2008		16,000	$	91.75	$	99.75
Collar	August 1 – 31, 2008		16,000	$	91.75	$	99.75
Collar	September 1 – 30, 2008		16,000	$	91.75	$	99.75

NOTE 17 — SUPPLEMENTAL OIL AND NATURAL GAS RESERVES AND STANDARDIZED MEASURE INFORMATION (UNAUDITED)

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

F-37

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

	France			Turkey			Romania			Hungary			Total
				Natural Gas (MMcf)
PROVED RESERVES
December 31, 2004		—			—			—			—			—
Revisions of previous estimates		—			—			—			—			—
Extensions, discoveries and other additions		—			6,476			3,486			—			9,962
Sale of reserves		—			—			—			—			—
Production		—			—			—			—			—
December 31, 2005		—			6,476			3,486			—			9,962
Revisions of previous estimates		—			(1,151	)		(1,185	)		—			(2,336	)
Extensions, discoveries and other additions		—			16,099			1,186			950			18,235
Sale of reserves		—			—			—			—			—
Production		—			—			(446	)		—			(446	)
December 31, 2006		—			21,424			3,041			950			25,415
Revisions of previous estimates		—			(8,215	)		(1,671	)		(950	)		(10,836	)
Extensions, discoveries and other additions		—			741			—			—			741
Sale of reserves		—			—			—			—			—
Production		—			(1,011	)		(598	)		—			(1,609	)
December 31, 2007		—			12,939			772			—			13,711
PROVED DEVELOPED
December 31, 2005		—			—			3,486			—			3,486
December 31, 2006		—			—			3,040			950			3,990
December 31, 2007		—			4,248			772			—			5,020
	Oil (MBbls)
PROVED RESERVES
December 31, 2004		11,536			627			—			—			12,163
Revisions of previous estimates		(587	)		77			—			—			(510	)
Extensions, discoveries and other additions		477			—			24			—			501
Sale of reserves		—			—			—			—			—
Production		(448	)		(65	)		—			—			(513	)
December 31, 2005		10,978			639			24			—			11,641
Revisions of previous estimates		(906	)		95			4			—			(807	)
Extensions, discoveries and other additions		—			—			19			1			20
Sale of reserves		—			—			—			—			—
Production		(444	)		(69	)		(6	)		—			(519	)
December 31, 2006		9,628			665			41			1			10,335
Revisions of previous estimates		661			481			(27	)		(1	)		1,114
Extensions, discoveries and other additions		39			—			—			—			39
Sale of reserves		—			(30	)		—			—			(30	)
Production		(360	)		(67	)		(8	)		—			(435	)
December 31, 2007		9,968			1,049			6			—			11,023
PROVED DEVELOPED
December 31, 2005		7,688			378			24			—			8,090
December 31, 2006		6,770			405			41			1			7,217
December 31, 2007		7,170			808			6			—			7,984

F-38

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

The prices of oil and natural gas at December 31, 2007, 2006, and 2005 used in the table shown below, were $95.72, $57.75 and $56.24 per Bbl of oil, respectively, and $8.91, $6.98 and $5.99 per Mcf of natural gas, respectively

	France		Turkey		Romania			Hungary		Total
	(In thousands)
As of and for the year ended December 31, 2005
Future cash inflows	$	621,765	$	70,498	$	18,574		$	—	$	710,837
Future production costs		223,273		15,267		4,588			—		243,128
Future development costs		30,883		22,317		552			—		53,752
Future income tax expense		113,742		2,736		961			—		117,439
Future net cash flows		253,867		30,178		12,473			—		296,518
10% annual discount for estimated timing of cash flows		144,738		14,390		1,798			—		160,926
Standardized measure of discounted future net cash flows related to proved reserves	$	109,129	$	15,788	$	10,675		$	—	$	135,592
As of and for the year ended December 31, 2006
Future cash inflows	$	551,139	$	185,815	$	21,163		$	5,732	$	763,849
Future production costs		214,474		20,407		5,198			1,658		241,737
Future development costs		33,580		20,757		159			800		55,296
Future income tax expense		95,067		7,114		(602	)		2,057		103,636
Future net cash flows		208,018		137,537		16,408			1,217		363,180
10% annual discount for estimated timing of cash flows		121,828		53,207		3,019			248		178,302
Standardized measure of discounted future net cash flows related to proved reserves	$	86,190	$	84,330	$	13,389		$	970	$	184,877
As of and for the year ended December 31, 2007
Future cash inflows	$	963,444	$	209,405	$	4,495		$	—	$	1,177,344
Future production costs		305,939		29,759		3,202			—		338,900
Future development costs		32,221		22,272		95			—		54,588
Future income tax expense		200,094		6,597		—			—		206,691
Future net cash flows		425,190		150,777		1,198			—		577,165
10% annual discount for estimated timing of cash flows		250,979		66,729		88			—		317,796
Standardized measure of discounted future net cash flows related to proved reserves	$	174,211	$	84,048	$	1,110		$	—	$	259,369

F-39

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

	France			Turkey			Romania			Hungary			Total
	(In thousands)
Balance at December 31, 2004		54,600			8,226			—			—			62,826
Sales of oil and natural gas, net		(15,180	)		(2,107	)		—			—			(17,287	)
Net changes in prices and production costs		72,285			3,463			—			—			75,748
Net change in development costs		(2,223	)		(11,356	)		(472	)		—			(14,051	)
Extensions and discoveries		7,723			18,906			11,963			—			38,592
Revisions of previous quantity estimates		(9,507	)		1,347			—			—			(8,160	)
Previously estimated development costs incurred		—			—			—			—			—
Net change in income taxes		(22,271	)		(2,422	)		814			—			(23,879	)
Accretion of discount		8,187			815			—			—			9,002
Other		15,515			(1,084	)		(1,630	)		—			12,801
Balance at December 31, 2005		109,129			15,788			10,675			—			135,592
Sales of oil and natural gas, net		(20,201	)		(3,041	)		(1,481	)		—			(24,723	)
Net changes in prices and production costs		(6,102	)		7,074			2,987						3,959
Net change in development costs		(2,101	)		970			(130	)		(641	)		(1,902	)
Extensions and discoveries		—			65,127			5,159			3,267			73,553
Revisions of previous quantity estimates		(13,781	)		(2,355	)		(4,617	)		—			(20,753	)
Previously estimated development costs incurred		(2,132	)		—			(552	)		—			(2,684	)
Net change in income taxes		9,312			(3,445	)		1,262			(1,656	)		5,473
Accretion of discount		13,570			1,679			989			—			16,238
Other		(1,504	)		2,533			(905	)		—			124
Balance at December 31, 2006		86,190			84,330			13,387			970			184,877
Sales of oil and natural gas, net		(18,529	)		(9,213	)		(1,271	)		—			(29,013	)
Net changes in prices and production costs		120,639			38,613			(7,953	)		—			151,299
Net change in development costs		(266	)		(5,701	)		59			641			(5,267	)
Extensions and discoveries		1,076			3,930			—			—			5,006
Revisions of previous quantity estimates		18,303			(28,262	)		(2,726	)		(3,267	)		(15,952	)
Previously estimated development costs incurred		(1,992	)		(8,523	)		—			—			(10,515	)
Net change in income taxes		(42,760	)		257			448			1,656			(40,399	)
Accretion of discount		11,871			8,492			(841	)		—			19,522
Sale of reserves		—			(967	)		—			—			(967	)
Other		(321	)		1,092			7			—			778
Balance at December 31, 2007	$	174,211		$	84,048		$	1,110		$	—		$	259,369

F-40