Toreador Resources 10K/A 2005 Annual report (amended)

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: Restatement of Previously Issued Financial Statements for Fiscal Years Ended
December 31, 2003, 2004, and 2005


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

COMMISSION FILE NUMBER: 0-02517

Toreador Resources Corporation

(Exact name of Registrant as specified in its charter)


Delaware		75-0991164
(State or other jurisdiction of incorporation)		(I.R.S. Employer Identification Number)

4809 Cole Avenue, Suite 108
Dallas, Texas		75205
(Address of principal executive office)		(Zip Code)

Registrant’s telephone number, including area code: (214) 559-3933

Securities registered pursuant to Section 12(b) of the Exchange Act:


Title of each Class:		Name of each exchange on which registered:
COMMON STOCK, PAR VALUE		NASDAQ NATIONAL MARKET SYSTEM
$.15625 PER SHARE

Securities registered pursuant to Section 12(g) of the Exchange Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ

Indicate by check whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes o No þ

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (check one) Large accelerated filer. o Accelerated filerþ Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Exchange Act). Yes o No þ

The aggregate market value of the voting common equity of the registrant held by non-affiliates, computed by reference to the closing sales price of such stock, as of June 30, 2005 was $217,834,420. (For purposes of determination of the aggregate market value, only directors, executive officers and 10% or greater stockholders have been deemed affiliates.)

The number of shares outstanding of the registrant’s common stock, par value $.15625, as of January 11, 2007 was 15,934,484 shares.

DOCUMENTS INCORPORATED BY REFERENCE

None.

TABLE OF CONTENTS


		Page
Explanatory Note about the Report		1

PART I

Item 1 and 2.	Business and Properties	2

PART II

Item 6.	Selected Financial Data	20

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21

Item 8.	Financial Statements and Supplementary Data	35

Item 9A.	Controls and Procedures	35

PART IV

Item 15.	Exhibits and Financial Statement Schedules	38

SIGNATURES		38
Consent of Grant Thornton LLP
Consent of LaRoche Petroleum Consultants, Ltd.
Certification of Chief Executive Officer Pursuant to Section 302
Certification of Chief Financial Officer Pursuant to Section 302
Certification of Chief Accounting Officer Pursuant to Section 302
Certification Pursuant to Section 906

Explanatory Note about the Report

In August 2006, the management and audit committee of Toreador Resources Corporation (“Toreador,” “we,” “us,” “our,” or the “Company”) determined that the Company should restate its financial statements for the quarter ended March 31, 2006, and on September 7, 2006, the management and audit committee of Toreador determined that the Company should restate its consolidated financial statements as of and for the year ended December 31, 2005, and its consolidated financial statements for the quarter ended June 30, 2006.

On November 16, 2006, Toreador’s management and the chairman of the audit committee determined that Toreador should also restate its consolidated financial statements as of and for the years ended December 31, 2003 and 2004. The restatements are due to various errors that were discovered during and in conjunction with the audit of the restatements for the year ended December 31, 2005. The restatement of the financial statements for the years ended December 31, 2003 and 2004 has been approved by the audit committee.

In May 2006, the Company’s previous independent registered public accounting firm resigned and, on June 6, 2006, the Company’s audit committee engaged Grant Thornton LLP as the Company’s new independent registered public accounting firm. Grant Thornton LLP was engaged and has performed audits of the Company’s restated financial statements as of December 31, 2004 and 2005 and for each of the three years in the period ended December 31, 2005. See Report of Independent Registered Public Accounting Firm.

This Form 10-K/A amends and restates only Items 1, 2, 6, 7, and 8 of Part II and Item 15 of Part IV of the Form 10-K for the year ended December 31, 2005, to reflect the effect of these restatements on the Company’s financial statements for the periods presented and amends Item 9A for the year ended December 31, 2005 to disclose additional control deficiencies that were discovered during the restatements. Accordingly, this Form 10-K/A should be read in conjunction with the Company’s original Form 10-K for the year ended December 31, 2005. Except for the foregoing amended information, this Form 10-K/A continues to describe conditions as of the date of the original Form 10-K for the year ended December 31, 2005, and the Company has not updated the disclosures contained herein to reflect events that occurred at a later date. In addition, the filing of this Form 10-K/A shall not be deemed an admission that the original filings, when made, included any untrue statement of a material fact or omitted to state a material fact necessary to make a statement made therein not misleading. This Form 10-K/A should be read in conjunction with our filings made with the Securities and Exchange Commission subsequent to the filing of the original Form 10-K for the years ended December 31, 2003, 2004 and 2005, including any amendments to those filings. In addition, pursuant to the rules of the Securities and Exchange Commission, Exhibits 31.1, 31.2 and 31.3 and 32.1 of the original Form 10-K for the year ended December 31, 2005 have been amended and filed herewith to contain currently dated certifications from our Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer.

As described in Note 3 of the consolidated financial statements, the significant restatement adjustments relate to: the accounting for insurance claims related to previously reported incidents occurring in the Black Sea; the capitalization of interest associated with the Company’s development operations in Turkey; identified additional impairment of certain oil and gas properties; changes in the calculation of depreciation, depletion and amortization; adjustments to the foreign currency translation and transactions in France and Turkey; write-off of deferred loan costs; adjustments to the asset retirement obligations balance; write-off of improperly capitalized seismic cost; accrual of certain liabilities; and, adjustments to the deferred tax accounts.

PART I

Items 1 and 2. Business and Properties

Toreador Resources Corporation, a Delaware corporation (“Toreador,” “we,” “us,” “our,” or the “Company”), is an independent international energy company engaged in oil and natural gas exploration, development, production, leasing and acquisition activities. Our strategy is to increase our reserves through a balanced combination of exploratory drilling, development and exploitation projects and acquisitions. We primarily focus on international exploration activities in countries where we can establish large acreage positions. We also focus on prospects where we do not have to compete directly with major integrated or large independent oil and natural gas producers and where extensive geophysical and geological data is available. Our international operations are all located in European Union or European Union candidate countries that we believe have stable governments, have existing transportation infrastructure, have attractive fiscal policies and are net importers of oil and natural gas.

We currently hold interests in permits granting us the right to explore and develop oil and natural gas properties in offshore and onshore Turkey, Hungary, Romania and France. We also own various non-operating working interest properties primarily in Texas, Kansas, New Mexico, Louisiana and Oklahoma. At December 31, 2005, we held interests in approximately 4.7 million gross acres and approximately 3.8 million net acres, of which 98% is undeveloped. At December 31, 2005, our estimated net proved reserves were 15 million barrels of oil equivalent (MMBOE).

Historically, our operations have been concentrated in the Paris Basin in France and in south central onshore Turkey. These two regions accounted for 85% of our total proved reserves as of December 31, 2005 and approximately 75% of our total production for the year ended December 31, 2005.

Incorporated in 1951, we were formerly known as Toreador Royalty Corporation.

See the “Glossary of Selected Oil and Natural Gas Terms” at the end of Item 1 for the definition of certain terms in this annual report.

Recent Developments

Public Offering

On February 16, 2005, we sold 1,437,500 shares of our common stock pursuant to a public offering at a price to the public of $24.25 per share. The sale resulted in net proceeds of approximately $32.3 million. The proceeds were used to fund the 2005 capital expenditure program and for general corporate purposes.

Acquisition

In June 2005, we acquired 100% of Pogo Hungary Ltd, a wholly owned subsidiary of Pogo Producing Company. The purchase price was approximately $9 million.

Private Placement

On September 16, 2005, we sold 806,450 shares of our common stock to certain accredited investors pursuant to a private placement. We have used and will use the net proceeds of approximately $23.6 million for general corporate purposes, including the funding of our capital expenditures requirements in 2005 and 2006.

Convertible Notes

On September 27 and September 30, 2005, we sold an aggregate principal amount of $86,250,000 of the 5.00% Convertible Senior Notes due 2025. We have used and will use the net proceeds of approximately $82.2 million for general corporate purposes, including the funding of our capital expenditures requirements in 2005 and 2006.

Production Structure Issues

In 2005 two separate incidents occurred, in offshore Turkey in the Black Sea, which resulted in the loss of two caissons and three wells. Both of these incidents were insured and the Company expects to receive reimbursement, from the insurance company for substantially the entire value of the two caissons and three wells, as the replacement wells are redrilled and the new structures are installed.

Drilling and Production Facility Update

In January, the Charmottes-111H horizontal well was completed as an oil producer in France. The development well is currently producing 400 barrels of oil per day during daylight hours for five days a week. Once the well is connected to a pipeline, which will take place during the second quarter, it is anticipated that production rates will be held to approximately 500 barrels per day to properly manage the reservoir.

Also in January, a contract was awarded to Momentum Engineering of Dubai, UAE, for the construction and installation of production platforms for the South Akcakoca Sub-basin natural gas project offshore Turkey in the Black Sea. The contract was for two platforms with an option for another two platforms. Based on drilling success, one of the options for an additional platform was exercised in March.

In February, the Dogu Ayazli-1 exploration well encountered approximately 60 meters of net pay from 12 zones in the Eocene-age Kusuri formation offshore Turkey in the South Akcakoca Sub-basin. During extended testing the well produced over 9.0 million cubic feet per day of natural gas, and was suspended after testing while waiting for installation of a production platform. Subsequently, the Dogu Ayazli-2 was spudded in early March to test the northwest flank of the structure.

In March, the Akkaya-2 well confirmed the presence of natural gas on the northern flank of the Akkaya prospect in the South Akcakoca Sub-basin. Logs indicated net pay of approximately 21 meters, which was in line with expectations. The well was scheduled to be tested in mid to late March.

In Romania, a production facility was constructed in the Fauresti field to allow production from the four wells re-entered in 2005 and suspended as gas producers. It is anticipated that permits to sell the gas produced will be awarded in early April 2006. It is our understanding that when we start selling our gas in Romania, we will be the first non-Romanian exploration and production company to do so.

Strategy

Our business strategy is to grow our oil and natural gas reserves, production volumes and cash flows through drilling internally generated prospects, primarily in the international arena. We also seek complementary acquisitions of new interests in our core geographic areas of operation.

We seek to:

Target under-explored basins in international regions.

Our international operations are all located in European Union or European Union candidate countries that we believe have stable governments, have existing transportation infrastructure, have attractive fiscal policies and are net importers of oil and natural gas. We focus on countries where we can establish large acreage positions that we believe offer multi-year investment opportunities and concentrate on prospects where extensive geophysical and geological data is available. Currently, we have international operations in Turkey, Hungary, Romania and France. We believe our concentrated and extensive acreage positions have allowed us to develop the regional expertise needed to interpret specific geological trends and develop economies of scale.

Maintain a deep inventory of drilling prospects.

Our South Akcakoca sub-basin gas project is located on approximately 50,000 acres within our approximately 962,000 acre Western Black Sea permits. It is the only area we have explored within these permits and we believe

there are significant additional drilling opportunities within and outside of the South Akcakoca sub-basin. Similarly, we believe our Hungarian and Romanian positions offer multi-year drilling opportunities.

Pursue new permits and selective property acquisitions.

We target incremental acquisitions in our existing core areas through the pursuit of new permits. Our additional growth initiatives include identifying acquisitions of (i) producing properties that will enable us to increase our production and (ii) reserve and acreage positions on favorable economic terms. Generally, we seek properties and acquisition candidates where we can apply our existing technical knowledge base.

Manage our risk exposure.

Because exploration projects have a higher degree of risk than development projects, we generally plan to limit our exploratory expenditures to approximately one-half of the total annual capital expenditure budget per year. We have balanced our exploration and development activities to support our overall goal of growing and maintaining a long-lived reserve base. We also expect to make significant investments in seismic data. By equipping our geologists and geophysicists with state-of-the-art seismic information, we intend to increase the number of higher potential prospects we drill. As deemed appropriate, we may enter into joint ventures in order to reduce our risk exposure in exchange for a portion of our interests.

Maintain operational flexibility.

Given the volatility of commodity prices and the risks involved in drilling, we remain flexible and may adjust our drilling program and capital expenditure budget. We may defer capital projects in order to seize attractive acquisition opportunities. If certain areas generate higher-than-anticipated returns, we may accelerate drilling in those areas and decrease capital expenditures elsewhere.

Leverage experienced management, local expertise and technical knowledge.

We have assembled a management team with considerable technical expertise and industry experience. The members of our management team average more than 25 years of exploration and development experience in over 40 countries. Additionally, we have an extensive team of technical experts and many of these experts are nationals in the countries in which we operate. We believe this provides us with local expertise in our countries of operations.

Turkey

We established our initial position in Turkey at the end of 2001 through the acquisition of Madison Oil Company. In Turkey, we currently hold interests in 22 exploration and three exploitation permits covering approximately 2.0 million net acres. Our exploration and development program focuses on the following areas:

Western Black Sea Permits

We currently are the operator and hold a 36.75% working interest in the Western Black Sea permits, which cover approximately 962,000 gross acres.

South Akcakoca Sub-Basin

The South Akcakoca sub-basin is an area of approximately 50,000 acres located in the Western Black Sea, offshore Turkey. We discovered gas in September 2004 with the Ayazli-1 well and since that time have drilled five successful delineation wells, the Akkaya-1, Ayazli-2, Ayazli-3, Dogu Ayazli-1 and Akkaya-2. The Cayagzi-1 delineation well was drilled to total depth and did not encounter hydrocarbons, and was plugged and abandoned. We expect to drill five development wells in 2006, two of which will require a floating rig, and complete the first phase of pipeline and facility construction with production to begin in the second half of 2006. The first phase of infrastructure development includes: setting up four production platforms; laying two sub sea pipelines; constructing the onshore processing facility for the entire sub-basin development; and constructing the onshore pipeline to tie into the national pipeline operated by the Turkish national gas utility.

Eregli Sub-Basin

The Eregli sub-basin is an area of approximately 75,000 acres located in the Western Black Sea, offshore Turkey. We plan to shoot a high resolution 2D seismic survey on the permit in preparation for an exploration program, which we expect to commence in mid-2006. We also plan to drill one exploration well prior to the end of 2006.

Thrace Black Sea Permits

The Thrace Black Sea permits are located offshore Turkey in the Black Sea between Bulgarian waters and the Bosporus Straits. We are the operator and hold a 100% working interest in the permit covering 844,000 net acres. In June 2005, HEMA Endustri A.S., a Turkish-based conglomerate, agreed to pay 100% of the first $1.5 million of the geophysical and exploration costs on this acreage to receive an option for a 50% interest in this permit.

Central Black Sea Permit

In January 2005, the Turkish government awarded us two additional Black Sea permits located in shallow waters offshore central Turkey comprising approximately 233,000 acres. We will conduct an analysis of existing technical data on these two permits in which we hold a 100% working interest.

Eastern Black Sea Permit

We were recently awarded an exploration permit on three blocks in the Black Sea offshore Turkey in the coastal waters to the west northwest of the city of Trabzon. The three blocks total approximately 357,062 acres. We are the operator of and hold 100% working interest in this permit.

Calgan Permit

Onshore in south central Turkey, we currently operate and hold a 75% working interest in the Calgan exploration permit, which covers an area of approximately 92,000 net acres. In 2004, we drilled the Calgan-2 exploratory well which encountered oil shows. In October 2005, we drilled a lateral extension and we are currently reviewing the best method to utilize in completing the well. Additionally, we are participants in a development well in the Cendere Field, located east of the Calgan permit, with a 20% working interest.

Southeast Turkey Permit

Onshore in southeast Turkey, east southeast of our Calgan permit, we were recently granted an exploration permit on one block of approximately 95,897 acres. The block is west of some existing oil fields. We are operator of and hold 100% working interest in this permit.

Hungary

We established our initial position in Hungary in June 2005 through the acquisition of Pogo Hungary Ltd. from Pogo Producing Company for $9 million. We currently hold an interest in one exploration permit covering two blocks aggregating approximately 764,000 net acres.

Szolnok Block

Two gas wells were drilled by the previous operator in the Szolnok Block, each of which initially tested at over 4 Mmcf per day. We expect to construct a gas processing facility and tie-in pipeline for such wells in 2006, once we complete negotiations and finalize a gas contract with the Hungarian national oil company. In addition, extensive 2D and 3D seismic surveys conducted by the prior owner delineated multiple prospects, and we intend to start exploration drilling on the Szolnok Block in 2006.

Tompa Block

The Tompa Block prospect, where we expect to commence drilling in the first half of 2006, is located in the northeast corner of the Tompa Block, situated between two existing producing fields. Extensive 2D and 3D seismic surveys conducted by the prior owner delineated multiple drilling prospects.

Romania

We established our initial position in Romania in early 2003 through the award of an exploration permit in the Viperesti block. We hold a 100% interest in one rehabilitation and two exploration permits covering approximately 625,000 acres.

Viperesti Permit

We currently are the operator and hold 100% of this exploration permit, covering approximately 324,000 acres.

Moinesti Permit

We are the operator and hold 100% of this exploration permit, covering approximately 300,000 acres. We are currently gathering geological and geophysical data and reprocessing seismic data.

Fauresti Rehabilitation Permit

We are the operator and hold 100% of this rehabilitation permit covering an existing shut-in oil field covering approximately 1,325 acres. During 2005, we conducted a six-well re-entry program and were successful in converting four of the wells into natural gas and condensate producers. A second five-well re-entry program is planned for 2006.

France

We established our initial position in France at the end of 2001 through the acquisition of Madison Oil Company. We hold interests in permits covering five producing oil fields in the Paris Basin on approximately 24,261 net acres as well as four exploration permits covering approximately 278,946 net acres.

Charmottes Field

We hold a 100% working interest and operate the permit covering the Charmottes Field, which currently has 12 producing oil wells. Operations are being conducted to optimize production on two recently drilled horizontal wells, the Charmottes-108H and the Charmottes-110H.

Neocomian Complex

Pursuant to two exploitation permits, we operate and hold a 100% working interest in the permits covering the Neocomian Fields, a group of four oil fields. The complex currently has 81 producing oil wells.

Courtenay Permit

We hold a 100% working interest and are the operator of this permit covering approximately 183,000 acres which surrounds the Neocomian Fields. We expect to begin an exploration drilling program on this permit in 2006.

Nemours Permit

We hold a 33¹/3% working interest in this permit covering approximately 47,300 gross acres which is operated by Lundin Petroleum AB. During 2005 oil was discovered in the La Tonnelle-1 exploration well. Further development activity is expected in 2006.

Nangis Permit

We hold a 100% working interest in the approximately 50,000 acre Nagis permit in the northern Paris Basin.

Aufferville permit

We hold a 100% working interest and operate this permit covering approximately 33,100 acres.

United States

We hold non-operating working interests in 943 gross wells (52 net wells) primarily in Texas, Oklahoma, New Mexico, Kansas and Louisiana. We intend to spend approximately $3 million in the United States in 2006.

Title To Oil and Natural Gas Properties

We do not hold title to any of our international properties, but we have been granted permits by the applicable government entities that allow us, as applicable, to engage in exploration, exploitation and production.

Turkey

We have 22 exploration permits covering six geographic regions. The Western Black Sea permits have been extended through 2007, the Calgan permit expires in 2007, the Southeast Turkey and the Eastern Black Sea permits expire in 2008 and the Thrace Black Sea and the Central Black Sea permits expire in 2009. Onshore exploration permits are granted for four-year terms and may be extended for two additional two-year terms, and offshore exploration permits are granted for six-year terms and may be extended for two additional three-year terms, provided that drilling obligations stipulated under Turkish law are satisfied. Under Turkish law, exploitation permits are generally granted for a period of 20 years and may be renewed upon application for two additional 10-year periods. If an exploration permit is extended for development as an exploitation permit, the period of the exploration permit is counted toward the 20-year exploitation permit.

The following is certain information relating to our Turkish proved reserves:


				At December 31, 2005
	Permit							Post-Expiration Proved				Percent of Proved
	Expiration			Total Proved Reserves				Reserves				Reserves
Property	Year			(MBbl)		(MMCF)		(MBbl)		(MMCF)		Post-Expiration
Zeynel		2013	(1)		44				13				29.54	%
Cendere (2 permits)		2011	(1)		595				216				36.30	%
S Akcakoca Sub-Basin		2007	(2)				6,477				4,037		62.33	%


(1)		Exploitation Permit

(2)		Exploration Permit

Hungary

We have not yet established proved reserves on any of these properties. We have one exploration permit that expires in 2009.

Romania

The Moinesti and Viperesti permits will expire in 2009 and the Fauresti rehabilitation permit will expire in 2015. If, prior to the expiration of our Romanian permits, we have not completed the minimum exploration program required by the permits, we must pay the estimated costs of such exploration program to the Romanian government. If we were required to make such payments to the Romanian government, we estimate that the aggregate amount

would be approximately $8 million. We have not yet established proved reserves on the Moinesti and Viperesti permits.

The following is certain information relating to our Romanian proved reserves, all of which relate to the pre-expiration period of the Fauresti Rehabilitation permit:

At December 31, 2005

Total Proved

Permit Expiration

Reserves

Oil

Gas

Property

Year

(MBOE)

(MBbl)

(MMcf)_

Fauresti

2015

605

3,486

France

We hold four French exploration permits: Aufferville, Nemours, Nangis and Courtenay. No proved reserves have been established in these permits. The Nangis permit expiry date has been extended to mid-2006, the Courtenay permit expires in 2006, and the Aufferville and Nemours permits both expire in 2007. The French exploration permits have minimum financial requirements that we expect to meet during their terms. If such obligations are not met, the permits could be subject to forfeiture.

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


			At December 31, 2005
			Total Proved		Post-Expiration		Percent of Proved
	Permit Expiration		Reserves		Proved Reserves		Reserves
Property	Year		(MBbl)		(MBbl)		Post-Expiration_
Neocomian Fields		2011		8,367		6,208		74.22	%
Charmottes Field		2013		2,611		975		37.34	%

Although the French government has no obligation to renew exploitation permits, we believe it will renew such exploitation permits so long as we, the permit holder, demonstrate financial and technical capabilities and establish the studies used in defining the work schedule. However, there can be no assurance that we will be able to renew any permits that expire.

United States

We currently own interests in producing acreage only in the form of non-operating working interests due to the sale of our U.S. mineral and royalty interests in January 2004.

Oil and Natural Gas Reserves

The following table sets forth information about our estimated net proved reserves at December 31, 2005 and 2004. LaRoche Petroleum Consultants, Ltd., an independent petroleum engineering firm in Dallas, Texas, prepared the estimates of proved developed reserves, proved undeveloped reserves and discounted present value (pretax). We prepared the estimate of standardized measure of proved reserves in accordance with Financial Accounting Standards Board Statement of Financial Accounting Standards No. 69, Disclosures about Oil and Gas Producing Activities. No reserve reports have been provided to any governmental agencies.


	December 31,
	2005		2004
	(restated)		(restated)
U.S.
Proved developed:
Oil (MBbl)		792		775
Gas (MMcf)		5,225		4,875
Total (MBOE)		1,663		1,587
Proved undeveloped:
Oil (MBbl)		1		5
Gas (MMcf)		70		58
Total (MBOE)		12		15
Discounted present value at 10% (pretax) (in thousands) (1)	$	20,180	$	19,951
Standardized measure of proved reserves (in thousands)	$	21,033	$	13,906

FRANCE
Proved developed:
Oil (MBbl)		7,688		7,309
Proved undeveloped:
Oil (MBbl)		3,290		4,227
Discounted present value at 10% (pretax) (in thousands) (1)	$	144,738	$	98,248
Standardized measure of proved reserves (in thousands)	$	109,129	$	54,600

TURKEY
Proved developed:
Oil (MBbl)		378		360
Proved undeveloped:
Oil (MBbl)		261		267
Gas (MMcf)		6,476		—
Total (MBOE)		1,340		267
Discounted present value at 10% (pretax) (in thousands) (1)	$	14,390	$	4,065
Standardized measure of proved reserves (in thousands)	$	15,788	$	8,226

ROMANIA
Proved developed:
Oil (MBbl)		24		—
Gas (MMcf)		3,486		—
Total (MBOE)		605		—
Discounted present value at 10% (pretax) (in thousands) (1)	$	1,798	$	—
Standardized measure of proved reserves (in thousands)	$	10,676	$	—

COMBINED
Proved developed:
Oil (MBbl)		8,882		8,444
Gas (MMcf)		8,711		4,875
Total (MBOE)		10,334		9,256
Proved undeveloped:
Oil (MBbl)		3,552		4,499
Gas (MMcf)		6,546		58
Total (MBOE)		4,643		4,509
Total proved:
Oil (MBbl)		12,434		12,943
Gas (MMcf)		15,257		4,933
Total (MBOE)		14,977		13,765
Discounted present value at 10% (pretax) (in thousands) (1)	$	181,106	$	122,264
Standardized measure of proved reserves (in thousands)	$	156,626	$	76,732


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

Reserves were estimated using oil and natural gas prices and production and development costs in effect on December 31, 2005 and 2004, without escalation. The reserves were determined using both volumetric and production performance methods. Proved reserves are those estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.THE VALUES REPORTED MAY NOT NECESSARILY REFLECT THE FAIR MARKET VALUE OF THE RESERVES.

Productive Wells

The following table shows our gross and net interests in productive oil and natural gas wells as of December 31, 2005. Productive wells include wells currently producing or capable of production.


	Gross (1)						Net (2)
	Oil		Gas		Total		Oil		Gas		Total
United States		663		280		943		21.89		29.83		51.72
France		104		—		104		103.50		—		103.50
Turkey		15		—		15		2.94		—		2.94


(1)		“Gross” refers to wells in which we have a working-interest.

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

Acreage

The following table shows the developed and undeveloped acreage attributable to our ownership as of December 31, 2005.


	Developed Acreage				Undeveloped Acreage				Total Acreage
	Gross		Net		Gross		Net		Gross		Net
United States		253,740		37,405		89,581		40,208		343,321		77,613
France		24,260		24,260		313,891		282,376		338,151		306,636
Turkey		31,730		3,059		2,614,303		1,975,459		2,646,033		1,978,518
Romania		—		—		625,325		625,325		625,325		625,325
Hungary		—		—		764,237		764,237		764,237		764,237

Total		309,730		64,724		4,407,337		3,687,605		4,717,067		3,752,329

Undeveloped acreage includes only those leased acres on which wells have not been drilled or completed to permit the production of commercial quantities of oil and natural gas regardless of whether or not the acreage contains proved reserves.

Drilling Activity

The following table shows our drilling activities on a gross and net basis for the years ended 2005, 2004 and 2003.


	Year ended December 31,
	2005				2004				2003
	Gross (1)		Net (2)		Gross (1)		Net (2)		Gross (1)		Net (2)
UNITED STATES
Development:
Gas (3)		7		0.08		3		0.75		1		0.03
Oil (4)		20		0.04		4		0.20		2		0.19
Abandoned (5)		2		0.26		—		—		—

Total		29		0.38		7		0.95		3		0.22


Exploratory
Gas (3)		1		0.25		—		—		—		—
Oil (4)		2		0.45		—		—		—		—
Abandoned (5)		—		—		3		0.5		—		—

Total		3		0.70		3		0.5		—		—


FRANCE
Development:
Oil (4)		5		5		7		7		—		—
Abandoned (5)		—		—		—		—		—		—

Total		5		5		7		7		—		—


Exploratory:
Oil (4)		1		0.5		—		—		—		—
Abandoned (5)		—		—		—		—		—		—

Total		1		0.5		—		—		—		—


TURKEY
Development:
Gas (3) (8)		4		1.8		—		—		—		—
Abandoned (5)		1		0.4		—		—		—		—

Total		5		2.2		—		—		—		—


Exploratory
Oil (6)		—		—		1		0.75		—		—
Gas (7)		—		—		1		0.40		—		—
Abandoned (5)		—		—		—		—		2		1.30

Total		—		—		2		1.15		2		1.30


(1)		“Gross” is the number of wells in which we have a working interest.

(2)		“Net” is the aggregate obtained by multiplying each gross well by our after payout percentage working interest.

(3)		“Gas” means natural gas wells that are either currently producing or are capable of production.

(4)		“Oil” means producing oil wells.

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

(6)		“Oil” means oil shows were found and temporarily suspended awaiting further work.

(7)		“Gas” means gas flow was tested and temporarily suspended awaiting further work.

(8)		Includes two wells that are replacement wells for the wells lost when the production structure collapsed.

Net Production, Unit Prices And Costs

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


	United
	States		France		Turkey		Total
Year Ended December 31, 2005
Production:
Oil (Bbls)		60,433		403,991		64,792		529,216
Daily average (Bbls/Day)		165		1,107		178		1,450
Gas (Mcf)		569,566		—		—		569,566
Daily average (Mcf/Day)		1,560		—		—		1,560
Daily average (BOE/Day)		425		1,107		178		1,710

Unit prices:
Average oil price ($/Bbl)	$	52.37	$	50.92	$	43.48	$	50.17
Average gas price ($/Mcf)		7.56		—		—		7.56
Average equivalent price ($/BOE)		48.08		50.92		43.48		49.86

Unit costs ($/BOE):
Lease operating	$	13.49	$	13.34	$	10.96	$	13.13
Exploration and acquisition		8.05		2.50		4.46		4.71
Depreciation, depletion and amortization		7.63		8.70		8.44		8.40
Dry hole cost		—		—		26.84		2.79
General and administrative		33.51		2.33		7.22		10.70

Total	$	62.68	$	26.87	$	54.92	$	39.73


Year Ended December 31, 2004
Production:
Oil (Bbls)		68,129		396,806		73,118		538,053
Daily average (Bbls/Day)		187		1,087		200		1,474
Gas (Mcf)		546,118		—		—		546,118
Daily average (Mcf/Day)		1,496		—		—		1,496
Daily average (BOE/Day)		436		1,087		200		1,723

Unit prices:
Average oil price ($/Bbl)	$	38.87	$	35.39	$	31.05	$	35.24
Average gas price ($/Mcf)		5.81		—		—		5.81
Average equivalent price ($/BOE)		35.44		35.39		31.05		34.90

Unit costs ($/BOE):
Lease operating	$	11.00	$	12.31	$	10.44	$	11.76
Exploration and acquisition		8.55		0.36		41.41		7.20
Depreciation, depletion and amortization		7.84		5.93		6.93		6.53
General and administrative		26.41		3.66		24.74		11.86

Total	$	53.80	$	22.26	$	83.52	$	37.35


	United
	States		France		Turkey		Total		Total (1)
Year Ended December 31, 2003
Production:
Oil (Bbls)		190,118		373,999		91,680		655,797		541,467
Daily average (Bbls/Day)		521		1,025		251		1,797		1,483
Gas (Mcf)		1,578,591		—		—		1,578,591		739,941
Daily average (Mcf/Day)		4,325		—		—		4,325		2,027
Daily average (BOE/Day)		1,260		1,025		251		2,535		1,821

Unit prices:
Average oil price ($/Bbl)	$	28,17	$	25.76	$	24.29	$	26.40	$	26.02
Average gas price ($/Mcf)		4.78		—		—		4.78		4.74
Average equivalent price ($/BOE)		28.46		25.76		24.29		26.94		26.47

Unit costs ($/BOE):
Lease operating	$	2.48	$	11.47	$	8.81	$	6.77	$	10.01
Exploration and acquisition		2.52		—		13.22		2.60		3.63
Depreciation, depletion and amortization		3.05		4.22		5.65		3.78		4.88
Impairment of oil and natural gas properties		0.38		—		—		0.19		0.26
General and administrative		4.25		2.17		11.09		4.09		4.49

Total	$	11.68	$	17.86	$	38.77	$	17.43	$	23.27


(1)		This column sets forth production and other information for the year ended December 31, 2003, as if the sale of U. S. mineral royalty assets had taken on January 1, 2003.

Office Lease

We occupy 16,327 square feet of office space at 4809 Cole Avenue, Suite 108, Dallas, Texas 75205 under a lease from SVP Cole, L.P. We also occupy 3,218 square feet of office space Paris, France, approximately 9,000 square feet of office in Ankara, Turkey, 3,767 square feet in Bucharest, Romania and 2,896 square feet of office space in Budapest, Hungary. Total rental expense for 2005 was approximately $354,000

Markets and Competition

In France, we currently sell all of our oil production to Elf Antar France S.A., the largest purchaser in the area. This production is shipped by truck to a nearby Elf refinery. The oil also can be transported to refineries on the north coast of France via pipeline. Production in Turkey is sold to refineries in the southern part of the country.

Our domestic oil and natural gas production is sold to various purchasers typically in the areas where the oil or natural gas is produced. Generally, we do not refine or process any of the oil and natural gas we produce. We are currently able to sell, under contract or in the spot market through the operator, substantially all of the oil and the natural gas we are capable of producing at current market prices. Most of our oil and natural gas is sold under short-term contracts or contracts providing for periodic adjustments or in the spot market; therefore, our revenue streams are highly sensitive to changes in current market prices. Our natural gas is sold to pipeline companies rather than end users.

The oil and natural gas industry is highly competitive. We encounter strong competition from other independent operators and from major oil companies in acquiring properties, contracting for drilling equipment and securing trained personnel. Many of these competitors have financial and technical resources and staffs substantially larger than those available to us. As a result, our competitors may be able to pay more for desirable leases, and they may pay more to evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources permit us to do.

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

Competition for attractive oil and natural gas producing properties, undeveloped leases and drilling rights is also strong, and we can give no assurance we will be able to compete satisfactorily in acquiring properties. Many major oil companies have publicly indicated their decision to focus on overseas activities. We cannot ensure we will be successful in acquiring any such properties.

Government Regulation

International

General

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

Government Regulation

Our current or future operations, including exploration and development activities on our properties, require permits from various governmental authorities, and such operations are and will be governed by laws and regulations governing prospecting, development, production, exports, taxes, labor standards, occupational health, waste disposal, toxic substances, land use, environmental protection and other matters. Compliance with these requirements may prove to be difficult and expensive. See “Item 1A. Risk Factors” for further information regarding international government regulation.

Permits and License

In order to carry out exploration and development of mineral interests or to place these into commercial production, we may require certain licenses and permits from various governmental authorities. There can be no guarantee that we will be able to obtain all necessary licenses and permits that may be required. In addition, such licenses and permits are subject to change and there can be no assurances that any application to renew any existing licenses or permits will be approved. See “Item 1A. Risk Factors” for further information regarding our foreign permits and licenses.

Repatriation of Earnings

Currently, there are no restrictions on the repatriation of earnings or capital to foreign entities from France, Turkey, Romania or Hungary. However, there can be no assurance that any such restrictions on repatriation of earnings or capital from the aforementioned countries or any other country where we may invest will not be imposed in the future.

Environmental

The oil and natural gas industry is subject to extensive and varying environmental regulations in each of the jurisdictions in which we may operate. Environmental regulations establish standards respecting health, safety and environmental matters and place restrictions and prohibitions on emissions of various substances produced concurrently with oil and natural gas. These regulations can have an impact on the selection of drilling locations and facilities, potentially resulting in increased capital expenditures. In addition, environmental legislation may require

those wells and production facilities to be abandoned and sites reclaimed to the satisfaction of local authorities. We are committed to complying with environmental and operation legislation wherever we operate.

Domestic

General

The availability of a ready market for oil and natural gas production depends upon numerous factors beyond our control. These factors include state and federal regulation of oil and natural gas production and transportation, as well as regulations governing environmental quality and pollution control, state limits on allowable rates of production by a well or proration unit, the amount of oil and natural gas available for sale, the availability of adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels. For example, a productive natural gas well may be “shut-in” due to an oversupply of natural gas or lack of an available natural gas pipeline in the areas in which we may conduct operations. State and federal regulations generally are intended to prevent waste of oil and natural gas, protect rights to produce oil and natural gas between owners in a common reservoir, control the amount of oil and natural gas produced by assigning allowable rates of production, and control contamination of the environment. Pipelines and natural gas plants also are subject to the jurisdiction of various federal, state and local agencies.

Our natural gas sales are affected by the availability, terms and costs of transportation. The rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act (“NGA”), as well as under Section 311 of the Natural Gas Policy Act (“NGPA”). Since 1985, the FERC has implemented regulations intended to increase competition within the natural gas industry by making natural gas transportation more accessible to natural gas buyers and sellers on an open-access, nondiscriminatory basis. The FERC has announced several important transportation-related policy statements and rule changes, including a statement of policy and final rule issued February 25, 2000, concerning alternatives to its traditional cost-of-service rate-making methodology to establish the rates interstate pipelines may charge for their services. The final rule revises FERC’s pricing policy and current regulatory framework to improve the efficiency of the market and further enhance competition in natural gas markets.

Our oil sales also are affected by the availability, terms and costs of transportation. The rates, terms, and conditions applicable to the interstate transportation of oil by pipelines are regulated by the FERC under the Interstate Commerce Act. The FERC has implemented a simplified and generally applicable rate-making methodology for interstate oil pipelines to fulfill the requirements of Title XVIII of the Energy Policy Act of 1992 that includes an indexing system to establish ceilings on interstate oil pipeline rates.

We conduct operations on federal, state or Indian oil and natural gas leases. Such operations must comply with numerous regulatory restrictions, including various nondiscrimination statutes, royalty and related valuation requirements, and certain of such operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by the Bureau of Land Management (“BLM”).

The Mineral Leasing Act of 1920 (the “Mineral Act”) prohibits direct or indirect ownership of any interest in federal onshore oil and natural gas leases by a foreign citizen of a country that denies “similar or like privileges” to citizens of the United States. Such restrictions on citizens of a “nonreciprocal” country include ownership or holding or controlling stock in a corporation that holds a federal onshore oil and natural gas lease. If this restriction is violated, the corporation’s lease can be canceled in a proceeding instituted by the United States Attorney General. Although the regulations of the BLM (which administers the Mineral Act) provide for agency designations of nonreciprocal countries, there are presently no such designations in effect. We own interests in federal onshore oil and natural gas leases. It is possible that some of our stockholders may be citizens of foreign countries, which at some time in the future might be determined to be nonreciprocal under the Mineral Act.

The pipelines we use to gather and transport our oil and natural gas may be subject to regulation by the Department of Transportation (“DOT”) under the Hazardous Liquids Pipeline Safety Act of 1979, as amended (“HLPSA”). The HLPSA governs the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Where applicable, the HLPSA requires us and other pipeline operators to comply

with regulations issued pursuant to HLPSA that are designed to permit access to and allow copying of records and to make certain reports available and provide information as required by the Secretary of Transportation.

The Pipeline Safety Act of 1992 (the “Pipeline Safety Act”) amends the HLPSA in several important respects. The Pipeline Safety Act requires the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) of DOT to consider environmental impacts, as well as its traditional public safety mandate, when developing pipeline safety regulations. In addition, the Pipeline Safety Act mandates the establishment by DOT of pipeline operator qualification rules requiring minimum training requirements for operators, and requires that pipeline operators provide maps and records to PHMSA. It also authorizes PHMSA to require certain pipeline modifications as well as operational and maintenance changes. We believe our pipelines are in substantial compliance with the HLPSA and the Pipeline Safety Act and their regulations and comparable state laws and regulations where such laws and regulations are applicable. However, we could incur significant expenses if new or additional safety measures are required.

U.S. Federal and State Taxation

Federal and state governments may propose tax initiatives that affect us. We are unable to determine what effect, if any, future proposals would have on product demand or our results of operations.

U.S. Environmental Regulation

Exploration, development and production of oil and natural gas, including operation of saltwater injection and disposal wells, are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, installing and operating oil and natural gas wells. Our domestic activities are subject to a variety of environmental laws and regulations, including, but not limited to:

	•		Oil Pollution Act of 1990 (OPA);

	•		Clean Water Act (CWA);

	•		Comprehensive Environmental Response, Compensation and Liability Act (CERCLA);

	•		Resource Conservation and Recovery Act (RCRA);

	•		Clean Air Act (CAA); and

	•		Safe Drinking Water Act (SDWA).

Our domestic activities also are controlled by state regulations promulgated under comparable state statutes. We also are subject to regulations governing the handling, transportation, storage and disposal of naturally occurring radioactive materials that are found in our oil and natural gas operations. Civil and criminal fines and penalties may be imposed for noncompliance with these environmental laws and regulations. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking certain activities, limit or prohibit other activities due to protected areas or species, can impose certain substantial liabilities for the cleanup of pollution, impose certain reporting requirements, and can require substantial expenditures for compliance.

Under OPA and CWA, our release of oil and hazardous substances into or upon waters of the United States, adjoining shore lines and wetlands and offshore areas could result in our being held responsible for the (1) costs of remediating a release, (2) administrative and civil penalties and/or criminal fines, (3) OPA specified damages such as loss of use and (4) natural resource damages. The extent of liability could be extensive depending upon the circumstances of the release. Liability can be joint and several and without regard to fault. The CWA also may impose permitting requirements for certain discharges of pollutants and requirements to develop Spill Prevention Control and Countermeasure Plans and Facility Response Plans to address potential discharges of oil into or upon waters of the United States and adjoining shorelines.

CERCLA and comparable state statutes, also known as Superfund laws, can impose joint, several and retroactive liability, without regard to fault or the legality of the original conduct, on specified classes of persons for the release of a “hazardous substance” into the environment. In practice, clean-up costs are usually allocated among various responsible parties. Liability can arise from conditions on properties where operations are conducted and/or from conditions at third-party disposal facilities where wastes from operations were sent. Although CERCLA, as

amended, currently exempts petroleum (including oil, natural gas and natural gas liquids) from the definition of hazardous substance, some similar state statutes do not provide such an exemption. Additionally, our operations may involve the use or handling of other materials that may be classified as hazardous substances under CERCLA and similar state statutes. We cannot assure investors that the exemption will be preserved in any future amendments of the Act. Such amendments could have a significant impact on our costs or operations.

RCRA and comparable state and local programs impose requirements on the management, including treatment, storage and disposal, of both hazardous and nonhazardous solid wastes. Although we believe we have utilized operating and waste disposal practices that were standard in the industry at the time, hydrocarbons or other solid wastes may have been disposed or released on or under the properties we own or lease or on or under locations where such wastes have been taken for disposal. In addition, many of these properties have been owned or operated by third parties. We have not had control over such parties’ treatment of hydrocarbons or other solid wastes and the manner in which such substances may have been disposed or released. We generate hazardous and nonhazardous solid waste in our routine operations. From time to time, proposals have been made that would reclassify certain oil and natural gas wastes, including wastes generated during pipeline, drilling and production operations, as “hazardous wastes” under RCRA, which would make these solid wastes subject to much more stringent handling, transportation, storage, disposal and clean-up requirements. Adoption of these proposals could have a significant impact on our operating costs. While state laws vary on this issue, state initiatives to further regulate oil and natural gas wastes could have a similar impact on our operations.

Oil and natural gas exploration and production, and possibly other activities, have been conducted at the majority of our properties by previous owners and operators. Materials from these operations remain on some of the properties and in some instances require remediation. In some instances we have agreed to indemnify the sellers of producing properties from whom we have acquired reserves against certain liabilities for environmental claims associated with the properties. We do not believe the costs to be incurred by us for compliance and remediating previously or currently owned or operated properties will be material, but we cannot guarantee that potential costs would not result in material expenditures.

If in the course of our routine oil and natural gas operations, surface spills and leaks, including casing leaks of oil or other materials occur, we may incur penalties and costs for waste handling, remediation and third-party actions for damages. Moreover, we are able to directly control the operations of only the wells that we operate. Notwithstanding our lack of control over wells owned by us but operated by others, the failure of the operator to comply with applicable environmental regulations may, in certain circumstances, be attributable to us and may create legal liabilities for us.

We do not anticipate that we will be required in the near future to expend amounts that are material in relation to our total capital expenditures program by reason of environmental laws and regulations, but inasmuch as these laws and regulations are frequently changed and interpreted, we are unable to predict the ultimate cost of compliance or the extent of liability risks. We are unable to assure investors that more stringent laws and regulations protecting the environment will not be adopted or that we will not incur material expenses in complying with environmental laws and regulations in the future. If substantial liabilities to third parties or governmental entities are incurred, the payment of such claims may reduce or eliminate the funds available for project investment or result in loss of our properties. Although we maintain insurance coverage we consider to be customary in the industry, we are not fully insured against all of these risks, either because insurance is not available or because of high premium costs. Accordingly, we may be subject to liability or may lose substantial portions of properties due to hazards that cannot be insured against or have not been insured against due to prohibitive premium costs or for other reasons. The imposition of any of these liabilities or compliance obligations on us may have a material adverse effect on our financial condition and results of operations.

OSHA and Other Regulations

We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under the Title III of CERCLA and similar state statutes require us to organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

Employees

As of March 24, 2006, we employed 67 full-time employees. None of our employees are represented by unions or covered by collective bargaining agreements. To date, we have not experienced any strikes or work stoppages due to labor problems, and we have good relations with our employees. As needed, we also utilize the services of independent consultants on a contract basis.

Segment Reporting

See Note 17 in the Notes to Consolidated Financial Statements for financial information by segment.

Internet Address/Availability of Reports

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

Glossary Of Selected Oil and Natural Gas Terms

“3D” or “3D SEISMIC.” An exploration method of sending energy waves or sound waves into the earth and recording the wave reflections to indicate the type, size, shape, and depth of subsurface rock formations. 3D seismic provides three-dimensional pictures.

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

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

“BTU.” British Thermal Unit.

“DEVELOPMENT WELL” A well drilled within the proved boundaries of an oil or natural gas reservoir with the intention of completing the stratigraphic horizon known to be productive.

“DISCOUNTED PRESENT VALUE.” The present value of proved reserves is an estimate of the discounted future net cash flows from each property at the specified date, or as otherwise indicated. Net cash flow is defined as net revenues, after deducting production and ad valorem taxes, less future capital costs and operating expenses, but before deducting federal income taxes. The future net cash flows have been discounted at an annual rate of 10% to determine their “present value.” The present value is shown to indicate the effect of time on the value of the revenue stream and should not be construed as being the fair market value of the properties. In accordance with Securities and Exchange Commission rules, estimates have been made using constant oil and natural gas prices and operating costs at the specified date, or as otherwise indicated.

“DRY HOLE.” A development or exploratory well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

“EXPLORATORY WELL” A well drilled to find and produce oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir, or to extend a known reservoir.

“GROSS ACRES” or “GROSS WELLS.” The total number of acres or wells, as the case may be, in which a working or any type of royalty interest is owned.

“MBbl.” One thousand Bbls.

“MBOE.” One thousand BOE.

“Mcf.” One thousand cubic feet of natural gas.

“MMBOE.” One million BOE.

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

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

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

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

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

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

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

“STANDARDIZED MEASURE.” Under the Standardized Measure, future cash flows are estimated by applying year-end prices, adjusted for fixed and determinable changes, to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end costs to determine pretax cash inflows. Future income taxes are computed by applying the statutory tax rate to the excess inflows over a company’s tax basis in the associated properties.

Tax credits, net operating loss carryforwards and permanent differences also are considered in the future tax calculation. Future net cash inflows after income taxes are discounted using a 10% annual discount rate to arrive at the Standardized Measure.

“UNDEVELOPED ACREAGE.” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

“WORKING INTEREST.” The operating interest (not necessarily as operator) that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production, subject to all royalties, overriding royalties and other burdens, and to all exploration, development and operational costs including all risks in connection therewith.

PART II

Item 6. Selected Financial Data

The following selected financial information (which is not covered by the report of independent registered public accounting firm) is summarized from our results of operations for the five-year period ended December 31, 2005 and as well as selected consolidated balance sheet data as of December 31, 2005, 2004, 2003, 2002 and 2001 (restated for 2005, 2004, 2003 and 2002) and should be read in conjunction with the consolidated financial statements and the notes thereto included in “Item 8. Financial Statements and Supplementary Data.”


	Years ended December 31,
	2005			2004			2003			2002			2001
	(restated) (1)			(restated) (1)			(restated)(1)(2)			(restated)(1)
	(Amounts in thousands, except per share amounts)
Operating Results:
Revenues	$	31,117		$	21,028		$	16,240		$	15,375		$	7,963
Costs and expenses		(24,911	)		(23,502	)		(15,976	)		(17,897	)		(11,538	)

Operating income (loss)		6,206			(2,474	)		264			(2,522	)		(3,575	)
Other income from continuing operations (expense)		4,027			(949	)		2,593			(5,205	)		(974	)

Income (loss) before income taxes		10,233			(3,423	)		2,857			(7,727	)		(4,549	)
Income tax benefit		315			1,153			603			2,061			1,802

Income (loss) from continuing operations, net of tax		10,548			(2,270	)		3,460			(5,666	)		(2,747	)
Income (loss) from discontinued operations, net of tax		47			17,690			1,182			(441	)		2,105
Dividends on preferred shares		(684	)		(714	)		(500	)		(374	)		(360	)

Net income (loss) available to common shares	$	9,911		$	14,706		$	4,142		$	(6,481	)	$	(1,002	)

Basic income (loss) available to common shares per share	$	0.69		$	1.54		$	0.44		$	(0.69	)	$	(0.16	)

Diluted income (loss) available to common shares per share	$	0.65		$	1.54		$	0.44		$	(0.69	)	$	(0.16	)

Weighted average shares outstanding
Basic		14,213			9,571			9,338			9,343			6,319
Diluted		15,140			9,571			9,347			9,343			6,319

Balance Sheet Data:
Working capital (deficit)	$	91,299		$	(2,728	)	$	(30,022	)	$	(7,569	)	$	(879	)
Oil and natural gas properties, net		138,158			82,394			79,217			71,872			78,028
Total assets		261,814			101,178			95,203			86,853			94,454
Long term debt, including current portion		92,060			9,022			30,976			26,860			36,874
Stockholders’ equity		132,359			61,345			39,598			30,021			33,555
Cash Flow Data:
Net cash provided by (used in) operating activities	$	6,699		$	(3,703	)	$	11,354		$	6,362		$	8,856
Capital expenditures for oil and natural gas property and equipment, including acquisitions		65,963			15,385			4,442			6,178		$	11,979


(1)		As described in Note 3 to the financial statements, the Company restated its financial statements for the years ended December 31, 2002, 2003, 2004 and 2005.

(2)		Effective January 1, 2003, the Company adopted Statements of Financial Accounting Standards No. 143,Accounting for Asset Retirement Obligationsand changed its method of accounting for asset retirement obligations.

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. Unless otherwise noted, all financial information provided in this report gives effect to our restatement as described in “Restatement of Previously Issued Financial Statements.”

Executive Overview

We are an independent international energy company engaged in oil and natural gas exploration, development, production, leasing and acquisition activities. Our strategy is to increase our oil and natural gas reserves through a balanced combination of exploratory drilling, development and exploitation projects and acquisitions. We primarily focus on international exploration activities in countries where we can establish large acreage positions. We also focus on prospects where we do not have to compete directly with major integrated or large independent oil and natural gas producers and where extensive geophysical and geological data is available. Our international operations are located in European Union or European Union candidate countries that we believe have stable governments, have transportation infrastructure, attractive fiscal policies and are net-importers of oil and natural gas.

We currently hold interests in permits granting us the right to explore and develop oil and natural gas properties in the Paris Basin, France; onshore and offshore Turkey; onshore Romania; and Hungary. We also own various working-interest properties primarily in Texas, Kansas, New Mexico, Louisiana and Oklahoma.

Income available to common shares for 2005 was $9.9 million, or $0.65 per diluted share, compared with income applicable to common shares of $14.7 million, or $1.54 per diluted share, in 2004. Operating income from continuing operations for 2005 was $6.2 million, compared with an operating loss from continuing operations of $2.5 million in 2004.

Revenues for the year ended December 31, 2005 were $31.1 million, a 48% increase over 2004 revenues of $21 million.

In 2005, our oil and natural gas production was 624,144 BOE versus production of 629,073 BOE for 2004. Our average realized oil price per barrel for 2005 was $50.17, a 42.3% increase over the average realized oil price per barrel of $35.24 in 2004. The average realized gas price in 2005 was $7.56 per Mcf, 30.1% higher than the average realized gas price of $5.81 per Mcf in 2004.

At December 31, 2005, we held interests in approximately 4.7 million gross acres (approximately 3.8 million net acres). For a more detailed description of our properties see “Items 1 and 2. Business and Properties.” At December 31, 2005, our net proved reserves were estimated at approximately 15 MMBOE.

On February 16, 2005, we sold 1,437,500 shares of our common stock pursuant to a public offering at a price to the public of $24.25 per share. The sale resulted in net proceeds of approximately $32.3 million, which was used to fund our 2005 capital expenditure budget and for general corporate purposes.

In June 2005, we acquired 100% of Pogo Hungary Ltd., a wholly owned subsidiary of Pogo Producing Company. The purchase price was approximately $9 million.

On September 16, 2005, we sold 806,450 shares of our common stock to certain accredited investors pursuant to a private placement. The net proceeds of approximately $23.6 million have been and are being used for general corporate purposes, including the funding of our capital expenditures requirements in 2005 and 2006.

On September 27, 2005, we sold $75 million of 5% Convertible Senior Notes due October 1, 2025 to qualified institutional buyers pursuant to Rule 144A of the Securities Act of 1933. The Company also granted the initial purchasers the option to purchase an additional $11.25 million aggregate principal amount of Notes to cover over-allotments. The option was exercised on September 30, 2005, which resulted in a total principal amount of $86.25 million and total net proceeds of approximately $82.2 million. The funds have been and are being used for general corporate purposes, including funding a portion of the Company’s 2005 and 2006 exploration and development activities.

We will continue to seek opportunities to accelerate our worldwide acquisition and development program by:

	•		Exploiting existing properties and developing existing reserves.

	•		Implementing a balanced program of exploration, development and exploitation, thereby managing our risk exposure.

	•		Pursuing new permits and selective property acquisitions under terms that include:

	•		High-impact exploration concessions in core geographic areas primarily located in the Euro-Eastern Mediterranean region; and

	•		Established producing properties that offer potentially significant additions to our asset base.

•

Maintaining operational flexibility by adjusting our drilling program and capital expenditure budget during the year when necessary.

RESTATEMENT OF PREVIOUSLY ISSUED FINANCIAL STATEMENTS

In August 2006, the Company’s management and the audit committee determined that the Company should restate its financial statements for the quarter ended March 31, 2006, and on September 7, 2006, the management and audit committee of Toreador determined that the Company should restate its consolidated financial statements as of and for the year ended December 31, 2005, and its consolidated financial statements for the quarter ended June 30, 2006.

In this Annual Report on Form 10-K/A, we have restated our previously filed consolidated financial statements for the years ended December 31, 2005, 2004 and 2003. The restatement adjustments resulted in a cumulative net decrease in retained earnings of $1.8 million as of December 31, 2005, and a cumulative net decrease in stockholders’ equity of $1.9 million as of December 31, 2005. The restatement adjustments also resulted in an increase in previously reported income available to common shares of $2.9 million for the year ended December 31, 2005, a reduction in previously reported income available to common shares of $9.6 million for the year ended December 31, 2004 and an increase in previously reported income available to common shares of $2.3 million for the year ended December 31, 2003. For more information on the background and details of our restatement, see Note 3 to the consolidated financial statements.

Critical Accounting Policies And Management’s Estimates

The discussion and analysis of our financial condition and results of operations is based upon the consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. Our significant accounting policies are described in Note 2 to our consolidated financial statements included in this Form 10-K/A. 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.

The application of the successful efforts method of accounting requires management’s judgment to determine the proper designation of wells as either developmental or exploratory, which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and application of industry experience. Wells may be completed that are assumed to be productive and actually deliver oil and natural gas in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. On occasion, wells are drilled which have targeted geologic structures that are both developmental and exploratory in nature, and in such instances an allocation of costs is required to properly account for the results. Delineation seismic costs incurred to select development locations within a productive oil and natural gas field are typically treated as development costs and capitalized, but often these seismic programs extend beyond the proved reserve areas and therefore management must estimate the portion of seismic costs to expense as exploratory. The evaluation of oil and natural gas leasehold acquisition costs requires management’s judgment to estimate the fair value of exploratory costs related to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

The successful efforts method of accounting can have a significant impact on the operational results reported when we enter a new exploratory area in hopes of finding oil and natural gas reserves. The initial exploratory wells may be unsuccessful and the associated costs will be expensed as dry hole costs. Seismic costs can be substantial which will result in additional exploration expenses when incurred.

Reserve Estimates

Proved reserves are estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods as well as oil and natural gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery after testing by a pilot project or after the operation of an installed program has been confirmed through production response that increased recovery will be

achieved. Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Proved undeveloped reserves on undrilled acreage is limited (i) to those drilling units offsetting productive units that are reasonably certain of production when drilled and (ii) to other undrilled units where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. We emphasize that the volume of reserves are estimates that, by their nature are subject to revision. The estimates are made using geological and reservoir data, as well as production performance data. These estimates are reviewed annually and revised, either upward or downward, as warranted by additional performance data. We had a downward reserve revision of 2.4% for the year ended December 31, 2005 and upward reserve revisions of 5.03% and 2.61% of proved reserves during the years ended December 31, 2004 and 2003, respectively. These reserve revisions resulted primarily from improved or a decline in performance from a variety of sources such as an addition to or a reduction in recoveries below or above previously established lowest known hydrocarbon levels, improved or a decline in drainage from natural drive mechanisms, and the realization of improved or declined drainage areas. If the estimates of proved reserves were to decline, the rate at which we record depletion expense would increase.

Impairment of Oil and Natural Gas Properties

We review our proved oil and natural gas properties for impairment on an annual basis or whenever events and circumstances indicate a potential decline in the recoverability of their carrying value. We estimate the expected future cash flows from our proved oil and natural gas properties and compare these future cash flows to the carrying value of the oil and natural gas properties to determine if the carrying value is recoverable. If the carrying value exceeds the estimated undiscounted future cash flows, we will adjust the carrying value of the oil and natural gas properties to its fair value in the current period. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, anticipated capital expenditures, and a discount rate commensurate with the risk associated with realizing the expected cash flows projected. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the period. Given the complexities associated with oil and natural gas reserve estimates and the history of price volatility in the oil and natural gas markets, events may arise that will require us to record an impairment of our oil and natural gas properties and there can be no assurance that such impairments will not be required in the future nor that they will not be material.

Future Development and Abandonment Costs

Future development costs include costs incurred to obtain access to proved reserves, including drilling costs and the installation of production equipment. Future abandonment costs include costs to dismantle and relocate or dispose of our production equipment, gathering systems, wells and related structures and restoration costs of land. We develop estimates of these costs for each of our properties based upon the type of production structure, depth of water, reservoir characteristics, depth of the reservoir, market demand for equipment, currently available procedures and consultations with construction and engineering consultants. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including changing technology, the ultimate settlement amount, inflation factors, credit adjusted discount rates, timing of settlement and changes in the political, legal, environmental and regulatory environment. We review our assumptions and estimates of future abandonment costs on an annual basis. The accounting for future abandonment costs changed on January 1, 2003, with the adoption of SFAS 143 “Accounting for Asset Retirement Obligations”. SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.

Holding all other factors constant, if our estimate of future abandonment costs is revised upward, earnings would decrease due to higher depreciation, depletion and amortization expense. Likewise, if these estimates were revised downward, earnings would increase due to lower depreciation, depletion and amortization expense.

Income Taxes

For financial reporting purposes, we generally provide taxes at the rate applicable for the appropriate tax jurisdiction. Because our present intention is to reinvest the unremitted earnings in our foreign operations, we do not provide U.S. income taxes on unremitted earnings of foreign subsidiaries. Management periodically assesses the need to utilize these unremitted earnings to finance our foreign operations. This assessment is based on cash flow projections that are the result of estimates of future production, commodity prices and expenditures by tax jurisdiction for our operations. Such estimates are inherently imprecise since many assumptions utilized in the cash flow projections are subject to revision in the future.

Management also periodically assesses, by tax jurisdiction, the probability of recovery of recorded deferred tax assets based on its assessment of future earnings estimates. Such estimates are inherently imprecise since many assumptions utilized in the assessments are subject to revision in the future.

New Accounting Pronouncements

SFAS No. 157,Fair Value Measurement, (“SFAS 157”). This new standard provides guidance for using fair value to measure assets and liabilities. The FASB believes the standard also responds to investors’ requirement for expanded information about the extent to which companies measure assets and liabilities at fair value, the information used to measure fair value, and the effect of fair value measurements on earnings. SFAS 157 applies whenever other standards require (or permit) assets or liabilities to be measured at fair value but does not expand the use of fair value in any new circumstances. The standard clarifies that for items that are not actively traded, such as certain kinds of derivatives, fair value should reflect the price in a transaction with a market participant, including an adjustment for risk, not just the company’s mark-to-model value. SFAS 157 also requires expanded disclosure of the effect on earnings for items measured using unobservable data. Under SFAS 157, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the principal market for asset or liability or, in the absence of a principal market, the most advantageous market for the asset or liability. In this standard, the FASB clarifies the principle that fair value should be based on the assumptions market participants would use when pricing the asset or liability. In support of this principle, SFAS 157 establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. The fair value hierarchy gives the highest priority to quoted prices in active markets and the lowest priority to unobservable data, for example, the reporting entity’s own data. Under the standard, fair value measurements would be separately disclosed by level within the fair value hierarchy. The provisions of SFAS 157 are effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. Earlier application is encouraged, provided that the reporting entity has not yet issued financial statements for that fiscal year, including any financial statements for an interim period within that fiscal year. We are currently evaluating this statement and have not yet determined the impact of such on our financial statements. We plan to adopt this statement when required at the start of our fiscal year beginning January 1, 2008.

In December 2004, the FASB issued SFAS No. 123(R), “Share-Based Payment.” SFAS No. 123(R) revises SFAS No. 123, “Accounting for Stock-Based Compensation,” and focuses on accounting for share-based payments for services provided by employee to employer. The statement requires companies to expense the fair value of employee stock options and other equity-based compensation over the service period. The statement does not require a certain type of valuation model, and either a binomial or Black-Scholes model may be used. During the first quarter of 2005, the Securities and Exchange Commission (SEC) approved a new rule for public companies to delay the adoption of this standard. In April 2005, the SEC took further action to amend Regulation S-X to state that the provisions of SFAS No. 123(R) will be effective beginning with the first annual or interim reporting period of the registrant’s first fiscal year beginning on or after June 15, 2005 for all non-small business issuers. SFAS 123(R) permits public companies to adopt its requirements using one of two methods: a “modified-prospective” method or a “modified-retrospective” method. The Company plans to adopt SFAS 123(R) using the modified-prospective method under which it will record compensation expense for all share-based awards that vest or are granted after the effective date. The adoption of SFAS No. 123(R) will reduce our operating results approximately $80,000 a year for 2006 and 2007, but will not impact our future cash flows.

In April 2005, the FASB issued FASB Staff Position (FSP) FAS 19-1 “Accounting for Suspended Well Costs.” This staff position amends FASB Statement No. 19 “Financial Accounting and Reporting by Oil and Gas Producing Companies” and provides guidance about exploratory well costs to companies who use the successful efforts method of accounting. The position states that exploratory well costs should continue to be capitalized if: 1) a sufficient quantity of reserves are discovered in the well to justify its completion as a producing well and 2) sufficient progress is made in assessing the reserves and the well’s economic and operating feasibility. If the exploratory well costs do not meet both of these criteria, these costs should be expensed, net of any salvage value. Additional annual disclosures are required to provide information about management’s evaluation of capitalized exploratory well costs. In addition, the Staff Position requires the annual disclosure of: 1) net changes from period to period of capitalized exploratory well costs for wells that are pending the determination of proved reserves, 2) the amount of exploratory well costs that have been capitalized for a period greater than one year after the completion of drilling and 3) an aging of exploratory well costs suspended for greater than one year with the number of wells it related to. Further, the disclosures should describe the activities undertaken to evaluate the reserves and the projects, the information still required to classify the associated reserves as proved and the estimated timing for completing the evaluation. For our disclosures, refer to Note 7 of the Notes to the Consolidated Financial Statements.

FASB Interpretation No. 48,Accounting for Uncertainty in Income Taxes — An Interpretation of FASB Statement No. 109,(“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109. FIN 48 also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The new FASB standard also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. The evaluation of a tax position in accordance with FIN 48 is a two-step process. The first step is a recognition process whereby the enterprise determines whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more-likely-than-not recognition threshold, the enterprise should presume that the position will be examined by the appropriate taxing authority that has full knowledge of all relevant information. The second step is a measurement process whereby a tax position that meets the more-likely-than-not recognition threshold is calculated to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006. Earlier application is permitted as long as the enterprise has not yet issued financial statements, including interim financial statements, in the period of adoption. The provisions of FIN 48 are to be applied to all tax positions upon initial adoption of this standard. Only tax positions that meet the more-likely-than-not recognition threshold at the effective date may be recognized or continue to be recognized upon adoption of FIN 48. The cumulative effect of applying the provisions of FIN 48 should be reported as an adjustment to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) in the year of adoption. We are currently evaluating the statement and have not yet determined the impact of such on our financial statements.

On February 16, 2006, the FASB issued Statement 155, “Accounting for Certain Hybrid Instruments — an amendment of FASB Statements No. 133 and 140.” The statement amends Statement 133 to permit fair value measurement for certain hybrid financial instruments that contain an embedded derivative and provides additional guidance on the applicability of Statement 133 and 140 to certain financial instruments and subordinated concentrations of credit risk. The new standard is effective for the first fiscal year that begins after September 16, 2006. We are currently evaluating the impact this new standard will have on the Company.

In March 2005, the FASB issued FIN No. 47,“Accounting for Conditional Asset Retirement Obligations, an interpretation of SFAS No. 143”(“FIN 47”). FIN 47 requires an entity to recognize a liability for the fair value of a conditional asset retirement obligation in the period in which it is incurred if the liability’s fair value can be reasonably estimated. FIN 47 clarifies that the term “conditional asset retirement obligation” as used in SFAS No. 143, “Accounting for Conditional Asset Retirement Obligations,” refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. FIN 47 is effective no later than the end of fiscal years ending after December 15, 2005. The adoption of FIN 47 did not have a material impact on our financial position, results of operations or cash flows.

fair value is determinable, the transaction must be accounted for at fair value resulting in recognition of any gain or loss. SFAS 153 is effective for nonmonetary transactions in fiscal periods that begin after June 15, 2005. We do not anticipate the implementation of this standard will have a material impact on its financial position, results of operations or cash flows.

SEC Staff Accounting Bulletin No. 108,Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements(“SAB No. 108”). In September 2006, the Securities and Exchange Commission (SEC) provided guidance on the consideration of the effects of prior year misstatements in quantifying current year misstatements for the purpose of a materiality assessment. SAB No. 108 establishes a dual approach that requires quantification of financial statement errors based on the effects of the error on each of the company’s financial statements and the related financial statement disclosures. SAB No. 108 is effective for fiscal years ending after November 15, 2006. We currently apply the dual approach to evaluate our misstatements and do not expect our adoption of this statement to effect our future financial reporting.

In March 2004, the Emerging Issues Task Force (“EITF”) reached a consensus that mineral rights, as defined in EITF Issue No. 04-2,“Whether Mineral Rights Are Tangible or Intangible Assets,”are tangible assets and that they should be removed as examples of intangible assets in SFAS Nos. 141,“Business Combinations,”and SFAS No. 142,“Goodwill and Other Intangible Assets.”The Financial Accounting Standards Board (“FASB”) has recently ratified this consensus and directed the FASB staff to amend SFAS Nos. 141 and 142 through the issuance of FASB Staff Positions (“FSP”) Nos. FAS 141-1 and FAS 142-1,“Interaction of FASB Statements No. 141, Business Combinations, and No. 142, Goodwill and Other Intangible Assets, and EITF Issue No. 04-2, “Whether Mineral Rights Are Tangible or Intangible Assets.”In addition, FSP FAS 142-2,“Application of FASB Statement No. 142, Goodwill and Other Intangible Assets, to Oil- and Gas-Producing Entities”confirms that SFAS No. 142 does not change the balance sheet classification or disclosures of mineral rights of oil and gas producing enterprises. Historically, we have included the costs of such mineral rights as tangible assets, which is consistent with the EITF’s consensus. As such, EITF 04-2 and the related FSPs have not affected our consolidated financial statements.

LIQUIDITY AND CAPITAL RESOURCES

This section should be read in conjunction with Notes 9 and 10 to Notes to Consolidated Financial Statements included in this filing.

The Company delayed the filing of its Quarterly Report on Form 10-Q for the nine month period ended September 30, 2006. The delay in filing such Form 10-Q is the result of restatements of Toreador’s consolidated financial statements for the years ended December 31, 2003, 2004 and 2005 and for its consolidated financial statements for each of the quarters ended March 31 and June 30, 2006, as described in Note 3 to the consolidated financial statements.

As a result of this delay, a covenant default occurred under Section 4.03(b) of the Indenture, dated as of September 27, 2005 (the “Indenture”), between Toreador and The Bank of New York Trust Company, N.A. (the “Trustee”), with respect to Toreador’s 5.00% Convertible Senior Notes due 2025. Section 4.03(b) of the Indenture requires Toreador to provide the Trustee with copies of Toreador’s annual reports, information, documents and other reports

that Toreador is required to file with the Securities and Exchange Commission (the “SEC”) pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 within thirty (30) days of when such reports are required to be filed with the SEC.

On December 15, 2006, Toreador received a notice from the Trustee under Section 4.03(b) of the Indenture for failing to provide the Trustee with a copy of its Quarterly Report on Form 10-Q for the nine month period ended September 30, 2006. Under Section 6.01(v) of the Indenture, this covenant default will not lead to an Event of Default unless Toreador fails to cure the covenant default within thirty (30) days after receiving the written notice from the Trustee. The thirty (30) day period ends on January 14, 2007. The Company provided a copy of the quarterly report on the complete Form 10-Q to the Trustee on January 14, 2007. The Company provided a copy of the complete Form 10-Q for the quarter ended September 30, 2006, to the Trustee in accordance with the requirements of the Indenture.

Under Section 6.02 of the Indenture, if an Event of Default occurs and is continuing, the Trustee by written notice to Toreador, or the holders of at least twenty five percent (25%) in aggregate principal amount of the securities then outstanding by written notice to Toreador and the Trustee, may declare the principal of, and any premium and accrued and unpaid interest, if any, and any premium on, all securities to be immediately due and payable. The notes outstanding have an aggregate principal amount of $86.25 million at January 14, 2007.

Under Section 7.2.1 of the Credit Agreement, dated December 30, 2004 (the “Credit Agreement”), between Toreador Exploration & Production, Inc., Toreador Acquisition Corporation (collectively, the “Borrowers”) and Texas Capital Bank, N.A. (“Texas Capital”), the Borrowers are required to provide Texas Capital on or before the 60th day after the last day of each fiscal quarter, a copy of the unaudited consolidated financial statements of Toreador. Under Section 8.1.7 of the Credit Agreement, an Event of Default would occur if either the Borrowers or Toreador, as Guarantor under the Credit Agreement, default in the performance or observance of any other provision contained in any agreements or instruments evidencing or governing a material debt and such default is not waived and continues beyond any applicable cure period. Texas Capital, however, has waived the Default and Event of Default until January 16, 2007. As of January 14, 2007, the Company had $5.55 million borrowed under the Credit Agreement.

Pursuant to Section 19.1.1(b) of the Reserve Base Revolving Facility Agreement by and between Madison Energy France, Madison Oil France, Toreador, Madison Oil Company Europe, and Natixis Banques Populaires (“Natixis”), dated December 23, 2004 (the “Agreement”), Toreador was required to provide Natixis with its unaudited consolidated financial statements for the nine month period ended September 30, 2006 within forty-five (45) days after the end of such quarter. Natixis waived until January 16, 2007 such default and any other default under the Agreement as a result of Toreador not yet providing such financial statements. As of January 14, 2007, Toreador had $11 million borrowed under the Agreement.

Liquidity

As of December 31, 2005, we had cash and cash equivalents and short-term investments of $93.1 million, a current ratio of approximately 5.4 to 1 and a debt (convertible debenture, long-term debt and convertible senior notes) to equity ratio of .70 to 1. For the twelve months ended December 31, 2005, operating income was $6.2 million and capital expenditures, including the acquisition of the Hungarian assets (Pogo Hungary Ltd.) for $9 million, was $66 million.

We believe that our cash flow from operations, net proceeds from our recent private placement, convertible notes offering and available borrowings under our credit facilities will sufficiently fund these capital requirements. We may also use some of these amounts to fund possible acquisitions of properties. We may also seek additional funds if unanticipated capital requirements arise and to fund any potential acquisitions.

Senior Debt

On December 23, 2004, we entered into a five-year $15 million reserve-based borrowing facility with a French lender to finance the development of our existing French fields, acquisitions of new fields, general working capital and other corporate purposes. The facility bears interest at a floating rate of 2.25-2.75% above LIBOR (6.59% total rate at December 31, 2005) depending on the principal outstanding. Toreador and certain of its U.S. and French subsidiaries have each guaranteed the obligations under the facility. This facility will require monthly interest payments until December 23, 2009, at which time all unpaid principal and interest are due. Under the $15 million facility borrowings of approximately $8 million were available at December 31, 2005. The $15 million facility contains various affirmative and negative covenants. These covenants, among other things, limit additional indebtedness, the sale of assets, change of control and management, limitations on the distribution of stock

dividends and require us to meet certain financial requirements. Specifically, we must maintain an interest cost ratio of not less than 4.00 to 1.00, an indebtedness ratio of not less than 1.00 to 1.00, asset life cover ratio of not less than 1.25 to 1.00, a loan life cover ratio equal to or greater than 1.15 to 1.00 and a debt service coverage ratio equal to or greater than 1.10 to 1.00. As of December 31, 2005, we were in compliance with all covenants.

On December 30, 2004, we entered into a five-year $25 million reserve-based borrowing facility with Texas Capital Bank, N.A. in order to finance the development and acquisition of oil and natural-gas interests both domestically and internationally and for working capital purposes. The facility bears interest at a rate of prime less 0.5% (6.75% total rate at December 31, 2005) and is collateralized by our domestic working interests. The borrowers under this facility are two of our domestic subsidiaries, and Toreador has guaranteed the obligations. At December 31, 2005, we had approximately an additional $3.3 million available for borrowings. The $25 million facility requires monthly interest payments until January 1, 2009 at which time all unpaid principal and interest are due. The $25 million facility contains various affirmative and negative covenants. These covenants, among other things, limit additional indebtedness, the sale of assets, change of control and management and require us to meet certain financial requirements. Specifically, we must maintain a current ratio of 1.25 to 1.00 (exclusive of amounts due under revolving credit arrangements) and an interest coverage ratio of not less than 3.00 to 1.00. As of December 31, 2005, we were in compliance with all covenants .

New Secured Revolving Facility

On December 28, 2006, the Company as a guarantor and its direct and indirect subsidiaries, Toreador Turkey Ltd., as a borrower and guarantor, Toreador Romania Ltd., as a borrower and a guarantor, Madison Oil France SAS, as a borrower and a guarantor, Toreador Energy France S.C.S., as a borrower and a guarantor, and Toreador International Holding L.L.C., entered into a Loan and Guarantee Agreement with International Finance Corporation. The Loan and Guarantee Agreement provides for the A Loan Facility which is a secured revolving facility with a current maximum facility amount of $25 million which maximum facility amount will increase to $40 million when the projected total borrowing base amount exceeds $50 million. The A Loan Facility has not closed at this time and is not yet available. The Loan and Guarantee Agreement also provides for a $10 million C Loan Facility to Toreador Turkey and Toreador Romania. As of January 14, 2007 the C Loan Facility had $10 million outstanding. Both the A Loan Facility and the C Loan Facility are to fund the borrowers’ operations in Turkey and Romania.

Interest will accrue on any loans under the A Loan Facility at a rate of 2% over the six month LIBOR rate. Interest accrues on the C Loan Facility at a rate of 1.5% over the six month LIBOR rate until any loans are made under the A Loan Facility after which the rate for the C Loan Facility shall be lowered to 0.5% over the six month LIBOR rate. As of January 14, 2007 the interest rate on the C Loan Facility is 6.86%. Interest is to be paid on each June 15 and December 15.

In order for any loans to be made under the A Loan Facility certain conditions must be met, including, but not limited to, the following: (i) the lender shall have received a first ranking security interest (a) in certain proceeds, receivables and contract rights relating to and from the sale of oil or gas production in France, Turkey and Romania and (b) in funds held in certain bank accounts; (ii) the lender shall have received an assignment of all rights and claims to any compensation or other special payments in respect of all concessions other than those arising in the normal course of operations payable by the government of Turkey and Romania; (iii) the lender shall have received a first ranking pledge (a) by Toreador International of all its shares in the borrowers; (b) by Madison Oil of all its shares in Toreador France; and (c) by the Company of all its shares in Toreador International; and (iv) the current loan facilities with Natixis Banques Populaires and with Texas Capital Bank, N.A. shall have been repaid in full.

The Company is to meet the following ratios on a consolidated basis: (i) the Life of Loan Coverage Ratio of not less than: (a) 1.2:1.0 in 2006 and 2007; (b) 1.3:1.0 in 2008; and (c) 1.4:1.0 in 2009 and each subsequent year thereafter; (ii) Reserve Tail Ratio of not less than 25%; (iii) Adjusted Financed Debt to EBITDA ratio of not more than 3.0:1.0; (iv) Liabilities to Tangible Net Worth Ratio of not more than 60:40; and (v) Interest Coverage Ratio of not less than 3.0:1.0.

The obligors are subject to certain negative covenants, including, but not limited to, the following: (i) subject to certain exceptions, paying dividends; (ii) subject to certain exceptions, incurring debt, making guarantees or creating or permitting to exist any liens, (iii) subject to certain exceptions, making or permitting to exist loans or advances to, or deposits, with other persons or investments in any person or enterprise; (iv) subject to certain exceptions, selling, transferring, leasing or otherwise disposing of all or a material part of its borrowing base assets; and (v) subject to certain exceptions, undertaking or permitting any merger, spin-off, consolidation or reorganization.

Preferred Stock

On February 22, 2005, 82,000 shares of Series A-1 Convertible Preferred Stock were exchanged for an aggregate of 532,664 shares of our common stock. As of December 31, 2005, there were 72,000 shares of Series A-1 Convertible Preferred Stock outstanding. At the option of the holder, the Series A-1 Convertible Preferred Stock may be converted into common shares at a price of $4.00 per common share (conversion would amount to 450,000 Toreador common shares). The Series A-1 Convertible Preferred Stock accrues dividends at an annual rate of $2.25 per share payable quarterly in cash. At any time on or after November 1, 2007, we may elect to redeem for cash any or all shares of Series A-1 Convertible Preferred Stock. The optional redemption price per share is the sum of (1) $25.00 per share plus (2) any accrued unpaid dividends, and such sum is multiplied by a declining multiplier. The multiplier is 105% until October 31, 2008, 104% until October 31, 2009, 103% until October 31, 2010, 102% until October 31, 2011, 101% until October 31, 2012, and 100% thereafter.

5% Convertible Senior Notes Due 2025

On September 27, 2005, we sold $75 million of Convertible Senior Notes due October 1, 2025 to qualified institutional buyers pursuant to Rule 144A of the Securities Act of 1933. We also granted the initial purchasers the option to purchase an additional $11.25 million aggregate principal amount of notes to cover over-allotments. The option was exercised on September 30, 2005. The total principal amount of notes issued was $86.25 million and total net proceeds were approximately $82.2 million.

The notes bear interest at a rate of 5% per annum and can be converted into common stock at an initial conversion rate of 23.3596 shares of common stock per $1,000 principal amount of Notes, subject to adjustment (equivalent to a conversion price of approximately $42.81 per share). We may redeem the notes, in whole or in part, on or after October 6, 2008, and prior to October 1, 2010, for cash at a redemption price equal to 100% of the principal amount of notes to be redeemed, plus any accrued and unpaid interest, if the closing price of its common stock exceeds 130% of the conversion price over a specified period. On or after October 1, 2010, we may redeem the notes, in whole or in part, at a redemption price equal to 100% of the principal amount of notes to be redeemed, plus any accrued and unpaid interest, irrespective of the price of its common stock. Holders may convert their notes at any time prior to the close of business on the business day immediately preceding their stated maturity, and holders may, upon the occurrence of certain fundamental changes, and on October 1, 2010, October 1, 2015, and October 1, 2020, require us to repurchase all or a portion of their notes for cash in an amount equal to 100% of the principal amount of such Notes, plus any accrued and unpaid interest.

Dividend and Interest Requirements

Dividends on our common stock may be declared and paid out of funds legally available when and as determined by our board of directors. Our policy is to hold and invest corporate funds on a conservative basis, and, thus, we do not anticipate paying cash dividends on our common stock in the foreseeable future. The terms of our Series A-1 Convertible Preferred Stock prohibit us from paying dividends on the common stock without the approval of the holders of a majority of the then outstanding shares of the Series A-1 Convertible Preferred Stock.

Dividends on our Series A-1 Convertible Preferred Stock are paid quarterly. For the year ended December 31, 2005 dividends totaled $684,314, of which $186,258 was paid in cash and the remaining $498,056 was paid by the issuance of common stock. Cash dividends of $714,000 were paid for the twelve month period ended December 31, 2004.

The terms of the $15 million reserve-based borrowing facility limit our ability to pay dividends on our common stock to twenty-five percent (25%) of net profit (as defined in the facility agreement), less any dividend amounts paid on our preferred stock.

Contractual Obligations

The following table sets forth our contractual obligations in thousands at December 31, 2005 for the periods shown:


			Less than		One To		Four to		More Than
	Total		One Year		Three Years		Five Years		Five Years
Long-term debt	$	92,060	$	810	$	5,000	$	—	$	86,250
Lease commitments		2,604		1,184		840		118		462

Total contractual obligations	$	94,664	$	1,994	$	5,840	$	118	$	86,712

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

Results of Operations

Comparison of Years Ended December 31, 2005 and 2004


	For the Years Ended December 31,
	2005		2004					2005		2004
Production:					Average Price:
Oil (MBbls):						Oil ($/Bbl):
United States		60		68			United States	$	52.37	$	38.87
France		404		397			France		50.92		35.39
Turkey		65		73			Turkey		43.48		31.05

Total		529		538			Total	$	50.17	$	35.24


Gas (MMcf):						Gas ($/Mcf):
United States		570		546			United States	$	7.56	$	5.81
France		—		—			France		—		—
Turkey		—		—			Turkey		—		—

Total		570		546			Total	$	7.56	$	5.81


MBOE:						$/ BOE:
United States		155		159			United States	$	48.08	$	35.44
France		404		397			France		50.92		35.39
Turkey		65		73			Turkey		43.48		31.05

Total		624		629			Total	$	49.86	$	34.90

Revenues

Oil and natural gas sales

Oil and natural gas sales for the twelve months ended December 31, 2005 were $31.1 million, as compared to $22.3 million for the comparable period in 2004. This increase is primarily due to a significant increase in the average realized price of both oil and natural gas. Production decreased by approximately 10 MBOE due primarily to normal declines in the US and in Turkey, offset by a slight increase in France from the results of successful workovers and new drilling.

The above table compares both volumes and prices received for oil and natural gas for the twelve months ended December 31, 2005 and 2004. Oil and natural gas prices are and probably will continue to be extremely volatile and a significant change will have a material impact on our revenue.

We had no loss on commodity derivatives for the year ended December 31, 2005, as compared to $1.3 million loss for the comparable period of 2004. We were not party to any hedging contracts as of December 31, 2005.

Costs and expenses

Lease operating

Lease operating expense was $8.2 million, or $13.13 per BOE produced for the twelve months ended December 31, 2005, as compared to $7.4 million, or $11.76 per BOE produced for the comparable period in 2004. This increase is primarily due to the workover program in France and a 11 MBOE decline in production when comparing the twelve months ended December 31, 2005 to 2004.

Exploration expense

Exploration expense for the twelve months ended December 31, 2005 was $2.9 million, as compared to $4.5 million for the comparable period in 2004. In 2004 we conducted a seismic program in the Black Sea, resulting in an additional $1.8 million of exploration expense cost in 2004.

Dry hole and abandonment

Dry hole and abandonment cost for the twelve months ended December 31, 2005 was $1.7 million, as compared to no dry hole and abandonment cost for the comparable period of 2004. This increase is due to expensing of the Boyabot # 1 well in Turkey, which did not test sufficient oil and natural gas to be declared commercial.

Depreciation, depletion and amortization.

For the twelve months ended December 31, 2005 depreciation, depletion and amortization expense was $5.2 million, or $8.40 per BOE produced, as compared to $4.1 million, or $6.53 per BOE produced for the twelve months ended December 31, 2004. This increase is primarily due to increased investments in oil and gas properties and a 4,929 BOE decline in production.

Impairment of oil and natural gas properties

Impairment charged in 2005 was $110,000 compared to no impairments in 2004. This increase was due to marginal properties in the United States.

General and administrative

General and administrative expense was $6.7 million for the twelve months ended December 31, 2005, compared with $7.5 million for the comparable period of 2004. The decrease is primarily due to allocating a portion of Turkey’s cost to the development project and exploration expense. This decrease is partially offset by an increase in the United States primarily due to increased staff, Securities and Exchange Commission filings, Sarbanes-Oxley compliance and expensing of stock compensation expense related to the restricted stock granted by the Board of Directors to certain employees and non employee directors.

Other income and expense

Other income and expense resulted in income of $4 million for the twelve months ended December 31, 2005 versus a loss of $949,000 for the comparable period in 2004. The increase was primarily due to a $2.4 million foreign currency exchange gain in 2005 versus a foreign exchange gain of $127,000 in 2004. In 2005 we incurred $1.4 million in interest expense, of which all was capitalized to oil and gas properties, compared to $1.9 million of interest expense in 2004, of which $432,000 was capitalized to oil and gas properties. Also in 2005 we recorded interest income of $1.4 million as compared to $515,000 in 2004.

Discontinued operations

The following table compares discontinued operations for years ended December 31, 2005, 2004 and 2003:


	Twelve Months Ended December 31.
	2005		2004			2003
	(Restated)		(Restated)			(Restated)
	(in thousands)
Revenues:
Oil and natural gas sales	$	63	$	139		$	7,261
Lease bonuses and rentals		—		—			341
Loss on commodity derivatives		—		—			(1,304	)

Total revenues		63		139			6,298
Costs and expenses:
Lease operating		1		(10	)		1,046
Allocated general and administrative		15		163			2,222
Depreciation, depletion and amortization		—		—			734
Interest expense		—		—			711

Total costs and expenses		16		153			4,713
Gain on sale of properties		—		28,711			—

Income before taxes		47		28,697			1,585
Income tax provision		—		11,007			403

Income from discontinued operations	$	47	$	17,690		$	1,182

Income available to common shares

For the twelve months ended December 31, 2005, we reported income from continuing operations net of taxes of $10.6 million, compared with a loss of $2.3 million for the same period of 2004. For the twelve months ended December 31, 2005 income available to common shares was $9.9 million versus $14.7 million for the year ended December 31, 2004.

Other comprehensive income

The most significant element of comprehensive income, other than net income, is foreign currency translation. As of December 31, 2004, we had accumulated an unrealized gain of $4.7 million. In the year ended December 31, 2005, we had an unrealized loss of $8.1 million. The primary reason for decrease is due to the strength of the Euro compared to the United States Dollar in 2005. The functional currency of our operations in France is the Euro and in Romania, Turkey and Hungary the functional currency is the United States Dollar. The exchange rate used to translate the financial position of the French, Turkish, Romanian and Hungarian operations at December 31, 2005 was approximately US $1.18 per Euro, 0.74 New Turkish Lira per US Dollar, 35,080 Romanian Lei per US Dollar and 214.35 Hungarian Forint per US Dollar, respectively. The Euro rate at December 31, 2004, was US $1.36 per Euro and US $0.74 per million Turkish Lira. There were no Romanian or Hungarian operations in the year ended December 31, 2004.

Comparison of Years Ended December 31, 2004 and 2003


	For the Twelve Months Ended December 31,
	2004		2003		2003						2004		2003		2003
					(As adjusted(1))										(As adjusted(1))
Production:							Average Price:
Oil (MBbls):								Oil ($/Bbl):
United States		68		190		75			United States		$	38.87	$	28.17	$	27.89
France		397		374		374			France			35.39		25.76		25.76
Turkey		73		92		92			Turkey			31.05		24.29		24.65

Total		538		656		541				Total	$	35.24	$	26.40	$	26.02


Gas (MMcf):								Gas ($/Mcf):
United States		546		1,579		740			United States		$	5.81	$	4.78	$	4.74
France		—		—		—			France			—		—		—
Turkey		—		—		—			Turkey			—		—		—

Total		546		1,579		740				Total	$	5.81	$	4.78	$	4.74


MBOE:								$/BOE:
United States		159		453		200			United States		$	35.44	$	28.46	$	28.05
France		397		374		374			France			35.39		25.76		25.76
Turkey		73		92		92			Turkey			31.05		24.29		24.65

Total		629		919		666				Total	$	34.90	$	26.94	$	26.47


(1)		This column sets forth production and prices for the year ended December 31, 2003, as if the U. S. mineral royalty asset sale had taken place January 1, 2003.

Revenues

Oil and natural gas sales

For the year ended December 31, 2004, oil and natural gas sales revenues were $22.3 million, increasing approximately $5.3 million, or 31%, from $17.0 million for the year ended December 31, 2003. This was due to an increase in the average prices we received for oil and natural gas sales. In 2004, our average oil price per barrel was $35.24 versus $26.02 in 2003, as adjusted. Our average price for natural gas in 2004 was $5.81 per Mcf, compared with $4.74 in 2003, as adjusted. The increase in revenues was offset by a 5% decrease in overall production of 37,000 BOE from 666,000 BOE in 2003, as adjusted to 629,000 BOE in 2004. Production in the United States, excluding the U.S. mineral royalty asset, decreased 41,000 BOE, the result of the natural decline of our existing properties and the loss of production on the Vermillion 175 #1. Turkish production decreased by 19,000 BOE due to the natural decline of existing properties and the loss of production on the Cendere #12 well. French production increased 23,000 BOE, a result of the workover program and the addition of the Charmottes 109 during the year.

Gain (loss) on commodity derivatives

We utilized commodity derivative instruments as part of our risk management program and, prior to the repayment of our senior credit facilities in January 2004, we utilized them to comply with the requirements of our senior credit facilities. These transactions are generally structured as either swaps or collar contracts. A swap has the effect of an outright sale at a specific price. A collar has the effect of creating a sale only if a floor or ceiling price is exceeded. These instruments: (i) reduce the effect of the price fluctuations of the commodities we produce and sell; and (ii) support our annual capital budgeting and expenditure plans. When we had our senior credit facilities, these instruments protected the amounts required for servicing outstanding debt; and maximized the funds available under these facilities. The trading party that represents the other side of each of these transactions is known as a “counterparty.” The counterparty of our United States transactions is Coral Energy Holdings, L.P., an affiliate of Royal Dutch/ Shell. The counterparty of our French transactions was Barclays Capital. Currently we do not have any

commodity derivative instruments for our production. The following table summarizes the results of our risk-management efforts during 2004 and 2003:


	2004			2003			Variance
	(in thousands)
Changes in fair value	$	1,159		$	(365	)	$	1,524
Realized gain (loss)		(2,481	)		(411	)		(2,070	)

Net	$	(1,322	)	$	(776	)	$	(546	)

As noted above, we had structured our commodity derivatives to reduce the effect of price fluctuations of the commodities we produce and sell. As a result, those derivatives decline in value as the underlying commodity prices rise. Any losses incurred on derivatives are offset by higher oil and natural gas sales revenues due to increases in underlying commodity prices. However, under the requirements of Statement of Financial Accounting Standards No. 133, as amended, and because we chose not to designate our derivatives as hedges, mark to market loss on the derivatives is generally accrued through earnings prior to the recognition of higher sales prices.

Costs and expenses

Lease operating

Lease operating expenses increased $1.2 million, or 19%, from 2003 to 2004, primarily due to the increase in workover costs on our French properties.

Exploration expense

Exploration expense expense increased $2.2 million, from 2003 to 2004, due to the December 2004 seismic program in the Black Sea of Turkey.

Depreciation, depletion and amortization

Depreciation, depletion and amortization increased $634,000, or 18%, compared with 2003 due to decreased reserve balances in Turkey. We calculate depletion on our oil and natural gas properties using the units-of-production method. Current-year production is divided by beginning reserves and then multiplied by the net value of the properties.

Impairment of oil and natural gas properties

Impairment charged in 2004 was zero, compared with $171,000 in 2003.

General and administrative

General and administrative expenses increased $3.7 million, in 2004. The majority of this increase was the result of actual 2003 costs totaling $2.2 million being allocated to discontinued operations based on the percent of oil and natural gas revenues applicable to discontinued operations to the total oil and gas revenues. The remaining increase was the result of the final settlement of a severance claim in France and expenses associated with the pay off of the Barclays credit facility.

Other income and expense

Other income and expense resulted in $949,000 of expense during 2004 versus $2.6 million of income for 2003. The decrease was a result of foreign currency transaction gains of $2.1 million primarily on payments towards the facility we had with Barclays Bank, plc, or the Barclays Facility in 2003. Equity in earnings of unconsolidated subsidiaries had a loss of $18,000 for 2004 compared with a gain of $22,000 for 2003.

Net income available to common shares

During 2004, we had earnings available to common stockholders of $14.7 million, compared with $4.1 million for 2003. Improved results for 2004 were largely due to $17.7 million income from discontinued operations, which includes a $28.7 million gain on the sale of U.S. mineral and royalty properties. In addition, we received a benefit from income taxes of $1.2 million compared to $603,000 in 2003. The increase was mainly the result of utilizing net operating loss carryforwards from prior years.

Other comprehensive income

The most significant element of comprehensive income, other than net income (loss), is foreign currency translation. The functional currency of our operations in France is the Euro, and in Turkey the functional currency is the U.S. dollar. The exchange rate used to translate the financial position of the French operations at December 31, 2004, was approximately U.S. $1.36 per Euro and U.S. $0.74 per million Turkish Lira. At December 31, 2003, the exchange rates were U.S. $1.26 per Euro and U.S. $0.70 per million Turkish Lira.

Selected Quarterly Financial Data (Unaudited)

We derived the selected historical financial data in the table below from our unaudited interim consolidated financial statements. The sum of net income per share by quarter may not equal the net income per share for the year due to variations in the weighted average shares outstanding used in computing such amounts. The historical data presented here are only a summary and should be read in conjunction with the consolidated financial statements, related notes and other financial information included elsewhere in this annual report.


	Three Months Ended
	March			June		September		December
	31			30,		30,		31,
	(in thousands, except per share data)
For the year ended December 31, 2005 (restated) (1):
Total revenues	$	6,676		$	7,164	$	8,770	$	8,507
Total costs and expenses		5,281			5,476		7,040		7,114
Income (loss) from continuing operations		1,925			1,956		1,351		5,316
Income (loss) from discontinued operations, net of tax		10			1		14		22
Net income (loss)		1,935			1,957		1,365		5,338
Income available to common shares		1,372			1,917		1,324		5,298
Basic income available to common shares per share		0.11			0.14		0.09		0.35
Diluted income available to common shares per share		0.10			0.13		0.09		0.32

For the year ended December 31, 2004 (restated) (1):
Total revenues	$	3,862		$	5,134	$	5,631	$	6,401
Total costs and expenses		4,579			3,880		4,023		11,020
Income (loss) from continuing operations		(1,413	)		1,369		1,951		(4,177	)
Income (loss) from discontinued operations, net of tax		17,691			31		81		(113	)
Net income (loss)		16,278			1,400		2,032		(4,290	)
Income (loss) available to common shares		16,098			1,220		1,852		(4,464	)
Basic income (loss) available to common shares per share		2.34			0.13		0.18		(0.86	)
Diluted income (loss) available to common shares per share		1.86			0.12		0.15		(0.77	)

(1)

As described in Note 3 to the financial statements, the Company restated its financial statements for the years ended December 31, 2003, 2004 and 2005.

Off Balance Sheet Arrangements

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

Item 8. Financial Statements and Supplementary Data.

The Report of Independent Registered Public Accounting Firm and Consolidated Financial Statements are set forth beginning on page F-1 of this annual report on Form 10-K/A 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 9A. Controls and Procedures

Corporate Disclosure Controls

Evaluation of Disclosure Controls and Procedures

The Company maintains disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) that are designed to provide reasonable assurance that the information required to be disclosed by us in reports filed under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission.

We carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this amended annual report. Based on that evaluation, our Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer concluded that, as a result of the material weaknesses discussed below, our disclosure controls and procedures as of December 31, 2005 were not effective.

Management’s Annual Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as that term is defined in Exchange Act Rule 13a-15(f) and 15d-15(e). Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting principles. Our control environment is the foundation for our system of internal control over financial reporting and is an integral part of our Code of Ethical Conduct and Business Practices and our Code of Ethics for the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer, which sets the tone of our Company. Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect our transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of our financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.

In order to evaluate the effectiveness of our internal control over financial reporting as of December 31, 2005, as required by Section 404 of the Sarbanes-Oxley Act of 2002, our management conducted an assessment, including testing, based on the criteria set forth in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO Framework”). Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. In addition, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.

Under the supervision and with the participation of our management, including our Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer we conducted an evaluation of the effectiveness of our internal control over financial reporting in connection with the annual report on Form 10-K for the year ended December 31, 2005 filed in March 2006, and in connection with this amended annual report on Form 10-K/A for the year ended December 31, 2005. As a result of these assessments, various materials weaknesses were identified. A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected.

In connection with the filing of our 10-K for the year ended December 31, 2005, in March 2006, we originally identified material weaknesses that contributed to our conclusion that our internal control over financial reporting was not effective. These material weaknesses were as follows:

	•		During the year-end audit several errors were found in spreadsheets. We believe that the failure of the review process to detect the errors constituted a material weakness.

	•		During the audit of the statutory accounts of our French subsidiary, several audit adjustments were recorded to the statutory accounts, which affected the tax basis of our French oil and gas properties. During the preparation of our deferred tax provision, our French staff failed to consider the statutory audit adjustments in determining the book — tax basis difference, which resulted in an error in our deferred tax provision for France.

	•		Our review of the system of controls surrounding the information technology system revealed that 1) several employees could prepare and post entries, leading to a segregation of duties issue; 2) there was inadequate security over the proper storage of offsite back-up tapes and the periodic review of back-up tapes to ensure their accuracy; 3) security logs generated by the system were not periodically reviewed and terminated employees were not disconnected from the system in a timely manner; and 4) several authorized users of our accounting system had access to modules that create additional segregation of duties issues.

As a result of the restatement of our financial statements for the years ended December 31, 2003, 2004 and 2005, we have identified the following material weaknesses:

	•		We did not maintain an effective control environment and our financial and accounting organization was not adequate to support our financial reporting requirements. The involvement of corporate personnel in the reporting of foreign transactions and operations was not sufficient to accurately capture and record such activity and we did not maintain a sufficient complement of personnel with an appropriate level of accounting knowledge, experience and training in the application of generally accepted accounting principles consistent with the level and complexity of our operations.

	•		Our accounting and financial reporting systems and procedures were not sufficiently designed to ensure consistent or complete application of our accounting policies or to prepare financial statements in accordance with generally accepted accounting principles. This includes not only the sufficiency of our review of sensitive calculations, reconciliations and spreadsheets but also the preparation and processing of financial accounting information.

These material weaknesses resulted in adjustments to substantially all accounts in our financial statements and related disclosures for the years ended December 31, 2003, 2004 and 2005. These material weaknesses could result in material misstatements of future annual or interim financial statements that would not be prevented or detected.

Based on our assessment, and because of the material weaknesses described above, management has concluded that our internal control over financial reporting was not effective as of December 31, 2005 to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes in accordance with generally accepted accounting principles.

Changes in Internal Controls

Management has addressed these material weaknesses as follows:

During the year-end audit of the statutory accounts of our French subsidiary, several audit adjustments were recorded to the statutory accounts, which affected the tax basis of our French oil and gas properties. During the preparation of our deferred tax provision, our French staff failed to consider the statutory audit adjustments in determining the book — tax basis difference, which resulted in an error in our deferred tax provision for France. During the course of performing the year-end audit, our registered independent accounting firm detected the omission of the statutory audit adjustments, and we have corrected our French deferred tax provision accordingly.

We engaged an independent third party in May 2006, in France, to verify that all statutory adjustments are properly prepared and correctly stated in the statutory books.

During our review of the system of controls surrounding the information technology system as of December 31, 2005, such review revealed that 1) several employees could prepare and post entries, leading to a segregation of duties issue; 2) inadequate security over the proper storage of offsite back-up tapes and the periodic review of back-up tapes to ensure their accuracy; 3) security logs generated by the system were not periodically reviewed and terminated employees were not disconnected from the system in a timely manner; and 4) several authorized users of our accounting system have access to modules that create additional segregation of duties issues. We have restricted access in June 2006 to the journal entry module within our accounting system, and implemented a control to ensure that posted journal entries are properly supported and approved. We are still in the process of reviewing logical access to our accounting system and modifying such access to prevent segregation of duties issues. Additionally, we are currently in the process of reviewing our practices in implementing changes or compensating controls where necessary to remediate the other weaknesses mentioned above. Included in our remediation activities was the hiring of a full-time information technology professional to supervise these efforts.

Management is currently evaluating the implementation of additional procedures that may be necessary to fully remediate these material weaknesses. Management is in the process of making the following changes to its system of internal controls.

	•		Improving the computerized integrated financial reporting system. This will automate the manual processes that are causing errors in spreadsheets.

	•		Hiring additional experienced accounting staff to allow for improved segregation of duties and a more thorough review, by senior financial officers, of the financial statements and underlying supporting documentation.

	•		Providing additional training to our accounting staff and acquiring other accounting resources to improve our ability to report our financial statements in accordance with GAAP.

	•		Formally documenting our accounting policies and procedures.

PART IV

ITEM 15. Exhibits and Financial Statement Schedules.


		(a) The following documents are filed as part of this report:

1.		Index to Consolidated Financial Statements, Reports of Independent Registered Public Accounting Firm, Consolidated Balance Sheets as of December 31, 2005 and 2004, Consolidated Statements of Operations and Comprehensive Income for the three years in the period ended December 31, 2005, Consolidated Statements of Changes in Stockholders’ Equity for each of the three years in the period ended December 31, 2005, Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 2005, and Notes to Consolidated Financial Statements.

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

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

SIGNATURES

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


TOREADOR RESOURCES CORPORATION

January 14, 2007		/s/ G. Thomas Graves III

		G. Thomas Graves III, President and Chief Executive Officer

January 14, 2007		/s/ Douglas W. Weir

		Douglas W. Weir, Senior Vice President and Chief Financial Officer

January 14, 2007		/s/ Charles J. Campise

		Charles J. Campise, Vice President — Accounting and Chief Accounting Officer

INDEX TO EXHIBITS


EXHIBIT
NUMBER		DESCRIPTION
2.1	-	Agreement and Plan of Merger, dated as of October 3, 2001, between Toreador Resources Corporation and Madison Oil Company (previously filed as Exhibit 2.1 to Toreador Resources Corporation Registration Statement on Form S-4, No. 333-72314, filed on October 26, 2001, and incorporated herein by reference).

2.2	-	Agreement for Purchase and Sale, dated December 17, 2003, by and among Toreador Resources Corporation and Tormin, Inc., as Sellers, and Black Stone Acquisitions Partners I, L.P., as Buyer (previously filed as Exhibit 2.1 to Toreador Resources Corporation Current Report on Form 8-K filed on January 15, 2004, File No. 0-2517, and incorporated herein by reference).

2.3	-	Quota Purchase Agreement between Pogo Overseas Production BV, as Seller, and Toreador Resources Corporation, as Purchaser, dated as of June 7, 2005 (previously filed as Exhibit 2.1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on June 13, 2005, File No. 0-2517, and incorporated herein by reference).

3.1	-	Restated Certificate of Incorporation, of Toreador Resources Corporation (previously filed as Exhibit 3.1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on March 29, 2005, File No. 0-2517, and incorporated herein by reference).

3.2	-	Third Amended and Restated Bylaws of Toreador Resources Corporation (previously filed as Exhibit 3.2 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on March 29, 2005, File No. 0-2517, and incorporated herein by reference).

4.1	-	Settlement Agreement, dated June 25, 1998, among the Gralee Persons, the Dane Falb Persons and Toreador Royalty Corporation (previously filed as Exhibit 4.1 to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2004, File No. 0-2517, and incorporated herein by reference).

4.2	-	Warrant, dated July 22, 2004, issued by Toreador Resources Corporation to Nigel Lovett (previously filed as Exhibit 4.14 to Toreador Resources Corporation Registration Statement on Form S-3 filed with the Securities and Exchange Commission on August 20, 2004, File No. 0-2517, and incorporated herein by reference).

4.3	-	Warrant No. 30, issued by Toreador Resources Corporation to Rich Brand amending and replacing Warrant dated July 22, 2004 (previously filed as Exhibit 4.3 to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2005, File No. 0-2517, and incorporated herein by reference).

4.4	-	Registration Rights Agreement, effective February 22, 2005, between Toreador Resources Corporation and James R. Anderson (previously filed as Exhibit 4.1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on February 24, 2005, File No. 0-2517, and incorporated herein by reference).

4.5	-	Registration Rights Agreement, effective February 22, 2005, between Toreador Resources Corporation and Karen Anderson (previously filed as Exhibit 4.2 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on February 24, 2005, File No. 0-2517, and incorporated herein by reference).

4.6	-	Registration Rights Agreement, effective February 22, 2005, between Toreador Resources Corporation and Roger A. Anderson (previously filed as Exhibit 4.3 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on February 24, 2005, File No. 0-2517, and incorporated herein by reference).

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


4.8	-	Registration Rights Agreement, dated July 26, 2003, between Toreador Resources Corporation and James R. Anderson (previously filed as Exhibit 4.7 to Toreador Resources Corporation Quarterly Report on Form 10-Q for the quarter ended June 30, 2003, File No. 0-2517, and incorporated herein by reference).

4.9	-	Registration Rights Agreement, dated August 13, 2003, between Toreador Resources Corporation and Karen Anderson (previously filed as Exhibit 4.8 to Toreador Resources Corporation Quarterly Report on Form 10-Q for the quarter ended September 30, 2003, File No. 0-2517, and incorporated herein by reference).

4.10	-	Registration Rights Agreement, dated October 20, 2003, between Toreador Resources Corporation and William I. Lee and Wilco Properties, Inc. (previously filed as Exhibit 4.9 to Toreador Resources Corporation Quarterly Report on Form 10-Q for the quarter ended September 30, 2003, File No. 0-2517, and incorporated herein by reference).

4.11	-	Registration Rights Agreement, dated December 15, 2003, between Toreador Resources Corporation and James R. Anderson (previously filed as Exhibit 4.9 to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2003, File No. 0-2517, and incorporated herein by reference).

4.12	-	Registration Rights Agreement, dated December 15, 2003, between Toreador Resources Corporation and Roger A. Anderson (previously filed as Exhibit 4.10 to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2003, File No. 0-2517, and incorporated herein by reference).

4.13	-	Registration Rights Agreement, dated December 22, 2003, between Toreador Resources Corporation and Wilco Properties Inc (previously filed as Exhibit 4.11 to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2003, File No. 0-2517, and incorporated herein by reference).

4.14	-	Registration Rights Agreement, dated July 20, 2004, between Toreador Resources Corporation and the Investors party thereto (previously filed as Exhibit 4.1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on July 23, 2004, File No. 0-2517, and incorporated herein by reference).

4.15	-	Registration Rights Agreement, dated July 22, 2004, between Toreador Resources Corporation and the Investors party thereto (previously filed as Exhibit 4.9 to Toreador Resources Corporation Registration Statement on Form S-3 filed with the Securities and Exchange Commission on August 20, 2004, File No.
		0-2517, and incorporated herein by reference).

4.16	-	Warrant, dated July 22, 2004, issued by Toreador Resources Corporation to RP&C International (Securities), Inc. (previously filed as Exhibit 4.12 to Toreador Resources Corporation Registration Statement on Form S-3 filed with the Securities and Exchange Commission on August 20, 2004, File No. 0-2517, and incorporated herein by reference).

4.17	-	Registration Rights Agreement dated September 27, 2005 by and between Toreador Resources Corporation and UBS Securities LLC and the other initial purchasers named in the purchase agreement (previously filed as Exhibit 4.18 to the Registration Statement on Form S-3 (333-129628) filed with the Securities and Exchange Commission on November 10, 2005, File No. 0-2517, and incorporated herein by reference).

4.18	-	Indenture dated as of September 27, 2005 by and between Toreador Resources Corporation and The Bank of New York Trust Company, N.A. (previously filed as Exhibit 4.19 to the Registration Statement on Form S-3 (333-129628) filed with the Securities and Exchange Commission on November 10, 2005, File No. 0-2517, and incorporated herein by reference).

10.1+	-	Employment letter agreement between Madison Oil Company and Michael J. FitzGerald dated September 10, 2001 (previously filed as Exhibit 10.1 to Toreador Resources Corporation Quarterly Report on Form 10-Q for the quarter ended March 31, 2002, File No. 0-2517, and incorporated herein by reference).


10.2+	-	Toreador Royalty Corporation 1990 Stock Option Plan (previously filed as Exhibit 10.2 to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2004, File No. 0-2517, and incorporated herein by reference).

10.3+	-	Amendment to Toreador Royalty Corporation 1990 Stock Option Plan, effective as of May 15, 1997 (previously filed as Exhibit 10.3 to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2004, File No. 0-2517, and incorporated herein by reference).

10.4+	-	Toreador Royalty Corporation Amended and Restated 1990 Stock Option Plan, effective as of September 24, 1998 (previously filed as Exhibit 10.4 to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2004, File No. 0-2517, and incorporated herein by reference).

10.5+	-	Amendment Number One to Toreador Resources Corporation Amended and Restated 1990 Stock Option Plan (previously filed as Exhibit 10.1 to Toreador Resources Corporation Quarterly Report on Form 10-Q for the quarter ended June 30, 2002, File No. 0-2517, and incorporated herein by reference).

10.6+	-	Amendment Number Two to Toreador Resources Corporation Amended and Restated 1990 Stock Option Plan (previously filed as Exhibit 10.4 to Toreador Resources Corporation Quarterly Report on Form 10-Q for the quarter ended June 30, 2002, File No. 0-2517, and incorporated herein by reference).

10.7+	-	Toreador Royalty Corporation 1994 Non-Employee Director Stock Option Plan, as amended (previously filed as Exhibit 10.7 to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2004, File No. 0-2517, and incorporated herein by reference).

10.8+	-	Toreador Resources Corporation Amended and Restated 1994 Non-employee Director Stock Option Plan (previously filed as Exhibit 10.2 to Toreador Resources Corporation Quarterly Report on Form 10-Q for the quarter ended June 30, 2002, File No. 0-2517, and incorporated herein by reference).

10.9+	-	Toreador Resources Corporation 2002 Stock Option Plan (previously filed as Exhibit 10.16 to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2001, File No. 0-2517, and incorporated herein by reference).

10.10+	-	Amendment Number One to the Toreador Resources Corporation 2002 Stock Option Plan (previously filed as Exhibit 10.5 to Toreador Resources Corporation Quarterly Report on Form 10-Q for the quarter ended June 30, 2002, File No. 0-2517, and incorporated herein by reference).

10.11+	-	Toreador Resources Corporation 2005 Long-Term Incentive Plan (previously filed as Exhibit 10.1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on May 23, 2005, File No. 0-2517, and incorporated here by reference).

10.12+	-	Form of Employee Restricted Stock Award (previously filed as Exhibit 10.2 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on May 23, 2005, File No. 0-2517, and incorporated here by reference).

10.13+	-	Form of Outside Director Restricted Stock Award (previously filed as Exhibit 10.3 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on May 23, 2005, File No. 0-2517, and incorporated here by reference).

10.14+	-	Form of Indemnification Agreement, dated as of April 25, 1995, between Toreador Royalty Corporation and each of the members of our Board of Directors (previously filed as Exhibit 10.11 to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2004, File No. 0-2517, and incorporated herein by reference).

10.15	-	Contract for the Supply of Crude Oil from the Parisian Basin, effective January 1, 1997, between Elf Antwar France and Midland Madison Petroleum Company (n/k/a Madison Energy France) (previously filed as Exhibit 10.14 to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2001, File No. 0-2517, and incorporated herein by reference).


10.16	-	Second Amended and Restated Convertible Debenture, dated March 31, 2004, between Madison Oil Company and PHD Partners L.P. (previously filed as Exhibit 10.2 to Toreador Resources Corporation Quarterly Report on Form 10-Q for the year ended March 31, 2004, File No. 0-2517, and incorporated herein by reference).

10.17	-	Subordinated Revolving Credit Agreement, dated as of October 3, 2001, between Madison Oil Company and Toreador Resources Corporation (previously filed as Exhibit 2.2 to Toreador Resources Corporation Registration Statement on Form S-4, No. 333-72314, filed on October 26, 2001, and incorporated herein by reference).

10.18	-	Subordinated Revolving Credit Note, dated as of October 3, 2001, between Toreador Resources Corporation and Madison Oil Company (previously filed as Exhibit 2.3 to Toreador Resources Corporation Registration Statement on Form S-4, No. 333-72314, filed on October 26, 2001, and incorporated herein by reference).

10.19	-	Securities Purchase Agreement, effective November 1, 2002, among Toreador Resources Corporation and persons party thereto (previously filed as Exhibit 10.24 to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2002, File No. 0-2517, and incorporated herein by reference).

10.20	-	Securities Purchase Agreement, dated October 20, 2003, between Toreador Resources Corporation and William I. Lee and Wilco Properties, Inc. (previously filed as Exhibit 10.5 to Toreador Resources Corporation Quarterly Report on Form 10-Q for the quarter ended September 30, 2003, File No. 0-2517, and incorporated herein by reference).

10.21	-	Securities Purchase Agreement, dated December 15, 2003, between Toreador Resources Corporation and James R. Anderson (previously filed as Exhibit 10.20 to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2003, File No. 0-2517, and incorporated herein by reference).

10.22	-	Securities Purchase Agreement, dated December 15, 2003, between Toreador Resources Corporation and Roger A. Anderson (previously filed as Exhibit 10.21 to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2003, File No. 0-2517, and incorporated herein by reference).

10.23	-	Securities Purchase Agreement, dated December 22, 2003, between Toreador Resources Corporation and Wilco Properties, Inc. (previously filed as Exhibit 10.22 to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2003, File No. 0-2517, and incorporated herein by reference).

10.24	-	Letter Agreement, dated August 11, 2004, by and between Toreador Resources Corporation and David M. Brewer (previously filed as Exhibit 10.6 to Toreador Resources Corporation Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, File No. 0-2517, and incorporated herein by reference).

10.25	-	Reserve Base Revolving Facility Agreement, dated December 23, 2004, by and among Toreador Resources Corporation, Madison Energy France, Madison Oil France, Madison Oil Company Europe and Natexis Banques Populaires and the other Lenders party thereto (previously filed as Exhibit 10.1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on December 29, 2004, File No. 0-2517, and incorporated herein by reference).

10.26	-	Credit Agreement, dated December 30, 2004, by and among Toreador Resources Corporation, Toreador Acquisition Corporation, Toreador Exploration and Production, Inc. and Texas Capital Bank, N.A. (previously filed as Exhibit 10.1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on January 3, 2005, File No. 0-2517, and incorporated herein by reference).

10.27	-	Guaranty, dated December 30, 2004, executed by Toreador Resources Corporation in favor of Texas Capital Bank, N.A. (previously filed as Exhibit 10.2 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on January 3, 2005, File No. 0-2517, and incorporated herein by reference).


10.28	-	Securities Purchase Agreement, dated July 26, 2003, between Toreador Resources Corporation and James R. Anderson (previously filed as Exhibit 10.8 to Toreador Resources Corporation Quarterly Report on Form 10-Q for the quarter ended June 30, 2003, File No. 0-2517, and incorporated herein by reference).

10.29	-	Securities Purchase Agreement, dated August 13, 2003, between Toreador Resources Corporation and Karen Anderson (previously filed as Exhibit 10.4 to Toreador Resources Corporation Quarterly Report on Form 10-Q for the quarter ended September 30, 2003, File No. 0-2517, and incorporated herein by reference).

10.30	-	7.85% Convertible Subordinated Note due June 30, 2009, dated July 22, 2004, executed by Toreador Resources Corporation (previously filed as Exhibit 10.2 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on July 23, 2004, File No. 0-2517, and incorporated herein by reference).

10.31	-	Purchase Agreement, dated July 20, 2004, by and among Toreador Resources Corporation and the Investors party thereto (previously filed as Exhibit 10.1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on July 23, 2004, File No. 0-2517, and incorporated herein by reference).

10.32	-	Summary Sheet: Executive Officer Annual Base Salaries (previously filed as Exhibit 10.1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on February 1, 2006, File No. 0-2517, and incorporated herein by reference).

10.33	-	Summary Sheet: Short-Term Incentive Compensation Plan (previously filed as Exhibit 10.2 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on February 1, 2006, File No. 0-2517, and incorporated herein by reference).

10.34	-	Summary Sheet: Director Compensation (previously filed as Exhibit 10.3 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on March 29, 2005, File No. 0-2517, and incorporated herein by reference).

10.35	-	Warrant to Purchase Common Stock of Toreador Resources Corporation dated July 11, 2005, by and between Toreador Resources Corporation and Natexis Banques Popularis (previously filed as Exhibit 10.1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on July 13, 2005, File No. 0-2517, and incorporated herein by reference).

10.36	-	Form of Subscription Agreement for September 16, 2005 Private Placement (previously filed as Exhibit 10.1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on September 22, 2005, File No. 0-2517, and incorporated herein by reference).

10.37	-	Purchase Agreement dated November 22, 2005 by and among Toreador Resources Corporation, UBS Securities LLC and the other initial Purchasers named in Exhibit A attached thereto (previously filed as Exhibit 10.2 to the Registration Statement on Form S-3 (333-129628) filed with the Securities and Exchange Commission on November 10, 2005, File No. 0-2517, and incorporated herein by reference).

12.1	-	Computation of Ratio of Earnings to Fixed Charges (previously filed as Exhibit 12.1 to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2005, File No. 0-2517, and incorporated herein by reference).

21.1	-	Subsidiaries of Toreador Resources Corporation (previously filed as Exhibit 21.1 to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2005, File No. 0-2517, and incorporated herein by reference).

23.1*	-	Consent of Grant Thornton LLP

23.2*	-	Consent of LaRoche Petroleum Consultants, Ltd.

24.1	-	Power of Attorney (previously filed as signatures to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2005, File No. 0-2517, and incorporated herein by reference).


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

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

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

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


*		Filed herewith

+		Management contract or compensatory plan

Item 8. Financial Statements

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


	Page

Report of Independent Registered Public Accounting Firm		F-2

Financial Statements (1)

Consolidated Balance Sheets as of December 31, 2005 and 2004		F-3

Consolidated Statements of Operations and Comprehensive Income for each of the three years in the period ended December 31, 2005		F-4

Consolidated Statements of Changes in Stockholders’ Equity for each of the three years in the period ended December 31, 2005		F-5

Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 2005		F-6

Notes to Consolidated Financial Statements		F-7


(1)		As described in Note 3 to the financial statements, the Company restated its financial statements for the years ended December 31, 2003, 2004 and 2005.

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

Toreador Resources Corporation

We have audited the accompanying consolidated balance sheets of Toreador Resources Corporation (a Delaware Corporation) and subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements of operations and comprehensive income, changes in stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2005. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Toreador Resources Corporation and subsidiaries as of December 31, 2005 and 2004 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 3, management of the Company determined that adjustments were required to previously issued financial statements. As a result, the Company has restated its consolidated financial statements as of December 31, 2005 and 2004 and for each of the three years in the period ended December 31, 2005.

/s/ Grant Thornton LLP

Dallas, Texas

January 14, 2007

F-2

TOREADOR RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS
(in thousands, except share and per share data)


	December 31,
	2005			2004
	(restated)			(restated)
ASSETS
Current assets:
Cash and cash equivalents	$	53,113		$	4,977
Short-term investments		40,000			—
Accounts and notes receivable		8,162			3,850
Income taxes receivable		4,453			—
Other		6,537			1,187

Total current assets		112,265			10,014


Oil and natural gas properties, net, using successful efforts method of accounting		138,158			82,394
Investments in unconsolidated entities		2,251			1,466
Goodwill		4,195			5,979
Other assets		4,945			1,325

	$	261,814		$	101,178

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	19,248		$	11,112
Current portion of long-term debt		—			37
Convertible debenture — related party		810			—
Income taxes payable		908			1,593

Total current liabilities		20,966			12,742


Long-term accrued liabilities		1,410			1,136
Long-term debt		5,000			—
Long-term asset retirement obligations		3,630			3,291
Deferred income tax liabilities		12,199			13,679
Convertible subordinated notes		86,250			7,500
Convertible debenture — related party		—			1,485

Total liabilities		129,455			39,833

Commitments and contingencies
Stockholders’ equity:
Preferred stock, Series A-1, $1.00 par value, 4,000,000 shares authorized; liquidation preference of $1,800; 72,000 and 154,000 shares issued		72			154
Common stock, $0.15625 par value, 30,000,000 shares authorized;16,142,824 and 11,724,146 shares issued		2,522			1,832
Additional paid-in capital		108,001			37,524
Retained earnings		29,564			19,653
Accumulated other comprehensive income (loss)		(3,364	)		4,716
Deferred compensation		(1,902	)		—
Treasury stock at cost, 721,027 shares		(2,534	)		(2,534	)

Total stockholders’ equity		132,359			61,345

	$	261,814		$	101,178

See accompanying notes to the consolidated financial statements.

F-3

TOREADOR RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(in thousands, except per share data)


	Year ended December 31,
	2005			2004			2003
	(restated)			(restated)			(restated)
Revenue:
Oil and natural gas sales	$	31,117		$	22,336		$	16,998
Loss on commodity derivatives		—			(1,322	)		(776	)
Lease bonuses and rentals		—			14			18

Total revenue		31,117			21,028			16,240


Operating costs and expenses:
Lease operating expense		8,198			7,399			6,220
Exploration expense		2,940			4,530			2,352
Dry hole and abandonment		1,738			—			—
Depreciation, depletion and amortization		5,245			4,110			3,476
Impairment of oil and natural gas properties		110			—			171
General and administrative		6,680			7,463			3,757

Total operating costs and expenses		24,911			23,502			15,976


Operating income (loss)		6,206			(2,474	)		264

Other income (expense):
Equity in earnings (loss) of unconsolidated investments		222			(18	)		22
Gain (loss) on sale of properties and other assets		12			(159	)		120
Foreign currency exchange gain		2,386			127			3,808
Interest and other income		1,407			515			294
Interest expense		—			(1,414	)		(1,651	)

Total other income (expense)		4,027			(949	)		2,593


Income (loss) from continuing operations before income taxes		10,233			(3,423	)		2,857
Income tax benefit		315			1,153			603


Income (loss) from continuing operations		10,548			(2,270	)		3,460
Income from discontinued operations, net of tax of $11,007 in 2004 and $403 in 2003		47			17,690			1,182

Net income		10,595			15,420			4,642
Preferred dividends		(684	)		(714	)		(500	)


Income available to common shares	$	9,911		$	14,706		$	4,142


Basic income available to common shares per share from:
Continuing operations	$	0.69		$	(0.31	)	$	0.32
Discontinued operations		—			1.85			0.12

	$	0.69		$	1.54		$	0.44


Diluted income available to common shares per share from:
Continuing operations	$	0.65		$	(0.31	)	$	0.32
Discontinued operations		—			1.85			0.12

	$	0.65		$	1.54		$	0.44


Weighted average shares outstanding:
Basic		14,213			9,571			9,338
Diluted		15,140			9,571			9,347

Statement of Comprehensive Income
Net income	$	10,595		$	15,420		$	4,642
Foreign currency translation adjustments and other		(8,080	)		2,885			2,360


Comprehensive income	$	2,515		$	18,305		$	7,002

See accompanying notes to the consolidated financial statements.

F-4

TOREADOR RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
(in thousands)
(Restated)


																Accumulated
	Preferred			Preferred			Common		Common		Additional					Other			Treasury						Total
	Stock			Stock			Stock		Stock		Paid-in		Retained			Comprehensive			Stock			Deferred			Stockholders’
	(Shares)			($)			(Shares)		($)		Capital		Earnings			Income (loss)			($)			Compensation			Equity
Balance at December 31, 2002 as reported		197		$	197			10,059	$	1,572	$	30,510	$	(1,864	)	$	2,140		$	(2,534	)		—		$	30,021
Adjustment due to foreign exchange		—			—			—		—		—		2,669			(2,669	)		—			—			—


Balance as restated at December 31, 2002		197			197			10,059		1,572		30,510		805			(529	)		(2,534	)		—			30,021
Cash payment of preferred dividends		—			—			—		—		—		(500	)		—			—			—			(500	)
Issuance of preferred stock		123			123			—		—		2,952					—			—			—			3,075
Net income		—			—			—		—		—		4,642			—			—			—			4,642
Change in fair value of available-for-sale securities		—			—			—		—		—		—			8			—			—			8
Foreign currency translation adjustment		—			—			—		—		—		—			2,322			—			—			2,322
Losses reclassified to net income		—			—			—		—		—		—			30			—			—			30


Balance at December 31, 2003, as restated		320			320			10,059		1,572		33,462		4,947			1,831			(2,534	)		—			39,598
Cash payment of preferred dividends		—			—			—		—		—		(714	)		—			—			—			(714	)
Issuance of stock options for professional services		—			—			—		—		58		—			—			—			—			58
Conversion of preferred stock		(166	)		(166	)		1,037		162		4		—			—			—			—			—
Conversion of convertible debenture		—			—			100		16		659		—			—			—			—			675
Exercise of stock options		—			—			528		82		2,228		—			—			—			—			2,310
Tax benefit from exercise of stock options		—			—			—		—		1,113		—			—			—			—			1,113
Net income		—			—			—		—		—		15,420			—			—			—			15,420
Foreign currency translation adjustment		—			—			—		—		—		—			2,885			—			—			2,885


Balance at December 31, 2004, as restated		154			154			11,724		1,832		37,524		19,653			4,716			(2,534	)		—			61,345
Cash payment of preferred dividends		—			—			—		—		—		(186	)		—			—			—			(186	)
Conversion of preferred stock		(82	)		(82	)		512		80		2		—			—			—			—			—
Conversion of notes payable		—			—			915		143		6,270		—			—			—			—			6,413
Conversion of convertible debenture		—			—			100		16		659		—			—			—			—			675
Issuance of common stock, net of issuance costs		—			—			2,244		350		55,568		—			—			—			—			55,918
Exercise of stock options		—			—			493		77		2,475		—			—			—			—			2,552
Issuance of warrants		—			—			—		—		60		—			—			—			—			60
Tax benefit of stock option exercises		—			—			—		—		2,557		—			—			—			—			2,557
Exercise of warrants		—			—			20		3		107		—			—			—			—			110
Common shares issued in payment of preferred dividends		—			—			20		3		495		(498	)		—			—			—			—
Issuance of restricted stock		—			—			115		18		2,284		—			—			—			(2,302	)		—
Amortization of deferred stock compensation		—			—			—		—		—		—			—			—			400			400
Net income		—			—			—		—		—		10,595			—			—			—			10,595
Foreign currency translation adjustment		—			—			—		—		—		—			(8,080	)		—			—			(8,080	)


Balance at December 31, 2005, as restated		72		$	72			16,143	$	2,522	$	108,001	$	29,564		$	(3,364	)	$	(2,534	)	$	(1,902	)	$	132,359

See accompanying notes to the consolidated financial statements.

F-5

TOREADOR RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)


	Year Ended December 31
	2005			2004			2003
	(Restated)			(Restated)			(Restated)
Cash flows from operating activities:
Net Income	$	10,595		$	15,420		$	4,642
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		5,245			4,110			3,476
Amortization of deferred debt issuance cost		—			383			—
Impairment of oil and natural gas properties		110			—			171
Dry hole and abandonment costs		1,738			—			—
Deferred income taxes		93			2,556			641
Unrealized (gain) losses on commodity derivatives		—			(1,159	)		123
Gain on sale of properties and equipment		(12	)		(28,552	)		120
Equity in (earnings) loss of unconsolidated investments		(222	)		18			(22	)
Stock-based compensation		400			58			—
Gain/(loss) on sale of marketable securities		—			20			41
Change in operating assets and liabilities, net of acquisition
(Increase) decrease in accounts and notes receivables		(4,304	)		(520	)		525
(Increase) decrease in income taxes receivable		(4,453	)		—			512
(Increase) decrease in other assets		(9,740	)		(931	)		(77)
Increase (decrease) in accounts payable and accrued liabilities		7,934			4,114			389
Increase (decrease) in income taxes payable		(685	)		780			813

Net cash provided by (used in) operating activities		6,699			(3,703	)		11,354

Cash flows from investing activities:
Expenditures for property and equipment		(57,000	)		(15,385	)		(4,442	)
Net cash for acquisitions		(8,751	)		—			—
Proceeds from the sale of properties and equipment, net of transaction costs		29			42,125			424
Distributions from unconsolidated entities		191			255			—
Purchase of short-term investments		(40,000	)		—			—
Proceeds from sale of marketable securities		—			—			46
Investments in unconsolidated subsidiaries		(754	)		(1,210	)		—

Net cash provided by (used in) investing activities		(106,285	)		25,785			(3,972	)

Cash flows from financing activities:
Net borrowings (repayments) under revolving credit arrangements		4,963			(28,779	)		(4,444	)
Exercise of stock options		2,552			2,310			—
Exercise of warrants		170			—			—
Proceeds from issuance of common stock, net of issuance cost of $3,940		55,918			—			—
Issuance of preferred stock		—						3,075
Proceeds from issuance of notes payable		86,250			7,500			—
Payment of preferred dividends		(186	)		(714	)		(500	)

Net cash provided by (used in) financing activities		149,667			(19,683	)		(1,869	)

Net increase in cash and cash equivalents		50,081			2,399			5,513
Effects of foreign currency translation on cash and cash equivalents		(1,945	)		(241	)		(3,670	)
Cash and cash equivalents, beginning of year		4,977			2,819			976


Cash and cash equivalents, end of year	$	53,113		$	4,977		$	2,819

Supplemental disclosures:
Cash paid during the period for interest, net of interest capitalization	$	—		$	1,304		$	1,255
Cash paid during the period for income taxes	$	2,690		$	5,250		$	629
Non-cash investing and financing activities
Conversion of preferred stock to common stock		82			166			—
Conversion of notes payable to common stock		6,413			—			—
Conversion of convertible debentures to common stock		675			675			—
Common shares issued for preferred dividends		498			—			—

See accompanying notes to the consolidated financial statements.

F-6

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(RESTATED)

NOTE 1 — DESCRIPTION OF BUSINESS

Toreador Resources Corporation (“Toreador”) is an independent energy company engaged in foreign and domestic oil and natural gas exploration, development, production, leasing and acquisition activities. The accompanying consolidated financial statements are presented in U.S. dollars and in accordance with accounting principles generally accepted in the United States.

BASIS OF PRESENTATION

Toreador consolidates all of its majority-owned subsidiaries (collectively, “we,” “us,” “our,” or the “Company”). All intercompany accounts and transactions are eliminated in consolidation. We account for our investments in entities in which we hold less than a majority interest under the equity method.

In January 2004, we sold our U.S. mineral and royalty assets to Black Stone Acquisitions Partners I, L.P. (“Royalty Sale”). We retained all of our working-interest properties. From the approximate $45.0 million cash consideration ($41.9 million net of transaction costs) that we received, we discharged our outstanding credit facilities. The financial results for those assets sold are classified as discontinued operations in the accompanying financial statements. See further discussion in Note 16 to the consolidated financial statements.

NOTE 2 — SIGNIFICANT ACCOUNTING POLICIES

USE OF ESTIMATES

The preparation of the consolidated financial statements requires management of the Company to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.

The Company’s estimates of crude oil and natural gas reserves are the most significant estimates used. All of the reserve data in the Form 10-K for the year ended December 31, 2005 and this Form 10-K/A are estimates. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may be different from the quantities of crude oil and natural gas that are ultimately recovered.

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

CASH AND CASH EQUIVALENTS AND SHORT-TERM INVESTMENTS

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

F-7

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2005 we had $40 million in time deposits bearing interest at 2.87% and maturing on April 7, 2006 that are included in short-term investments. Included in the cash balance at December 31, 2005 is $306,000 of restricted cash in France.

As of December 31, 2005 and 2004 we had $6.5 million and $4.4 million, respectively, on deposit in foreign banks.

CONCENTRATION OF CREDIT RISK AND ACCOUNTS RECEIVABLE

Financial instruments that potentially subject us to a concentration of credit risk consist principally of cash, accounts receivable, and our hedging and derivative financial instruments. We place our cash with high credit quality financial institutions. We sell oil and natural gas to various customers. Historically, we have not experienced any losses related to accounts receivable, and accordingly, we do not believe an allowance for doubtful accounts is warranted either at December 31, 2005 or 2004. Substantially all of our accounts receivable are due from purchasers of oil and natural gas. We place our hedging and derivative financial instruments with financial institutions and other firms that we believe have high credit ratings. For a discussion of the credit risks associated with our hedging activities, please see “Derivative Financial Instruments” below.

FINANCIAL INSTRUMENTS

The carrying amounts of financial instruments including cash and cash equivalents, short-term investments, accounts receivable, marketable securities, accounts payable and accrued liabilities approximate fair value, at December 31, 2005 and 2004, due to the short-term nature or maturity of the instruments.

Long-term debt approximated fair value based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for debt of the same maturities.

On December 31, 2005 the convertible subordinate notes which had a book value of $86.25 million, were trading at $84.50, which would equal a fair market value of approximately $72.9 million. On December 31, 2004 the convertible subordinated notes which had a net book value of $7.5 million and were convertible into 914,634 shares and had a fair value of $20 million based on the market price of our common stock.

DERIVATIVE FINANCIAL INSTRUMENTS

We use various swap and option contracts to (i) reduce the effect of the volatility of price changes on the commodities we produce and sell; and (ii) support our annual capital budgeting and expenditure plans. In order to accomplish this objective, we periodically enter into oil and natural gas swap and option agreements that fix the price of oil and natural gas sales within ranges determined acceptable at the time we execute the contracts. We may also, from time to time, enter into hedges of foreign currency. Losses from these financial instruments totaled $63,000 in 2004. We did not enter into any commodity or foreign currency hedges in 2005.

We are exposed to credit losses in the event of nonperformance by the counterparties to our financial instruments. We anticipate, however, that such counterparties will be able to fully satisfy their obligations under the contracts. We do not obtain collateral or other security to support financial instruments subject to credit risk but we monitor the credit standing of the counterparties. At December 31, 2005 and 2004, we had no accounts receivable from our counterparties.

We have elected not to designate the derivative financial instruments to which we are a party as hedges, and accordingly, we record such contracts at fair value and recognize changes in such fair value in current earnings as they occur.

INVENTORIES

At December 31, 2005 and 2004, other current assets included $951,000, and $530,000 of inventory, respectively. Those amounts consist of tubular goods and crude oil held in storage tanks. Inventories are stated at the lower of actual cost or market based on the average cost method.

F-8

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

OIL AND NATURAL GAS PROPERTIES

We follow the successful efforts method of accounting for oil and natural gas exploration and development expenditures. Under this method, costs of successful exploratory wells and all development wells are capitalized. Costs to drill exploratory wells that do not find proved reserves are expensed. In the absence of a determination as to whether the reserves that have been found can be classified as proved, we carry the costs of drilling such exploratory wells as an asset for no more than one year following completion of drilling. If, after that year has passed, a determination that proved reserves have been found cannot be made, we will assume that the well is impaired, and charge the cost to expense. Significant costs associated with the acquisition of oil and natural gas properties are capitalized. Upon sale or abandonment of units of property or the disposition of miscellaneous equipment, the cost is removed from the asset account, net of the accumulated depreciation or depletion, and the gain or loss is credited to or charged against operations.

Maintenance and repairs are charged to expense; betterments of property are capitalized and depreciated as described below.

We capitalize interest on major projects that require an extended period of time to complete. Interest capitalized in 2005, 2004 and 2003 was $1,434,000, $432,000, and $286,000, respectively.

DEPRECIATION, DEPLETION AND AMORTIZATION

We provide depreciation, depletion and amortization of our investment in producing oil and natural gas properties on the units-of-production method, based upon independent reserve engineers’ estimates of recoverable oil and natural gas reserves from the property. Depreciation expense for fixed assets is generally calculated on a straight-line basis based upon estimated useful lives of three to seven years.

IMPAIRMENT OF ASSETS

We evaluate producing property costs for impairment and reduce such costs to fair value if the sum of expected undiscounted future cash flows is less than net book value pursuant to Statement of Financial Accounting Standard No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“Statement 144”). We assess impairment of non-producing leasehold costs and undeveloped mineral and royalty interests periodically on a property-by-property basis. We charge any impairment in value to expense in the period incurred. We incurred impairment losses on our United States oil and natural gas producing properties of $110,000 in 2005, zero in 2004, and $171,000 in 2003.

F-9

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ASSET RETIREMENT OBLIGATIONS

We account for our asset retirement obligations in accordance with Statement No. 143, “Accounting for Asset Retirement Obligations” (“Statement 143”), which requires us to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, we either settle the obligation for its recorded amount or incur a gain or loss upon settlement.

The following table summarizes the changes in our asset retirement liability during the years ended December 31, 2005 and 2004:


	2005			2004
	Restated
	(in thousands)
Asset retirement obligation January 1	$	3,291		$	2,896
Asset retirement accretion expense		204			156
Foreign currency exchange gain (loss)		(407	)		316
Property additions		542			63
Property dispositions		—			(140	)

Asset retirement obligation at December 31	$	3,630		$	3,291

GOODWILL

We account for goodwill in accordance with Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets” (“Statement 142”). Under Statement 142, goodwill and indefinite-lived intangible assets are not amortized but are reviewed annually (or more frequently if impairment indicators arise) for impairment. Separable intangible assets that are not deemed to have an indefinite life are amortized over their useful lives.

We review annually the value of goodwill recorded or more frequently if impairment indicators arise. We recognized no goodwill impairment during 2005 or 2004. Goodwill was reduced by $1.5 million and $1.6 million in 2004 and 2005, respectively, for a corresponding reduction in deferred tax liabilities which resulted from the recognition of prior Madison Oil Company net operating losses that were reserved at the date of acquisition. Goodwill was also adjusted for $211,000 in 2005 for the foreign currency translation loss adjustment. The balance of goodwill at December 31, 2005 is approximately $4.2 million.

REVENUE RECOGNITION

Our French crude oil production accounts for the majority of our sales. We sell our French crude oil to Elf Antar France S.A. (“ELF”), and recognize the related revenues when the production is delivered to ELF’s refinery, typically via truck. At the time of delivery to the plant, title to the crude oil transfers to ELF. The terms of the contract with ELF state that the price received for oil sold will be the arithmetic mean of all average daily quotations of Dated Brent published in Platt’s Oil Market Wire for the month of production less a specified differential per barrel. The pricing of oil sales is done on the first day of the month following the month of production. In accordance with the terms of the contract, payment is made within six working days of the date of issue of the invoice. The contract with ELF is automatically extended for a period of one year unless either party cancels it in

F-10

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

writing no later than six months prior to the beginning of the next year. We periodically review ELF’s payment timing to ensure that receivables from ELF for crude oil sales are collectible. In 2005, 2004 and 2003 sales to ELF represents approximately 66%, 63% and 55%, respectively, of the Company’s total revenue.

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

STOCK-BASED COMPENSATION

Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation” (“Statement 123”), encourages, but does not require, the adoption of a fair value-based method of accounting for employee stock-based compensation transactions. We have elected to apply the provisions of Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (“Opinion 25”), and related interpretations, in accounting for our employee stock-based compensation plans. Under Opinion 25, compensation cost is measured as the excess, if any, of the quoted market price of our stock at the date of the grant above the amount an employee must pay to acquire the stock.

Had compensation costs for employees under our two stock-based compensation plans been determined based on the fair value at the grant dates under those plans consistent with the method proscribed by Statement 123, our net income (loss) and earnings (loss) available to common shares per share would have been reduced to the pro forma amounts listed below:


	For the Year Ended December 31,
	2005		2004		2003
	(Restated)		(Restated)		(Restated)
	(in thousands, except per share data)
Income available to common shares, as reported	$	9,911	$	14,706	$	4,142
Basic earnings available to common shares per share reported		0.69		1.54		0.44
Diluted earnings available to common shares per share reported		0.65		1.54		0.44
Pro-forma stock-based compensation costs under the fair value method, net of related tax		82		833		23
Pro-forma income available to common shares, as under the fair-value method		9,829		13,873		4,119
Pro-forma basic earnings available to common shares per share under the fair value method	$	0.69	$	1.45	$	0.44
Pro-forma diluted earnings available to common shares per share under the fair value method		0.65		1,45		0.44

F-11

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The fair value of each option granted is estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions:


	For the Year Ended December 31,
	2005			2004			2003
Dividend yield per share		—			—			—
Volatility		70.9	%		44	%		42	%
Risk-free interest rate		4.0	%		4.58	%		2.8	%
Expected lives	5 years			3 years			10 years

FOREIGN CURRENCY TRANSLATION

The functional currency of the countries in which we operate is the U.S. dollar in the United States, Turkey, Romania and Hungary and the Euro in France. Gains and losses resulting from the translations of Euros into U.S. dollars are included in other comprehensive income for the current period. Gains and losses resulting from the translations of the New Turkish Lira in Turkey, the Lei in Romania and the Forint in Hungary are included in income available to common shares for the current period. We periodically review the operations of our entities to ensure the functional currency of each entity is the currency of the primary economic environment in which we operate.

INCOME TAXES

We are subject to income taxes in the United States, France, Turkey, Hungary and Romania. The current provision for taxes on income consists primarily of income taxes based on the tax laws and rates of the countries in which operations were conducted during the periods presented. We compute our provision for deferred income taxes using the liability method. Under the liability method, deferred income tax assets and liabilities are determined based on differences between financial reporting and income tax basis of assets and liabilities and are measured using the enacted tax rates and laws. The measurement of deferred tax assets is adjusted by a valuation allowance, if necessary, to reduce the future tax benefits to the amount, based on available evidence it is more likely than not deferred tax assets will be realized. Goodwill was reduced by $1.5 million and $1.6 million in 2004 and 2005, respectively, for a corresponding reduction in deferred tax liabilities which resulted from the recognition of prior Madison Oil Company net operating losses. At the end of 2003, we made a commitment to be fully reinvested in our international subsidiaries. Accordingly, in 2003, we reversed the deferred tax liability originally booked as a result of the acquisition of Madison Oil Company in the amount of $2.4 million. This amount represented deferred income taxes applicable to undistributed earnings of Madison Oil Company at the time of the acquisition.

NEW ACCOUNTING PRONOUNCEMENTS

In March��2005, the FASB issued FIN No. 47,“Accounting for Conditional Asset Retirement Obligations, an interpretation of SFAS No. 143”(“FIN 47”). FIN 47 requires an entity to recognize a liability for the fair value of a conditional asset retirement obligation in the period in which it is incurred if the liability’s fair value can be reasonably estimated. FIN 47 clarifies that the term “conditional asset retirement obligation” as used in SFAS No. 143, “Accounting for Conditional Asset Retirement Obligations,” refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. FIN 47 is effective no later than the end of fiscal years ending after December 15, 2005. The adoption of FIN 47 did not have a material impact on our financial position, results of operations or cash flows.

On December 16, 2004, FASB issued SFAS No. 153,Exchanges of Nonmonetary Assets, an Amendment of APB Opinion No. 29, Accounting for Nonmonetary Transactions (“ SFAS 153”). This statement amends APB Opinion 29 to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. Under SFAS 153, if a nonmonetary exchange of similar productive assets meets a commercial-substance criterion and fair value is determinable, the transaction must be accounted for at fair value resulting in recognition of any gain or loss. SFAS 153 is effective for nonmonetary transactions in fiscal periods that begin after June 15, 2005. We do not anticipate the implementation of this standard will have a material impact on its financial position, results of operations or cash flows.

F-12

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On February 6, 2006, the FASB issued Statement 155, “Accounting for Certain Hybrid Instruments — an amendment of FASB Statements No. 133 and 140.” The statement amends Statement 133 to permit fair value measurement for certain hybrid financial instruments that contain an embedded derivative, provides additional guidance on the applicability of Statement 133 and 140 to certain financial instruments and subordinated concentrations of credit risk. The new standard is effective for the first fiscal year that begins after September 16, 2006. As of December 31, 2005 the Company has not entered into nor do we expect to enter into any agreements that would be subject to this Statement.

NOTE 3 — RESTATEMENT OF PREVIOUSLY ISSUED FINANCIAL STATEMENTS

On November 16, 2006, Toreador’s management and the chairman of the audit committee determined that Toreador should also restate its consolidated financial statements as of and for the years ended 2003 and 2004. The restatements are due to various errors that were discovered during and in conjunction with the audit of the restatements for the year ended December 31, 2005.

The accompanying consolidated balance sheet as of December 31, 2005 and 2004 and related consolidated statements of operations and comprehensive income, changes in stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2005 have been restated. Beginning retained earnings as of January 1, 2003 was restated to reflect to revise the Company’s foreign currency accounting under financial accounting standards No. 52Foreign Currency Translation. The significant adjustments are as follows:

Capitalization of Interest

We determined that the costs incurred in connection with the development program in offshore Turkey met the definition of a qualifying asset, as defined, and satisfied the three conditions for capitalization outlined Statement of Financial Accounting Standards No. 34, as amended,Capitalization of Interest Cost. Previously, we had not capitalized any interest related to development costs incurred. These adjustments reduce interest expense and increase capitalized oil and gas properties on the consolidated balance sheet. For the years ended December 31, 2005, 2004 and 2003 the pre-tax adjustment was $1.43 million, $432,000, and $286,000 respectively.

Insurance Claim Adjustments

In 2005 two separate, significant property loss incidents occurred in offshore Turkey in the Black Sea, which resulted in the loss of two caissons and three wells. Both of these instances were insured. In December 2005, the Company received notice that the insurance company had reserved $10.6 million, net to the Company, for potential payment of these claims. As of December 31, 2005, the net book value of the wells and caissons was $11.1 million. The Company initially recorded the expected insurance recovery of $10.6 million as a receivable and reduced oil and gas properties and expensed the difference between the book value of the wells and caissons of $569,000 as a loss on involuntary conversions. The Company subsequently concluded that under successful efforts accounting these were development wells and the costs associated with the lost wells and caissons, as well as the costs to re-drill the wells, should be capitalized and no gain or loss recorded. As a result, oil and gas properties were increased $11.1 million, the insurance receivable was decreased $10.6 million and $569,000 was credited to income. The oil and gas properties including the $11.1 million were assessed for possible impairment in accordance with the Company’s impairment policies and no impairment was deemed necessary. Future insurance recoveries from these losses, if any, will be recorded as reductions of oil and gas properties.

Foreign Currency

The Company follows Statement of Financial Accounting Standards No. 52Foreign Currency Translation(SFAS 52) to translate the functional currency financial statements of the foreign subsidiaries to the reporting currency for consolidation purposes. During the process of performing these calculations, the Company determined that they had errors in the formulas used to calculate these adjustments that resulted in conversions being incorrectly computed. In addition, the Company incorrectly recorded certain foreign currency transactions in other comprehensive income that should have been recorded as foreign currency transaction gain and losses. Finally, the Company incorrectly used the Turkish Lira as their functional currency instead of the US dollar under the criteria of SFAS 52.

Depletion, Depreciation and Amortization (DD&A)

The Company follows the successful efforts method to account for oil and gas properties. Under the successful efforts method, both proved property acquisition costs and proved property well development costs are amortized on a unit-of-production basis as the related proved reserves are produced. Proved property acquisition costs are required to be depleted over the total proved reserves, while costs of wells and related equipment and facility are to be depleted over the proved developed reserves. Depletion may be computed separately for each property or alternatively the properties may be aggregated on the basis of common geological features or stratigraphic condition. The Company was not properly segregating acquisition costs and well development costs. In addition, the Company did not properly value the salvage value for the oil and gas properties.

Write-off of deferred loan costs

In 2002, the Company obtained a loan from a bank related to the acquisition of Madison Energy France. In 2003, the Company incurred additional loan fees of Euro 644,000 (approximately $809,000) related to the loan. These costs were capitalized in other assets as deferred loan costs. Subsequently, the loan was paid-off but the deferred loan costs were not properly expensed.

Seismic costs

SFAS No. 19, (as amended)Financial Accounting and Reporting by Oil and Gas Producing Companies requires the costs of geological and geophysical costs to be expensed when incurred. The Company had improperly capitalized certain seismic costs that should have been expensed as incurred.

Unaccrued payroll and other costs

The Company had not properly accrued payroll and other costs.

Asset Retirement Obligations

In 2004, the Company evaluated its Asset Retirement Obligations (ARO) under Statement No. 143 “Accounting for Asset Retirement Obligations” and determined that they had under estimated the required ARO by $1.0 million.

Below are restated financial statements that present the previously reported balance, the restatement adjustments and the restated balance.

F-13

Income Statement Impact of Restatement for the Year Ended December 31, 2005 (In thousands)


	Income Statement Impact of Restatement for the Year Ended December 31, 2005
	As					Insurance			Foreign						Other			Total
	Previously			Capitalization		Claim			Currency						Adjustments/			Restatement			As
	Reported			of Interest		Adjustments			Translations			DD&A			Reclassifications			Adjustments			Restated
Revenue
Oil and natural gas sales	$	30,856		$	—	$	—		$	—		$	—		$	261		$	261		$	31,117
Loss on commodity derivatives		—			—		—			—			—			—			—			—
Lease bonuses and rentals		—			—		—			—			—			—			—			—

Total Revenues		30,856			—		—			—			—			261			261			31,117
Operating costs and expenses
Lease operating expenses		9,111			—		—			(913	)		—			—			(913	)		8,198
Exploration expense		2,830			—		—			—			—			110			110			2,940
Dry hole and abandonment		1,739			—		—			(1	)		—			—			(1	)		1,738
Depreciation, depletion and amortization		4,243			—		—			—			1,002			—			1,002			5,245
Loss on involuntary conversion of assets		569			—		(569	)		—			—			—			(569	)		—
Impairment of oil and natural gas properties		—			—		—			—			—			110			110			110
General and administrative		6,818			—		—			50			—			(188	)		(138	)		6,680

Total Operating costs and expenses		25,310			—		(569	)		(864	)		1,002			32			(399	)		24,911
Operating Income		5,546			—		569			864			(1,002	)		229			660			6,206
Other Income (expense)
Equity earnings (loss) of unconsolidated investments		222			—		—			—			—			—			—			222
Gain (loss) on sale of properties and other assets		12			—		—			—			—			—			—			12
Foreign Currency exchange gain		148			—		—			2,238			—			—			2,238			2,386
Interest and other income		1,706			—		—			—			—			(299	)		(299	)		1,407
Interest expense		(1,632	)		1,434		—			—			—			198			1,632			—

Total other income (expense)		456			1,434		—			2,238			—			(101	)		3,571			4,027
Income from continuing operations before income taxes		6,002			1,434		569			3,102			(1,002	)		128			4,231			10,233
Income Tax Benefit		1,659			—		—			—			—			(1,344	)		(1,344	)		315

Income from Continuing Operations		7,661			1,434		569			3,102			(1,002	)		(1,216	)		2,887			10,548
Income from Discontinued Operations, net of tax		47			—		—			—			—			—			—			47

Net Income		7,708			1,434		569			3,102			(1,002	)		(1,216	)		2,887			10,595
Preferred dividends		(684	)		—		—			—			—			—			—			(684	)

Income available to common shares	$	7,024		$	1,434	$	569		$	3,102		$	(1,002	)	$	(1,216	)	$	2,887		$	9,911

Basic income available to common shares per share from
Continuing Operations	$	0.49																			$	0.69
Discontinued Operations		—																				—

	$	0.49																			$	0.69

Diluted income available to common shares per share from
Continuing Operations	$	0.47																			$	0.65
Discontinued Operations		—																				—

	$	0.47																			$	0.65

Weighted average shares outstanding:
Basic		14,274																				14,213
Diluted		15,207																				15,140

F-14

Income Statement Impact of Restatement for the Year Ended December 31, 2004


	Income Statement Impact of Restatement for the Year Ended December 31, 2004
	As					Write off			Foreign			Unaccrued						Other			Total
	Previously			Capitalization		Seismic			Currency			Payroll and						Adjustments/			Restatement			As
	Reported			of Interest		Cost			Translations			Other Costs			DD&A			Restatements			Adjustments			Restated
Revenue
Oil and natural gas sales	$	22,336		$	—	$	—		$	—		$	—		$	—		$	—		$	—		$	22,336
Loss on commodity derivatives		(1,322	)		—		—			—			—			—			—			—			(1,322	)
Lease bonuses and rentals		14			—		—			—			—			—			—			—			14

Total Revenues		21,028			—		—			—			—			—			—			—			21,028
Operating costs and expenses
Lease operating expenses		6,873			—		—			526			—			—			—			526			7,399
Exploration expense		3,402			—		929			217			—			—			(18	)		1,128			4,530
Dry hole and abandonment		—			—		—			—			—			—			—			—			—
Depreciation, depletion and amortization		3,538			—		—			—			—			496			76			572			4,110
Loss on involuntary conversion of assets		—			—		—			—			—			—			—			—			—
Impairment of oil and natural gas properties		—			—		—			—			—			—			—			—			—
General and administrative		5,646			—		—			—			1,485			—			332			1,817			7,463

Total Operating costs and expenses		19,459			—		929			743			1,485			496			390			4,043			23,502
Operating Income (loss)		1,569			—		(929	)		(743	)		(1,485	)		(496	)		(390	)		(4,043	)		(2,474	)
Other Income (expense)
Equity earnings (loss) of unconsolidated investments		(18	)		—		—			—			—			—			—			—			(18	)
Gain (loss) on sale of properties and other assets		(336	)		—		—			—			—			—			177			177			(159	)
Foreign currency exchange gain		3,904			—					(3,777	)		—			—			—			(3,777	)		127
Interest and other income		396			—		—			—			—			—			119			119			515
Interest expense		(1,611	)		432		—			—			—			—			(235	)		197			(1,414	)

Total other income (expense)		2,335			432		—			(3,777	)		—			—			61			(3,284	)		(949	)
Income from continuing operations before income taxes		3,904			432		(929	)		(4,520	)		(1,485	)		(496	)		(329	)		(7,327	)		(3,423	)
Income tax benefit		3,576			—		—			—			—			—			(2,423	)		(2,423	)		1,153

Income from continuing operations		7,480			432		(929	)		(4,520	)		(1,485	)		(496	)		(2,752	)		(9,750	)		(2,270	)
Income from discontinued operations, net of tax		17,539			—		—			—			—			—			151			151			17,690

Net income		25,019			432		(929	)		(4,520	)		(1,485	)		(496	)		(2,601	)		(9,599	)		15,420
Preferred dividends		(714	)		—		—			—			—			—			—			—			(714	)

Income available to common shares	$	24,305		$	432	$	(929	)	$	(4,520	)	$	(1,485	)	$	(496	)	$	(2,601	)	$	(9,599	)	$	14,706

Basic income available to common shares per share from
Continuing operations	$	0.71																						$	(0.31	)
Discontinued operations		1.83																							1.85

	$	2.54																						$	1.54

Diluted income available to common shares per share from
Continuing operations	$	0.60																						$	(0.31)
Discontinued operations		1.37																							1.85

	$	1.97																						$	1.54

Weighted average shares outstanding:
Basic		9,571																							9,571
Diluted		12,817																							9,571

F-15

Income Statement Impact of Restatement for the Year Ended December 31, 2003 (In thousands)


	Income Statement Impact of Restatement for the Year Ended December 31, 2003
	As					Foreign						Write-off			Other				Total
	Previously			Capitalization		Currency						of Deferred			Adjustments/			Restatement			As
	Reported			of Interest		Translations			DD&A			Loan Costs			Reclassifications			Adjustments			Restated
Revenue
Oil and natural gas sales	$	17,845		$	—	$	—		$	—		$	—		$	(847	)	$	(847	)	$	16,998
Loss on commodity derivatives		(1,017	)		—		—			—			—			241			241			(776	)
Lease bonuses and rentals		18			—		—			—			—			—			—			18

Total Revenues		16,846			—		—			—			—			(606	)		(606	)		16,240
Operating costs and expenses
Lease operating expenses		6,651			—		—			—			—			(431	)		(431	)		6,220
Exploration expense		2,411			—		—			—			—			(59	)		(59	)		2,352
Dry hole and abandonment		—			—		—			—			—			—			—			—
Depreciation, depletion and amortization		3,246			—		(29	)		259			—			—			230			3,476
Loss on involuntary conversion of assets		—			—		—			—			—			—			—			—
Impairment of oil and natural gas properties		171			—		—			—			—			—			—			171
General and administrative		3,494			—		—			—			—			263			263			3,757

Total Operating costs and expenses		15,973			—		(29	)		259			—			(227	)		3			15,976
Operating Income		873			—		29			(259	)		—			(379	)		(609	)		264
Other Income (expense)
Equity earnings (loss) of unconsolidate investments		22			—		—			—			—			—			—			22
Gain (loss) on sale of properties and other assets		80			—		—			—			—			40			40			120
Foreign Currency exchange gain		979			—		2,829			—			—						2,829			3,808
Interest and other income		173			—		121			—			—			—			121			294
Interest expense		(1,193	)		286		—			—			(809	)		65			(458	)		(1,651	)

Total other income (expense)		61			286		2,950			—			(809	)		105			2,532			2,593
Income from continuing operations before income taxes		934			286		2,979			(259	)		(809	)		(274	)		1,923			2,857
Income Tax Benefit		266			—		—			—			—			337			337			603

Income from Continuing Operations		1,200			286		2,979			(259	)		(809	)		63			2,260			3,460
Income from Discontinued Operations, net of tax		1,182			—		—			—			—			—			—			1,182

Net Income		2,382			286		2,979			(259	)		(809	)		63			2,260			4,642
Preferred dividends		(500	)		—		—			—			—			—			—			(500	)

Income available to common shares	$	1,882		$	286	$	2,979		$	(259	)	$	(809	)	$	63		$	2,260		$	4,142

Basic income available to common shares per share from Continuing Operations	$	0.07																			$	0.32
Discontinued Operations		0.13																				0.12

	$	0.20																			$	0.44

Diluted income available to common shares per share from Continuing Operations	$	0.07																			$	0.32
Discontinued Operations		0.13																				0.12

	$	0.20																			$	0.44

Weighted average shares outstanding:
Basic		9,338																				9,338
Diluted		9,347																				9,347

F-16

Balance Sheet Impact of Restatement as of December 31, 2005 (In thousands)


	As					Insurance			Foreign						Other			Total
	Previously			Capitalization		Claim			Currency						Adjustments /			Restatement			As
	Reported			of Interest		Adjustments			Translations			DD & A			Reclassifications			Adjustments			Restated
Assets
Cash and cash equivalents	$	52,507		$	—				$	300		$	—		$	306		$	606		$	53,113
Accounts and notes receivable		18,506			—		(10,600	)		256			—			—			(10,344	)		8,162
Income taxes receivable		4,736			—		—			—			—			(283	)		(283	)		4,453
Other		3,243			—		—			—			—			3,294			3,294			6,537
Oil & Gas properties, net, using successful efforts method of accounting		134,035			1,434		11,100			(155	)		(1,141	)		(7,115	)		4,123			138,158
Goodwill		2,487			—		—			—			—			1,708			1,708			4,195
Other assets		5,415			—		—			—			—			(470	)		(470	)		4,945

Liabilities
Accounts payable & accrued liabilities		22,479			—		—			(130	)		—			(3,101	)		(3,231	)		19,248
Long-term accrued liabilities		1,043			—		—			—			—			367			367			1,410
Long-term asset retirement obligations		2,225			—											1,405			1,405			3,630

Deferred income tax liabilities		10,221			—		—			(1,005	)		—			2,983			1,978			12,199

Shareholder’s Equity													—
Retained earnings		31,346			—		—			—			—			(1,782	)		(1,782	)		29,564
Accumulated other comprehensive income (loss)		(3,261	)		—		—			—			—			(103	)		(103	)		(3,364	)


(1)	Other adjustments and reclassifications primarily relate to carried over adjustments from prior period restatements and the following year 2005 adjustments:


	—	Reclassification of advances paid to vendors incorrectly recorded as additions to oil and gas properties totaling approximately $3.2 million

	—	Adjustment to reduce oil & gas properties cost for the amounts to be invoices to JIB partners totaling approximately $3.4 million

	—	Adjustment for under estimation of asset retirement obligation totaling approximately $1.4 million

F-17

Balance Sheet Impact of Restatement as of December 31, 2004


	As				Foreign						Asset		Other			Total
	Previously		Capitalization		Currency						Retirement		Adjustments /			Restatement			As
	Reported		of Interest		Translations			DD & A			Obligations		Reclassifications			Adjustments			Restated
Assets
Accounts and notes receivable	$	3,230	$	—	$	—		$	—		$	—	$	620		$	620		$	3,850
Oil & Gas properties, net, using successful efforts method of accounting		79,667		718		(985	)		(647	)		1,015		2,626			2,727			82,394
Investments in unconsolidated entities		1,467		—		—			—			—		(1	)		(1	)		1,466
Goodwill		2,487		—		7			—			—		3,485			3,492			5,979
Other assets		1,659		—		—			—			—		(334	)		(334	)		1,325

Liabilities
Accounts payable & accrued liabilities		6,634		—		—			—			—		4,478			4,478			11,112
Income taxes payables		1,633		—		—			—			—		(40	)		(40	)		1,593
Long-term asset retirement obligations		2,331		—		—			—			960		—			960			3,291

Deferred income tax liabilities		10,660		—		(960	)		—			—		3,979			3,019			13,679

Shareholder’s Equity									—			—		—
Additional paid-in capital		37,523		—		—						—		1			1			37,524
Retained earnings		24,323		—		(3,277	)		(731	)		—		(662	)		(4,670	)		19,653

Accumulated other comprehensive income		1,960		—		2,756			—			—		—			2,756			4,716


(2)	Other adjustments and reclassifications primarily relate to the following periods and year 2004 adjustments:

	Prior periods
	—	Reversal of deferred tax liability relating to acquisition of properties incorrectly adjusted to goodwill totalling approximately $2.4 million
	—	Adjustment for payment of pre-acquisition contingencies incorrectly recorded as additions to oil and gas properties totaling approximately $1.6 million
	—	Adjustment to correctly record deferred tax liability totalling approximately $2.6 million
	Year 2004
	—	Reclassification of advances received from join interest billing (JIB) partners to accounts payable incorrectly recorded as additions to oil and gas properties totaling approximately $3.7 million
	—	Adjustment to correctly record deferred tax liability totaling approximately $1.6 million

F-18

Cumulative Impact of Restatement on Retained Earnings (In thousands)


										Cumulative
										Adjustments
	Year Ended			Year Ended			Year Ended			as of
	December 31,			December 31,			December 31,			December 31,
	2003			2004			2005			2005
Retained earnings, as previously reported	$	18		$	24,323		$	31,346
Restatement adjustments for:
Capitalization of Interest		286			432			1,434		$	2,152
Write-off Seismic Cost		—			(929	)		—			(929	)
Unaccrued Payroll and Other Cost		—			(1,485	)		—			(1,485	)
Insurance Claim Adjustment		—			—			569			569
Foreign Currency Translations		2,979			(4,520	)		3,102			1,561
DD&A		(259	)		(496	)		(1,002	)		(1,757	)
Write-off of Deferred Loan Costs		(809	)					—			(809	)
Other, net		(274	)		(178	)		129			(323	)

Total impact of restatement adjustments before income taxes		1,923			(7,176	)		4,232			(1,021	)
Benefit (provision) for income taxes		337			(2,423	)		(1,344	)		(3,430	)

Net effect of adjustments on income statement		2,260			(9,599	)		2,888			(4,451	)
Restatement of beginning retained earnings		2,669			—			—			2,669

		4,929			(9,599	)		2,888		$	(1,782	)

Impact of prior period restatement and other stockholders’ equity adjustments		—			4,929			(4,670	)

Retained earnings, as restated	$	4,947		$	19,653		$	29,564

Cash flow impact of restatement for the years ended December 31, 2005, 2004 and 2003 are as follows:


	2005			2004			2003

Net cash provided by (used in):
Operating activities
— As previously reported	$	9,532		$	94		$	6,879
— As restated		6,699			(3,703	)		11,354
Investing activities
— As previously reported		(68,572	)		24,426			(3,241	)
— As restated		(106,285	)		25,785			(3,972	)
Financing activities
— As previously reported		145,501			(20,864	)		(1,869	)
— As restated	$	149,666		$	(19,683	)	$	(1,869	)

F-19

NOTE 4 — ACQUISITION

In June 2005, we acquired 100% of Pogo Hungary Ltd., a wholly owned subsidiary of Pogo Producing Company. The primary reasons for the merger were to, (i) expand the diversity of Toreador’s portfolio of oil and natural gas assets to include additional international activities, (ii) to offer a larger, more diverse company to our current and potential investors, and (iii) to combine the talents of both companies’ management to strengthen Toreador’s pre-existing exploration, operating and exploitation capacity. The results of operations are included in our consolidated financial statements effective with the date of acquisition through December 31, 2005. Our results of operations would not have been different than reported and, therefore, we have not provided any pro forma disclosures. The purchase price was approximately $9 million, which was settled in cash and was allocated as follows (in thousands):


	Value
	Allocated
Cash and other current assets	$	254
Plant, property and equipment — materials and supplies inventory		3,141
Non-producing lease cost		5,822
Other assets		259
Accounts payable		(476	)

Total purchase price allocation	$	9,000

F-20

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 5 — EARNINGS PER SHARE

In accordance with the provisions of FASB Statement of Financial Accounting Standards No. 128, “Earnings per Share” (“Statement 128”), basic earnings per share are computed on the basis of the weighted-average number of common shares outstanding during the periods. Diluted earnings per share is computed based upon the weighted-average number of common shares plus the assumed issuance of common shares for all potentially dilutive securities.


	Year ended December 31,
	2005		2004			2003
	(Restated)		(Restated)			(Restated)
	(in thousands, except per share data)
Basic earnings per share:
Numerator
Income (loss) from continuing operations, net of income tax	$	10,548	$	(2,270	)	$	3,460
Less: dividends on preferred shares		684		714			500

Net income from continuing operations, net of tax		9,864		(2,984	)		2,960
Income from discontinued operations, net of tax		47		17,690			1,182

Income available to common shares	$	9,911	$	14,706		$	4,142

Denominator
Common shares outstanding		14,213		9,571			9,338
Basic earnings available to common shares per share from:
Continuing operations	$	0.69	$	(0.31	)	$	0.32
Discontinued operations		—		1.85			0.12

Basic income per share	$	0.69	$	1.54		$	0.44

Diluted earnings per share:
Numerator
Income from continuing operations, net of income tax	$	10,548	$	(2,270	)	$	3,460
Less: dividends on preferred shares		684		714			500
Add: interest on convertible debentures		73		—			—

Net income from continuing operations, net of tax		9,937		(2,984	)		2,960
Income from discontinued operations, net of tax		47		17,690			1,182

	$	9,984	$	14,706		$	4,142

F-21

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	Year ended December 31,
	2005			2004			2003
	(Restated)			(Restated)			(Restated)
	(in thousands, except per share data)
Denominator
Common shares outstanding		14,213			9,571			9,338
Stock options, restricted stock and warrants		746			—	(2)		9
Conversion of preferred shares		—	(1)		—	(2)		—	(1)
Conversion of 7.85% notes payable		—	(1)		—	(2)		—	(4)
Conversion of 5.0% notes payable		—	(1)		—	(3)		—	(3)
Conversion of debentures		181			—	(2)		—	(1)

Diluted shares outstanding		15,140			9,571			9,347

Diluted earnings available to common shares per share from:
Continuing operations	$	0.65		$	(0.31	)	$	0.32
Discontinued operations		—			1.85			0.12

Diluted income per share	$	0.65		$	1.54		$	0.44

Anti-dilutive securities not included above are as follows:
Stock options, restricted stock and warrants		—			523			—
Preferred shares		524			1,997			1,393
7.85% notes payable		43			410			—
Debentures		—			316			320
5% notes payable		552			—			—


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

(2)		Conversion of these securities would be antidilutive in 2004 due to operating losses, therefore, are not included for the calculation of diluted earnings per share in 2004.

(3)		5% Senior Convertible Notes were issued on September 27, 2005.

(4)		7.85% Notes Payable were issued in July 2004 and subsequently exchanged in January 2005

NOTE 6 — ACCOUNTS AND NOTES RECEIVABLE

Accounts receivable consisted of the following:


	December 31,
	2005		2004
	(Restated)		(Restated)
	(in thousands)
Accrued oil and natural gas sales receivable	$	5,608	$	3,790
Trade receivables		2,142		27
Other account and note receivables		412		33

	$	8,162	$	3,850

Accrued oil and natural gas sales receivables are due from either purchasers of oil and gas or operators in oil and natural gas wells for which the Company owns an interest. Oil and natural gas sales are generally unsecured and such amounts are generally due within 30 days after the month of sale.

Trade receivables are the amounts due from our joint interest partners in our Black Sea operation. These receivables are generally due within 15 days after receipt of monthly joint interest billing.

Other receivables are accrued interest receivable, at December 31, 2005 on time deposits, value added tax refunds and travel advances to employees.

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

F-22

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 7 — PROPERTIES AND EQUIPMENT

Oil and Natural Gas Properties consist of the following:


	December 31,
	2005			2004
	Restated
	(in thousands)
Licenses and concessions	$	3,272		$	3,997
Non-producing leaseholds		65,128			22,127
Producing leaseholds and intangible drilling costs		97,238			85,797
Lease and well equipment		5,617			1,908
Furniture, fixtures and office equipment		2,365			1,517

		173,620			115,346
Accumulated depreciation, depletion and amortization		(35,462	)		(32,952	)

Total oil and natural gas properties	$	138,158		$	82,394

During 2005 we did not sell any material oil and natural gas properties. In 2004, we sold various properties and equipment for $42.1 million, (net of closing costs) resulting in a gain of $28.7 million, before tax.

The Company capitalizes exploratory well costs until a determination is made that the well has found proved reserves or is deemed noncommercial, in the latter case the well costs are immediately charged to exploration expense.

The following table reflects the Company’s capitalized exploratory well activity and does not include amounts that were capitalized and subsequently expensed in the same period:


	December 31
	2005			2004
	Restated
	(in thousands)

Capitalized exploratory well cost, beginning of the period	$	2,307		$	—
Additions to capitalized exploratory well costs pending determination of proved reserves		1,042			2,307
Reclassified to oil and natural gas properties based on determination of proved reserves		(2,307	)		—

Capitalized exploratory well costs, end of period	$	1,042		$	2,307

The following table provides an aging of capitalized exploratory well costs (suspended well costs), as of December 31 of each year, based on the date the drilling was completed:


	December 31
	2005		2004
	Restated
	(in thousands)

Capitalized exploratory well cost that have been capitalized for a period of one year or less	$	1,042	$	2,307
Capitalized exploratory well cost that have been capitalized for a period greater than one year		—		—

Balance at the end of the period	$	1,042	$	2,307

NOTE 8 — INVESTMENTS IN UNCONSOLIDATED SUBSIDIARIES

In February 2004, we acquired 45% of ePsolutions. Based in Austin, Texas, ePsolutions is a software and energy services company in the electric industry and deregulated energy markets. ePsolutions is the developer of emPower system, a CIS, EDI and billing solution for energy companies within deregulated energy markets. At December 31,

F-23

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2005 and 2004 our investment in ePsolutions amounted to $1.3 million and $799,000, respectively. For the years ended December 31, 2005 and 2004 we advanced $759,000 and $1.2 million, respectively, and we recorded equity in the loss of ePsolutions of $238,000 in 2005 and a loss of $312,000 in 2004. We received a dividend from ePsolutions of $99,000 in 2004.

In July 2000, we acquired 35% of EnergyNet.com, Inc. (“EnergyNet”), an Internet based oil and natural gas property auction company. At December 31, 2005 and 2004, our investment in EnergyNet amounted to $832,000 and $554,000, respectively. We recorded equity in the earnings of EnergyNet of $409,000 in 2005, $279,000 in 2004, and $6,500 in 2003. We received a dividend from EnergyNet of $131,250 in 2005 and $131,250 in 2004.

In April 2000, we acquired a 50% interest in Capstone Royalty, LLC (“Capstone”), a joint venture formed to acquire mineral interests at county auctions in west Texas and develop those interests. Our investment in Capstone amounted to $104,000 and $112,000 at December 31, 2005 and 2004, respectively. We recorded equity in the earnings of Capstone amounting to $51,000 in 2005, $15,000 in 2004 and $15,000 in 2003. We received a distribution of $60,000 in 2005 and $25,000 from Capstone in 2004 and $0 in 2003.

NOTE 9 — LONG-TERM DEBT

Long-term debt consisted of the following:


	December 31,
	2005			2004
	(Restated)
	(in thousands)
Revolving line of credit with Texas Capital Bank, N.A.	$	—		$	37
Revolving line of credit with Natexis Banques Populaires		5,000			—
Convertible subordinated notes		86,250			7,500
Convertible debenture — related party		810			1,485

		92,060			9,022
Less: current portion		(810	)		(37	)

	$	91,250		$	8,985

CONVERTIBLE SENIOR NOTES DUE OCTOBER 1, 2025

On September 27, 2005, we issued $75 million of Convertible Senior Notes due October 1, 2025 (“Notes”) to qualified institutional buyers pursuant to Rule 144A of the Securities Act of 1933. The Company also granted the initial purchasers the option to purchase an additional $11.25 million aggregate principal amount of Notes to cover over-allotments. The option was exercised on September 30, 2005. The total principal amount of Notes issued was $86.25 million and total net proceeds were approximately $82.2 million. We incurred approximately $4.1 million of costs associated with the issuance of the Notes; these costs have been recorded in other assets on the balance sheet and are being amortized to interest expense using the effective interest rate method over the term of the Notes. The net proceeds have been and will be used for general corporate purposes, including funding a portion of the Company’s 2005 and 2006 exploration and development activities.

The Notes bear interest at a rate of 5% per annum and can be converted into common stock at an initial conversion rate of 23.3596 shares of common stock per $1,000 principal amount of Notes, subject to adjustment in an event of a fundamental change, as defined, (equivalent to a conversion price of approximately $42.81 per share). The Company may redeem the Notes, in whole or in part, on or after October 6, 2008, and prior to October 1, 2010, for cash at a redemption price equal to 100% of the principal amount of Notes to be redeemed, plus any accrued and unpaid interest, if the closing price of

F-24

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

its common stock exceeds 130% of the conversion price over a specified period. On or after October 1, 2010, the Company may redeem the Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of Notes to be redeemed, plus any accrued and unpaid interest, irrespective of the price of its common stock. Holders may convert their Notes at any time prior to the close of business on the business day immediately preceding their stated maturity, and holders may, upon the occurrence of certain fundamental changes, and on October 1, 2010, October 1, 2015, and October 1, 2020, require the Company to repurchase all or a portion of their Notes for cash in an amount equal to 100% of the principal amount of such Notes, plus any accrued and unpaid interest.

REVOLVING LINE OF CREDIT WITH NATIXIS BANQUES POPULAIRES

On December 23, 2004, we entered into a five-year $15.0 million reserve-based borrowing facility with a French lender to finance the development of our existing French fields, acquisitions of new fields, general working capital and other corporate purposes. The facility bears interest at a floating rate of 2.25-2.75% above LIBOR (6.59% at December 31, 2005) depending on the principal outstanding. The facility is collateralized by certain of our French assets, including contracts relating to our rights and interests in our French fields, our direct and indirect equity interests in certain of our subsidiaries and payments received from the sale of our French production. The Company and certain of its U.S. and French subsidiaries have each guaranteed the obligations under the facility. This facility will require monthly interest payments until December 23, 2009, at which time all unpaid principal and interest are due. We are subject to a commitment fee of one half (1/2) of the applicable margin, 1.25% as of December 31, 2005, on the available and unused facility borrowings. Under the $15.0 million facility, borrowings of approximately $8.0 million are available at December 31, 2005. The $15.0 million facility contains various affirmative and negative covenants. These covenants, among other things, limit additional indebtedness, the sale of assets, change of control and management, limitations on the distribution of stock dividends and require us to meet certain financial requirements. Specifically, we must maintain an interest cost ratio of not less than 4.00 to 1.00, an indebtedness ratio of not less than 1.00 to 1.00, asset life cover ratio of not less than 1.25 to 1.00, a loan life cover ratio equal to or greater than 1.15 to 1.00 and a debt service coverage ratio equal to or greater than 1.10 to 1.00. As of December 31, 2005, we were in compliance with all covenants.

REVOLVING LINE OF CREDIT WITH TEXAS CAPITAL BANK, N.A.

On December 30, 2004, we entered into a five-year $25.0 million reserve-based borrowing facility with Texas Capital Bank, N.A. in order to finance the development and acquisition of oil and natural-gas interests both domestically and internationally and for working capital purposes. The facility bears interest at a rate of prime less 0.5% (6.75% total rate at December 31, 2005) and is collateralized by our domestic working interests. The borrowers under this facility are two of our domestic subsidiaries, and the Company has guaranteed the obligations. At December 31, 2005, we had approximately $3.3 million available for borrowings. The $25.0 million facility requires monthly interest payments until January 1, 2009 at which time all unpaid principal and interest are due. We are subject to a commitment fee of one-half of one percent (1/2 of 1%) as of December 31, 2005, on the available and unused facility borrowings. The $25 million facility contains various affirmative and negative covenants. These covenants, among other things, limit additional indebtedness, the sale of assets, change of control and management and require us to meet certain financial requirements. Specifically, we must maintain a current ratio of 1.25 to 1.00 (exclusive of amounts due under revolving credit arrangements) and an interest coverage ratio of not less than 3.00 to 1.00. As of December 31, 2005, we were in compliance with all covenants.

REVOLVING LINE OF CREDIT WITH BARCLAYS BANK, PLC

As part of our acquisition of Madison Oil Company, we assumed a revolving credit facility with Barclays Bank, Plc (the “Barclays Facility”) that was to mature on December 31, 2005 and was secured by the production from our French properties. We had $11.8 million outstanding at December 31, 2003 under the Barclays Facility. During 2003, we used $2.8 million of our available cash flow to reduce the amounts outstanding under the Barclays Facility. We discharged the Barclays Facility in January 2004 with a portion of the proceeds from the U. S. mineral royalty

F-25

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

asset sale. Under the terms of the Warrant Buyback Letter dated May 19, 2003, we were required to buy 500,000 outstanding warrants back from Barclays for the sum of $100,000 upon final settlement of the Barclays Facility.

Additionally, we were required to make a final settlement payment totaling $925,000 less the amounts of any payments made to Barclays for interim fees due before the final settlement under the terms of the Settlement Fee Letter dated May 19, 2003. The settlement payment amount after deduction of the interim fees paid to Barclays was approximately $806,000.

CONVERTIBLE SUBORDINATED NOTES

In July 2004, we sold to certain institutional investors pursuant to a private offering $7.5 million aggregate principal amount of 7.85% convertible subordinated notes due June 30, 2009. We used the net proceeds of the offering to accelerate our oil development program in France’s Paris Basin and for general corporate purposes. The 7.85% convertible subordinated notes due June 30, 2009 bore interest at the rate of 7.85% per annum and were convertible into shares of Toreador common stock at a conversion price of $8.20 per share. Toreador had the right to cause the 7.85% notes to be converted on or after February 22, 2005, if the closing price of Toreador’s common stock was greater than $14.35 for the 30 consecutive trading days prior to the date of Toreador’s conversion notice. On January 13, 2005, we offered the option to the holders of the 7.85% notes to exchange their notes for the aggregate number of shares of our common stock issuable upon conversion of each of their notes and that portion of interest payable pursuant to the notes that would otherwise have been payable to the holders through February 22, 2005 absent conversion of the notes prior to such date. On or prior to January 20, 2005, all of our 7.85% convertible subordinated notes due June 30, 2009 (with a carrying value, net of unamortized loan fees of $6.4 million) were exchanged for an aggregate of 914,634 shares of our common stock and an aggregate cash payment (in lieu of interest) of approximately $85,000 which is included in interest expense in 2005.

CONVERTIBLE DEBENTURE

As part of our acquisition of Madison Oil Company, we assumed and amended a convertible debenture (“Debenture”) payable to PHD Partners LP. The general partner of PHD Partners LP is a corporation wholly owned by David M. Brewer, a director and significant stockholder of Toreador. The amended and restated debenture used to bear interest at 10% per annum and was due on March 31, 2006. At the holders’ option, the amended and restated debenture could be converted into common stock at a ratio of $6.75 per share. We originally had 319,962 common shares reserved for issuance related to the conversion of the amended and restated debenture. As of March 31, 2004, the amended and restated debenture was amended and restated to bear interest at 6% per annum, eliminate the Company’s right under certain circumstances to force a conversion of the principal into shares of Toreador common stock and eliminate the Company’s ability to repay principal prior to maturity. The maturity date remains March 31, 2006. At the holder’s option, the second amended and restated convertible debenture can be converted into Toreador common stock at a conversion price of $6.75 per share. In December 2004, PHD Partners LP converted $675,000 of the second amended and restated debenture into 100,000 shares of our common stock. As a result, at December 31, 2004 the outstanding principal amount of the second amended and restated convertible debenture was approximately $1.5 million. On August 10, 2005, PHD Partners converted $675,000 of the second amended and restated debenture into 100,000 shares of our common stock, resulting in an outstanding principal balance of $810,000 at December 31, 2005. Interest payments made to PHD Partners LP were $73,195, $352,416 and $108,437 in 2005, 2004 and 2003, respectively.

The following table summarizes the principal maturities under our long-term debt arrangements at December 31, 2005, (In thousands):


	2006		2007		2008		2009		2010		Thereafter		Total

Long-term debt	$	810	$	2,000	$	—	$	3,000	$	—	$	86,250	$	92,060

F-26

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 10 — CAPITAL

Toreador had 72,000 and 154,000 shares of nonvoting Series A-1 Convertible Preferred Stock outstanding at December 31, 2005 and 2004, respectively. At the option of the holder, the Series A-1 Convertible Preferred Stock may be converted into common shares at a price of $4.00 per common share (conversion would amount to 450,000 Toreador common shares at December 31, 2005). The Series A-1 Convertible Preferred Stock accrues dividends at an annual rate of $2.25 per share payable quarterly in cash. At any time on or after November 1, 2007, we may elect to redeem for cash any or all shares of Series A-1 Convertible Preferred Stock. The optional redemption price per share is the sum of (1) $25.00 per share of the Series A-1 Convertible Preferred Stock plus (2) any accrued unpaid dividends, and such sum is multiplied by a declining multiplier. The multiplier is 105% until October 31, 2008, 104% until October 31, 2009, 103% until October 31, 2010, 102% until October 31, 2011, 101% until October 31, 2012, and 100% thereafter.

On December 31, 2004, 6,000 shares of Series A-1 Convertible Preferred Stock were converted into 37,500 shares of our common stock pursuant to the terms of the Series A-1 Convertible Preferred Stock.

On December 31, 2004, 160,000 shares of Series A Convertible Preferred Stock were converted into 1,000,000 shares of our common stock pursuant to the terms of the Series A Convertible Preferred Stock.

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

As part of our acquisition of Madison Oil Company, in 2001 we issued warrants for the purchase of 111,509 shares of our common stock. At December 31, 2005 there were 4,130 warrants outstanding at $8.05 that expire in July 2010 and 2,360 warrants outstanding at $5.37 that expire in August 2010.

On July 22, 2004, we issued warrants for the purchase of 40,000 shares of our common stock at $8.20 per share. The warrant was issued pursuant to the terms of the letter agreement dated July 19, 2004. At December 31, 2005 there were 36,400 warrants outstanding all of which expire July 22, 2009.

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

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

REGISTRATION RIGHTS AGREEMENTS

In July 2004, concurrent with the issuance of the Company's Convertible Subordinated Notes, the Company entered into registration rights agreements to register a sufficient amount of common stock to satisfy the conversion feature of the notes. The registration rights agreements provide that if a registration statement is not effective within 90 days following the issuance of the Convertible Subordinated Notes (or 120 days if the SEC issues comments on the registration statement) or if the Company does not subsequently maintain the effectiveness of the registration statement (following a 20 day grace period), then in addition to any other rights the investor may have, the Company will be required to pay the investor liquidated damages, in cash, equal to one percent per month of the aggregate purchase price paid by such investor. Pursuant to the terms of the registration rights agreements, the Company filed a registration statement on Form S-3 with the SEC on August 20, 2004, which was declared effective on August 31, 2004, which was within 90 days of closing.

The Company views the registration rights agreements containing the liquidated damages provision as a separate freestanding contracts. The Company's view is analogous to “View C” in EITF Issue No. 05-4,“The Effect of a Liquidated Damages Clause on a Freestanding Financial Instrument Subject to EITF Issue No. 00-19, ‘Accounting for Derivative Financial Instruments Indexed to, and Potentially Settled in, a Company's Own Stock.’”Under this approach, the registration rights agreement is accounted for separately from the Convertible Subordinated Notes.

The Company has valued the liquidated damages provision of the registration rights agreements at nominal value. In determining this as the fair value, the Company considered the following factors. The agreement provides that there is a 90-day period to have the registration statement declared effective before liquidated damages apply and up to 120 days if the SEC provides comments on the registration statement. The Company believed at the closing of the private placement that it was probable the registration statement would be declared effective within the 90-day period. The registration statement was declared effective in the same fiscal quarter as the closing of the private placement, and therefore the Company was aware that there was no value to the liquidated damages provision related to effectiveness of the registration statement. The liquidated damages provision would only have value in the future if the registration became ineffective in a future period for more than 20 days in any 12-month period. At the time of the issuance, the Company believed that the events that would lead to a suspension of effectiveness were unlikely to occur. In future periods, should the Company conclude that it is probable, as defined in SFAS No. 5,“Accounting for Contingencies,” that a liability for liquidated damages will occur, the Company will record the estimated cash value of the liquidated damages liability at that time.

F-27

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 11 — INCOME TAXES

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


	2005			2004			2003
	(restated)			(restated)			(restated)
	(in thousands)
Current:
U.S. Federal	$	(2,421	)	$	7,129		$	178
U.S. State		46			844			161
Foreign		1,140			(611	)		689
Deferred:
U.S. Federal		1,383			329			(113	)
U.S. State		—			—			(1	)
Foreign		(463	)		2,163			(1,114	)

	$	(315	)	$	9,854		$	(200	)


The tax provision (benefit) has been allocated between continuing operations and discontinued operations as follows:
Provision (benefit) allocated to:
Continuing operations	$	(315	)	$	(1,153	)	$	(603	)
Discontinued operations		—			11,007			403

	$	(315	)	$	9,854		$	(200	)

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


	2005			2004			2003
	(restated)			(restated)			(restated)
	(in thousands)
Statutory tax at 34%	$	3,501		$	8,532		$	1,783
Tax basis and rate differences related to foreign operations		(2,967	)		3,065			616
Use of NOL carryforwards		—			(3,940	)		(523	)
State income tax, net		(148	)		833			245
Foreign currency gain not taxable in foreign partnership		(857	)		431			—
Release of tax reserve		(49	)		(554	)		—
Adjustments to valuation allowance		(385	)		1,748			450
Release of deferred tax under APB 23		—			—			(2,400	)
Use of percentage depletion		(98	)		—			—
Use of capital loss carryover		(90	)		—			—
Other		778			(261	)		(371	)

	$	(315	)	$	9,854		$	(200	)

F-28

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, 2005 and 2004 were as follows:


	December 31,
	2005			2004
	(restated)			(restated)
	(in thousands)
Deferred tax assets:
Net operating loss carryforward — United States	$	2,190		$	1,454
Net operating loss carryforward — Foreign		8,811			1,396
Other		248			100

Gross deferred tax assets		11,249			2,950
Valuation allowance		(5,053	)		(1,407	)

Net deferred tax assets		6,196			1,543

Deferred tax liabilities:
Differences in oil and gas property capitalization and depletion methods— United States		(1,637	)		(1,072	)
Differences in oil and gas property capitalization and depletion methods— Foreign		(16,594	)		(13,520	)
Unrealized foreign currency translation gains		—			(518	)
Other		(164	)		(112	)

Gross deferred tax liabilities		(18,395	)		(15,222	)

Net deferred tax liabilities	$	(12,199	)	$	(13,679	)

At December 31, 2005, Toreador had the following carryforwards available to reduce future taxable income (in thousands) (restated):


Jurisdiction	Expiry		Amount
United States		2010 — 2021	$	5,919
Hungary	Unlimited			24,825
Turkey		2006 — 2010		12,527
France	Unlimited			3,243

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 sufficient to realize all of our deferred tax assets we have recorded the following valuation allowances:


	December 31,
	2005		2004
	(restated)		(restated)
	(in thousands)
United States	$	—	$	292
Turkey		64		230
Hungary		4,000		—
France		989		885

	$	5,053	$	1,407

During 2005, we determined, based on available evidence, that it was no longer necessary to provide for valuation allowances against the net operating losses in the United States.

F-29

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 12 — BENEFIT PLANS

We have a 401(k) retirement savings plan. Employees are eligible to defer portions of their salaries, limited by Internal Revenue Service regulations. Employer matches are discretionary, and are determined annually by the board of directors. Such discretionary matches amounted to $52,000 in 2005, $75,000 in 2004, and zero in 2003.

NOTE 13 — STOCK COMPENSATION PLANS

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

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

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

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

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

A summary of stock option transactions is as follows (restated):


	2005					2004					2003
				WEIGHTED					WEIGHTED					WEIGHTED
				AVERAGE					AVERAGE					AVERAGE
				EXERCISE					EXERCISE					EXERCISE
	SHARES			PRICE		SHARES			PRICE		SHARES			PRICE
Outstanding at January 1		1,346,690		$	4.91		1,515,940		$	4.43		1,434,106		$	4.57
Granted		20,000			16.90		442,700			5.78		120,000			3.10
Exercised		(492,750	)		5.18		(538,102	)		4.33		—
Forfeited		(15,000	)		3.10		(73,848	)		4.95		(38,166	)		5.54

Outstanding at December 31		858,940			5.07		1,346,690			4.91		1,515,940			4.43

Exercisable at December 31		827,274			5.27		1,182,690			5.59		1,081,006			4.52

F-30

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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


					WEIGHTED-AVERAGE		WEIGHTED-AVERAGE
YEAR		OPTION TYPE	SHARES		EXERCISE PRICE		FAIR VALUE
	2005	Exercise price equal to market price		20,000	$	16.90	$	7.31

	2004	Exercise price greater than market price		352,700	$	5.50	$	1.60

		Exercise price equal to market price		90,000	$	6.89	$	2.50

	2003	Exercise price equal to market price		120,000	$	3.10	$	1.12

The following table summarizes information about the fixed price stock options outstanding at December 31, 2005 (restated):


						Weighted
						Average
						Remaining
		Number		Number		Contractual
Exercise Price		Outstanding		Exercisable		Life in Years
$	2.75		45,000		45,000		2.73
	3.00		5,000		5,000		3.42
	3.10		95,000		63,334		7.47
	3.12		10,940		10,940		4.72
	3.88		5,000		5,000		3.83
	4.12		68,000		68,000		6.42
	4.29		14,750		14,750		5.66
	4.51		20,000		20,000		6.13
	4.96		50,000		50,000		8.39
	5.00		236,133		236,133		3.25
	5.50		225,817		225,817		7.00
	5.75		25,800		25,800		5.18
	5.95		30,000		30,000		5.38
	13.75		7,500		7,500		8.88
	16.90		20,000		20,000		9.39

$	5.07		858,940		827,274		5.63

At December 31, 2005, there were 120,208 remaining shares available for grant under the plans collectively.

In May 2005, stockholders approved the Toreador Resources Corporation 2005 Long-Term Incentive Plan (the “Plan”). The Plan authorizes the issuance of up to 250,000 shares of the Company’s common stock to key employees, key consultants and outside directors of the Company. In 2005 the Board of Directors authorized a total of 114,560 shares of restricted stock be granted to employees and non-employee directors. In accordance with Opinion 25, the compensation cost is measured by the difference between the quoted market price of the stock at the date of grant and the price, if any, to be paid by an employee and is recognized as expense over the period the recipient performs related services. The restricted stock grants vest over a three year period and the average price of the stock on the date of the grants was $25.13. Stock compensation expense of $400,790 is included in the Statement of Operations for the year ended December 31, 2005, which represents the cost recognized from the date of the grants through December 31, 2005.

NOTE 14 — COMMITMENTS AND CONTINGENCIES

We lease our office space under non-cancelable operating leases, expiring during 2006 through 2008. We also sublease portions of the leased space to one related party and two unrelated parties under non-cancelable sub-leases

F-31

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

that expire on June 30, 2006. The following is a schedule of minimum future rentals under our non-cancelable operating leases, giving effect to the non-cancelable sub-leases, as of December 31, 2005 (in thousands) (restated):


2006	$	1,184
2007		524
2008		198
2009		118
2010		118
Thereafter		462

		2,604
Less: minimum rents from subleases		34

	$	2,570

Net rent expense totaled $354,000 in 2005, $380,000 in 2004 and $356,000 in 2003.

Turkish Registered Capital.Under the existing Petroleum Law of Turkey, capital that is invested by foreign companies in projects such as oil and natural gas exploration can be registered with the General Directorate of Petroleum Affairs, thereby qualifying for protection against adverse changes in the exchange rate between the time of the initial investment and the time such capital is repatriated out of Turkey. Since 1997 the Turkish government has suspended such protection for repatriated capital. As the holder of more than $50 million of registered capital, we have filed suit in Turkey to attempt to restore the exchange rate protections afforded under the law. No amounts are accrued related to this contingency. In March 2002, a lower level court ruled in favor of the Company. The ruling was subject to appeal that was heard in December 2002. The appellate court reversed the lower court’s ruling. All internal Turkish legal proceedings are exhausted and the rejection of the exchange protection award is final. We have appealed the case to the European Court of Human Rights which is a court recognized by Turkey. We cannot predict the outcome of this matter.

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

NOTE 15 — RELATED PARTY TRANSACTIONS

On June 14, 2004, we issued stock options for 29,500 shares of our common stock to David M. Brewer. Mr. Brewer currently serves as a director for Toreador. The options were in payment to Mr. Brewer for consulting services related to our international activities. The options were granted pursuant to the Toreador Resources Corporation 2002 Stock Option Plan. The exercise price is $5.50 per share. The options expire no later than 10 years from the date of issuance. We recorded a charge to general and administrative costs of $58,000 in 2004.

William I. Lee, a director of the Company, is also Chairman of the Board and majority owner of Wilco Properties, Inc (“Wilco”). The Company subleases office space to Wilco pursuant to a sub-lease agreement. We recorded reductions to rent expense totaling $48,000 in 2005, $45,000 in 2004 and $47,000 in 2003 related to the sublease with Wilco. We have an informal agreement with Wilco under which one of the two companies incurs, on behalf of the other, certain miscellaneous expenses that are subsequently reimbursed by the other company. We had amounts receivable related to this arrangement of $146, $2,000 and $1,500 at December 31, 2005, 2004 and 2003, respectively.

On November 1, 2002, pursuant to a private placement we issued $925,000 of Series A-1 Convertible Preferred Stock to certain of our directors or entities controlled by certain of our directors. In connection with the securities purchase agreements, Toreador entered into a registration rights agreement effective November 1, 2002, among Toreador and the purchasers which provides for the registration of the common stock issuable upon conversion of the Series A-1 Convertible Preferred Stock. During 2003, pursuant to private placements we issued 41,000 shares of our Series A-1 Convertible Preferred Stock for the total amount of $1,025,000 to William I. Lee and Wilco as follows: (i) in October 2003, 34,000 shares were issued to William I. Lee and Wilco, an entity controlled by Mr. Lee; and (ii) in December 2003, 7,000 shares were issued to Wilco. The Series A-1 Convertible Preferred Stock is governed by a certificate of designation. The Series A-1 Convertible Preferred Stock was sold for

F-32

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

a face value of $25.00 per share, and pays an annual cash dividend of $2.25 per share that result in an annual yield of 9.0%. At the option of the holder, the Series A-1 Convertible Preferred Stock may be converted into common shares at a price of $4.00 per common share. The $4.00 conversion price was higher than the market price of our common stock at the time of issuances. The Series A-1 Convertible Preferred Stock is redeemable at our option, in whole or in part, at any time on or after November 1, 2007. The optional redemption price per share is 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 is multiplied by a declining multiplier. The multiplier is 105% until October 31, 2008, 104% until October 31, 2009, 103% until October 31, 2010, 102% until October 31, 2011, 101% until October 31, 2012, and 100% thereafter. In connection with the securities purchase agreements entered into with William I. Lee and Wilco, Toreador granted certain “piggy-back” registration rights relating to the common stock issuable upon conversion of the Series A-1 Convertible Preferred Stock. The sale of the Series A-1 Convertible Preferred Stock was effected in reliance upon the exemption from securities registration afforded by the provisions of Section 4(2) of the Securities Act of 1933, as amended, and Regulation D as promulgated by the Securities and Exchange Commission under the Securities Act of 1933, as amended.

In 2002, we acquired Wilco Turkey Ltd (“WTL”) from Wilco. WTL’s primary asset is an interest (ranging from 52.5% to 87.5%) in exploration licenses covering 2.2 million acres in the Thrace Basin and in the central and southeast areas of Turkey. We also acquired from
F-Co Holdings Kandamis (“F-Co”) additional interests (ranging from 7.5% to 12.5%) in the same exploration licenses. The purpose of the acquisition was to obtain, explore and possibly develop the acreage covered by the licenses. The acreage in the Thrace Basin is adjacent to or near the acreage we held prior to the acquisition of WTL. In exchange for all of the outstanding common stock of WTL, we agreed to give Wilco an overriding royalty interest in any successful wells we drill on the acreage covered by the exploration licenses we acquired. We also agreed to give F-Co, in exchange for its interest in the acreage, an overriding royalty interest in any successful wells we drill on the acreage. As of the acquisition date, there were no outstanding liabilities associated with WTL. We did not convey value to Wilco or F-Co on the acquisition date, or assume any liabilities; therefore, the fair value of the transaction was zero. We have allocated no value to the assets acquired from WTL and F-Co. Wilco is controlled by William I. Lee, a director and stockholder, and F-Co are partially owned by Peter L. Falb, a director and stockholder.

We own a 32% interest in EnergyNet.com, Inc., an Internet based oil and natural gas property auction company. We did not pay any commissions on property sales to EnergyNet during 2005 and 2004.

NOTE 16 — DISCONTINUED OPERATIONS

On January 14, 2004, pursuant to the terms of an Agreement for Purchase and Sale dated December 17, 2003, Toreador and Tormin, Inc., a wholly owned subsidiary of Toreador, sold their United States mineral and royalty assets to Black Stone Acquisitions Partners I, L.P. The gross consideration was approximately $45 million cash. The effective date of the sale was January 1, 2004.

The results of operations of assets in the United States to be sold as of December 31, 2003 have been presented as discontinued operations in the accompanying consolidated statements of operations. Prior year results have also been reclassified to report the results of operations of the assets to be sold as discontinued operations. Results for these assets reported as discontinued operations were as follows:


	Year ended December 31,
	2005		2004		2003
	(Restated)		(Restated)		(Restated)
	(in thousands)
Revenues:
Oil and natural gas sales	$	63	$	139	$	7,261
Lease bonuses and rentals		—		—		341
Loss on commodity derivatives		—		—		(1,304	)

Total revenues		63		139		6,298

F-33


	Year ended December 31,
	2005		2004			2003
	(Restated)		(Restated)			(Restated)
	(in thousands)
Costs and expenses:
Lease operating		1		(10	)		1,046
Depreciation, depletion and amortization		—		—			734
Impairment of oil and natural gas properties		—		—			—
Allocated general and administrative		15		163			2,222
Interest expense		—		—			711

Total costs and expenses		16		153			4,713
Gain on sale of properties		—		28,711			—

Income before taxes		47		28,697			1,585
Income tax provision		—		11,007			403

Income from discontinued operations (U.S.)	$	47	$	17,690		$	1,182

General and administrative expense and interest expense was allocated to discontinued operations based on the percent of oil and natural gas revenue applicable to discontinued operations to the total oil and gas revenue.

NOTE 17 — INFORMATION ABOUT OIL AND NATURAL GAS PRODUCING ACTIVITIES AND OPERATING SEGMENTS

We have operations in only one industry segment, the oil and natural gas exploration and production industry. We are structured along geographic operating segments or regions. As a result, we have reportable operations in the United States, Western Europe (France) and Eastern Europe (Hungary, Romania and Turkey). Geographic operating segment income tax expenses have been determined based on statutory rates existing in the various tax jurisdictions where we have oil and natural gas producing activities.

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

The following tables provide the geographic operating segment data required by Statement of Financial Accounting Standards No. 131, “Disclosure about Segments of an Enterprise and Related Information”. The United States segment data for the years ended December 31, 2005, 2004, and 2003 excludes discontinued operations sold in January 2004 through the U. S. mineral royalty asset sale (see Note 16).


	United
	States			France			Turkey			Hungary			Romania			Total
	(In thousands)
For the year ended December 31, 2005(restated)
Revenues:
Oil and natural gas sales	$	7,728		$	20,572		$	2,817		$	—		$	—		$	31,117
Loss on commodity derivatives		—			—			—			—			—			—

Total revenues		7,728			20,572			2,817			—			—			31,117
Costs and expenses:
Lease operating		2,096			5,392			710			—			—			8,198
Exploration expense		1,250			1,011			289			237			153			2,940
Depreciation, depletion and amortization		1,185			3,513			547			—			—			5,245
Dry hole cost		—			—			1,738			—			—			1,738
Impairment of oil and gas properties		110			—												110
General and administrative		5,206			941			468			20			45			6,680

Total costs and expenses		9,847			10,857			3,752			257			198			24,911

Operating income (loss)		(2,119	)		9,715			(935	)		(257	)		(198	)		6,206
Other income (expense)		395			(347	)		2,873			(33	)		1,139			4,027

Income (loss) before income taxes		(1,724	)		9,368			1,938			(290	)		941			10,233
Benefit (provision) for income taxes		992			77			(754	)		—			—			315

Income (loss) from continuing operations, net of tax	$	(732	)	$	9,445		$	1,184		$	(290	)	$	941		$	10,548

F-34


	United
	States			France			Turkey			Hungary			Romania		Total
	(In thousands)
Selected assets:
Oil and natural gas properties	$	21,110		$	83,627		$	51,724		$	9,728		$	7,431	$	173,620
Accumulated depreciation, depletion, and amortization		(8,099	)		(24,992	)		(2,146	)		(225	)		—		(35,462	)

Oil and natural gas properties, net	$	13,011		$	58,635		$	49,578		$	9,503		$	7,431	$	138,158

Investments in unconsolidated entities	$	2,251		$	—		$	—		$	—		$	—	$	2,251

Goodwill	$	—		$	3,276		$	919		$	—		$	—	$	4,195

Total assets	$	244,783		$	57,221		$	11,853		$	541		$	1,328	$	315,726

Expenditures for additions to long-lived assets:
Property acquisition costs	$	401		$	—		$	—		$	9,096		$	—	$	9,497
Development costs		1,306			19,065			27,900			—			7,114		55,385
Exploration costs		203			—			—			—			—		203
Other		192			111			236			279			—		818

Total expenditures for long-lived assets	$	2,102		$	19,176		$	28,136		$	9,375		$	7,114	$	65,903


	United
	States (1)			France			Turkey			Total

For the year ended December 31, 2004(restated)
Revenues:
Oil and natural gas sales	$	6,038		$	14,042		$	2,270		$	22,350
Loss on commodity derivatives		(1,322	)		—			—			(1,322	)

Total revenues		4,716			14,042			2,270			21,028
Costs and expenses:
Lease operating		1,751			4,885			763			7,399
Exploration Expenses		1,361			141			3,028			4,530
Depreciation, depletion and amortization		1,247			2,356			507			4,110
General and administrative		4,203			1,451			1,809			7,463

Total costs and expenses		8,562			8,833			6,107			23,502

Operating income (loss)		(3,846	)		5,209			(3,837	)		(2,474	)
Other income (expense)		(249	)		(386	)		(314	)		(949	)

Income (loss) before income taxes		(4,095	)		4,823			(4,151	)		(3,423	)
Benefit for income taxes		2,705			(1,552	)		—			1,153

Income (loss) from continuing operations, net of tax	$	(1,390	)	$	3,271		$	(4,151	)	$	(2,270	)

Selected assets:
Oil and natural gas properties	$	19,480		$	75,168		$	20,698		$	115,346
Accumulated depreciation, depletion, and amortization		(7,074	)		(24,454	)		(1,424	)		(32,952	)

Oil and natural gas properties, net	$	12,406		$	50,714		$	19,274		$	82,394

Investments in unconsolidated entities	$	1,466		$	—		$	—		$	1,466

Goodwill	$	—		$	5,060		$	919		$	5,979

Total assets	$	97,632		$	49,293		$	8,165		$	155,090

Expenditures for additions to long-lived assets:
Property acquisition costs	$	—		$	—		$	—		$	—
Development costs		360			6,260			1,437			8,057
Exploration costs		398			—			6,568			6,966
Other		121			11			230			362

Total expenditures for long-lived assets	$	879		$	6,271		$	8,235		$	15,385


(1)		Amounts reflect reclassifications to discontinued operations.

F-35


	United
	States (1)			France			Turkey			Total
	(In thousands)
For the year ended December 31, 2003 (restated)
Revenues:
Oil and natural gas sales	$	5,124		$	9,633		$	2,259		$	17,016
Loss on commodity derivatives		(302	)		(474	)		—			(776	)

Total revenues		4,822			9,159			2,259			16,240
Costs and expenses:
Lease operating		1,122			4,290			808			6,220
Exploration expenses		1,140			—			1,212			2,352
Depreciation, depletion and amortization		1,381			1,577			518			3,476
Impairment of oil and natural gas properties		171			—			—			171
General and administrative		1,930			810			1,017			3,757

Total costs and expenses		5,744			6,677			3,555			15,976

Operating income (loss)		(922	)		2,482			(1,296	)		264
Other income (expense)		(67	)		1,922			738			2,593

Income (loss) before income taxes		(989	)		4,404			(558	)		2,857
Benefit (provision) for income taxes		178			758			(333	)		603

Income (loss) from continuing operations, net of tax	$	(811	)	$	5,162		$	(891	)	$	3,460

Selected assets:
Oil and natural gas properties	$	39,250		$	63,200		$	10,702		$	113,152
Accumulated depreciation, depletion, and amortization		(12,713	)		(20,068	)		(1,154	)		(33,935	)

Oil and natural gas properties, net	$	26,537		$	43,132		$	9,548		$	79,217

Investments in unconsolidated entities	$	529		$	—		$	—		$	529

Goodwill	$	929		$	5,483		$	912		$	7,324

Total assets	$	88,929		$	39,179		$	8,114		$	136,222

Expenditures for additions to long-lived assets:
Property acquisition costs	$	—		$	—		$	—		$	—
Development costs		615			2,571			—			3,186
Exploration costs		—			—			1,256			1,256
Other		—			—			—			—

Total expenditures for long-lived assets	$	615		$	2,571		$	1,256		$	4,442


(1)		Amounts reflect reclassifications to discontinued operations.

F-36

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


	December 31,
	2005			2004
	(restated)
	(in thousands)
Total assets for reportable segments	$	315,726		$	155,090
Elimination of intersegment receivables and investments		(53,912	)		(53,912	)

Total consolidated assets	$	261,814		$	101,178

NOTE 18 — Subsequent Events

Insurance Claims

In 2005, two separate incidents occurred offshore Turkey in the Black Sea, which resulted in the loss of two caissons and three wells. Both of these incidents were insured under two “Construction and Risk,” or CAR policies, and two “Operator’s Extra Expense,” or OEE policies.

In October 2006, the underwriter of the CAR policies advised the Company that upon receipt of an executed “Receipt and Release” Agreement signed by all the named insured’s that they will pay in full and final settlement $8.8 million. The Company’s net share of these proceeds will be $3.2 million and will be recorded as a reduction to oil and natural gas properties. The Company will continue to pursue the remaining claims under the OEE policies.

Notice of Default

The Company delayed the filing of its Quarterly Report on Form 10-Q for the nine month period ended September 30, 2006. The delay in filing such Form 10-Q is due to the Company not completing its restated consolidated financial statements for the years ended December 31, 2003, 2004 and 2005 and its consolidated financial statements for each of the quarters ended March 31 and June 30, 2006, as described in Note 3.

As a result of this delay, a covenant default occurred under Section 4.03(b) of the Indenture, dated as of September 27, 2005 (the “Indenture”), between the Company and The Bank of New York Trust Company, N.A. (the “Trustee”), with respect to the Company’s 5.00% Convertible Senior Notes due 2025. Section 4.03(b) of the Indenture requires the Company to provide the Trustee with copies of the Company’s annual reports, information, documents and other reports that the Company is required to file with the Securities and Exchange Commission (the “SEC”) pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 within thirty (30) days of when such reports are required to be filed with the SEC.

On December 15, 2006, the Company received a notice from the Trustee under Section 4.03(b) of the Indenture for failing to provide the Trustee with a copy of its Quarterly Report on Form 10-Q for the nine month period ended September 30, 2006. Under Section 6.01(v) of the Indenture, this covenant default will not lead to an Event of Default unless the Company fails to cure the covenant default within thirty (30) days after receiving the written notice from the Trustee. The thirty (30) day period ends on January 14, 2007. The Company provided a copy of the complete Form 10-Q for the quarter ended September 30, 2006 to the Trustee in accordance with the requirements of the Indenture.

Under Section 6.02 of the Indenture, if an Event of Default occurs and is continuing, the Trustee by written notice to the Company, or the holders of at least twenty five percent (25%) in aggregate principal amount of the securities then outstanding by written notice to Toreador and the Trustee, may declare the principal of, and any premium and accrued and unpaid interest, if any, and any premium on, all securities

F-37

to be immediately due and payable. The notes outstanding have an aggregate principal amount of $86.25 million at January 14, 2007.

Pursuant to Section 19.1.1(b) of the Reserve Base Revolving Facility Agreement by and between Madison Energy France, Madison Oil France, Toreador, Madison Oil Company Europe, and Natixis Banques Populaires (“Natixis”), dated December 23, 2004 (the “Agreement”), Toreador was required to provide Natixis with its unaudited consolidated financial statements for the nine month period ended September 30, 2006 within forty-five (45) days after the end of such quarter. Natixis has waived such default and any other default under the Agreement as a result of the Company not yet providing such financial statements until January 16, 2007. Toreador had $11 million borrowed under the Agreement at January 14, 2007.

New Secured Revolving Facility

On December 28, 2006, the Company as a guarantor and its direct and indirect subsidiaries, Toreador Turkey Ltd., as a borrower and guarantor, Toreador Romania Ltd., as a borrower and a guarantor, Madison Oil France SAS , as a borrower and a guarantor, Toreador Energy France S.C.S., as a borrower and a guarantor, and Toreador International Holding L.L.C., entered into a Loan and Guarantee Agreement with International Finance Corporation. The Loan and Guarantee Agreement provides for the A Loan Facility which is a secured revolving facility with a current maximum facility amount of $25 million which maximum facility amount will increase to $40 million when the projected total borrowing base amount exceeds $50 million. As of January 14, 2007, the A Loan Facility has not closed at this time and is not yet available. The Loan and Guarantee Agreement also provides for a $10 million C Loan Facility to Toreador Turkey and Toreador Romania. As of January 14, 2007, the C Loan Facility has $10.0 million outstanding. Both the A Loan Facility and the C Loan Facility are to fund the borrowers’ operations in Turkey and Romania.

Interest will accrue on any loans under the A Loan Facility at a rate of 2% over the six month LIBOR rate. Interest accrues on the C Loan Facility at a rate of 1.5% over the six month LIBOR rate until any loans are made under the A Loan Facility after which the rate for the C Loan Facility shall be lowered to 0.5% over the six month LIBOR rate. As of January 14, 2007, the interest rate on the C Loan Facility is 6.86%. Interest is to be paid on each June 15 and December 15.

Nasdaq Violation

On November 14, 2006, Toreador received a Staff Determination Letter from the Nasdaq Stock Market that Toreador violated Nasdaq Marketplace Rule 4310(c)(14) by not timely filing the Form 10-Q for the quarter ended September 30, 2006 which is a requirement for continued listing. On January 11, 2007, Toreador had a hearing with the Nasdaq Listing Qualifications Panel regarding this violation. Toreador has not received the decision yet from the Nasdaq Listing Qualifications Panel regarding whether Toreador’s common stock will remain listed on the Nasdaq Stock Market.

NOTE 19 — SUPPLEMENTAL OIL AND NATURAL GAS RESERVES AND STANDARDIZED MEASURE INFORMATION (UNAUDITED)

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

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-38


	United
	States			France			Turkey			Romania		Total
	Natural Gas (MMcf)
PROVED RESERVES
December 31, 2002		12,121			—			—			—		12,121
Revisions of previous estimates		508			—			—			—		508
Extensions, discoveries and other additions		365			—			—			—		365
Sale of reserves		(401	)		—			—			—		(401	)
Production		(1,311	)		—			—			—		(1,311	)

December 31, 2003 (Restated)		11,282			—			—			—		11,282
Revisions of previous estimates		(574	)		—			—			—		(574	)
Extensions, discoveries and other additions		143			—			—			—		143
Sale of reserves		(5,400	)		—			—			—		(5,400	)
Production		(518	)		—			—			—		(518	)

December 31, 2004 (Restated)		4,933			—			—			—		4,933
Revisions of previous estimates		641			—			—			—		641
Extensions, discoveries and other additions		227			—			6,476			3,486		10,189
Sale of reserves		—			—			—			—		—
Production		(506	)		—			—			—		(506	)

December 31, 2005 (Restated)		5,295			—			6,476			3,486		15,257


PROVED DEVELOPED
December 31, 2003		11,158			—			—			—		11,158

December 31, 2004		4,875			—			—			—		4,875

December 31, 2005 (Restated)		5,225			—			—			3,486		8,711


	Oil (MBbl)

PROVED RESERVES
December 31, 2002		1,887			11,243			972			—		14,102
Revisions of previous estimates		153			160			23			—		336
Extensions, discoveries and other additions		11			—			—			—		11
Sale of reserves		(3	)		—			—			—		(3	)
Production		(210	)		(428	)		(103	)		—		(741	)

December 31, 2003 (Restated)		1,838			10,975			892			—		13,705
Revisions of previous estimates		114			956			(190	)		—		880
Extensions, discoveries and other additions		—			—			—			—		—
Sale of reserves		(1,103	)		—			—			—		(1,103	)
Production		(69	)		(395	)		(75	)		—		(539	)

December 31, 2004 (Restated)		780			11,536			627			—		12,943
Revisions of previous estimates		73			(587	)		77			—		(437	)
Extensions, discoveries and other additions		—			477			—			24		501
Sale of reserves		—			—			—			—		—
Production		(60	)		(448	)		(65	)		—		(573	)

December 31, 2005 (Restated)		793			10,978			639			24		12,434


PROVED DEVELOPED
December 31, 2003		1,709			6,571			583			—		8,863

December 31, 2004		775			7,309			360			—		8,444

December 31, 2005		792			7,688			378			24		8,882

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


	United
	States		France		Turkey		Romania		Total
	(In thousands)
As of and for the year ended December 31, 2003 (Restated)
Future cash inflows	$	121,802	$	303,691	$	23,412	$	—	$	448,905
Future production costs		28,173		141,351		8,735		—		178,259
Future development costs		352		17,443		1,960		—		19,755
Future income tax expense		29,610		46,647		3,494		—		79,751

Future net cash flows		63,667		98,250		9,223		—		171,140
10% annual discount for estimated timing of cash flows		29,347		59,159		3,325		—		91,831

Standardized measure of discounted future net cash flows related to proved reserves	$	34,320	$	39,091	$	5,898	$	—	$	79,309


As of and for the year ended December 31, 2004 (Restated)
Future cash inflows	$	62,256	$	432,828	$	20,919	$	—	$	516,003
Future production costs		25,432		182,574		7,861		—		215,867
Future development costs		164		25,902		1,470		—		27,536
Future income tax expense (benefit)		10,803		71,504		(703)		—		81,604

Future net cash flows		25,857		152,848		12,291		—		190,996
10% annual discount for estimated timing of cash flows		11,951		98,248		4,065		—		114,264

Standardized measure of discounted future net cash flows related to proved reserves	$	13,906	$	54,600	$	8,226	$	—	$	76,732


As of and for the year ended December 31, 2005 (Restated)
Future cash inflows	$	95,502	$	621,765	$	70,498	$	18,574	$	806,339
Future production costs		34,190		223,273		15,267		4,588		277,318
Future development costs		319		30,883		22,317		552		54,071
Future income tax expense		19,780		113,742		2,736		961		137,219

Future net cash flows		41,213		253,867		30,178		12,473		337,731
10% annual discount for estimated timing of cash flows		20,180		144,738		14,390		1,798		181,106

Standardized measure of discounted future net cash flows related to proved reserves	$	21,033	$	109,129	$	15,788	$	10,675	$	156,625

F-40

The prices of oil and natural gas at December 31, 2005, 2004, and 2003 used in the above table, were $56.24, $37.55 and $27.87 per Bbl of oil, respectively, and $6.98, $5.99 and $5.90 per Mcf of natural gas, respectively.

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


	United
	States			France			Turkey			Romania			Total
	(In thousands)
Balance at December 31, 2002	$	34,618		$	52,844		$	7,583		$	—		$	95,045
Sales of oil and natural gas, net		(10,636	)		(5,343	)		(1,430	)		—			(17,409	)
Net changes in prices and production costs		7,978			(13,108	)		(1,718	)		—			(6,848	)
Extensions and discoveries		981			—			—			—			981
Revisions of previous quantity estimates		3,209			847			212			—			4,268
Net change in income taxes		(4,641	)		2,031			1,412			—			(1,198	)
Accretion of discount		3,462			5,284			758			—			9,504
Sales of reserves		(61	)		—			—			—			(61	)
Other		(590	)		(3,464	)		(919	)		—			(4,973	)

Balance at December 31, 2003 (Restated)		34,320			39,091			5,898			—			79,309
Sales of oil and natural gas, net		(4,287	)		(9,157	)		(1,507	)		—			(14,951	)
Net changes in prices and production costs		(4,264	)		28,408			2,450			—			26,594
Net change in future development costs		77			(4,962	)		61			—			(4,824	)
Extensions and discoveries		309			—			—			—			309
Revisions of previous quantity estimates		229			8,065			(2,712	)		—			5,582
Previously estimated development costs incurred		(45	)		(4,296	)		(401	)		—			(4,742	)
Net change in income taxes		9,947			(14,114	)		2,516			—			(1,651	)
Accretion of discount		4,321			6,019			761			—			11,101
Sales of reserves		(25,020	)		—			—			—			(25,020	)
Other		(1,681	)		5,546			1,160			—			5,025

Balance at December 31, 2004 (Restated)		13,906			54,600			8,226			—			76,732
Sales of oil and natural gas, net		(5,371	)		(15,180	)		(2,107	)		—			(22,658	)
Net changes in prices and production costs		10,187			72,285			3,463			—			85,935
Net change in development costs		(119	)		(2,223	)		(11,356	)		(472	)		(14,170	)
Extensions and discoveries		725			7,723			18,906			11,963			39,317
Revisions of previous quantity estimates		3,353			(9,507	)		1,347			—			(4,807	)
Previously estimated development costs incurred		(77	)		—			—			—			(77	)
Net change in income taxes		(4,250	)		(22,271	)		(2,422	)		814			(28,129	)
Accretion of discount		149			8,187			815			—			9,151
Other		2,530			15,515			(1,084	)		(1,629	)		15,332

Balance at December 31, 2005 (Restated)	$	21,033		$	109,129		$	15,788		$	10,676		$	156,626

F-41

Toreador Resources (TRGL) Inactive 10-K/A2005 FY Annual report (amended)