TOREADOR RESOURCES CORP - FORM 10-K/A

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EX-31.2 - EXHIBIT 31.2 - TOREADOR RESOURCES CORP	a6671959ex31_2.htm
EX-32.1 - EXHIBIT 32.1 - TOREADOR RESOURCES CORP	a6671959ex32_1.htm
EX-31.1 - EXHIBIT 31.1 - TOREADOR RESOURCES CORP	a6671959ex31_1.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K/A

(Amendment No. 1)

þ	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
	ACT OF 1934

	For the fiscal year ended: December 31, 2010

o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
	EXCHANGE ACT OF 1934

Commission file number 001-34216

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)

c/o Toreador Holding SAS

9 rue Scribe

75009 Paris, France

(Address of principal executive office)

Registrant's telephone number, including area code: + 33 1 47 03 34 24

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 Professional Segment NYSE Euronext Paris

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 x

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 x

Indicate by check mark whether the Registrant (i) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the past 12 months (or for such shorter period that the Registrant was required to file such reports), and (ii) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or infomration statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definition 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 x

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 in Rule 12b-2 of the Exchange Act). Yes o No x

The aggregate market value of the voting and non-voting common equity of the registrant held by non-affiliates, computed by reference to the closing sales price of such stock, as of June 30, 2010 was $133,045,049. (For purposes of determination of the aggregate market value, only directors, executive officers and 10% or greater stockholders have been deemed affiliates.)

As of March 11, 2011, there were 25,942,705 shares of common stock, par value $.15625 per share, outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant's Proxy Statement for the 2011 Annual Meeting of Stockholders, expected to be filed on or before April 30, 2011, are incorporated by reference into Part III of this Form 10-K.

TABLE OF CONTENTS


		Page
PART I
Item 1 and 2.	Business and Properties		1
Item 1A.	Risk Factors		19
Item 1B.	Unresolved Staff Comments		32
Item 2.	Properties (see Item 1. Business and Properties)		32
Item 3.	Legal Proceedings		34
Item 4.	Reserved
PART II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer
	Purchases of Equity Securities		35
Item 6.	Selected Financial Data		36
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of
	Operations		39
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		67
Item 8.	Financial Statements and Supplementary Data		67
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial
	Disclosure		68
Item 9A.	Controls and Procedures		69
Item 9B.	Other Information		69
PART III
Item 10.	Directors, Executive Officers and Corporate Governance		69
Item 11.	Executive Compensation		69
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related
	Stockholder Matters		70
Item 13.	Certain Relationships and Related Transactions and Director Independence		70
Item 14.	Principal Accountant Fees and Services		70
PART IV
Item 15.	Exhibits and Financial Statement Schedules		71
SIGNATURES			72

EXPLANATORY NOTE

We are filing this Amendment No. 1 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2010, as filed with the U.S. Securities and Exchange Commission on March 16, 2011, to correct certain inadvertent omissions of Items 9B, 10 and 11 we discovered in our original filing. In order to ensure that the filing is complete and there are no other omissions, we are refiling the Form 10-K for the fiscal year ended December 31, 2010 in full.

We also have provided current certifications from our Chief Executive Officer (principal executive officer) and Chief Financial Officer (principal financial and accounting officer), as required by Rule 13a-14(a) or Rule 15d-14(a), as adopted under Section 302 of the Sarbanes-Oxley Act of 2002, and Section 1350 of Title 18 of the United States Code, as adopted under Section 906 of the Sarbanes-Oxley Act of 2002.

Other than the changes referred to above, all other infomraiton included in our Annual Report on Form 10-K/A for the fiscal year ended December 31, 2010 remains unchanged. This Amendment No. 1 does not reflect events occuring after the filing of our Form 10-K and does not modify or update the disclosures therein in anyway other than to reflect the amendments as described above and of forth below.

PART I

Items 1 and 2. Business and Properties

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.

Toreador Resources Corporation (together with its direct and indirect subsidiaries, "Toreador," "we," "us," "our," or the "Company"), is an independent energy company engaged in the exploration and production of crude oil with interests in developed and undeveloped oil properties in the Paris Basin, France. We are currently focused on the development of our conventional fields and the exploitation of the prospective shale oil play within our Paris Basin acreage position.

We currently operate solely in the Paris Basin, which covers approximately 170,000 km2 of northeastern France, centered 50 to 100 km east and south of Paris. At December 31, 2010, we held interests in approximately 997,000 gross exploration acres (awarded and pending publication). According to Gaffney, Cline & Associates Ltd, an independent petroleum and geological engineering firm, or Gaffney Cline, as of December 31, 2010, our proved reserves were 5.5 MBbls, our proved plus probable reserves were 9.1 MBbls and our proved plus probable plus possible reserves were 13.9 MBbls. Our production for 2010 averaged approximately 885 bbl/d from two conventional oilfield areas in the Paris Basin — the Neocomian Complex and Charmottes fields. As of December 31, 2010, production from these oil fields represented a majority of our total revenue and substantially all of our sales and other operating revenue. We intend to maintain production from these mature assets using suitable enhanced oil recovery techniques. In addition to this production base, we have identified several additional conventional exploration targets, including the La Garenne field, which is the first of these targets, and for which we intend to formulate a development plan.

We are also currently focused on exploiting our shale oil acreage in the Paris Basin. On May 10, 2010, our subsidiary, Toreador Energy France (“TEF”) entered into an investment agreement (the “Hess Investment Agreement”) with Hess Oil France S.A.S. (“Hess”) relating to exploitation of our shale oil acreage in the Paris Basin. Our current priority is to execute with Hess as our strategic partner a proof of concept program by drilling, completing and testing six or more exploration wells.

We are a Delaware corporation that was incorporated in 1951. Our common stock is traded on the NASDAQ Global Market under the trading symbol "TRGL" and on the Professional Segment of NYSE Euronext Paris under the trading symbol "TOR".

Our offices in the United States are located at 13760 Noel Road, Suite 1100, Dallas, TX, 75240-1383 (telephone number: (214) 559-3933). Our principal executive offices are located at c/o Toreador Holding SAS, 9 rue Scribe, 75009 Paris, France (telephone number: +33 1 47 03 34 24). Our website address is www.toreador.net.

Recent Developments

Dual Listing

On December 17, 2010, our common stock began trading on the Professional Segment of NYSE Euronext Paris (“Euronext”) under the trading symbol “TOR”. Our dual listing does not change our capital structure, share count or current NASDAQ listing and is intended to create additional liquidity for investors as well as provide greater access to our shares, which are denominated in Euros on Euronext, in Euro-zone markets and currencies.

Repurchase and Redemption of 5.00% Convertible Senior Notes

On October 1, 2010, we repurchased approximately $32.3 million aggregate principal amount of our 5.00% Convertible Senior Notes pursuant to the holders’ option, and, on November 24, 2010, redeemed the remaining $0.1 million aggregate principal amount outstanding. See “Liquidity - 5.00% Convertible Senior Notes due October 1, 2025.” Following such repurchase and redemption, our outstanding long-term debt consists of approximately $31.6 million aggregate principal amount of our 8.00%/7.00% Convertible Senior Notes.

Proof of Concept Program

On October 12, 2010, TEF and Hess received approval from the French government for its first four well permit applications, as well as the necessary environmental permits. On November 20, 2010, Hess executed an agreement for the provision of drilling and related services for the initial six firm wells targeting the Liassic shale oil source rock system. The first of the four wells, which will be located on the Chateau Thierry Permit, is expected to be drilled vertically to a total depth of 3,000 meters. The primary geologic target of the well is the Liassic section, the top of which is expected to be encountered at an approximate depth of 2,300 meters. Conventional cores are expected to be taken throughout the Liassic section to evaluate reservoir and rock properties.

On February 4, 2011, France’s Ministry of Environment and Ministry of Energy announced its intention to conduct a study on the economic, social and environmental stakes relating to the development of shale gas and shale oil in France (the “France Shale Study”). On February 10, 2011, Toreador and Hess met with representatives of the Ministry of Environment and the Ministry of Energy to discuss the impact the France Shale Study might have on its unconventional oil exploration, particularly the proof of concept program. Following such discussion, Toreador concluded that they will voluntarily delay such drilling pending the results of the France Shale Study and any interim or subsequent political developments. In the interim, Toreador intends to cooperate with the French government in conducting the France Shale Study, including by providing scientific data and practical experiences regarding oil development, hosting delegations to observe oil operations in the Paris Basin and initiating baseline environmental studies with third-party environmental experts that would be available to the French government.

On March 2, 2011 an additional study on the impact of shale gas and shale oil was launched by the French National Assembly (the “National Assembly Study”), the conclusions of which are expected to be published in June 2011 (at the same time as the final report relating to the France Shale Study). On March 11, 2011, the Prime Minister of France announced that the moratorium on unconventional exploration has been extended to exploration permits and works authorizations until mid-June 2011 (originally mid-April), i.e. when the conclusions of the studies on the environmental impact of drilling techniques will have been rendered. The Company does not currently know the impact of such decision on its proof of concept program. The Company is currently evaluating its drilling program in light of these developments and will continue to monitor further developments and adjust its plans as necessary.

Concessions Renewal

The decrees relating to the renewal of the Châteaurenard concession and of the Saint-Firmin-des-Bois concession, which together account for 93% of our existing reserves, received final French government approvals on February 1, 2011, and were published in the Journal Officiel on February 3, 2011. The renewals extend the expiry date of both concessions to January 1, 2036.

Strategy

The primary components of our strategy are:

Focus on France. All of our oil assets are currently located in France, having disposed of our interests in Turkey, Romania and Hungary in 2009. We believe we can leverage our substantial acreage position and our experience and industry relationships in France to grow the Company.

Capture, develop and accelerate conventional prospects. We have identified a number of conventional exploration targets, including the La Garenne field, which is the first of these targets, and for which we intend to formulate a development plan.

Target the prospective unconventional oil resource play. We intend to work with Hess on our proof of concept program and potential development of our Paris Basin shale oil acreage position.

Seize opportunities for external growth. We continue to evaluate and, where appropriate, intend to pursue acquisition opportunities on terms we consider favorable. In particular, we consider acquisitions of businesses or interests that will complement and allow us to expand our activities.

Continue to focus on operational costs. Since the beginning of 2009, we have improved operational efficiencies, and we continue to focus on maintaining efficient operations.

Maintain optimal capital structure. We intend to maintain a conservative capital structure over time.

Our Properties

Title to Oil Properties

Toreador does not hold title to any of its properties; we hold interests in permits or concessions granted by French governmental authorities granting us the right to explore and develop oil properties in France. We currently hold interests in approximately 780,000 gross exploration acres in the Paris Basin and have applications pending for approximately 217,000 additional gross acres. Our conventional exploration and production operations consist primarily of our existing producing fields. In addition to this production base, we have identified several additional conventional exploration targets, including the La Garenne field, which is the first of these targets, and for which we intend to formulate a development plan. Our unconventional exploration operations consist primarily of the potential exploration of the prospective shale oil play within our Paris Basin acreage position. We have ready access to existing infrastructure (pipelines) and end-markets (refineries) in the Paris Basin. The table below summarizes the acreage covered by the exploration permits and exploitation concessions we currently hold, or for which we have applied. For exploration permits, under the terms of the Hess Investment Agreement, TEF and Hess have designated an area of mutual interest within the Paris Basin (the “AMI”). If either party acquires or applies for a working interest in an exploration permit or exploitation concession within the AMI, such party would be required to offer to the other party 50% of such interest on the same terms and conditions. For a more detailed description of each permit, concession or application, see "Permits, Concessions and Pending Applications."

Permit Name		Working Interest			Type	Expiration Date	Gross Acreage
Charmottes			100	%	Production	October 24, 2013	9,019
Chateaurenard			100	%	Production	January 1, 2036	11,268
St. Firmin Des Bois			100	%	Production	January 1, 2036	3,973
						Total Production	24,260
Aufferville			50	%	Exploration	June 16, 2010*****	33,095
Rigny le Ferron			50	%	Exploration	February 20, 2011**	82,748
Joigny			50	%	Exploration	February 20, 2011**	33,152
Mairy			25	%	Exploration	August 15, 2011	109,705
Nogent sur Seine			50	%	Exploration	August 8, 2012	65,727
Leudon en Brie			50	%	Exploration	August 8, 2012	26,740
Nemours			25	%	Exploration	June 16, 2013	46,992
Courtenay			50	%	Exploration	October 1, 2013	76,276
Chateau Thierry			50	%	Exploration	October 24, 2014	192,468
Champrose			40	%	Exploration	October 21, 2015	113,396
						Total Exploration	780,299
Coulommiers			—		Pending publication		45,900	***
L'Ourcq			—		Pending publication		48,680	***
Mary sur Marne			—		Pending publication		30,815	***
Nangis			—		Pending publication		26,966	***
Nanteuil			—		Pending publication		48,680	***
Valence en Brie			—		Pending publication		16,015	***
						Total Pending	217,054
Chevry / Ozoir			—		Application		97,606	****
Coole			—		Application		207,818	****
Fere-en-Tardenois			—		Application		64,885	****
Leudon extension			—		Application		12,876	****
Maisoncelles			—		Application		49,626	****
Meaux			—		Application		155,175	****
Plaisir			—		Application		32,667	****
Rozay en Brie			—		Application		36,273	****
Sezanne			—		Application		214,890	****
						Total Applications	871,816
	TOTAL EXPLORATION (PERMITS AND APPLICATIONS)						1,869,168	(°)

Note: all numbers in the table are direct conversion from the surface estimates in square kilometers

** Renewal application pending.

*** No longer subject to competitive application but not yet formalized by publication in the Official Journal of the French Republic.

**** The application award process may result in Toreador and Hess receiving less than a 100% working interest in the pending applications or only part of the acreage represented by an application.

***** Renewal application filed.

(°) Assuming successful applications.

Conventional Exploration and Production

Producing Fields

Our production for 2010 was 323 mbbl, representing an average of approximately 885 bbl/d, from two areas for which we hold exploitation concessions: the Neocomian Complex and Charmottes fields (producing from the Dogger and Trias horizon). As of December 31, 2010, these fields represented 100% of our total proved reserves (5.5 MBbls).

All our production is currently sold to Total pursuant to an agreement signed with Elf Antar in 1996, as amended. Following an initial term expiring in 2002, the agreement automatically renews for one-year periods unless notice of termination is given at least six months in advance. The sale price is based on the monthly-average dated Brent price over the month of production, less a discount. In 2010, sales to Total, representing all of our oil production revenues, totalled $24.7 million.

La Garenne and Prospect Inventory

We began drilling on the La Garenne well on November 12, 2009. The well confirmed a five-meter reservoir within a 50-meter oil column in the target Dogger formation. Based on our continued evaluation of the well results, we believe the well confirms a porous and hydrocarbon-bearing reservoir with a localized low-permeability area at the crest of the structure. We completed production testing of the well in January 2010, and the results were inconclusive. The well flowed only limited quantities from one of its two horizons in the Dogger. We intend to formulate a development plan for La Garenne following a more detailed analysis. We expect that the vertical well we drilled will be used as a water disposal or an injection well in the development of this field.

We have identified several additional conventional prospects on our acreage.

Our ability to explore and develop these prospects may be subject to us obtaining additional funding.

Unconventional Exploration: Paris Basin Shale Oil

In addition to our conventional exploration and production, we are also currently focused on exploiting our shale oil acreage in the Paris Basis pursuant to the Hess Investment Agreement and pending the result of the France Shale Study and any interim or subsequent political developments. See “Recent Developments-Operations Update-Proof of Concept Program” above.

In accordance with the Hess Investment Agreement, Hess made a $15 million upfront payment (plus applicable VAT of $2.9 million) to TEF on June 10, 2010. In addition, subject to government approval, TEF has transferred 50% of its working interest in each permit to Hess. The Ministry of Industry, Energy, and Numeric Economy (Ministère de l’Industrie, de l'Energie, et de l’Énergie numérique) in France granted first-stage approval of these transfers on June 25, 2010. An application for the grant to Hess of title (together with TEF) to the permits has also been filed with the French government and is pending. Upon such approval, Hess would become title holder and have the right to become operator of record for those exploration permits.

Fiscal Terms and Infrastructure

Fiscal Terms

Toreador believes that the Paris Basin presents attractive and stable fiscal terms. Mineral rights in France belong to the French State, and production of hydrocarbons occurs under a concession regime. Holders of a concession or production license must pay the French tax authorities a royalty proportional to the value of the products extracted. This royalty is paid starting from production. The royalty regime distinguishes between “old production” and “new production” and is ring-fenced by production concession. Under the current French Mining Code, the royalty payable is progressive and depends on annual production levels, with royalty rates currently ranging between 0% (below 50,000 tonnes, i.e., 970 bbl/d) and 12% (above 300,000 tonnes, i.e., 5,820 bbl/d) for “new production”. “Old production” is subject to an 8% royalty (below 50,000 tonnes), increasing to 30% (above 300,000 tonnes, i.e., 5,820 bbl/d).

Local mining taxes, or RCDM (redevance communale et départementale des mines), are also payable to the applicable administrative French county and municipality on whose territory the oil is produced. This local tax is determined by multiplying production by a unit rate, which is set each year by the Ministry of the Environment and Energy. The local mining tax is payable in arrears (tax for the production of 2009 is payable in 2011), is ring-fenced by well, and the regime distinguishes between fields entered into production before and after January 1, 1992. For the year 2010 (payable in 2012), the level of tax has been set at €16.84 per ton of oil equivalent to approximately $3.00 per bbl based on an exchange rate of 0.769, for pre-1992 production and €5.36 per ton of oil produced for post-1992 production, equivalent to approximately $0.95 per bbl based on an exchange rate of 0.769. Both the royalties and local mining taxes described above generally apply only to onshore fields; there is a reduced rate for offshore fields located less than one nautical mile from the coast (Toreador does not currently hold any permits covering offshore fields). Each of the taxes is deductible when determining the profit subject to French corporate tax. We are not required to pay surface rental or fees.

Infrastructure

The Paris Basin is conveniently located to utilize existing French infrastructure. The Grandpuits refinery operated by Total is in the heart of the Paris Basin (approximately 30 miles south of the Chateau Thierry permit). Paris Basin crude oil production is currently approximately 11,000 bbl/d (as of December 31, 2010). Our current Paris Basin oil is trucked to the Grandpuits refinery operated by Total after being stored in on-site storage tanks. There is also a major pipeline operated by Lundin Petroleum from the Villeperdue field to the Grandpuits refinery, in which there is substantial free capacity.

Permits, Concessions and Pending Applications

Exploration Permits

We currently hold a 50% working interest in the following exploration permits: Rigny le Ferron, Chateau Thierry, Aufferville, Courtenay, Joigny, Nogent sur Seine, Leudon en Brie; a 25% working interest in the Nemours and Mairy exploration permits; and a 40% working interest in the Champrose exploration permit.

Under French mining law, an exploration permit (“permis exclusif de recherche”) gives the holder an exclusive right to explore and then produce hydrocarbons. Any area, offshore and onshore, which is not covered yet by such a permit may be subject to application at any time. An application for a permit, or a renewal of a permit, is awarded by ministerial order following an administrative consultation and a submission to the regulatory authorities. An exploration permit is initially granted for a period of up to five years and may be renewed twice for up to five years each time; however, except under exceptional circumstances, the area covered by the permit is reduced by half at the first renewal and by a quarter of the remaining area at the second renewal. The permit holder may designate the areas to remain after such reduction, and in any event, the area covered by a permit may not be reduced below 175 km2. The exploration permits have minimum financial requirements, and if such obligations are not met, the permits could be subject to forfeiture. The renewal of an exploration permit is generally granted, provided the holder has met all its obligations thereunder and has agreed to certain future financial commitments at least equal to the financial commitments made during the previous permit period, pro-rated by the duration of the renewal and the area remaining. In case the ministerial decision to renew an exploration permit has not been issued before the expiry date of the permit, the permit holder is entitled to keep on exploring within the perimeter authorized by the exploration permit until an express decision is issued by the minister in charge of energy.

Rigny le Ferron

We hold a 50% working interest in, and operate, the Rigny le Ferron permit, which covers approximately 82,748 acres. The existing seismic lines representing around 1,000 km2 were reprocessed and interpreted in 2008, following which several Dogger prospects were identified and mapped. Toreador began drilling on the La Garenne well on November 12, 2009. Toreador completed production testing of the well in January 2010, and the results were inconclusive. The well flowed only limited quantities from one of its two horizons in the Dogger. We intend to formulate a development plan for La Garenne following a more detailed analysis. The Rigny le Ferron permit expired in February 2011; however we filed a renewal application on this permit in August 2010, which is currently pending. Although no renewal decision has been issued before the expiry date of the Rigny le Ferron permit, under the current French Mining Code, such permit can still be operated until an express decision is issued by the minister with respect to its renewal.

Chateau Thierry

We hold a 50% working interest in, and operate, the Chateau Thierry permit, which covers approximately 192,468 acres. We transferred the remaining 50% working interest to Hess in accordance with the Hess Investment Agreement. The Chateau Thierry permit expires in 2014.

Aufferville

We hold a 50% working interest in, and operate, the Aufferville permit, which covers approximately 33,095 acres. We transferred the remaining 50% working interest to Hess in accordance with the Hess Investment Agreement. The Aufferville permit expired in June 2010; however we filed a renewal application on this permit in 2009.

Nemours

We hold a 25% working interest in the Nemours permit, which covers approximately 46,992 acres and is operated by Lundin Petroleum AB. We transferred 25% of our working interest in this permit to Hess in accordance with the Hess Investment Agreement. The Nemours permit expires in 2013.

Courtenay

We hold a 50% working interest in, and operate, the Courtenay permit, which covers approximately 76,276 acres located east of the Neocomian Complex. We transferred the remaining 50% working interest to Hess in accordance with the Hess Investment Agreement. The Courtenay permit expires in 2013.

Joigny

We hold a 50% working interest in, and operate, the Joigny permit, which covers approximately 33,152 acres. We transferred the remaining 50% working interest to Hess in accordance with the Hess Investment Agreement. Seismic interpretation is underway on the acreage to delineate prospects in the Portlandian limestone. The Joigny permit expired in February 2011; however, we filed a renewal application in August 2010 which is currently pending.

Malesherbes

The Malesherbes permit expired on March 30, 2010, and we did not request renewal of the permit.

Mairy

We currently hold a 25% working interest in, and operate, the Mairy permit, which covers approximately 109,705 acres. We transferred 25% of our working interest in this permit to Hess in accordance with the Hess Investment Agreement. In 2011, we intend to drill one well on the Mairy permit. The permit expires in August 2011; however, we filed a renewal application for this permit in February 2011, which is currently pending.

Nogent sur Seine

We hold a 50% working interest in, and operate, the Nogent sur Seine permit, which covers approximately 65,727 acres. We transferred the remaining 50% working interest to Hess in accordance with the Hess Investment Agreement. The Nogent sur Seine permit expires in 2012.

Leudon en Brie

We hold a 50% working interest in, and operate, the Leudon en Brie permit, which covers approximately 26,740 acres. We transferred the remaining 50% working interest to Hess in accordance with the Hess Investment Agreement. The Leudon en Brie permit expires in 2012.

Champrose

Following first-stage approval by the government in December 2010 of a farm-in agreement with Poros SAS and Hess, we currently hold a 40% working interest in the Champrose permit, which covers approximately 113,396 acres. The Champrose permit expires in 2015.

Exploitation Concessions

We currently hold two exploitation concessions covering two producing oil fields in the Paris Basin: the Neocomian Complex and Charmottes fields (Dogger and Trias). As of December 31, 2010, production from these oil fields represented majority of our total revenue and substantially all of our sales and other operating revenue.

		At December 31, 2010
Property	Permit Expiration Year	Total Proved Reserves (Mbbl)		Post-Expiration Proved Reserves (Mbbl)		Percent of Proved Reserves Post- Expiration
Neocomian Fields	2036		5,154		1,500		29.10	%
Charmottes Fields*	2013		369		22		5.96	%

* Reserve estimate for Charmottes field is based on an assumed renewal of the concession in 2013.

Under French mining law, hydrocarbons may only be developed once a concession has been granted. During the exploration permit period, the permit holder has the exclusive right to obtain an exploitation concession. An exploitation concession is granted by decree, after a public enquiry, a local administrative consultation and a submission to the regulatory authorities. The decree sets forth the concession's perimeter and duration, which cannot exceed 50 years. To be awarded an exploitation concession, the applicant must, among other things, prove that it has the appropriate technical and financial capabilities to perform the operations and comply with safety and environmental regulations. An exploitation concession may be extended several times, each time for no longer than 25 years. An application for a renewal must be submitted two years before the expiration of the concession. The French government is not obligated to renew an exploitation concession, and such renewal would be subject to our satisfaction of technical and financial capability requirements.

Holders of a concession or production license must pay the French government a royalty proportional to the value of the products extracted. This royalty generally applies only to onshore fields and is backdated when the concession is granted but paid as from the day of the first sale of the products extracted. It is deductible from the French corporate tax. Local mining taxes are also payable by the holder, and are determined by multiplying production by a unit rate, which is set each year by the regulatory authorities. These taxes also generally apply only to onshore fields; there is a reduced rate for offshore fields located less than one nautical mile from the coast (we do not currently hold any permits covering offshore fields). Mining taxes are deductible when determining profit subject to French corporate tax.

Neocomian Complex

We hold a 100% working interest in, and operate, the two concessions (Chateaurenard and St. Firmin Des Bois) covering the Neocomian Complex, which consist of a group of four smaller field units. As of December 31, 2010, the complex had 80 producing oil wells, and production was approximately 788 bbl/d. The Chateaurenard concession, which covers approximately 11,268 acres, and the St. Firmin Des Bois concession, which covers approximately 3,973 acres, were both renewed on February 1, 2011 and the renewal decrees published in the French Journal Officiel on February 3, 2011. The renewals extend the expiry date of both concessions to January 1, 2036.

Charmottes

We hold a 100% working interest in, and operate, the Charmottes concession, which consists of two oil fields at different horizons (Dogger and Trias). As of December 31, 2010, the fields had seven producing oil wells, and production was approximately 97 bbl/d. The Charmottes concession, which covers approximately 9,019 acres, expires in October 2013. We filed an application for renewal of the Charmottes concession in February 2011.

Applications Pending Official Publication

Below is a description of the exploration permits for which we have applied that are no longer subject to competition but for which official award is pending publication of the ministerial order.

Coulommiers

We have a pending application for the Coulommiers permit, which covers approximately 45,900 acres. This is an amended surface of the original Coulommiers application made in November 2009. We are currently awaiting publication of the ministerial order granting us the permit.

L'Ourcq

We filed an amended application in 2010 for the L'Ourcq permit, which covers approximately 48,680 acres. This permit is an amended surface of the original Fere-en-Tardenois application made in August 2009. We are currently awaiting publication of the ministerial order granting us the permit.

Mary sur Marne

We filed an application for the Mary sur Marne permit, which covers approximately 30,815 acres. This is an amended surface of the original Fere-en-Tardenois and Coulommiers applications. We are currently awaiting publication of the ministerial order granting us the permit.

Nangis

We filed an application in January 2009 for the Nangis permit, which covers approximately 26,966 acres. We are currently awaiting publication of the ministerial order granting us the permit.

Nanteuil

We filed an application for the Nanteuil permit, which covers approximately 48,680 acres. This permit is an amended surface of the original Fere-en-Tardenois application made in August 2009. We are currently awaiting publication of the decree granting us the permit.

Valence en Brie

We filed an application in January 2009 for the Valence en Brie permit, which covers approximately 16,015 acres. We are currently awaiting publication of the ministerial order granting us the permit.

Pending Applications

Below is a description of the exploration permits for which we have applied and are awaiting the results of the application process. The application award process may result in Toreador and Hess getting less than a 100% working interest in the pending applications or only part of that application depending on competition for all or part of the acreage. If the minister in charge of mines has not issued a decision with respect to the outcome of the permit application (or extension) within two years following the date of application, the granting of such a permit is deemed to be refused.

Plaisir

We filed an application in September 2008 (revised in December 2008) for the Plaisir permit, which covers approximately 32,667 acres.

Fere-en-Tardenois

We filed an application in August 2009 for the Fere-en-Tardenois permit, which, following certain amendment applications reflecting revised surfaces, now covers approximately 64,885 acres. We are still waiting the result of the application award process.

Rozay-en-Brie

We filed an application in June 2010 for the Rozay-en-Brie permit, jointly with Hess, which covers approximately 36,273 acres. We are still waiting the result of the application award process.

Meaux

We filed an application in June 2010 for the Meaux permit, jointly with Hess, which covers approximately 155,175 acres. We are still waiting the result of the application award process.

Chevry / Ozoir

In August 2010, we, together with Hess, entered into an agreement with Poros SAS to join their application for the Chevry/Ozoir permit, which they initially filed in December 2008, and which covers approximately 97,606 acres. We are still waiting the result of the application award process.

Maisoncelles

We filed an application in August 2010 for the Maisoncelles permit, jointly with Hess, which covers approximately 49,626 acres. We are still waiting the result of the application award process.

Sézanne

We filed an application in August 2010 for the Sezanne permit, jointly with Hess, which covers approximately 214,890 acres. We are still waiting the result of the application award process.

Leudon extension

We filed an application in October 2010 for an extension to our existing Leudon permit, jointly with Hess, which covers approximately 12,876 acres. We are still waiting the result of the application award process.

Coole

We filed an application in November 2010 for the Coole permit, jointly with Hess, which covers approximately 207,818 acres. We are still waiting the result of the application award process.

Oil Reserves

Summary of Oil Reserves as of December 31, 2010 and 2009

The following table sets forth information about our estimated net proved reserves, probable reserves and possible reserves at December 31, 2010 and 2009 for our properties in France. Gaffney, Cline & Associates Ltd, an independent petroleum engineering firm in the United Kingdom ("GCA"), audited our proved developed reserves, proved undeveloped reserves, probable reserves, possible reserves and discounted present value (pretax) as of December 31, 2010 and 2009. We prepared the estimate of standardized measure of proved reserves in accordance with FASB ASC 932, "Extractive Activities-Oil and Gas." No reserve reports have been provided to any governmental agencies.

	December 31,
	2010		2009
	(Mbbl)		(Mbbl)
Proved developed		5,111	5,383
Proved undeveloped		412	420
Total Proved		5,523	5,803
Probable		3,562	3,333
Possible		4,816	5,202

Our proved reserves at December 31, 2010 were 5.5 Mbbls. All of our proved reserves are located in the Paris Basin, France. The Neocomian Complex, one of our two producing assets, accounted for 93.32% of our proved reserves. The decrease of our proved reserves from 5.8 Mbbls in 2009 to 5.5 Mbbls in 2010 can be explained primarily a result of the production from these assets during 2010 (approximately 323 Mbbl) and was partially offset by an increase in oil prices used to calculate the reserves in 2009 and 2010 ($79.35 and $56.99, respectively).

Proved Reserves Disclosures

Recent SEC Rule-Making Activity. In December 2008, the Securities and Exchange Commission ("SEC") announced that it had adopted amendments designed to modernize the oil and gas company reserves reporting requirements. The most significant amendments to the requirements include the following:

●	replacement of the year-end price with the average prices over 12 months to calculate reserve estimates;

●	inclusion of oil and gas extracted from non-traditional sources in reserve estimates;

●	permitted use of new technologies that meet the definition of "reliable" to determine oil and gas reserves and requirement to disclose which technologies the registrant used to determine reserves;

●	required disclosure of reserves by specific geographic area;

●	permitted disclosure of both probable and possible reserves, as defined, in addition to required disclosure of proved reserves;

●	requirement to include reports and related consents from third parties who prepare, audit, or perform a process review of the registrant's reserves estimates if the registrant discloses the involvement of third parties for such purposes.

We adopted these rules effective December 31, 2009 which was the first time we requested GCA to provide us with a third-party opinion on our two producing assets, the Charmottes field and the Neocomian Complex (see "Third-Party Reserves Audit" below for further detail).

Probable and Possible Reserves

Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates. Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project. Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

Internal Controls Over Reserves Estimates

Our policies regarding internal controls over the recording of reserves estimates require reserves to be in compliance with the SEC definitions and guidance and prepared in accordance with generally accepted petroleum engineering principles. Responsibility for compliance in reserves bookings is delegated to a qualified petroleum engineer in our Paris office under the supervision of the Country Manager for France and our Chief Executive Officer. The petroleum engineer prepares all reserves estimates for our two producing assets. Data used in these integrated assessments include information obtained directly from the subsurface via wellbores such as well logs, reservoir cores, fluid samples, static and dynamic information, production test data and production history. Other types of data used include 2D seismic recently reprocessed and calibrated to available well control. The tools used to interpret the data included reservoir modeling and simulation, Decline Curve Analyses and data analysis packages. The preliminary reserves assessment was prepared by our petroleum engineer who left the employ of the company early in the fourth quarter of the year after a three-month handover. The final reserves analysis was updated and reviewed by our Engineering Manager who is a petroleum engineer and has had the opportunity to assess the work and concurs with the approach and the results obtained by his predecessor. Our Engineering Manager holds a degree in chemical engineering and has over 30 years of experience in various petroleum industry roles including several years of combined experience in reservoir engineering and reserves evaluation, all focussed mainly on the Western Canadian and Williston basins of North America and with minor exposure to other basins. He is a licenced Professional Engineer in the Province of Alberta, Canada which qualifications are recognized by La Commission des Titres d'Ingénieur of France and has been a member of the Society of Petroleum Engineers (SPE) for more than 25 years. We engage a third-party petroleum consulting firm (GCA) to audit all of our reserves. See "Third-Party Reserves Audit" below.

Third-Party Reserves Audit

The reserves audit for the year ending December 31, 2010 was performed by Gaffney, Cline & Associates ("GCA"), a leading international petroleum engineering consultancy.

GCA noted in its report that the concession that covers the Charmottes field expires in 2013. Under French law, exploitation concessions can generally be renewed for periods of up to 25 years. Although the French government has no obligation to renew the exploitation concessions, renewals have been generally granted as long as the operator demonstrates continued financial and technical capabilities to operate under such concessions. Renewal of the concessions covering the Neocomian Complex was granted on February 1, 2011, and effective as of January 1, 2011. The renewal decrees extended the validity period of the concessions covering the Neocomian Complex to January 1, 2036. Toreador applied for a renewal of the concession covering the Charmottes field in February 2011. GCA has assumed for purposes of its report that the renewal will be granted and that the economic terms of the concessions will not be altered on renewal.

GCA determined that our estimates of reserves conform to the guidelines of the SEC, including the criteria of "reasonable certainty," as it pertains to expectations about the recoverability of reserves in future years, under existing economic and operating conditions, consistent with the definition in the recently amended Rule 4-10(a) of Regulation S-X. GCA issued an unqualified audit opinion on our proved reserves at December 31, 2010, based upon its evaluation. The GCA opinion concluded that our estimates of proved, probable and possible reserves were, in aggregate, reasonable and have been prepared in accordance with generally accepted petroleum engineering and evaluation principles. GCA's report is attached to this Annual Report on Form 10-K as an exhibit.

The technical personnel at GCA responsible for overseeing the audit of our reserves estimate are Brian Rhodes and Chris Freeman. Mr. Rhodes holds a B.Sc (Hons) Geology, is a member of the Energy Institute, the Petroleum Exploration Society of Great Britain, the Society of Petroleum Engineers and the European Association of Geoscientists and Engineers, and has more than 33 years industry experience. Dr. Freeman has nearly 30 years of Industry experience, holds a B.Sc. (Hons) Physics from Lancaster University, a Ph.D. from the University of Cambridge, an MBA from Cass Business School in London, he has been a member of the Society of Petroleum Engineers (SPE) for over 25 years, and is a member of the Petroleum Exploration Society of Great Britain, and the Energy Institute.

Proved Undeveloped Reserves

As of December 31, 2010, our proved undeveloped reserves ("PUDs") totalled 369 Mbbl of crude oil, all of which were associated with the Neocomian fields. As of December 31, 2010, PUDs represented approximately 6.7% of our total proved reserves. We currently estimate that future development costs relating to the development of these PUDs are projected to be approximately $5 million in 2013. No activity was undertaken in 2010 to convert PUDs to proved developed reserves.

Productive Wells

The following table shows our gross and net interests in productive oil wells as of December 31, 2010 producing or capable of production.

	Gross(1)		Net(2)	Total
	Oil		Oil	Total
France		133	133	133

(1) "Gross" refers to wells in which we have a working interest.

(2) "Net" refers to the aggregate of our percentage working interest in gross wells before royalties, before or after payout, as appropriate.

Acreage

The following table shows the developed and undeveloped acreage attributable to our ownership as of December 31, 2010.

Developed Acreage

Undeveloped Acreage

Total Acreage

Gross

Net

Gross

Net

Gross

Net

France

24,260

780,299

339,636

804,559

363,896

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 and Other Exploratory and Development Activities

Drilling Activity

The following table shows our drilling activities on a gross and net basis for the years ended 2010, 2009 and 2008.

For The Year Ended December 31,

2010

2009

2008

Gross(1)

Net(2)

Gross(1)

Net(2)

Gross(1)

Net(2)

FRANCE

Exploratory:

Abandoned(3)

–

(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) "Abandoned" means wells that were dry when drilled and were abandoned without production casing being run.

Production, Production Prices and Costs

The following table summarizes our oil production, net of royalties, for the periods indicated for France. It also summarizes calculations of our total average unit sales prices and unit costs.


	For The Year Ended December 31,
	2010			2009			2008
Production:
Oil (Bbls)			323,073			328,416			365,361
Daily average (Bbls/Day)			885			900			1,001
Unit prices:
Average oil price ($/Bbl)		$	76.67		$	57.17		$	93.32
Unit costs ($/BOE):
Lease operating		$	35.90		$	25.57		$	25.35
Exploration and acquisition*			0.64			-			0.39
Depreciation, depletion and amortization			13.59			16.66			12.83
Dry hole costs			-			-			-
General and administrative			46.98			11.25			3.54

Total		$	97.10		$	53.48		$	42.11

* Exploration and acquisition expense are net of personal, general and administrative cost of TEF as Operator and invoiced to Hess under the Hess Investment Agreement.

Office Leases

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 $33,050 per month for the term of the lease. In July 2009, we subleased approximately 18,525 square feet of our Dallas office due to the relocation of corporate headquarters to Paris, France. We received approximately $214,656 and $103,987 from the sublease in 2010 and 2009, respectively, which was recorded as a reduction in rent expense. We also lease 3,218 square feet of office space in Paris, France. The lease expires on December 1, 2011 and rent is $16,795 per month. Total net rental expense for 2010 was approximately $278,154.

Markets and Competition

All our production is currently sold to Total, the largest purchaser in the Paris Basin, pursuant to an agreement signed with Elf Antar in 1996, as amended. Following an initial term expiring in 2002, the agreement automatically renews for one-year periods unless notice of termination is given at least six months in advance. The sale price is based on the monthly-average dated Brent price over the month of production, less a discount. In 2010, sales to Total, representing all of our oil production net revenues (after French State royalty), totalled $24.0 million and represented 59% of our total revenue and other income. In 2009 and 2008, sales to Total represented all of our oil production revenues from France, totalled (after French State royalty) $19.2 million and $34.1 million, respectively, and represented 98% and 99%, respectively, of our total revenues and other income. This production is shipped by truck to the nearby Total Grandpuits refinery.

The oil industry is highly competitive. We encounter strong competition from other independent operators and from major oil companies in acquiring exploration permits and exploitation concessions, 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 secure desirable permits and concessions, and they may pay more to evaluate, bid for and purchase a greater number of permits and concessions or prospects than our financial or personnel resources permit us to do.

We are also affected by competition for drilling rigs and the availability of tubular goods and certain other equipment. While the oil industry has experienced shortages of drilling rigs and equipment, pipe and personnel in the past, we are not presently experiencing any shortages and do not foresee any such shortages in the near future; however, we are unable to predict how long current market conditions will continue.

Competition for attractive oil permits and concessions and drilling rights is also strong, and we can give no assurance we will be able to compete satisfactorily in acquiring these permits and concessions. Since many major oil companies have publicly indicated their decision to focus on non-U.S. activities, we cannot ensure we will be successful in acquiring any such permits and concessions.

Government Regulation

General

Toreador currently operates solely in France. The oil industry is subject to extensive and continually changing regulations on environmental, drilling, production, transportation and sale matters, which can increase the cost of doing business, and consequently, may affect profitability. These laws and regulations may, among other things:

●	require acquisition of a permit before drilling commences;

●	set the methods of drilling and casing wells;

●	restrict the types, quantities and concentrations of various materials that can be released into the environment in connection with drilling and production activities;

●	require installation of expensive pollution control equipment;

●	require a special license for the transportation of hydrocarbons;

●	limit or prohibit construction or drilling activities in certain ecologically sensitive and other protected areas; and

●	require remedial measures to mitigate pollution from historical and ongoing operations.

Failure to comply with these laws and regulations or to obtain or comply with permits may result in the assessment of administrative, civil and criminal penalties, imposition of remedial requirements and the imposition of injunctions to force future compliance. See also " — Fiscal Terms and Infrastructure."

Our activities are affected by political stability and government regulations relating to foreign investment and the oil industry. Changes in these regulations or shifts in political attitudes are beyond our control and may adversely affect our business. Our operations may be affected by government regulations with respect to restrictions on production, price controls, income taxes, expropriation of property, environmental legislation and mine safety. For more information, see "— Recent Developments — Proof of Concept Program."

Our current or future operations, including exploration and development activities on our acreage, require permits from various governmental authorities, and such operations are and will be governed by laws and regulations governing prospecting, development, production, 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 government regulation.

Environmental

The oil industry is subject to extensive and varying environmental regulations in each of the jurisdictions in which we have historically operated or in which we currently, or may in the future, 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.

Our operations are subject to various 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 also may expose us to liability for the conduct of others or for our actions that were in compliance with all applicable laws at the time those actions were taken. We may incur significant costs as a result of environmental accidents, such as oil spills, natural gas leaks, ruptures, or discharges of hazardous materials into the environment, including clean-up costs and fines or penalties. Additionally, we may incur significant costs in order to comply with environmental laws and regulations and may be forced to pay fines or penalties if we do not comply. In addition, future climate change regulation, a subject of discussion in many jurisdictions currently, could require us to incur increased operating costs and could adversely affect the price or market demand for the oil that we produce. See "Risk Factors" for further information regarding environmental regulation.

We are committed to complying with environmental and operation legislation wherever we operate.

Permits and Concessions

In order to carry out exploration and development of mineral interests or to place these into commercial production, we are required to obtain certain permits and concessions from governmental authorities. There can be no guarantee that we will be able to obtain all necessary permits and concessions that may be required. In addition, such permits and concessions are subject to change and there can be no assurances that any application to renew any existing permits or concessions will be approved. See " — Permits, Concessions and Pending Applications" for a description of our permits and concessions, and see "Risk Factors" for further information regarding renewal of such permits and concessions.

Repatriation of Earnings

Currently, there are no restrictions on the repatriation of earnings or capital to foreign entities from France. 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.

Employees

As of March 16, 2011, we employed 35 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 information about oil producing activities and operating segments.

Internet Address/Availability of Reports

Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), are made available free of charge on our website at http://www.toreador.net as soon as reasonably practicable after we electronically file such material with, or otherwise furnish it to, the SEC and the Autorité des marches financiers (AMF) in France.

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.

"BBL/D." Bbl per day.

"BOE." Barrels of oil equivalent.

"DEVELOPED OIL AND GAS RESERVES." Reserves of any category that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

"DEVELOPMENT WELL." A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

"DISCOUNTED PRESENT VALUE." The present value of proved reserves is an estimate of the discounted future net cash flows from each property at the specified date, or as otherwise indicated. Net cash flow is defined as net revenues, after deducting production and ad valorem taxes, less future capital costs and operating expenses, but before deducting federal income taxes. The future net cash flows have been discounted at an annual rate of 10% to determine their "present value." The present value is shown to indicate the effect of time on the value of the revenue stream and should not be construed as being the fair market value of the properties. In accordance with SEC rules, estimates have been made using constant oil and natural gas prices calculated based on unweighted arithmetic average of the first day of the month price during the 12-month period on the specified date and operating costs in effect 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 a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another 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.

"KM." One kilometer.

"MBBL." One thousand bbl.

"MBBLS." One million bbl.

"MBOE." One thousand boe.

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

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

"POSSIBLE RESERVES." Those additional reserves that are less certain to be recovered than probable reserves.

"PROBABLE RESERVES." Those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

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

"PROVED RESERVES." The estimated quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.

"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.

"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.

"UNDEVELOPED OIL AND GAS RESERVES." Reserves of any category 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.

"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

The results and impact of pending French governmental studies relating to the development of shale oil in France are uncertain. Future restrictions on shale oil in France would have a material adverse effect on our business.

We currently rely on funds from our strategic partner for execution of our proof of concept program.

Pursuant to the Hess Investment Agreement, in order for Hess to retain its working interests in the relevant exploration permits in connection with our proof of concept program, Hess is required to invest up to $120 million in fulfillment of a two-phase work program. If Hess does not spend $120 million in fulfillment of the work program and/or elects not to proceed to the second phase of the work program, Toreador would be entitled to receive back from Hess the portion of its working interest in each permit Toreador transferred to Hess in connection with the execution of the Hess Investment Agreement; however, Toreador would then be required to expend the capital required to fund such work program (or any other work program). If Hess does spend $120 million in fulfillment of the work program, Toreador would be required to fund its portion of subsequent exploration, appraisal and development activities in accordance with individual participation agreements governing the joint operations on each permit. As a result, Toreador may require additional capital to execute the proof of concept program or fund such subsequent work, as applicable, which it may not be able to obtain on favorable terms, if at all.

We may require additional capital in the future, which may not be available on favorable terms, if at all.

We may require additional capital in 2011 and beyond to, among other things, execute our business plan, which would entail substantial capital expenditures. Under French law, each of our exploration permits and exploitation concessions require that we commit to expenditures of a certain amount over the period of the applicable permit or concession. Though we consider these amounts discretionary, such expenditures would be required to renew such permits.

We currently have a limited amount of oil production in France, and the revenues from our current production are not expected to be sufficient to cover all of the costs that would be necessary to explore and develop all our existing permits. Accordingly, we will continue to rely, to the extent available, on existing working capital and additional funds obtained from external sources, including potential strategic partners, to cover these costs. If these resources are unavailable, we may be required to curtail our drilling, development and other activities.

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 prices;

●	requirements and commitments under existing permits and concessions;

●	staffing levels and competitive conditions;

●	any purchases or dispositions of assets; and

●	other factors affecting our business at any given time.

To the extent that our existing capital and borrowing capabilities are insufficient to meet these requirements and cover any losses, we will need to raise additional funds through debt or equity financings, including offerings of our common stock, securities convertible into our common stock or rights to acquire our common stock, or revise our business plan and/or curtail our growth. Any equity or debt financing or additional borrowings, if available at all, may be on terms that are not favorable to us. In addition, the New Convertible Senior Notes limit our ability to incur or increase our debt based on our proved plus probable reserves. Under the terms of the New Convertible Senior Notes, we may not maintain total consolidated net debt, or incur debt, in excess of the product of (x) $7.00 and (y) the number of barrels of our proved plus probable reserves, except for nonrecourse financing for projects or acquisitions, joint ventures or partnerships and certain other permitted debt. Any securities we issue in future financings may have rights, preferences and privileges that are senior to those of our common stock. If our need for capital arises because of significant losses, the occurrence of these losses may make it more difficult for us to raise the necessary capital. If we cannot raise funds on acceptable terms if and when needed, we may not be able to take advantage of future opportunities, grow our business or respond to competitive pressures or unanticipated requirements.

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

In addition, if we issue additional equity securities, including upon conversion of our existing or any future convertible or similar securities, the value of currently outstanding common stock may be diluted and the trading price of our common stock may be adversely affected. See " — Risks Related to Our Common Stock — We may issue equity securities that may depress the trading price of our common stock and may dilute the interests of our existing stockholders."

We may not be able to maintain or renew our existing exploration permits or exploitation concessions or obtain new ones, which could reduce our proved reserves.

We do not hold title to our properties in France but hold exploration permits and exploitation concessions granted by the French government. Under French law, each exploration permit requires us to commit expenditures of a certain amount of exploration costs and is subject to renewal after the initial term of up to five years. Under French law, each exploitation concession requires a similar commitment of expenditure and is subject to renewal after an initial term of up to 50 years.

We currently hold three exploitation concessions covering two producing oil areas in the Paris Basin — the Neocomian Complex (Chateaurenard and St. Firmin Des Bois) and Charmottes fields (producing from the Dogger and Trias horizon). The production from these oil fields currently represents substantially all of our sales and other operating revenue. We obtained a renewal of the Chateaurenard and St. Firmin Des Bois concessions in February 2011, extending the expiry date of each to January 1, 2036 and we filed a renewal application for the Charmottes fields in February 2011. We have also filed renewal applications for exploration permits that expired in 2010 or 2011 (Auferville, Rigny le Ferron and Joigny) or will expire later in 2011 (Mairy). These renewal applications are currently pending with the French government. Although no renewal decision has been issued before the expiry of the Aufferville, Rigny le Ferron and Joigny permits, under current French Mining Code, such permits can still be operated until an express decision of the minister is issued with respect to their renewal. However, there is a doubt as to whether such exploration will still be possible after 15 months following the date of filing of the renewal application since the silence kept by the minister for more than 15 months following the date of filing of the renewal application may be construed as an implicit refusal to grant the renewal of an exploration permit.

There can be no assurance that we will be able to renew any of these permits or concessions when they expire, convert exploration permits into exploitation concessions or obtain additional permits or concessions in the future. If we do not satisfy the French government that we have financial and technical capacities necessary to operate under such permits or concessions, such permits or concessions may be withdrawn and/or not renewed. If we cannot renew some or all of these permits or concessions when they expire or convert exploration permits into exploitation concessions, we will not be able to include the proved reserves associated with the permit or concession and we will be unable to engage in production to recover reserves, which production currently represents substantially all of our revenue. Any such negative developments with respect to our permits would have a material adverse effect on our ability to conduct our business.

Our indebtedness and near-term debt obligations could materially adversely affect our financial health, limit our ability to finance capital expenditures and future acquisitions and prevent us from executing our business plan.

On December 31, 2010, we had approximately $31.6 million outstanding aggregate principal amount of our New Convertible Senior Notes recorded at a fair value of $34.4 million. Our level of indebtedness has, or could have, important consequences to investors, because:

●	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 for acquisitions, capital expenditures or general corporate purposes;

●	it may limit our flexibility in planning for, or reacting to, changes in our business and industry; and

●	we may be substantially more leveraged than some of our competitors, which may place us at a relative competitive disadvantage and make us more vulnerable to downturns in our business, our industry or the economy in general.

In addition, the terms of our New Convertible Senior Notes restrict, and the terms of any future indebtedness, including any future credit facility, may restrict, our ability to incur additional indebtedness because of debt or financial covenants we are, or may be, required to meet. Under the terms of the New Convertible Senior Notes, we may not maintain total consolidated net debt, or incur debt, in excess of the product of (x) $7.00 and (y) the number of barrels of our proved plus probable reserves, except for nonrecourse financing for projects or acquisitions, joint ventures or partnerships and certain other permitted debt. Thus, we may not be able to obtain sufficient capital to grow our business or implement our business strategy and may lose opportunities to acquire interests in oil properties or related businesses because of our inability to fund such growth.

Our ability to comply with restrictions and covenants, including those in our New Convertible Senior Notes or in any future credit facility, is uncertain and will be affected by the level of our proved plus probable reserves, 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.

We have incurred net losses in recent years, and there can be no assurance we will be profitable in the future.

Our future financial results are uncertain. We incurred net losses of approximately $9.5 million, $25.4 million and $108.6 million in the years ended December 31, 2010, 2009 and 2008, respectively. Our strategy includes conducting efficient operations and maintaining an optimal capital structure; however, there can be no assurance that our strategy will be effective or that we will be profitable in the future.

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

Our future success as an oil producer depends upon our ability to find, develop and acquire additional oil reserves that are profitable. Oil reserves are depleting assets, and production of oil 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, revenues 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.

This risk may be compounded by the fact that as of December 31, 2010, 6.7% of our total estimated proved reserves were classified as undeveloped, which, by their nature, are less certain and will require significant capital expenditures and successful drilling operations.

Since we do not hold title to our properties but rather hold exploration permits and exploitation concessions granted to us by the French government, the SEC may require that a portion of reported proved reserves associated with these permits not be included in our proved reserves.

Rather than holding title to our properties, we hold exploration permits and exploitation concessions that have been granted to us by the French government for a specific time period. We must apply to have these permits renewed and extended in order to continue our exploration and development rights. Although we have historically reported our proved reserves assuming that the permits will be extended in due course, the SEC may take the view that our ability to renew and extend our permits past their current expiration dates is not sufficiently certain for us to 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 SEC regarding the likelihood of extension, no assurance can be given that the SEC will allow us to continue to include these additional reserves in our proved reserves.

The loss of the current single purchaser of our oil production could have a material adverse effect on our financial condition and results of operations.

For the year ended December 31, 2010, Total accounted for all of our revenues from oil production in France. Our contract with Total was signed in 1996 (then with Elf Antar) and automatically renews for one-year periods unless notice of termination is given at least six months in advance. If Total determines not to renew this contract, ceases purchasing our oil on terms that are favorable to us or fails to pay us and we are unable to contract with another purchaser, it would have a material adverse effect on our financial condition, future cash flows and the results of operations. This customer concentration may also increase our overall exposure to credit risk.

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 prices.

We currently, and may in the future, enter into various hedging transactions for a portion of our production in an attempt to reduce our exposure to the volatility of oil prices. In a typical hedge transaction, we will have the right to receive from the counterparty to the hedge the excess of the fixed price specified in the hedge over a floating price based on a market index, multiplied by the quantity hedged. If the floating price exceeds the fixed price, we will be required to pay the counterparty this difference multiplied by the quantity hedged. In such case, we will be required to pay the difference regardless of whether we have sufficient production to cover the quantities specified in the hedge. Significant reductions in production at times when the floating price exceeds the fixed price could require us to make payments under the hedge agreements even though such payments are not offset by sales of production. Hedging also could prevent us from receiving the full advantage of increases in oil prices above the fixed amount specified in the hedge.

We depend on our senior management team and other key personnel. Accordingly, the loss of any of these individuals could adversely affect our business, financial condition and results of operations and future growth.

Our success is largely dependent on the skills, experience and efforts of our senior management and other key personnel. Although we have entered into employment agreements with our Chief Executive Officer and Chief Financial Officer, we can give no assurance that either of these individuals will remain with us. The loss of the services of either of these individuals or other employees with critical skills needed to operate our business could have a negative effect on our business, financial conditions and results of operations and future growth. Our ability to manage our growth, if any, will require us to continue to train, motivate and manage our employees and to attract, motivate and retain additional qualified personnel.

Competition for these types of personnel is intense in our industry, and we may not be successful in attracting, assimilating and retaining the personnel required to grow and operate our business profitably.

It may not be possible to serve process on our directors and officers or enforce judgments against them or us.

Many of our directors and executive officers live outside of the United States. Most of the assets of certain of our directors and executive officers and substantially all of our assets are located outside of the United States. As a result, it may not be possible to serve process on such persons in the United States or to enforce judgments obtained in U.S. courts against them based on the civil liability provisions of the securities laws of the United States.

Our operations are in France and we have previously operated in other international jurisdictions and we are subject to political, economic and legal risks and other uncertainties.

Our operations are in France and we have previously operated in other international jurisdictions, including through joint venture arrangements with parties in various international jurisdictions. We are, and have been, subject to the following risks and uncertainties that can affect our international 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 non-U.S. 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 non-U.S. courts in connection with legal disputes and the possible inability to subject non-U.S. persons to the jurisdiction of courts in the United States; and

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

Further, our non-U.S. operations and international business relationships are subject to laws and regulations that may restrict activities involving restricted countries, organizations, entities and persons that have been identified as unlawful actors or that are subject to U.S. economic sanctions. If we are not in compliance with any such applicable laws and regulations or U.S. economic sanctions, we may be subject to civil or criminal penalties and other remedial measures.

All of our revenues are currently attributable to our properties in the Paris Basin in France. Any disruption in production, development or our ability to produce and sell oil in France would have a material adverse effect on our results of operations or reduce future revenues.

All of our sales revenues are currently attributable to our properties in the Paris Basin in France. We depend on third parties in France for the transportation and refining of our oil production. Any disruption in production, development or our ability to produce and sell oil in France would have a material adverse effect on our results of operations or reduce future revenues. If production of oil in the Paris Basin were disrupted or curtailed, or in the case of labor or other disruptions affecting French refineries, transportation or other infrastructure, our cash flows and revenues would be significantly reduced.

Our operations are subject to currency fluctuation risks.

We currently have operations involving the U.S. dollar and Euro, and we are subject to fluctuations in the value of the U.S. dollar as compared to the Euro. While our oil sales are calculated on a U.S. dollar basis, our expenditures are in Euro and 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. These currency fluctuations, including the recent fluctuations, may adversely affect our results of operations. We do not currently hedge our exposure to currency fluctuations.

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 of 2002, 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 and prevent fraud and other errors in our reporting and recordkeeping.

If, as a result of deficiencies in our financial or other internal controls, including significant deficiencies, we have not or cannot provide reliable financial reports or internal recordkeeping or compliance procedures, our business decision or compliance process may be adversely affected, our business and operating results could be harmed, we may be subject to legal penalties or other claims, investors could lose confidence in our reported financial information and the price of our stock could decrease. For a discussion of our internal control over financial reporting, see Item 9A, "Controls and Procedures."

In connection with the sales of our assets in Turkey, we granted certain significant indemnities to the purchasers of those assets.

In 2005, two separate incidents occurred offshore Turkey in the Black Sea, which resulted in the sinking of the Fallen Structures, as defined below, and the loss of three natural gas wells. We have not been requested, or ordered by any governmental or regulatory body, to remove the Fallen Structures. Therefore, we believe it is unlikely that we will receive such a request or order, and no liability has been recorded. In connection with the 2009 sales of our assets in Turkey we agreed to indemnify each purchaser against and in respect of any claims, liabilities and losses arising from the Fallen Structures. We have also indemnified a third-party vendor for any claims made related to these incidents. We are unable to estimate the potential liability associated with the Fallen Structures. We have also granted certain other indemnities to the purchasers of our assets in Turkey and to the purchaser of our assets in Hungary in connection with the 2009 sales. Though certain of these indemnities are subject to limitations, including limitations on the time period during which claims may be asserted and the amounts for which we are liable, there can be no assurance that we will not incur future liabilities to the purchasers in connection with these transactions or that the amount of such liabilities will not be material or will not have a material adverse effect on our financial condition.

We face certain litigation risks, and unfavorable results of legal proceedings could have a material adverse effect on us.

We are party to certain lawsuits. Regardless of the merits of any claim, litigation can be lengthy, time-consuming, expensive, and disruptive to normal business operations and may divert management's time and resources, which may have a material adverse effect on our business, financial condition and results of operations, including our cash flow. The results of complex legal proceedings are difficult to predict. Should we fail to prevail in these matters, or should any of these matters be resolved against us, we may be faced with significant monetary damages, which also could materially adversely affect our business, financial condition and results of operations, including our cash flow.

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

We continue to evaluate and, where appropriate, intend to pursue acquisition opportunities on terms we consider favorable. In particular, we consider 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.

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.

Risks Related to Our Industry

A decline in oil prices will have an adverse impact on our operations, and oil prices have been extremely volatile in recent years.

Our future revenues, cash flows and profitability are substantially dependent upon prevailing prices for oil. In recent years, oil prices and, therefore, the level of drilling, exploration, development and production, have been extremely volatile. Any significant or extended decline in oil 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. Lower prices may make it uneconomical for us to increase or even continue current production levels of oil.

Volatility in the oil industry results from numerous factors, over which we have no control, including:

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

●	the cost of exploring for, producing and transporting oil;

●	the domestic and foreign supply and demand of oil;

●	domestic and foreign governmental regulation;

●	the level and price of foreign oil transportation;

●	available pipeline and other oil transportation capacity;

●	weather and other natural conditions;

●	international political, military, regulatory and economic conditions, particularly in oil-producing regions;

●	the level of consumer demand;

●	the price and availability of alternative fuels;

●	the effect of worldwide energy conservation measures; and

●	the ability of oil companies to raise capital.

Significant declines in oil prices may:

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

●	reduce the amount of oil we can produce economically;

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

●	reduce our revenues, operating income and cash flow;

●	reduce the carrying value of our oil properties; and

●	limit our access to sources of capital.

Oil prices rose to unprecedented levels during 2008. In September 2008, with the onset of the deterioration of the credit and equity markets, oil prices declined by more than 70% by the end of 2008. Oil prices recovered slowly throughout 2009 and 2010 and have recently now increased significantly in connection with the recent political instability in the Middle East. Such volatile oil prices caused us to remain cautious in our capital expenditure program for 2010 and continue to influence how we will operate on a go-forward basis. Our internally generated cash flow and cash on hand historically have not been sufficient to fund all of our expenditures, and we have in the past relied on the sales of non-core assets to provide us with additional capital. Though average oil prices increased by approximately 30% from the twelve months ended December 31, 2009 to twelve months ended December 31, 2010, oil prices are, and we expect will continue to be, volatile. The results of our operations are highly dependent upon the prices received from our oil production, which are dependent on numerous factors beyond our control. Accordingly, significant changes to oil prices are likely to have a material impact on our financial condition, results of operation, cash flows and revenue.

Competition in the oil 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 exploration, development, production, and acquisition activities. The oil 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 companies in each of the following areas:

●	seeking to acquire desirable exploration permits or exploitation concessions;

●	marketing our oil production;

●	integrating new technologies; and

●	seeking to acquire the equipment and expertise necessary to develop and operate our acreage.

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

The unavailability or high cost of drilling rigs, equipment, supplies, insurance, personnel and oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.

Our industry is cyclical and, from time to time, there could be a shortage of drilling rigs, equipment, supplies, insurance, qualified personnel or oil field services. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, the demand for, and wages of, qualified drilling rig crews rise as the number of active rigs in service increases. When oil prices are high, the demand for oilfield services rises and the cost of these services increases.

We are subject to complex laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations.

Our operations are subject to complex and stringent laws and regulations, including the French Mining Code. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, concessions approvals and certificates from various governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. For example, France’s Ministry of Environment and Ministry of Energy announced in February 2011 their intention to conduct a study on the economic, social and environmental stakes relating to the development of shale oil in France. A preliminary report is expected mid-April 2011 and a final report by the end of June 2011. We do not know what impact this study might have on our unconventional oil exploration. We are monitoring developments and assisting the French government in this study by providing technical and scientific information on the Paris Basin shale oil resource.

We may be unable to obtain all necessary permits, concessions approvals and certificates, or renewals thereof, for proposed projects. Alternatively, we may have to incur substantial expenditures to obtain, maintain or renew authorizations to conduct existing projects. If a project is unable to function as planned due to changing requirements or public opposition, we may suffer expensive delays, extended periods of non-operation or significant loss of value in a project. All such costs may have a negative effect on our business and results of operations.

Our business exposes us to liability and extensive environmental regulation.

Our operations are subject to various 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 also may 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, ruptures, or discharges of hazardous materials into the environment, including clean-up costs and fines or penalties. Additionally, we may incur significant costs in order to comply with environmental laws and regulations and may be forced to pay fines or penalties if we do not comply.

For example, in 2005, two separate incidents occurred offshore Turkey in the Black Sea, which resulted in the sinking of two caissons, or the Fallen Structures, and the loss of three natural gas wells. We have not been requested or ordered by any governmental or regulatory body to remove the Fallen Structures. Therefore, we believe that the likelihood of receiving such a request or order is remote, and no liability has been recorded. In connection with the 2009 sales of our assets in Turkey, we agreed to indemnify each purchaser against and in respect of any claims, liabilities and losses arising from the Fallen Structures. We have also indemnified a third-party vendor for any claims made related to these incidents. See " — Risks Related to Our Company — In connection with the recent sales of our assets in Turkey, we granted certain significant indemnities to the purchasers of those assets."

In addition, future climate change regulation, a subject of discussion in many jurisdictions currently, could require us to incur increased operating costs and could adversely affect the price or market demand for the oil that we produce.

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 France in which we may 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 prices and cause a reduction in our revenues. In addition, oil 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 face numerous risks in finding commercially productive oil reservoirs, including delays in our drilling operations as a result of factors that are beyond our control and that may not be covered by insurance.

Our drilling will involve numerous risks, including the risk that no commercially productive oil 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;

●	fire, explosions and blowouts;

●	pressure or irregularities in formations;

●	environmental accidents such as oil spills, ruptures or discharges of toxic gases, brine or well fluids into the environment (including groundwater contamination);

●	equipment failures or accidents;

●	weather conditions; and

●	shortages or delays in the delivery of equipment.

Any of these events could adversely affect our ability to conduct our operations or cause substantial losses, including:

●	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

●	attorneys' fees and other expenses incurred in the prosecution or defense of litigation.

As is customary in our industry, we maintain insurance against some, but not all, of these risks. We cannot assure 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 our 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 and may significantly reduce our revenues.

In addition, any use by us of 3D seismic and other advanced technology to explore for oil requires greater predrilling 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 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 that 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.

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

The process of estimating oil reserves is complex. It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors. Any material inaccuracies in our reserve estimates or underlying assumptions could materially affect the quantities and present values of our reserves. 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 prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

Actual future production, oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil 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 incorporated by reference in this prospectus supplement. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil prices and other factors, many of which are beyond our control.

You should not assume that the present value of our proved reserves is the current market value of our estimated oil reserves.

You should not assume that the pre-tax net present value of our proved reserves is the current market value of our estimated oil reserves. In accordance with the revised SEC requirements, we base the pre-tax net present value of future net cash flows from our proved reserves on 12-month average 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 and may be affected by factors such as:

●	supply of and demand for oil;

●	actual prices we receive for oil;

●	our actual operating costs;

●	the amount and timing of our capital expenditures;

●	the amount and timing of actual production; and

●	changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of our properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flow, which is required by the SEC, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil industry in general.

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. We operate in a price-sensitive industry, and there is often significant volatility in the market price of common stock irrespective of company performance. As a result, our high and low intra-day stock prices for 2010 were $16.20 and $5.35, respectively. Fluctuations in the price of our common stock may be exacerbated by conditions in the energy and oil industries or conditions in the financial markets generally.

Our common stock is quoted on The NASDAQ Global Market under the symbol "TRGL" and as of December 17, 2010 under the symbol "TOR" on the Professional Segment of NYSE Euronext in Paris. 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 France;

●	trends in our industry and the markets in which we operate;

●	changes in financial estimates and recommendations by securities analysts;

●	acquisitions and financings by us or our competitors;

●	quarterly variations in operating results;

●	litigation or governmental action involving or affecting us;

●	volatility in exchange rates between the U.S. dollar and the Euro;

●	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.

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 any future credit facility may restrict our ability to pay dividends on our common stock.

We may issue equity securities, including upon conversion of existing securities, that may depress the trading price of our common stock and may dilute the interests of our existing stockholders.

Sales or issuances of common stock or securities convertible into our common stock or the issuance of securities senior to our common stock may depress the trading price of our common stock. We may not have the ability to issue new common stock or securities convertible into common stock due to the decline in the equity market and our share price.

Any issuance of equity securities, including the issuance of shares upon conversion of our New Convertible Senior Notes, could dilute the interests of our existing stockholders and could substantially decrease the trading price of our common stock and the New Convertible Senior Notes. The terms of the New Convertible Senior Notes provide that the conversion rate be adjusted for certain securities offerings conducted prior to October 1, 2010 if 120% of the offering price in such offering is less than the then current conversion price. Thus, because we sold shares in the February 2010 offering at $8.50 per share, the conversion price of the New Convertible Senior Notes was adjusted to approximately $10.20 per share, representing 120% of the public offering price of the offering. Such adjustment will result in further dilution to our stockholders, if and when such notes are converted. The conversion price of the New Convertible Senior Notes will not be further adjusted under such provision in the indenture because the proceeds from the offering were in excess of $20 million. Under the terms of the indenture, we will not be required to issue shares of common stock upon conversion of the aggregate principal amount of the New Convertible Senior Notes that would exceed 19.9% of our outstanding shares of common stock or otherwise require shareholder approval.

We may issue common stock or securities convertible into our common stock 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 the conversion of debentures, or for other reasons.

We have an effective shelf registration from which additional shares of our common stock and other securities can be issued. We may not be able to sell shares of our common stock or other securities at a price per share that is equal to or greater than the price per share paid by our current shareholders. If the price per share at which we sell additional shares of our common stock or related securities in future transactions is less than the price per share at which we have sold shares in the past, shareholders will suffer a dilution in their investment.

Provisions in the indenture for the New Convertible Senior Notes and our charter 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 New Convertible Senior Notes) occurs, holders of 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 New Convertible Senior Notes), we also may be required to increase the conversion rate applicable to the notes surrendered for conversion upon the fundamental change. In addition, the indenture for the New 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.

Our charter authorizes our Board of Directors to set the terms of preferred stock, and our bylaws limit stockholder proposals at meetings of stockholders. In addition, Delaware law contains provisions that impose restrictions on business combinations with interested parties. Because of these provisions of our charter and bylaws and of Delaware law, persons considering unsolicited tender offers or other unilateral takeover proposals may be more likely to negotiate with our Board of Directors rather than pursue non-negotiated takeover attempts. As a result, these provisions may make it more difficult for our stockholders to benefit from transactions that are opposed by an incumbent Board of Directors.

The personal liability of our directors for monetary damages for breach of their fiduciary duty of care is limited by the Delaware General Corporation Law and by our certificate of incorporation.

The Delaware General Corporation Law allows corporations to limit available relief for the breach of directors' duty of care to equitable remedies such as injunction or rescission. Our certificate of incorporation limits the liability of our directors to the fullest extent permitted by Delaware law.

Specifically, our directors will not be personally liable for monetary damages for any breach of their fiduciary duty as a director, except for liability:

●	for any breach of their duty of loyalty to the company or our stockholders;

●	for acts or omissions not in good faith or that involve intentional misconduct or a knowing violation of law;

●	under provisions relating to unlawful payments of dividends or unlawful stock repurchases or redemptions; and

●	for any transaction from which the director derived an improper personal benefit.

This limitation may have the effect of reducing the likelihood of derivative litigation against directors, and may discourage or deter stockholders or management from bringing a lawsuit against directors for breach of their duty of care, even though such an action, if successful, might otherwise have benefited our stockholders.

We have the ability to issue "blank check" preferred stock, which, if issued, could affect the rights of holders of our common stock.

Our charter authorizes our Board of Directors, subject to the rules of The NASDAQ Global Market, to issue up to four million shares of preferred stock and to set the terms of the preferred stock without seeking stockholder approval. The terms of such preferred stock may adversely impact the dividend and liquidation rights of holders of our common stock.

ITEM 1B. Unresolved Staff Comments

None.

ITEM 2. Properties (see Items 1 and 2. Business and Properties)

ITEM 3. Legal Proceedings

Netherby

On October 16, 2003, we entered into an agreement (the "Netherby Agreement") with Phillip Hunnisett and Roy Barker ("Hunnisett and Barker"), pursuant to which Hunnisett and Barker agreed to post the collateral required by the Turkish government for Madison Oil Turkey Inc. (a Liberian company later reincorporated in the Cayman Islands as Toreador Turkey) (“Madison Oil”) to retain its 36.75% interest in relation to eight offshore exploration SASB licenses in exchange for a 1.5% gross overriding royalty interest (the "Overriding Royalty") on the net value to Madison Oil of all future production, if any, deriving from Madison Oil's interest in such SASB licenses. Since March 2009, we have corresponded with Hunnisett and Barker regarding a dispute over the amount of the compensation payable by us to Hunnisett and Barker under the Netherby Agreement as a result of Toreador Turkey's sale of a 26.75% interest in the SASB licenses to Petrol Ofisi in March 2009 (the "Netherby Payment Amount"). Hunnisett and Barker have contended that the Netherby Payment Amount could be up to $10.4 million; however, we do not believe that Hunnisett and Barker are entitled to such amount.

On September 30, 2009, we completed the sale of Toreador Turkey, including with it Toreador Turkey's remaining 10% interest in the SASB license, to Tiway Oil A/S ("Tiway"). In connection with this sale, we agreed to indemnify Tiway against and in respect of any and all claims, liabilities, and losses arising from the Overriding Royalty. We are treating the said indemnity as extending to Tiway Turkey Ltd (previously Tiway Turkey Ltd) as well.

On September 6, 2010, English High Court proceedings were commenced by Hunnisett and Barker, as well as Netherby Investments Limited against Tiway Turkey Limited (previously Toreador Turkey Limited) and Toreador. The proceedings were served on Toreador on October 20, 2010. Tiway Turkey Limited was served with the proceedings on or around December 8, 2010. In the said proceedings, Hunnisett and Barker now argue that an agreement was reached between the parties in around November 2008 regarding the Netherby Payment Amount in the sum of $7.2 million. In addition they argue that on a proper construction of the Netherby Agreement, they are entitled to continuing Overriding Royalty including on the 26.75% interest in the SASB licenses that was sold to Petrol Ofisi in March 2009 and/or to a capitalized sum of "not less than" $7.2 million. In addition or in the alternative, Hunnisett and Barker raise a wholly new claim for rectification of the Netherby Agreement on the basis they claim it does not reflect the true agreement of the parties. They seek rectification of the Netherby Agreement so that upon a sale such as the sale of the 26.75% interest in the SASB licenses that was sold to Petrol Ofisi in March 2009, the Netherby Agreement parties are required to first agree a capitalized sum to be paid to Hunnisett and Barker. Hunnisett and Barker also seek costs and interest.

On January 31, 2011, the Company and Tiway Turkey Limited filed a joint defense denying the majority of the claims asserted by Hunnisett and Barker. In its defense, the Company and Tiway Turkey Limited only admit a payment is due to Hunnisett and Barker in sum of $574,696 together with accrued interest as compensation properly due under the Netherby Agreement. Toreador and Tiway Turkey Limited deny that any other payment is due to Hunnisett and Barker and/or Netherby Investments Limited, whether in relation to (i) The alleged amount of $7.2 million supposedly agreed upon in November 2008 ("the Buy-Back Agreement") as being payable in respect of the Netherby Payment Amount; and (ii) The Overriding Royalty payments Hunnisett and Barker assert is due to them following the sale of the 26.75% SASB interest to Petrol Ofisi and/or the sum of no less than $7.2 million which Hunnisett and Barker assert is the capitalized monies due to them following the sale of the 26.75% interest to Petrol Ofisi. Furthermore, the Company and Tiway Turkey Limited deny Hunnisett and Barker's claim for rectification of the Netherby Agreement.

As of December 31, 2010, we had accrued approximately $644,000 (i.e. $574,696 plus accrued interest) as a contingent liability for these claims, with the expense of legal cost of $254,356 and $222,280 of Overriding Royalty payment included in discontinued operations. We also accrued $248,000 (recorded under long-term accrued liabilities) as a provision for the 1.5% Overriding Royalty the Company will have to pay on the net value to Hunnisett and Barker of all future production, if any, deriving from Madison Oil's interest in such SASB licenses.

Scowcroft

On June 17, 2009, The Scowcroft Group, Inc. ("Scowcroft") filed a complaint in the U.S. District Court for the District of Columbia against us. The complaint alleged that we breached a contract (the "Scowcroft Contract") between Scowcroft and us relating to the sale of our interests in the SASB and that Scowcroft was entitled to a success fee thereunder as a result of the sale of our interests in the SASB to Petrol Ofisi in March 2009. The complaint also alleged unjust enrichment/quantum meruit and fraud. Scowcroft sought damages in the amount of $2 million plus interest, costs and expenses. On April 30, 2010, Toreador and Scowcroft executed a settlement agreement (the "Settlement Agreement"), pursuant to which Toreador agreed to pay Scowcroft $495,000 and, subject to receipt of such payment, Scowcroft agreed to take actions to dismiss the suit and the parties agreed to a mutual release with respect to claims relating to the Scowcroft Contract. On April 30, 2010, Toreador made the settlement payment and the parties filed a stipulation of dismissal of the action. As of December 31, 2010, $657,000 has been expensed in discontinued operations consequently, consisting of the settlement amount and associated legal costs.

Petrol Ofisi

On January 25, 2010, we received a claim notice from Tiway under the Share Purchase Agreement, dated September 30, 2009, among us, Tiway Oil AS and Tiway relating to the sale of Toreador Turkey Ltd. (the “SPA”) in respect of a third-party claim asserted by Petrol Ofisi against Toreador Turkey Ltd. in the amount of TRY 7.6 million ($5.1 million), for which Tiway alleges we are liable for an estimated TRY 2.1 million ($1.4 million). A hearing on this matter was held on July 20, 2010, and the Court has appointed three experts to evaluate the case. A hearing was held on November 2, 2010 and the Court adjourned pending the issuance of the experts’ report. The next hearing is scheduled for April 5, 2011. The Company believes that the risk associated with this matter is remote and no amount has been recorded in connection therewith.

TPAO

On October 6, 2010, Toreador received a claim notice from Tiway under the SPA in respect of an arbitration initiated by Türkiye Petrolleri A.O. (“TPAO”) against Tiway relating to alleged damages and losses suffered in connection with the Akçakoca-Çayağzi Pipeline Construction Project in 2005. Tiway asserts in the letter that the total relief sought is $2,993,038. We do not believe the arbitration initiated by TPAO is justified, nor we believe Tiway is entitled to indemnification for such claim under the SPA. We understand the arbitration is currently scheduled for October 2011. The Company believes that the risk associated with this matter is remote and no amount has been recorded in connection therewith.

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.

Item 4. Reserved

Reserved

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" and on the Professional Segment of NYSE Euronext in Paris under the trading symbol "TOR" since December 17, 2010. 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 fiscal years as reported by the Nasdaq Global Market based upon quotations that reflect inter-dealer prices, without retail mark-up, mark-down or commission and may not necessarily represent actual transactions.


	High		Low
2010
Fourth quarter	$	16.20	$	11.75
Third quarter		11.18		5.71
Second quarter		9.68		5.35
First quarter		13.05		7.42
2009
Fourth quarter	$	11.58	$	7.60
Third quarter		10.79		4.50
Second quarter		7.26		2.39
First quarter		4.74		1.96

As of March 11, 2011, there were 25,942,705 shares of common stock outstanding and held of record by approximately 351 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).

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 its policy of holding and investing corporate funds on a conservative basis, retaining earnings to finance the growth of its business. We did not declare or pay any cash dividends on our common stock in 2009 or 2010, and we do not anticipate paying cash dividends on our common stock in the foreseeable future.

During 2010 and 2009, there were no equity securities issued pursuant to transactions exempt from the registration requirements under the Securities Act of 1933, as amended, that were not disclosed previously in Current Reports on Form 8-K or Quarterly Reports on Form 10-Q.

For the three months ended December 31, 2010, we did not repurchase any shares of our common stock. See "Liquidity and Capital Resources — 5.00% Convertible Senior Notes Due 2025" for a discussion of repurchases of our 5.00% Convertible Senior Notes.

Below is a line graph comparing the 5-year cumulative total stockholder return on our common stock with the Nasdaq Market Index and the Hemscott Group Index (Independent Oil & Gas Companies):

COMPARISON 5-YEAR CUMULATIVE TOTAL

RETURN

AMONG TOREADOR RESOURCES CORP.,

NASDAQ MARKET INDEX AND HEMSCOTT GROUP INDEX

ASSUMES $100 INVESTED IN JANUARY 1, 2006 ASSUMES DIVIDEND REINVESTED FISCAL YEAR ENDING DECEMBER 31, 2010

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, 2010 as well as selected consolidated balance sheet data as of December 31, 2010, 2009, 2008, 2007 and 2006 and should be read in conjunction with the consolidated financial statements and the notes thereto included herewith.

On June 14, 2007, the Board of Directors authorized management to sell all our oil and natural gas properties in the United States. The sale of these properties completed the divestiture of the Company's non-core U.S. assets and allowed Toreador to focus exclusively on its non-U.S. operations. The sale was closed on September 1, 2007 for $19.1 million, which resulted in a pre-tax gain of $9.2 million.

On March 3, 2009 we completed the sale of a 26.75% interest in the South Akcakoca Sub-Basin (SASB) project associated licenses located in the Black Sea offshore Turkey, to Petrol Ofisi for $55 million. In accordance with the revised assignment announced on February 3, 2009, $50 million of the proceeds was paid by Petrol Ofisi on March 3, 2009, and the remaining $5 million was paid on September 1, 2009. There was no gain or loss resulting from this sale.

On September 30, 2009, the Company entered into a Share Purchase Agreement (the "Share Purchase Agreement") with Tiway Oil BV, a company organized under the laws of the Netherlands ("Tiway"), and Tiway Oil AS, a company organized under the laws of Norway, pursuant to which the Company agreed to sell 100% of the outstanding shares of Toreador Turkey Ltd. ("Toreador Turkey") to Tiway for total consideration consisting of: (1) a cash payment of $10.5 million to be paid at closing, (2) exploration success payments dependent upon certain future commercial discoveries as provided in the Share Purchase Agreement, up to a maximum aggregate consideration of $40 million, and (3) future quarterly 10% pre-tax net profit interest payments if a field goes into production that was discovered by an exploration well drilled within four years of closing on certain of the licenses then still held by Tiway. The sale of Toreador Turkey was completed on October 7, 2009 and resulted in a gain of $1.8 million.

On September 30, 2009, the Company entered into a Quota Purchase Agreement (the "Quota Purchase Agreement") with RAG (Rohöl-Aufsuchungs Aktiengesellschaft), a corporation organized under the laws of Austria ("RAG"), pursuant to which the Company agreed to sell 100% of its equity interests in Toreador Hungary Limited ("Toreador Hungary") to RAG for total consideration consisting of (1) a cash payment of US$5.4 million (€3.7 million) paid at closing, (2) US$435,000 (€300,000), which was held back subject to a post-closing adjustment and was paid to us on November 5, 2009 and (3) a contingent payment of US$2.9 million (€2 million) to be paid upon post-transaction completion of agreements relating to certain assets of Toreador Hungary. The sale of Toreador Hungary was completed on September 30, 2009 and resulted in a loss of $4.1 million.

The results of operations of assets in the United States, Turkey, Hungary and Romania for 2006 to 2009 have been presented as discontinued operations in the accompanying consolidated statements of operations.

On May 10, 2010, Toreador Energy France S.C.S. (“TEF.”), a company organized under the laws of France and an indirect subsidiary of the Company, entered into an Hess Investment Agreement (the “Hess Investment Agreement”) with Hess Oil France S.A.S.(“Hess”), a company organized under the laws of France and a wholly owned subsidiary of Hess Corporation, a Delaware corporation, pursuant to which (x) Hess becomes a 50% holder of TEF.’s working interests in its awarded and pending exploration permits in the Paris Basin, France (the “Permits”) subject to fulfillment of Work Program (as described in (y) (2) hereafter) and (y) (1) Hess must make a $15 million upfront payment to TEF, (2) Hess will have the right to invest up to $120 million in fulfillment of a two-phase work program (the “Work Program”) and (3) TEF would be entitled to receive up to a maximum of $130 million of success fees based on reserves and upon the achievement of an oil production threshold, each as described more fully below.

Pursuant to the Hess Investment Agreement, TEF has transferred 50% of its working interest in each Permit to Hess (collectively, the “Transfer Working Interests”) and, on June 10, 2010, Hess paid TEF $15 million plus VAT, i.e., an aggregate amount of $17.9 million (such payment having been recorded as other income for the year ended December 31, 2010 as this revenue is not subject to any further obligation or performance by the Company nor is it dependent upon any approval).

Under the terms of the Hess Investment Agreement, TEF is entitled to invoice Hess for all personal general and administrative costs associated with its activities as operator of the Permits and such amounts are recorded as “Other operating income”.

	For The Year Ended December 31,
	2010			2009			2008			2007			2006
	(Amounts in thousands, except per share amounts)
Operating Results:
Revenues	$	40,764		$	19,236		$	34,150		$	25,907		$	27,294
Operating costs and expenses		(33,496	)		(35,415	)		(32,586	)		(29,473	)		(20,552	)
Operating income (loss)		7,268			(16,179	)		1,564			(3,566	)		6,742
Other income (expense)		(9,888	)		397			(3,082	)		(2,384	)		3,373
Income (loss) from continuing operations,
before income tax		(2,620	)		(15,782	)		(1,518	)		(5,950	)		10,115
Income tax benefit (provision)		(6,130	)		450			(5,502	)		1,402			(3,236	)
Income (loss) from continuing operations,
net of tax		(8,750	)		(15,332	)		(7,020	)		(4,548	)		6,879
Income (loss) from
discontinued operations, net of
tax		(740	)		(10,080	)		(101,585	)		(69,873	)		(4,301	)
Dividends on preferred shares		-			—			—			(162	)		(162	)
Income (loss) available to
common shares	$	(9,490	)	$	(25,412	)	$	(108,605	)	$	(74,583	)	$	2,416
Basic income (loss) available to
common shares per share	$	(0.35	)	$	(1.24	)	$	(5.48	)	$	(4.07	)	$	0.16
Diluted income (loss) available
to common shares per share	$	(0.35	)	$	(1.24	)	$	(5.48	)	$	(4.07	)	$	0.15
Weighted average shares
outstanding
Basic		25,153			20,564			19,831			18,358			15,527
Diluted		25,165			20,564			19,831			18,358			15,884
Balance Sheet Data:
Working capital	$	9,326		$	(30,193	)	$	73,286		$	203,591		$	188,029
Oil and natural gas properties,
net		65,778			74,621			72,753			80,983			71,663
Oil and natural gas properties held for sale,
net		—			—			91,959			190,968			179,352
Total assets		100,299			97,155			207,156			323,111			317,204
Debt, including current portion		34,394			54,616			110,275			116,250			112,800
Stockholders' equity		24,068			6,137			52,560			163,825			147,151
Cash Flow Data:
Net cash provided by (used in)
operating activities	$	10,535		$	(7,345	)	$	16,766		$	(12,434	)	$	122
Capital expenditures for oil and
natural gas property and
equipment, including
acquisitions		1,503			3,386			(770	)		3,824			5,883
Capital expenditures for oil and
natural gas property and
equipment held for sale		—			4,528			11,472			86,820			99,282

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. Certain prior-year amounts have been reclassified and adjusted to present the operations of Turkey, Hungary and Romania as discontinued operations.

EXECUTIVE OVERVIEW

We are an independent energy company engaged in the exploration and production of crude oil with interests in developed and undeveloped oil properties in the Paris Basin, France. We are currently focused on the development of our conventional fields and the exploitation of the prospective shale oil play within our Paris Basin acreage position.

We currently operate solely in the Paris Basin, which covers approximately 170,000 km2 of northeastern France, centered 50 to 100 km east and south of Paris. At December 31, 2010 we held interests in approximately 997,000 gross exploration acres (awarded and pending publication). According to Gaffney, Cline & Associates Ltd, an independent petroleum and geological engineering firm, or Gaffney Cline, as of December 31, 2010, our proved reserves were 5.5 Mbbls, our proved plus probable reserves were 9.1 MBbls and our proved plus probable plus possible reserves were 13.9 Mbbls. Our production for 2010 averaged approximately 885 bbl/d from two conventional oilfield areas in the Paris Basin — the Neocomian Complex and Charmottes fields. As of December 31, 2010, production from these oil fields represented a majority of our total revenue and substantially all of our sales and other operating revenue. We intend to maintain production from these mature assets using suitable enhanced oil recovery techniques. In addition to this production base, we have identified several additional conventional exploration targets, including the La Garenne field, which is the first of these targets, and for which we intend to formulate a development plan.

We are also currently focused on exploiting our shale oil acreage in the Paris Basin by executing with our strategic partner, Hess, a proof of concept program by drilling, completing and testing pilot wells.

Recent Developments

Dual Listing

Repurchase and Redemption of 5.00% Convertible Senior Notes

On October 1, 2010, we repurchased approximately $32.3 million aggregate principal amount of our 5.00% Convertible Senior Notes pursuant to the holders’ option, and, on November 24, 2010, redeemed the remaining $0.1 million aggregate principal amount outstanding. See “Liquidity-5.00% Convertible Senior Notes Due October 1, 2025.” Following such repurchase and redemption, our outstanding long-term debt consists of approximately $31.6 million aggregate principal amount of our 8.00%/7.00% Convertible Senior Notes recorded at a fair value of $34.4 million.

Proof of Concept Program

Concessions Renewal

The decrees relating to the renewal of the Châteaurenard concession and of the Saint-Firmin-des-Bois concession, which together account for 93% of our existing reserves, received final French government approvals on February 1, 2011, and were published in the Journal Officiel of the French Republic on February 3, 2011. The renewals extend the expiry date of both concessions to January 1, 2036.

Financial Summary

For the twelve months ended December 31, 2010:

●	Revenue and other operating income from continuing operations were $40.8 million.

●	Operating costs from continuing operations were $33.5 million.

●	Loss from discontinued operations, net of income taxes, was $0.7 million.

●	Net loss available to common shares was $9.5 million.

●	Production was 323 MBOE.

At December 31, 2010, we had:

●	Cash and cash equivalents of $21.6 million.

●	A current ratio (current assets/current liabilities) of 1.47 to 1.

●	A debt to equity ratio of 3.17 to 1.

Following the repurchase of $32,256,000 aggregate principal amount of the 5.00% Convertible Senior Notes on October 1, 2010 and the redemption of the remaining $129,000 principal amount outstanding of the 5.00% Convertible Senior Notes on November 24, 2010, our long-term debt currently consists solely of the 8.00%/7.00% Convertible Senior Notes in an aggregate principal nominal amount of $31,631,000 recorded at a fair value of $34,394,000.

Critical Accounting Policies

The discussion and analysis of our financial condition and results of operations is based upon the consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. Our significant accounting policies are described in Note 2 - Significant Accounting Policies” to our consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2010. 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 using different assumptions or conditions. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our financial statements:

Successful Efforts Method of Accounting

We account for our oil and natural gas exploration and development activities utilizing the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and natural gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but such costs are charged to expense if and when the well is determined not to have found reserves in commercial quantities. In most cases, a gain or loss is recognized for sales of producing properties.

As of December 31, 2010, we had $0.2 million of costs associated with exploratory costs that had been capitalized for a period of one year or less.

As of December 31, 2010, we had $2.9 million of costs associated with exploratory costs that have 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.

Reserves Estimate

Proved reserves are estimated quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward recoverable in future years from known reservoirs, and under existing economic conditions, operating methods, and government regulations - prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Proved undeveloped reserves on undrilled acreage are limited (i) to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances and (ii) to other undrilled locations if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

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, 2010, notwithstanding the 2010 total production of approximately 323,000 Bbl, our proved and probable reserves remain essentially flat for the twelve months ended December 31, 2010 as compared to the twelve months ended December 31, 2009. This stability can be correlated to a better long-term performance of our main producing asset, the Neocomian Complex, and a higher oil price; our reserves at December 31, 2010 were priced at $79.35 per Bbl, as compared to $56.99 at December 31, 2009.

Impairment of Oil Properties

We review our proved oil 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 properties and compare these future cash flows to the carrying value of the oil 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 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 reserves estimate and the history of price volatility in the oil market, events may arise that will require us to record an impairment of our oil properties and there can be no assurance that such impairments will not be required in the future nor that they will not be material.

We recorded no impairment for continuing operations in the twelve months ended December 31, 2010, 2009, 2008.

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 FASB ASC 410 "Asset Retirement and Environmental Obligations". ASC 410 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 be 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. In 2005, two separate incidents occurred offshore Turkey in the Black Sea, which resulted in the sinking of the Fallen Structures and the loss of three natural gas wells. We have not been requested, or ordered by any governmental or regulatory body, to remove the Fallen Structures. Therefore, we believe it is unlikely that we will receive such a request or order, and no liability has been recorded.

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 FASB ASC 815, "Derivatives and Hedging," 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 as an asset or a liability 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 France is the Euro. 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.

Bad debt allowance

An allowance for doubtful accounts is calculated on a customer by customer basis per management's review of the collectability

New Accounting Pronouncements

On December 31, 2008 the SEC issued the final rule, "Modernization of Oil and Gas Reporting" (the "Final Reporting Rule"). The Final Reporting Rule adopts revisions to the SEC's oil and gas reporting disclosure requirements and is effective for annual reports on Forms 10-K for years ending on or after December 31, 2009. The revisions are intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves to help investors evaluate their investments in oil and gas companies. The amendments are also designed to modernize the oil and gas disclosure requirements to align them with current practices and changes in technology. Revised requirements in the Final Reporting Rule include, but are not limited to:

●	Oil and gas reserves must be reported using the un-weighted arithmetic average of the first day of the month price for each month within a 12 month period, rather than year-end prices;
●	Companies will be allowed to report, on an optional basis, probable and possible reserves;
●	Non-traditional reserves, such as oil and gas extracted from coal and shales, will be included in the definition of "oil and gas producing activities;"
●	Companies will be permitted to use new technologies to determine proved reserves, as long as those technologies have been demonstrated empirically to lead to reliable conclusions with respect to reserve volumes;

●

Companies will be required to disclose, in narrative form, additional details on their proved undeveloped reserves ("PUDs"), including the total quantity of PUDs at year end, and any material changes to PUDs that occurred during the year, investments and progress made to convert PUDs to developed oil and gas reserves and an explanation of the reasons why material concentrations of PUDs in individual fields or countries have remained undeveloped for five years or more after disclosure as PUDs; and

●

Companies will be required to report the qualifications and measures taken to assure the independence and objectivity of any business entity or employee primarily responsible for preparing or auditing reserves estimate.

We have adopted the disclosure requirements beginning with the year ended December 31, 2009.

In January 2010, the Financial Accounting Standards Board (the “FASB”) issued guidance that clarifies and requires new disclosures about fair value measurements. The clarifications and requirement to disclose the amounts and reasons for significant transfers between Level 1 and Level 2, as well as significant transfers in and out of Level 3 of the fair value hierarchy, were adopted by the Company in the first quarter of 2010. The new guidance also requires that purchases, sales, issuances, and settlements be presented gross in the Level 3 reconciliation and that requirement is effective for fiscal years beginning after December 15, 2010 and for interim periods within those years, with early adoption permitted. Adoption of the guidance which only amends the disclosures requirements did not have significant impact on our financial statements.

In February 2010, the FASB issued 2010-09, Amendments to Certain Recognition and Disclosure Requirements ("ASU 2010-09"). ASU 2010-09 amends Accounting Standards Codification (“ASC”) 855, Subsequent Events, by removing the requirement for an SEC filer to disclose the date through which subsequent events have been evaluated. Management's responsibility to evaluate subsequent events through the date of issuance remains unchanged. The Company adopted amendments to the codification resulting from ASU 2010-09 on February 24, 2010. As ASU 2010-09 relates specifically to disclosures, the adoption of this standard had no impact on our consolidated financial condition, results of operations or cash flows.

On July 21, 2010, the FASB issued ASU 2010-20, Disclosure about the Credit Quality of Financing Receivables and the Allowance for Credit Losses ("ASU 2010-20"). ASU 2010-20 amends existing disclosure guidance to require entities to provide extensive new disclosures in their financial statements about their financing receivables, including credit risk exposures and the allowance for credit losses. ASU 2010-20 is effective for fiscal and interim periods beginning after December 15, 2010. The adoption of this standard had no impact on our disclosure requirements.

In December 2010, the FASB issued ASU 2010-28, When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts (“ASU 2010-28”). ASU 2010-28 modifies Step 1 of the goodwill impairment test for reporting units with zero or negative carrying amounts. This eliminates an entity’s ability to assert that a reporting unit is not required to perform Step 2 because the carrying amount of the reporting unit is zero or negative despite the existence of qualitative factors that indicate the goodwill is more likely than not impaired. ASU 2010-28 is effective for fiscal and interim periods beginning after December 15, 2010. The Company does not believe that the adoption of this standard will have a material impact on our consolidated financial statements.

In December 2010, the FASB issued ASU 2010-29, Disclosure of Supplementary Pro Forma Information for Business Combinations (“ASU 2010-29”). ASU 2010-29 specifies that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. ASU 2010-29 is effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010. The Company does not believe that the adoption of this standard will have a material impact on our consolidated financial statements.

LIQUIDITY AND CAPITAL RESOURCES

This section should be read in conjunction with “Note 7 - Long Term Debt” in the Notes to the Consolidated Financial Statements included in this filing.

Liquidity

The Company's liquidity depends on cash flow from operations and existing cash resources. As of December 31, 2010, we had cash and cash equivalents of $21.6 million, a current ratio of approximately 1.47 to 1 and a debt to equity ratio of 3.17 to 1. For the twelve months ended December 31, 2010, we had an operating income of $7.3 million. We had sales and operating revenue of $40.8 million. We had no other capital expenditures apart from technical studies of La Garenne for $218,000. The Company does not currently have a credit facility and intends to rely on its cash balance to meet its immediate cash requirements.

Our cash flow from operations is highly dependent upon the prices received from our oil production, which are dependent on numerous factors beyond our control. Accordingly, significant changes to oil prices are likely to have a material impact on our financial condition, results of operation, cash flows and revenue. Oil prices have been very volatile over the fiscal year of 2010, and we expect, will continue to be, volatile in the fiscal year 2011. In order to reduce our exposure to crude oil price fluctuations, on November 2, 2010, we have entered into a collar contract for approximately 15,208 Bbls per month for the months of January 2011 through December 2011 for which the floor price is $78.00 per Bbl, and the ceiling price is $91.00 per Bbl. See “Note 13 – Derivatives” for further information.

On February 1, 2010, we consummated an exchange transaction (the "Convertible Notes Exchange"). In the Convertible Notes Exchange, in exchange for (a) $22,231,000 principal amount of our outstanding 5.00% Convertible Senior Notes (the "Old Notes") and (b) $9.4 million cash, we issued $31,631,000 aggregate principal amount of our 8.00%/7.00% Convertible Senior Notes due 2025 (the "New Convertible Senior Notes") and paid accrued and unpaid interest on the Old Notes.

On February 12, 2010, we completed a registered underwritten public offering of 3,450,000 shares of common stock, including 450,000 shares of common stock acquired by the underwriters from us to cover over-allotment options. The net proceeds to Toreador from the offering were approximately $26.8 million, after deducting underwriting discounts, commissions and estimated offering expenses. We used the net proceeds, together with cash on hand, to satisfy payment obligations arising from the holders' exercise of their right on October 1, 2010 to require the Company to repurchase its 5.00% Convertible Senior Notes. Following the repurchase of $32,256,000 aggregate principal amount of the 5.00% Convertible Senior Notes on October 1, 2010 and the redemption of the remaining $129,000 principal amount outstanding of the 5.00% Convertible Senior Notes on November 24, 2010, our long-term debt currently consists solely of the 8.00%/7.00% Convertible Senior Notes.

We currently have no mandatory capital expenditures in 2011; however, we intend to formulate a development plan for the La Garenne field. In addition, under French law, each of our exploration permits and exploitation concessions require that we commit to expenditures of a certain amount over the period of the applicable permit or concession. Though we consider these amounts discretionary, such expenditures would be required to renew such permits.

We believe we will have sufficient cash flow from operations and cash on hand to meet all of our 2011 obligations.

5.00% CONVERTIBLE SENIOR NOTES DUE OCTOBER 1, 2025

On September 27, 2005, we issued $75 million of Convertible Senior Notes due October 1, 2025 (the "5.00% Convertible Senior Notes") to qualified institutional buyers pursuant to Rule 144A of the Securities Act of 1933, as amended (the "Securities Act"). The Company also granted the initial purchasers the option to purchase an additional $11.25 million aggregate principal amount of 5.00% Convertible Senior Notes to cover over-allotments. The over-allotment option was exercised on September 30, 2005. The total principal amount of 5.00% Convertible Senior 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 5.00% Convertible Senior Notes; these costs have been recorded in other assets on the balance sheet and have been amortized to interest expense over the term of the 5.00% Convertible Senior Notes (i.e., from issuance to the earliest date on which holders may require the Company to repurchase all or a portion of their 5.00% Convertible Notes, in this case October 1, 2010).

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 5.00% Convertible Senior Notes bore interest at a rate of 5.00% per annum.

During 2008, the Company repurchased $6 million, face value, of the 5.00% Convertible Senior Notes on the open market for $5.3 million. In 2009, the Company repurchased $25.7 million face value of the 5.00% Convertible Senior Notes on the open market for $21.3 million, resulting in a gain on the early extinguishment of debt of $3.4 million after writing off deferred loan costs of approximately $1 million. On February 1, 2010, Toreador consummated an exchange transaction (the "Convertible Notes Exchange"). In the Convertible Notes Exchange, in exchange for (a) $22,231,000 principal amount of our outstanding 5.00% Convertible Senior Notes (the “Old Notes”) and (b) $9.4 million cash, we issued $31,631,000 aggregate principal amount of our 8.00%/7.00% Convertible Senior Notes (the New Convertible Senior Notes) and paid accrued and unpaid interest on the Old Notes.

As the debt instruments exchanged in the Convertible Notes Exchange have substantially different terms, the Company recognized the exchange of the 5.00% Convertible Senior Notes as extinguishment of debt. As a result, for the twelve months ended December 31, 2010, the Company recognized a loss of $4.3 million including write off of loan original fee of $822,000 for the debt extinguishment. The New Convertible Senior Notes are recorded at a fair value of $35,065,000 on the date of exchange. The accretion expense on the Convertible Notes Exchange, which was determined using fair market value of the New Convertible Senior Notes, will be amortized to income over their term. The accretion impact (positive) of $593,417 was recorded for the twelve months ended December 31, 2010.

Following the repurchase of $32,256,000 aggregate principal amount of the 5.00% Convertible Senior Notes on October 1, 2010 and the redemption of the remaining $129,000 principal amount outstanding of the 5.00% Convertible Senior Notes on November 24, 2010, our long-term debt currently solely consists of the 8.00/7.00% Convertible Senior Notes in $31.6 million principal aggregate amount.

8.00%/7.00% CONVERTIBLE SENIOR NOTES DUE OCTOBER 1, 2025

On February 1, 2010, Toreador consummated the Convertible Notes Exchange. In the Convertible Notes Exchange, in exchange for (a) the Old Notes and (b) $9.4 million cash, we issued $31,631,000 aggregate principal amount of the New Convertible Senior Notes and paid accrued and unpaid interest on the Old Notes. We incurred approximately $1.9 million of costs associated with the issuance of the New Convertible Senior Notes; these costs have been recorded in other assets on the balance sheets and are being amortized to interest expense over the term of the New Convertible Senior Notes (i.e from issuance to the earliest date on which holders may require the Company to repurchase all or a portion of their New Convertible Senior Notes, in this case October 1, 2013).

The New Convertible Senior Notes are senior unsecured obligations of the Company, ranking equal in right of payment with future unsubordinated indebtedness. The New Convertible Senior Notes will mature on October 1, 2025 and paid annual cash interest at 8.00% from February 1, 2010 until January 31, 2011 and at 7.00% per annum thereafter. Interest on the New Convertible Senior Notes is payable on February 1 and August 1 of each year, beginning on August 1, 2010.

The New Convertible Senior Notes were convertible prior to February 1, 2011 only if an event of default occurred and was continuing under the terms of the indenture, upon a change of control (as defined in the indenture) and to the extent the Company elected to redeem the New Convertible Senior Notes in a Provisional Redemption (as defined below). The New Convertible Senior Notes are convertible at any time on or after February 1, 2011 and before the close of business on October 1, 2025.

The New Convertible Senior Notes are convertible into shares of our common stock at an initial conversion rate of 72.9927 shares of common stock per $1,000 principal amount of New Convertible Senior Notes (which is equivalent to an initial conversion price of $13.70 per share), subject to adjustment upon certain events. Under the terms of the indenture governing the New Convertible Senior Notes, if on or before October 1, 2010, we sold shares of our common stock in an equity offering or an equity-linked offering (other than for compensation), for cash consideration per share such that 120% of the issuance price was less than the conversion price of the New Convertible Senior Notes then in effect, the conversion price was to be reduced to an amount equal to 120% of such offering price. As a result of our February 2010 public offering, the conversion rate of the New Convertible Senior Notes adjusted to 98.0392 shares of common stock per $1,000 principal amount of New Convertible Senior Notes (which is equivalent to a conversion price of approximately $10.20 per share). Pursuant to the indenture, the conversion price of the New Convertible Senior Notes will not be further adjusted under such provision because the proceeds from the public offering were in excess of $20 million.

The New Convertible Senior Notes may be redeemed in whole or in part at the Company's option prior to October 1, 2013, in cash at a redemption price equal to one hundred percent (100%) of the principal amount of the New Convertible Senior Notes redeemed, plus accrued and unpaid interest, if any, to, but excluding, the redemption date plus a make-whole payment, if the closing sale price of the Company's common stock has exceeded 200% of the conversion price then in effect for at least twenty (20) trading days in any consecutive thirty (30)-trading day period ending on the trading day prior to the date of mailing of the relevant notice of redemption (a "Provisional Redemption"). The New Convertible Senior Notes may be redeemed in whole or in part at the Company's option on or after October 1, 2013 for cash at a redemption price equal to 100% of the principal amount of the New Convertible Senior Notes redeemed, plus any accrued and unpaid interest to, but excluding, the redemption date. In addition, upon the occurrence of certain fundamental changes, or on each of October 1, 2013, October 1, 2015 and October 1, 2020, a holder may require the Company to repurchase all or a portion of the New Convertible Senior Notes in cash for 100% of the principal amount of the New Convertible Senior Notes to be purchased, plus any accrued and unpaid interest to, but excluding, the purchase date.

Pursuant to the indenture, the Company and its subsidiaries may not incur debt other than Permitted Indebtedness. "Permitted Indebtedness" includes (i) the New Convertible Senior Notes; (ii) indebtedness incurred by the Company or its subsidiaries not to exceed the sum of (i) the product of (x) $7.00 and (y) the number of barrels of proved plus probable reserves and (ii) cash equivalents less the aggregate principal amount of the New Convertible Senior Notes outstanding less the aggregate principal amount of the 5.00% Convertible Senior Notes less any Refinancing Debt; (iv) indebtedness that is nonrecourse to the Company or any of its subsidiaries used to finance projects or acquisitions, joint ventures or partnerships, including acquired indebtedness ("Nonrecourse Debt"); and (iv) certain other customary categories of permitted debt. In addition, the Company may not permit its total consolidated net debt as of any date to exceed the product of (x) $7.00 and (y) the number of barrels of proved plus probable reserves other than for Nonrecourse Debt. The proved plus probable reserves underlying any Nonrecourse Debt for which debt has been incurred as permitted debt pursuant to clause (iii) above will be excluded from the proved plus probable reserves calculation for the purposes of the above debt covenants.

CHANGE IN AMORTIZATION OF ISSUE PREMIUM AND DEBT ISSUANCE COSTS

The Company reviews the estimated lives of its assets and liabilities and related amortization period on an ongoing basis. This review indicated in 2010 that the estimated amortization period of the Company’s issue premium and debt issuance costs were deemed to be shorter than the previously assigned amortization period. As a result, effective July 1, 2010, the Company changed its estimates for the amortization period of its issue premium and debt issuance costs to reflect the first put option date of the related callable debt. This change in estimate resulted from a change in the pattern of recognition of those expenses resulting from the repurchase option for the 5.00% Convertible Senior Notes on October 1, 2010.

Based on this early redemption, the Company has decided that for a debt instrument that is puttable by the holder prior to the debt’s stated maturity date, it is preferable to amortize the related issuance costs and purchase premium over a period no longer than through the first put option date. For the same reason, the Company has elected to amortize under the effective interest rate method (“EIR”) the cost associated with the New Convertible Senior Notes. The issue premium on the Convertible Notes Exchange and the costs associated with the issuance of its convertible senior notes will now be amortized over the term of the first puttable dates of these callable debts. In all prior periods, the issue premium and the debt issuance costs were amortized over the terms of the debt issuance (i.e., October 1, 2025 for both the 5.00% Convertible Senior Notes and the New Convertible Senior Notes). The effect of this change in estimate was to increase the interest expense by $1,153,805, increase the accretion impact (positive) by $190,194 (or increase net loss for $963,611 and decrease basic and diluted earnings per share by $0.04 for the twelve months ended December 31, 2010). The unamortized debt issuance costs included in other assets amounted to $1.6 million and $2.0 million as of December 31, 2010 and 2009, respectively.

Dividends

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.

Contractual Obligations

The following table sets forth our contractual obligations in thousands at December 31, 2010 for the periods shown:

	Total		Less Than One Year		One to Three Years		Four to Five Years		More Than Five Years
Long-term debt	$	34,394	$	-	$	34,394	$	-	$	-
Asset retirement
obligation	6,866		-		253		2,118		4,495
Lease commitments	3,045		707			1,628		710	-
Total contractual
obligations	$	44,305	$	707	$	36,275	$	2,828	$	4,495

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

Results of Operations

Comparison of Years Ended December 31, 2010 and 2009

Results of Continuing Operations

In 2009, the Company disposed of its interest in Turkey, Hungary and Romania. The results of operations for these operations were reclassified as discontinued operations for all periods presented and are discussed separately under the heading "Results of discontinued operations".

	For The Year Ended December 31,
	2010			2009			2010			2009
Production:						Average Price:
Oil (Mbbl):						Oil ($/Bbl):
France		$	323	$	328	France		$	76.67	$	57.17

Revenue and other operating income

Sales and other operating revenue

Sales and other operating revenue for the twelve months ended December 31, 2010 were $24 million, as compared to sales and other operating revenue of $19.2 million for the comparable period in 2009. This increase is primarily due to the global increase in oil prices. The increase in the average realized price for oil from $57.17 in 2009 to $76.67 in 2010 resulted in an increase of revenue of $6.3 million. Production remained relatively stable, decreasing from 328 MBbl in 2009 to 323 MBbl in 2010.

The above table compares both volumes and prices received for oil for the twelve months ended December 31, 2010 and 2009. Oil prices are and probably will continue to be extremely volatile and a significant change would have a material impact on our revenue.

Other operating income

Other operating income for the twelve months ended December 31, 2010 was $16.8 million as compared to zero for the comparable period in 2009, which represented (i) the $15 million upfront payment received from Hess on June 10, 2010 under the Hess Investment Agreement and (ii) $1,769,697 invoiced to Hess under the terms of the Hess Investment Agreement for all personal general and administrative costs associated with its activities as operator of the exploration permits in the Paris Basin.

Costs and expenses

Lease operating

Lease operating expense was $11.6 million, or $35.90 per BOE produced, for the twelve months ended December 31, 2010, as compared to $8.4 million, or $25.60 per BOE produced, for the comparable period in 2009.

This increase is mainly due to the classification of certain costs associated with particular properties as lease operating expenses in 2010 including (i) $1,090,000 relating to certain taxes associated with oil production and (ii) approximately $7 million relating to costs associated with production sites and additional Paris headquarter expenses (which in the year ended December 31, 2009 were classified as general and administrative expenses, but following the strategic partnership with Hess are now mainly incurred in connection with our existing oil production and conventional reservoirs development and therefore have been classified as lease operating expenses). Lease operating expense for the twelve months ended December 31, 2010 also includes inventory turnover variation for an amount of $142,000.

Exploration expense

Exploration expense for the twelve months ended December 31, 2010 was $2.0 million, as compared to $138,000 for the comparable period in 2009. This increase is due primarily to expenses associated with geological and technical studies the Company conducted and commissioned in connection with the the shale oil development project.

Depreciation, depletion and amortization

For the twelve months ended December 31, 2010, depreciation, depletion and amortization expense was $4.4 million, or $13.59 per BOE produced, as compared to $5.3 million, or $17.57 per BOE produced for the twelve months ended December 31, 2009. This decrease is primarily due to the higher proved reserves assigned to our French assets at December 31, 2009 due to increased oil prices (as depreciation, depletion and amortization is calculated for the first three quarters of the year based on the reserves assigned to our French assets at the end of the preceding year).

Accretion on discounted assets and liabilities

Accretion expense for the twelve months ended December 31, 2010 was $89,000 (positive) as compared to $507,000 for the twelve months ended December 31, 2009. The accretion expense for the twelve months ended December 31, 2010 is composed of $ 504,000 as asset retirement obligation expense and $ 593,000 of accretion impact (positive) related to the fair value of the New Convertible Senior Notes.

Impairment of oil and natural gas properties

We had no impairment charged in 2010 or 2009 for continuing operations.

General and administrative

General and administrative expense (including stock compensation) was $15.2 million for the twelve months ended December 31, 2010, as compared to $20.4 million for the comparable period of 2009.

Excluding stock compensation, general and administrative expense was $11.9 million for the twelve months ended December 31, 2010, compared with $16.8 million for the comparable period of 2009. This decrease is primarily due to certain exceptional costs incurred in 2009, such as $1.5 million incurred due to resignation of former officers, $545,000 for legal and consulting costs associated with subsidiary sales and approximately $4 million of costs associated with the Dallas office/relocation of headquarters, which was partially offset by costs incurred in 2010 in connection with the Company’s processes to identify a strategic partner and achieve its dual listing.

Stock compensation expense

Stock compensation expense was $ 3.2 million for the twelve months ended December 31, 2010 in connection with the grant of 287,750 of the Company’s shares at a weighted average price of $10.32 per share, compared with $ 3.6 million for the comparable period of 2009 in connection with the grant of 1,304,387 of the Company’s shares at a weighted average price of $6.40 per share.

(Loss) Gain on oil derivative contracts

Loss on oil derivative contracts was $0.4 million for the year ended December 31, 2010, as compared to a loss of $ 0.9 million for 2009.

The realized loss in 2010 represents the recognized gain (on the 2010 hedging contract) and the unrealized loss (on the 2011 hedging contract) as shown in the table below on the commodity derivative contracts with Vitol S.A. Presented in the table below is a summary of the contracts entered into:

Type	Period	Barrels		Floor		Ceiling		Gain
Collar	January 1 — December 31, 2010		182,500	$	68	$	81	$	886

Type	Period	Barrels		Floor		Ceiling		(Loss)
Collar	January 1 — December 31, 2011		182,500	$	78	$	91	$	(1,330	)

Foreign currency exchange gain (loss)

We recorded a loss on foreign currency exchange of $0.9 million for the year ended December 31, 2010 as compared with a gain of $0.2 million for the comparable period of 2009. This decrease is mainly due to the fact that Toreador Energy France booked a loss on foreign currency exchange in its statutory accounts in Euro over the year ended December 31, 2010 due to the receipt on June 10, 2010 of the $15 million upfront payment from Hess under the Hess Investment Agreement combined with the weakening of the U.S. dollar compared to the Euro over the same period (this loss having been recorded in the financial statements of the Company for the year ended December 31, 2010 in accordance with FAS 52 “Foreign Currency Translation”).

Gain (Loss) on the early extinguishment of debt

As the debt instruments exchanged in the Convertible Notes Exchange have substantially different terms, the Company recognized the exchange of the 5.00% Convertible Senior Notes as extinguishment of debt. As a result, for the twelve months ended December 31, 2010, the Company recognized a loss of $4.3 million including write off of loan original fee of $822,000 for the debt extinguishment. For the year ended December 31, 2009, we repurchased $25.7 million principal amount of the Notes on the open market and through privately negotiated transactions for $21.3 million plus accrued interest and prepaid loan fees resulting in a gain of $3.3 million on the early extinguishment of debt.

In accordance with the terms, procedures and conditions outlined in the indenture and the 5.00% Convertible Senior Notes, each holder of the 5.00% Convertible Senior Notes had an option to require the Company to purchase all or a portion of its 5.00% Convertible Senior Notes on October 1, 2010. Pursuant to the exercise of this option, the Company repurchased $32,256,000 principal amount of the 5.00% Convertible Senior Notes on October 1, 2010. Interest on the repurchased 5.00% Convertible Senior Notes accrued up to, but not including, October 1, 2010 was been paid to record holders of 5.00% Convertible Senior Notes as of September 15, 2010. The repurchase on October 1, 2010 resulted in a loss of $1.1 million after writing off all deferred debt issuance costs pertaining to the 5.00% Convertible Senior Notes.

Interest expense, net of interest capitalization

Interest expense was $4.8 million for the year ended December 31, 2010, as compared to $3.4 million for the comparable period of 2009. The increase is mainly due to the additional interest payments relating to the New Convertible Senior Notes issued in February 2010, which was offset by decreased interest payments relating to the 5.00% Convertible Senior Notes, of which $22.2 million of the aggregate principal amount outstanding were exchanged for a portion of the New Convertible Senior Notes in the Convertible Notes Exchange. Interest expense for the New Convertible Senior Notes was $2,242,000 for the twelve months ended December 31, 2010 as compared to zero for the twelve months ended December 31, 2009. Interest expense for the 5.00% Convertible Senior Notes was $1,308,000 for the twelve months ended December 31, 2010 as compared to $3,346,000 for the twelve months ended December 31, 2009. Amortization of loan fees of $1,524,969 was recorded for the twelve months ended December 31, 2010 compared to $158,000 for the twelve months ended December 31, 2009, due to the change in estimate of the lives of the issue premium and debt issuance costs associated to 5.00% Convertible Senior Notes and to the 8.00%/7.00% New Convertible Senior Notes (See Note 7 – “Change in depreciable lives of issue premium and debt issuance costs”).

Income tax (benefit) provision

For the year ended December 31, 2010 we reported an income tax provision of $6.1 million compared to a benefit of $0.5 million for the same period of 2009. The increase in income tax is primarily due to a higher French taxable income as a result of higher oil prices and the initial payment made by Hess under the Hess Investment Agreement.

Other comprehensive income (loss)

The most significant element of comprehensive income, other than net income, is foreign currency translation. As of December 31, 2010, we had accumulated an unrealized loss of $2.5 million. For the year ended December 31, 2009, we had an unrealized gain of $4.6 million.

The functional currency of our operations in France is the Euro, and the exchange rate used to translate the financial position of the French operations at December 31, 2010 and 2009 is shown below:


	December 31,
		2010		2009
US Dollars		€	0.7484	€	0.6942

Results of Discontinued Operations

We had no sales and other operating revenue from discontinued operations for the twelve months ended December 31, 2010 due to the sale of all our discontinued operations in 2009. For the twelve months ended December 31, 2010, we recorded $1,034,000 as general and administrative expense associated with the payment of $657,000 made to Scowcroft under the Settlement Agreement on April 30, 2010 and associated legal costs, $254,354 for legal costs associated to the Netherby dispute and Overriding Interest payment, and $104,000 of additional tax associated with Toreador Hungary Limited activities in 2009. We thus recorded a loss of $739,000 from discontinued operations for the twelve months ended December 31, 2010.

On March 3, 2009, we completed the sale of a 26.75% interest in the South Akcakoca Sub-Basin (SASB) project associated licenses located in the Black Sea offshore Turkey, to Petrol Ofisi for $55 million. In accordance with the revised assignment announced on February 3, 2009, $50 million of the proceeds was paid by Petrol Ofisi on March 3, 2009, and the remaining $5 million was paid on September 1, 2009. There was no gain or loss resulting from this sale.

On September 30, 2009, the Company entered into a Share Purchase Agreement (the "Share Purchase Agreement") with Tiway Oil BV, a company organized under the laws of the Netherlands ("Tiway"), and Tiway Oil AS, a company organized under the laws of Norway, pursuant to which the Company agreed to sell 100% of the outstanding shares of Toreador Turkey Ltd. to Tiway for total consideration consisting of: (1) a cash payment of $10.5 million to be paid at closing, (2) exploration success payments dependent upon certain future commercial discoveries as provided in the Share Purchase Agreement, up to a maximum aggregate consideration of $40 million, and (3) future quarterly 10% pre-tax net profit interest payments if a field goes into production that was discovered by an exploration well drilled within four years of closing on certain of the licenses then still held by Tiway. The sale of Toreador Turkey Ltd. was completed on October 7, 2009 and resulted in a gain of $1.8 million for the twelve months ending December 31, 2009.

On September 30, 2009, the Company entered into a Quota Purchase Agreement (the "Quota Purchase Agreement") with RAG (Rohöl Aufsuchungs Aktiengesellschaft), a corporation organized under the laws of Austria ("RAG"), pursuant to which the Company agreed to sell 100% of its equity interests in Toreador Hungary Limited to RAG for total consideration consisting of (1) a cash payment of $5.4 million (€ 3.7 million) paid at closing, (2) $435,000 (€ 300,000), which was held back subject to a post-closing adjustment and was paid to us on November 5, 2009 and (3) a contingent payment of $2.9 million (€2 million) to be paid upon post-transaction completion of agreements relating to certain assets of Toreador Hungary. The sale of Toreador Hungary was completed on September 30, 2009 and resulted in a loss of $4.1 million.

The results of operations of assets in Romania, Turkey and Hungary have been presented as discontinued operations in the accompanying consolidated statement of operations (see “Note15 – Discontinued Operations”). Results for these assets reported as discontinued operations were as follows:

	For The Year Ended December 31,
		2010			2009
	(In thousands)
Revenues:
Oil and natural gas sales		$	107		$	4,545
Costs and expenses:
Lease operating			-			886
Exploration expense			-			868
Impairment of oil and natural gas properties			-			10,725
Depreciation, depletion and amortization			-			157
Dry hole costs			-			1,318
General and administrative			1,070			3,424
(Gain) loss on sale of properties			-			(3,583	)

Total costs and expenses			1,070			13,795

Operating loss			(963	)		(9,250	)
Other income (expense):
Loss on early extinguishment of debt			-			(4,881	)
Foreign currency exchange			258			3,822
Interest and other income			66			414
Interest and other expense			-			(185	)

Loss before taxes			(639	)		(10,080	)
Income tax provision			(101	)		-

Loss from discontinued operations		$	(740	)	$	(10,080	)

	For The Year Ended December 31,
		2010	2009		2010	2009
Production:				Average Price:
Oil (Mbbl):				Oil ($/Bbl):
Turkey		—	39	Turkey	—	49.78
Romania		—	—	Romania	—	—

Total		—	39	Total average oil price	—	49.78

Gas (MMcf):				Gas ($/Mcf):
Turkey		—	301	Turkey	—	8.64
Romania		—	—	Romania	—	—

Total		—	301	Total average gas price	—	8.64

MBOE:				$/ BOE:
Turkey		—	89	Turkey	—	50.94
Romania		—	—	Romania	—	—

Total		—	89	Total average price per BOE	—	50.94

Revenue and other operating income

Sales and other operating revenue

Sales and other operating revenue for the twelve months ended December 31, 2010 were $71,000 resulting from Romania royalty interest (Fauresti) as compared to $4.5 million for the comparable period in 2009. This decrease is due to the sale all of our discontinued assets in 2009.

Total costs and expenses

Lease operating

Lease operating expense was zero for the twelve months ended December 31, 2010, as compared to $886,000, for the comparable period in 2009. This decrease is due to the sale of all our discontinued assets in 2009.

Exploration expense

Exploration expense for the twelve months ended December 31, 2010 was $0 as compared to $868,000 for the comparable period in 2009. This decrease is primarily due to the sale of our 26.75% interest in the SASB to Petrol Ofisi in March 2010, followed by the sale of Toreador Turkey to Tiway in October 2009 and the disposal of our Romanian operations in January 2009.

Dry hole and abandonment

Dry hole and abandonment cost for the twelve months ended December 31, 2010 was zero as compared to $1.3 million in 2009. In 2009 we drilled the Durusu#1, in offshore Turkey, which was a dry hole.

Depreciation depletion and amortization

For the twelve months ended December 31, 2010, depreciation, depletion and amortization expense was zero as compared to $157,000 for the twelve months ended December 31, 2009. This decrease is due to the sale of all our discontinued assets in 2009.

Impairment of oil and natural gas properties and intangible assets

Impairment charged in 2010 was zero as compared to $10.7 million in 2009. The 2009 impairment was a result of 1) the Company's decision not to proceed with the Kiha pipeline in Hungary for $5.4 million and 2) the decline in the fair market value of the South Akcakoca Sub-basin assets in Turkey for $5.3 million.

For further information, see “Note 15 – Discontinued Operations”

General and administrative

For the twelve months ended December 31, 2010, we recorded $943,000 as general and administrative expense compared to $3.4 million for the same period last year. These expenses were associated with the payment made to Scowcroft under the Settlement Agreement on April 30, 2010 and associated legal costs, $182,000 for legal costs associated to the Netherby dispute and Overriding Interest payment, and $104,000 of additional tax associated with Toreador Hungary Limited activities in 2009.

Gain/loss on sale of assets

For the year ended December 31, 2010, we did not have a sale of assets as compared with a gain of $3.6 million for the comparable period of 2009. The table below shows the gain/(loss) by country:

		For The Year Ended December 31,
		2010		2009
	(In thousands)
Turkey		$	—	$	1,811
Romania			—		5,846
Hungary			—		(4,074	)
United States			—		—

Gain (loss) on sale of assets		$	—	$	3,583

The gains are primarily attributable to the reclassification of Accumulated Other Comprehensive Income, recorded on the balance sheet, to gain/(loss) on sale.

Loss on early extinguishment of debt

We did not record any loss for early extinguishment of debt for for the year ended December 31, 2010 compared to a loss on the early extinguishment of debt of $4.9 million for the same period in 2009, which was due to early repayment of the International Finance Corporation revolving credit facility with the proceeds of the Petrol Ofisi sale for an outstanding balance of $36.4 million (including $5.9 million of additional compensation and $500,000 for accrued interest and fees).

Foreign currency exchange

We did not record a gain on foreign currency exchange for for the year ended December 31, 2010 as compared with a $3.8 million gain for the comparable period of 2009. This decrease is due to the sale of all of our discontinued assets in 2009.

Interest and other income

Interest and other income was $66,000 for the year ended December 31, 2010 as compared with $414,000 in the comparable period of 2009. This decrease is due to the sale of all our discontinued assets in 2009.

Interest expense, net of interest capitalization

Interest expense was zero for the year ended December 31, 2010, as compared to $185,000 for the comparable period of 2009. This decrease is due to the sale all of our discontinued assets over 2009.

Comparison of Years Ended December 31, 2009 and 2008

Results of Continuing Operations

	For the Years Ended December 31,
	2009		2008			2009		2008
Production:					Average Price:
Oil (Mbbl):					Oil ($/Bbl):
France		328		365	France	$	57.17	$	93.32

Revenue and other operating income

Sales and other operating revenue

Sales and other operating revenue for the twelve months ended December 31, 2009 were $19.2 million, as compared to $34.2 million for the comparable period in 2008. This decrease is primarily due to the global decrease in oil prices and decreased production in 2009, as compared to the prior year. The decline in production of 37 mbbl is primarily a result of wells being shut in for workovers and of natural decline. The decrease in the average realized price for oil from $93.32 in 2008 to $57.17 in 2009 resulted in a decrease of revenue of $11.9 million, and the decline in production resulted in a decrease of revenue of $3.5 million.

The above table compares both volumes and prices received for oil for the twelve months ended December 31, 2009 and 2008. Oil 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 $8.4 million, or $25.60 per BOE produced for the twelve months ended December 31, 2009, as compared to $9.3 million, or $25.37 per BOE produced for the comparable period in 2008. This decrease is primarily due to the decrease in production.

Exploration expense

Exploration expense for the twelve months ended December 31, 2009 was $138,000, as compared to $1.2 million for the comparable period in 2008. The decrease is due to the elimination of the exploration staff in the Dallas office due to the relocation of our headquarters to Paris, France.

Depreciation, depletion and amortization

For the twelve months ended December 31, 2009, depreciation, depletion and amortization expense was $5.8 million, or $17.57 per BOE produced, as compared to $5 million, or $13.70 per BOE produced for the twelve months ended December 31, 2008. This increase is primarily due to the lower proved reserves assigned to our French assets at December 31, 2008 due to depressed oil prices and was partially offset by the decline in oil production of 37MBbl and increased reserves at December 31, 2009.

Impairment of oil and natural gas properties

Impairment charged in 2009 for continuing operations was zero compared to $2.3 million in 2008. The impairment was primarily a result of an impairment charge of $2 million for the undeveloped leasehold costs in Trinidad, due to management’s decision to exit Trinidad and discontinue our association with our registered agent in the country. Additionally, in April 2007, we sold our interest in ePsolutions for $3.4 million in cash and 50,000 shares of preferred stock with a value of $10.00 per share. Due to the rising cost of electricity and the deterioration of the deregulated electric market in Texas, ePsolutions has reduced their forecasted growth for the next several years. Accordingly, we have reduced our carrying value of our investment in ePsolutions by $300,000 which we believe more accurately reflects the current market value of this investment.

General and administrative

General and administrative expense was $20.4 million for the twelve months ended December 31, 2009, as compared to $13.0 million for the comparable period of 2008. Exceptional general and administrative includes stock compensation, cost incurred due to resignation of former officers, costs associated with subsidiary sales and costs associated with the Dallas office/relocation of headquarters.

General and administrative before stock compensation, cost incurred due to resignation of former officers, costs associated with subsidiary sales and costs associated with the Dallas office/relocation of headquarters

General and administrative expense was $11.3 million for the twelve months ended December 31, 2009, compared with $9.8 million for the comparable period of 2008. This decrease is primarily due to closing the Dallas office and relocating to Paris.

Stock compensation expense

Stock compensation expense was $3.6 million for the twelve months ended December 31, 2009, compared with $2.3 million for the comparable period of 2008. This increase is due to the change in the structure of Board compensation, effective beginning in 2009, whereby directors receive a greater portion of their compensation in stock rather than cash and a stock bonus that was granted to foreign office employees. The immediate vesting of grants made to employees in the Dallas office that have been terminated has been classified as “Cost associated with the Dallas office/relocation of corporate headquarters from Dallas, Texas to Paris, France” and are not reflected in this amount.

Cost incurred due to the resignation of former officers of the Company

The Company and Nigel Lovett, our former President and Chief Executive Officer, entered into a Separation and Mutual Release Agreement (the “Lovett Release”) in connection with his resignation from the Company in January 2009. Pursuant to the Lovett Release, Toreador amended certain terms and conditions of Mr. Lovett’s 2008 employment agreement (the “2008 Employment Agreement”) with Toreador. The terms of the 2008 Employment Agreement, as amended, provide for Toreador to: (i) pay Mr. Lovett all unpaid compensation earned but not paid, (ii) pay Mr. Lovett certain severance payments totaling $720,000 to be paid in 24 equal monthly installments, (iii) issue 90,000 shares of Toreador common stock to Mr. Lovett, and (iv) vest 6,800 shares of Toreador restricted stock held by Mr. Lovett. The cost associated with the Lovett Release totaled $832,000, which was recorded in the first quarter of 2009.

In June 2008, Michael FitzGerald resigned as Executive Vice President - Exploration and Production and Edward Ramirez resigned as Senior Vice President - Exploration and Production. Their Separation and Release Agreements provided for (i) each to receive one year of salary which together resulted in an expense of $600,000, and (ii) for Mr. FitzGerald the immediate vesting of 5,000 shares of restricted stock grants and for Mr. Ramirez the immediate vesting of 7,000 shares of restricted stock grants which together resulted in an expense of $35,000.

In addition in June 2008, three other employees resigned, which collectively resulted in an additional $304,000 of expense.

Cost associated with subsidiary sales

For the year ended December 31, 2009 we had $545,000 in legal and consulting expenses due to the sale of the Turkish and Hungarian subsidiaries, as compared to zero for the comparable period in 2008.

Cost associated with the Dallas office/ relocation of corporate headquarters from Dallas, Texas to Paris, France

For the year ended December 31, 2009 we had $4.0 million of costs associated with the Dallas office/ relocation of our headquarters to Paris, France. The major components are: 1) salaries and wages associated with Dallas office employees $919,000; 2) severance payments to terminated Dallas employees $1.7 million, which includes stock compensation of $866,000; 3) corporate restructuring expenses $847,000; 4) travel by Dallas office employees $322,000; 5) miscellaneous relocation costs $322,000 and 6) Dallas office rent $241,000. For the twelve months ended December 31, 2008, we did not have any such relocation costs.

Gain (loss) on oil derivative contracts

Loss on oil derivative contracts of $879,000 for the year ended December 31, 2009, as compared to a loss of $1.8 million for 2008.

The gain in 2009 represents the recognized gain on the commodity derivative contracts with Vitol S.A. Presented in the table below is a summary of the contracts entered into:

Type	Period	Barrels		Floor		Ceiling		Gain
Collar	July 1 — September 30, 2009		55,200	$	65.00	$	77.00	$	7
Collar	October 1 — December 30, 2009		55,200	$	65.00	$	77.00		—

Additionally, we recorded an unrecognized loss on the commodity derivative contracts for 2010, with Vitol S.A. Presented in the table below is a summary of the contracts entered into:

Type	Period		Barrels				Floor				Ceiling				(Loss)
Collar	January 1 – December 31, 2010			182,500			$	68.00			$	81.00			$	(886	)

The 2008 loss represents the recognized loss on the commodity derivative contracts with Total Oil Trading. Presented in the table below is a summary of the contracts entered into with the gain (loss) in thousands:

Type	Period	Barrels		Floor		Ceiling		Gain/(Loss)
Collar	January 1 — March 31, 2008		48,000	$	84.75	$	92.75	$	(19	)
Collar	April 1 — June 30, 2008		48,000	$	92.25	$	100.25		(2,239	)
Collar	July 1 — September 30, 2008		48,000	$	91.75	$	99.75		477
								$	(1,781	)

Foreign currency exchange gain (loss)

We recorded a gain on foreign currency exchange of $169,000 for the year ended December 31, 2009 as compared with a loss of $145,000 for the comparable period of 2008. This increase is primarily due to the strengthening of the Euro compared to the U. S. Dollar in 2009.

Gain on the early extinguishment of debt

For the year ended December 31, 2009, we repurchased $25.7 million principal amount of our 5% Convertible Senior Notes on the open market and through privately negotiated transactions for $21.3 million plus accrued interest and prepaid loan fees resulting in a gain of $3.3 million on the early extinguishment of debt. For the comparable period of 2008, we repurchased $6 million of the Convertible Senior Notes for $5.3 million plus accrued interest and prepaid loan fees resulting in a $458,535 gain on the early extinguishment of debt.

Interest and other income

Interest and other income was $251,000 for the year ended December 31, 2009 as compared with $775,000 in the comparable period of 2008. The decrease is due primarily to having a lower average cash balance in 2009, as compared to 2008.

Interest expense, net of interest capitalization

Interest expense was $3.4 million for the year ended December 31, 2009, as compared to $4.2 million for the comparable period of 2008. This decrease is due to the repurchase of $25.7 million principal of the Convertible Notes. This is offset by the amount recorded in 2008 for capitalized interest $1 million, as compared to $355,000 for the comparable period in 2009.

Provision for income taxes

For the year ended December 31, 2009 we reported an income tax benefit of $450,000, compared to an expense of $5.5 million for the same period of 2008. The reduction in income tax is primarily due to a decrease in the French tax provision due to a tax refund of 2008 French income tax in 2009 and a reduction in 2009 French taxable income.

Loss available to common shares

For the year ended December 31, 2009, we reported a loss from continuing operations net of taxes of $15.3 million, compared with a loss of $7.0 million for the same period of 2008. For the twelve months ended December 31, 2009 we recorded a loss available to common shares of $25.4 million versus a loss available to common shares of $108.6 million for the year ended December 31, 2008.

Other comprehensive income (loss)

The most significant element of comprehensive income, other than net income, is foreign currency translation. As of December 31, 2009, we had accumulated an unrealized gain of $4.6 million. For the year ended December 31, 2008, we had an unrealized loss of $5.3 million. This increase is primarily due to the strengthening of the Euro in 2009 as compared to the U.S. Dollar.

The functional currency of our operations in France is the Euro and The exchange rates used to translate the financial position of the French operations at December 31, 2009 and 2008 are shown below:

	December 31,
	2009		2008

Euro	$	1.4406	$	1.3917

Results of Discontinued Operations

In February 2009, the Board of Directors authorized management to retain Stellar Energy Advisors, based in London, UK, to manage a process to monetize its wholly owned subsidiary, Toreador Turkey, including the Company’s remaining 10% interest in the SASB, in addition to the onshore production, and 2.2 million net acres in exploration licenses that are currently held in Turkey. On September 30, 2009, the Company entered into the Share Purchase Agreement with Tiway, pursuant to which the Company agreed to sell 100% of the outstanding shares of Toreador Turkey to Tiway. The sale of Toreador Turkey was completed on October 7, 2009. This resulted in a financial gain of $1.9 million which was recorded in the fourth quarter of 2009.

In accordance with the covenants of the International Finance Corporation revolving credit facility, proceeds of the Petrol Ofisi sale were used to fully repay and retire the outstanding balance of $36.4 million, which includes $5.9 million of additional compensation and $500,000 for accrued interest and fees. Remaining proceeds will be used to retire a portion of the Notes and fund this year's capital program to meet minimum commitments associated with the Company's licenses.

Additionally, on September 30, 2009, the Company entered into the Quota Purchase Agreement with RAG, pursuant to which the Company agreed to sell 100% of its equity interests in Toreador Hungary to RAG. The sale of Toreador Hungary was completed on September 30, 2009. This resulted in a financial loss of $4.1 million which was recorded in the third quarter of 2009.

The results of operations of assets in the United States, Romania, Turkey and Hungary have been presented as discontinued operations in the accompanying consolidated statement of operations (see “Note 15 – Discontinued Operations”). Results for these assets reported as discontinued operations were as follows:

The table below compares discontinued operations for the years ended December 31, 2009 and 2008:

	Year Ended December 31
	2009			2008
	(In thousands)
Revenue and other operating income
Sales and other operating revenue	$	4,545		$	28,226
Costs and expenses:
Lease operating		886			7,971
Exploration expense		868			4,582
Impairment of oil and natural gas properties and intangible assets		10,725			82,951
Depreciation, depletion and amortization		157			28,148
Dry hole costs		1,318			-
General and administrative		3,424			2,445
(Gain) loss on sale of properties		(3,583	)		123
Total costs and expenses		13,795			126,220
Operating loss		(9,250	)		(97,994	)
Other income (expense):
Loss on early extinguishment of debt		(4,881	)		-
Foreign currency exchange		3,822			(342	)
Interest and other income		414			1,004
Interest expense		(185	)		(3,679	)
Loss before taxes		(10,080	)		(101,011	)
Income tax provision		-			574
Loss from discontinued operations	$	(10,080	)	$	(101,585	)

	For the Years Ended December 31,
	2009		2008			2009		2008
Production:					Average Price:
Oil (MBbl):					Oil ($/Bbl):
Turkey		39		56	Turkey		49.78		93.21
Romania		-		3	Romania		-		57.97
Total		39		59	Total average oil price		49.78		91.25
Gas (MMcf):					Gas ($/Mcf):
Turkey		301		1,840	Turkey		8.64		11.14
Romania		-		446	Romania		-		5.32
Total		301		2,286	Total average gas price		8.64		10.00
MBOE:					$/ BOE:
Turkey		89		363	Turkey		50.94		70.88
Romania		-		77	Romania		-		32.99
Total		89		440	Total average price per BOE		50.94		64.20

Revenue and other operating income

Sales and other operating revenue

Sales and other operating revenue for the twelve months ended December 31, 2009 were $4.5 million, as compared to $28.2 million for the comparable period in 2008. This decrease is primarily due to the sale of our 26.75% interest in the SASB to Petrol Ofisi, in March 2009, followed by the sale of Toreador Turkey to Tiway in October 2009 and the disposal of our Romanian operations in January 2009. Also the decrease in oil and natural gas prices in 2009, when compared to 2008 added to the decrease.

Total costs and expenses

Lease operating

Lease operating expense was $886,000 for the twelve months ended December 31, 2009, as compared to $8.0 million, for the comparable period in 2008. This decrease is primarily due to the sale of our 26.75% interest in the SASB to Petrol Ofisi, in March 2009, followed by the sale of Toreador Turkey to Tiway in October 2009 and the disposal of our Romanian operations in January 2009.

Exploration expense

Exploration expense for the twelve months ended December 31, 2009 was $868,000, as compared to $4.6 million for the comparable period in 2008. This decrease is primarily due to the sale of our 26.75% interest in the SASB to Petrol Ofisi, in March 2009, followed by the sale of Toreador Turkey to Tiway in October 2009 and the disposal of our Romanian operations in January 2009.

Dry hole and abandonment

Dry hole and abandonment cost for the twelve months ended December 31, 2009 was $1.3 million as compared to zero in 2008. In 2009 we drilled the Durusu#1, in offshore Turkey, which was a dry hole.

Depreciation, depletion and amortization.

For the twelve months ended December 31, 2009, depreciation, depletion and amortization expense was $157,000, as compared to $28.1 million for the twelve months ended December 31, 2008. This decrease is primarily due to the assets being held for sale which allowed us to suspend calculating depletion on these assets.

Impairment of oil and natural gas properties

Impairment charged in 2009 for discontinued operations was $10.7 million compared to $83.0 million in 2008. The 2009 impairment was a result of 1) the Company’s decision not to proceed with the Kiha pipeline in Hungary $5.4 million and 2) the decline in the fair market value of the South Akcakoca Sub-basin assets in Turkey $5.3 million. The 2008 impairment was due to:

(1) In 2008, the impairment charge in Turkey was a result of a decline in the fair market value of the Company’s interest in South Akcakoca Sub-Basin assets. In June 2008, we determined the fair market value based on a Letter of Intent to sell a 26.75% interest in the South Akcakoca Sub-Basin assets to Petrol Ofisi AS for $80.3 million. This sale price indicated that the fair value of our 36.75% working interest was approximately $103.8 million. The net book value of the Black Sea asset at June 30, 2008 was $157.3 million, resulting in an impairment of $53.5 million.

(2) In January 2009, the Company and Petrol Ofisi agreed to a revised purchase price of $55 million. This resulted in an impairment on assets held for sale, which is comprised of the 26.75% interest in the South Akcakoca Sub-basin assets, of $25.6 million.

(3) In December 2008, we incurred an additional $2.4 million impairment charge in Turkey for assets that were unrelated to the sale of South Akcakoca Sub-Basin assets. The impairment was a result of writing off an exploratory well where sufficient progress was not made to develop the area and a plan of development will not be prepared, by the operator, in the foreseeable future.

(4) When recording the acquisition of Madison Oil in 2002, we recorded $833,000 of goodwill associated with the Turkish assets. We periodically review the value of goodwill to determine if an impairment is required. The review at December 31, 2008, indicated that the total amount recorded for goodwill should be impaired. The reason for this impairment is due to the fair value of the Turkish subsidiary, based on the discounted present value of the oil and gas reserves being less than the carrying value of the Turkish subsidiary. This resulted in an impairment charge of $833,000.

(5) In December 2008, we recorded an impairment in Romania of $600,000 due to the net book value of the oil and natural gas properties exceeding future cash flows.

General and administrative

General and administrative expense was $3.4 million for the twelve months ended December 31, 2009, compared with $2.4 million for the comparable period of 2008. The increase is primarily due to the severance paid to employees in Turkey and Hungary, after the sale of those operations.

Gain/loss on sale of assets

For the year ended December 31, 2009, we recorded a gain on sale of assets of $3.6 million, compared to a loss of $123,000 for the comparable period of 2008. The table below shows the gain/(loss) by country:

	Year Ended December 31
	2009			2008
	(In thousands)

Turkey	$	1,811		$	-
Romania		5,846			-
Hungary		(4,074	)		-
United States of America		-			(123	)
Gain (loss) on sale of assets	$	3,583		$	(123	)

The gains are primarily attributable to the reclassification of Other Comprehensive Income, recorded on the balance sheet, to gain/(loss) on sale.

Loss on early extinguishment of debt

In accordance with the covenants of the International Finance Corporation revolving credit facility, proceeds of the Petrol Ofisi sale were used to fully repay and retire the outstanding balance of $36.4 million, which includes $5.9 million of additional compensation and $500,000 for accrued interest and fees. This resulted in a loss on the early extinguishment of debt of $4.9 million.

Foreign currency exchange

We recorded a gain on foreign currency exchange of $3.8 million for the year ended December 31, 2009 as compared with a $342,000 loss for the comparable period of 2008. This increase is primarily due to the strengthening of the U. S. Dollar compared to the Turkish Lira, Hungarian Forent and Romanian Lei.

Interest and other income

Interest and other income was $414,000 for the year ended December 31, 2009 as compared with $1 million in the comparable period of 2008. The decrease is due primarily to having a lower average cash balance in 2009, as compared to 2008.

Interest expense, net of interest capitalization

Interest expense was $185,000 million for the year ended December 31, 2009, as compared to $3.7 million for the comparable period of 2008. This decrease is due to the repayment of the facility with the International Finance Corporation In March 2009.

Selected Quarterly Financial Data

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 is 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,
2010:
Revenue/other operating income	$	5,511		$	20,946		$	6,563		$	7,744
Total costs and expenses		7,330			6,951			5,928			13,287
Income (loss) from continuing
operations, net of tax		(6,904	)		6,550			(2,604	)		(5,792	)
Income (loss) from discontinued
operations, net of tax		(575	)		(247	)		(290	)		372
Net income (loss)		(7,479	)		6,303			(2,894	)		(5,420	)
Income (loss) available
to common shares		(7,479	)		6,303			(2,894	)		(5,420	)
Basic income (loss) available to
common shares per share		(0.32	)		0.26			(0.12	)		(0.22	)
Diluted income (loss) available
to common shares per share		(0.32	)		0.26			(0.11	)		(0.22	)
For the year ended December 31,
2009:
Total revenues	$	3,387		$	4,504		$	5,205		$	6,140
Total costs and expenses		8,471			8,748			7,012			11,184
Income (loss) from continuing
operations, net of tax		(5,923	)		(601	)		(1,941	)		(6,867	)
Income (loss) from discontinued
operations, net of tax		(4,953	)		3,483			(10,518	)		1,908
Net income (loss)		(10,876	)		2,882			(12,459	)		(4,959	)
Income (loss) available to
common shares		(10,876	)		2,882			(12,459	)		(4,959	)
Basic income (loss) available to
common shares per share		(0.54	)		0.14			(0.59	)		(0.24	)
Diluted income (loss) available to
common shares per share		(0.54	)		0.14			(0.59	)		(0.24	)

Off-balance sheet arrangements

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

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 prices 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 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 Prices

We market our oil production primarily on a spot market basis. As a result, our earnings could be affected by changes in oil prices, regulatory matters or demand for oil. As market conditions dictate, from time to time we will lock in future oil 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.

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.

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." Currently we have the following derivative outstanding.

Type	Period	Barrels		Floor		Ceiling

Collar	January 1, 2010 - December 31, 2010		182,500	$	68.00	$	81.00

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 commodity prices.

Item 8. Financial Statements and Supplementary Data.

The Reports of Independent Registered Public Accounting Firms and Consolidated Financial Statements are set forth beginning on page F-1 of this Annual Report on Form 10-K and are incorporated herein.

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

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

None.

Item 9A. Controls and Procedures

Corporate Disclosure Controls

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our chief executive officer and chief financial officer, has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended, which we refer to as the Exchange Act) as of the end of the period covered by this report. Based on this evaluation, our chief executive officer and chief financial officer have concluded that, as of the end of such period, these controls and procedures are effective to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission's rules and forms. These disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the report that we file or submit is accumulated and communicated to our management, including our chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

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 Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended. 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.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.

We carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial 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 the Chief Financial Officer concluded that our disclosure controls and procedures as of December 31, 2010 were effective.

In order to evaluate the effectiveness of our internal control over financial reporting as of December 31, 2010, as required by Section 404 of the Sarbanes-Oxley Act of 2002, our management, with the participation of the Company's Chief Executive Officer and Chief Financial Officer, conducted an assessment, including testing, based on the criteria set forth in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the "COSO Framework"). Based on such assessment, management has concluded that our internal control over financial reporting is effective as of December 31, 2010.

Ernst & Young Audit, 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, 2010, has issued an attestation report on our internal control over financial reporting as of December 31, 2010, which is included in Item 8. "Financial Statements".

Change in Internal Control over Financial Reporting

During 2010 and implemented in the quarter ended December 2010, we took the following actions to address a material weakness identified in our Annual Report on Form 10-K for the year ended December 31, 2009:

Hired additional staff, as well as increased external accounting resources with respect to the financial consolidation process, the preparation and review of sensitive calculations and spreadsheets.

Implemented additional review and reconciliation policies and procedures. In addition, Deloitte Conseil conducted review of key accounting and financial reporting procedures.

Upgraded our accounting and consolidation software as well as implemented certain software designed to assist in the preparation of annual and quarterly reports.

In addition, the Company also strengthened its internal control regarding contracts, guarantees and other commitments approval.

We believe these measures have adequately addressed the material weaknesses identified in our Annual Report on Form 10-K for the year ended December 31, 2009 and have strengthened our internal controls over financial reporting. We are committed to continuing to improve our internal control processes and will continue to review our financial reporting controls and procedures.

Except as otherwise indicated above, there have been no changes in our internal control over financial reporting during the quarter ended December 31, 2010 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

Item 9B. Other Information.

None.

Item 10. Directors, Executive Officers 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 2011 Annual Meeting of Stockholders, 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 2011 Annual Meeting of Stockholders 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 2011 Annual Meeting of Stockholders 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 2011 Annual Meeting of Stockholders 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 registered public accounting firms for services in 2010 and 2009 and (ii) audit committee's pre-approval policies and procedures for audit and non-audit services, will be set forth in our Proxy Statement relating to the 2011 Annual Meeting of Stockholders and that is incorporated herein by reference.

PART IV

ITEM 15. Exhibits and Financial Statement Schedules.

The following documents are filed as part of this report:

1. Index to Consolidated Financial Statements, Reports of Independent Registered Public Accounting Firms, Consolidated Balance Sheets as of December 31, 2010 and 2009, Consolidated Statements of Operations and Comprehensive Income (Loss) for each of the three years in the period ended December 31, 2010, Consolidated Statements of Changes in Stockholders' Equity for each of the three years in the period ended December 31, 2010, Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 2010, 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.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Amendment No. 1 on Form 10-K/A to be signed on its behalf by the undersigned, thereunto duly authorized.


April 7, 2011		TOREADOR RESOURCES CORPORATION

		/s/ Craig M. McKenzie
		Craig M. McKenzie
		President and Chief Executive Officer

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/ Craig M. McKenzie	President, Chief Executive Officer and Director	April 7, 2011
Craig M. McKenzie	(Principal Executive Officer)

/s/ Marc Sengès	Chief Financial Officer	April 7, 2011
Marc Sengès	(Principal Financial and Accounting Officer)

/s/ Peter Hill*	Chairman and Director	April 7, 2011
Peter Hill

/s/ Ian Vann*	Director	April 7, 2011
Ian Van

/s/ Bernard Polge de Combret*	Director	April 7, 2011
Bernard Polge de Combret

/s/ Herbert Williamson*	Director	April 7, 2011
Herbert Williamson

/s/ Adam Kroloff*	Director	April 7, 2011
Adam Kroloff

* By Marc Sengès as attorney-in-fact.

INDEX TO EXHIBITS

Exhibit Number		Description
2.1		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 (previously filed as Exhibit 10.1 to the Current Report on Form 8-K filed on August 6, 2007 and incorporated herein by reference).

2.2		Letter of Intent by and between Toreador Turkey Limited and Toreador Turkey Limited, Ankara Turkey Branch, and PETROL OFISI AS, dated August 8, 2008 (previously filed as Exhibit 2.1 to the Current Report on Form 8-K filed on August 13, 2008 and incorporated herein by reference).

2.3		Assignment Agreement between PETROL OFISI AS, PETROL OFISI ARAMA URETIM SANAYI ve TICARET ANONIM SIRKETI and Toreador Turkey Limited, Toreador Turkey Limited, Ankara Turkey Branch and Toreador Resources Corporation, dated September 17, 2008 (previously filed as Exhibit 2.2 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 and incorporated herein by reference).

2.4		Amendment Protocol dated January 30, 2009 relating to the Assignment Agreement between PETROL OFISI AS, PETROL OFISI ARAMA URETIM SANAYI ve TICARET ANONIM SIRKETI and Toreador Turkey Limited, Toreador Turkey Limited, Ankara Turkey Branch and Toreador Resources Corporation, dated September 17, 2008 (previously filed as Exhibit 2.1 to the Current Report on Form 8-K filed on February 4, 2009 and incorporated herein by reference).

3.1		Restated Certificate of Incorporation of Toreador Resources Corporation (previously filed as Exhibit 3.1 to the Current Report on Form 8-K filed on March 29, 2005 and incorporated herein by reference).

3.2		Certificate of Amendment of Restated Certificate of Incorporation of Toreador Resources Corporation, dated June 3, 2010 (previously filed as Exhibit 3.1 to the Current Report on Form 8-K filed on June 7, 2010 and incorporated herein by reference).

3.3		Fourth Amended and Restated Bylaws of Toreador Resources Corporation (previously filed as Exhibit 3.1 to the Current Report on Form 8-K filed on November 13, 2007 and incorporated herein by reference).

4.1		Certificate of Designation, Preferences and Rights of Series B Preferred Stock (previously filed as Exhibit 3.1 to the Current Report on Form 8-K filed on November 24, 2008 and incorporated herein by reference).

4.2		Indenture dated as of September 27, 2005 by and between Toreador Resources Corporation and The Bank of New York Trust Company, N.A. (previously filed as Exhibit 4.19 to the Registration Statement on Form S-3 (333-129628) filed on November 10, 2005 and incorporated herein by reference).

4.3		Rights Agreement dated as of November 20, 2008 between Toreador Resources Corporation and American Stock Transfer, as Rights Agent (previously filed as Exhibit 4.1 to the Form 8-A filed on November 24, 2008 and incorporated herein by reference).

4.4		Indenture dated as of February 1, 2010, by and between Toreador Resources Corporation and The Bank of New York Trust Company, N.A. (previously filed as Exhibit 4.1 to the Current Report on Form 8-K filed on February 3, 2010 and incorporated herein by reference).

10.1+		Toreador Resources Corporation Amended and Restated 1990 Stock Option Plan, effective as of September 24, 1998 (previously filed as Exhibit 10.4 to the Annual Report on Form 10-K for the year ended December 31, 2004 and incorporated herein by reference).

Exhibit Number		Description
10.2+		Amendment Number One to Toreador Resources Corporation Amended and Restated 1990 Stock Option Plan (previously filed as Exhibit 10.4 to the Annual Report on Form 10-K for the year ended December 31, 2007 and incorporated herein by reference).

10.3+		Amendment Number Two to Toreador Resources Corporation Amended and Restated 1990 Stock Option Plan (previously filed as Exhibit 10.5 to the Annual Report on Form 10-K for the year ended December 31, 2007 and incorporated herein by reference).

10.4+		Toreador Resources Corporation Amended and Restated 1994 Non-employee Director Stock Option Plan (previously filed as Exhibit 10.7 to the Annual Report on Form 10-K for the year ended December 31, 2007 and incorporated herein by reference).

10.5+		Toreador Resources Corporation 2002 Stock Option Plan (previously filed as Exhibit 10.8 to the Annual Report on Form 10-K for the year ended December 31, 2007 and incorporated herein by reference).

10.6+		Amendment Number One to the Toreador Resources Corporation 2002 Stock Option Plan (previously filed as Exhibit 10.9 to the Annual Report on Form 10-K for the year ended December 31, 2007 and incorporated herein by reference).

10.7+		Toreador Resources Corporation 2005 Long-Term Incentive Plan (previously filed as Exhibit 10.1 to Toreador Resources Corporation Current Report on Form 8-K filed on May 23, 2005 and incorporated herein by reference).

10.8+		Amendment Number One to Toreador Resources Corporation 2005 Long-Term Incentive Plan (previously filed as Exhibit 10.1 to the Current Report on Form 8-K filed on May 12, 2006 and incorporated herein by reference).

10.9+		Amendment Number Two to Toreador Resources Corporation 2005 Long-Term Incentive Plan (previously filed as Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2008 and incorporated herein by reference).

10.10+		Amendment Number Three to Toreador Resources Corporation 2005 Long-Term Incentive Plan (previously filed as Exhibit 4.7 to the Registration Statement on Form S-8 filed on May 15, 2008 and incorporated herein by reference).

10.11		Amendment Number Four to Toreador Resources Corporation 2005 Long-Term Incentive Plan (previously filed as Appendix B to the Preliminary Proxy Statement on Schedule 14A filed on April 19, 2010 and incorporated herein by reference).

10.11+		Employment Agreement of Nigel Lovett dated March 14, 2007 (previously filed as Exhibit 10.33 to the Registration Statement on Form S-1 filed on May 8, 2007 and incorporated herein by reference).

10.12		Contract for the Supply of Crude Oil from the Parisian Basin, effective January 1, 1997, between Elf Antwar France and Midland Madison Petroleum Company (n/k/a Toreador Energy France) (previously filed as Exhibit 10.43 to the Annual Report on Form 10-K for the year ended December 31, 2007 and incorporated herein by reference).

10.13		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 on Form 10-Q for the quarter ended September 30, 2007, File No. 0-2517, and incorporated hereby by reference).

10.14+		Release Agreement by and between David M. Brewer and Toreador Resources Corporation dated March 24, 2008 (previously filed as Exhibit 10.5 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2008 and incorporated herein by reference).

Exhibit Number		Description
10.15+		2008 Discretionary Employee Bonus Policy (previously filed as Exhibit 10.10 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2008 and incorporated herein by reference).

10.16+		2008 Performance Goals and Payout Amounts (previously filed as Exhibit 10.11 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2008 and incorporated herein by reference).

10.17+		Summary Sheet — 2008 Director Compensation (previously filed as Exhibit 10.12 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2008 and incorporated herein by reference).

10.18		Waiver Letter dated May 3, 2008 by International Finance Corporation in favor of Toreador Resources Corporation, Toreador Turkey Ltd., Toreador Romania Ltd., Madison Oil France, SAS, Toreador Energy France S.C.S., and Toreador International Holding Limited Liability Company (previously filed as Exhibit 10.13 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, File No. 0-2517, and incorporated herein by reference).

10.19+		Form of Outside Director Stock Award Agreement (previously filed as Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2008 and incorporated herein by reference).

10.20+		Nigel Lovett Nonqualified Stock Option Agreement dated May 15, 2008 (previously filed as Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2008 and incorporated herein by reference).

10.21+		Nigel Lovett Incentive Stock Option Agreement dated May 15, 2008 (previously filed as Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2008 and incorporated herein by reference).

10.22+		Nigel Lovett Restricted Stock Agreement dated May 15, 2008 (previously filed as Exhibit 10.5 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2008 and incorporated herein by reference).

10.23+		Separation Agreement and Release dated June 27, 2008 by and between Toreador Resources Corporation and Michael J. FitzGerald (previously filed as Exhibit 10.7 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2008 and incorporated herein by reference).

10.24+		Separation Agreement and Release dated June 27, 2008 by and between Toreador Resources Corporation and Edward Ramirez (previously filed as Exhibit 10.8 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2008 and incorporated herein by reference).

10.25+		First Amendment dated July 3, 2008 to the Separation Agreement and Release between Edward Ramirez and Toreador Resources Corporation dated June 27, 2008 (previously filed as Exhibit 10.9 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2008 and incorporated herein by reference).

10.26		Parent Corporate Guaranty by PETROL OFISI AS in favor of Toreador Turkey Limited and Toreador Turkey Limited, Ankara Turkey Branch, dated September 17, 2008 (previously filed as Exhibit 10.1 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 and incorporated herein by reference).

10.27		Form of Employee Restricted Stock Agreement (previously filed as Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 and incorporated herein by reference).

Exhibit Number		Description
10.28+		Summary Sheet regarding changes in Director Compensation (July 2008) (previously filed as Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 and incorporated herein by reference).

10.29+		Settlement Agreement, dated January 22, 2009, among Toreador Resources Corporation, Nanes Balkany Partners I LP, John M. McLaughlin, Nigel J. Lovett, Craig M. McKenzie, Julien Balkany, and Peter Hill (previously filed as Exhibit 10.1 to the Current Report on Form 8-K filed on January 27, 2009 and incorporated herein by reference).

10.30+		Resignation and Mutual Release Agreement, dated January 22, 2009, between Toreador Resources Corporation and John M. McLaughlin (previously filed as Exhibit 10.2 to the Current Report on Form 8-K filed on January 27, 2009 and incorporated herein by reference).

10.31+		Separation and Mutual Release Agreement, dated January 22, 2009, between Toreador Resources Corporation and Nigel J. Lovett (previously filed as Exhibit 10.3 to the Current Report on Form 8-K filed on January 27, 2009 and incorporated herein by reference).

10.32+		Form of McLaughlin/Lovett Indemnity Agreement, dated January 22, 2009, for John M. McLaughlin and Nigel J. Lovett (previously filed as Exhibit 10.4 to the Current Report on Form 8-K filed on January 27, 2009 and incorporated herein by reference).

10.33+		Form of Director Indemnity Agreement, dated January 22, 2009, for current directors (previously filed as Exhibit 10.5 to the Current Report on Form 8-K filed on January 27, 2009 and incorporated herein by reference).

10.34+		Letter Agreement, dated January 22, 2009, between Toreador Resources Corporation and Craig M. McKenzie (previously filed as Exhibit 10.6 to the Current Report on Form 8-K filed on January 27, 2009 and incorporated herein by reference).

10.35+		Retention Agreement dated March 19, 2009 by and between Toreador Resources Corporation and Charles Campise (previously filed as Exhibit 10.1 to the Current Report on Form 8-K filed on March 23, 2009 and incorporated herein by reference).

10.36+		Employment Agreement by and between Toreador Resources Corporation and Craig McKenzie, dated August 24, 2009 (previously filed as Exhibit 10.1 to the Current Report on Form 8-K filed on August 24, 2009 and incorporated herein by reference)

10.37+		Employment Agreement by and between Toreador Resources Corporation and Marc Sengès dated September 15, 2009 (previously filed as Exhibit 10.1 to the Current Report on Form 8-K filed on September 17, 2009 and incorporated herein by reference).

10.38		Quota Purchase Agreement, dated September 30, 2009, between Toreador Resources Corporation and Rohöl-Aufsuchungs Aktiengesellschaft (previously filed as Exhibit 10.1 to the Current Report Form 8-K filed on October 6, 2009 and incorporated herein by reference).

10.39		Share Purchase Agreement dated September 30, 2009 among Toreador Resources Corporation, Tiway Oil BV and Tiway Oil AS (previously filed as Exhibit 10.1 to the Current Report on Form 8-K filed on October 6, 2009 and incorporated herein by reference).

10.40		Investment Agreement dated May 10, 2010 by and between Toreador Energy France S.C.S. and Hess Oil France (previous filed as Exhibit 10.1 to the Current Report on Form 8-K filed on May 10, 2010 and incorporated herein by reference).

12.1		Computation of Ratio of Earnings to Fixed Charges. (previously filed with our Annual Report on Form 10-K for the year ended December 31, 2010 and incorporated herein by reference).

21.1		Subsidiaries of Toreador Resources Corporation. (previously filed with our Annual Report on Form 10-K for the year ended December 31, 2010 and incorporated herein by reference).

23.1		Consent of Ernst and Young Audit. (previously filed with our Annual Report on Form 10-K for the year ended December 31, 2010 and incorporated herein by reference).
23.2		Consent of Grant Thornton LLP. (previously filed with our Annual Report on Form 10-K for the year ended December 31, 2010 and incorporated herein by reference).

23.3		Consent of Gaffney, Cline & Associates Ltd. (previously filed with our Annual Report on Form 10-K for the year ended December 31, 2010 and incorporated herein by reference).

24.1		Power of Attorney (included as part of the signature page). (previously filed with our Annual Report on Form 10-K for the year ended December 31, 2010 and incorporated herein by reference).

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

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

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

99.1		French Ministry Documentation (previously filed as Exhibit 99.1 to the Amended Annual Report on Form 10-K/A for the year ended December 31, 2006 and incorporated herein by reference).

99.2		Report of Gaffney, Cline & Associates Ltd. (previously filed as Exhibit 99.2 to our Annual Report on Form 10-K for the year ended December 31, 2010 and incorporated herein by reference).

* Filed herewith

+ Management contract or compensatory plan

TOREADOR RESOURCES CORPORATION

Item 8. Financial Statements and Supplementary data

INDEX TO CONSOLIDATED FINANCIAL

STATEMENTS


	Page
Report of Ernst & Young Audit, Independent Registered Public Accounting Firm	F-1

Report of Grant Thornton LLP, Independent Registered Public Accounting Firm		F-3

Financial Statements

Consolidated Balance Sheets as of December 31, 2010 and 2009		F-4

Consolidated Statements of Operations and Comprehensive Income (Loss) for each of the three years in the
period ended December 31, 2010, 2009 and 2008		F-5

Consolidated Statements of Changes in Stockholders' Equity for each of the three years in the period
ended December 31, 2010, 2009 and 2008		F-6

Consolidated Statements of Cash Flows for each of the three years in the period ended December 31,
2010, 2009 and 2008		F-7

Notes to Consolidated Financial Statements		F-8

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders of Toreador Resources Corporation

We have audited the accompanying consolidated balance sheet of Toreador Resources Corporation (the “Company”) as of December 31, 2010, and the related consolidated statements of operations and comprehensive income (loss), changes in stockholders’ equity, and cash flows for the year then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit.

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

In our opinion, based the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Toreador Resources Corporation at December 31, 2010, and the consolidated results of its operations and its cash flows for the year then ended, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Toreador Resources Corporation's internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 16, 2011 expressed an unqualified opinion thereon.

Paris-La Défense,

March 16, 2011

Ernst & Young Audit

/s/ PHILIPPE DIU

F-1

TOREADOR RESOURCES CORPORATION

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders of Toreador Resources Corporation

We have audited Toreador Resources Corporation internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Toreador Resources Corporation’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.

In our opinion, Toreador Resources Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on the COSO criteria.

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 as of December 31, 2010, and the related consolidated statements of operations and comprehensive income (loss), changes in stockholders’ equity, and cash flows for the year then ended of Toreador Resources Corporation and our report dated March 16, 2011 expressed an unqualified opinion thereon.

Paris-La Défense,

March 16, 2011

Ernst & Young Audit

/s/ PHILIPPE DIU

F-2

REPORT

OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Shareholders

Toreador Resources Corporation

We have audited the accompanying consolidated balance sheets of Toreador Resources Corporation (a Delaware corporation) and subsidiaries as of December 31, 2009, and the related consolidated statements of operations and comprehensive income (loss), stockholders’ equity, and cash flows for each of the two years in the period ended December 31, 2009. 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.

As discussed in Note 1 to the consolidated financial statements, the Company has changed its reserve estimates and related disclosures as a result of adopting new oil and gas reserve estimation and disclosure requirements as of December 31, 2009.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Toreador Resources Corporation and subsidiaries. as of December 31, 2009, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America.

Dallas, Texas

March 16, 2010

/s/ GRANT THORNTON LLP

F-3

TOREADOR RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS

	December 31,
	2010			2009

	(In thousands, except share and per share data)
ASSETS
Current assets:
Cash and cash equivalents (Note 2)	$	21,616		$	8,712
Accounts receivable, net (Notes 2 and 4)		4,427			3,126
Income tax receivable (Note 9)		-			245
Other		2,959			3,593
Total current assets		29,002			15,676

Oil properties (Note 5)
Oil properties, gross		108,979			116,435
Accumulated depreciation, depletion and amortization		(43,201	)		(41,814	)
Oil properties, net		65,778			74,621

Investments (Note 6)		200			200
Goodwill		3,685			3,973
Other assets		1,634			2,685

Total assets	$	100,299		$	97,155

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	11,890		$	12,491
Deferred lease payable — current portion		113			107
Derivatives (Note 13)		1,330			886
Current portion of long-term debt (Note 7)		-			32,385
Income taxes payable (Note 9)		6,341			-
Total current liabilities		19,674			45,869

Long-term accrued liabilities		348			385
Deferred lease payable, net of current portion		329			442
Asset retirement obligations (Note 2)		6,866			6,733
Deferred income tax (Note 9)		14,618			15,358
Long-term debt (Notes 7 and 14)		34,394			22,231
Total liabilities		76,229			91,018

Stockholders' equity:
Common stock, $0.15625 par value, 30,000,000 shares
authorized; 25,849,705 in 2010 and 22,106,955 in
2009 shares issued		4,039			3,454
Additional paid-in capital		200,230			170,895
Accumulated deficit		(186,068	)		(176,578	)
Accumulated other comprehensive income		8,403			10,900
Treasury stock at cost, 721,027 shares for 2009 and
2010		(2,534	)		(2,534	)
Total stockholders' equity		24,070			6,137

Total liabilities and stockholders' equity	$	100,299		$	97,155

The accompanying notes are an integral part of these financial statements.

F-4

TOREADOR RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)

	For The Year Ended December 31,
	2010			2009			2008
	(In thousands, except share and per share data)
Revenues and other income: (Note 2)
Sales and other operating revenue	$	23,994		$	19,236		$	34,150
Other operating income		16,770			-			-
Total revenues and other income		40,764			19,236			34,150
Operating costs and expenses:
Lease operating expense		11,597			8,396			9,263
Exploration expense		1,977			138			1,224
Depreciation, depletion and amortization		4,390			5,256			4,637
Accretion on discounted assets and liabilities
(Note 2)		(89	)		507			357
Impairment of oil and natural gas properties and
intangible assets		-			-			2,282
General and administrative		15,177			20,360			13,042
Gain on sale of properties and other assets		-			(121	)		-
Loss on oil and gas derivative contracts (Note
13)		444			879			1,781
Total operating costs and expenses		33,496			35,415			32,586
Operating income (loss)		7,268			(16,179	)		1,564
Other (expense) income:
Foreign currency exchange gain (loss)		(874	)		169			(145	)
(Loss) gain on the early extinguishment of debt
(Note 7)		(4,256	)		3,596			1,233
Interest expense, net of interest capitalized		(4,758	)		(3,368	)		(4,170	)
Total other (expense) income		(9,888	)		397			(3,082	)
Income (loss) before taxes from continuing operations		(2,620	)		(15,782	)		(1,518	)
Income tax (benefit) provision (Note 9)		6,130			(450	)		5,502
Loss from continuing operations, net of income taxes		(8,750	)		(15,332	)		(7,020	)
Loss from discontinued operations, net of income taxes (Note 15)		(740	)		(10,080	)		(101,585	)
Net loss available to common shares	$	(9,490	)	$	(25,412	)	$	(108,605	)

Basic loss available to common shares per share: (Note 3)
From continuing operations, net of income taxes	$	(0.35	)	$	(0.75	)	$	(0.35	)
From discontinued operations, net of income
taxes		(0.03	)		(0.49	)		(5.13	)
	$	(0.38	)	$	(1.24	)	$	(5.48	)

Diluted loss available to common shares per
share: (Note 3)
From continuing operations, net of income taxes	$	(0.35	)	$	(0.75	)	$	(0.35	)
From discontinuing operations, net of income taxes		(0.03	)		(0.49	)		(5.13	)
	$	(0.38	)	$	(1.24	)	$	(5.48	)
Weighted average shares outstanding:
Basic		25,153			20,564			19,831
Diluted		25,165			20,564			19,831
Statement of Comprehensive Loss
Net loss	$	(9,490	)	$	(25,412	)	$	(108,605	)
Foreign currency translation adjustments		(2,497	)		4,561			(5,254	)
Foreign currency translation adjustments subsidiaries
sold		-			(30,161	)		—
Comprehensive income (loss)	$	(11,987	)	$	(51,012	)	$	(113,859	)

The accompanying notes are an integral part of these financial statements.

F-5

TOREADOR RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

	Common Stock (in thousands)			Common Stock ($)			Additional paid in capital ($)			Accumulated deficit ($)			Accumulated Other Comprehensive Income (loss) ($)			Treasury Stock (in thousands)		Treasury Stock ($)			Total Stockholders' Equity
Balance at December 31,
2007		20,567		$	3,214		$	163,955		$	(42,564	)	$	41,754			721	$	(2,534	)	$	163,825
Exercise of stock options		189			29			716			-			-			-		-			745
Issuance of restricted stock		228			36			(36	)		-			-			-		-			-
Issuance of common stock		-			-			-			-			-			-		-			-
Stock option expense		-			-			94			-			-			-		-			94
Amortization of deferred stock
compensation		-			-			2,231			-			-			-		-			2,231
Net loss		-			-			-			(108,605	)		-			-		-			(108,605	)
Foreign currency translation
adjustment		-			-			-			-			(5,254	)		-		-			(5,254	)
Tax effect of restricted stock		-			-			(444	)		-			-			-		-			(444	)
Payment of equity issuance
costs		-			-			-			-			-			-		-			-
Other		-			-			(32	)		-			-			-		-			(32	)

Balance at December 31,
2008		20,984		$	3,279		$	166,484		$	(151,169	)	$	36,500			721	$	(2,534	)	$	52,560
Exercise of stock options		31			5			109			-			-			-		-			114
Return stock options
exercised		(30	)		(5	)		(158	)		-			-			-		-			(163	)
Issuance of restricted stock,
net of forfeitures		1,122			175			(175	)		-			-			-		-			-
Stock option expense		-			-			38			-			-			-		-			38
Amortization of deferred stock
compensation		-			-			4,618			-			-			-		-			4,618
Net loss		-			-			-			(25,412	)		-			-		-			(25,412	)
Foreign currency translation
adjustment		-			-			-			-			4,561			-		-			4,561
Foreign currency translation
adjustment subsidiaries sold		-			-			-			-			(30,161	)		-		-			(30,161	)
Tax effect of restricted stock		-			-			(21	)		-			-			-		-			(21	)

Balance at December 31,
2009		22,107		$	3,454		$	170,895		$	(176,578	)	$	10,900			721	$	(2,534	)	$	6,137
Exercise of stock options		5			1			15			-			-			-		-			16
Return of stock options
exercised		-			-			-			-			-			-		-			-
Issuance of restricted stock		288			45			(45	)		-			-			-		-			-
Issuance of common stock		3,450			539			28,786			-			-			-		-			29,325
Amortization of deferred
stock compensation		-			-			3,214			-			-			-		-			3,214
Net loss		-			-			-			(9,490	)		-			-		-			(9,490	)
Foreign currency translation
adjustment		-			-			-			-			(2,497	)		-		-			(2,497	)
Tax effect of restricted stock		-			-			(146	)		-			-			-		-			(146	)
Payment of equity
issuance costs		-			-			(2,489	)		-			-			-		-			(2,489	)

Balance at December 31,
2010		25,850		$	4,039		$	200,230		$	(186,068	)	$	8,403			721	$	(2,534	)	$	24,070

The accompanying notes are an integral part of these financial statements.

F-6

TOREADOR RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

	For The Year Ended December 31,
	2010			2009			2008
	(In thousands)
Cash flows from operating activities:
Net loss	$	(9,490	)	$	(25,412	)	$	(108,605	)
Adjustments to reconcile net loss to net cash provided by (used
in) operating activities:
Depreciation, depletion and amortization		4,390			5,413			32,784
Accretion on discounted assets and liabilities		(89	)		507			357
Amortization of deferred debt issuance costs		1,525			158			338
Stock based compensation		3,214			4,656			2,325
Deferred income taxes (liabilities) benefit		(740	)		968			-
Dry hole costs		-			1,318			-
Impairment of oil and natural gas properties		-			10,725			85,233
Gain on sale of properties and equipment		-			(121	)		-
Gain on sale of discontinued operations		-			(3,582	)		123
Loss (gain) on early extinguishment of debt — convertible notes		4,256			1,554			(458	)
Bad debt expense		(395	)		-			-
Unrealized loss on commodity derivatives		444			886			-
(Increase) decrease in accounts receivable		(906	)		(2,069	)		2,027
Decrease in income taxes receivable		245			(245	)		-
Decrease (increase) in other current assets		634			120			135
Decrease in other assets		651			(21	)		108
Increase in assets and liabilities held for sale		-			(3,050	)		604
(Decrease) increase in accounts payable and accrued liabilities		599			5,187			858
Decrease in deferred lease payable		(107	)		(114	)		(19	)
Increase (decrease) in income taxes payable		6,341			(4,223	)		956
Decrease in long-term accrued liabilities		(37	)		-			-
Net cash provided by (used in) operating activities		10,535			(7,345	)		16,766
Cash flows from investing activities:
Proceeds from sale of property and equipment		-			70,851			-
Additions to property and equipment		(1,503	)		(7,914	)		(10,702	)
Restricted cash		-			-			8,685
Proceeds from sale of oil and gas properties		8			-			-
Net cash (used in) provided by investing activities		(1,495	)		62,937			(2,017	)
Cash flows from financing activities:
Repayment of convertible notes		(54,616	)		-			-
Tax benefit related to restricted stock		(146	)		-			-
Issuance of convertible notes		31,631			-			-
Deferred debt issuance costs		(1,947	)		-			-
Proceeds from issuance of common stock, net of equity issuance
costs of $2,489		26,837			-			(32	)
Exercise of stock options		15			(49	)		745
Payment of long-term debt		-			(57,712	)		(5,275	)
Net cash provided by (used in) financing activities		1,774			(57,761	)		(4,562	)
Net increase (decrease) in cash and cash equivalents		10,814			(2,169	)		10,187
Effects of foreign currency translation on cash and cash equivalents		2,090			(3,979	)		(3,731	)
Cash and cash equivalents, beginning of period		8,712			14,860			8,404
Cash and cash equivalents, end of period	$	21,616		$	8,712		$	14,860
Supplemental disclosures:
Cash paid during the period for interest, net of interest capitalized	$	3,255		$	3,169		$	5,626
Cash paid during the period for income taxes	$	14		$	4,032		$	3,058
Non-cash investing and financing activities
Additions to oil and natural gas properties related to asset
retirement obligations		-			-			1,294

The accompanying notes are an integral part of these financial statements.

F-7

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010

NOTE 1 – DESCRIPTION OF BUSINESS

Toreador Resources Corporation ("Toreador") is an independent energy company engaged in the exploration and production of crude oil interests in developed and undeveloped oil properties in the Paris Basin, France. 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.

Certain previously recorded amounts at December 31, 2009 have been reclassified to conform to this period presentation.

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 reserves are the most significant estimates used. All of the reserve data in the Annual Report on Form 10-K for the year ended December 31, 2010 are estimates. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil. There are numerous uncertainties inherent in estimating quantities of proved crude oil reserve. The accuracy of any reserve estimates 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 that are ultimately recovered.

Other items subject to estimates and assumptions include the carrying amounts of oil properties, goodwill, asset retirement obligations, derivative financial instruments and deferred income tax assets. Actual results could differ significantly from those estimates.

CASH AND CASH EQUIVALENTS

Cash and cash equivalents include cash on hand, amounts due from banks and all highly liquid investments with original maturities of three months or less. We maintain our cash in bank deposit accounts. We have not experienced any losses in such accounts.

As of December 31, 2010 and 2009 we had $21.5 million and $8.6 million, respectively, on deposit in foreign banks.

CONCENTRATION OF CREDIT RISK AND ACCOUNTS RECEIVABLE

Financial instruments that potentially subject us to a concentration of credit risk consist principally of cash and cash equivalents, accounts receivable, and our hedging and derivative financial instruments. We place our cash with high-credit quality financial institutions. We currently sell oil to one customer, TOTAL. Substantially all of our accounts receivable are due from TOTAL, as purchaser of our oil production, and from our partner Hess Oil France in connection with certain personal general and administrative costs associated with, and invoiced to Hess Oil France pursuant to the Hess Investment Agreement dated as of May 10, 2010. We place our hedging and derivative financial instruments with financial institutions and other firms that we believe have high credit ratings.

We periodically review the collectability of accounts receivable and record an allowance for doubtful accounts on those amounts which are, in our judgment, unlikely to be collected. We have not had any significant credit losses in the past and we believe our accounts receivable are fully collectable with the exception of the current allowance.

F-8

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 (CONTINUED)

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. 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.

FINANCIAL INSTRUMENTS

The carrying amounts of financial instruments including cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities approximate fair value, at December 31, 2010 and 2009, due to the short-term nature or maturity of the instruments.

The current portion of long-term debt approximates the 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.

At December 31, 2009, the 5.00% Convertible Senior Notes, which had a book value of $54.6 million, were trading at or near par value, which would equal a fair market value of approximately $52.416 million.

At December 31, 2010, the New Convertible Senior Notes, which had a book value of $31.6 million, were trading at $166.51, which would equal a fair market value of approximately $52.6 million.

INVENTORIES

At December 31, 2010 and 2009, other current assets included $2.7 million, and $3.2 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 weighted average cost method.

OIL PROPERTIES

We follow the successful efforts method of accounting for oil 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 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 2010, 2009 and 2008 was $0, $355,000, and $1 million, respectively.

We record furniture, fixtures and equipment at cost.

F-9

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 (CONTINUED)

LOSS FROM DISCONTINUED OPERATIONS

In the fourth quarter of 2008 and during the first quarter of 2009, Toreador farmed out or sold all of its working interests in Romania to three different companies and closed its office; thus, we no longer have any operational involvement in Romania. This resulted in a gain of $5.8 million which was recorded in the first quarter of 2009. We retained a royalty of 1.5% of gross proceeds from oil and gas sales from the Fauresti Field. Lotus Petrol’s acquisition of Toreador’s Romanian assets in 2008 obliged it to pay an amount equal to 12.5% Gross Overriding Royalty Interest (GORRI) on all and any hydrocarbon production until the Fauresti wells have been plugged and abandoned. In order to verify such amounts, Lotus is obliged to provide Toreador with monthly production statements. These production statements were delivered late and Toreador has not yet received the outstanding GORRI payments for the period from 1 October 2009 to December 31, 2010. These outstanding payments for an aggregate amount of $384,000 have been demanded and Toreador is currently in correspondence with Lotus on ensuring that these overdue amounts are paid. Nevertheless the receivables have been fully off-set by a bad-debt allowance, even if the Company will use all available actions to obtain payment from Lotus.

On September 30, 2009, the Company entered into a Quota Purchase Agreement (the "Quota Purchase Agreement") with RAG (Rohöl-Aufsuchungs Aktiengesellschaft), a corporation organized under the laws of Austria ("RAG"), pursuant to which the Company agreed to sell 100% of its equity interests in Toreador Hungary Limited ("Toreador Hungary") to RAG for total consideration consisting of (1) a cash payment of US$5.4 million (€3.7 million) paid at closing, (2) US$435,000 (€300,000), which was held back subject to a post closing adjustment and was paid to us on November 5, 2009, and (3) a contingent payment of US$2.9 million (€2 million) to be paid upon post-transaction completion of agreements relating to certain assets of Toreador Hungary. The sale of Toreador Hungary was completed on September 30, 2009. The sale of Toreador Hungary resulted in a loss of $4.1 million.

DEPRECIATION, DEPLETION AND AMORTIZATION

We provide depreciation, depletion and amortization of our investment in producing oil 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, equipment and leasehold improvements are amortized over the shorter of their useful lives or lease term 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 the Financial Accounting Standards Board (FASB) Accounting Standard Codification (ASC) 360, "Property, Plant, and Equipment". We assess impairment of non-producing leasehold costs and undeveloped mineral and royalty interests periodically on a property-by-property basis. We charge any impairment in value to expense in the period incurred.

There was no impairment charged in 2010 and 2009 for continuing operations.

F-10

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 (CONTINUED)

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 FASB ASC 360, “Plant, Property and Equipment”. We assess impairment of non-producing leasehold costs and undeveloped mineral and royalty interests periodically on a property-by-property basis. We charge any impairment in value to expense in the period incurred.

The $2.3 million impairment in 2008 was a result of the following:

(1) We recorded an impairment charge of $2 million for the undeveloped leasehold costs in Trinidad, due to management’s decision to exit Trinidad and discontinue our association with our registered agent in the country.

(2) In April 2007, we sold our interest in ePsolutions for $3.4 million in cash and 50,000 shares of preferred stock with a value of $10.00 per share. Due to the rising cost of electricity and the deterioration of the deregulated electric market in Texas, ePsolutions has reduced their forecasted growth for the next several years. Accordingly, we have reduced our carrying value of our investment in ePsolutions by $300,000 which we believe more accurately reflects the current market value of this investment.

Impairment charged in 2010 for discontinued operations was zero as compared to $10.7 million in 2009. The 2009 impairment was a result of 1) the Company's decision not to proceed with the Kiha pipeline in Hungary for $5.4 million and 2) the decline in the fair market value of the South Akcakoca Sub-basin assets in Turkey for $5.3 million.

Impairment charged in 2009 for discontinued operations was $10.7 million as compared to $82.9 million in 2008. The 2009 impairment was a result of 1) the Company’s decision not to proceed with the Kiha pipeline in Hungary $5.4 million and 2) the decline in the fair market value of the South Akcakoca Sub-basin assets in Turkey $5.3 million. The 2008 impairment was due to:

(5) In December 2008, we recorded an impairment in Romania of $600,000 due to the net book value of the oil and natural gas properties exceeding future cash flows.

F-11

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 (CONTINUED)

BAD DEBT ALLOWANCE

An allowance for doubtful accounts is calculated by customer by customer basis according to the management review of the collectability

ASSET RETIREMENT OBLIGATIONS

We account for our asset retirement obligations in accordance with ASC 410, "Asset Retirement and Environmental Obligations", which requires us to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, we either settle the obligation for its recorded amount or incur a gain or loss upon settlement.

As of December 31, 2010, we updated our asset retirement obligations and assets based on the last reserve life estimates available to the Company and on higher retirement cost estimates. The combined effect of those changes was to decrease our asset retirement obligation by $96,767 and decrease our asset retirement obligations for the same amount.

The following table summarizes the changes in our asset retirement liability during the twelve months ended December 31, 2010 and for the year ended December 31, 2009:

	2010			2009
	(in thousands)
Asset retirement obligation at January 1	$	6,733		$	6,037
Asset retirement accretion expense		505			507
Foreign currency exchange loss (gain)		(469	)		189
Change in reserve life estimate		97			-
Asset retirement obligation at the end of the period	$	6,866		$	6,733

Goodwill

We account for goodwill in accordance with FASB Accounting Standards Codification No. 350 "Intangibles-Goodwill and Other" ("ASC 350"). Under ASC 350, goodwill and indefinite-lived intangible assets are not amortized but are reviewed annually (or more frequently if impairment indicators arise) for impairment. Goodwill fair value is estimated using discounted cash flow method.

We review annually at fiscal year end the value of goodwill recorded or more frequently if impairment indicators arise. We recognized $0, $0 and $883,000 goodwill impairment in 2010, 2009 and 2008 respectively. The impairment of goodwill in 2008 was due to the fair value of the Turkish subsidiary, based on the discounted present value of the oil and gas reserves being less than its carrying value. Goodwill was adjusted $288,000 in 2010 and $135,000 in 2009 for the foreign currency translation adjustment.

Revenue Recognition

Our French crude oil production accounts for substantially all of our oil sales. We sell our French crude oil to Total Raffinage Marketing ("TOTAL"), and recognize the related revenues when the production is delivered to TOTAL's refinery, typically via truck. At the time of delivery to the plant, title to the crude oil transfers to TOTAL. The terms of the contract with TOTAL 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 TOTAL 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 TOTAL's payment timing to ensure that receivables from TOTAL for crude oil sales are collectible. In 2010, 2009 and 2008 sales to TOTAL represents approximately 99%, 98% and 99%, respectively, of the Company's total sales and other operating revenue and approximately 61% and 62% of the Company's accounts receivable at December 31, 2010 and 2009, respectively.

F-12

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 (CONTINUED)

We recognize revenue for our remaining production when the quantities are delivered to or collected by the respective purchaser. Title to the produced quantities transfers to the purchaser at the time the purchaser collects or receives the quantities. Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices. The purchasers of such production have historically made payment for crude oil and natural gas purchases within thirty and sixty days of the end of each production month, respectively. We periodically review the difference between the dates of production and the dates we collect payment for such production to ensure that receivables from those purchasers are collectible. Taxes associated with production are classified as lease operating expense.

In accordance with the Hess Investment Agreement, Hess made a $15 million upfront payment (plus applicable VAT of $2.9 million) to TEF on June 10, 2010. We recorded this $15 million one-time payment as “Other operating income”. Under the Hess Investment Agreement, our subsidiary, TEF, is entitled to invoice Hess for all personal general and administrative expenses associated with its activities as operator under the exploration permits we hold and in which we transferred to Hess 50% of our interest pursuant to the Hess Investment Agreement. We invoice Hess Oil France for such administrative expenses based on time spent by our employees at an agreed hourly rate and we recognize other operating income as the general and administrative expense are incurred.

STOCK-BASED COMPENSATION

We account for stock-based compensation in accordance with FASB ASC 718, "Compensation — Stock Compensation" ASC 718 establishes the accounting for transactions in which an entity pays for employee services in share-based payment transactions. ASC 718 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.

FOREIGN CURRENCY TRANSLATION

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

INCOME TAXES

We are subject to income taxes in the United States and France. The current provision for taxes on income consists primarily of income taxes based on the tax laws and rates of the countries in which operations were conducted during the periods presented. All interest and penalties related to income tax is charged to general and administrative expense. We compute our provision for deferred income taxes using the liability method. Under the liability method, deferred income tax assets and liabilities are determined based on differences between financial reporting and income tax basis of assets and liabilities and are measured using the enacted tax rates and laws. The measurement of deferred tax assets is adjusted by a valuation allowance, if necessary, to reduce the future tax benefits to the amount, based on available evidence it is more likely than not deferred tax assets will be realized. We made a commitment to be fully reinvested in our international subsidiaries.

LEGAL FEES

We do not accrue for estimated legal fees or other related costs when accruing for loss contingencies, rather they are expensed as incurred.

F-13

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 (CONTINUED)

DEFERRED DEBT ISSUANCE COST

Deferred debt issue costs are amortized under the effective interest method over the term of the loan (i.e for New Convertible Senior Notes, from issuance to the earliest date on which holders may require the Company to repurchase all or a portion of their New Convertible Senior Notes) as a component of interest expense. Deferred debt issuance costs, which are included in other assets, totalled approximately $1.6 million and $2 million net of accumulated amortization of $261,000 and $766,000 as of December 31, 2010 and 2009, respectively.

TREASURY STOCK

At December 31, 2010 and 2009 we had 721,027 shares of treasury stock valued at a historical cost of approximately $2.5 million or $3.47 a share.

New Accounting Pronouncements

●	Oil and gas reserves must be reported using the un-weighted arithmetic average of the first day of the month price for each month within a 12 month period, rather than year-end prices;

●	Companies will be allowed to report, on an optional basis, probable and possible reserves;

●	Non-traditional reserves, such as oil and gas extracted from coal and shales, will be included in the definition of "oil and gas producing activities;"

●	Companies will be permitted to use new technologies to determine proved reserves, as long as those technologies have been demonstrated empirically to lead to reliable conclusions with respect to reserve volumes;

●	Companies will be required to disclose, in narrative form, additional details on their proved undeveloped reserves ("PUDs"), including the total quantity of PUDs at year end, and any material changes to PUDs that occurred during the year, investments and progress made to convert PUDs to developed oil and gas reserves and an explanation of the reasons why material concentrations of PUDs in individual fields or countries have remained undeveloped for five years or more after disclosure as PUDs; and

●	Companies will be required to report the qualifications and measures taken to assure the independence and objectivity of any business entity or employee primarily responsible for preparing or auditing reserves estimate.

We have adopted the disclosure requirements beginning with the year ended December 31, 2009.

In January 2010, the FASB issued guidance that clarifies and requires new disclosures about fair value measurements. The clarifications and requirement to disclose the amounts and reasons for significant transfers between Level 1 and Level 2, as well as significant transfers in and out of Level 3 of the fair value hierarchy, were adopted by the Company in the first quarter of 2010. The new guidance also requires that purchases, sales, issuances, and settlements be presented gross in the Level 3 reconciliation and that requirement is effective for fiscal years beginning after December 15, 2010 and for interim periods within those years, with early adoption permitted. Adoption of the guidance which only amends the disclosures requirements did not have significant impact on our financial statements.

F-14

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 (CONTINUED)

In February 2010, the FASB issued 2010-09, Amendments to Certain Recognition and Disclosure Requirements ("ASU 2010-09"). ASU 2010-09 amends ASC 855, Subsequent Events, by removing the requirement for an SEC filer to disclose the date through which subsequent events have been evaluated. Management's responsibility to evaluate subsequent events through the date of issuance remains unchanged. The Company adopted amendments to the Codification resulting from ASU 2010-09 on February 24, 2010. As ASU 2010-09 relates specifically to disclosures, the adoption of this standard had no impact on our condensed consolidated financial condition, results of operations or cash flows.

On July 21, 2010, the FASB issued ASU 2010-20, Disclosure about the Credit Quality of Financing Receivables and the Allowance for Credit Losses ("ASU 2010-20"). ASU 2010-20 amends existing disclosure guidance to require entities to provide extensive new disclosures in their financial statements about their financing receivables, including credit risk exposures and the allowance for credit losses. ASU 2010-20 is effective for fiscal and interim periods beginning after December 15, 2010. The Company will review the requirements under the standards to determine what impacts, if any, the adoption of the standard would have on our condensed consolidated financial statements.

F-15

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 (CONTINUED)

NOTE 3 — EARNINGS PER SHARE

In accordance with the provisions of FASB ASC 260, "Earnings per Share", 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.

	For The Year Ended December 31,
	2010			2009			2008
	(in thousands, except per share data)

Basic loss per share:
Numerator:
Loss from continuing operations, net of
income tax	$	(8,750	)	$	(15,332	)	$	(7,020	)
Loss from discontinued operations, net of
income tax		(740	)		(10,080	)		(101,585	)
Net loss available to common shareholders	$	(9,490	)	$	(25,412	)	$	(108,605	)

Denominator:
Weighted average common shares outstanding		25,153			20,564			19,831

Basic loss available to common shareholders
per share from:
Continuing operations	$	(0.35	)	$	(0.75	)	$	(0.35	)
Discontinued operations		(0.03	)		(0.49	)		(5.13	)
	$	(0.38	)	$	(1.24	)	$	(5.48	)

Diluted loss per share:
Numerator:
Loss from continuing operations, net of
income tax	$	(8,750	)	$	(15,332	)	$	(7,020	)
Loss from discontinued operations, net of
income tax		(740	)		(10,080	)		(101,585	)
Net loss available to common shareholders	$	(9,490	)	$	(25,412	)	$	(108,605	)

Denominator:
Weighted average common shares outstanding		25,165			20,564			19,831
Stock options, restricted stock and warrants		—	(1)		—	(1)		—	(1)
Conversion of preferred shares		—	(2)		—	(2)		—	(2)
Conversion of notes payable		—	(3)		—	(3)		—	(3)
Diluted shares outstanding		25,165			20,564			19,831

Diluted loss available to common
shareholders per share from:
Continuing operations	$	(0.35	)	$	(0.75	)	$	(0.35	)
Discontinued operations		(0.03	)		(0.49	)		(5.13	)
Diluted loss per share	$	(0.38	)	$	(1.24	)	$	(5.48	)
Anti-dilutive securities not included above are
as follows:
Stock options, restricted stock and
warrants		12			37			25
Preferred shares		—			—			—
5% notes payable		—			1,376			1,966

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

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

(3)	Conversion of the Company's 5.00% Convertible Senior Notes due 2025 would be anti-dilutive and the Company's 8.00%/7.00% Convertible Senior Notes due 2025 are not eligible for conversion in 2010 (subject to certain terms and conditions under the Indenture dated as of February 1, 2010) therefore, there are no dilutive shares.

F-16

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 (CONTINUED)

NOTE 4 – ACCOUNTS RECEIVABLE

Accounts receivable consisted of the following:

	December 31,
	2010			2009
	(in thousands)
Oil and natural gas sales receivables	$	3,843		$	2,072
Recoverable VAT		439			778
Other accounts receivable		539			276
Bad debt allowance		(395	)		-
	$	4,427		$	3,126

Accrued oil sales receivables are due from purchasers of oil production from our French wells for which the Company owns an interest. Oil sales are generally unsecured and such amounts are generally due within 30 days after the month of sale.

Other receivables and VAT at December 31, 2010 and 2009 consist of accrued interest receivable on time deposits, value added tax refunds and travel advances to employees.

NOTE 5 — OIL PROPERTIES

Oil properties consist of the following:

	December 31,
	2010			2009
	(in thousands)
Licenses and concessions	$	198		$	205
Producing leaseholds and intangible drilling costs		107,230			115,112
Furniture, fixtures and office equipment		1,551			1,118

		108,979			116,435
Accumulated depreciation, depletion and amortization		(43,201	)		(41,814	)

Total oil properties, net	$	65,778		$	74,621

F-17

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 (CONTINUED)

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.

	December 31,
	2010			2009
	(in thousands)
Capitalized exploratory well cost, beginning of the year	$	2,887		$	—
Additions to capitalized exploratory costs pending determination of proved
reserves		218			2,887
Foreign currency exchange gain (loss)		(229	)		—
Impairment		—			—

Capitalized exploratory well costs, end of year	$	2,875		$	2,887

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,
	2010		2009
	(in thousands)
Capitalized exploratory well cost that have been capitalized for a
period of one year or less	$	218	$	2,887
Capitalized exploratory well costs that have been capitalized for a
period greater than one year		2,657		—

Balance at end of year (included in oil properties)	$	2,875	$	2,887

NOTE 6 — INVESTMENT IN UNCONSOLIDATED ENTITY

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. In April 2007, we sold our interest in ePsolutions to ePsolutions for the following consideration: (i) $3.9 million in cash and (ii) 50,000 preferred shares of Series A in ePsolutions, and we recorded a gain on the sale of $2.3 million for the year ended December 31, 2007. At December 31, 2010, those 50,000 preferred shares in eP Solutions were recorded for $200,000, following an impairment of $300,000 occurred in 2008, based on the last transaction which occurred on ePsolutions stock. The Company has not identified any impairment indicator on this investment as compared to the value of the shares as of December 31, 2010.

F-18

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 (CONTINUED)

NOTE 7 — LONG-TERM DEBT

Long-term debt consisted of the following:

	December 31,		December 31,
	2010		2009
Convertible senior notes	$	34,394	$	54,616

Less: current portion		-		(32,385	)

Total long-term debt	$	34,394	$	22,231

Secured Revolving Facility with the International Finance Corporation

On December 28, 2006, we entered into a loan and guarantee agreement with International Finance Corporation. The loan and guarantee agreement provided for a $25 million facility which was a secured revolving facility with a maximum facility amount of $25 million which maximum facility amount would have increased 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 provided for an unsecured $10 million facility which was funded on December 28, 2006. Both the $25 million facility and the $10 million facility were to fund our operations in Turkey and Romania.

On March 3, 2009, we repaid and retired the facilities with the International Finance Corporation. The total amount of the payment was $36.4 million, which comprised $30 million principal, $5.9 million additional compensation due under the credit facility as a result of our repayment (such additional compensation calculated under the terms of the credit facility as a percentage of the Company's earnings before interest, tax, depreciation, amortization and exploration expense) and $500,000 for accrued interest and fees. As a result of the early extinguishment, we recorded a loss of $4.9 million for the twelve months ended December 31, 2009, which was recorded in discontinued operations.

5.00% CONVERTIBLE SENIOR NOTES DUE OCTOBER 1, 2025

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 5.00% Convertible Senior Notes bore interest at a rate of 5.00% per annum.

During 2008, the Company repurchased $6 million, face value, of the 5.00% Convertible Senior Notes on the open market for $5.3 million. In 2009 the Company repurchased $25.7 million face value of the 5.00% Convertible Senior Notes on the open market for $21.3 million, resulting in a gain on the early extinguishment of debt of $3.4 million after writing off deferred loan costs of approximately $1 million. On February 1, 2010, Toreador consummated an exchange transaction (the "Convertible Notes Exchange"). In the Convertible Notes Exchange, in exchange for (a) $22,231,000 principal amount of our outstanding 5.00% Convertible Senior Notes (the “Old Notes”) and (b) $9.4 million cash, we issued $31,631,000 aggregate principal amount of our 8.00%/7.00% Convertible Senior Notes (“the New Convertible Senior Notes”) and paid accrued and unpaid interest on the Old Notes.

F-19

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 (CONTINUED)

8.00%/7.00% CONVERTIBLE SENIOR NOTES DUE OCTOBER 1, 2025

F-20

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 (CONTINUED)

CHANGE IN AMORTIZATION OF ISSUE PREMIUM AND DEBT ISSUANCE COSTS

Based on this early redemption, the Company has decided that for a debt instrument that is puttable by the holder prior to the debt’s stated maturity date, it is preferable to amortize the related issuance costs and purchase premium over a period no longer than through the first put option date. For the same reason, the Company has elected to amortize under the effective interest rate method the cost associated with the New Convertible Senior Notes. The issue premium on the Convertible Notes Exchange and the costs associated with the issuance of its convertible senior notes will now be amortized over the term of the first puttable dates of these callable debts. In all prior periods, the issue premium and the debt issuance costs were amortized over the terms of the debt issuance (i.e., October 1, 2025 for both the 5.00% Convertible Senior Notes and the New Convertible Senior Notes). The effect of this change in estimate was to increase the interest expense by $1,153,805, increase the accretion impact (positive) by $190,194 (or increase net loss for $963,611 and increase basic and diluted loss per share by $0.04 for the twelve months ended December 31, 2010. The unamortized debt issuance costs included in other assets amounted to $1.6 million and $2.0 million as of December 31, 2010 and 2009, respectively.

The New Convertible Senior Notes have a first put option date on October 1, 2013 and will mature on October 1, 2025.

F-21

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 (CONTINUED)

NOTE 8 — CAPITAL

We account for registration rights agreements containing a contingent obligation to make future payments or otherwise transfer consideration under a registration payment arrangement. 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 FASB ASC 450 "Contingencies".

On February 12, 2010, we completed a registered underwritten public offering of 3,450,000 shares of common stock, including 450,000 shares of common stock acquired by the underwriters from us to cover over-allotment options. The net proceeds to Toreador from the offering were approximately $26.8 million, after deducting underwriting discounts, commissions and estimated offering expenses. We intended to use the net proceeds, together with cash on hand, to satisfy payment obligations arising from the holders' exercise, if any, of their right on October 1, 2010 to require the Company to repurchase its 5.00% Convertible Senior Notes and for general corporate purposes. Pending such use, we invested the net proceeds in mutual and money market funds and/or bank certificates of deposit. Following the repurchase of $32,256,000 aggregate principal amount of the 5.00% Convertible Senior Notes on October 1, 2010 and the redemption of the remaining $129,000 principal amount outstanding of the 5.00% Convertible Senior Notes on November 24, 2010, our sole long-term debt currently consists of the New Convertible Senior Notes for an aggregate principal amount of $31,631,000.

Toreador had zero shares of nonvoting Series A-1 Convertible Preferred Stock outstanding at December 31, 2010, 2009 and 2008. At the option of the holder, the Series A-1 Convertible Preferred Stock were convertible into common shares at a price of $4.00 per common share (conversion would amount to 450,000 Toreador common shares at December 31, 2007). The Series A-1 Convertible Preferred Stock accrues dividends at an annual rate of $2.25 per share payable quarterly in cash. At any time on or after November 1, 2007, we could elect to redeem for cash any or all shares of Series A-1 Convertible Preferred Stock. The optional redemption price per share was the sum of (1) $25.00 per share of the Series A-1 Convertible Preferred Stock plus (2) any accrued unpaid dividends, and such sum was 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 December 2007, all the Series A-1 Convertible Preferred Stock was converted into common shares.

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 Company and ParCon Consulting. At December 31, 2010 all 10,000 warrants were outstanding which expired on January 3, 2011.

For the twelve months ended December 31, 2010, the Company issued 287,750 shares of stock to employees and directors, of which 132,733 shares were immediately vested in accordance with the terms of the grants and 5,000 stock options were exercised under the terms of the option agreements. There were 332 forfeitures of restricted stock and stock options for the twelve months ended December 31, 2010.

NOTE 9 — INCOME TAXES

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

	2010				2009				2008
	(in thousands)
Current:
U.S. Federal		$	(7	)		$	(388	)		$	(5	)
U.S. State			-				-				(115	)
Foreign			5,982				(1,030	)			7,526
Deferred:
U.S. Federal			(146	)			(19	)			(443	)
Foreign			402				987				(887	)

		$	6,231			$	(450	)		$	6,076

The tax provision (benefit) has been allocated between
continuing operations and discontinued operations as
follows:
Provision (benefit) allocated to:
Continuing operations		$	6,130			$	(450	)		$	5,502
Discontinued operations			101				—				574

		$	6,231			$	(450	)		$	6,076

F-22

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 (CONTINUED)

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

	2010				2009				2008
	(in thousands)
Statutory tax at 34%		$	(1,108	)		$	(8,675	)		$	(34,860	)
Rate differences related to foreign operations			(170	)			150				13,706
Utilization of foreign net operating loss			—				(286	)			—
State income tax, net			—				—				(76	)
Foreign currency gain (loss) not taxable in foreign
jurisdictions			—				(1,978	)			498
Release of FIN 48 liability			(7	)			(314	)			—
Adjustments to valuation allowance			6,688				11,133				26,440
Other			828				(480	)			368

		$	6,231			$	(450	)		$	6,076

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, 2010 and 2009 were as follows:

	December 31,
	2010				2009
	(in thousands)
Deferred tax assets:
Net operating loss carryforward — United States		$	37,168			$	31,029
Net operating loss carryforward — Foreign			22				—
Restricted stock			467				370
Derivative			452				—
Other			114				114

Gross deferred tax assets			38,223				31,513
Valuation allowance			(38,223	)			(31,513	)

Net deferred tax assets		$	-			$	-

Deferred tax liabilities:
Oil properties capitalization and depreciation
methods			(16,991	)			(15,358	)
Other			2,373				—

Net deferred tax liabilities		$	(14,618	)		$	(15,358	)

F-23

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 (CONTINUED)

At December 31, 2010, Toreador had the following carryforwards available to reduce future taxable income (in thousands):


Jurisdiction	Expiry	Amount (in thousands)
United States	2011 — 2024	$	109,318
Hungary	unlimited	$	216

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,
	2010			2009
	(in thousands)
United States		$	37,168		$	31,029
Hungary			22			—

		$	37,190		$	31,029

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 (in thousands)
United States	$	109,318
Hungary	$	216

F-24

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 (CONTINUED)

In accordance with FASB ASC 740, "Income Taxes", we have elected to treat our foreign earnings as permanently reinvested outside the US and are not providing US tax expense on those earnings. The determination of the theoretical tax rate is not practicable.

We adopted provisions of FASB ASC 740, "Income Taxes" relating to uncertain tax positions. We recognize potential accrued interest and penalties related to unrecognized tax benefits within our global operations in income tax expense. For the years ended December 31, 2010 and 2009, we recognized $0 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.

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 provisions relating to uncertain tax provisions, 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 2010 we recognized $0 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, 2010:

Unrecognized tax benefit at January 1, 2010	$	7
Tax Year Closed		(7	)
Unrecognized tax benefit at December 31, 2010	$	-

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.

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

For the years ended December 31, 2010 and 2009 we recognized a current tax benefit related to restricted stock grants of approximately $0 and $0 and a deferred tax liability and a deferred tax benefit of approximately $0 and $21,000, respectively.

F-25

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 (CONTINUED)

NOTE 10 — PENSION, POST-RETIREMENT, AND POST-EMPLOYMENT OBLIGATIONS

Provisions for employee retirement indemnities amounted to $99,000 and $0 for the twelve months ended December 31, 2010 and December 31, 2009, respectively. Pension benefits, which only consist in retirement indemnities, have been defined only for the Company's French subsidiaries.

In 2009, we terminated our 401(k) retirement savings plan due to the Company closing the Dallas, Texas office and relocating to Paris France. Employees were 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 $0 in 2010, $37,701 in 2009 and $95,000 in 2008. Discretionary employer matches are determined annually by the board of directors and such discretionary matches amounted to $0 in 2010, 2009 and 2008.

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.

A summary of stock option transactions is as follows:

	2010					2009
	SHARES			WEIGHTED AVERAGE EXERCISE PRICE		SHARES			WEIGHTED AVERAGE EXERCISE PRICE
Outstanding at January 1		67,370		$	7.78		248,370		$	6.77
Granted		—			—		—			—
Exercised		(5,000	)	$	3.10		(31,000	)	$	3.67
Forfeited		(4,420	)		3.12		(150,000	)	$	6.96
Outstanding at the end of the
period		57,950		$	8.15		67,370		$	7.78
Exercisable at the end of the
period		57,950		$	8.15		67,370		$	7.78

The intrinsic value of the options exercised at December 31, 2010 was zero. For the twelve months ended December 31, 2010 and for the year ended December 31, 2009 we received cash from stock option exercises of $15,500 and $113,875, respectively. As of December 31, 2010, all outstanding options were 100% vested. As of December 31, 2010 and December 31, 2009, the total compensation cost related to non-vested stock options not yet recognized was zero.

F-26

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 (CONTINUED)

The following table summarizes information about the fixed price stock options outstanding at December 31, 2010:

		Number Outstanding			Number Exercisable
Exercise Price		Shares	Intrinsic Value (in thousands)		Shares	Intrinsic Value (in thousands)		Weighted Average Remaining Contractual Life in Years


	5.50	200	$	2	200	$	2	3.32
	5.50	40,250	403		40,250	403		3.32
	13.75	7,500	13		7,500	13		3.88
	16.90	10,000	-14		10,000	-14		4.38
		57,950	$	405	57,950	$	405	3.73

In May 2005, the Company's stockholders approved the Toreador Resources Corporation 2005 Long-Term Incentive Plan (the "Plan"). At the Company's 2010 Annual Meeting of Stockholders, the stockholders of the Company approved an amendment to the Plan which increased the authorized number of shares of Company common stock available under the Plan from 1,750,000 shares to 3,250,000 shares. Thus, the Plan, as amended, authorizes the issuance of up to 1,500,000 new shares of the Company's common stock to key employees, key consultants and outside directors of the Company.

At December 31, 2010, the Board of Directors has authorized a total of 287,750 shares of restricted stock to 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 or director and is recognized as an expense over the period the recipient performs related services. The restricted stock grants vest immediately or over up to a three-year period (depending on the grant), and the weighted average price of the stock on the date of the grants was $9.79 for the twelve months ended December 31, 2010. Stock compensation expense of $582,000 is included in the Statement of Operations for the three months ended December 31, 2010 and stock compensation expense of $ 3.2 million is included in the Statement of Operations for the twelve months ended December 31, 2010, which represents the cost recognized from the date of the grants through December 31, 2010. As of December 31, 2010, the total compensation cost related to non-vested restricted stock grants not yet recognized is approximately $2.9 million. This amount will be recognized as compensation expense over the next 36 months maximum.

On December 31, 2010, there were 1,318,421 remaining shares available for grant under the Plan.

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, 2010:

F-27

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 (CONTINUED)

	Shares			Weighted Average Grant-Date Fair Value
Non-vested at December 31, 2009		378,130		$	10.25
Shares granted		287,750		$	9.79
Shares vested		(298,708	)	$	9.45
Shares forfeited		(332	)		12.05
Non-vested at December 31, 2010		366,840		$	10.72

NOTE 12— COMMITMENTS AND CONTINGENCIES

We lease our office space under non-cancellable operating leases, expiring in 2014. The following is a schedule of minimum future rentals under our non-cancelable operating leases as of December 31, 2010 (in thousands):

	Rental		Sub-lease			Net Rental
	Expense		Income			Expense
2011		707		(232	)		475
2012		813		(232	)		582
2013		815		(232	)		583
2014		710		(174	)		536

	$	3,045	$	(868	)	$	2,176

Net rental expense totaled $278,154 in 2010, $442,144 in 2009 and $952,000 in 2008.

“Fallen Structures”

In 2005, two separate incidents occurred offshore Turkey in the Black Sea, which resulted in the sinking of two caissons (the "Fallen Structures") and the loss of three natural gas wells. The Company has not been requested to or ordered by any governmental or regulatory body to remove the caissons. Therefore, the Company believes that the likelihood of receiving such a request or order is remote and no liability has been recorded. In connection with the Company's sale of its 26.75% interest in the South Akcakoca Sub-Basin (“SASB”) to Petrol Ofisi in March 2009 and its sale of Toreador Turkey Ltd. (“Toreador Turkey”) to Tiway Oil BV ("Tiway") in October 2009, the Company agreed to indemnify Petrol Ofisi and Tiway, respectively, against and in respect of any claims, liabilities and losses arising from the Fallen Structures. The Company has also agreed to indemnify a third-party vendor for any claims made related to these incidents.

Momentum

In 2006, Tiway Turkey Limited (formerly Toreador Turkey Limited) entered into an agreement with Momentum Engineering LLC ("Momentum"). The agreement was an EPIC contract relating to the South Akcakoca Sub-Basin ("SASB") Project of which Tiway Turkey Limited was the then Operator. Momentum completed and delivered the major installation works, leaving some work outstanding, namely the removal of several flotation tanks from the Ayazli tripod. The Settlement and Release Agreement for the works, signed by Momentum, Tiway Turkey Limited and the Company on August 13, 2008 specifically included a statement that Momentum would undertake to remove the fallen tanks by September 30, 2008; however it did not do so. In September 2009, Türkiye Petrolleri A.O. ("TPAO") the current Operator for the SASB Project sought the removal of the flotation tanks. In Momentum's operation to remove the tanks in November 2009, one of the tanks fell to the seabed. Momentum stated it had no intention of removing the fallen tank and TPAO thus arranged for a third party contractor to remove the tank, at a cost of $118,000.

F-28

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 (CONTINUED)

This amount has now been invoiced to Tiway Turkey Limited by TPAO and a request for reimbursement of this sum has been sent to Momentum by Tiway Turkey Limited. Separately, Momentum has invoiced Tiway Turkey Limited the sum of $130,835 for the VAT it incurred for the removal of the tanks. This VAT invoice has been rejected by Tiway Turkey Limited. As at February 2011, Tiway Turkey Limited awaits a response from Momentum to its request for reimbursement of the $118,000. Pursuant to the Share Purchase Agreement of September 30, 2009, Tiway has reserved its right to pursue the Company for these reimbursement costs, should it become necessary. We are not aware of any change in the positions of Tiway towards TPAO nor that proceedings have been commenced between TPAO and Tiway. The Company believes that the risk associated with this matter is remote is remote and no liability has been recorded.

Netherby

On September 30, 2009, we completed the sale of Toreador Turkey, including with it Toreador Turkey's remaining 10% interest in the SASB license, to Tiway Oil A/S ("Tiway"). In connection with this sale, we agreed to indemnify Tiway against and in respect of any and all claims, liabilities, and losses arising from the Overriding Royalty. Toreador is treating the said indemnity as extending to Tiway Turkey Ltd (previously Tiway Turkey Ltd).

On September 6, 2010 English High Court proceedings were commenced by Hunnisett and Barker, as well as Netherby Investments Limited against Tiway Turkey Limited (previously Toreador Turkey Limited) and Toreador. The proceedings were served on Toreador on October 20, 2010. Tiway Turkey Limited was served with the proceedings on around December 8, 2010. In the said proceedings, Hunnisett and Barker now argue that an agreement was reached between the parties in around November 2008 regarding the Netherby Payment Amount in the sum of $7.2 million. In addition they argue that on a proper construction of the Netherby Agreement, they are entitled to continuing Overriding Royalty including on the 26.75% interest in the SASB licenses that was sold to Petrol Ofisi in March 2009 and/or to a capitalized sum of "not less than" $7.2 million. In addition or in the alternative, Hunnisett and Barker raise a wholly new claim for rectification of the Netherby Agreement on the basis they claim it does not reflect the true agreement of the parties. They seek rectification of the Netherby Agreement so that upon a sale such as the sale of the 26.75% interest in the SASB licenses that was sold to Petrol Ofisi in March 2009, the Netherby Agreement parties are required to first agree a capitalized sum to be paid to Hunnisett and Barker. Hunnisett and Barker also seek costs and interest.

On January 31, 2011 the Company and Tiway Turkey Limited filed its joint defense denying the majority of the claims asserted by Hunnisett and Barker. In its defense the Company and Tiway Turkey Limited only admit a payment is due to Hunnisett and Barker in sum of $574,696 together with accruing interest, representing payment by way of compensation properly due under the Netherby Agreement. The Company is willing and able to pay this sum to Hunnisett and Barker. Toreador and Tiway Turkey Limited deny that any other payment is due to Hunnisett and Barker and/or Netherby Investments Limited, whether in relation to

(i) the alleged amount of $7.2 million supposedly agreed upon in November 2008 ("the Buy-Back Agreement") as being payable in respect of the Netherby Payment Amount; and

F-29

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 (CONTINUED)

(ii) the Overriding Royalty payments Hunnisett and Barker assert is due to them following the sale of the 26.75% SASB interest to Petrol Ofisi and/or the sum of no less than $7.2 million which Hunnisett and Barker assert is the capitalized monies due to them following the sale of the 26.75% interest to Petrol Ofisi

Furthermore the Company and Tiway Turkey Limited deny Hunnisett and Barker's claim for rectification of the Netherby Agreement. On February 4, 2011 the Company and Tiway Turkey Limited served a formal request for further information seeking clarification on certain aspects of the claims. Until a response to this request is received, the nature of Hunnisett and Barker's claims and the merits of those claims, in particular in relation to the Buy-Back Agreement, are yet to be fully ascertained.

As of December 31, 2010, we had accrued approximately $644,000 (i.e. $574,696 plus accrued interests recorded under accounts payable and accrued liabilities) as a contingent liability for these claims, with the expense of legal cost of $254,356 and $222,280 of Overriding Royalty payment included in discontinued operations. We also accrued $248,000 (recorded under long-term accrued liabilities) as a provision for the 1.5% Overriding Royalty the Company will have to pay on the net value to Hunnisett and Barker of all future production, if any, deriving from Madison Oil's interest in such SASB licenses.

Scowcroft

Petrol Ofisi

On January 25, 2010, we received a claim notice from Tiway under the Share Purchase Agreement, dated September 30, 2009, among us, Tiway Oil AS and Tiway relating to the sale of Toreador Turkey Ltd. (the “SPA”) in respect of a third-party claim asserted by Petrol Ofisi against Toreador Turkey Ltd. in the amount of TRY 7.6 million ($5.1 million), for which Tiway alleges we are liable for an estimated TRY 2.1 million ($1.4 million). A hearing on this matter was held on July 20, 2010, and the Court has appointed three experts to evaluate the case. A hearing was held on November 2, 2010 and the Court adjourned pending the issuance of the experts’ report. The next hearing is scheduled for April 5, 2011 as the court still awaits the experts' report. The Company believes that the risk associated with this matter is remote is remote and no liability has been recorded.

TPAO

Tiway has assumed the defense of this matter and its legal representatives in Turkey have drafted a detailed defense in which Tiway rejects each of the damages and losses alleged by the TPAO. The Company does not accept liability for the arbitration under the indemnity provided to Tiway in the Share Purchase Agreement dated September 30, 2009. The Company is informed the arbitration is estimated to take place in mid-October 2011, in Ankara. The Company believes that the risk associated with this matter is remote is remote and no liability has been recorded.

F-30

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 (CONTINUED)

Lundin Indemnification

Toreador Energy France SCS ("TEF") executed on August 6, 2010, an indemnification and guarantee agreement for a maximum aggregate amount of €50 million first demand guarantee to cover Lundin International ("Lundin") against any claim by a third party arising from drilling works executed by TEF as operator on the Mairy permit. The title to the Mairy permit was awarded to Lundin, TEF and EnCore (E&P) Ltd jointly in August 2007. Earlier this year, Lundin communicated its desire to withdraw from the permit on which no drilling works had been performed and consequently assigned its working interest of 40% in equal parts to TEF and EnCore (E&P) Ltd. TEF subsequently assigned half of its now 50% working interest to Hess Oil France SAS by virtue of the Hess Investment Agreement. Under French mining law, all titleholders are held jointly and severally responsible for all damages and claims relating to works on a permit. Therefore, under the indemnification and guarantee agreement, TEF agreed to indemnify Lundin upon notice of any liability or claim for damages by a third party against Lundin in connection with works performed by TEF on the Mairy permit from February 15, 2010 until the transfer of title of such permit is formally accepted by the French government. No works are expected to begin on the permit, if at all, prior to the second half of 2011, therefore no claims have been made or are currently anticipated under this agreement.

Shale oil study conducted by French Government

On February 4, 2011, France’s Ministry of Environment and Ministry of Energy announced their intention to conduct a study on the economical, social and environmental stakes relating to the development of shale gas and shale oil in France. On February 10, 2011, Hess and Toreador met with the Ministry of Environment and the Ministry of Energy to discuss the impact this study might have on its unconventional oil exploration. Following a constructive discussion with the Ministers, Toreador has concluded the following:

●	The drilling of the first four vertical wells in our proof of concept program will not involve hydraulic fracturing and will be similar in design to wells drilled over the last fifty years in the Paris Basin. We will determine the timing and sequencing of any hydraulic fracturing operations following the issuance of the final report, which is expected to be issued in June 2011.

●	We will assist the French Government in the study by providing scientific data and practical experiences regarding oil development.

We will also initiate baseline environmental studies with third party French environmental experts that evaluate the quality of groundwater, surface water, surface soils, and air, as well as the potential noise and odor before site construction and before and after drilling operations. These studies will be made available to the French government and incurred by Hess under the Hess Investment Agreement.

F-31

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 (CONTINUED)

NOTE 13 — DERIVATIVES

We periodically utilize derivative instruments such as futures and swaps for purposes of hedging our exposure to fluctuations in the sale price of crude oil.

We entered into futures and swap contracts for approximately 16,000 Bbls per month for the months of January 2008 through September 2008. This resulted in a net derivative fair value loss of $1.8 million for the twelve months ended December 31, 2008, as presented in the table below:


Type	Period	Barrels		Floor		Ceiling		(Gain) Loss
Collar	January 1 — March 31, 2008		48,000	$	84.75	$	92.75	$	19
Collar	April 1 — June 30, 2008		48,000	$	92.25	$	100.75		2,239
Collar	July 1 — September 30, 2008		48,000	$	91.75	$	99.75		(477)
								1,781

On June 16, 2009, we entered into collars contracts for approximately 18,000 Bbls per month for the months of July 2009 through December 2009. This resulted in a realized gain of $7,000 for the year ended December 31, 2009. Presented in the table below is a summary of the contracts entered into for the year ended December 31, 2009 and gain as of December 31, 2009:

Type	Period	Barrels		Floor		Ceiling		(Gain) Loss
Collar	July 1 — December 2009		110,400	$	65.00	$	77.00	$	(7	)

In December 2009, we entered into collars contracts for approximately 15,208 Bbls per month for the entire year of 2010. This resulted in a realized gain at December 31, 2010 of $886,000. Presented in the table below is a summary of the contracts entered into for the year end December 31, 2010:

Type	Period	Barrels		Floor		Ceiling		Realized (gain) loss for the year ended, December 31, 2010

Collar	January 1, 2010 - December 31, 2010		182,500	$	68.00	$	81.00	$	(886	)

In November 2010, we entered into collars contracts for approximately 15,208 Bbls per month for the entire year of 2011. This resulted in an unrealized loss at December 31, 2010 of $1,330,000. Presented in the table below is a summary of the contracts entered into for the year end December 31, 2011:

Type	Period	Barrels		Floor		Ceiling		Unrealized (gain) loss for the year ended, December 31, 2011

Collar	January 1, 2011 - December 31, 2011		182,500	$	78.00	$	91.00	$	1,330

F-32

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 (CONTINUED)

NOTE 14 — FAIR VALUE MEASUREMENTS

The carrying amounts of financial instruments including cash and cash equivalents, short-term investments, accounts receivable, accounts payable and accrued liabilities approximate fair value at December 31, 2010 and December 31, 2009, due to the short-term nature or maturity of the instruments.

On December 31, 2009, the 5.00% Convertible Senior Notes, which had a book value of $54.6 million, were trading at or near par value, which would equal a fair market value of approximately $52.416 million.

On December 31, 2010, the New Convertible Senior Notes, which had a book value of $31.6 million, were trading at $166.51 which would equal a fair market value of approximately $52.6 million.

ASC 820 "Fair value measurements and disclosures", formerly SFAS No. 157, establishes a fair value hierarchy which prioritizes the inputs to valuation techniques used to measure fair value into three levels. The fair value hierarchy gives the highest priority to quoted market prices (unadjusted) in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 inputs are inputs, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly.

Certain assets and liabilities are reported at fair value on a nonrecurring basis in our consolidated balance sheets. The following methods and assumptions were used to estimate the fair values:

Asset Impairments - The Company reviews a proved oil and gas property for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such property. We estimate the undiscounted future cash flows expected in connection with the property and compare such undiscounted future cash flows to the carrying amount of the property to determine if the carrying amount is recoverable. If the carrying amount of the property exceeds its estimated undiscounted future cash flows, the carrying amount of the property is reduced to its estimated fair value. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. In the discounted cash flow method, estimated future cash flows are based on management's expectations for the future and include estimates of future oil and gas production, commodity prices based on commodity futures price strips as of the date of the estimate, operating and development costs, and a credit risk-adjusted discount rate.

The Company recorded asset impairments of $10.7 million in discontinued operations on proved properties during the year ended December 31, 2009. During the year December 31, 2008, the Company recorded impairments of $82.9 million for discontinued operation and $2.3 million for continued operations on proved properties. Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the impairment analysis include the Company's estimate of future natural gas and crude oil prices, operating and development costs, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data.

Goodwill - We account for goodwill in accordance with FASB Accounting Standards Codification No. 350 "Intangibles-Goodwill and Other" ("ASC 350"). Under ASC 350, goodwill and indefinite-lived intangible assets are not amortized but are reviewed annually (or more frequently if impairment indicators arise) for impairment. Goodwill fair value is estimated using discounted cash flow method.

Asset Retirement Obligations — The initial measurement of asset retirement obligations at fair value is calculated using cash flows techniques and based on internal estimates of future retirement costs associated with oil and gas properties. Significant Level 3 inputs used in the calculation of asset retirement obligations include plugging costs and reserve lives. A reconciliation of the Company's asset retirement obligation is presented in “Note ##SAP – Significant Accounting Policies”.

Effective January 1, 2008, we adopted the authoritative guidance that applies to all financial assets and liabilities required to be measured and reported on a fair value basis. Beginning January 1, 2009, we also applied the guidance to non-financial assets and liabilities. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The guidance requires disclosure that establishes a framework for measuring fair value expands disclosure about fair value measurements and requires that fair value measurements be classified and disclosed in one of the following categories:

F-33

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 (CONTINUED)

Level 1:	Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. We consider active markets as those in which transactions for the assets or liabilities occur with sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2:	Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that we value using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data or supported by observable levels at which transactions are executed in the market place. Instruments in this category include non-exchange traded derivatives such as over-the-counter commodity price swaps, certain investments and interest rate swaps.

Level 3:	Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity). Our valuation models for derivative contracts are primarily industry-standard models (i.e., Black-Scholes) that consider various inputs including: (a) quoted forward prices for commodities, (b) time value, (c) volatility factors, (d) counterparty credit risk and (e) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Level 3 instruments primarily include derivative instruments, such as basis swaps, commodity price collars and floors and accrued liabilities. Although we utilize third -party broker quotes to assess the reasonableness of our prices and valuation techniques, we do not have sufficient corroborating market evidence to support classifying these assets and liabilities as Level 2.

Measurement information for assets that are measured at fair value on a non-recurring basis was as follows:

				Fair Value Measurements Using
Description		Fair Value Measurement		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Inpaiment Loss
	(in thousands)
Year End
December 31,
2010

8.00/7.00%
Convertible Senior
Notes		$	35,065		—		—	$	35,065	$	—

F-34

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 (CONTINUED)

The following table summarizes the valuation of our investments and financial instrument assets (liabilities) measured on a recurring basis at fair value by pricing levels:

	Fair Value Measurement Using
	(Level 1)		(Level 2)		(Level 3)		Total

As of December 31, 2010:
Oil derivative contracts	$	-	$	-	$	1,330	$	1,330

Total	$	-	$	-	$	1,330	$	1,330

As of December 31, 2009:
Oil derivative contracts	$	-	$	-	$	886	$	886
	$	-	$	-	$	886	$	886

The table below summarizes the change in carrying values associated with Level 3 financial instruments:

	For The Year Ended			For The Year Ended
	December 31, 2010			December 31, 2009
	Oil Derivative Contracts			Oil Derivative Contracts
Balance at beginning of year	$	886		$	-
Realized (gain) loss		(886	)
Unrealized (gain) loss		1,330			886

Balance at end of the year	$	1,330		$	886

NOTE 15 — DISCONTINUED OPERATIONS

On September 30, 2009, the Company entered into a Share Purchase Agreement (the "Share Purchase Agreement") with Tiway Oil BV, a company organized under the laws of the Netherlands ("Tiway"), and Tiway Oil AS, a company organized under the laws of Norway, pursuant to which the Company agreed to sell 100% of the outstanding shares of Toreador Turkey to Tiway for total consideration consisting of: (1) a cash payment of $10.5 million to be paid at closing, (2) exploration success payments dependent upon certain future commercial discoveries as provided in the Share Purchase Agreement, up to a maximum aggregate consideration of $40 million, and (3) future quarterly 10% pre-tax net profit interest payments if a field goes into production that was discovered by an exploration well drilled within four years of closing on certain of the licenses then still held by Tiway. The sale of Toreador Turkey was completed on October 7, 2009 and resulted in a gain of $1.8 million.

F-35

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 (CONTINUED)

The results of operations of assets in Romania, Turkey and Hungary have been presented as discontinued operations in the accompanying consolidated statement of operations. Results for these assets reported as discontinued operations were as follows:

Discontinued Operations were as follows for the year ended December 31 2010, 2009 and 2008:

		For The Year Ended December 31,
		2010			2009			2008
Revenue and other income
	Sales and other operating revenue	$	107		$	4,545		$	28,226
Operating costs and expenses:
	Lease operating expense		—			886			7,971
	Exploration expense		—			868			4,582
	Dry hole costs		—			1,318			—
	Depreciation, depletion and amortization		—			157			28,148
	Accretion on discounted assets and liabilities		—			—			—
	Impairment of oil and natural gas properties		—			10,725			82,951
	General and administrative expense		1,070			3,424			2,445
	(Gain) loss on sale of properties and other assets		—			(3,583	)		123
	Total operating costs and expenses		1,070			13,795			126,220
	Operating loss		(963	)		(9,250	)		(97,994	)
Other income (expense)
	Foreign currency exchange gain		258			3,822			(342	)
	Interest and other income		66			414			1,004
	Loss on early extinguishment of debt — revolving credit facility		—			(4,881	)		—
	Other expense		—			—			—
	Interest expense, net of interest capitalized		—			(185	)		(3,679	)
Loss before income taxes			(639	)		(10,080	)		(101,011	)
Income tax provision			(101	)		—			574
Net loss from discontinued operations		$	(740	)	$	(10,080	)	$	(101,585	)

F-36

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 (CONTINUED)

NOTE 16 — GEOGRAPHIC OPERATING SEGMENT INFORMATION

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

During the fourth quarter of 2010, the Company fully consolidated Toreador International Holding LLC (“TIH”), its wholly-owned subsidiary incorporated in Hungary. Consequently, the full year 2010 results of TIH were incorporated in the Company’s consolidated financial statements as of December 31, 2010, resulting in an increase in Company’s equity of $202,000 consisting of $147,000 of net income generated by TIH during the twelve months ended December 31, 2010 and $55,000 from prior fiscal periods which is not material to the financial position of the company.

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 still valid.

	United States			France			Total
	(In thousands)
For The Year Ended December 31, 2010
Revenues and other income:
Sales and other operating revenue	$	27		$	23,967		$	23,994
Other income		-			16,770			16,770
Total revenues and other income		27			40,737			40,764
Operating costs and expenses:
Lease operating expense		-			11,597			11,597
Exploration expense		17			1,960			1,977
Depreciation, depletion and amortization		94			4,296			4,390
Accretion on discounted assets and liabilities (Notes 2)		(593	)		504			(89	)
General and administrative		10,152			5,025			15,177
Loss (gain) on oil and gas derivative contracts (Note 13)		444			-			444
Total operating costs and expenses		10,114			23,382			33,496
Operating income (loss)		(10,087	)		17,355			7,268
Other (expense) income:
Foreign currency exchange gain (loss)		43			(917	)		(874	)
Loss on the early extinguishment of debt		(4,256	)
Interest expense, net of interest capitalized		(4,860	)		102			(4,758	)
Total other income (expense)		(9,073	)		(815	)		(9,888	)
Income (loss) before taxes from continuing operations		(19,160	)		16,540			(2,620	)
Income tax (benefit) provision (Note 9)		(153	)		6,283			6,130
Loss from continuing operations, net of income taxes		(19,007	)		10,257			(8,750	)
Selected assets:
Properties and equipment		731			108,248			108,979
Accumulated depreciation, depletion, and amortization		(340	)		(42,861	)		(43,201	)
Oil and natural gas properties, net		391			65,387			65,778
Goodwill		-			3,685			3,685
Total assets for reportable segments		49,798			97,331			147,129
Expenditures for additions to long-lived assets:
Exploration costs		-			218			218
Total expenditures for long-lived assets		-			218			218

F-37

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 (CONTINUED)

	United States			France			Total
				(In thousands)
For The Year Ended December 31, 2009
Revenues and other income:
Sales and other operating revenue	$	461		$	18,775		$	19,236
Other income		-			-			-
Total revenues and other income		461			18,775			19,236
Operating costs and expenses:
Lease operating expense		-			8,396			8,396
Exploration expense		138			-			138
Depreciation, depletion and amortization		292			4,964			5,256
Accretion on discounted assets and
liabilities (Note 2)					507			507
General and administrative		16,666			3,694			20,360
Gain on sale of properties and other
assets		(121	)					(121	)
Loss (gain) on oil and gas derivative
contracts (Note 13)		886			(7	)		879
Total operating costs and expenses		17,861			17,554			35,415
Operating income (loss)		(17,400	)		1,221			(16,179	)
Other (expense) income:
Foreign currency exchange gain (loss)								-
Other income		182			215			397
Total other income (expense)		182			215			397
Loss before taxes from continuing operations		(17,218	)		1,436			(15,782	)
Income tax (benefit) provision (Note 9)		408			42			450
Loss from continuing operations, net of income
taxes		(16,810	)		1,478			(15,332	)
Selected assets:
Properties and equipment	$	650		$	115,785		$	116,435
Accumulated depreciation, depletion, and
amortization		(246	)		(41,568	)		(41,814	)
Oil and natural gas properties, net	$	404		$	74,217		$	74,621
Goodwill	$	-		$	3,973		$	3,973
Total assets for reportable segments	$	42,996		$	100,989		$	143,985
Expenditures for additions to long-lived assets:
Exploration costs	$	-		$	2,887		$	2,887
Development costs		-			499			499
Total expenditures for long-lived
assets	$	-		$	3,386		$	3,386

F-38

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 (CONTINUED)

	United States			France			Total
				(In thousands)
For The Year Ended December 31, 2008
Revenues and other income:
Sales and other operating revenue	$	52		$	34,098		$	34,150
Other income								-
Total revenues and other income		52			34,098			34,150
Operating costs and expenses:
Lease operating expense		-			9,263			9,263
Exploration expense		1,080			144			1,224
Depreciation, depletion and amortization		307			4,330			4,637
Accretion on discounted assets and
liabilities (Note 2)		-			357			357
Impairment of oil and natural gas
properties and intangible assets		2,282			-			2,282
General and administrative		11,747			1,295			13,042
Loss (gain) on oil and gas derivative
contracts (Note 13)		-			1,781			1,781
Total operating costs and expenses		15,416			17,170			32,586
Operating income (loss)		(15,364	)		16,928			1,564
Other (expense) income:
Other income (expense)		(3,154	)		72			(3,082	)
Total other income (expense)		(3,154	)		72			(3,082	)
Loss before taxes from continuing operations		(18,518	)		17,000			(1,518	)
Income tax (benefit) provision (Note 9)		563			(6,065	)		(5,502	)
Loss from continuing operations, net of income
taxes		(17,955	)		10,935			(7,020	)
Selected assets:
Properties and equipment	$	1,860		$	108,668		$	110,528
Accumulated depreciation, depletion, and
amortization		(1,163	)		(36,612	)		(37,775	)
Oil and natural gas properties, net	$	697		$	72,056		$	72,753
Goodwill	$	-		$	3,838		$	3,838
Total assets for reportable segments	$	276,434		$	93,691		$	370,125
Expenditures for additions to long-lived assets:
Exploration costs	$	-		$	431		$	431
Development costs		10			-			10
Total expenditures for long-lived
assets	$	10		$	431		$	441

F-39

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 (CONTINUED)

	December 31,
	2010			2009
	(in thousands)
Total assets for reportable segments	$	147,129		$	143,985
Total assets of entities held for sale
Elimination of intersegment receivables and investments		(46,830	)		(46,830	)

Total consolidated assets	$	100,299		$	97,155

NOTE 17— SUBSEQUENT EVENTS

The Company evaluated its December 31, 2010 financial statements for subsequent events through the date the financial statements were issued.

Concessions Renewal

The decrees relating to the renewal of the Châteaurenard concession and of the Saint-Firmin-des-Bois concession, which together account for nearly all of Toreador’s existing reserves, received final French government approvals on February 1, 2011, and were published in the French Journal Officiel on February 3, 2011. The renewals extend the expiry date of both concessions to January 1, 2036.

F-40

TOREADOR RESOURCES CORPORATION

SUPPLEMENTAL OIL AND NATURAL GAS RESERVES AND STANDARDIZED MEASURE

INFORMATION (UNAUDITED)

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

Users of this information should be aware that the process of estimating quantities of proved and proved developed oil and gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir also may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates may occur from time to time.

Recent SEC and FASB Rule-Making Activities. On December 31, 2008, the SEC issued the Final Rule adopting revisions to the SEC's oil and gas reporting disclosure requirements. In addition, in January 2010, the FASB issued ASU 2010-03, which aligns the FASB's oil and gas reserve estimation and disclosure requirements with the requirements in the SEC's Final Rule.

We adopted the Final Rule and ASU 2010-03 effective December 31, 2009 as a change in accounting principle that is inseparable from a change in accounting estimate. Such a change is accounted for prospectively under the authoritative accounting guidance. Comparative disclosures applying the new rules for periods before the adoption of ASU 2010-03 and the Final Rule are not required.

Our adoption of ASU 2010-03 and the Final Rule on December 31, 2009 impacted our financial statements and other disclosures in our annual report on Form 10-K for the year ended December 31, 2009, as follows:

●	All oil and gas reserves volumes presented as of and for the year ended December 31, 2009 were prepared using the updated reserves rules and are not on a basis comparable with prior periods.

●	This change in comparability occurred because we estimated our proved reserves at December 31, 2009 using the updated reserves rules, which require use of the unweighted average first-day-of-the-month commodity prices for the prior twelve months , adjusted for market differentials, and permits the use of reliable technologies to support reserve estimates. Under the previous reserve estimation rules, which are no longer in effect, our net proved oil and gas reserves would have been calculated using end of period oil and gas prices. Adoption of ASU 2010-03 and the Final Rule did not have any significant effect on our reserves estimate, however, standardized measure of discounted future net cash flows related to proved reserves decreased by approximately $29 million due to use of unweighted twelve month average price compare to year end price.

Reserves Estimates. All reserve information in this report is based on estimates prepared by our independent engineering firm and is the responsibility of management. The preparation of our oil reserves estimates is completed in accordance with our prescribed internal control procedures, which include verification of data input into reserves forecasting and economics evaluation software, as well as multi-discipline management reviews.

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

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

F-41

TOREADOR RESOURCES CORPORATION

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

	France		Turkey	Romania		Hungary	Total
	Natural Gas (MMcf)
PROVED RESERVES
December 31, 2007		—	12,939		772	—		13,711
Revisions of previous estimates		—	(819)		(310)	950		(179)
Extensions, discoveries and other additions		—	—		—	—		—
Sale of reserves		—	—		—	—		—
Production		—	(1,643)		(376)	—		(2,019)

December 31, 2008		—	10,477		86	950		11,513
Revisions of previous estimates		—	—		—	—		—
Extensions, discoveries and other additions		—	—		—	—		—
Sale of reserves		—	(10,477)		(86)	(950)		(11,513)
Production		—	—		—	—		—

December 31, 2009		—	—		—	—		—
Revisions of previous estimates		—	—		—	—		—
Extensions, discoveries and other additions		—	—		—	—		—
Sale of reserves		—	—		—	—		—
Production		—	—		—	—		—

December 31, 2010		—	—		—	—		—

PROVED DEVELOPED
December 31, 2008		—	2,437		86	950		3,473

December 31, 2009		—	—		—	—		—

December 31, 2010		—	—		—	—		—


	Oil (MBbls)
PROVED RESERVES
December 31, 2007		9,968	1,049		6	—		11,023
Revisions of previous estimates		(4,694)	(253)		(2)	1		(4,948)
Extensions, discoveries and other additions		—	—		—	—		—
Sale of reserves		—	—		—	—		—
Production		(360)	(55)		(3)	—		(418)

December 31, 2008		4,914	741		1	1		5,657
Revisions of previous estimates		1,217	—		—	—		1,217
Extensions, discoveries and other additions		—	—		—	—		—
Sale of reserves		—	(741)		(1)	(1)		(743)
Production		(328)	—		—	—		(328)

December 31, 2009		5,803	—		—	—		5,803
Revisions of previous estimates		43	—		—	—		43
Extensions, discoveries and other additions		—	—		—	—		—
Sale of reserves		—	—		—	—		—
Production		(323)	—		—	—		(323)

December 31, 2010		5,153	—		—	—		5,523

PROVED DEVELOPED
December 31, 2008		4,385	500		1	1		4,887

December 31, 2009		5,383	—		—	—		5,383

December 31, 2010		5,111	—		—	—		5,111

PROVED UNDEVELOPED
December 31, 2008		529	241		—	—		770
December 31, 2009		420	—		—	—		420
December 31, 2010		412	—		—	—		412

F-42

TOREADOR RESOURCES CORPORATION

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

The following information was developed utilizing procedures prescribed by FASB Accounting Standards Codification Topic 932, Extractive Industries — Oil and Gas (Topic 932). The information is based on estimates prepared by our independent engineering firm. The "standardized measure of discounted future net cash flows" should not be viewed as representative of the current value of our proved oil reserves. It and the other information contained in the following tables may be useful for certain comparative purposes, but should not be solely relied upon in evaluating us or our performance.

In reviewing the information that follows, we believe that the following factors should be taken into account:

●	future costs and sales prices will probably differ from those required to be used in these calculations;

●	actual production rates for future periods may vary significantly from the rates assumed in the calculations;

●	a 10% discount rate may not be reasonable relative to risk inherent in realizing future net oil revenues; and

●	future net revenues may be subject to different rates of income taxation.

Under the standardized measure, future cash inflows were estimated by applying the prices used in estimating our proved oil and gas reserves to the year-end quantities of those reserves. Future cash inflows do not reflect the impact of open hedge positions. Future cash inflows were reduced by estimated future development, abandonment and production costs based on year-end costs in order to arrive at net cash flows before tax. Future income tax expense has been computed by applying year-end statutory tax rates to aggregate future pre-tax net cash flows reduced by the tax basis of the properties involved and tax carryforwards. The standardized measure is derived from using a discount rate of 10% a year to reflect the timing of future net cash flows relating to proved oil and gas reserves.

In general, management does not rely on the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves and varying price and cost assumptions considered more representative of a range of possible outcomes.

The prices of oil and natural gas at December 31, 2010, 2009, and 2008 used to estimate reserves in the table shown below, were $79.35, $56.99 and $34.29 per Bbl of oil, respectively, and $0, $0 and $12.68 per Mcf of natural gas, respectively. The price at December 31, 2010 and 2009, were the average price for the corresponding year. 2008 is at the price as of December 31, 2008.

F-43

TOREADOR RESOURCES CORPORATION

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

	France			Turkey			Romania				Hungary			Total
	(In thousands)
As of and for the year ended December 31, 2008
Future cash inflows		$	170,662		$	155,179		$	412			$	13,735		$	339,988
Future production costs			105,298			26,939			381				1,851			134,469
Future development costs			13,658			71,283			159				550			85,650
Future income tax expense			10,027			-			-				-			10,027

Future net cash flows			41,679			56,957			(128	)			11,334			109,842
10% annual discount for estimated timing of cash flows			23,116			29,909			(7	)			2,056			55,074

Standardized measure of discounted future net cash flows related to proved reserves		$	18,563		$	27,048		$	(121	)		$	9,278		$	54,768

As of and for the year ended December 31, 2009
Future cash inflows		$	301,070		$	-		$	-			$	-		$	301,070
Future production costs			187,900			-			-				-			187,900
Future development costs			60,160			-			-				-			60,160
Future income tax expense			11,959			-			-				-			11,959

Future net cash flows(1)			41,051			-			-				-			41,051
10% annual discount for estimated timing of cash flows			24,282			-			-				-			24,282

Standardized measure of discounted future net cash flows related to proved reserves(1)		$	16,769		$	-		$	-			$	-		$	16,769

As of and for the year ended December 31, 2010
Future cash inflows		$	391,860		$			$				$			$	391,860
Future production costs			176,630													176,630
Future development costs			33,500													33,500
Future income tax expense			79,221													79,221

Future net cash flows			102,509			-			-				-			102,509
10% annual discount for estimated timing of cash flows			57,114													57,114

Standardized measure of discounted future net cash flows related to proved reserves		$	45,395		$	-		$	-			$	-		$	45,395


(1) The negative values are due to plugging and abandonment costs incurred in the final year.

F-44

TOREADOR RESOURCES CORPORATION

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

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

	France				Turkey				Romania				Hungary				Total
	(In thousands)
Balance at December 31, 2007			174,211				84,048				1,110				—				259,369
Sales of oil and natural gas, net			(24,834	)			(22,191	)			1,906				—				(45,119	)
Net changes in prices and production costs			(212,520	)			(7,298	)			(481	)			—				(220,299	)
Net change in development costs			7,795				(30,943	)			(62	)			(451	)			(23,661	)
Extensions and discoveries			—				—				—				—				-
Revisions of previous quantity estimates			(26,219	)			(11,419	)			(105	)			9,737				(28,006	)
Previously estimated development costs incurred			—				(5,475	)			—				—				(5,475	)
Net change in income taxes			81,846				5,329				(2,712	)			38				84,501
Accretion of discount			26,260				8,938				111				—				35,309
Sale of reserves			—				—				—				—				-
Other			(7,976	)			6,059				112				(46	)			(1,851	)

Balance at December 31, 2008			18,563			$	27,048			$	(121	)		$	9,278			$	54,768
Sales of oil and natural gas, net			(10,379	)			(4,753	)			(72	)			—				(15,204	)
Net changes in prices and production costs			18,069				—				—				—				18,069
Net change in development costs			(22,579	)			—				—				—				(22,579	)
Extensions and discoveries			—				—				—				—				-
Revisions of previous quantity estimates			11,531				—				—				—				11,531
Previously estimated development costs incurred			—				—				—				—				-
Net change in income taxes			(7,774	)			—				—				—				(7,774	)
Accretion of discount			2,511				—				—				—				2,511
Sale of reserves			—				(22,295	)			193				(9,278	)			(31,380	)
Other			6,827				—				—				—				6,827

Balance at December 31, 2009		$	16,769			$	-			$	-			$	-			$	16,769
Sales of oil and natural gas, net			(12,369	)			—				—				—				(12,369	)
Net changes in prices and production costs			8,829				—				—				—				8,829
Net change in development costs			12,061				—				—				—				12,061
Extensions and discoveries			—				—				—				—				-
Revisions of previous quantity estimates			723				—				—				—				723
Previously estimated development costs incurred			—				—				—				—				-
Net change in income taxes			(11,484	)			—				—				—				(11,484	)
Accretion of discount			2,511				—				—				—				2,511
Sale of reserves			—				—				—				—				-
Other			28,355				—				—				—				28,355

Balance at December 31, 2010		$	45,395			$	-			$	-			$	-			$	45,395

F-45

Computation of Ratio of Earnings to Fixed Charges:
	For The Year Ended December 31,
	2010			2009			2008			2007			2006
Earnings (loss):
Pretax
Income from continuing operations	$	(9,004	)	$	(15,782	)	$	(102,507	)	$	(81,466	)	$	10,115

Add: fixed charges	$	3,748		$	3,493		$	7,848		$	4,291		$	1,099
Equity in earnings of unconsolidated sub		-			-			-			(22	)		401

Less:
Pref Dividends (grossed-up)		-			-			-			(162	)		(245	)
Interest capitalized		-			230			-			-			(8	)

Earnings as defined in Item 503 of Reg. S-K	$	(5,255	)	$	(12,059	)	$	(94,659	)	$	(77,359	)	$	11,362
Fixed Costs:
Interest expense	$	3,550		$	3,525			7,650			3,940			660
cap int		-			(230	)		-			-			8
Pref Dividends (grossed-up)		-			-			-			162			245
Interest included in rental expense		198			198			198			189			186
Fixed costs as defined in Item 503 of Reg. S-K	$	3,748		$	3,493		$	7,848		$	4,291		$	1,099

Ratio of earnings to fixed costs		N/A			N/A			N/A			N/A			13.31
Pref Dividends Excluded
$ value of deficiency	$	(9,004	)	$	(15,552	)	$	(102,507	)	$	(81,488	)		N/A

Ratio of earnings to fixed costs		N/A			N/A			N/A			N/A			10.34
and preference dividends
$ value of deficiency	$	(9,004	)	$	(15,552	)	$	(102,507	)	$	(81,650	)		N/A

F-46

Attached files

TOREADOR RESOURCES CORP Reports

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