Toreador Resources 10Q 2006 Q3 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended: September 30, 2006


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

Commission file number0-02517

TOREADOR RESOURCES CORPORATION

(Exact name of registrant as specified in its charter)


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

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

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

Indicate by check mark whether the Registrant (i) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the past 12 months (or for such shorter period that the Registrant was required to file such reports), and (ii) has been subject to such filing requirements for the past 90 days. Yesþ Noo

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 filero Accelerated filerþ Non-accelerated filero

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

As of January 12, 2007 there were 15,934,484 shares of common stock outstanding.

TOREADOR RESOURCES CORPORATION

TABLE OF CONTENTS


		Page
Explanatory Note about this Report —			i

PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements (unaudited)⁽¹⁾

	Consolidated Balance Sheets – September 30, 2006 and December 31, 2005		1

	Consolidated Statements of Operations — for the three months ended September 30, 2006 and 2005		2

	Consolidated Statements of Operations — for the nine months ended September 30, 2006 and 2005		3

	Consolidated Statements of Cash Flows — for the nine months ended September 30, 2006 and 2005		4

	Notes to Consolidated Financial Statements		5

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		17

Item 3.	Quantitative and Qualitative Disclosure About Market Risk

Item 4.	Controls and Procedures		30

PART II. OTHER INFORMATION

Item 1A.	Risk Factors		32

Item 3.	Defaults Upon Senior Securities		32

Item 6.	Exhibits		32

SIGNATURES			33
Rule 13a-14(a) Certification of Chief Executive Officer
Rule 13a-14(a) Certification of Chief Financial Officer
Rule 13a-14(a) Certification of Chief Accounting Officer
Section 1350 Certification


(1)		As described in Note 1 to the financial statements, the Company restated its financial statements for the year ended December 31, 2005.

Explanatory Note About This Report

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

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

TOREADOR RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS

(in thousands, except share data)
(UNAUDITED)


	September 30,			December 31,
	2006			2005
				(Restated)
ASSETS
Current assets:
Cash and cash equivalents	$	24,134		$	53,113
Restricted cash		23,804			—
Short-term investments		—			40,000
Accounts and notes receivable		2,300			8,162
Income taxes receivable		4,979			4,453
Other		10,213			6,537

Total current assets		65,430			112,265

Oil and gas properties, net, using successful efforts method of accounting		227,332			138,158
Advances to and investments in unconsolidated entities		2,479			2,251
Goodwill		4,244			4,195
Other assets		6,382			4,945

	$	305,867		$	261,814


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable and accrued liabilities	$	49,940		$	19,248
Convertible debenture – related party		—			810
Income taxes payable		785			908

Total current liabilities		50,725			20,966


Long-term accrued liabilities		1,357			1,410
Long-term debt		—			5,000
Long-term asset retirement obligation		4,002			3,630
Deferred income taxes		11,721			12,199
Convertible senior notes		86,250			86,250

Total liabilities		154,055			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 and outstanding		72			72
Common stock, $0.15625 par value, 30,000,000 shares authorized;16,650,761 and 16,142,824 shares issued and outstanding		2,602			2,522
Additional paid-in capital		110,338			108,001
Retained earnings		40,210			29,564
Accumulated other comprehensive income (loss)		1,124			(3,364	)
Deferred compensation		—			(1,902	)
Treasury stock, at cost, 721,027 shares		(2,534	)		(2,534	)


Total stockholders’ equity		151,812			132,359

	$	305,867		$	261,814

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

TOREADOR RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)

(UNAUDITED)


	Three Months Ended
	September 30,
				2005
	2006			(restated)
Oil and natural gas sales	$	10,726		$	8,770

Operating costs and expenses:
Lease operating		2,634			2,112
Exploration expense		414			1,232
Dry hole and abandonment		—			1,382
Depreciation, depletion and amortization		1,975			969
General and administrative		2,395			1,345

Total operating costs and expenses		7,418			7,040


Operating income		3,308			1,730

Other income (expense):
Equity in earnings of unconsolidated investments		71			(7	)
Loss on sale of properties and other assets		(11	)		—
Foreign currency exchange gain		2,736			195
Interest income and expense and other, net		545			215

Total other income, net		3,341			403


Income before taxes		6,649			2,133
Income tax provision		1,188			782


Income from continuing operations		5,461			1,351
Income from discontinued operations, net of tax		11			14

Net income		5,472			1,365
Preferred dividends		(40	)		(41	)


Income available to common shares	$	5,432		$	1,324


Basic income available to common shares per share	$	0.35		$	0.09


Diluted income available to common shares per share	$	0.33		$	0.09


Weighted average shares outstanding:

Basic		15,637			14,543

Diluted		18,677			15,907

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

TOREADOR RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)
(UNAUDITED)


	Nine Months Ended
	September 30,
				2005
	2006			(restated)
Revenue:
Oil and natural gas sales	$	30,798		$	22,610

Operating costs and expenses:
Lease operating		7,722			6,372
Exploration expense		2,652			2,037
Dry hole and abandonment		—			1,382
Depreciation, depletion and amortization		4,564			2,902
General and administrative		7,280			5,104

Total operating costs and expenses		22,218			17,797


Operating income		8,580			4,813

Other income (expense):
Equity in earnings of unconsolidated investments		263			117
Gain on sale of properties and other assets		640			12
Foreign currency exchange gain		1,863			155
Interest income and expense and other, net		1,811			794

Total other income, net		4,577			1,078


Income before taxes		13,157			5,891
Income tax provision		2,975			659


Income from continuing operations		10,182			5,232
Income from discontinued operations, net of tax		11			25

Net income		10,193			5,257
Preferred dividends		(122	)		(644	)


Income available to common shares	$	10,071		$	4,613


Basic income available to common shares per share	$	0.65		$	0.33


Diluted income available to common shares per share	$	0.63		$	0.31


Weighted average shares outstanding:

Basic		15,488			13,845


Diluted		17,316			15,197

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

TOREADOR RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)
(UNAUDITED)


	Nine Months Ended
	September 30,
				2005
	2006			(restated)
Cash flows from operating activities:
Net income	$	10,193		$	5,257
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		4,564			2,902
Dry holes and abandonments		—			1,382
Gain on sale of properties and other assets		(640	)		(12	)
Deferred income taxes		1,151			6,578
Equity in earnings of unconsolidated investments		(263	)		(117	)
Stock based compensation		1,936			223
Realized gains on foreign currency transactions		(1,863	)		(155	)
Change in operating assets and liabilities:
Increase (decrease) in accounts and notes receivables		5,336			(7,795	)
Increase in other assets		(5,299	)		(3,795	)
Increase in accounts payable and accrued liabilities		30,639			2,227
Decrease in income taxes payable		(1,333	)		(1,593	)

Net cash provided by operating activities		44,421			5,102


Cash flows from investing activities:
Expenditures for property and equipment		(93,851	)		(33,853	)
Restricted cash		(23,804	)		—
Acquisition of Pogo-Hungary		—			(8,751	)
Short-term investments		40,000			—
Investment in unconsolidated subsidiaries		35			(592	)

Net cash used in investing activities		(77,620	)		(43,196	)


Cash flows from financing activities:
Borrowings from long-term debt		—			6,796
Payment for debt issuance costs		—			(3,897	)
Repayments of long-term debt		(5,000	)		(2,000	)
Proceeds from issuance of common stock		969			58,646
Proceeds from convertible senior notes		—			86,250
Tax benefit of stock option exercised		1,210			—
Payment of preferred dividends		(122	)		(144	)

Net cash provided by (used in) financing activities		(2,943	)		145,651


Net increase (decrease) in cash and cash equivalents		(36,142	)		107,557

Effects of foreign currency translation on cash and cash equivalents		7,163			(4,139	)
Cash and cash equivalents, beginning of period		53,113			4,977

Cash and cash equivalents, end of period	$	24,134		$	108,395

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

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

NOTE 1 — BASIS OF PRESENTATION

The consolidated financial statements of Toreador Resources Corporation and subsidiaries (“Toreador,” “we,” “us,” “our,” or the “Company”) included herein have been prepared by the Company without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. They reflect all adjustments which are, in the opinion of management, necessary for a fair presentation of the financial position and results of operations for the interim periods, on a basis consistent with the annual audited financial statements. All such adjustments are of a normal recurring nature. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted pursuant to such rules and regulations. However, the Company believes that the disclosures contained herein are adequate to make the information presented not misleading. The consolidated balance sheet at December 31, 2005 is derived from the December 31, 2005 audited consolidated financial statements, as restated. These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Company’s amended annual report on Form 10-K/A for the year ended December 31, 2005. The results of operations for interim periods are not necessarily indicative of the results to be expected for the full year.

Restricted cash

Restricted cash consists of cash balances held by a bank in the form of certificates of deposits. The restricted cash is held as collateral for a “Stand-by Letter of Credit” required by the contractor for the installation of the offshore pipeline in the Black Sea.

Restatement of Previously Issued Financial Statements

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

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

The accompanying Balance Sheet as of December 31, 2005 and the Consolidated Statement of Operations for the three and nine months ended September 30, 2005 and cash flows for the nine months ended September 30, 2005 have been restated. The significant adjustments are as follows:

Capitalization of Interest

We determined that the costs incurred in connection with the development program in offshore Turkey met the definition of a qualifying asset, as defined, and satisfied the three conditions for capitalization outlined Statement of Financial Accounting Standards No. 34, as amended,Capitalization of Interest Cost. Prior to April 1, 2006, we had not capitalized any interest related to development costs incurred. These adjustments reduce interest expense and increase capitalized oil and gas properties on the consolidated balance sheet. For the three months and nine months ended September 30, 2005, the pre-tax adjustment was $245,000 and $510,000 respectively.

Insurance Claim Adjustments

In 2005 two separate, significant property loss incidents occurred in offshore Turkey in the Black Sea, which resulted in the loss of two caissons and three wells. Both of these instances were insured. In December 2005, the Company received notice that the insurance company had reserved $10.6 million, net to the Company, for potential payment of these claims. As of December 31, 2005, the net book value of the wells and caissons was $11.1 million. In December 2005, the Company recorded the expected insurance recovery of $10.6 million as a receivable and reduced oil and gas properties and expensed the difference between the book value of the wells and caissons of $569,000 as a loss on involuntary conversions. In addition, the quarter ended March 31, 2006, the Company recorded an allowance against the insurance receivable of $1.5 million. This adjustment was revised in the restated financial statements for the quarter ended March 31, 2006. The Company subsequently concluded that under successful efforts accounting these were development wells and the costs associated with the lost wells and caissons, as well as the costs to re-drill the wells, should be capitalized and no gain or loss recorded. As a result, oil and gas properties were increased $11.1 million, the insurance receivable was decreased $10.6 million and $569,000 was credited to income. The oil and gas properties including the $11.1 million were assessed for possible impairment in accordance with the Company’s impairment policies and no impairment was deemed necessary. Future insurance recoveries from these losses, if any, will be recorded as reductions of oil and gas properties.

Foreign Currency

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

For the three and nine months ended September 30, 2005, the pre-tax adjustment was $(45,000) and $21,000, respectively.

Depletion, Depreciation and Amortization (DD&A)

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

For the three and nine months ended September 30, 2005, the pre-tax adjustment was a decrease of $4,000 and an increase of $21,000, respectively.

The effect of the restatements on the consolidated statements of operations for the three month and nine month periods ended September 30, 2005 and on the consolidated statements of cash flows for the nine month period ended September 30, 2005 is as follows:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2005						2005
	As						As
	Previously			As			Previously			As
	Reported			Restated			Reported			Restated
Oil and natural gas sales	$	8,770		$	8,770		$	22,348		$	22,610

Operating costs and expenses		7,085			7,040			17,776			17,797

Operating Income		1,685			1,730			4,572			4,813


Other Income (expense), net		161			403			568			1,078

Income before taxes		1,846			2,133			5,140			5,891
Income tax provision (benefit)		782			782			659			659

Income from continuing operations		1,064			1,351			4,481			5,232
Income from discontinued operations, net of tax		14			14			25			25

Net Income		1,078			1,365			4,506			5,257
Preferred dividends		(41	)		(41	)		(644	)		(644	)

Income available to common shares	$	1,037		$	1,324		$	3,862		$	4,613


Basic income available to common shares per share from
Continuing operations		0.07			0.09			0.28			0.33
Discontinued operations		—			—			—			—

	$	0.07			0.09		$	0.28			0.33


Diluted income available to common shares per share from
Continuing operations		0.07			0.09			0.27			0.31
Discontinued operations		—			—			—			—

	$	0.07			0.09		$	0.27			0.31


Weighted average shares outstanding:
Basic		14,679			14,543			13,891			13,845
Diluted		15,593			15,907			14,857			15,197

The effects of the restatements on the statement of cash flows are as follows: (in thousands)


	Nine months ended September 30, 2005
	As previously
	reported			Restated

Cash flows from operating activities	$	7,677		$	5,102
Cash flows from investing activities		(50,385	)		(43,196	)
Cash flows from financial activities		145,651			145,651

New Accounting Pronouncements

In February 2006, the FASB issued Statement 155, “Accounting for Certain Hybrid Instruments- an amendment of FASB Statements No. 133 and 140.” The statement amends Statement 133 to permit fair value measurement for certain hybrid financial instruments that contain an embedded derivative, provides additional guidance on the applicability of Statement 133 and 140 to certain financial instruments and subordinated concentrations of credit risk. The new standard is effective for the first

fiscal year that begins after September 16, 2006. As of September 30, 2006, the Company has not entered into nor do we expect to enter into any agreements that would be subject to this statement.

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

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

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

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

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

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

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

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

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

NOTE 2 — INSURANCE CLAIM ON 2005 BLACK SEA INCIDENTS

In 2005 two separate incidents occurred, in offshore Turkey in the Black Sea, which resulted in the loss of two caissons and three wells. Both of these incidents were insured. In December 2005 the Company received notice that the insurance company has reserved $10.6 million (net to the Company) for potential payment of this claim. As of December 31, 2005 the book value of the wells and caissons was $11.1 million. The costs associated with the caissons and lost wells, as well as the cost to redrill and replace the caissons, are development costs and are recorded as oil and natural gas properties. In addition, the quarter ended March 31, 2006, the Company recorded an allowance against the insurance receivable of $1.5 million. This adjustment was revised in the Restated Financial Statements for the quarter ended March 31, 2006. The oil and natural gas property will be assessed for possible impairment in accordance with the Company’s impairment policy, as a result of the increased cost associated with the development of the reserves. Insurance recoveries, if any, will be recorded as reductions of oil and natural gas properties when such amounts are received. See Note 10 for further discussion of further developments.

NOTE 3 — 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 three and nine months ended September 30, 2006 include an additional compensation expense of $12,183 and $53,733, respectively, 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 compensation are presented as a cash inflow from financing activities.

For the three and nine months ended September 30, 2005, 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 net earnings and earnings per share if a fair value based method had been applied to all awards.


	Three Months Ended		Nine Months Ended
	September 30, 2005		September 30, 2005
	(restated)		(restated)
Income applicable to common shares, as reported	$	1,324	$	4,613
Basic earnings available to common shares per share as reported		0.09		0.33
Diluted earnings available to common shares per share reported		0.09		0.31
Pro-forma stock-based compensation costs under the fair value method, net of related tax		7		49
Pro-forma income available to common shares, as under the fair-value method		1,317		4,564
Pro-forma basic earnings available to common shares per share under the fair-value method		0.09		0.33
Pro-forma diluted earnings available to common shares per share under the fair-value method		0.09		0.31

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:


	Options granted in
	2005
Dividend yield per share (1)		—
Volatility (2)		70.9	%
Risk-free interest rate (3)		4.0	%
Expected lives (4)	5 years


(1)		Historically, we have not paid dividends on common shares and do not anticipate doing so during the expected lives of these options.

(2)		We estimated volatility based on historic rates of return on our common stock over periods similar to the expected lives of the related options.

(3)		We estimated the risk free rate based on treasury issues with lives similar to the expected lives of the related options based on quotes available at or near the dates of grant of the related options.

(4)		We estimated expected lives considering, a) the contractual term of the related options, b) the average age of options exercised near the date of grant of the related options and c) our expectation of our stock performance during the contractual period.

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 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.

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.

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 for the nine months ended September 30, 2006 is as follows:


				WEIGHTED
				AVERAGE EXERCISE
	SHARES			PRICE
Outstanding at January 1, 2006		858,940		$	5.07
Granted		—			—
Exercised		(173,070	)		(4.83	)
Forfeited		—			—

Outstanding at September 30, 2006		685,870			5.10

Exercisable at September 30, 2006		672,536		$	4.87

On the date of exercise, the intrinsic value of the options exercised in the above table was approximately $4.8 million. During the three and nine months ended September 30, 2006, we received cash from stock option exercises of zero and $858,000, respectively and recognized a tax benefit related to such exercises of zero million and $1.2 million.

Upon exercise, we issue the full amount of shares exercisable per the term of the options from new shares. We have no plans to repurchase those shares in the future.

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 325,335 shares of restricted stock which have been granted to employees, key consultants 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 $25.89. Stock compensation expense of approximately $786,000 and $1.9 million is included in the Statement of Operations for the three and nine months ended September 30, 2006, respectively. As of September 30, 2006, the total compensation cost related to nonvested restricted grants not yet recognized is approximately $6.1 million. This amount will be recognized as compensation expense over the next 43 months.

The following table summarizes the changes in outstanding restricted stock grants along with their related grant-date fair values, during the nine months ended September 30, 2006:


				Grant-Date
	Shares			Fair Value
Non-vested at January 1, 2006		114,560		$	20.10
Shares granted		211,075			29.03
Shares vested		(34,864	)		(19.19	)
Shares forfeited		(300	)		(31.42	)

Non-vested at September 30, 2006		290,471		$	26.69

NOTE 4 — EARNINGS PER COMMON SHARE

Basic net income available to common shares per share is calculated by dividing net income by the weighted average number of shares of common stock outstanding during the period. Diluted net income available to common shares per share assumes the conversion of all potentially dilutive securities and is calculated by dividing net income by the sum of the weighted average number of shares of common stock outstanding plus all potentially dilutive securities.

The following table reconciles the numerators and denominators of the basic and diluted earnings per ordinary share computation:


	Three Months Ended September 30,				Nine Months Ended September 30,
			2005				2005
	2006		(restated)		2006		(restated)
	*(in thousands, except per share data)*
Basic earnings available to common shares per share:
Numerator:
Net income	$	5,472	$	1,365	$	10,193	$	5,257
Less: dividends on preferred shares		40		41		122		644

Income available to common shares	$	5,432	$	1,324	$	10,071	$	4,613

Denominator:
Common shares outstanding		15,637		14,543		15,488		13,845

Income per share available to common shares	$	0.35	$	0.09	$	0.65	$	0.33

Diluted earnings per share:
Numerator:
Net income	$	5,472	$	1,365	$	10,193	$	5,257
Plus: interest on convertible debt		679		11		685		38
Less: dividends on preferred shares		—		—		—		563

Income available to common shares	$	6,151	$	1,376	$	10,878	$	4,732


	Three Months Ended September 30,						Nine Months Ended September 30,
				2005						2005
	2006			(restated)			2006			(restated)
	*(in thousands, except per share data)*
Denominator:
Common shares outstanding		15,637			14,543			15,488			13,845
Common stock options, warrants and restricted stock		575			751			671			851
Conversion of preferred shares		450			450			450			300
Conversion of 5.0% notes payable		2,015			—	(1)		672			—	(1)
Conversion of 7.85% notes payable		—	(2)		—	(2)		—	(2)		—	(2)
Conversion of debenture		—	(2)		163			35			201

Diluted shares outstanding		18,677			15,907			17,316			15,197

Income per share available to common shares	$	0.33		$	0.09		$	0.63		$	0.31



(1)		The 5% notes payable were issued September 27, 2005 and September 30, 2005. The conversion of these securities would result in the inclusion of 174,240 and 58,719 of common shares for the three and nine months ended September 30, 2005, respectively.

(2)		The 7.85 % notes payable were converted to common stock in January 2005.

NOTE 5 — COMPREHENSIVE INCOME (LOSS)

The following table presents the components of comprehensive income (loss) net of related tax:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2006		2005		2006		2005
			(restated)				(restated)
Net income	$	5,472	$	1,365	$	10,193	$	5,257
Foreign currency translation adjustment		9,576		1,912		4,488		(13,918	)

Comprehensive income (loss)	$	15,048	$	3,277	$	14,681	$	(8,661	)

NOTE 6 — LONG-TERM DEBT

Convertible Senior Notes due October 1, 2025

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

Revolving Line of Credit with Natexis Banques Populaires

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 (7.63% total rate at September 30, 2006) depending on the principal outstanding. The $15 million facility contains various affirmative and negative covenants. As of September 30, 2006, we were in compliance with all covenants. In August 2005, $5 million was borrowed against this facility for our operations in Turkey and was repaid on April 18, 2006. The maximum commitment fee associated with the facility is 1.375% of the borrowing base, which at September 30, 2006 was set at $8 million. As of September 30, 2006, there was approximately $6.8 million available under this credit facility. In October 2006, the borrowing base was re-determined and was set at $14.6 million.

Revolving Line of Credit with Texas Capital Bank, N.A.

On December 30, 2004, we entered into a five-year $25 million reserve-based borrowing facility with Texas Capital Bank, N.A. The facility bears interest at a rate of prime less 0.5% (7.75% total rate at September 30, 2006). The $25 million facility contains various affirmative and negative covenants. As of September 30, 2006, we were in compliance with all covenants, there were no outstanding balances and approximately $6 million was available under this facility.

Convertible Subordinated Notes

On January 13, 2005, the Company offered the option to the holders of the 7.85% convertible subordinated notes to exchange their notes for the aggregate number of shares of our common stock issuable upon conversion of each of their notes and that portion of interest payable pursuant to the notes that would otherwise have been payable to the holders through February 22, 2005 absent conversion of the notes prior to such date. On or prior to January 20, 2005, all of our 7.85% convertible subordinated notes due June 30, 2009 with a carrying value, net of unamortized loan fees, of $6.4 million were exchanged for an aggregate of 914,634 shares of our common stock and an aggregate cash payment (in lieu of interest) of approximately $85,000 which is included in interest expense.

Convertible Debenture

Prior to the acquisition of Madison Oil Company, Madison Oil Company was party to a convertible debenture in the amount of approximately $2.2 million payable to PHD Partners LP and due on March 31, 2006. The general partner of PHD Partners LP is a corporation wholly-owned by David M. Brewer, a director and significant stockholder of Toreador. The original debenture bore interest at 10% per annum. As of March 31, 2004, the debenture was amended and restated to bear interest at 6% per annum, eliminate Toreador’s right under certain circumstances to force a conversion of the principal into shares of Toreador common stock and eliminate Toreador’s ability to repay principal prior to maturity. At the holder’s option, the second amended and restated convertible debenture was convertible into Toreador common stock at a conversion price of $6.75 per share. On August 10, 2005, PHD Partners LP converted $675,000 of the second amended and restated debenture into 100,000 shares of our common stock. In the first quarter 2006, PHD Partners LP converted the remaining balance of $810,000 of the second amended and restated debenture into 119,962 shares of our common stock.

Interest Payments

For the three and nine months ended September 30, 2006 we have made cash payments for interest of zero and $2.2 million, respectively, and for the three and nine months ended September 30, 2005 we made no cash payments of interest.

NOTE 7 — ASSET RETIREMENT OBLIGATIONS

We apply Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”). SFAS 143 requires entities to record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred if a reasonable estimate of fair value can be made. No wells were abandoned in the nine months ended September 30, 2006 or the nine months ended September 30, 2005. Changes in asset retirement obligations during the nine months ended September 30, 2006 and 2005 were as follows:


	2006		2005
				Restated
Asset retirement obligation January 1	$	3,630	$	3,291
Asset retirement accretion expense		372		104
Property additions		—		170
Foreign currency translation adjustment		—		65

Asset retirement obligation at September 30	$	4,002	$	3,630

NOTE 8 — GEOGRAPHIC OPERATING SEGMENT INFORMATION

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, France, Turkey, Romania and Hungary.

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.”


	Three Months Ended September 30, 2006
	United
	States			France		Turkey		Romania			Hungary			Total
Revenues	$	1,896		$	6,834	$	1,200	$	796		$	—		$	10,726
Costs and expenses		3,097			3,021		457		1,135			(292	)		7,418

Operating income (loss)	$	(1,201	)	$	3,813	$	743	$	(339	)	$	292		$	3,308


	Three Months Ended September 30, 2005 (restated)
	United
	States			France		Turkey			Romania			Hungary			Total
Revenues	$	1,979		$	5,962	$	829		$	—		$	—		$	8,770
Costs and expenses		2,321			2,293		2,183			70			173			7,040

Operating income (loss)	$	(342	)	$	3,669	$	(1,354	)	$	(70	)	$	(173	)	$	1,730


	Nine Months Ended September 30, 2006
	United
	States			France		Turkey		Romania			Hungary			Total
Revenues	$	5,389		$	21,564	$	3,049	$	796		$	—		$	30,798
Costs and expenses		8,898			9,770		1,563		1,348			639			22,218

Operating income (loss)	$	(3,509	)	$	11,794	$	1,486	$	(552	)	$	(639	)	$	8,580


	Nine Months Ended September 30, 2005 (restated)
	United
	States			France		Turkey			Romania			Hungary			Total
Revenues	$	5,506		$	14,998	$	2,106		$	—		$	—		$	22,610
Costs and expenses		7,399			6,791		3,348			86			173			17,797

Operating income (loss)	$	(1,893	)	$	8,207	$	(1,242	)	$	(86	)	$	(173	)	$	4,813


	Total Assets (1)
	United
	States		France		Turkey		Romania		Hungary		Total
September 30, 2006	$	34,347	$	88,110	$	153,863	$	15,591	$	13,956	$	305,867

September 30, 2005 (restated)	$	128,128	$	60,733	$	48,137	$	3,736	$	9,656	$	250,390


(1)		Total consolidated assets reflect the effect of intersegment eliminations.

NOTE 9 – INCOME TAXES

At September 30, 2006, the Company had recorded an income tax receivable of $5.0 million resulting primarily from a tax net operating loss through September 30, 2006 in our U.S segment and a $360,000 income tax payable resulting primarily from our net operating income through September 30, 2006 in our French segment. For the nine months ended September 30, 2006 and 2005 we paid income taxes of zero and approximately $900,000, respectively, related to 2004 taxable income. Our effective income tax rate differs from the statutory rates applicable to jurisdictions in which we operate due primarily to a change in enacted tax rates in France along with a net operating loss carryback claim relating to our 2003 French taxable income we discovered during the preparation of our 2005 French income tax return.

In May 2006, Texas enacted legislation that replaces the taxable capital and earned surplus components of its franchise tax with a new tax that is based on modified gross revenue. The new tax became effective beginning with the 2007 tax year. The prior franchise tax remained in effect through the end of 2006.

In accordance with generally accepted accounting principles in the United States, the new franchise tax is based on a measure of income, and thus accounted for in accordance with Statement of Financial

Accounting Standards No. 109 “Accounting for Income Taxes” (SFAS 109). The provisions of SFAS 109 require recognition of the effects of the tax law change in the period of enactment. The impact of the change in Texas tax law is not expected to have a material impact on the financial results of the Company.

Note 10 – Subsequent Event

Insurance Claims

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

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

Notice of Default

The Company delayed the filing of its Quarterly Report on Form 10-Q for the nine month period ended September 30, 2006. The delay in filing such Form 10-Q is due to Toreador not completing its restated consolidated financial statements for the years ended December 31, 2003, 2004 and 2005 and its consolidated financial statements for each of the quarters ended March 31 and June 30, 2006, as described in Note 1.

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

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

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

Default would occur if either the Borrowers or Toreador, as Guarantor under the Credit Agreement, default in the performance or observance of any other provision contained in any agreements or instruments evidencing or governing a material debt and such default is not waived and continues beyond any applicable cure period. Texas Capital, however, has waived the Default and Event of Default until January 16, 2007. As of January 14, 2006, the Company had $5.55 million borrowed under the Credit Agreement.

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

New Secured Revolving Facility

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

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

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

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

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

Nasdaq Violation

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

ITEM 2 – MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion is intended to assist you in understanding our business and results of operations together with our present financial condition. This section should be read in conjunction with our Consolidated Financial Statements and the accompanying notes included elsewhere in this Quarterly Report on Form 10-Q, as well as our Amended Annual Report on Form 10-K/A for the year ended December 31, 2005.

DISCLOSURES REGARDING FORWARD-LOOKING STATEMENTS

Certain matters discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this 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 caption 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. See “Item 1A. Risk Factors” in our Annual Report on Form 10-K/A, for the year ended December 31, 2005 for additional discussion of risks affecting our business.

Restatement for Previously Issued Financial Statements

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

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

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 exploration 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 data is available. Our international operations are located in the European Union or European Union candidate countries that we believe have stable governments, 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 onshore and offshore Turkey and onshore Hungary, Romania and France. We also own various working-interest properties primarily in Texas, Kansas, New Mexico, Louisiana and Oklahoma.

The Company’s financial and operating highlights for the nine months ended September 30, 2006, included the following:

	•		Operating income of $8.6 million, compared with $4.8 million for the nine months ended September 30, 2005,

	•		Production of 535 MBOE, compared with 462 MBOE for the nine months ended September 30, 2005,

	•		Cash flows from operating activities of $44.4 million, compared with $5.2 million for the nine months ended September 30, 2005, and

	•		Installation of the first tripod on the Akkaya structure in the Black Sea.

LIQUIDITY AND CAPITAL RESOURCES

This section should be read in conjunction with Note 6 to Notes to Consolidated Financial Statements included in this filing.

days after receiving the written notice from the Trustee. The thirty (30) day period ends on January 14, 2007. The Company provided a copy of the complete Quarterly Report on Form 10-Q for the quarter ended September 30, 2006 to the Trustee in accordance with the requirements of the Indenture.

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

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

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

Liquidity

As of September 30, 2006, we had cash on hand of $24.1 million, a current ratio of approximately 1.29 to 1 and a debt (currently consisting of convertible senior notes) to equity ratio of .56 to 1. For the three and nine months ended September 30, 2006, operating income was $3.3 million and $8.6 million, respectively, and capital expenditures were $38.6 million and $93.9 million, respectively.

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 (7.63 % total rate at September 30, 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 $6.8 million were available at September 30, 2006. In October 2006, the borrowing base was re-determined and was increased to $14.6 million. The $15 million facility contains various affirmative and negative covenants. These covenants, among other things, limit additional indebtedness, the sale of assets, change of control and management, limitations on the distribution of stock dividends and require us to meet certain financial requirements. Specifically, we must maintain an interest cost ratio of not less than 4.00

to 1.00, an indebtedness ratio of not less than 1.00 to 1.00, asset life cover ratio of not less than 1.25 to 1.00, a loan life cover ratio equal to or greater than 1.15 to 1.00 and a debt service coverage ratio equal to or greater than 1.10 to 1.00. As of September 30, 2006, we were in compliance with all covenants. At September 30, 2006, we had no outstanding borrowings; however, as of January 14, 2007, we had $11 million outstanding at an annual interest rate of 7.87%.

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 September 30, 2006) and is collateralized by our domestic working interests. The borrowers under this facility are two of our domestic subsidiaries, and Toreador has guaranteed the obligations. At September 30, 2006, we had no amounts outstanding and approximately $6 million available for borrowings. The $25 million facility requires monthly interest payments until January 1, 2009 at which time all unpaid principal and interest are due. The $25 million facility contains various affirmative and negative covenants. These covenants, among other things, limit additional indebtedness, the sale of assets, change of control and management and require us to meet certain financial requirements. Specifically, we must maintain a current ratio of 1.25 to 1.00 (exclusive of amounts due under revolving credit arrangements) and an interest coverage ratio of not less than 3.00 to 1.00. As of September 30, 2006, we were in compliance with all covenants. At September 30, 2006, we had no outstanding borrowings; however, as of January 14, 2007, we had $5.55 million outstanding at an annual interest rate of 7.75%.

New Secured Revolving Facility

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

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

Company of all its shares in Toreador International; and (iv) the current loan facilities with Natixis Banques Populaires and with Texas Capital Bank, N.A. shall have been repaid in full.

Convertible Senior Notes

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. The Company also granted the initial purchasers the option to purchase an additional $11.25 million aggregate principal amount of Notes to cover over-allotments. The option was exercised on September 30, 2005, which resulted in a total principal amount of $86.25 million and total net proceeds of approximately $82.2 million. The funds have been used for general corporate purposes, including funding a portion of the Company’s 2005 and 2006 exploration and development activities. (See Note 6 to Notes to Consolidated Financial Statements for additional detail.)

Preferred Stock

As of September 30, 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 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.

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.

Private Placement

On September 16, 2005, we sold 806,450 shares of our common stock to certain accredited investors pursuant to a private placement. The net proceeds of approximately $23.8 million was used for general corporate purposes, including the funding of our capital expenditures requirements in 2005 and 2006.

Dividends on our Series A-1 Convertible Preferred Stock are paid quarterly. For the three and nine months ended September 30, 2006 dividends totaled $41,000 and $122,000, respectively, of which all was paid in cash. Dividends of $41,000 and $644,000, respectively, were paid for the three and nine months ended September 30, 2005 of which $41,000 and $146,000, respectively, were paid in cash.

The terms of the $15 million reserve-based borrowing facility limit our ability to pay dividends on our common stock to twenty-five percent (25%) of net profit (as defined in the facility agreement), less any dividend amounts paid on our preferred stock. The terms of the new loan with the International Finance Corporation prohibit us from paying dividends except on our Series A-1 Convertible Preferred Stock.

Contractual Obligations

We believe that sufficient funds will be available from operating cash flow, cash on hand, our current facilities, other facilities that we may enter into and any future public or private issuance of debt or equity securities to meet anticipated capital budget requirements and fund potential acquisitions through September 30, 2007.

CRITICAL ACCOUNTING POLICIES

The discussion and analysis of our financial condition and results of operations is based upon the consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. Our significant accounting policies are described in Note 2 to our consolidated financial statements included in Amended Form 10-K/A for the year ended December 31, 2005. We have identified below policies that are of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by management. We analyze our estimates on a periodic basis and base our estimates on experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates using different assumptions or conditions. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our financial statements:

Successful Efforts Method of Accounting

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

The application of the successful efforts method of accounting requires management’s judgment to determine the proper designation of wells as either developmental or exploratory, which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and application of industry experience. Wells may be completed that are assumed to be productive and actually deliver oil and natural gas in quantities insufficient to be economic, which

may result in the abandonment of the wells at a later date. On occasion, wells are drilled which have targeted geologic structures that are both developmental and exploratory in nature, and in such instances an allocation of costs is required to properly account for the results. Delineation seismic costs incurred to select development locations within a productive oil and natural gas field are typically treated as development costs and capitalized, but often these seismic programs extend beyond the proved reserve areas and therefore management must estimate the portion of seismic costs to expense as exploratory. The evaluation of oil and natural gas leasehold acquisition costs requires management’s judgment to estimate the fair value of exploratory costs related to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

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

Reserve Estimates

Proved reserves are estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods as well as oil and natural gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery after testing by a pilot project or after the operation of an installed program has been confirmed through production response that increased recovery will be achieved. Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Proved undeveloped reserves on undrilled acreage is limited (i) to those drilling units offsetting productive units that are reasonably certain of production when drilled and (ii) to other undrilled units where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. We emphasize that the volume of reserves are estimates that, by their nature are subject to revision. The estimates are made using geological and reservoir data, as well as production performance data. These estimates are reviewed annually and revised, either upward or downward, as warranted by additional performance data. We had a downward reserve revision of 2.4% for the year ended December 31, 2005 and upward reserve revisions of 5.03% and 2.34% of proved reserves during the years ended December 31, 2004 and 2003, respectively. These reserve revisions resulted primarily from improved or a decline in performance from a variety of sources such as an addition to or a reduction in recoveries below or above previously established lowest known hydrocarbon levels, improved or a decline in drainage from natural drive mechanisms, and the realization of improved or declined drainage areas. If the estimates of proved reserves were to decline, the rate at which we record depletion expense would increase.

Impairment of Oil and Natural Gas Properties

We review our proved oil and natural gas properties for impairment on an annual basis or whenever events and circumstances indicate a potential decline in the recoverability of their carrying value. We estimate the expected future cash flows from our proved oil and natural gas properties and compare these future cash flows to the carrying value of the oil and natural gas properties to determine if the carrying value is recoverable. If the carrying value exceeds the estimated undiscounted future cash flows, we will adjust the carrying value of the oil and natural gas properties to its fair value in the current period. The factors used to determine fair value include, but are not limited to, estimates of reserves, future

commodity prices, future production estimates, anticipated capital expenditures, and a discount rate commensurate with the risk associated with realizing the expected cash flows projected. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the period. Given the complexities associated with oil and natural gas reserve estimates and the history of price volatility in the oil and natural gas markets, events may arise that will require us to record an impairment of our oil and natural gas properties and there can be no assurance that such impairments will not be required in the future nor that they will not be material.

Future Development and Abandonment Costs

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

RESULTS OF OPERATIONS

COMPARISON OF THE THREE MONTHS ENDED SEPTEMBER 30, 2006 AND 2005

The following tables present production and average unit prices for the geographic segments indicated:


	For the Three Months Ended September 30,
	2006		2005
Production
Oil (MBbls):
United States		16		15
France		104		105
Romania		2		—
Turkey		20		16

Total		142		136


Gas (MMcf):
United States		121		135
France		—		—
Romania		192		—
Turkey		—		—

Total		313		135


MBOE:
United States		36		38
France		104		105
Romania		34		—
Turkey		20		16

Total		194		159


Average Price
Oil ($/Bbl):
United States	$	65.56	$	58.18
France		65.94		57.00
Romania		50.65		—
Turkey		60.74		51.04

Total	$	64.91	$	56.42


Gas ($/Mcf):
United States	$	6.04	$	8.20
France		—		—
Romania		3.50		—
Turkey		—		—

Total	$	4.48	$	8.20


$/BOE:
United States	$	49.33	$	52.81
France		65.94		57.00
Romania		23.12		—
Turkey		60.74		51.04

Total	$	54.71	$	55.39

Revenue

Oil and natural gas sales

Oil and natural gas sales for the three months ended September 30, 2006 were $10.7 million, as compared to $8.8 million for the comparable period in 2005. This increase is primarily due to an increase in production of 35 MBOE that resulted in an additional $2 million of revenue, somewhat offset by a $0.68 per BOE decline in average price received that resulted in a $132,000 decrease in revenue. The increase in production was primarily due to a full quarter of Romanian gas sales.

The above table compares both volumes and prices received for oil and natural gas for the three months ended September 30, 2006 and 2005. Oil and natural gas prices are and will continue to be extremely volatile and a significant change will have a material impact on our revenue.

We had no loss on commodity derivatives in the three months ended September 30, 2006 and 2005. We were not party to any hedging contracts as of September 30, 2006.

Costs and expenses

Lease operating

Lease operating expense was $2.6 million, or $13.40 per BOE produced for the quarter ended September 30, 2006, as compared to $2.1 million, or $13.21 per BOE produced for the comparable period in 2005. This increase is primarily due to a full quarter of Romanian gas sales.

Exploration expense.

Exploration expense for the third quarter of 2006 was $414,000, as compared to $1.2 million in the third quarter of 2005. This decrease is due primarily to the completion of seismic interpretation and analysis of our Black Sea prospects in offshore Turkey.

Dry hole and abandonment

Dry hole and abandonment cost for the third quarter of 2006 was zero, as compared to $1.4 million in the third quarter of 2005. This decrease is due to expensing the Boyabot # 1 well in Turkey, which did not test sufficient oil and gas to be declared commercial, in the quarter ended September 30, 2005.

Depreciation, depletion and amortization.

Third quarter 2006 depreciation, depletion and amortization expense was $2.0 million, or $10.31 per BOE produced, as compared to $1 million, or $6.29 per BOE produced for the third quarter of 2005. This increase is primarily due to the development and recompletion program in France in 2005 and a full quarter of Romania gas sales.

General and administrative

General and administrative expense was $2.4 million, for the third quarter of 2006 compared with $1.3 million for the third quarter of 2005. The increase is primarily due to increased staff and pay increases and bonuses, expensing of stock compensation expense related to the restricted stock granted by the Board of Directors to certain employees and non employee directors, the expensing of stock options as required by the adoption of SFAS 123 (R), and consulting fees associated with the preparation of the Company’s “Strategic Plan” as requested by the Board of Directors.

Other income and expense

Other income and expense resulted in income of $3.3 million for the three months ended September 30, 2006 versus $403,000 for the comparable period in 2005. The primary reason for the increase was due to a currency gain in Turkey during the third quarter of 2006 totaling $2.7 million.

Income available to common shareholders

For the third quarter of 2006, we reported income available to common shareholders of $5.4 million, compared with $1.3 million for the same period of 2005.

Other comprehensive income

This item should be read in conjunction with Note 5 in the Notes to Consolidated Financial Statements included in this filing.

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 $3.3 million. In the third quarter 2006 we had an unrealized gain of $9.6 million. The functional currency of our operations in France is the Euro, the functional currency in Romania, Turkey and in Hungary is the US Dollar. The exchange rates used to translate the financial position of the French, Turkish, Romanian and Hungarian operations at September 30, 2006 and 2005, are shown below:


	September 30, 2006		September 30, 2005
Euro	$	1.2660	$	1.2042

New Turkish Lira	$	0.6624	$	0.7407

Romania Lei	$	0.00004	$	0.00003

Hungarian Forint	$	0.0046	$	0.0048

COMPARISON OF THE NINE MONTHS ENDED SEPTEMBER 30, 2006 AND 2005

The following tables present production and average unit prices for the geographic segments indicated:


	For the Nine Months Ended September 30,
	2006		2005
Production
Oil (MBbls):
United States		45		45
France		341		301
Romania		2		—
Turkey		54		49

Total		442		395


Gas (MMcf):
United States		369		396
France		—		—
Romania		192		—
Turkey		—		—

Total		561		396


MBOE:
United States		106		112
France		341		301
Romania		34		—
Turkey		54		49

Total		535		462


Average Price
Oil ($/Bbl):
United States	$	62.97	$	51.32
France		63.26		49.88
Romania		50.65		—
Turkey		56.83		43.06

Total	$	62.38	$	49.20


Gas ($/Mcf):
United States	$	6.25	$	7.04
France		—		—
Romania		3.50		—
Turkey		—		—

Total	$	5.31	$	7.04


$/BOE:
United States	$	48.24	$	45.97
France		63.26		49.88
Romania		23.12		—
Turkey		56.83		43.06

Total	$	57.05	$	48.21

Revenue

Oil and natural gas sales

Oil and natural gas sales for the nine months ended September 30, 2006 were $30.8 million, as compared to $22.6 million for the comparable period in 2005. This increase is primarily due to a $8.84 per BOE increase in price that resulted in a $4.2 million increase in revenue and an increase in production of 73 MBOE that resulted in an additional $4.3 million of revenue. The increase in production was primarily due to the French workovers and horizontal wells completed in late 2005 and the commencement of Romanian gas sales. The above table compares both volumes and prices received for oil and natural gas for the nine months ended September 30, 2006 and 2005. Oil and natural gas prices are and will continue to be extremely volatile and a significant change will have a material impact on our revenue.

We had no loss on commodity derivatives in the nine months ended September 30, 2006 and 2005. We were not party to any hedging contracts as of September 30, 2006.

Costs and expenses

Lease operating

Lease operating expense was $7.7 million, or $14.39 per BOE produced for the nine months ended September 30, 2006, as compared to $6.4 million, or $13.85 per BOE produced for the comparable period in 2005. This increase is primarily due to the 2006 workover program in France, commencement of production in Romania, higher costs and the age of the fields.

Exploration expense.

Exploration expense for the nine months ended September 30, 2006 was $2.7 million, as compared to $2.0 million for the comparable period in 2005.

Dry hole and abandonment

Dry hole and abandonment cost for the nine months ended September 30, 2006 was zero, as compared to $1.4 million for the comparable period in 2005. This decrease is due to expensing the Boyabot # 1 well in Turkey, which did not test sufficient oil and gas to be declared commercial, in the period ended September 30, 2005.

Depreciation, depletion and amortization.

For the nine months ended September 30, 2006, depreciation, depletion and amortization expense was $4.6 million, or $8.60 per BOE produced, as compared to $2.9 million, or $6.28 per BOE produced for the nine months ended September 30, 2005. This is increase is primarily due to increased investments in oil and gas properties.

General and administrative

General and administrative expense was $7.3 million, for the nine months ended September 30, 2006 compared with $5.1 million for the comparable period of 2005. The increase is primarily due to increased personnel costs, expensing of stock based compensation expense related to the restricted stock granted by the Board of Directors to certain employees and non employee directors, the expensing of stock options

as required by the adoption of SFAS 123 (R), the Hungarian office which was open in July 2005 and consulting fees associated with the preparation of the Company’s “Strategic Plan”.

Other income and expense

Other income and expense resulted in income of $4.6 million for the nine months ended September 30, 2006 versus income of $1.1 million for the comparable period in 2005. The increase is primarily due to the realized a foreign exchange gain of $1 million that was primarily attributable to a Euro deposit account that was established in late 2005. We purchased the Euros when the value was $1.19 and on September 30, 2006 the Euro was valued at approximately $1.27. We also realized currency transaction gains in Turkey and Hungary. In the second quarter of 2006 we also recorded a gain on the sale of oil and gas properties and other assets of $651,000.

Net income available to common shareholders

For the nine months ended September 30, 2006, we reported income available to common shareholders of $10.1 million, compared with $4.6 million for the same period of 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 $3.3 million. For the nine months ended September 30, 2006, we had an unrealized gain of $1.1 million. The functional currency of our operations in France is the Euro, the functional currency in Romania, Turkey and in Hungary is the US Dollar. The exchange rates used to translate the financial position of the French, Turkish, Romanian and Hungarian operations at September 30, 2006 and 2005 are shown below:


	September 30, 2006		September 30, 2005
Euro	$	1.2660	$	1.2042

New Turkish Lira	$	0.6624	$	0.7420

Romania Lei	$	0.00004	$	0.00003

Hungarian Forint	$	0.0046	$	0.0048

Item 3. Quantitative and Qualitative Disclosure About Market Risk

There have been no material changes from the information provided in Item 7A of our Annual Report on Form 10K for the year ended December 31, 2005.

ITEM 4 – CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in reports that we file or submit under the Securities Exchange Act of 1934, is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and that such information is accumulated and communicated to our management, including our Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer, as appropriate, to allow timely decisions regarding required disclosures. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management is required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures. As of the end of the period covered by this report, and under the supervision and with the participation of our management, including our Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer, we evaluated the effectiveness of the design and operation of these disclosure controls and procedures. As a result of the weaknesses described below, based on this evaluation, our Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer 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.

We have assessed our internal controls and concluded the following material weaknesses existed at September 30, 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.

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

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

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

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the three months ended September 30, 2006, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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

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

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

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

	•		Formally documenting our accounting policies and procedures.

PART II. OTHER INFORMATION

Item 1A. Risk Factors

Failure to maintain effective internal controls could have a material adverse effect on our operations and 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 three months ended September 30, 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.

We anticipate that at December 31, 2006, our disclosure controls and procedures will not have been effective in reaching a reasonable level of assurance of achieving management’s desired controls and procedures objectives and that we will have material weaknesses in our internal control over financial reporting.

Item 3 – Defaults Upon Senior Securities

See Note 10 and “Item 2 – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources” regarding the default under the Indenture.

ITEM 6 – EXHIBITS


Exhibit
Number	Description	Incorporation by Reference
10.1	Michael J. FitzGerald Change in Control Agreement dated November 8, 2006	Incorporated by reference from Exhibit 10.1 to Current Report on Form 8-K filed on November 15, 2006.

10.2	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, as 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	Incorporated by reference from Exhibit 10.1 to Current Report on Form 8-K filed on January 4, 2007.

31.1	Rule 13a-14(a) Certification of Chief Executive Officer	Filed Herewith

31.2	Rule 13a-14(a) Certification of Chief Financial Officer	Filed Herewith

31.3	Rule 13a-14(a) Certification of Chief Accounting Officer	Filed Herewith

32.1	Section 1350 Certification of Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer	Filed Herewith

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


	TOREADOR RESOURCES CORPORATION, Registrant
January 14, 2007	/s/ G. Thomas Graves III
	G. Thomas Graves III
	President and Chief Executive Officer



January 14, 2007	/s/ Douglas W. Weir
	Douglas W. Weir
	Senior Vice President and Chief Financial Officer



January 14, 2007	/s/ Charles J. Campise
	Charles J. Campise
	Vice President – Accounting and Chief Accounting Officer

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Toreador Resources (TRGL) Inactive 10-Q2006 Q3 Quarterly report

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