Toreador Resources 10K/A 2006 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: December 31, 2006


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

COMMISSION FILE NUMBER: 0-02517

Toreador Resources Corporation

(Exact name of Registrant as specified in its charter)


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

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

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

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


Title of each Class:		Name of each exchange on which registered:

COMMON STOCK, PAR VALUE $.15625 PER SHARE		NASDAQ GLOBAL MARKET

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yeso Noþ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yeso Noþ

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. Yesþ Noo

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 filero

Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Exchange Act). Yeso Noþ

The aggregate market value of the voting and non-voting common equity of the registrant held by non-affiliates, computed by reference to the closing sales price of such stock, as of June 30, 2006 was $317,007,097. (For purposes of determination of the aggregate market value, only directors, executive officers and 10% or greater stockholders have been deemed affiliates.)

The number of shares outstanding of the registrant’s common stock, par value $.15625, as of July 20, 2007 was 19,387,126 shares.

DOCUMENTS INCORPORATED BY REFERENCE

None

TABLE OF CONTENTS

Explanatory Note about the Report


	Page
PART I

Item 1 and 2. Business and Properties		1

Item 1A. Risk Factors		18

PART II

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations		27

Item 8. Financial Statements and Supplementary Data		42

Item 9A. Controls and Procedures		42

PART IV

Item 15. Exhibits and Financial Statement Schedules		45

SIGNATURES		45
Legal Opinion of Gunel & Kaya
Consent of Grant Thornton LLP
Consent of LaRoche Petroleum Consultants, Ltd.
Certification Pursuant to Section 302
Certification Pursuant to Section 302
Certification Pursuant to Section 906
French Ministry Documentation
Hungarian Mining Law Summary
Portions of Hungarian Mining Act
Portions of Governmental Decree Implementing the Hungarian Mining Act

Explanatory Note about the Report

This Form 10-K/A of Toreador Resources Corporation (“Toreador,” “we,” “us,” “our” or the “Company”) amends and restates only Items 1 and 2 and 1A of Part I, Items 7, 8 and 9A of Part II and Item 15 of Part IV of the 10-K for the year ended December 31, 2006. Items 1 and 2 have been amended and restated to reflect that the name of the exploration block in Hungary on which we have proved reserves is the Tompa exploration block and not the Szolnok exploration block and to reflect additional information regarding title to our properties in Turkey, Hungary and France. Item 1A has been amended and restated to add additional information regarding the risk of our proved reserves being lessened if we cannot extend or convert certain of our foreign permits. Item 7 has been amended and restated (i) to add the section “Revenue Recognition,” to explain that the amount of any gas imbalances resulting from us not recording sales on the entitlement method is insignificant; (ii) to add under “Successful Efforts Method of Accounting” a description of exploratory costs that have been capitalized for a period greater than one year; (iii) to provide additional information under “Reserve Estimates” to set forth the facts and the specific revisions related to such facts that resulted in the upward reserve revision for the year ended December 31, 2004 and the downward reserve revisions for the years ended December 31, 2005 and 2006; and (iv) to explain under “Comparison of Years Ended December 31, 2006 and 2005 — Discontinued Operations” the reasons we received certain revenues and incurred certain expenses after the effective date of the asset sale described therein. Item 8 has been amended and restated to correct certain Edgar transmission errors that occurred in the financial statements regarding 2004 Net cash provided by (used in) financing activities in the Consolidated Statements of Cash Flows and 2005 Gross Deferred Tax Liabilities in Note 10 — Income Taxes. Item 9A has been amended and restated to correct certain cross-references and reflect the examination of the disclosure controls and procedures and internal control over financial reporting as of December 31, 2006 by our Chief Executive Officer and our Vice President — Finance and Accounting and Chief Accounting Officer who is now our principal financial officer since the departure of our Chief Financial Officer effective June 1, 2007. Except for the foregoing amended information, this Form 10-K/A continues to describe the conditions as of the date of the original Form 10-K for the year ended December 31, 2006, and we have 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 filing, 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, including any amendment to those filings. In addition, pursuant to the rules of the Securities and Exchange Commission, Exhibit 31.1, 31.2, 31.3 and 32.1 of the original Form 10-K have been amended and new Exhibits 31.1, 31.2 and 32.1 are filed herewith to contain currently dated certifications from our Chief Executive Officer and our Vice President — Finance & Accounting and Chief Accounting Officer.

PART I

Items 1 and 2. Business and Properties

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

We currently hold interests in permits granting us the right to explore and develop oil and natural gas properties in offshore and onshore Turkey, Hungary, Romania and France. We also own various non-operating working interest properties primarily in Texas, Kansas, New Mexico, Louisiana and Oklahoma. At December 31, 2006, we held interests in approximately 5.5 million gross acres and approximately 4.2 million net acres, of which 94.4% is undeveloped. At December 31, 2006, our estimated net proved reserves were 16 million barrels of oil equivalent (MMBOE).

Historically, our operations have been concentrated in the Paris Basin in France and in south central onshore Turkey and offshore Turkey in the Black Sea. These two regions accounted for 86.9% of our total proved reserves as of December 31, 2006 and approximately 69% of our total production for the year ended December 31, 2006.

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

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

Recent Developments

New Secured Revolving Facility

On December 28, 2006, we entered into a loan and guarantee agreement with International Finance Corporation for our operations in Turkey and Romania. The loan and guarantee agreement provides for two separate facilities, the first of which (the “$10 million facility”) is unsecured and was fully funded on December 28, 2006. The second facility (the “$25 million facility”) is a secured revolving facility which was fully funded on March 2, 2007. The $25 million facility has a current maximum facility amount of $25 million which maximum facility amount will increase to $40 million when the projected total borrowing base amount exceeds $50 million.

Change in President and Chief Executive Officer

In January 2007, Mr. G. Thomas Graves III resigned as President and Chief Executive Officer. Following Mr. Graves’ resignation, the Board of Directors elected Mr. Nigel J. B. Lovett to the position of President and Chief Executive Officer. Mr. Lovett has been a member of our Board of Directors since January 2006 and prior to becoming our President and Chief Executive Officer had more than 26 years experience as an investment banker.

Update on current operations

Turkey

Two new gas discoveries, the Guluc-1 well, flowed approximately 17 million cubic feet of gas per day through a 48/64-inch choke at a flowing pressure of approximately 1,180 psi. and the Alapli-1 well tested approximately 6.8 million cubic feet of gas per day through a 32/64-inch choke at a flowing pressure of 1,064 psi.

The topsides for the Akkaya production tripod have been set and secured. The next step is to tie the three Akkaya wells into the production manifold and then tie in the offshore pipeline. Once this process is complete, the wells will be ready to be put on production.

The topsides for the Dogu Ayazli tripod are on location, waiting for seas to moderate before attempting to lift the structure onto the tripod.

France

The St. Loup D’Ordon-1 exploration well was drilled to test a Neocomian channel sand to the northeast of Toreador’s Neocomian Field Complex in the Paris Basin. The well did not encounter commercial hydrocarbons and has been plugged and abandoned.

Romania

The Naeni-6 well is drilling ahead at approximately 1,460 meters depth after intermediate casing was set and is expected to reach total depth in late March 2006. A rig has been moved onto the Lapos-2 exploration well location and will spud as soon as the necessary permits are granted.

Strategy

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

We seek to:

Target under-explored basins in international regions.

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

Maintain a deep inventory of drilling prospects.

Our South Akcakoca sub-basin gas project is located on approximately 50,000 acres within our approximately 962,000 acre Western Black Sea permits. It is the only area we have explored within these permits and we believe there are significant additional drilling opportunities within and outside of the South Akcakoca sub-basin. Similarly, we believe our Hungarian and Romanian positions offer multi-year drilling opportunities.

Pursue new permits and selective property acquisitions.

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

Manage our risk exposure.

Because exploration projects have a higher degree of risk than development projects, we generally plan to limit our exploratory expenditures to approximately one-half of the total annual capital expenditure budget per year. We have balanced our exploration and development activities to support our overall goal of growing and maintaining a long-lived reserve base. We also expect to make significant investments in seismic data. By equipping our geologists and geophysicists with state-of-the-art seismic information, we intend to increase the number of higher

potential prospects we drill. As deemed appropriate, we may enter into joint ventures in order to reduce our risk exposure in exchange for a portion of our interests.

Maintain operational flexibility.

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

Leverage experienced management, local expertise and technical knowledge.

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

Turkey

We established our initial position in Turkey at the end of 2001 through the acquisition of Madison Oil Company. In Turkey, we currently hold interests in 31 exploration and three exploitation permits covering approximately 2.5 million net acres. Our exploration and development program focuses on the following areas:

Western Black Sea Permits

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

South Akcakoca Sub-Basin

The South Akcakoca sub-basin is an area of approximately 50,000 acres located in the Western Black Sea, offshore Turkey. We discovered gas in September 2004 with the Ayazli-1 well and since that time have drilled ten successful delineation wells, The Cayagzi-1 and Kuzey Akkaya-1 delineation wells were drilled to total depth and did not encounter hydrocarbons, and were plugged and abandoned. We have drilled seven development wells, Dogu Ayazlý-1, Akkaya-2, Dogu Ayazlý-2, Akkaya-3, Bayhanlý-1, Akcakoca-3 and Akcakoca-4 in 2006, two of which required a floating rig, and completed the first phase of pipeline and facility construction with production to begin in March or April of 2007. The first phase of infrastructure development includes: setting up three production platforms; laying two sub sea pipelines; constructing the onshore processing facility for the entire sub-basin development; and constructing the onshore pipeline to tie into the national pipeline operated by the Turkish national gas utility.

Eregli Sub-Basin

The Eregli sub-basin is an area of approximately 75,000 acres located in the Western Black Sea, offshore Turkey. We plan to shoot approximately 325 km. high resolution 2D marine seismic survey on the permit in preparation for an exploration program, which we expect to commence in mid-2007. In February 2007 we spudded the Alapli # 1 well.

Thrace Black Sea Permits

The Thrace Black Sea permits are located offshore Turkey in the Black Sea between Bulgarian waters and the Bosporus Straits. We are the operator and hold a 50% working interest in the permit covering 422,000 net acres. In June 2005, HEMA Endustri A.S., a Turkish-based conglomerate, agreed to pay 100% of the first $1.5 million of the geophysical and exploration costs on this acreage in exchange for an option for a 50% interest in this permit. In 2006, we completed approximately 1500 km. 2D marine seismic program and we are currently evaluating the seismic to pick the first drilling location. The first two wells on the Thrace Black Sea permits will be drilled in 2007.

Central Black Sea Permit

In January 2005, the Turkish government awarded us two additional Black Sea permits located in shallow waters offshore central Turkey comprising approximately 233,000 acres. We intend to acquire 240 km. of 2D marine seismic survey in 2007, and we will then conduct a full analysis of existing technical data on these two permits in which we hold a 100% working interest.

Eastern Black Sea Permit

We have an exploration permit on three blocks in the Black Sea offshore Turkey in the coastal waters to the west northwest of the city of Trabzon. The three blocks total approximately 357,062 acres. We are the operator of and hold 100% working interest in this permit. In early 2007, we completed approximately 90 km. of total 230 km. 2D marine seismic program in 2006. The rest of the program will be completed in mid-2007.

Buyukdag Permit

The Buyukdag permits cover approximately 39,450 acres located in Eastern Turkey in which we hold 100% working interest. We have already initiated re-processing of existing 2D seismic data in the permit area and plan to acquire approximately 300 km. 2D onshore seismic survey in 2007.

Southeast Turkey Permits

Bakuk

Onshore in southeast Turkey, at the Syrian border, we were recently granted an exploration permit on one block of approximately 95,897 acres. The block is west of some existing oil and gas fields. We are operator of and hold 100% working interest in this permit. We are reprocessing all 2D seismic data which were acquired by the previous operator prior to drilling an exploration well in the permit area.

Van

The Van permit area is surrounded by the most prolific oil fields in southeast Turkey and it covers approximately 965,000 acres. We are currently gathering geological and geophysical data to define prospective structures. We are the operator of and hold a 100% working interest in this permit.

Hungary

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

Szolnok Block

Two gas wells were drilled by the previous operator in the Szolnok Block, each of which initially tested at over 4 Mmcf per day. We expect to construct a gas processing facility and tie-in pipeline for such wells in 2007, once a gas contract has been concluded. A review of the extensive 2D and 3D seismic surveys, conducted by the prior owner, delineated multiple prospects of which one was drilled in June of 2006. This well was a geophysical and geological success however the inert content exceeded the economic threshold and, therefore, the well was subsequently plugged and abandoned.

The necessary permits and drilling applications are currently being prepared which should enable the drilling of several additional prospects, each of which is testing a variety of features and concepts – stratigraphic and structural in nature.

Tompa Block

Three exploratory wells and two re-entries were undertaken in the southern Tompa Block prospect. The exploration wells failed to encounter commercial hydrocarbons, however; the data and knowledge gained in the exploration process have escalated several leads to the prospect category. The necessary applications are also being prepared which should enable these prospects to be drilled in the late 2007 or early 2008 timeframe.

Plans to tie-in the two completed re-entry wells are progressing and first production from the Tompa Block is expected in early 2008. Negotiations for the oil and gas sale contract are well advanced.

Romania

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

Viperesti Permit

We currently are the operator and hold 100% of this exploration permit, covering approximately 324,000 acres. In December 2006, we spudded the first exploratory well on this prospect the Naeni # 2 bis and in January the well was plugged and abandoned. In February 2007, we spudded the second well the Naeni # 6, the results should be known by the end of the first quarter.

Moinesti Permit

We are the operator and hold 100% of this exploration permit, covering approximately 300,000 acres.

Fauresti Rehabilitation Permit

We are the operator and hold 100% of this rehabilitation permit. During 2006 we completed the production facility and are currently producing approximately 3.2 MMCFD and 50 BBLS of condensate per day.

France

We established our initial position in France at the end of 2001 through the acquisition of Madison Oil Company. We hold interests in permits covering five producing oil fields in the Paris Basin on approximately 24,200 net acres as well as three exploration permits covering approximately 232,200 net acres.

Charmottes Field

We hold a 100% working interest and operate the permit covering the Charmottes Field, which currently has 9 producing oil wells. The field is produced from two separate reservoirs, one at 1500 meters (4,500 feet) in the fractured limestone of the Dogger and the second one from the Triassic sandstones at 2500 meters (7,500 feet) in the Donnemarie formation. Production is approximately 200 BOPD from both reservoirs

Neocomian Complex

Pursuant to two exploitation permits, we operate and hold a 100% working interest in the permits covering the Neocomian Fields, that is comprised of a group of four oil fields. The complex currently has 86 producing oil wells and production is approximately 920 BOPD.

Courtenay Permit

We hold a 100% working interest and are the operator of this permit covering approximately 183,000 net acres which surrounds the Neocomian Fields. An exploration well was drilled was February 2007 and was plugged and abandoned.

Nemours Permit

We hold a 33¹/₂% working interest in this permit covering approximately 15,700 net acres which is operated by Lundin Petroleum AB.

Aufferville Permit

We hold a 100% working interest and operate this permit covering approximately 33,100 acres. Two exploration wells will be drilled in April 2007 on the Dogger limestone objective to test two distinct prospects.

United States

We hold non-operating working interests in 990 gross wells (52 net wells) primarily in Texas, Oklahoma, New Mexico, Kansas and Louisiana.

Title to Oil and Natural Gas Properties

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

Turkey

We have 31 exploration permits covering seven geographic regions. The Western Black Sea permits have been extended through November 2007 and prior to the date of expiration we expect to have completed our minimum work commitment to extend these permits for an additional three to four years. The Southeast Turkey and the Eastern Black Sea permits expire in September 2009, the Thrace Black Sea and the Central Black Sea permits expire in the first quarter of 2009 and the Van and Buyukbey permits expire in May and July 2010, respectively.

Onshore exploration permits are granted for four-year terms and may be extended for two additional two-year terms, and offshore exploration permits are granted for six-year terms and may be extended for two additional three-year terms, provided that drilling obligations stipulated under Turkish law are satisfied. Under Turkish law, exploitation permits are generally granted for a period of 20 years and may be renewed upon application for two additional 10-year periods. If an exploration permit is extended for development as an exploitation permit, the period of the exploration permit is counted toward the 20-year exploitation permit. In the opinion of Toreador’s Turkish counsel, Gunel & Kaya, a holder of an exploration permit that has had a discovery made on such exploration permit area and who applies for an exploitation permit in accordance with Turkish petroleum law shall be granted an exploitation permit for any area or areas covered by the exploration permit upto one-half of the exploration permit area. Therefore, in the opinion of Gunel & Kaya, upon application for an exploitation permit, the exploration permit covering the area of the South Akcakoca Sub-Basin in which the gas discovery was made will be converted into an exploitation permit with an initial period of 20 years.

In addition, the Zeynel and Cendere exploitation permits are in their initial 20 year period and are eligible for renewal for up to two periods of 10 years each. In the opinion of Gunel & Kaya, renewal applications for exploitation permits will be granted to those holders who have production of economical quantities of petroleum and comply fully with the obligations under the Turkish petroleum law. There is a long and clear track record of extending exploitation permits as since 1998, there have been at least 48 renewals of exploitation permits, with a majority of those renewals occurring since 2001, and as of July 9, 2007, an application for renewal of an exploitation permit has never been denied and at least 69 conversions of exploration permits to exploitation permits have been granted and as of July 9, 2007, an application for conversion of an exploration permit to an exploitation permit has never been denied. However, there can be no assurance that our exploration permit will be converted into an exploitation permit or that our exploitation permits will be renewed.

Our Turkish proved reserves are:


				At December 31, 2006
	Permit							Post-Expiration Proved				Percent of Proved
	Expiration			Total Proved Reserves				Reserves				Reserves
Property	Year			(MBbl)		(MMCF)		(MBbl)		(MMCF)		Post-Expiration
Zeynel		2013	(1)		37				18				48.65	%
Cendere (2 permits)		2012	(1)		628				223				35.50	%
S Akcakoca Sub-Basin		2007	(2)				21,425				21,425		100.00	%


(1)		Exploitation Permit

(2)		Exploration Permit

Hungary

We have two exploration permits that expire in March 2009. In 2006, we re-completed one well that was drilled by the previous operator on the Tompa exploration permit. We are currently in the process of connecting the well to the sales pipeline.

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

There is a long and clear track record of exploration permits being converted into mining plot designations. Based on research on the MBFH (Hungarian Office of Mining and Geology) website, since 1991 when MOL (MOL Hungarian Oil and Gas Public Limited Company), formerly the Hungarian state oil company, became a private company, there have been at least 72 mining plots granted. Based on conversations with representatives of the MBFH (Hungarian Office of Mining and Geology), since 1991 when MOL became a private company, there have not been any mining plot applications denied. However, there can be no assurance that we will be able to convert our exploration permit into a mining plot designation.

Our Hungarian proved reserves are:

At December 31, 2006

Permit

Post-Expiration Proved

Percent of Proved

Expiration

Total Proved Reserves

Reserves

Property

Year

(MBbl)

(MMCF)

(MBbl)

(MMCF)

Post-Expiration

Tompa

2009

950

—

542

57.05

Romania

The Moinesti and Viperesti permits will expire in 2009 and the Fauresti rehabilitation permit will expire in 2015. If, prior to the expiration of our Romanian permits, we have not completed the minimum exploration program required by the permits, we must pay the estimated costs of such exploration program to the Romanian government. If we were required to make such payments to the Romanian government, we estimate that the aggregate amount would be less than $8 million and as of December 31, 2006 we have spent $7.3 million. We have not yet established proved reserves on the Moinesti and Viperesti permits.

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

At December 31, 2006

Permit Expiration

Oil

Gas

Property

Year

(MBbl)

(MMcf)

Fauresti

2015

3,041

France

We hold three French exploration permits: Aufferville, Nemours and Courtenay. No proved reserves have been established in these permits. The Courtenay, Aufferville and Nemours permits expire in 2007, however due to drilling that has been completed or is planned for 2007 we anticipate that we will fulfill our minimum work commitment and anticipate that the permits will automatically be extended for a period of three to four years. The French exploration permits have minimum financial requirements that we expect to meet during their terms. If such obligations are not met, the permits could be subject to forfeiture.

Under French mining law, exploitation permits can be extended by successive prolongations, with each prolongation not to exceed 25 years and such extensions are not subject to competitive bidding or public inquiry. Although the French government has no obligation to renew exploitation permits, based on conversations with the French mining authority, we believe it will renew such exploitation permits so long as we, the permit holder, demonstrate financial and technical capabilities and establish the studies used in defining the work schedule.

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

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


			At December 31, 2006
			Total Proved		Post-Expiration		Percent of Proved
	Permit Expiration		Reserves		Proved Reserves		Reserves
Property	Year		(MBbl)		(MBbl)		Post-Expiration
Neocomian Fields		2011		8,064		5,854		72.60	%
Charmottes Field		2013		1,564		640		40.92	%

United States

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

Oil and Natural Gas Reserves

The following table sets forth information about our estimated net proved reserves at December 31, 2006 and 2005. LaRoche Petroleum Consultants, Ltd., an independent petroleum engineering firm in Dallas, Texas, prepared the estimates of proved developed reserves, proved undeveloped reserves and discounted present value (pretax). We prepared the estimate of standardized measure of proved reserves in accordance with Financial Accounting Standards Board Statement of Financial Accounting Standards No. 69,Disclosures about Oil and Gas Producing Activities. No reserve reports have been provided to any governmental agencies.


	December 31,
	2006		2005
U.S.
Proved developed:
Oil (MBbl)		699		792
Gas (MMcf)		4,068		5,225
Total (MBOE)		1,377		1,663
Proved undeveloped:
Oil (MBbl)		1		1
Gas (MMcf)		60		70
Total (MBOE)		11		12
Discounted present value at 10% (pretax) (in thousands) (1)	$	19,324	$	31,299
Standardized measure of proved reserves (in thousands)	$	13,264	$	21,033

FRANCE
Proved developed:
Oil (MBbl)		6,770		7,688
Proved undeveloped:
Oil (MBbl)		2,858		3,290
Discounted present value at 10% (pretax) (in thousands) (1)	$	131,824	$	164,075
Standardized measure of proved reserves (in thousands)	$	86,190	$	109,129

TURKEY
Proved developed:
Oil (MBbl)		405		378
Proved undeveloped:
Oil (MBbl)		260		261
Gas (MMcf)		21,425		6,476
Total (MBOE)		3,831		1,340
Discounted present value at 10% (pretax) (in thousands) (1)	$	89,913	$	17,930
Standardized measure of proved reserves (in thousands)	$	84,3330	$	15,788

ROMANIA
Proved developed:
Oil (MBbl)		41		24
Gas (MMcf)		3,040		3,486
Total (MBOE)		548		605
Discounted present value at 10% (pretax) (in thousands) (1)	$	12,941	$	11,490
Standardized measure of proved reserves (in thousands)	$	13,388	$	10,676

HUNGARY
Proved developed:
Oil (MBbl)		1		—
Gas (MMcf)		950		—
Total (MBOE)		159		—
Discounted present value at 10% (pretax) (in thousands) (1)	$	2,625	$	—
Standardized measure of proved reserves (in thousands)	$	970	$	—

COMBINED
Proved developed:
Oil (MBbl)		7,916		8,882
Gas (MMcf)		8,058		8,711
Total (MBOE)		9,259		10,334
Proved undeveloped:
Oil (MBbl)		3,119		3,552
Gas (MMcf)		21,485		6,546
Total (MBOE)		6,700		4,643
Total proved:
Oil (MBbl)		11,035		12,434
Gas (MMcf)		29,543		15,257
Total (MBOE)		15,959		14,977
Discounted present value at 10% (pretax) (in thousands) (1)	$	256,627	$	224,795
Standardized measure of proved reserves (in thousands)	$	198,142	$	156,626


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

Reserves were estimated using oil and natural gas prices and production and development costs in effect on December 31, 2006 and 2005, without escalation. The reserves were determined using both volumetric and production performance methods. Proved reserves are those estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.THE VALUES REPORTED MAY NOT NECESSARILY REFLECT THE FAIR MARKET VALUE OF THE RESERVES.

Productive Wells

The following table shows our gross and net interests in productive oil and natural gas wells as of December 31, 2006. Productive wells include wells currently producing or capable of production.


	Gross (1)						Net (2)
	Oil		Gas		Total		Oil		Gas		Total
United States		682		308		990		21.04		31.35		52.39
France		131		—		131		130.50		—		130.50
Turkey		15		—		15		2.65		—		2.65
Romania		—		5		5		—		5.00		5.00


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

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

Acreage

The following table shows the developed and undeveloped acreage attributable to our ownership as of December 31, 2006.


	Developed Acreage				Undeveloped Acreage				Total Acreage
	Gross		Net		Gross		Net		Gross		Net
United States		254,140		37,503		86,893		39,509		341,033		77,012
France		24,260		24,260		263,730		232,215		287,990		256,475
Turkey		31,730		3,059		3,495,684		2,465,331		3,527,414		2,468,390
Romania		—		—		625,325		625,325		625,325		625,325
Hungary		—		—		764,237		764,237		764,237		764,237

Total		310,130		64,822		5,235,869		4,126,617		5,545,999		4,201,439

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

Drilling Activity

The following table shows our drilling activities on a gross and net basis for the years ended 2006, 2005 and 2004.


	Year ended December 31,
	2006				2005				2004
	Gross (1)		Net (2)		Gross (1)		Net (2)		Gross (1)		Net (2)
UNITED STATES
Development:			��
Gas (3)		12		0.14		7		0.08		3		0.75
Oil (4)		36		0.15		20		0.04		4		0.20
Abandoned (5)		—		—		2		0.26		—		—

Total		48		0.29		29		0.38		7		0.95


Exploratory
Gas (3)		5		0.35		1		0.25		—		—
Oil (4)		—		—		2		0.45		—		—
Abandoned (5)		8		0.99		—		—		3		0.50

Total		13		1.34		3		0.70		3		0.50


FRANCE
Development:
Oil (4)		—		—		5		5.00		7		7.00
Abandoned (5)		—		—		—		—		—		—

Total		—		—		5		5.00		7		7.00


Exploratory:
Oil (4)		—		—		1		0.50		—		—
Abandoned (5)		—		—		—		—		—		—

Total		—				1		0.50		—		—


TURKEY
Development:
Gas (3)		7		2.57		4		1.80		—		—
Abandoned (5)		2		0.56		1		0.40		—		—

Total		9		3.13		5		2.20		—		—


Exploratory
Oil (6)		—		—		—		—		1		0.75
Gas (7)		—		—		—		—		1		0.40

Abandoned (5)		—		—		—		—		—		—

Total		—		—		—		—		2		1.15


HUNGARY
Exploratory
Abandoned (5)		1		1.00		—		—		—		—


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

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

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

(4)		“Oil” means producing oil wells.

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

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

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

Net Production, Unit Prices And Costs

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


	United
	States		France		Turkey		Romania		Total
Year Ended December 31, 2006
Production:
Oil (Bbls)		58,449		441,759		68,342		7,728		576,278
Daily average (Bbls/Day)		160		1,210		187		21		1,578
Gas (Mcf)		489,793		—		—		502,192		991,985
Daily average (Mcf/Day)		1,342		—		—		1,376		2,718
Daily average (BOE/Day)		384		1,210		199		250		2,043
Unit prices:
Average oil price ($/Bbl)	$	61.29	$	61.74	$	56.10	$	52.71	$	60.90
Average gas price ($/Mcf)		6.38		—		—		3.57		4.96
Average equivalent price ($/BOE)		47.88		61.74		56.10		24.06		53.96
Unit costs ($/BOE):
Lease operating	$	15.71	$	16.36	$	11.60	$	7.86	$	14.75
Exploration and acquisition		13.44		0.98		11.69		7.09		5.32
Depreciation, depletion and amortization		10.92		7.06		10.94		22.85		10.17
Dry hole cost and impairment of oil and gas properties		12.40		—		—		—		4.65
General and administrative		43.15		4.31		11.81		6.09		13.25

Total	$	95.62	$	28.71	$	46.04	$	43.89	$	48.14

Year Ended December 31, 2005
Production:
Oil (Bbls)		60,433		403,991		64,792		—		529,216
Daily average (Bbls/Day)		165		1,107		178		—		1,450
Gas (Mcf)		569,566		—		—		—		569,566
Daily average (Mcf/Day)		1,560		—		—		—		1,560
Daily average (BOE/Day)		425		1,107		178		—		1,710
Unit prices:
Average oil price ($/Bbl)	$	52.37	$	50.92	$	43.48	$	—	$	50.17
Average gas price ($/Mcf)		7.56		—		—		—		7.56
Average equivalent price ($/BOE)		48.08		50.92		43.48		—		49.86
Unit costs ($/BOE):
Lease operating	$	13.49	$	13.34	$	10.96	$	—	$	13.13
Exploration and acquisition		8.05		2.50		4.46		—		4.71
Depreciation, depletion and amortization		7.63		8.70		8.44		—		8.40
Dry hole cost		—		—		26.84		—		2.79
General and administrative		33.51		2.33		7.22		—		10.70

Total	$	62.68	$	26.87	$	54.92	$	—	$	39.73

Year Ended December 31, 2004
Production:
Oil (Bbls)		68,129		396,806		73,118		—		538,053
Daily average (Bbls/Day)		187		1,087		200		—		1,474
Gas (Mcf)		546,118		—		—		—		546,118
Daily average (Mcf/Day)		1,496		—		—		—		1,496
Daily average (BOE/Day)		436		1,087		200		—		1,723
Unit prices:
Average oil price ($/Bbl)	$	38.87	$	35.39	$	31.05	$	—	$	35.24
Average gas price ($/Mcf)		5.81		—		—		—		5.81
Average equivalent price ($/BOE)		35.44		35.39		31.05		—		34.90
Unit costs ($/BOE):
Lease operating	$	11.00	$	12.31	$	10.44	$	—	$	11.76
Exploration and acquisition		8.55		0.36		41.41		—		7.20
Depreciation, depletion and amortization		7.84		5.93		6.93		—		6.53
General and administrative		26.41		3.66		24.74		—		11.86

Total	$	53.80	$	22.26	$	83.52	$	—	$	37.35

Office Lease

We occupy 16,327 square feet of office space at 4809 Cole Avenue, Suite 108, Dallas, Texas 75205 under a lease from SVP Cole, L.P. We also occupy 3,218 square feet of office space in Paris, France, approximately 9,000 square feet of office in Ankara, Turkey, 3,767 square feet in Bucharest, Romania and 2,896 square feet of office space in Budapest, Hungary. Total rental expense for 2006 was approximately $764,000.

Markets and Competition

In France, we currently sell all of our oil production to Elf Antar France S.A., the largest purchaser in the area. This production is shipped by truck to a nearby Elf refinery. The oil also can be transported to refineries on the north coast of France via pipeline. Oil production in Turkey is sold to refineries in the southern part of the country. Once gas production starts in the Sub Akcakkoca Sub-Basin, the gas will be sold through the national pipeline.

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

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

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

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

Government Regulation

International

General

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

Government Regulation

Our current or future operations, including exploration and development activities on our properties, require permits from various governmental authorities, and such operations are and will be governed by laws and

regulations governing prospecting, development, production, exports, taxes, labor standards, occupational health, waste disposal, toxic substances, land use, environmental protection and other matters. Compliance with these requirements may prove to be difficult and expensive. See “Item 1A. Risk Factors” for further information regarding international government regulation.

Permits and Licenses

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

Repatriation of Earnings

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

Environmental

The oil and natural gas industry is subject to extensive and varying environmental regulations in each of the jurisdictions in which we may operate. Environmental regulations establish standards respecting health, safety and environmental matters and place restrictions and prohibitions on emissions of various substances produced concurrently with oil and natural gas. These regulations can have an impact on the selection of drilling locations and facilities, potentially resulting in increased capital expenditures. In addition, environmental legislation may require those wells and production facilities to be abandoned and sites reclaimed to the satisfaction of local authorities. We are committed to complying with environmental and operation legislation wherever we operate.

Domestic

General

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

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

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. Notwithstanding our lack of control over wells owned by us but operated by others, the failure of the operator to comply with applicable environmental regulations may, in certain circumstances, be attributable to us and may create legal liabilities for us.

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

OSHA and Other Regulations

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

Employees

As of March 8, 2007, we employed 96 full-time employees. None of our employees are represented by unions or covered by collective bargaining agreements. To date, we have not experienced any strikes or work stoppages due to labor problems, and we have good relations with our employees. As needed, we also utilize the services of independent consultants on a contract basis.

Segment Reporting

See Note 16 in the Notes to Consolidated Financial Statements for financial information by segment.

Internet Address/Availability of Reports

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

Glossary Of Selected Oil and Natural Gas Terms

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

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

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

“BOPD” Barrels of oil per day.

“BTU.” British Thermal Unit.

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

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

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

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

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

“MBbl.” One thousand Bbls.

“MBOE.” One thousand BOE.

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

“MMcf” One million cubic feet of natural gas.

“MMBOE.” One million BOE.

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

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

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

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

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

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

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

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

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

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

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

Item 1A. Risk Factors

Our growth depends on our ability to obtain additional capital and we may not be able to obtain sufficient additional capital to grow our business.

Effectuation of our business strategy will require substantial capital expenditures. In order to fund our future growth, we will need to obtain additional capital. The amount and timing of our future capital requirements will depend upon a number of factors, including:

	•		drilling results and costs;

	•		transportation costs;

	•		equipment costs and availability;

	•		marketing expenses;

	•		oil and natural gas prices;

	•		requirements and commitments under existing permits;

	•		staffing levels and competitive conditions; and

	•		any purchases or dispositions of assets.

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

Our projected capital expenditures budget for 2007 is estimated at $81.5 million.

Currently, we have a $25 million reserve-based credit facility secured by our U.S. assets (the “Texas Capital Facility”); however, our ability to borrow under this facility is limited because of our borrowing base restrictions. At December 31, 2006, there was $5.6 million outstanding under the Texas Capital Facility and approximately $550,000 in additional borrowings were available under the facility. On March 2, 2007, our $15 million reserved-based credit facility was retired from the funds received from the new $25 million facility with the International Finance Corporation. See Note 8 to the Note to the Consolidated Financial Statements.

On December 28, 2006, we entered a loan and guarantee agreement with International Finance Corporation for our operations in Turkey and Romania. The loan and guarantee agreement provides for two separate facilities, the first of which is the $10 million facility which is unsecured and the second of which is the $25 million facility which is a secured revolving facility. The $25 million facility has a current maximum facility amount of $25 million which maximum facility amount will increase to $40 million when the total borrowing base amount exceeds $50 million.

We also have outstanding $86.25 million of Convertible Senior Notes due October 1, 2025.

At December 31, 2006, our debt to equity ratio was .77 to 1, and this ratio and our increased leverage may make it difficult for us to obtain additional funding, especially additional debt.

No assurance can be given that we will have the needed additional capital to fund our growth under these facilities or from existing operations, including our projected 2007 capital expenditures budget. If we are not able to obtain the additional capital necessary to fund our projected 2007 capital expenditures budget, we currently believe that we will reduce our capital expenditure by approximately $30 to $40 million by delaying exploratory projects until such time as we have the additional capital. We may also seek additional capital by (i) forward selling our crude oil and natural gas production; (ii) obtaining industry partners in our exploratory prospects; (iii) selling our non-core properties; or (iv) a combination of these actions. Ultimately, if we cannot obtain additional capital, we will be required to curtail our operations further by delaying our projects. In addition, we may also experience constraints on our cash available to fund our on-going operations.

In addition, to the extent that we are not able to obtain additional capital by the incurrence of additional debt, we may need to issue additional equity. Any such issuance of equity could be materially dilutive to our outstanding equity and equity holders. We are currently considering possible issuances of additional equity securities in order to fund our capital expenditures budget for 2007 which equity securities may be sold at a discount to current market prices and may result in substantial dilution to our equity holders.

The terms of our indebtedness may restrict our ability to grow.

As noted above, our debt to equity ratio may limit our ability to obtain additional indebtedness. Additionally. our new loan and guarantee agreement with the International Finance Corporation restricts our ability to incur additional indebtedness because of financial ratios that we must meet. Our Texas Capital Facility also restricts the ability of the borrowers, two of our domestic subsidiaries, to incur additional indebtedness because of financial ratios that we must meet.

Thus, we may not be able to obtain sufficient capital to grow our business, effectuate our business strategy and may lose opportunities to acquire interests in oil and natural gas properties or related businesses because of our inability to fund such growth. If we are unable to secure the necessary capital to fund our 2007 capital expenditure program, we will reduce our budget by $30 to $40 million, by delaying exploratory projects until we have the additional capital.

Our ability to comply with the restrictions and covenants of our indebtedness in the future is uncertain and is affected by the levels of cash flow from our operations and events or circumstances beyond our control. Our failure to comply with any of the restrictions and covenants could result in a default, which could permit the lender to accelerate repayments and foreclose on the collateral securing the indebtedness.

Any additional future indebtedness may limit our financial and operating flexibility in a manner similar to and potentially more restrictive than the facilities discussed above.

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

On a consistent basis, we evaluate and, where appropriate, pursue acquisition opportunities on terms we consider favorable. In particular, we pursue acquisitions of businesses or interests that will complement and allow us to expand our exploration activities; however, currently, we have no binding commitments related to any acquisitions. The successful acquisition of interests in oil and natural gas properties requires an assessment of:

	•		recoverable reserves;

	•		exploration potential;

	•		future oil and natural gas prices;

	•		operating costs;

	•		potential environmental and other liabilities and other factors; and

	•		permitting and other environmental authorizations required for our operations.

In connection with such an assessment, we would expect to perform a review of the subject properties that we believe to be generally consistent with industry practices. Nonetheless, the resulting conclusions are necessarily inexact and their accuracy inherently uncertain, and such an assessment may not reveal all existing or potential problems, nor will it necessarily permit us to become sufficiently familiar with the properties to fully assess their merits and deficiencies. Inspections may not always be performed on every platform or well, and structural and environmental problems are not necessarily observable even when an inspection is undertaken. As a result, acquired properties may prove to be worth less than we pay for them.

Future acquisitions could pose numerous additional risks to our operations and financial results, including:

	•		problems integrating the purchased operations, personnel or technologies;

	•		unanticipated costs;

	•		diversion of resources and management attention from our core business;

	•		entry into regions or markets in which we have limited or no prior experience; and

	•		potential loss of key employees, particularly those of any acquired organization.

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

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

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

	•		marketing our oil and natural gas production;

	•		integrating new technologies; and

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

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

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

Our operations are subject to numerous federal, state, local and foreign laws and regulations controlling the discharge of materials into the environment or otherwise relating to the protection of the environment. Such laws and regulations not only expose us to liability for our own negligence, but may also expose us to liability for the conduct of others or for our actions that were in compliance with all applicable laws at the time those actions were taken. We may incur significant costs as a result of environmental accidents, such as oil spills, natural gas leaks, ruptures, or discharges of hazardous materials into the environment, including clean-up costs and fines or penalties. Additionally, we may incur significant costs in order to comply with environmental laws and regulations and may be forced to pay fines or penalties if we do not comply.

A significant portion of our operations is conducted in Turkey, Hungary, Romania and France. Therefore, we are subject to political and economic risks and other uncertainties.

We have international operations and are subject to the following foreign issues and uncertainties that can affect our operations adversely:

	•		the risk of expropriation, nationalization, war, revolution, border disputes, renegotiation or modification of existing contracts, and import, export and transportation regulations and tariffs;

	•		taxation policies, including royalty and tax increases and retroactive tax claims;

	•		exchange controls, currency fluctuations and other uncertainties arising out of foreign government sovereignty over international operations;

	•		laws and policies of the United States affecting foreign trade, taxation and investment;

	•		the possibility of being subjected to the exclusive jurisdiction of foreign courts in connection with legal disputes and the possible inability to subject foreign persons to the jurisdiction of courts in the United States; and

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

Terrorist activities may adversely affect our business.

Terrorist activities, including events similar to those of September 11, 2001, or armed conflict involving the United States or any other country in which we hold interests, may adversely affect our business activities and financial condition. If events of this nature occur and persist, the resulting political and social instability could adversely affect prevailing oil and natural gas prices and cause a reduction in our revenues. In addition, oil and natural gas production facilities, transportation systems and storage facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our operations is destroyed or damaged. Costs associated with insurance and other security measures may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

We are highly dependent upon key personnel.

Our continued success is dependent to a significant degree upon the services of our executive officers and upon our ability to attract and retain qualified personnel who are experienced in the various phases of our business. Although we recently replaced G. Thomas Graves III when he resigned in January 2007 with Nigel Lovett, there can be no assurance that if we lose the services of one or more of our other executive officers that we will be able to attract and retain qualified management, geologists, geophysicists and other technical personnel. If we are unable to attract and retain qualified management, geologists, geophysicists and other technical personnel, our business, financial condition, results of operations or the market value of our common stock could be materially adversely affected.

Our marketing of oil and natural gas production principally depends upon facilities operated by others, and these operations may change and have a material adverse effect on our marketing.

Our marketing of oil and natural gas production principally depends upon facilities operated by others. The operations of those facilities may change and have a material adverse effect on our marketing of oil and natural gas production. In addition, we rely upon third parties to operate many of our properties and may have no control over

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

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

We do not hold title to properties in Turkey, Hungary, Romania and France, but have exploration and exploitation permits granted by these countries’ respective governments. Approximately 35% of our proved reserves as of December 31, 2006 are estimated to be recovered after the expiration of the applicable permit. There can be no assurance that we will be able to renew any of these permits when they expire, convert exploration permits into exploitation permits or obtain additional permits in the future. If we cannot review some or all of these permits when they expire or convert exploration permits into exploitation permits, we will not be able to include the proved reserves associated with the permit.

Since we do not hold title to our foreign properties but rather hold exploitation and exploration permits granted to us by the applicable foreign governments, the Securities and Exchange Commission may require that a certain portion of proved reserves associated with these permits not be included in our proved reserves.

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

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

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

Our operations are subject to currency fluctuation risks.

We currently have operations involving the U.S. dollar, Euro, New Turkish Lira, Forint and Romanian Lei. We are subject to fluctuations in the value of the U.S. dollar as compared to the Euro, New Turkish Lira, Forint and Romanian Lei respectively. These fluctuations may adversely affect our results of operations.

We cannot rely on the results of our non-core assets in the future.

We have made equity investments in technology-related businesses that, although related to the energy industry, are not part of our core strategy. Although we have obtained a return of some of our initial investments and have received earnings from these investments during various periods, there can be no assurance that we will be able to obtain any future returns from these investments. Additionally, these investments are subject to the risks associated

generally with technology-related industries, including obsolescence, competition, concentration and the inability to obtain the necessary capital for future growth.

Failure to maintain effective internal controls could have a material adverse effect on our operations and our stock price.

We are subject to Section 404 of the Sarbanes-Oxley Act which requires annual management assessment of the effectiveness of our internal control over financial reporting and a report by our independent auditors addressing our internal controls and management’s assessment. Effective internal controls are necessary for us to produce reliable financial reports. If, as a result of deficiencies in our internal controls, we cannot provide reliable financial reports, our business decision process may be adversely affected, our business and operating results could be harmed, we could be deemed in violation of our lending covenants, investors could lose confidence in our reported financial information and the price of our stock could decrease.

During the evaluation of disclosure controls and procedures for the year ended December 31, 2006, we concluded that our disclosure controls and procedures were not effective in reaching a reasonable level of assurance of achieving management’s desired controls and procedures objectives and that we had material weaknesses in our internal control over financial reporting. There is no guarantee that we will be able to resolve these material weaknesses or avoid have other material weaknesses in the future.

Risks Related To Our Industry

A decline in oil and natural gas prices will have an adverse impact on our operations.

Our revenues, cash flows and profitability are substantially dependent upon prevailing prices for oil and natural gas. In recent years, oil and natural gas prices and, therefore, the level of drilling, exploration, development and production, have been extremely volatile. Any significant or extended decline in oil or natural gas prices will have a material adverse effect on our business, financial condition and results of operations and could impair access to future sources of capital. Volatility in the oil and natural gas industry results from numerous factors over which we have no control, including:

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

	•		the cost of exploring for, producing and transporting oil and natural gas;

	•		the domestic and foreign supply of oil and natural gas;

	•		domestic and foreign governmental regulation;

	•		the level and price of foreign oil and natural gas transportation;

	•		available pipeline and other oil and natural gas transportation capacity;

	•		weather conditions;

	•		international political, military, regulatory and economic conditions;

	•		the level of consumer demand;

	•		the price and the availability of alternative fuels;

	•		the effect of worldwide energy conservation measures; and

	•		the ability of oil and natural gas companies to raise capital.

Significant declines in oil and natural gas prices for an extended period may:

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

	•		reduce the amount of oil and natural gas that we can produce economically;

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

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

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

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

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

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

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

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

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

In addition, as a “successful efforts” company, we account for unsuccessful exploration efforts, i.e., the drilling of “dry holes,” as an expense of operations which impacts our earnings. Significant expensed exploration charges in any period would materially adversely affect our earnings for that period and could cause our earnings to be volatile from period to period.

We are exposed to operating hazards and uninsured risks.

As noted by the fact that in 2005 we incurred two separate incidents, in offshore Turkey in the Black Sea, which resulted in the loss of two caissons and three wells, our operations are subject to the risks inherent in the oil and natural gas industry, including the risks of:

	•		fire, explosions and blowouts;

	•		pipe failure;

	•		abnormally pressured formations; and

	•		environmental accidents such as oil spills, natural gas leaks, ruptures or discharges of toxic gases, brine or well fluids into the environment (including groundwater contamination).

These events may result in substantial losses to us from:

	•		injury or loss of life;

	•		severe damage to or destruction of property, natural resources and equipment;

	•		pollution or other environmental damage;

	•		clean-up responsibilities;

	•		regulatory investigation;

	•		penalties and suspension of operations; or

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

As is customary in our industry, we maintain insurance against some, but not all, of these risks. We cannot assure investors that our insurance will be adequate to cover these losses or liabilities. We do not carry business interruption insurance. Losses and liabilities arising from uninsured or underinsured events may have a material adverse effect on our financial condition and operations.

We carry well control insurance for our drilling operations. Our coverage includes blowout protection and liability protection on domestic and international wells.

The producing wells in which we have an interest occasionally experience reduced or terminated production. These curtailments can result from mechanical failures, contract terms, pipeline and processing plant interruptions, market conditions and weather conditions. These curtailments can last from a few days to many months.

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

Any material inaccuracies in these reserve estimates or underlying assumptions could materially affect the quantities and present values of our reserves. The process of estimating natural gas and oil reserves is complex. It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves shown in this annual report. In order to prepare these estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. The process also requires economic assumptions relating to matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and pre-tax net present value of reserves shown in this annual report. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

Investors should not assume that the pre-tax net present value of our proved reserves referred to in this annual report is the current market value of our estimated oil and natural gas reserves. We base the pre-tax net present value of future net cash flows from our proved reserves on prices and costs on the date of the estimate. Actual future prices, costs, and the volume of produced reserves may differ materially from those used in the pre-tax net present value estimate.

Risks Related To Our Common Stock

Our stock’s public trading price has been volatile, which may depress the trading price of our common stock.

Our stock price is subject to significant volatility. Overall market conditions, in addition to other risks and uncertainties described in this “Risk Factors” section and elsewhere in this annual report, may cause the market price of our common stock to fall. We participate in a price sensitive industry, which often results in significant volatility in the market price of common stock irrespective of company performance. As a result, our high and low closing stock prices for the twelve months ended March 8, 2007 were $34.49 and $17.14 respectively. Fluctuations in the price of our common stock may be exacerbated by conditions in the energy and oil and natural gas industries or conditions in the financial markets generally. Because our Convertible Senior Notes are convertible into shares of our common stock at a conversion rate equal to 23.3596 shares of common stock per $1,000 principal amount of Convertible Senior Notes, volatility in the price of our common stock may depress the trading price of the Convertible Senior Notes. The risk of volatility and depressed prices of our common stock also applies to holders who receive shares of common stock upon conversion of their Convertible Senior Notes.

Our common stock is quoted on the Nasdaq Global Market under the symbol “TRGL.” However, daily trading volumes for our common stock are, and may continue to be, relatively small compared to many other publicly traded securities. It may be difficult for investors to sell their shares of common stock in the public market at any given time at prevailing prices, and the price of our common stock may, therefore, be volatile.

Numerous factors, including many over which we have no control, may have a significant impact on the market price of our common stock, including, among other things:

	•		current events affecting the political, economic and social situation in the United States and other countries where we operate;

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

	•		litigation involving or affecting us;

	•		changes in financial estimates and recommendations by securities analysts;

	•		acquisitions and financings by us or our competitors;

	•		quarterly variations in operating results;

	•		volatility in exchange rates between the US dollar and the currencies of the foreign countries in which we operate;

	•		the operating and stock price performance of other companies that investors may consider to be comparable; and

	•		purchases or sales of blocks of our securities.

In addition, the stock market in recent years has experienced extreme price and trading volume fluctuations that often have been unrelated or disproportionate to the operating performance of individual companies. These broad market fluctuations may adversely affect the price of our common stock, regardless of our operating performance. In addition, sales of substantial amounts of our common stock in the public market, or the perception that those sales may occur, could cause the market price of our common stock to decline. Furthermore, stockholders may initiate securities class action lawsuits if the market price of our stock drops significantly, which may cause us to incur substantial costs and could divert the time and attention of our management.

These factors, among others, could significantly depress the price of our common stock.

A large percentage of our common stock is owned by our officers and directors, and such stockholders may control our business and affairs.

At March 8, 2007, our officers and directors as a group beneficially owned approximately 14 % of our common stock (including shares issuable upon exercise of stock options held by officers and directors and upon conversion of our Series A-1 Convertible Preferred Stock held by directors and affiliates of certain directors). Due to their large ownership percentage interest, they may be able remain entrenched in their positions.

We do not intend to pay cash dividends on our common stock in the foreseeable future.

We currently intend to continue our policy of retaining earnings to finance the growth of our business. As a result, we do not anticipate paying cash dividends on our common stock in the foreseeable future. In addition, the terms of our outstanding shares of preferred stock and our loan and guarantee agreement with the International Finance Corporation restrict our ability to pay dividends on our common stock. Because we do not anticipate paying cash dividends for the foreseeable future, holders who convert their Convertible Senior Notes and receive shares of our common stock will not realize a return on their investment unless the trading price of our common stock appreciates, which we cannot assure.

We may issue equity securities in the future which may depress the trading price of our common stock and may dilute the interests of our existing stockholders.

Future sales or issuances of common stock or the issuance of securities senior to our common stock may depress the trading price of our common stock .

Any issuance of equity securities, including the issuance of shares upon conversion of the Convertible Senior Notes, could dilute the interests of our existing stockholders and could substantially decrease the trading price of our common stock and the notes. We may issue equity securities in the future for a number of reasons, including to finance our operations and business strategy, to adjust our ratio of debt to equity, to satisfy our obligations upon the exercise of outstanding warrants or options, or upon conversion of preferred stock or debentures, or for other reasons. As of March 8, 2007, there were:

	•		673,870 shares of our common stock issuable upon exercise of outstanding options, at a weighted average exercise price of $5.13 per share, of which options to purchase 660,536 shares were exercisable;

	•		98,760 shares of our common stock issuable upon exercise of outstanding warrants, at a weighted average exercise price of $19.81 per share, of which 98,760 were exercisable;

	•		450,000 shares of our common stock issuable upon conversion of our Series A-1 Convertible Preferred Stock, at a conversion rate equal to 6.25 shares of common stock per share of Series A-1 Convertible Preferred Stock (subject to certain adjustments for stock splits, stock dividends, mergers or assets distributions); and

	•		421,915 shares of our common stock available for future grant under our equity incentive plan.

Additionally, we are currently considering possible issuances of additional equity securities in order to fund our capital expenditures budget for 2007 which equity securities may be sold at a discount to current market prices and may result in substantial dilution to our equity holders.

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

Our total consolidated long-term debt as of December 31, 2006 was approximately $112.8 million and represented approximately .77 of our total capitalization as of that date. Our level of indebtedness could have important consequences to investors, because:

	•		it could affect our ability to satisfy our payment obligations under our indebtedness;

	•		a substantial portion of our cash flows from operations will have to be dedicated to interest and principal payments and may not be available for operations, working capital, capital expenditures, expansion, acquisitions or general corporate or other purposes;

	•		it may impair our ability to obtain additional financing in the future;

	•		it may impair our ability to compete with companies that are not as highly leveraged;

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

	•		it may make us more vulnerable to downturns in our business, our industry or the economy in general.

Provisions in our charter documents, the indenture for the Convertible Senior Notes and Delaware law could discourage an acquisition of us by a third party, even if the acquisition would be favorable to holders of our common stock or the Convertible Senior Notes.

If a “change in control” (as defined in the indenture for the Convertible Senior Notes ) occurs, holders of the Convertible Senior Notes will have the right, at their option, to require us to repurchase all or a portion of their notes. In the event of certain “fundamental changes” (as defined in the indenture for the Convertible Senior Notes), we also may be required to increase the conversion rate applicable to notes surrendered for conversion upon the fundamental change. In addition, the indenture for the Convertible Senior Notes prohibits us from engaging in certain mergers or acquisitions unless, among other things, the surviving entity assumes our obligations under the notes. These and other provisions, including the provisions of our charter documents and Delaware law, could prevent or deter a third party from acquiring us even where the acquisition could be beneficial to holders of our common stock or the notes.

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

Our charter documents provide our board of directors the right to issue preferred stock upon such terms and conditions as it deems to be in our best interests. The terms of such preferred stock may adversely impact the dividend and liquidation rights of the common stockholders without the approval of the common stockholders.

PART II

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

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Certain of the matters discussed under the captions “Business and Properties,” “Legal Proceedings,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and elsewhere in this annual report may constitute “forward-looking” statements for purposes of the Securities Act of 1933, and the Securities Exchange Act of 1934 and, as such, may involve known and unknown risks, uncertainties and other factors that may cause the actual results, performance or achievements to be materially different from future results, performance or achievements expressed or implied by such forward-looking statements. When used in this report, the words “anticipates,” “estimates,” “plans,” “believes,” “continues,” “expects,” “projections,” “forecasts,” “intends,” “may,” “might,” “could,” “should,” and similar expressions are intended to be among the statements that identify forward-looking statements. Various factors that could cause the actual results, performance or achievements to differ materially from our expectations are disclosed in this report (“Cautionary Statements”), including, without limitation, those statements made in conjunction with the forward-looking statements included under the captions identified above and otherwise herein. All written and oral forward-looking statements attributable to us are expressly qualified in their entirety by the Cautionary Statements.

Executive Overview

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

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

Income available to common shares for 2006 was $2.4 million, or $0.16 per diluted share, compared with income applicable to common shares of $9.9 million, or $0.69 per diluted share, in 2005. Operating income for 2006 was $5.3 million, compared with operating income of $6.2 million in 2005.

Revenues for the year ended December 31, 2006 were $40.4 million, a 30% increase over 2005 revenues of $31.1 million.

In 2006, our oil and natural gas production was 741,609 BOE versus production of 624,144 BOE for 2005. Our average realized oil price per barrel for 2006 was $60.90, a 21.4% increase over the average realized oil price per barrel of $50.17 in 2005. The average realized gas price in 2006 was $4.96 per Mcf, 34.4% lower than the average realized gas price of $7.56 per Mcf in 2005.

At December 31, 2006, we held interests in approximately 5.5 million gross acres (approximately 4.2 million net acres). For a more detailed description of our properties see “Items 1 and 2. Business and Properties.” At December 31, 2006, our net proved reserves were estimated at approximately 16 MMBOE.

In the second quarter of 2006, we started production in Romania resulting in an additional 91,427 BOE of production for the year.

In the third and fourth quarter of 2006, we installed the tripods on the Ayazli and Akkaya structures in the Black Sea and currently anticipate commencement of production in April 2007. We will continue to seek opportunities to accelerate our worldwide acquisition and development program by:

	•		Exploiting existing properties and developing existing reserves.

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

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

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

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

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

Critical Accounting Policies and Management’s Estimates

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

Revenue Recognition

Our French crude oil production accounts for the majority of our sales. We sell our French crude oil to Elf Antar France S.A. ("ELF"), and recognize the related revenues when the production is delivered to ELF's refinery, typically via truck. At the time of delivery to the plant, title to the crude oil transfers to ELF. The terms of the contract with ELF state that the price received for oil sold will be the arithmetic mean of all average daily quotations of Dated Brent published in Platt's Oil Market Wire for the month of production less a specified differential per barrel. The pricing of oil sales is done on the first day of the month following the month of production. In accordance with the terms of the contract, payment is made within six working days of the date of issue of the invoice. The contract with ELF is automatically extended for a period of one year unless either party cancels it in writing no later than six months prior to the beginning of the next year. We periodically review ELF's payment timing to ensure that receivables from ELF for crude oil sales are collectible. In 2006, 2005 and 2004 sales to ELF represents approximately 67%, 66% and 63%, respectively, of the Company's total revenue and approximately 20% and 23% of the Company's accounts receivable at December 31, 2006 and 2005, respectively.

We recognize oil and natural gas 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. Due to our small net revenue interest in most natural gas properties, we record natural gas revenues under the sales method. This method records sales on volumes for which actual payment is received versus payments for which one is entitled to receive. We believe that the amount of any gas imbalances that result from not recording sales on the entitlement method is insignificant. The purchasers of such production have historically made payment for crude oil and natural gas purchases within thirty and sixty days of the end of each production month, respectively. We periodically review the difference between the dates of production and the dates we collect payment for such production to ensure that receivables from those purchasers are collectible. Taxes associated with production are classified as lease operating expense.

Successful Efforts Method of Accounting

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

As of December 31, 2006, we have approximately $4.4 million of exploratory costs that had been capitalized for one year or less which included one well located in the United States, two wells in Hungary and two wells in Romania. The U.S. well has been completed and is being evaluated further. Currently, approximately $77,000 has been capitalized and if no additional work is done on the well by September 30, 2007, we will expense the well as dry hole cost. During the first quarter 2007, we declared the two Hungarian wells and the two Romanian wells as dry holes and expensed approximately $4.3 million as dry hole cost.

As of December 31, 2006, we had approximately $856,000 of exploratory costs that had been capitalized for a period greater than one year which included two wells located in the United States. One of the wells was spudded on October 12, 2005 and the drilling rig was released on November 6, 2005 after the successful testing of the well. The closest natural gas pipeline connection was approximately three miles from the well and the operator chose to delay completion of the well until a satisfactory natural gas market could be identified and the well could be completed and tied into a sales line economically. We expect this to occur by year end 2007. The second well was spudded on August 4, 2005 and due to the multiple pay zones encountered in the well, testing continued through the first quarter of 2006. For the remainder of 2006 the operator evaluated the test results to devise a completion procedure that would achieve maximum production from all pay zones for a minimal amount of capital outlay. We anticipate that the well will be transferred from capitalized exploratory cost in 2007.

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. 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.

For the year ended December 31, 2006, we had a downward reserve revision of 9%. This downward revision was due to the following factors: (i) in the Charmottes Field in France, several high volume producing wells experienced rapidly increasing water production which caused performance declines resulting in a downward revision of 921 MBO; (ii) in Romania, two gas wells watered out after producing for short periods of time resulting in a downward revision of 197 MBOE; (iii) in the South Akcakoca Sub-Basin, due to new drilling, a previous geological interpretation was refined resulting in a downward revision of 192 MBOE; (iv) in the United States properties, there was a downward revision of 30 MBO due to minor decreases in reserves across numerous wells and fields with no particular property or field contributing a significant portion of the 30 MBO reduction; and (v) there was a downward revision of 73 MBOE due to a decline in prices. These downward revisions were partially offset by upward revisions of 143 MBOE due to performance revisions over several fields, none of which individually contributed a significant portion of this upward revision.

For the year ended December 31, 2005, we had a downward reserve revision of 2.4% or 331 MBOE. Overall gas reserves were higher by 107 MBOE and oil reserves were lower by 437 MBO. The overall downward revision of 331 MBOE was primarily due to the decrease of 1,000 MBO in oil reserves in the Neocomian Field in France where new drilling diminished the estimated reserves in several existing proved undeveloped reserves and cause the removal of several proved undeveloped reserve locations which was partially offset primarily by new drilling in the Charmottes Field where a successful horizontal well established additional reserves of 438 MBO in an existing field, increased gas reserves in the United States of 107 MBOE and by an upward revision of 1,000 MBOE due to an increase in prices. With regard to the increase in reserves of 107 MBOE in the United States properties, no particular property contributing a significant portion of the increased reserves.

For the year ended December 31, 2004, we had an upward reserve revision of 5.0% or 784 MBOE. The upward revision was primarily due to an increase of 1397 MBOE due to price increases which were partially offset by a downward revision due to performance of 613 MBOE. Of the 613 MBOE downward revision, 200 MBOE was in the Cendere Field in Turkey which exhibited accelerated decline rates.

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 Financial Accounting Standards Board (“FASB”) believes the standard also responds to investors’ requirement for expanded information about the extent to which companies measure assets and liabilities at fair value, the information used to measure fair value, and the effect of fair value measurements on earnings. SFAS 157 applies whenever other standards require (or permit) assets or liabilities to be measured at fair value but does not expand the use of fair value in any new circumstances. The standard clarifies that for items that are not actively traded, such as certain kinds of derivatives, fair value should reflect the price in a transaction with a market participant, including an adjustment for risk, not just the company’s mark-to-model value. SFAS 157 also requires expanded disclosure of the effect on earnings for items measured using unobservable data. Under SFAS 157, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the principal market for asset or liability or, in the absence of a principal market, the most advantageous market for the asset or liability. In this standard, the FASB clarifies the principle that fair value should be based on the assumptions market participants would use when pricing the asset or liability. In support of this principle, SFAS 157 establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. The fair value hierarchy gives the highest priority to quoted prices in active markets and the lowest priority to unobservable data, for example, the reporting entity’s own data. Under the standard, fair value measurements would be separately disclosed by level within the fair value hierarchy. The provisions of SFAS 157 are effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. Earlier application is encouraged, provided that the reporting entity has not yet issued financial statements for that fiscal year, including any financial statements for an interim period within that fiscal year. We are currently evaluating this statement and have not yet determined the impact of such on our financial statements. We plan to adopt this statement when required at the start of our fiscal year beginning January 1, 2008.

On December 21, 2006, the FASB issued FSP No. EITF 00-19-2, “Accounting for Registration Payment Arrangements”(FSP EITF 00-19-2), which addresses an issuer’s accounting for registration payment arrangements and specifies that the contingent obligation to make future payments or otherwise transfer consideration under a registration payment arrangement, whether issued as a separate agreement or included as a provision of a financial instrument or other agreement, should be separately recognized and measured in accordance with FASB SFAS No. 5,“Accounting for Contingencies.”FSP EITF 00-19-2 is effective immediately for registration payment

arrangements and the financial instruments subject to those arrangements that are entered into or modified subsequent to the date of its issuance. For registration payment arrangements and financial instruments subject to those arrangements that were entered into prior to the issuance of FSP EITF 00-19-2, this guidance shall be effective for financial statements issued for fiscal years beginning after December 15, 2006, and interim periods within those fiscal years. We do not expect this standard to have any effect upon adoption, because the Company’s policy has been to accrue such liabilities when they are deemed probable.

In April 2005, the FASB issued FASB Staff Position (FSP) FAS 19-1 “Accounting for Suspended Well Costs.” This staff position amends FASB Statement No. 19 “Financial Accounting and Reporting by Oil and Gas Producing Companies” and provides guidance about exploratory well costs to companies who use the successful efforts method of accounting. The position states that exploratory well costs should continue to be capitalized if: 1) a sufficient quantity of reserves are discovered in the well to justify its completion as a producing well and 2) sufficient progress is made in assessing the reserves and the well’s economic and operating feasibility. If the exploratory well costs do not meet both of these criteria, these costs should be expensed, net of any salvage value. Additional annual disclosures are required to provide information about management’s evaluation of capitalized exploratory well costs. In addition, the Staff Position requires the annual disclosure of: 1) net changes from period to period of capitalized exploratory well costs for wells that are pending the determination of proved reserves, 2) the amount of exploratory well costs that have been capitalized for a period greater than one year after the completion of drilling and 3) an aging of exploratory well costs suspended for greater than one year with the number of wells it related to. Further, the disclosures should describe the activities undertaken to evaluate the reserves and the projects, the information still required to classify the associated reserves as proved and the estimated timing for completing the evaluation. We adopted FAS 19-1 as of December 31, 2005.

FASB Interpretation No. 48,Accounting for Uncertainty in Income Taxes — An Interpretation of FASB Statement No. 109,(“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109. FIN 48 also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The new FASB standard also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. The evaluation of a tax position in accordance with FIN 48 is a two-step process. The first step is a recognition process whereby the enterprise determines whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more-likely-than-not recognition threshold, the enterprise should presume that the position will be examined by the appropriate taxing authority that has full knowledge of all relevant information. The second step is a measurement process whereby a tax position that meets the more-likely-than-not recognition threshold is calculated to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006. The provisions of FIN 48 are to be applied to all tax positions upon initial adoption of this standard. Only tax positions that meet the more-likely-than-not recognition threshold at the effective date may be recognized or continue to be recognized upon adoption of FIN 48. The cumulative effect of applying the provisions of FIN 48 should be reported as an adjustment to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) in the year of adoption. We plan to adopt this statement at the start of our fiscal year beginning January 1, 2007. We are still determining the impact, if any, that this statement will have on our financial statements.

On February 16, 2006, the FASB issued Statement 155, “Accounting for Certain Hybrid Instruments — an amendment of FASB Statements No. 133 and 140.” The statement amends Statement 133 to permit fair value measurement for certain hybrid financial instruments that contain an embedded derivative and provides additional guidance on the applicability of Statement 133 and 140 to certain financial instruments and subordinated concentrations of credit risk. The new standard is effective for the first fiscal year that begins after September 16, 2006. We have determined that the impact on our financial statements will not be material. We have adopted FASB 155 on January 1, 2007.

to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. Under SFAS 153, if a nonmonetary exchange of similar productive assets meets a commercial-substance criterion and fair value is determinable, the transaction must be accounted for at fair value resulting in recognition of any gain or loss. SFAS 153 is effective for nonmonetary transactions in fiscal periods that begin after June 15, 2005. This standard did not have a material impact on our financial position, results of operations or cash flows.

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

In February 2007, the FASB issued Statement 159,“The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement 115”.The statement permits entities to choose to measure certain financial instruments and other items at fair value. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. Unrealized gains and losses on any items for which Toreador elects the fair value measurement option would be reported in earnings. Statement 159 is effective for fiscal years beginning after November 15, 2007. However, early adoption is permitted for fiscal years beginning on or before November 15, 2007, provided Toreador also elects to apply the provisions of Statement 157,“Fair Value Measurements”,at the same time. Toreador is currently assessing the effect, if any, the adoption of Statement 159 will have on its financial statements and related disclosures.

LIQUIDITY AND CAPITAL RESOURCES

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

Liquidity

As of December 31, 2006, we had cash and cash equivalents and restricted cash of $33.2 million, a current ratio of approximately 1.3 to 1 and a debt (convertible debenture, long-term debt and Convertible Senior Notes) to equity ratio of .77 to 1. For the twelve months ended December 31, 2006, operating income was $5.3 million and capital expenditures were $120.2 million.

Our preliminary capital expenditure budget (subject to projected available capital) for 2007 is $81.5 million, and we currently plan on funding our 2007 capital expenditure program through (i) funds that have been received from our new credit facilities with the International Finance Corporation; (ii) cash flow from our existing properties, including our Black Sea properties that are anticipated to commence production in April 2007, and (iii) future potential financing sources, including the public or private issuance of debt or equity.

We are currently considering possible issuances of additional equity securities in order to fund our capital expenditures budget for 2007 which equity securities may be sold at a discount to current market prices and may result in substantial dilution to our equity holders.

If the cash flow from our operations, including our Black Sea properties, is less than anticipated and or if we are unable to issue additional capital through the issuance of debt or equity, we currently believe that we will reduce our capital expenditures by approximately $30 to $40 million, by delaying exploratory projects until such time as we have additional capital. We may also seek additional capital by (i) forward selling our crude oil and natural gas production; (ii) obtaining industry partners in our exploratory prospects; (iii) selling our non-core properties; or (iv)

a combination of these actions. We believe such actions will allow us to meet our capital commitments and that as a result we will have sufficient liquidity for the remainder of 2007.

Senior Debt

On December 23, 2004, we entered into a five-year $15 million reserve-based borrowing facility with a French lender to finance the development of our existing French fields, acquisitions of new fields, general working capital and other corporate purposes. The facility bears interest at a floating rate of 2.25-2.75% above LIBOR (7.54% total rate at December 31, 2006) depending on the principal outstanding. Toreador and certain of its U.S. and French subsidiaries have each guaranteed the obligations under the facility. This facility will require monthly interest payments until December 23, 2009, at which time all unpaid principal and interest are due. Under the $15 million facility borrowings of approximately $909,000 were available at December 31, 2006. The $15 million facility contains various affirmative and negative covenants. These covenants, among other things, limit additional indebtedness, the sale of assets, change of control and management, limitations on the distribution of stock dividends and require us to meet certain financial requirements. Specifically, we must maintain an interest cost ratio of not less than 4.00 to 1.00, an indebtedness ratio of not less than 1.00 to 1.00, asset life cover ratio of not less than 1.25 to 1.00, a loan life cover ratio equal to or greater than 1.15 to 1.00 and a debt service coverage ratio equal to or greater than 1.10 to 1.00. On March 3, 2007 this facility was retired and replaced by the credit facility with the International Finance Corporation. See Note 8 to the Notes to the Consolidated Financial Statements.

As a result of not providing Natixis with our unaudited consolidated financial statements for the nine month period ended September 30, 2006 within forty-five (45) days after the end of such quarter, we were in default under the $15 million facility. Until January 16, 2007, Natixis waived such default and any other default under the facility as a result of us not yet providing such financial statements. On January 16, 2007, we filed the Form 10-Q for the quarter ended September 30, 2006 and provided the unaudited consolidated financial statements contained in the Form 10-Q to Natixis which cured the default.

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

On December 30, 2004, we entered into a five-year $25 million reserve-based borrowing facility with Texas Capital Bank, N.A. in order to finance the development and acquisition of oil and natural-gas interests both domestically and internationally and for working capital purposes. The facility bears interest at a rate of prime less 0.5% (7.75% total rate at December 31, 2006) and is collateralized by our domestic working interests. The borrowers under this facility are two of our domestic subsidiaries, and the parent entity has guaranteed the obligations. At December 31, 2006, we had $5.6 million outstanding and approximately an additional $550,000 available for borrowings. As of March 8, 2007, we had approximately $5.6 million outstanding and an additional approximately $550,000 available for borrowings. The Texas Capital facility requires monthly interest payments until January 1, 2009 at which time all unpaid principal and interest are due. The Texas Capital facility contains various affirmative and negative covenants. These covenants, among other things, limit additional indebtedness, the sale of assets, change of control and management and require us to meet certain financial requirements. Specifically, we must maintain a current ratio of 1.25 to 1.00 (exclusive of amounts due under revolving credit arrangements) and an interest coverage ratio of not less than 3.00 to 1.00.

We were in default under the Texas Capital facility for failing to provide Texas Capital on or before the 60th day after the last day of the fiscal quarter ended September 30, 2006 with a copy of the unaudited consolidated financial statements of Toreador and there was an event of default under the Texas Capital facility for defaulting in the performance or observance of a provision under the Senior Convertible Notes. Texas Capital waived the default and event of default until January 16, 2007. On January 16, 2007, we filed the Form 10-Q for the quarter ended September 30, 2006 and provided the unaudited consolidated financial statements contained in the Form 10-Q to Texas Capital which cured the default.

New Secured Revolving Facility

On December 28, 2006, we entered into a loan and guarantee agreement with International Finance Corporation. The loan and guarantee agreement provides for a $25 million facility which is a secured revolving facility with a current maximum facility amount of $25 million which maximum facility amount will increase to $40 million when

the projected total borrowing base amount exceeds $50 million. The $25 million facility funded on March 2, 2007. The total proceeds received on March 2, 2007 were approximately $25 million, of which $11 million was used to retire the outstanding balance on the $15 million credit facility and the remaining $14 million of funds will be used to finance our capital expenditures in Turkey and Romania. The loan and guarantee agreement also provides for an unsecured $10 million facility which funded on December 28, 2006. As of December 31, 2006 and March 8, 2007, the $10 million facility had $10 million outstanding. All amounts available under the new secured revolving facility have been funded. Both the $25 million facility and the $10 million facility are to fund the our operations in Turkey and Romania.

Interest accrues on any loans under the $25 million facility at a rate of 2% over the six month LIBOR rate. Interest accrued on the $10 million facility at a rate of 1.5% over the six month LIBOR rate until the $25 million facility funded on March 2, 2007 after which the rate for the $10 million facility was lowered to 0.5% over the six month LIBOR rate. As of December 31, 2006 the interest rate on the $10 million facility was 6.86%. As of March 8, 2007, the interest rate on the $25 million facility was 7.349% and the interest rate on the $10 million facility was 5.849%. Interest is to be paid on each June 15 and December 15.

On December 31, 2011, the maximum amount available under the $25 million facility begins to decrease by $5 million every six months from $40 million (assuming the projected borrowing base amount exceeds $50 million) until the final portion of the $25 million facility is due on December 15, 2014. On December 15, 2014, $5 million of the $10 million facility is to be repaid with the remaining $5 million being due on June 15, 2015.

We are to meet the following ratios on a consolidated basis: (i) the life of loan coverage ratio of not less than: (a) 1.2:1.0 in 2006 and 2007; (b) 1.3:1.0 in 2008; and (c) 1.4:1.0 in 2009 and each subsequent year thereafter; (ii) reserve tail ratio of not less than 25%; (iii) adjusted financed debt to EBITDA ratio of not more than 3.0:1.0; (iv) liabilities to tangible net worth ratio of not more than 60:40; and (v) interest coverage ratio of not less than 3.0:1.0.

We are subject to certain negative covenants, including, but not limited to, the following: (i) except as required by law or to pay the dividends on the Series A-1 Convertible Preferred Stock, paying dividends; (ii) subject to certain exceptions, incurring debt, making guarantees or creating or permitting to exist any liens, (iii) subject to certain exceptions, making or permitting to exist loans or advances to, or deposits, with other persons or investments in any person or enterprise; (iv) subject to certain exceptions, selling, transferring, leasing or otherwise disposing of all or a material part of its borrowing base assets; and (v) subject to certain exceptions, undertaking or permitting any merger, spin-off, consolidation or reorganization.

5% Convertible Senior Notes Due 2025

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

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

Due to our restating the consolidated financial statements for the years ended December 31, 2003, 2004 and 2005 and our consolidated financial statements for each of the quarters ended March 31 and June 30, 2006, we did not provide the trustee under the indenture of the Convertible Senior Notes with copies of our annual reports, information, documents and other reports that we are required to file with the Securities and Exchange Commission pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 within thirty (30) days of when such reports are required to be filed with the Securities and Exchange Commission.

On December 15, 2006, we received a notice from the trustee for failing to provide the trustee with a copy of our Form 10-Q for the nine month period ended September 30, 2006. Since we cured the covenant default within thirty (30) days after receiving the written notice from the trustee, we cured the default and an event of default did not occur.

The registration rights agreement covering the Convertible Senior Notes provides for a penalty if the registration statement is filed and declared effective but thereafter ceases to be effective (a “Suspension Period”) for an aggregate of forty-five (45) days in any three month period or ninety (90) days in any twelve month period (an “Event Date”). Such penalty calls for an additional 0.25% per annum in interest expense on the aggregate principal amount of the Convertible Senior Notes for the first ninety (90) days following an Event Date and an additional 0.50% per annum in interest expense on the aggregate principal amount of the Convertible Senior Notes thereafter, until such Suspension Period ends upon the registration statement again becoming effective. Because we did not file our Quarterly Report on Form 10-Q for the nine month period ended September 30, 2006 in a timely manner, the registration statement for the Convertible Senior Notes became ineffective and we entered a Suspension Period on November 15, 2006. Such Suspension Period ended on January 23, 2007 when we provided notice that the Form 10-Q had been filed and the Suspension Period was no longer in effect. Because the Suspension Period exceeded forty-five (45) days in any three month period, we will owe approximately $14,375 in additional interest expense. Once we file our Form 10-K for the year ended December 31, 2006, we will again enter a Suspension Period until we can file and have declared effective an amendment to our registration statement on Form S-1. Because of the previous Suspension Period, we will exceed the ninety (90) days in any twelve month period on the twenty first (21^st) day following the filing of our Form 10-K and will again begin to accrue additional interest as described above until we can file and have declared effective an amendment to our registration statement on Form S-1.

Preferred Stock

On February 22, 2005, 82,000 shares of Series A-1 Convertible Preferred Stock were exchanged for an aggregate of 512,000 shares of our common stock. As of December 31, 2006, there were 72,000 shares of Series A-1 Convertible Preferred Stock outstanding. At the option of the holder, the Series A-1 Convertible Preferred Stock may be converted into common shares at a price of $4.00 per common share (conversion would amount to 450,000 Toreador common shares). The Series A-1 Convertible Preferred Stock accrues dividends at an annual rate of $2.25 per share payable quarterly in cash. At any time on or after November 1, 2007, we may elect to redeem for cash any or all shares of Series A-1 Convertible Preferred Stock. The optional redemption price per share is the sum of (1) $25.00 per share plus (2) any accrued unpaid dividends, and such sum is multiplied by a declining multiplier. The multiplier is 105% until October 31, 2008, 104% until October 31, 2009, 103% until October 31, 2010, 102% until October 31, 2011, 101% until October 31, 2012, and 100% thereafter.

Dividend and Interest Requirements

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

Dividends on our Series A-1 Convertible Preferred Stock are paid quarterly. For the year ended December 31, 2006 dividends totaled $162,000.

The terms of the loan and guarantee agreement with the International Finance Corporation limit the payment of dividends only to those that are required by law and to dividends associated with our Series A-1 Convertible Preferred Stock.

Contractual Obligations

The following table sets forth our contractual obligations in thousands at December 31, 2006 for the periods shown:


			Less than		One To		Four to		More Than
	Total		One Year		Three Years		Five Years		Five Years
Long-term debt	$	112,800	$	5,000	$	6,000	$	5,500	$	96,300
Lease commitments		1,516		502		365		264		385

Total contractual obligations	$	114,316	$	5,502	$	6,365	$	5,764	$	96,685

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

Results of Operations

Comparison of Years Ended December 31, 2006 and 2005


	For the Years Ended December 31,
	2006		2005			2006		2005
Production:					Average Price:
Oil (MBbls):					Oil ($/Bbl):
United States		58		60	United States	$	61.29	$	52.37
France		442		404	France		61.74		50.92
Turkey		68		65	Turkey		56.10		43.48
Romania		8		—	Romania		52.71		—

Total		576		529	Total	$	60.90	$	50.17

Gas (MMcf):					Gas ($/Mcf):
United States		490		570	United States	$	6.38	$	7.56
France		—		—	France		—		—
Turkey		—		—	Turkey		—		—
Romania		502		—	Romania		3.57		—

Total		992		570	Total	$	4.96	$	7.56

MBOE:					$/ BOE:
United States		140		155	United States	$	47.88	$	48.08
France		442		404	France		61.74		50.92
Turkey		68		65	Turkey		56.10		43.48
Romania		92		—	Turkey		24.06		—

Total		742		624	Total	$	53.96	$	49.86

Revenues

Oil and natural gas sales

Oil and natural gas sales for the twelve months ended December 31, 2006 were $40.4 million, as compared to $31.1 million for the comparable period in 2005. This increase is primarily due to a significant increase in the average realized price for oil partially offset by a $2.60 decline in the price realized for natural gas. Production increased by approximately 118 MBOE due primarily to the start of production in Romania and increases in production in Turkey and France that was somewhat offset by lower production in the United States.

The above table compares both volumes and prices received for oil and natural gas for the twelve months ended December 31, 2006 and 2005. Oil and natural gas prices are and probably will continue to be extremely volatile and a significant change will have a material impact on our revenue.

We had no loss on commodity derivatives for the years ended December 31, 2006 and 2005.

Costs and expenses

Lease operating

Lease operating expense was $10.9 million, or $14.75 per BOE produced for the twelve months ended December 31, 2006, as compared to $8.2 million, or $13.13 per BOE produced for the comparable period in 2005. This increase is primarily due to increased operating costs in France, the start of production in Romania and higher costs associated with the age of our fields.

Exploration expense

Exploration expense for the twelve months ended December 31, 2006 was $3.9 million, as compared to $2.9 million for the comparable period in 2005. This change is primarily due to increased activity in Hungary and Romania in interpreting data in order to evaluate drilling locations for 2007.

Dry hole and abandonment

Dry hole and abandonment cost for the twelve months ended December 31, 2006 was $3.1 million, as compared to $1.7 million in 2005. This is primarily due to the drilling of a dry hole in Hungary.

Depreciation, depletion and amortization.

For the twelve months ended December 31, 2006 depreciation, depletion and amortization expense was $7.5 million, or $10.17 per BOE produced, as compared to $5.2 million, or $8.40 per BOE produced for the twelve months ended December 31, 2005. This increase is primarily due to the downward revision of proved reserves in the United States and France of approximately 1.1 MBOE of proved reserves.

Impairment of oil and natural gas properties

Impairment charged in 2006 was $345,000 compared to $110,000 in 2005. This increase was primarily due to the downward revisions of proved reserves in the United States.

General and administrative

General and administrative expense, not including stock compensation expense, was $7.2 million for the twelve months ended December 31, 2006, compared with $6.3 million for the comparable period of 2005. This increase is primarily due to increased personnel costs of $1.1 million, the Hungarian office which was opened in July 2005 of $310,000 and the costs of restating the financial statements for the years ended December 31, 2003, 2004 and 2005 and the quarters ended March 31, 2006 and June 30, 2006 of approximately $820,000. These were reduced by an increase in the amounts allocated to development projects and exploration expense of approximately $1.7 million

Stock compensation expense

Stock compensation expense was $2.7 million for the twelve months ended December 31, 2006, compared with $401,000 for the comparable period of 2005. The increase is due to the restricted stock granted by the Board of Directors to certain employees, consultants and non-employee directors and the expensing of stock options as required by the adoption of SFAS 123 (R).

Other income and expense

Other income and expense resulted in income of $0.9 million for the twelve months ended December 31, 2006 versus income of $4 million in 2005. This decrease is primarily due to foreign exchange losses in Hungary and Turkey.

Discontinued operations

On March 12, 2004, pursuant to the terms of an Agreement for Purchase and Sale dated December 17, 2003, Toreador and Tormin, Inc., a wholly owned subsidiary of Toreador, sold their United States mineral and royalty assets to Black Stone Acquisitions Partners I, L.P. The gross consideration was approximately $45 million cash. The effective date of the sale was January 1, 2004.

The revenue received and the cost incurred after the effective date were due to adjustments made by the operator prior to the effective date of the sale. We do not have any involvement with the properties sold.

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


	Twelve Months Ended December 31.
	2006		2005		2004
	(in thousands)
Revenues:
Oil and natural gas sales	$	11	$	63	$	139

Costs and expenses:
Lease operating		—		1		(10	)
Allocated general and administrative		—		15		163

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

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

Income from discontinued operations	$	11	$	47	$	17,690

Provision for income taxes

At December 31, 2006, it was “unlikely” that the United States parent entity, Toreador Resources Corporation, would be able to generate sufficient future taxable income to utilize $1.2 million of a $6.3 million net operating loss carryforward. We therefore established a valuation allowance of $1.2 million which resulted in an increase to the provision for income taxes.

Income available to common shares

For the twelve months ended December 31, 2006, we reported income from continuing operations net of taxes of $2.6 million, compared with income of $10.5 million for the same period of 2005. For the twelve months ended December 31, 2006 income available to common shares was $2.4 million versus $9.9 million for the year ended December 31, 2005.

Other comprehensive income

The most significant element of comprehensive income, other than net income, is foreign currency translation. As of December 31, 2005, we had accumulated an unrealized loss of $3.4 million. In the year ended December 31, 2006, we had an unrealized gain of $7.6 million. The functional currency of our operations in France is the Euro and in Romania, Turkey and Hungary the functional currency is the United States Dollar. The exchange rates used to translate the financial position of the French, Turkish, Romanian and Hungarian operations at December 31, 2006 and 2005 are shown below:


	December 31,
	2006		2005		2004
Euro	$	1.3170	$	1.1797	$	1.3621


New Turkish Lira	$	0.7065	$	0.7408	$	0.7418


Romania Lei	$	0.3886	$	0.3508	$	—


Hungarian Forint	$	0.0052	$	0.0047	$	—

Comparison of Years Ended December 31, 2005 and 2004


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

Total		529		538	Total	$	50.17	$	35.24

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

Total		570		546	Total	$	7.56	$	5.81

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

Total		624		629	Total	$	49.86	$	34.90

Revenues

Oil and natural gas sales

Oil and natural gas sales for the twelve months ended December 31, 2005 were $31.1 million, as compared to $22.3 million for the comparable period in 2004. This increase is primarily due to a significant increase in the average realized price of both oil and natural gas. Production decreased by approximately 5 MBOE due primarily to normal declines in our oil and gas properties in the US and in Turkey, offset by a slight increase in France from the results of successful workovers and new drilling.

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

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

Costs and expenses

Lease operating

Lease operating expense was $8.2 million, or $13.13 per BOE produced for the twelve months ended December 31, 2005, as compared to $7.4 million, or $11.76 per BOE produced for the comparable period in 2004. This increase is primarily due to the workover program in France and a 5 MBOE decline in production when comparing the twelve months ended December 31, 2005 to 2004.

Exploration expense

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

Dry hole and abandonment

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

Depreciation, depletion and amortization.

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

Impairment of oil and natural gas properties

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

General and administrative

General and administrative expense was $6.7 million for the twelve months ended December 31, 2005, compared with $7.5 million for the comparable period of 2004. The decrease is primarily due to allocating a portion of Turkey’s cost to the development project and exploration expense of $2.4 million. This decrease is partially offset by an increase in the United States primarily due to increased staff of approximately $121,000, Sarbanes-Oxley compliance of approximately $238,000, legal expenses of $175,000, professional fees of $167,000, data processing fees of $123,000 and expensing of stock compensation expense related to the restricted stock granted by the Board of Directors to certain employees, consultants and non employee directors of approximately $401,000.

Other income and expense

Other income and expense resulted in income of $4 million for the twelve months ended December 31, 2005 versus a loss of $790,000 for the comparable period in 2004. The increase was primarily due to a $2.4 million foreign currency exchange gain in 2005 versus a foreign exchange gain of $127,000 in 2004. In 2005 we incurred $1.4 million in interest expense, of which all was capitalized to oil and gas properties, compared to $1.9 million of

interest expense in 2004, of which $432,000 was capitalized to oil and gas properties. Also in 2005 we recorded interest income of $1.4 million as compared to $515,000 in 2004.

Income available to common shares

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

Other comprehensive income

The most significant element of comprehensive income, other than net income, is foreign currency translation. As of December 31, 2004, we had accumulated an unrealized gain of $4.7 million. In the year ended December 31, 2005, we had an unrealized loss of $8.1 million. The primary reason for decrease is due to the strength of the Euro compared to the United States Dollar in 2005. The functional currency of our operations in France is the Euro and in Romania, Turkey and Hungary the functional currency is the United States Dollar.

Selected Quarterly Financial Data (Unaudited)

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


	Three Months Ended
	March		June		September		December
	31,		30,		30,		31,
	(in thousands, except per share data)
For the year ended December 31, 2006:
Total revenues	$	9,769	$	10,303	$	10,726	$	9,589
Total costs and expenses		7,298		7,502		7,418		12,848
Income (loss) from continuing operations		3,148		1,573		5,461		(7,615	)
Income (loss) from discontinued operations, net of tax		—		—		11		—
Net income (loss)		3,148		1,573		5,472		(7,615	)
Income (loss) available to common shares		3,107		1,532		5,432		(7,655	)
Basic income (loss) available to common shares per share		0.20		0.10		0.35		(0.49	)
Diluted income (loss) available to common shares per share		0.19		0.09		0.33		(0.49	)

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

Off Balance Sheet Arrangements

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

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 Amended 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

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

We carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and our Vice President — Finance & Accounting and Chief Accounting Officer, who is our principal financial 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 and our Vice President — Finance & Accounting and Chief Accounting Officer concluded that, as a result of the material weaknesses discussed below, our disclosure controls and procedures as of December 31, 2006 were not effective.

Management’s Annual Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as that term is defined in Securities Exchange Act of 1934 Rule 13a-15(f) and 15d-15(f). Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting principles. Our control environment is the foundation for our system of internal control over financial reporting and is an integral part of our Code of Ethical Conduct and Business Practices which sets the tone of our Company. Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect our transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of our financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.

In order to evaluate the effectiveness of our internal control over financial reporting as of December 31, 2006, as required by Section 404 of the Sarbanes-Oxley Act of 2002, our management conducted an assessment, including testing, based on the criteria set forth inInternal Control—Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO Framework”). Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. In addition, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.

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

The following material weaknesses are the basis for our conclusion at December 31, 2006:

•

We did not maintain an effective control environment and our financial and accounting organization was not adequate to support our financial reporting requirements. The involvement of corporate personnel in

			the reporting of foreign transactions and operations was not sufficient to accurately capture and record such activity and we did not maintain a sufficient complement of personnel with an appropriate level of accounting knowledge, experience and training in the application of generally accepted accounting principles consistent with the level and complexity of our operations. The Company also did not have an adequate review and approval process for recorded journal entries and changes made to the general ledger.

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

Based on our assessment, and because of the material weaknesses described above, management has concluded that our internal control over financial reporting was not effective as of December 31, 2006 to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes in accordance with generally accepted accounting principles.

Grant Thornton LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Company included in this Amended Annual Report on Form 10-K/A, has issued an audit report on management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006. The report, dated March 16, 2007, which expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an opinion that the Company had not maintained effective internal control over financial reporting as of December 31, 2006 based on criteria established inInternal Control-Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) is included below.

Changes in Internal Controls

There were no changes in our internal control over financial reporting during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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

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

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

	•		Providing additional training to our accounting staff and acquiring other accounting resources to improve our financial reporting.

	•		Formally documenting our accounting policies and procedures.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Shareholders
Toreador Resources Corporation

We have audited management’s assessment, included in the accompanying “Management’s Annual Report on Internal Control Over Financial Reporting,” that Toreador Resources Corporation and subsidiaries (the “Company”) did not maintain effective internal control over financial reporting as of December 31, 2006, because of the effect of material weakness identified in management’s assessment,based on criteria established inInternal Control—Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. The following material weakness has been identified and included in management’s assessment.

	•		The Company did not maintain an effective control environment and its financial and accounting organization was not adequate to support its financial reporting requirements. The involvement of corporate personnel in the reporting of foreign transactions and operations was not sufficient to accurately capture and record such activity and it did not maintain a sufficient complement of personnel with an appropriate level of accounting knowledge, experience and training in the application of generally accepted accounting principles consistent with the level and complexity of its operations. The Company also did not have an adequate review and approval process for recorded journal entries and changes made to the general ledger.

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

These material weakness were considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2006 financial statements, and this report does not affect our report dated March 16, 2007, which expressed an unqualified opinion on those financial statements.

In our opinion, management’s assessment that the Company did not maintain effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on criteria established inInternal Control—Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission.Also in our opinion, because of the effect of the material weakness described above on the achievement of the objectives of the control criteria, the Company has not maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established inInternal Control—Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission.

/s/ GRANT THORNTON LLP

Dallas, Texas
March 16, 2007

PART IV

ITEM 15. Exhibits and Financial Statement Schedules.

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

Index to Consolidated Financial Statements, Reports of Independent Registered Public Accounting Firm, Consolidated Balance Sheets as of December 31, 2006 and 2005, Consolidated Statements of Operations and Comprehensive Income for the three years in the period ended December 31, 2006, Consolidated Statements of Changes in Stockholders’ Equity for each of the three years in the period ended December 31, 2006, Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 2006, and Notes to Consolidated Financial Statements.

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



July 23, 2007	/s/ Nigel J. Lovett
	Nigel J. Lovett, President and Chief Executive Officer



July 23, 2007	/s/ Charles J. Campise
	Charles J. Campise, Vice President — Finance & 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 November 1, 2002, among Toreador Resources Corporation and persons party thereto (previously filed as Exhibit 4.5 to Toreador Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2002, File No. 0-2517, and incorporated herein by reference).

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


EXHIBIT
NUMBER		DESCRIPTION

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

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

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

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

5.1*		Legal Opinion of Gunel & Kaya

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).


EXHIBIT
NUMBER		DESCRIPTION

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

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

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

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

10.12+	—	Amendment to Toreador Resources Corporation 2005 Long-Term Incentive Plan (previously filed as Exhibit 10.1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on May 12, 2006, File No. 0-2517, and incorporated herein by reference).

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

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

10.15+	—	Form of 2006 Outside Director Restricted Stock Award (previously filed as Exhibit 10.3 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on May 12, 2006, File No. 0-2517, and incorporated herein by reference).

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

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

10.18+	—	Summary of Amendment to Restricted Stock Award Agreement of Thomas P. Kellogg, dated April 6, 2006 (previously filed as Exhibit 10.1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on April 12, 2006, File No. 0-2517, and incorporated herein by reference).

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

10.20+	—	Summary Sheet: 2006 Non-Employee Director Equity Compensation (previously filed as Exhibit 10.2 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on May 12, 2006, File No. 0-2517, and incorporated herein by reference).


EXHIBIT
NUMBER		DESCRIPTION

10.21+	—	Summary Sheet: 2007 Director Compensation (previously filed as Exhibit 10.21 to Toreador Resources Corporation Annual Report on Form 10-K filed with the Securities and Exchange Commission on March 16, 2007, File No. 0-2517, and incorporated herein by reference).

10.22+	—	Michael FitzGerald Employee Restricted Stock Award Agreement dated May 30, 2006 (previously filed as Exhibit 10.1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on June 5, 2006, File No. 0-2517, and incorporated herein by reference).

10.23+	—	Ed Ramirez Employee Restricted Stock Award Agreement dated May 30, 2006 (previously filed as Exhibit 10.2 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on June 5, 2006, File No. 0-2517, and incorporated herein by reference).

10.24+	—	Michael J. FitzGerald Change in Control Agreement dated November 8, 2006 (previously filed as Exhibit 10.1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on November 15, 2006, File No. 0-2517, and incorporated herein by reference).

10.25+	—	Herbert C. Williamson III Restricted Stock Award Agreement dated November 8, 2006 (previously filed as Exhibit 10.25 to Toreador Resources Corporation Annual Report on Form 10-K filed with the Securities and Exchange Commission on March 16, 2007, File No. 0-2517, and incorporated herein by reference).

10.26+	—	Nigel Lovett Restricted Stock Award Agreement dated November 8, 2006 (previously filed as Exhibit 10.26 to Toreador Resources Corporation Annual Report on Form 10-K filed with the Securities and Exchange Commission on March 16, 2007, File No. 0-2517, and incorporated herein by reference).

10.27+	—	Nicholas Rostow Restricted Stock Award Agreement dated November 8, 2006 (previously filed as Exhibit 10.27 to Toreador Resources Corporation Annual Report on Form 10-K filed with the Securities and Exchange Commission on March 16, 2007, File No. 0-2517, and incorporated herein by reference).

10.28+	—	Letter Agreement by and between Toreador Resources Corporation and G. Thomas Graves III, dated January 25, 2007 (previously filed as Exhibit 10.1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on January 26, 2007, File No. 0-2517, and incorporated herein by reference).

10.29+	—	Summary Sheet: 2007 Nigel Lovett’s Annual Base Salary (previously filed as Exhibit 10.2 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on January 26, 2007, File No. 0-2517, and incorporated herein by reference).

10.30+	—	Summary Sheet: 2007 Executive Officer Base Salaries (previously filed as Exhibit 10.1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on January 31, 2007, File No. 0-2517, and incorporated herein by reference).

10.31+	—	G. Thomas Graves III Stock Award Agreement dated January 25, 2007 (previously filed as Exhibit 10.31 to Toreador Resources Corporation Annual Report on Form 10-K filed with the Securities and Exchange Commission on March 16, 2007, File No. 0-2517, and incorporated herein by reference).

10.32+	—	Summary Sheet: 2007 Short-Term Incentive Compensation Plan (previously filed as Exhibit 10.1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on February 12, 2007, File No. 0-2517, and incorporated herein by reference).

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


EXHIBIT
NUMBER		DESCRIPTION

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

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

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

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

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

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

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

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

10.42		Loan and Guarantee Agreement dated December 28, 2006 by and among Toreador Resources Corporation, as Guarantor, Toreador Turkey Ltd. as Borrower and Guarantor, Toreador Romania Ltd, a Borrower and Guarantor, Madison Oil France SAS, as Borrower and Guarantor, Toreador Energy France S.C.S., as Borrower and Guarantor, Toreador International Holding L.L.C., as Guarantor, and International Finance Corporation (previously filed as Exhibit 10.2 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on January 4, 2007, File No. 0-2517, and incorporated herein by reference).

10.43		Security Agreement dated February 21, 2007 (signed by Toreador Resources on February 27, 2007) by and between Toreador Resources Corporation, as Assignor, and International Finance Corporation, as Assignee (previously filed as Exhibit 10.43 to Toreador Resources Corporation Annual Report on Form 10-K filed with the Securities and Exchange Commission on March 16, 2007, File No. 0-2517, and incorporated herein by reference).


EXHIBIT
NUMBER		DESCRIPTION

10.44		Quota Charge Agreement dated February 28, 2007 by and between Toreador Resources Corporation, as Charger, and International Finance Corporation, as Chargee (previously filed as Exhibit 10.44 to Toreador Resources Corporation Annual Report on Form 10-K filed with the Securities and Exchange Commission on March 16, 2007, 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 filed with the Securities and Exchange Commission on March 16, 2007, File No. 0-2517, and incorporated herein by reference).

16.1		Letter on Change in Certifying Accountant from Hein &Associates LLP dated May 25, 2006 (previously filed as Exhibit 16.1 to Toreador Resources Corporation Current Report on Form 8-K filed with the Securities and Exchange Commission on May 26, 2006, File No. 0-2517, and incorporated herein by reference).

21.1	—	Subsidiaries of Toreador Resources Corporation (previously filed as Exhibit 21.1 to Toreador Resources Corporation Annual Report on Form 10-K filed with the Securities and Exchange Commission on March 16, 2007, File No. 0-2517, and incorporated herein by reference).

23.1*	—	Consent of Grant Thornton LLP

23.2*	—	Consent of LaRoche Petroleum Consultants, Ltd.

23.3*		Consent of Gunel & Kaya, included as part of Exhibit 5.1

24.1	—	Power of Attorney (previously filed as part of the signature page to Toreador Resources Corporation Annual Report on Form 10-K filed with the Securities and Exchange Commission on March 16, 2007, File No. 0-2517, and incorporated herein by reference) (included as part of the signature page).

31.1*	—	Certification of Chief Executive Officer (Principal 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 Vice President — Finance & Accounting and Chief Accounting Officer (Principal Financial Officer) pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1*	—	Certification of Chief Executive Officer (Principal Executive Officer) and Vice President — Finance & Accounting and Chief Accounting Officer (Principal Financial Officer) pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

99.1*		French Ministry Documentation

99.2*		Hungarian Mining Law Summary

99.3*		Portions of Hungarian Mining Act

99.4*		Portions of Governmental Decree Implementing the Hungarian Mining Act


*		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

Consolidated Balance Sheets as of December 31, 2006 and 2005		F-3

Consolidated Statements of Operations and Comprehensive Income for each of the three years in the period ended December 31, 2006		F-4

Consolidated Statements of Changes in Stockholders’ Equity for each of the three years in the period ended December 31, 2006		F-5

Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 2006		F-6

Notes to Consolidated Financial Statements		F-7

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders
Toreador Resources Corporation

We have audited the accompanying consolidated balance sheets of Toreador Resources Corporation (a Delaware Corporation) and subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of operations and comprehensive income, changes in stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2006. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Toreador Resources Corporation and subsidiaries as of December 31, 2006 and 2005 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the consolidated financial statements, effective January 1, 2006, the Company changed its method of accounting for stock-based compensation to conform to Statement of Financial Accounting Standards No. 123 (R),Share-Based Payment.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Toreador Resources Corporation and subsidiaries’ internal control over financial reporting as of December 31, 2006, based on criteria established inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 16, 2007, expressed an unqualified opinion on management’s assessment of the effectiveness of internal control over financial reporting and an adverse opinion on the effectiveness of internal control over financial reporting.

/s/ Grant Thornton LLP

Dallas, Texas
March 16, 2007

F-2

TOREADOR RESOURCES CORPORATION

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


	December 31,
	2006			2005
ASSETS
Current assets:
Cash and cash equivalents	$	12,664		$	53,113
Restricted cash		20,504			—
Short-term investments		—			40,000
Accounts receivable		9,547			8,162
Income taxes receivable		1,260			4,453
Other		8,445			6,537

Total current assets		52,420			112,265


Oil and natural gas properties, net, using successful efforts method of accounting		251,015			138,158
Investments in unconsolidated entities		2,659			2,251
Goodwill		4,551			4,195
Other assets		6,559			4,945

	$	317,204		$	261,814

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	33,827		$	19,248
Current portion of long-term debt		5,000			—
Convertible debenture — related party		—			810
Income taxes payable		745			908

Total current liabilities		39,572			20,966


Long-term accrued liabilities		394			1,410
Long-term debt, net of current portion		21,550			5,000
Long-term asset retirement obligations		5,125			3,630
Deferred income tax liabilities		17,162			12,199
Convertible subordinated notes		86,250			86,250

Total liabilities		170,053			129,455

Commitments and contingencies
Stockholders’ equity:
Preferred stock, Series A-1, $1.00 par value, 4,000,000 shares authorized; liquidation preference of $1,800; 72,000 shares issued		72			72
Common stock, $0.15625 par value, 30,000,000 shares authorized;16,655,511 and 16,142,824 shares issued		2,602			2,522
Additional paid-in capital		111,708			108,001
Retained earnings		31,980			29,564
Accumulated other comprehensive income (loss)		3,323			(3,364	)
Deferred compensation		—			(1,902	)
Treasury stock at cost, 721,027 shares		(2,534	)		(2,534	)

Total stockholders’ equity		147,151			132,359

	$	317,204		$	261,814

See accompanying notes to the consolidated financial statements

F-3

TOREADOR RESOURCES CORPORATION

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


	Year ended December 31,
	2006			2005			2004
Revenue:
Oil and natural gas sales	$	40,387		$	31,117		$	22,336
Loss on commodity derivatives		—			—			(1,322	)
Lease bonuses and rentals		—			—			14

Total revenue		40,387			31,117			21,028

Operating costs and expenses:
Lease operating expense		10,941			8,198			7,399
Exploration expense		3,946			2,940			4,530
Dry hole and abandonment		3,099			1,738			—
Depreciation, depletion and amortization		7,544			5,245			4,110
Impairment of oil and natural gas properties		345			110			—
General and administrative		9,829			6,680			7,463
(Gain) loss on sale of properties and other assets		(638	)		(12	)		159

Total operating costs and expenses		35,066			24,899			23,661

Operating income (loss)		5,321			6,218			(2,633	)
Other income (expense):
Equity in earnings (loss) of unconsolidated investments		401			222			(18	)
Foreign currency exchange gain (loss)		(605	)		2,386			127
Interest and other income		1,988			1,407			515
Interest expense		(891	)		—			(1,414	)

Total other income (expense)		893			4,015			(790	)

Income (loss) from continuing operations before income taxes		6,214			10,233			(3,423	)
Income tax benefit (provision)		(3,647	)		315			1,153

Income (loss) from continuing operations		2,567			10,548			(2,270	)
Income from discontinued operations		11			47			17,690

Net income		2,578			10,595			15,420
Preferred dividends		(162	)		(684	)		(714	)

Income available to common shares	$	2,416		$	9,911		$	14,706

Basic income available to common shares per share from:
Continuing operations	$	0.16		$	0.69		$	(0.31	)
Discontinued operations		—			—			1.85

	$	0.16		$	0.69		$	1.54


Diluted income available to common shares per share from:
Continuing operations	$	0.15		$	0.65		$	(0.31	)
Discontinued operations		—			—			1.85

	$	0.15		$	0.65		$	1.54


Weighted average shares outstanding:
Basic		15,527			14,213			9,571
Diluted		15,884			15,140			9,571
Statement of Comprehensive Income
Net income	$	2,578		$	10,595		$	15,420
Foreign currency translation adjustments		6,687			(8,080	)		2,885

Comprehensive income	$	9,265		$	2,515		$	18,305

See accompanying notes to the consolidated financial statements.

F-4

TOREADOR RESOURCES CORPORATION

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


																	Accumulated
	Preferred			Preferred			Common		Common		Additional						Other			Treasury						Total
	Stock			Stock			Stock		Stock		Paid-in			Retained			Comprehensive			Stock			Deferred			Stockholders’
	(Shares)			($)			(Shares)		($)		Capital			Earnings			Income (loss)			($)			Compensation			Equity
Balance at December 31, 2003		320		$	320			10,059	$	1,572	$	33,462		$	4,947		$	1,831		$	(2,534	)	$	—		$	39,598
Cash payment of preferred dividends		—			—			—		—		—			(714	)		—			—			—			(714	)
Issuance of stock options for professional services		—			—			—		—		58			—			—			—			—			58
Conversion of preferred stock		(166	)		(166	)		1,037		162		4			—			—			—			—			—
Conversion of convertible debenture		—			—			100		16		659			—			—			—			—			675
Exercise of stock options		—			—			528		82		2,228			—			—			—			—			2,310
Tax benefit of stock option exercises		—			—			—		—		1,113			—			—			—			—			1,113
Net income		—			—			—		—		—			15,420			—			—			—			15,420
Foreign currency translation adjustment		—			—			—		—		—			—			2,885			—			—			2,885

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

Balance at December 31, 2005		72			72			16,143		2,522		108,001			29,564			(3,364	)		(2,534	)		(1,902	)		132,359
Transfer deferred compensation to additional paid-in capital		—			—			—		—		(1,902	)		—			—			—			1,902			—
Cash payment of preferred dividends		—			—			—		—					(162	)		—			—			—			(162	)
Conversion of convertible debenture		—			—			120		19		791			—			—			—			—			810
Exercise of stock options		—			—			175		27		839			—			—			—			—			866
Issuance of restricted stock		—			—			214		33		(33	)		—			—			—			—			—
Exercise of warrants		—			—			4		1		33			—			—			—			—			34
Issuance of warrants		—			—			—		—		883			—			—			—			—			883
Tax benefit of stock option exercises		—			—			—		—		293			—			—			—			—			293
Stock option expense		—			—			—		—		66			—			—			—			—			66
Amortization of deferred stock compensation		—			—			—		—		2,737			—			—			—			—			2,737
Net income		—			—			—		—					2,578			—			—			—			2,578
Foreign currency translation adjustments		—			—			—		—		—			—			6,687			—			—			6,687

Balance at December 31, 2006		72		$	72			16,656	$	2,602	$	111,708		$	31,980		$	3,323		$	(2,534	)	$	—		$	147,151

See accompanying notes to the consolidated financial statements.

F-5

TOREADOR RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)


	Year Ended December 31
	2006			2005			2004
Cash flows from operating activities:
Net Income	$	2,578		$	10,595		$	15,420
Adjustments to reconcile net income to net cash provided by (used in) operating activities
Depreciation and amortization		7,544			5,245			4,110
Amortization of deferred debt issuance cost		—			—			383
Issuance of warrants to non-employee		107
Impairment of oil and natural gas properties		345			110			—
Dry hole and abandonment costs		3,099			1,738			—
Deferred income taxes		2,642			93			2,556
Unrealized gain on commodity derivatives		—			—			(1,159	)
Gain on sale of properties and equipment		(638	)		(12	)		(28,552	)
Equity in (earnings) loss of unconsolidated investments		(401	)		(222	)		18
Stock-based compensation		2,803			400			58
Gain on sale of marketable securities		—			—			20
Change in operating assets and liabilities, net of acquisitions
Increase in accounts receivable		(1,027	)		(4,304	)		(520	)
Increase in income taxes receivable		(655	)		(4,453	)		—
Increase in other assets		(4,596	)		(9,740	)		(931	)
Increase in accounts payable and accrued liabilities		(1,322	)		1,097			(360	)
Increase (decrease) in income taxes payable		3,625			(685	)		780

Net cash provided by (used in) operating activities		14,104			(138	)		(8,177	)

Cash flows from investing activities:
Expenditures for property and equipment		(105,165	)		(50,163	)		(10,911	)
Restricted cash		(20,504	)		—			—
Net cash for acquisitions		—			(8,751	)		—
Proceeds from the sale of properties and equipment		1,672			29			42,125
Distributions from unconsolidated entities		250			191			255
Sale (purchase) of short-term investments		40,000			(40,000	)		—
Investments in unconsolidated entities		(257	)		(754	)		(1,210	)

Net cash provided by (used in) investing activities		(84,004	)		(99,448	)		30,259

Cash flows from financing activities:
Repayment of revolving credit facilities		(5,000	)		(4,848	)		(28,816	)
Net borrowings (repayments) under revolving credit arrangements		26,550			9,811			37
Exercise of stock options		866			2,552			2,310
Proceeds from the exercise of warrants		34			170			—
Proceeds from issuance of common stock, net of issuance cost of $3,940		—			55,918			—
Tax benefit related to stock options		293			—			—
Proceeds from issuance of notes payable		—			86,250			7,500
Payment of preferred dividends		(162	)		(186	)		(714	)

Net cash provided by (used in) financing activities		22,581			149,667			(19,683	)

Net increase (decrease) in cash and cash equivalents		(47,319	)		50,081			2,399
Effects of foreign currency translation on cash and cash equivalents		6,870			(1,945	)		(241	)
Cash and cash equivalents, beginning of year		53,113			4,977			2,819

Cash and cash equivalents, end of year	$	12,664		$	53,113		$	4,977

Supplemental disclosures:
Cash paid during the period for interest, net of interest capitalized	$	—		$	—		$	1,304
Cash paid during the period for income taxes	$	2,414		$	2,690		$	5,250
Non-cash investing and financing activities
Conversion of preferred stock to common stock		—			82			166
Conversion of notes payable to common stock		—			6,413			—
Conversion of convertible debentures to common stock		810			675			675
Common shares issued for preferred dividends		—			498			—

See accompanying notes to the consolidated financial statements.

F-6

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 — DESCRIPTION OF BUSINESS

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

BASIS OF PRESENTATION

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

In January 2004, we sold our U.S. mineral and royalty assets to Black Stone Acquisitions Partners I, L.P. (“Royalty Sale”). We retained all of our working-interest properties. From the approximate $45.0 million cash consideration ($41.9 million net of transaction costs) that we received, we discharged our outstanding credit facilities. The financial results for those assets sold are classified as discontinued operations in the accompanying financial statements. Certain prior-year amounts have been reclassified to conform to the 2006 presentation. See further discussion in Note 15 to the consolidated financial statements.

NOTE 2 — SIGNIFICANT ACCOUNTING POLICIES

USE OF ESTIMATES

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

The Company’s estimates of crude oil and natural gas reserves are the most significant estimates used. All of the reserve data in the Form 10-K for the year ended December 31, 2006 are estimates. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may be different from the quantities of crude oil and natural gas that are ultimately recovered.

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

CASH AND CASH EQUIVALENTS AND SHORT-TERM INVESTMENTS

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

As of December 31, 2005 we had $40 million in time deposits bearing interest at 2.87%. Upon maturity in 2006, we transferred these funds to our operating account.

As of December 31, 2006 and 2005 we had $11.2 million and $6.5 million, respectively, on deposit in foreign banks.

F-7

RESTRICTED CASH

Restricted cash consists of $11.5 million held by a bank in the form of certificates of deposit as collateral for a “Stand-by Letter of Credit” required by the contractor for the installation on the offshore pipeline in the Black Sea; $7.8 million deposit used to secure a bank “Letter of Guarantee” that was issued as required under the mediation proceedings with Micoperi, Srl. and $1.2 million is a compensating cash balance as required by our credit facility with Natexis Bank. The total amount of $20.5 million is on deposit in foreign banks.

CONCENTRATION OF CREDIT RISK AND ACCOUNTS RECEIVABLE

Financial instruments that potentially subject us to a concentration of credit risk consist principally of cash, accounts receivable, and our hedging and derivative financial instruments. We place our cash with high credit quality financial institutions. We sell oil and natural gas to various customers. Historically, we have not experienced any losses related to accounts receivable, and accordingly, we do not believe an allowance for doubtful accounts is warranted either at December 31, 2006 or 2005. Substantially all of our accounts receivable are due from purchasers of oil and natural gas. We place our hedging and derivative financial instruments with financial institutions and other firms that we believe have high credit ratings. For a discussion of the credit risks associated with our hedging activities, please see “Derivative Financial Instruments” below.

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

FINANCIAL INSTRUMENTS

The carrying amounts of financial instruments including cash and cash equivalents, short-term investments, accounts receivable, accounts payable and accrued liabilities approximate fair value, at December 31, 2006 and 2005, due to the short-term nature or maturity of the instruments.

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

On December 31, 2006 the convertible subordinate notes which had a book value of $86.25 million, were trading at $1,005.80, which would equal a fair market value of approximately $86.8 million.

DERIVATIVE FINANCIAL INSTRUMENTS

In 2004, we used various swap and option contracts to (i) reduce the effect of the volatility of price changes on the commodities we produce and sell; and (ii) support our annual capital budgeting and expenditure plans. In order to accomplish this objective, in 2004 we periodically entered into oil and natural gas swap and option agreements that fixed the price of oil and natural gas sales within ranges determined acceptable at the time we execute the contracts. Losses from these financial instruments totaled $63,000 in 2004. We did not enter into any commodity contracts in 2006 or 2005.

In 2006, we purchased and sold 6 foreign currency forward contracts for Turkish Lira, two foreign currency forward contracts for Euros and two call options to purchase Euros.The contracts were purchased primarily to protect our exposure to foreign exchange changes in France and Turkey. When these contracts were settled we recognized a loss of approximately $464,000 that was recorded to foreign exchange gain (loss) on the Statement of Operations.

We are exposed to credit losses on derivative financial instruments in the event of nonperformance by the counterparties to our financial instruments. We anticipate, however, that such counterparties will be able to fully satisfy their obligations under the contracts. We do not obtain collateral or other security to support financial instruments subject to credit risk but we monitor the credit standing of the counterparties. At December 31, 2006 and 2005, we had no receivables from counterparties.

F-8

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

INVENTORIES

At December 31, 2006 and 2005, other current assets included $1.2 million, and $951,000 of inventory, respectively. Those amounts consist of tubular goods and crude oil held in storage tanks. Inventories are stated at the lower of actual cost or market based on the average cost method.

ADVANCES PAID TO VENDORS

At December 31, 2006 and 2005, other current assets included $3.8 million and $1.4 million of payments made to vendors in advance of performing the services or receiving the equipment.

OIL AND NATURAL GAS PROPERTIES

We follow the successful efforts method of accounting for oil and natural gas exploration and development expenditures. Under this method, costs of successful exploratory wells and all development wells are capitalized. Costs to drill exploratory wells that do not find proved reserves are expensed. Significant costs associated with the acquisition of oil and natural gas properties are capitalized. Upon sale or abandonment of units of property or the disposition of miscellaneous equipment, the cost is removed from the asset account, net of the accumulated depreciation or depletion, and the gain or loss is credited to or charged against operations.

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

We capitalize interest on major projects that require an extended period of time to complete. Interest capitalized in 2006, 2005 and 2004 was $4.3 million, $1.4 million, and $432,000, respectively.

We record furniture, fixtures and equipment at cost.

DEPRECIATION, DEPLETION AND AMORTIZATION

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

IMPAIRMENT OF ASSETS

We evaluate producing property costs for impairment and reduce such costs to fair value if the sum of expected undiscounted future cash flows is less than net book value pursuant to Statement of Financial Accounting Standard No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“Statement 144”). We assess impairment of non-producing leasehold costs and undeveloped mineral and royalty interests periodically on a property-by-property basis. We charge any impairment in value to expense in the period incurred. We incurred impairment losses on our United States oil and natural gas producing properties of $345,000 in 2006, $110,000 in 2005 and zero in 2004.

ASSET RETIREMENT OBLIGATIONS

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

F-9

The following table summarizes the changes in our asset retirement liability during the years ended December 31, 2006 and 2005:


	2006			2005
	(in thousands)
Asset retirement obligation January 1	$	3,630		$	3,291
Asset retirement accretion expense		246			204
Foreign currency exchange (gain) loss		325			(407	)
Change in estimates		61			—
Property additions		875			542
Property dispositions		(12	)		—

Asset retirement obligation at December 31	$	5,125		$	3,630

GOODWILL

We account for goodwill in accordance with Statement of Financial Accounting Standards No. 142,“Goodwill and Other Intangible Assets”(“Statement 142”). Under Statement 142, goodwill and indefinite-lived intangible assets are not amortized but are reviewed annually (or more frequently if impairment indicators arise) for impairment. Separable intangible assets that are not deemed to have an indefinite life are amortized over their useful lives. At December 31, 2006 and 2005, we did not have any intangible assets that did not have an indefinite life.

We review annually the value of goodwill recorded or more frequently if impairment indicators arise. We recognized no goodwill impairment during 2006, 2005 or 2004. Goodwill was reduced by $1.5 million and $1.6 million in 2004 and 2005, respectively, for a corresponding reduction in deferred tax liabilities which resulted from the recognition of prior Madison Oil Company net operating losses that were reserved at the date of acquisition. Goodwill was also adjusted $356,000 in 2006 and $211,000 in 2005 for the foreign currency translation adjustment. The balance of goodwill at December 31, 2006 and 2005 is approximately $4.6 million and $4.2 million, respectively.

REVENUE RECOGNITION

Our French crude oil production accounts for the majority of our sales. We sell our French crude oil to Elf Antar France S.A. (“ELF”), and recognize the related revenues when the production is delivered to ELF’s refinery, typically via truck. At the time of delivery to the plant, title to the crude oil transfers to ELF. The terms of the contract with ELF state that the price received for oil sold will be the arithmetic mean of all average daily quotations of Dated Brent published in Platt’s Oil Market Wire for the month of production less a specified differential per barrel. The pricing of oil sales is done on the first day of the month following the month of production. In accordance with the terms of the contract, payment is made within six working days of the date of issue of the invoice. The contract with ELF is automatically extended for a period of one year unless either party cancels it in writing no later than six months prior to the beginning of the next year. We periodically review ELF’s payment timing to ensure that receivables from ELF for crude oil sales are collectible. In 2006, 2005 and 2004 sales to ELF represents approximately 67%, 66% and 63%, respectively, of the Company’s total revenue and approximately 20% and 23% of the Company’s accounts receivable at December 31, 2006 and 2005, respectively.

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

F-10

STOCK-BASED COMPENSATION

In December 2004, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 123 (revised 2004),“Share Based Payment,”(SFAS 123R). SFAS 123R establishes the accounting for transactions in which an entity pays for employee services in share-based payment transactions. SFAS 123R requires companies to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. The fair value of employee share options and similar instruments is estimated using option-pricing models adjusted for the unique characteristics of those instruments. That cost is recognized over the period during which an employee is required to provide service in exchange for the award. The Company adopted SFAS 123R effective January 1, 2006, using the modified-prospective transition method. Under this method, compensation cost is recognized for awards granted and for awards modified, repurchased or cancelled in the period after adoption. Compensation cost is also recognized for the unvested portion of awards granted prior to adoption. Prior year financial statements are not restated. The Company’s results for the year ended December 31, 2006, include an additional compensation expense of $65,916, that is included in general and administrative expenses relating to the adoption of SFAS 123R. Additionally, upon adoption of SFAS 123R, excess tax benefits related to stock option exercises of $293,000 were presented as a cash inflow from financing activities.

Prior to adoption of SFAS 123 R, the Company accounted for stock based compensation plans under APB Opinion No. 25“Accounting for Stock Issued to Employees.”Compensation cost related to stock options issued to employees was recorded only if the grant-date market price of the underlying stock exceeded the exercise price. The following table illustrates the effect on income available to common shares and earnings available to common shares per share if a fair value based method had been applied to all awards.


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

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


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

FOREIGN CURRENCY TRANSLATION

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

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ensure the functional currency of each entity is the currency of the primary economic environment in which we operate.

INCOME TAXES

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

LEGAL FEES

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

DEFERRED DEBT ISSUE COST

Deferred debt issue costs are amortized on a straight line basis, which approximates the effective interest method over the term of the loan as a component of interest expense.

NEW ACCOUNTING PRONOUNCEMENTS

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5,“Accounting for Contingencies.”FSP EITF 00-19-2 is effective immediately for registration payment arrangements and the financial instruments subject to those arrangements that are entered into or modified subsequent to the date of its issuance. For registration payment arrangements and financial instruments subject to those arrangements that were entered into prior to the issuance of FSP EITF 00-19-2, this guidance shall be effective for financial statements issued for fiscal years beginning after December 15, 2006, and interim periods within those fiscal years. We do not expect this standard to have any effect upon adoption because the Company’s policy has been to accrue such liabilities when they are deemed probable.

In April 2005, the FASB issued FASB Staff Position (FSP) FAS 19-1“Accounting for Suspended Well Costs.”This staff position amends FASB Statement No. 19 “Financial Accounting and Reporting by Oil and Gas Producing Companies” and provides guidance about exploratory well costs to companies who use the successful efforts method of accounting. The position states that exploratory well costs should continue to be capitalized if: 1) a sufficient quantity of reserves are discovered in the well to justify its completion as a producing well and 2) sufficient progress is made in assessing the reserves and the well’s economic and operating feasibility. If the exploratory well costs do not meet both of these criteria, these costs should be expensed, net of any salvage value. Additional annual disclosures are required to provide information about management’s evaluation of capitalized exploratory well costs. In addition, the Staff Position requires the annual disclosure of: 1) net changes from period to period of capitalized exploratory well costs for wells that are pending the determination of proved reserves, 2) the amount of exploratory well costs that have been capitalized for a period greater than one year after the completion of drilling and 3) an aging of exploratory well costs suspended for greater than one year with the number of wells it related to. Further, the disclosures should describe the activities undertaken to evaluate the reserves and the projects, the information still required to classify the associated reserves as proved and the estimated timing for completing the evaluation. We adopted FAS 19-1 as of December 31, 2005.

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

On February 16, 2006, the FASB issued Statement 155,“Accounting for Certain Hybrid Instruments — an amendment of FASB Statements No. 133 and 140.”The statement amends Statement 133 to permit fair value measurement for certain hybrid financial instruments that contain an embedded derivative and provides additional guidance on the applicability of Statement 133 and 140 to certain financial instruments and subordinated concentrations of credit risk. The new standard is effective for the first fiscal year that begins after September 16, 2006. We have determined that the impact on our financial statements will not be material. We have adopted FASB 155 on January 1, 2007.

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

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

In February 2007, the FASB issued Statement 159,“The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement 115”.The statement permits entities to chosse to measure certain financial instruments and other items at fair value. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. Unrealized gains and losses on any items for which Toreador elects the fair value measurement option would be reported in earnings. Statement 159 is effective for fiscal years beginning after November 15, 2007. However, early adoption is permitted for fiscal years beginning on or before November 15, 2007, provided Toreador also elects to apply the provisions of Statement 157,“Fair Value Measurements”,at the same time. Toreador is currently assessing the effect, if any, the adoption of Statement 159 will have on its financial statements and related disclosures.

NOTE 3 — ACQUISITION

In June 2005, we acquired 100% of Pogo Hungary Ltd., a wholly owned subsidiary of Pogo Producing Company. The results of operations are included in our consolidated financial statements effective from the date of acquisition. Our results of operations would not have been different than reported and, therefore, we have not provided any pro forma disclosures. The purchase price was approximately $9 million, which was settled in cash and was allocated as follows (in thousands):


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

Total purchase price allocation	$	9,000

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NOTE 4 — EARNINGS PER SHARE

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


	Year ended December 31,
	2006			2005			2004
	(in thousands, except per share data)
Basic earnings per share:
Numerator
Income (loss) from continuing operations, net of income tax	$	2,567		$	10,548		$	(2,270	)
Less: dividends on preferred shares		162			684			714

Income (loss) from continuing operations, net of tax		2,405			9,864			(2,984	)
Income from discontinued operations, net of tax		11			47			17,690

Income available to common shares	$	2,416		$	9,911		$	14,706

Denominator
Common shares outstanding		15,527			14,213			9,571
Basic earnings available to common shares per share from:
Continuing operations	$	0.16		$	0.69		$	(0.31	)
Discontinued operations		—			—			1.85

Basic income per share	$	0.16		$	0.69		$	1.54

Diluted earnings per share:
Numerator
Income (loss) from continuing operations, net of income tax	$	2,567		$	10,548		$	(2,270	)
Less: dividends on preferred shares		162			684			714
Add: interest on convertible debentures					73			—

Income (loss) from continuing operations, net of tax		2,405			9,937			(2,984	)
Income (loss) from discontinued operations, net of tax		11			47			17,690

	$	2,416		$	9,984		$	14,706

Denominator
Common shares outstanding		15,527			14,213			9,571
Stock options, restricted stock and warrants		357			746			—	(2)
Conversion of preferred shares		—	(1)		—	(1)		—	(2)
Conversion of 7.85% notes payable (4)		—			—	(1)		—	(2)
Conversion of 5.0% notes payable (3)		—	(1)		—	(1)		—	(3)
Conversion of debentures		—	(1)		181			—	(2)

Diluted shares outstanding		15,884			15,140			9,571

Diluted earnings available to common shares per share from:
Continuing operations	$	0.15		$	0.65		$	(0.31	)
Discontinued operations		—			—			1.85

Diluted income per share	$	0.15		$	0.65		$	1.54

Anti-dilutive securities not included above are as follows:
Stock options, restricted stock and warrants		—			—			523
Preferred shares		450			524			1,997
7.85% notes payable (4)		—			43			410
Debentures		26			—			316
5% notes payable (3)		2,015			552			—


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

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

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

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

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NOTE 5 — ACCOUNTS RECEIVABLE

Accounts receivable consisted of the following:


	December 31,
	2006		2005
	(in thousands)
Accrued oil and natural gas sales receivables	$	4,209	$	5,608
Trade receivables		3,394		2,142
Other accounts receivable		1,944		412

	$	9,547	$	8,162

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

Trade receivables are the amounts due from our joint interest partners and amounts due from contractors where we have paid for supplies on their behalf. These receivables are generally due within 15 days after receipt of monthly joint interest billing or they are offset against invoices from contractors when billed.

Other receivables are accrued interest receivable, at December 31, 2006 and 2005 on time deposits, value added tax refunds and travel advances to employees.

NOTE 6 — OIL AND NATURAL GAS PROPERTIES

Oil and Natural Gas Properties consist of the following:


	December 31,
	2006			2005
	(in thousands)
Licenses and concessions	$	3,895		$	3,879
Non-producing leaseholds		149,481			64,521
Producing leaseholds and intangible drilling costs		139,761			102,855
Furniture, fixtures and office equipment		3,183			2,365

		296,320			173,620
Accumulated depreciation, depletion and amortization		(45,305	)		(35,462	)

Total oil and natural gas properties	$	251,015		$	138,158

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

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


	December 31
	2006			2005
	(in thousands)
Capitalized exploratory well cost, beginning of the year	$	1,042		$	2,307
Additions to capitalized exploratory well costs pending determination of proved reserves		4,400			1,042
Reclassified to oil and natural gas properties based on determination of proved reserves		(186	)		(2,307	)

Capitalized exploratory well costs, end of year	$	5,256		$	1,042

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


	December 31
	2006		2005
	(in thousands)
Capitalized exploratory well cost that have been capitalized for a period of one year or less	$	4,400	$	1,042
Capitalized exploratory well cost that have been capitalized for a period greater than one year		856		—

Balance at the end of the year	$	5,256	$	1,042

Included in the capitalized exploratory cost are three wells located in the United States, two wells in Hungary and two wells in Romania. We anticipate that the results of all these wells will be known by December 31, 2007.

NOTE 7 — INVESTMENTS IN UNCONSOLIDATED ENTITIES

In February 2004, we acquired 45% of ePsolutions. Based in Austin, Texas, ePsolutions is a software and energy services company in the electric industry and deregulated energy markets. ePsolutions is the developer of emPower system, a CIS, EDI and billing solution for energy companies within deregulated energy markets. At December 31, 2006 and 2005 our investment in ePsolutions amounted to $1.5 million and $1.3 million, respectively. For the years ended December 31, 2006 and 2005 we advanced $257,000 and $759,000, respectively, and we recorded equity in the loss of ePsolutions of $70,000 in 2006, a loss of $238,000 in 2005 and a loss of $312,000 in 2004.

In July 2000, we acquired 35% of EnergyNet.com, Inc. (“EnergyNet”), an Internet based oil and natural gas property auction company. At December 31, 2006 and 2005, our investment in EnergyNet amounted to $997,000 and $832,000, respectively. We recorded equity in the earnings of EnergyNet of $340,000 in 2006, $409,000 in 2005 and $279,000 in 2004. We received a dividend from EnergyNet of $175,000 in 2006, $131,250 in 2005 and $131,250 in 2004.

In April 2000, we acquired a 50% interest in Capstone Royalty, LLC (“Capstone”), a joint venture formed to acquire mineral interests at county auctions in west Texas and develop those interests. Our investment in Capstone amounted to $160,000 and $104,000 at December 31, 2006 and 2005, respectively. We recorded equity in the earnings of Capstone amounting to $131,000 in 2006, $51,000 in 2005 and $15,000 in 2004. We received a distribution from capstone of $75,000 in 2006, $60,000 in 2005 and $25,000 in 2004.

NOTE 8 — LONG-TERM DEBT

Long-term debt consisted of the following:


	December 31,
	2006			2005
	(in thousands)
Revolving line of credit with Texas Capital Bank, N.A	$	5,550		$	—
Revolving line of credit with Natexis Banques Populaires		11,000			5,000
Secured revolving facility with the International Finance Corporation		10,000			—
Convertible senior notes		86,250			86,250
Convertible debenture — related party		—			810

		112,800			92,060
Less: current portion		(5,000	)		(810	)

	$	107,800		$	91,250

CONVERTIBLE SENIOR NOTES DUE OCTOBER 1, 2025

On September 27, 2005, we issued $75 million of Convertible Senior Notes due October 1, 2025 (“Notes”) to qualified institutional buyers pursuant to Rule 144A of the Securities Act of 1933. The Company also granted the initial purchasers the option to purchase an additional $11.25 million aggregate principal amount of Notes to cover over-allotments. The option was exercised on September 30, 2005. The total principal amount of Notes issued was

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$86.25 million and total net proceeds were approximately $82.2 million. We incurred approximately $4.1 million of costs associated with the issuance of the Notes; these costs have been recorded in other assets on the balance sheet and are being amortized to interest expense using the straight-line interest rate method over the term of the Notes. The net proceeds were used for general corporate purposes, including funding a portion of the Company’s 2005 and 2006 exploration and development activities.

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

The registration rights agreement covering the Notes provides for a penalty if the registration statement is filed and declared effective but thereafter ceases to be effective (a “Suspension Period”) for an aggregate of forty-five (45) days in any three month period or ninety (90) days in any twelve month period (an “Event Date”). Such penalty calls for an additional 0.25% per annum in interest expense on the aggregate principal amount of the Notes for the first ninety (90) days following an Event Date and an additional 0.50% per annum in interest expense on the aggregate principal amount of the Notes thereafter, until such Suspension Period ends upon the registration statement again becoming effective. Because we did not file our Quarterly Report on Form 10-Q for the nine month period ended September 30, 2006 in a timely manner, the registration statement for the Convertible Senior Notes became ineffective and we entered a Suspension Period on November 15, 2006. Such Suspension Period ended on January 23, 2007 when we provided notice that the Form 10-Q had been filed and the Suspension Period was no longer in effect. Because the Suspension Period exceeded forty-five (45) days in any three month period, we will owe approximately $14,375 in additional interest expense. Once we file our Form 10-K for the year ended December 31, 2006, we will again enter a Suspension Period until we can file and have declared effective an amendment to our registration statement on Form S-1. Therefore, we have accrued a liability of $53,168 at December 31, 2006, which represents 90 days of additional interest at 0.25%. Because of the previous Suspension Period, we will exceed the ninety (90) days in any twelve month period on the twenty first (21^st) day following the filing of our Form 10-K and will again begin to accrue additional interest as described above until we can file and have declared effective an amendment to our registration statement on Form S-1.

REVOLVING LINE OF CREDIT WITH NATIXIS BANQUES POPULAIRES

On December 23, 2004, we entered into a five-year $15.0 million reserve-based borrowing facility with a French lender to finance the development of our existing French fields, acquisitions of new fields, general working capital and other corporate purposes. The facility bears interest at a floating rate of 2.25-2.75% above LIBOR (8.125% at

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December 31, 2006) depending on the principal outstanding. The facility is collateralized by certain of our French assets, including contracts relating to our rights and interests in our French fields, our direct and indirect equity interests in certain of our subsidiaries and payments received from the sale of our French production. The Company and certain of its U.S. and French subsidiaries have each guaranteed the obligations under the facility. This facility will require monthly interest payments until December 23, 2009, at which time all unpaid principal and interest are due. We are subject to a commitment fee of one half (1/2) of the applicable margin, 1.25% as of December 31, 2006, on the available and unused facility borrowings. Under the $15.0 million facility, at December 31, 2006, borrowings of approximately $909,000 were available and $11 million was outstanding. The $15.0 million facility contains various affirmative and negative covenants. These covenants, among other things, limit additional indebtedness, the sale of assets, change of control and management, limitations on the distribution of stock dividends and require us to meet certain financial requirements. Specifically, we must maintain an interest cost ratio of not less than 4.00 to 1.00, an indebtedness ratio of not less than 1.00 to 1.00, asset life cover ratio of not less than 1.25 to 1.00, a loan life cover ratio equal to or greater than 1.15 to 1.00 and a debt service coverage ratio equal to or greater than 1.10 to 1.00.

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

SECURED REVOLVING FACILITY WITH THE INTERNATIONAL FINANCE CORPORATION

On December 28, 2006, we guaranteed the obligations of certain of our direct and indirect subsidiaries in a loan and guarantee agreement with International Finance Corporation. The loan and guarantee agreement provides for the $25 million loan facility which is a secured revolving facility with a current maximum facility amount of $25 million which maximum facility amount will increase to $40 million when the projected total borrowing base amount exceeds $50 million. The $25 million facility was funded on March 2, 2007. The loan and guarantee agreement also provides for a $10 million facility. As of December 31, 2006 and March 8, 2007, the $10 million facility has $10.0 million outstanding. All amounts available under the new secured revolving facility have been funded. Both the $25 million facility and $10 million facility are to fund the our operations in Turkey and Romania.

Interest accrues on any loans under the A loan facility at a rate of 2% over the six month LIBOR rate. Interest accrued on the $10 million facility at a rate of 1.5% over the six month LIBOR rate until the $25 million facility was funded after which the rate for the $10 million facility was lowered to 0.5% over the six month LIBOR rate. As of December 31, 2006, the interest rate on the $10 million facility was 6.86%. As of March 8, 2007, the interest rate on the $10 million facility was 5.849% and the interest rate on the $25 million facility was 7.349%. Interest is to be paid on each June 15 and December 15.

The $25 million facility provided the following: (i) the lender has a first ranking security interest (a) in certain proceeds, receivables and contract rights relating to and from the sale of oil or gas production in France, Turkey and Romania and (b) in funds held in certain bank accounts; (ii) the lender has an assignment of all rights and claims to any compensation or other special payments in respect of all concessions other than those arising in the normal course of operations payable by the government of Turkey and Romania; and (iii) the lender has a first ranking pledge (a) by Toreador International Holding, LLC of all its shares in the borrowers; (b) by Madison Oil France SAS of all its shares in Toreador France; and (c) by the Company of all its shares in Toreador International Holding, LLC.

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The Company is required to meet the following ratios on a consolidated basis: (i) the life of loan coverage ratio of not less than: (a) 1.2:1.0 in 2006 and 2007; (b) 1.3:1.0 in 2008; and (c) 1.4:1.0 in 2009 and each subsequent year thereafter; (ii) reserve tail ratio of not less than 25%; (iii) adjusted financed debt to EBITDA ratio of not more than 3.0:1.0; (iv) liabilities to tangible net worth ratio of not more than 60:40; and (v) interest coverage ratio of not less than 3.0:1.0.

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

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

On December 30, 2004, we entered into a five-year $25.0 million reserve-based borrowing facility with Texas Capital Bank, N.A. in order to finance the development and acquisition of oil and natural-gas interests both domestically and internationally and for working capital purposes. The facility bears interest at a rate of prime less 0.5% (7.75% total rate at December 31, 2006) and is collateralized by our domestic working interests. The borrowers under this facility are two of our domestic subsidiaries, and the Company has guaranteed the obligations. At December 31, 2006, we had approximately $450,000 available for borrowings and the outstanding amount was $5.6 million. The Texas Capital facility requires monthly interest payments until January 1, 2010 at which time all unpaid principal and interest are due. We are subject to a commitment fee of one-half of one percent (1/2 of 1%) as of December 31, 2006, on the available and unused facility borrowings. The Texas Capital facility contains various affirmative and negative covenants. These covenants, among other things, limit additional indebtedness, the sale of assets, change of control and management and require us to meet certain financial requirements. Specifically, we must maintain a current ratio of 1.25 to 1.00 (exclusive of amounts due under revolving credit arrangements) and an interest coverage ratio of not less than 3.00 to 1.00.

CONVERTIBLE SUBORDINATED NOTES

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

F-20

CONVERTIBLE DEBENTURE

As part of our acquisition of Madison Oil Company, we assumed and amended a convertible debenture (“Debenture”) payable to PHD Partners LP. The general partner of PHD Partners LP is a corporation wholly owned by David M. Brewer, a director and significant stockholder of Toreador. The amended and restated debenture used to bear interest at 10% per annum and was due on March 31, 2006. At the holders’ option, the amended and restated debenture could be converted into common stock at a ratio of $6.75 per share. We originally had 319,962 common shares reserved for issuance related to the conversion of the amended and restated debenture. As of March 31, 2004, the amended and restated debenture was amended and restated to bear interest at 6% per annum, eliminate the Company’s right under certain circumstances to force a conversion of the principal into shares of Toreador common stock and eliminate the Company’s ability to repay principal prior to maturity. The maturity date remained March 31, 2006. At the holder’s option, the second amended and restated convertible debenture could be converted into Toreador common stock at a conversion price of $6.75 per share. In December 2004, PHD Partners LP converted $675,000 of the second amended and restated debenture into 100,000 shares of our common stock. As a result, at December 31, 2004 the outstanding principal amount of the second amended and restated convertible debenture was approximately $1.5 million. On August 10, 2005, PHD Partners converted $675,000 of the second amended and restated debenture into 100,000 shares of our common stock, resulting in an outstanding principal balance of $810,000 at December 31, 2005. In February 2006, PHD Partners LP converted the $135,000 of the second amended and restated debenture into 19,962 shares of our common stock and in March 2006, PHD Partners converted the remaining balance of $675,000 of the second amended and restated debenture into 100,000 shares of our common stock. Interest payments made to PHD Partners LP were $9,682, $73,195 and $352,416 in 2006, 2005 and 2004, respectively.

The following table summarizes the principal maturities under our long-term debt arrangements at December 31, 2006, (in thousands):


	2007		2008		2009		2010		2011		Thereafter		Total
Long-term debt	$	5,000	$	3,000	$	3,000	$	5,500	$	—	$	96,300	$	112,800

NOTE 9 — CAPITAL

Toreador had 72,000 shares of nonvoting Series A-1 Convertible Preferred Stock outstanding at December 31, 2006 and 2005. 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, 2006). 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, all (160,000 shares) of Series A Convertible Preferred Stock (which had identical terms to the Series A-1) 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

F-21

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.

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

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

On January 3, 2006, we issued warrants for the purchase of 10,000 shares of our common stock at $27.65 per share. The warrant was issued pursuant to the terms of the Engagement letter, dated January 3, 2006, between the Company and ParCon Consulting. At December 31, 2006 all 10,000 warrants were outstanding and expire on January 3, 2011. We recognized $106,800 in expense relating to the issuance of the warrants.

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

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

NOTE 10 — INCOME TAXES

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


	2006			2005			2004
	(in thousands)
Current:
U.S. Federal	$	(581	)	$	(2,421	)	$	7,129
U.S. State		(7	)		46			844
Foreign		1,156			1,140			(611	)
Deferred:
U.S. Federal		135			1,383			329
U.S. State		—			—			—
Foreign		2,944			(463	)		2,163

	$	3,647		$	(315	)	$	9,854

The tax provision (benefit) has been allocated between continuing operations and discontinued operations as follows:

Provision (benefit) allocated to:
Continuing operations	$	3,647		$	(315	)	$	(1,153	)
Discontinued operations		—			—			11,007

	$	3,647		$	(315	)	$	9,854

F-22

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


	2006			2005			2004
	(in thousands)
Statutory tax at 34%	$	2,113		$	3,501		$	8,532
Tax basis and rate differences related to foreign operations		584			(2,967	)		3,065
Use of NOL carryforwards		(121	)		—			(3,940	)
Reduction in Turkish net operating loss		143			—			—
State income tax, net		(5	)		(148	)		833
Foreign currency gain (loss) not taxable in foreign jurisdictions		265			(857	)		431
Release of tax reserve		—			(49	)		(554	)
Effect of rate changes in foreign countries		(1,062	)		—			—
Adjustments to valuation allowance		1,846			(385	)		1,748
Use of percentage depletion		—			(98	)		—
Use of capital loss carryover		—			(90	)		—
Other		(116	)		778			(261	)

	$	3,647		$	(315	)	$	9,854

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, 2006 and 2005 were as follows:


	December 31,
	2006			2005
	(in thousands)
Deferred tax assets:
Net operating loss carryforward — United States	$	2,150		$	2,190
Net operating loss carryforward — Foreign		7,002			8,811
Restricted stock		835			—
Other		416			248

Gross deferred tax assets		10,403			11,249
Valuation allowance		(6,609	)		(5,053	)

Net deferred tax assets		3,794			6,196

Deferred tax liabilities:
Differences in oil and gas property capitalization and depletion methods— United States		(1,337	)		(1,637	)
Differences in oil and gas property capitalization and depletion methods— Foreign		(19,064	)		(16,594	)
Unrealized foreign currency translation gains		(501	)		—
Other		(54	)		(164	)

Gross deferred tax liabilities		(20,956	)		(18,395	)

Net deferred tax liabilities	$	(17,162	)	$	(12,199	)

At December 31, 2006, Toreador had the following carryforwards available to reduce future taxable income (in thousands) :


Jurisdiction	Expiry		Amount
United States		2010 — 2021	$	6,323
Hungary	Unlimited			28,774
Turkey		2007 — 2010		8,476
France	Unlimited			2,245

F-23

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


	December 31,
	2006		2005
	(in thousands)
United States	$	1,241	$	—
Turkey		16		64
Hungary		4,604		4,000
France		748		989

	$	6,609	$	5,053

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


	Required
	Taxable Income
United States	$	3,650
Turkey		80
Hungary		28,775
France		2,244

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

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

NOTE 11 — 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 $74,000 in 2006, $52,000 in 2005 and $75,000 in 2004.

NOTE 12 — 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.

F-24

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 :


	2006					2005					2004
				WEIGHTED					WEIGHTED					WEIGHTED
				AVERAGE					AVERAGE					AVERAGE
				EXERCISE					EXERCISE					EXERCISE
	SHARES			PRICE		SHARES			PRICE		SHARES			PRICE
Outstanding at January 1		858,940		$	5.07		1,346,690		$	4.91		1,515,940		$	4.43
Granted		—			—		20,000			16.90		442,700			5.78
Exercised		(175,070	)		4.95		(492,750	)		5.18		(538,102	)		4.33
Forfeited		(10,000	)		3.10		(15,000	)		3.10		(73,848	)		4.95

Outstanding at December 31		673,870			5.13		858,940			5.07		1,346,690			4.91

Exercisable at December 31		660,536			4.90		827,274			5.27		1,182,690			5.59

The intrinsic value of the options exercised in 2006 was $4.0 million. For the year ended December 31, 2006, 2005 and 2004 we received cash from stock option exercises of $866,000, $2.6 million and $2.3 million, respectively and the Company recognized a tax benefit related to exercises of stock options of $293,000 in 2006, $2.5 million in 2005 and $1.1 million in 2004. During 2006, 18,667 shares vested having a fair value on the date of vesting of approximately $491,000. As of December 31, 2006, the total compensation cost related to nonvested stock options not yet recognized is approximately $67,000. This amount will be recognized as compensation expense over the next 16 months.

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


					WEIGHTED-AVERAGE		WEIGHTED-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

	2003	Exercise price equal to market price		90,000	$	6.89	$	2.50

On the date of exercise, the intrinsic value of the options exercised in the above table was approximately $4.0 million.

F-25

The following table summarizes information about the fixed price stock options outstanding at December 31, 2006 :


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

$	2.75		45,000	$	1,036		45,000	$	1,036		1.73
	3.00		5,000		114		5,000		114		2.42
	3.10		75,000		1,700		75,000		1,700		6.47
	3.12		4,420		100		4,420		100		3.72
	3.88		5,000		109		5,000		109		2.83
	4.12		51,000		1,104		51,000		1,104		5.42
	4.51		20,000		425		20,000		425		5.13
	4.96		40,000		832		40,000		832		7.39
	5.00		200,133		4,157		200,133		4,157		2.25
	5.50		170,017		3,446		170,017		3,446		6.00
	5.75		15,800		316		15,800		316		4.18
	5.95		15,000		297		15,000		297		4.38
	13.75		7,500		90		7,500		90		7.88
	16.90		20,000		177		6,666		59		8.39

$	5.10		673,870	$	13,903		660,536	$	13,785		4.63

At December 31, 2006, there were 120,208 remaining shares available for grant under the plans collectively.

In May 2005, stockholders approved the Toreador Resources Corporation 2005 Long-Term Incentive Plan (the “Plan”). The Plan, as amended, authorizes the issuance of up to 750,000 shares of the Company’s common stock to key employees, key consultants and outside directors of the Company. The Board of Directors has authorized a total of 328,385 shares of restricted stock be granted to employees and non-employee directors. The compensation cost is measured by the difference between the quoted market price of the stock at the date of grant and the price, if any, to be paid by an employee and is recognized as expense over the period the recipient performs related services. The restricted stock grants vest over a one to four year period depending on the grant and the average price of the stock on the date of the grants was $28.95. Stock compensation expense of $2.7 million and $400,790 is included in the Statement of Operations for the years ended December 31, 2006 and 2005, which represents the cost recognized from the date of the grants through December 31, 2006 and 2005. During 2006, 40,165 shares vested having a fair value of approximately $0.8 million on the date of vesting. As of December 31, 2006, the total compensation cost related to nonvested restricted stock grants not yet recognized is approximately $5.3 million. This amount will be recognized as compensation expense over the next 40 months.

For the years ended December 31, 2006 and 2005 we recognized a current tax benefit related to restricted stock grants of approximately $362,000 and zero and a deferred tax benefit of approximately $561,000 and $136,000, respectively.

The following table summarizes the changes in outstanding restricted stock grants along with their related grant-date fair values for the year ended December 31, 2006:


				Weighted Average
				Grant-Date
	Shares			Fair Value
Non-vested at January 1, 2006		114,560		$	20.10
Shares granted		213,825			28.95
Shares vested		(40,165	)		(20.27	)
Shares forfeited		(300	)		(30.83	)

Non-vested at December 31,2006		287,920		$	26.63

F-26

NOTE 13 — COMMITMENTS AND CONTINGENCIES

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


2007	$	502
2008		233
2009		132
2010		132
2011		132
Thereafter		385

	$	1,516

Net rent expense totaled $699,000 in 2006, $354,000 in 2005 and $380,000 in 2004.

Turkish Registered Capital.Under the existing Petroleum Law of Turkey, capital that is invested by foreign companies in projects such as oil and natural gas exploration can be registered with the General Directorate of Petroleum Affairs, thereby qualifying for protection against adverse changes in the exchange rate between the time of the initial investment and the time such capital is repatriated out of Turkey. Since 1997 the Turkish government has suspended such protection for repatriated capital. As the holder of more than $50 million of registered capital, we have filed suit in Turkey to attempt to restore the exchange rate protections afforded under the law. No amounts are accrued related to this gain contingency. In March 2002, a lower level court ruled in favor of 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.

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

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 14 — 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.

F-27

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 $50,000 in 2006, $48,000 in 2005 and $45,000 in 2004 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 zero, $146 and $2,000 at December 31, 2006, 2005 and 2004, 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 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.

NOTE 15 — DISCONTINUED OPERATIONS


	Year ended December 31,
	2006		2005		2004
	(in thousands)
Revenues:
Oil and natural gas sales	$	11	$	63	$	139

Costs and expenses:
Lease operating		—		1		(10	)
Allocated general and administrative		—		15		163

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

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

Income from discontinued operations	$	11	$	47	$	17,690

F-28

General and administrative 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 16 — 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, 2006, 2005, and 2004 excludes discontinued operations sold in January 2004 through the U. S. mineral royalty asset sale (see Note 15).

F-29


	United
	States			France			Turkey			Hungary			Romania			Total
	(In thousands)
For the year ended December 31, 2006
Revenues:
Oil and natural gas sales	$	7,079		$	27,274		$	3,834		$	—		$	2,200		$	40,387

Costs and expenses:
Lease operating		2,200			7,229			793			—			719			10,941
Exploration expense		1,883			432			799			184			648			3,946
Depreciation, depletion and amortization		1,529			3,119			748			59			2,089			7,544
Dry hole cost		1,393			—			—			1,706			—			3,099
Impairment of oil and gas properties		345			—			—			—			—			345
General and administrative		6,044			1,905			807			516			557			9,829
(Gain) loss on sale of properties and other assets		(202	)		—			(436	)		—			—			(638	)

Total costs and expenses		13,192			12,685			2,711			2,465			4,013			35,066

Operating income (loss)		(6,113	)		14,589			1,123			(2,465	)		(1,813	)		5,321
Other income (expense)		3,186			187			(1,055	)		(1,484	)		59			893

Income (loss) before income taxes		(2,927	)		14,776			68			(3,949	)		(1,754	)		6,214
Benefit (provision) for income taxes		378			(4,256	)		231			—			—			(3,647	)

Income (loss) from continuing operations, net of tax	$	(2,549	)	$	10,520		$	299		$	(3,949	)	$	(1,754	)	$	2,567

Selected assets:
Oil and natural gas properties	$	21,899		$	99,751		$	137,499		$	15,334		$	21,840		$	296,320
Accumulated depreciation, depletion, and amortization		(9,634	)		(30,439	)		(2,893	)		(283	)		(2,059	)		(45,305	)

Oil and natural gas properties, net	$	12,265		$	69,312		$	134,606		$	15,051		$	19,781		$	251,015

Investments in unconsolidated entities	$	2,659		$	—		$	—		$	—		$	—		$	2,659

Goodwill	$	—		$	3,632		$	919		$	—		$	—		$	4,551

Total assets	$	251,422		$	80,574		$	35,209		$	7,745		$	4,638		$	379,588

Expenditures for additions to long-lived assets:
Property acquisition costs	$	161		$	—		$	—		$	—		$	—		$	161
Development costs		77			15,931			86,222			1,759			6,943			110,932
Exploration costs		353			—			—			6,249			7,320			13,922
Other		283			127			228			83			111			832

Total expenditures for long-lived assets	$	874		$	16,058		$	86,450		$	8,091		$	14,374		$	125,847

F-30


	United
	States			France			Turkey			Hungary			Romania			Total
	(In thousands)
For the year ended December 31, 2005
Revenues:
Oil and natural gas sales	$	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
Gain on sale of properties and other assets		(12	)		—			—			—			—			(12	)

Total costs and expenses		9,835			10,857			3,752			257			198			24,899

Operating income (loss)		(2,107	)		9,715			(935	)		(257	)		(198	)		6,218
Other income (expense)		383			(347	)		2,873			(33	)		1,139			4,015

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

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

F-31


	United
	States (1)			��	France			Turkey			Total
For the year ended December 31, 2004
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
Loss on sale of properties and other assets		159				—			—			159

Total costs and expenses		8,721				8,833			6,107			23,661

Operating income (loss)		(4,005	)			5,209			(3,837	)		(2,633	)
Other income (expense)		(90	)			(386	)		(314	)		(790	)

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.

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


	December 31,
	2006			2005
	(in thousands)
Total assets for reportable segments	$	379,588		$	315,726
Elimination of intersegment receivables and investments		(62,384	)		(53,912	)

Total consolidated assets	$	317,204		$	261,814

NOTE 17 — Subsequent Event

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. On January 16, 2007, we filed the restated financial statements as of and for the year ended December 31, 2005 on Form 10-K/A, the restated financial statements for the quarters ended March 31, 2006 and June 30, 2006 on Forms 10-Q/A and the Form 10-Q for the quarter ended

F-32

September 30, 2006. On February 15, 2007, Toreador received notice from the Nasdaq Listing Qualifications panel that the violation has been cured and no further action will be taken.

NOTE 18 — 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-33


	United
	States			France			Turkey			Romania			Hungary		Total
	Natural Gas (MMcf)
PROVED RESERVES
December 31, 2003		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		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		5,295			—			6,476			3,486			—		15,257
Revisions of previous estimates		(760	)		—			(1,151	)		(1,185	)		—		(3,096	)
Extensions, discoveries and other additions		96			—			16,099			1,186			950		18,331
Sale of reserves		(2	)		—			—			—			—		(2	)
Production		(500	)		—			—			(446	)		—		(946	)

December 31, 2006		4,129			—			21,424			3,041			950		29,544


PROVED DEVELOPED
December 31, 2004		4,875			—			—			—			—		4,875

December 31, 2005		5,225			—			—			3,486			—		8,711

December 31, 2006		4,068			—			—			3,040			950		8,058


	Oil (MBbl)
PROVED RESERVES
December 31, 2003		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		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		793			10,978			639			24			—		12,434
Revisions of previous estimates		(30	)		(906	)		95			4			—		(838	)
Extensions, discoveries and other additions		—			—			—			19			1		20
Sale of reserves		—			—			—			—			—		—
Production		(63	)		(444	)		(69	)		(6	)		—		(582	)

December 31, 2006		700			9,628			665			41			1		11,035


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

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

December 31, 2006		699			6,770			405			41			1		7,916

F-34

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

The prices of oil and natural gas at December 31, 2006, 2005, and 2004 used in the above table, were $57.75, $56.24 and $37.55 per Bbl of oil, respectively, and $5.64, $6.98 and $5.99 per Mcf of natural gas, respectively.


	United
	States		France		Turkey			Romania			Hungary		Total
	(In thousands)
As of and for the year ended December 31, 2004
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
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


As of and for the year ended December 31, 2006
Future cash inflows	$	63,597	$	551,139	$	185,815		$	21,163		$	5,732	$	827,446
Future production costs		26,428		214,474		20,407			5,198			1,658		268,165
Future development costs		273		33,580		20,757			159			800		55,569
Future income tax expense		11,432		95,067		7,114			(602	)		2,057		115,068

Future net cash flows		25,464		208,018		137,537			16,408			1,217		388,644
10% annual discount for estimated timing of cash flows		12,200		121,828		53,207			3,019			248		190,502

Standardized measure of discounted future net cash flows related to proved reserves	$	13,264	$	86,190	$	84,330		$	13,388		$	970	$	198,142

F-35

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


	United
	States			France			Turkey			Romania			Hungary			Total
	(In thousands)
Balance at December 31, 2003	$	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		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		21,033			109,129			15,788			10,675			—			156,626
Sales of oil and natural gas, net		(4,879	)		(20,201	)		(3,041	)		(1,481	)		—			(29,602	)
Net changes in prices and production costs		(8,215	)		(6,102	)		7,074			2,987						(4,256	)
Net change in development costs		(55	)		(2,101	)		970			(130	)		(641	)		(1,957	)
Extensions and discoveries		238			—			65,127			5,159			3,267			73,791
Revisions of previous quantity estimates		(2,203	)		(13,781	)		(2,355	)		(4,617	)		—			(22,956	)
Previously estimated development costs incurred		(152	)		(2,132	)		—			(552	)		—			(2,836	)
Net change in income taxes		2,540			9,312			(3,445	)		1,262			(1,656	)		8,013
Accretion of discount		2,701			13,570			1,679			989			—			19,793
Other		2,256			(1,504	)		2,149			(905	)		—			1,526

Balance at December 31, 2006	$	13,264		$	86,190		$	84,3330		$	13,388		$	970		$	198,142

F-36

Toreador Resources (TRGL) Inactive 10-K/A2006 FY Annual report (amended)