TOREADOR RESOURCES CORP - FORM 10-Q

Attached files

file	filename
EX-31.1 - EX-31.1 - TOREADOR RESOURCES CORP	a10-17549_1ex31d1.htm
EX-31.2 - EX-31.2 - TOREADOR RESOURCES CORP	a10-17549_1ex31d2.htm
EX-32.1 - EX-32.1 - TOREADOR RESOURCES CORP	a10-17549_1ex32d1.htm

Table of Contents

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended: September 30, 2010

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

Commission file number 001-34216

TOREADOR RESOURCES CORPORATION

(Exact name of registrant as specified in its charter)

Delaware

75-0991164

(State or other jurisdiction

of incorporation)

(I.R.S. Employer

Identification Number)

c/o Toreador Holding SAS

9 rue Scribe

75009 Paris, France

(Address of principal executive office)

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

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

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

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

Large accelerated filer o	Accelerated filer x

Non-accelerated filer o	Smaller Reporting company o
(Do not check if a smaller reporting company)

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

As of November 8, 2010, there were 25,828,705 shares of common stock, par value $.15625 per share, outstanding.

Table of Contents

TOREADOR RESOURCES CORPORATION

TABLE OF CONTENTS

		Page
	PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements (unaudited)

	Condensed Consolidated Balance Sheets — September 30, 2010 and December 31, 2009	1

	Condensed Consolidated Statements of Operations — for the three months ended September 30, 2010 and 2009	2

	Condensed Consolidated Statements of Operations — for the nine months ended September 30, 2010 and 2009	3

	Condensed Consolidated Statement of Changes in Stockholder’s Equity — September 30, 2010	4

	Condensed Consolidated Statements of Cash Flows — for the nine months ended September 30, 2010 and 2009	5

	Notes to Condensed Consolidated Financial Statements	6

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	47

Item 4.	Controls and Procedures	48

	PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	49

Item 1A.	Risk Factors	49

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	49

Item 6.	Exhibits	49

	SIGNATURES	50

Table of Contents

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS (UNAUDITED)

TOREADOR RESOURCES CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEET

	September 30,			December 31,
	2010			2009
	(Unaudited)
	(In thousands, except share and per share data)
ASSETS
Current assets:
Cash and cash equivalents (Note 2)	$	53,550		$	8,712
Accounts receivable (Note 2)	3,388			3,126
Income tax receivable (Note 8)	—			245
Other	3,762			3,593
Total current assets	60,700			15,676

Oil and natural gas properties
Oil and natural gas properties, gross	108,061			116,435
Accumulated depletion, depreciation and amortization	(42,185		)	(41,814		)
Oil and natural gas properties, net	65,876			74,621

Investments	200			200
Goodwill	3,764			3,973
Other assets	1,738			2,685

Total assets	$	132,278		$	97,155

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	6,888		$	11,635
Deferred lease payable — current portion	112			107
Derivatives (Note 13)	177			886
Current portion of long-term debt (Note 5)	32,385			32,385
Income taxes payable (Note 8)	6,303			—
Total current liabilities	45,865			45,013

Long-term accrued liabilities	1,249			1,241
Deferred lease payable, net of current portion	359			442
Asset retirement obligations (Note 6)	4,009			6,733
Deferred income tax (Note 8)	14,866			15,358
Long-term debt (Notes 5 and 14)	34,716			22,231
Total liabilities	101,064			91,018
Stockholders’ equity:
Common stock, $0.15625 par value, 30,000,000 shares authorized; 28,828,705 in 2010 and 22,106,955 in 2009 shares issued	4,036			3,454
Additional paid-in capital	198,458			170,895
Accumulated deficit	(180,494		)	(176,578		)
Accumulated other comprehensive income	11,748			10,900
Treasury stock at cost, 721,027 shares for 2009 and 2010	(2,534		)	(2,534		)
Total stockholders’ equity	31,214			6,137

Total liabilities and stockholders’ equity	$	132,278		$	97,155

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

Table of Contents

TOREADOR RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

	Three Months Ended
	September 30,
	2010			2009
	(Unaudited)
	(In thousands, except share and per share data)
Revenues and other income:
Sales and other operating revenue	$	6,003		$	5,204
Other income	560			—
Total revenues and other income	6,563			5,204
Operating costs and expenses:
Lease operating expense	2,966			1,468
Exploration expense	201			22
Depreciation, depletion and amortization	1,129			1,266
Accretion on discounted assets and liabilities (Notes 5 and 6)	(246		)	127
General and administrative	1,773			4,136
Loss (gain) on oil and gas derivative contracts (Note 13)	105			(7		)
Total operating costs and expenses	5,928			7,012
Operating income (loss)	635			(1,808		)
Other (expense) income:
Foreign currency exchange gain (loss)	(1,178		)	1
Interest expense, net of interest capitalized (Note 5)	(2,727		)	(366		)
Total other income (expense)	(3,905		)	(365		)
Loss before taxes from continuing operations	(3,270		)	(2,173		)
Income tax (benefit) provision (Note 8)	(666		)	(232		)
Loss from continuing operations, net of income taxes	(2,604		)	(1,941		)
Loss from discontinued operations, net of income taxes (Note 12)	(290		)	(10,518		)
Net loss available to common shares	$	(2,894	)	$	(12,459	)

Basic loss available to common shares per share:
From continuing operations, net of income taxes	$	(0.11	)	$	(0.09	)
From discontinued operations, net of income taxes	(0.01		)	(0.50		)
	$	(0.12	)	$	(0.59	)

Diluted loss available to common shares per share:
From continuing operations, net of income taxes	$	(0.10	)	$	(0.09	)
From continuing operations, net of income taxes	(0.01		)	(0.50		)
	$	(0.11	)	$	(0.59	)

Weighted average shares outstanding:
Basic	24,660			20,869
Diluted	25,917			20,869

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

Table of Contents

TOREADOR RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

	Nine Months Ended
	September 30,
	2010			2009
	(Unaudited)
	(In thousands, except share and per share data)
Revenues and other income:
Sales and other operating revenue	$	17,460		$	13,096
Other income (Note 16)	15,560			121
Total revenues and other income	33,020			13,217
Operating costs and expenses:
Lease operating expense	7,344			5,029
Exploration expense	1,276			130
Depreciation, depletion and amortization	2,807			4,171
Accretion on discounted assets and liabilities (Notes 5 and 6)	(159		)	365
General and administrative	9,615			14,663
Gain on oil and gas derivative contracts (Note 13)	(709		)	(7		)
Total operating costs and expenses	20,174			24,351
Operating income (loss)	12,846			(11,134		)
Other (expense) income:
Foreign currency exchange gain (loss)	(1,254		)	131
(Loss) gain on the early extinguishment of debt (Note 5)	(4,256		)	3,370
Interest expense, net of interest capitalized	(4,448		)	(1,833		)
Total other (expense) income	(9,958		)	1,668
Income (loss) before taxes from continuing operations	2,888			(9,466		)
Income tax (benefit) provision (Note 8)	5,683			(1,002		)
Loss from continuing operations, net of income taxes	(2,795		)	(8,464		)
Loss from discontinued operations, net of income taxes (Note 12)	(1,113		)	(11,988		)
Net loss available to common shares	$	(3,908	)	$	(20,452	)

Basic loss available to common shares per share:
From continuing operations, net of income taxes	$	(0.12	)	$	(0.41	)
From discontinued operations, net of income taxes	(0.05		)	(0.59		)
	$	(0.17	)	$	(1.00	)

Diluted loss available to common shares per share:
From continuing operations, net of income taxes	$	(0.11	)	$	(0.41	)
From continuing operations, net of income taxes	(0.04		)	(0.59		)
	$	(0.15	)	$	(1.00	)

Weighted average shares outstanding:
Basic	24,393			20,428
Diluted	25,811			20,428

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

Table of Contents

TOREADOR RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

NINE MONTHS ENDED SEPTEMBER 30, 2010

(UNAUDITED)

	Common Stock (Shares)	Common Stock ($)		Additional Paid-in Capital			Accumulated deficit			Accumulated Other Comprehensive Income (loss)		Treasury Stock (Shares)	Treasury Stock ($)			Total Stockholders’ Equity
Balance at December 31, 2009	22,107	$	3,454	$	170,895		$	(176,578	)	$	10,900	721	$	(2,534	)	$	6,137
Exercise of stock options	5	—		15			—			—		—	—			15
Return of stock options exercised	—	1		—			—			—		—	—			1
Issuance of restricted stock	267	42		(42		)	—			—		—	—			—
Issuance of common stock	3,450	539		28,786			—			—		—	—			29,325
Amortization of deferred stock compensation	—	—		1,370			—			—		—	—			1,370
Net loss	—	—		—			(3,908		)	—		—	—			(3,908		)
Foreign currency translation adjustment	—	—		—			—			848		—	—			848
Tax effect of restricted stock	—	—		(87		)	—			—		—	—			(87		)
Payment of equity issuance costs	—	—		(2,489		)	—			—		—	—			(2,489		)
Other	—	—		10			(8		)	—		—	—			2

Balance at September 30, 2010	25,829	$	4,036	$	198,458		$	(180,494	)	$	11,748	721	$	(2,534	)	$	31,214

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

Table of Contents

TOREADOR RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	Nine Months Ended
	September 30,
	2010			2009
	(Unaudited)
	(In thousands)
Cash flows from operating activities:
Net loss	$	(3,908	)	$	(20,452	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	2,807			4,693
Accretion on discounted assets and liabilities	(159		)	—
Amortization of deferred debt issuance costs	1,409			—
Stock based compensation	2,631			3,909
Deferred income taxes (liabilities) benefit	(492		)	679
Dry hole costs				1,318
Impairment of oil and natural gas properties	—			10,725
Gain on sale of properties and equipment	—			(121		)
Gain on sale of discontinued operations	—			(1,675		)
Loss (gain) on early extinguishment of debt — convertible notes	4,256			(3,370		)
Loss on early extinguishment of debt — revolving credit facility	—			4,881
Unrealized gain on commodity derivatives	(709		)	—
Increase in accounts receivable	(262		)	(1,677		)
Decrease in income taxes receivable	245			—
Decrease (increase) in other current assets	(169		)	8
Decrease in other assets	652			155
Increase in other assets held for sale	—			(1,299		)
(Decrease) increase in accounts payable and accrued liabilities	(4,747		)	1,080
Decrease in deferred lease payable	(78		)	—
Increase (decrease) in income taxes payable	6,303			(4,223		)
Decrease in liabilities held for sale	—			(5,797		)
Decrease in long-term accrued liabilities	8			—
Net cash provided by (used in) operating activities	7,787			(11,166		)
Cash flows from investing activities:
Proceeds from sale of property and equipment	—			121
Additions to property and equipment	(298		)	(4,521		)
Proceeds from sale of oil and gas properties	—			60,418
Net cash (used in) provided by investing activities	(298		)	56,018
Cash flows from financing activities:
Repayment of convertible notes	(22,231		)	(12,661		)
Repayment of revolving credit facility	—			(36,372		)
Issuance of convertible notes	31,631
Deferred debt issuance costs	(1,936		)
Proceeds from issuance of common stock, net of equity issuance costs of $2,489	26,837			(49		)
Proceeds from exercise of stock options	15
Net cash provided by (used in) financing activities	34,316			(49,082		)
Net increase (decrease) in cash and cash equivalents	41,805			(4,230		)
Effects of foreign currency translation on cash and cash equivalents	3,033			(4		)
Cash and cash equivalents, beginning of period	8,712			14,860
Cash and cash equivalents, end of period	$	53,550		$	10,626
Supplemental disclosures:
Cash paid during the period for interest, net of interest capitalized	$	3,255		$	1,669
Cash paid during the period for income taxes	$	11		$	4,032

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

Table of Contents

TOREADOR RESOURCES CORPORATION

NOTES TO CONDENSED 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 (the “SEC”). 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, unless noted herein. 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. These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2009, which was filed with the SEC on March 16, 2010. The results of operations for interim periods are not necessarily indicative of the results to be expected for the full year.

We are a Delaware corporation that was incorporated in 1951. Our common stock is traded on the NASDAQ Global Market under the trading symbol TRGL. Our offices in the United States are located at 13760 Noel Road, Suite 1100, Dallas, TX, 75240-1383 (telephone number: (214) 559-3933). Our principal executive offices are located at c/o Toreador Holding SAS, 9 rue Scribe, 75009 Paris, France (telephone number: +33 1 47 03 34 24). Our website address is www.toreador.net.

Unless otherwise noted, amounts reported in tables are in thousands, except per unit data.

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

Revenue Recognition

Our French crude oil production accounts for substantially all of our sales. We sell our French crude oil to Total Raffinage Marketing (“TOTAL”), and recognize the related revenues when the production is delivered to TOTAL’s refinery, typically via truck. At the time of delivery to the plant, title to the crude oil transfers to TOTAL. The terms of the contract with TOTAL state that the price received for oil sold will be the arithmetic mean of all average daily quotations of Dated Brent published in Platt’s Oil Market Wire for the month of production less a specified differential per barrel. The pricing of oil sales is done on the first day of the month following the month of production. In accordance with the terms of the contract, payment is made within six working days of the date of issue of the invoice. The contract with TOTAL is automatically extended for a period of one year unless either party cancels it in writing no later than six months prior to the beginning of the next year.

Taxes associated with production are classified as lease operating expense.

Gain on sales of proved and unproved properties are only recognized when there is no uncertainty about the recovery of costs applicable to interests retained or where there is no substantial obligation for future performance by the Company. Losses on properties sold are recognized when incurred. Any gain or loss is reflected in “Other Income.”

New Accounting Pronouncements

In January 2010, the FASB issued guidance that clarifies and requires new disclosures about fair value measurements. The clarifications and requirement to disclose the amounts and reasons for significant transfers

Table of Contents

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

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

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

NOTE 2 - CONCENTRATION OF CREDIT RISK AND ACCOUNTS RECEIVABLE

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

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

Accounts receivable consisted of the following:

	September 30,		December 31,
	2010		2009
Oil and natural gas sales receivables	$	2,130	$	2,055
Recoverable VAT	71		636
Other accounts receivable	1,187		436
	$	3,388	$	3,126

Table of Contents

NOTE 3 — EARNINGS (LOSS) PER COMMON SHARE

The following table reconciles the numerators and denominators of the basic and diluted earnings (loss) per common share computation:

	Three Months Ended
	September 30,
	2010			2009
Basic loss per share:
Numerator:
Loss from continuing operations, net of income tax	$	(2,604	)	$	(1,941	)
Loss from discontinued operations, net of income tax	(290		)	(10,518		)
Net loss available to common shareholders	$	(2,894	)	$	(12,459	)

Denominator:
Weighted average common shares outstanding	24,660			20,869

Basic loss available to common shareholders per share from:
Continuing operations	$	(0.11	)	$	(0.09	)
Discontinued operations	(0.01		)	(0.50		)
	$	(0.12	)	$	(0.59	)

Diluted loss per share:
Numerator:
Loss from continuing operations, net of income tax	$	(2,604	)	$	(1,941	)
Loss from discontinued operations, net of income tax	(290		)	(10,518		)
Net loss available to common shareholders	$	(2,894	)	$	(12,459	)

Denominator:
Weighted average common shares outstanding	25,917			20,869
Conversion of notes payable	—		(1)	—		(1)
Diluted shares outstanding	25,917			20,869

Diluted loss available to common shareholders per share from:
Continuing operations	$	(0.10	)	$	(0.09	)
Discontinued operations	(0.01		)	(0.50		)
	$	(0.11	)	$	(0.59	)

(1)

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

Table of Contents

	Nine Months Ended
	September 30,
	2010			2009
Basic loss per share:
Numerator:
Loss from continuing operations, net of income tax	$	(2,795	)	$	(8,464	)
Loss from discontinued operations, net of income tax	(1,113		)	(11,988		)
Net loss available to common shareholders	$	(3,908	)	$	(20,452	)

Denominator:
Weighted average common shares outstanding	24,393			20,428

Basic loss available to common shareholders per share from:
Continuing operations	$	(0.12	)	$	(0.41	)
Discontinued operations	(0.05		)	(0.59		)
	$	(0.17	)	$	(1.00	)

Diluted loss per share:
Numerator:
Loss from continuing operations, net of income tax	$	(2,795	)	$	(8,464	)
Loss from discontinued operations, net of income tax	(1,113		)	(11,988		)
Net loss available to common shareholders	$	(3,908	)	$	(20,452	)

Denominator:
Weighted average common shares outstanding	25,811			20,428
Conversion of notes payable	—		(1)	—		(1)
Diluted shares outstanding	25,811			20,428

Diluted loss available to common shareholders per share from:
Continuing operations	$	(0.11	)	$	(0.41	)
Discontinued operations	(0.04		)	(0.59		)
	$	(0.15	)	$	(1.00	)

(1)

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

Table of Contents

NOTE 4 — COMPREHENSIVE INCOME (LOSS)

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Net loss	$	(2,894	)	$	(12,459	)	$	(3,908	)	$	(20,452	)
Foreign currency translation adjustment	7,300			(2,034		)	848			(4,289		)
Comprehensive income (loss)	$	4,406		$	(14,493	)	$	(3,060	)	$	(24,741	)

NOTE 5 — LONG-TERM DEBT

Long-term debt consisted of the following:

	September 30,			December 31,
	2010			2009
Convertible senior notes	$	67,101		$	54,616

Less: current portion	(32,385		)	(32,385		)

Total long-term debt	$	34,716		$	22,231

Secured Revolving Facility with the International Finance Corporation

On December 28, 2006, we entered into a loan and guarantee agreement with International Finance Corporation. The loan and guarantee agreement provided for a $25 million facility which was a secured revolving facility with a maximum facility amount of $25 million which maximum facility amount would have increased to $40 million when the projected total borrowing base amount exceeds $50 million. The $25 million facility was funded on March 2, 2007. The loan and guarantee agreement also provided for an unsecured $10 million facility which was funded on December 28, 2006. Both the $25 million facility and the $10 million facility were to fund our operations in Turkey and Romania.

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

5.00% CONVERTIBLE SENIOR NOTES DUE OCTOBER 1, 2025

Table of Contents

The Company also granted the initial purchasers the option to purchase an additional $11.25 million aggregate principal amount of 5.00% Convertible Senior Notes to cover over-allotments. The over-allotment option was exercised on September 30, 2005. The total principal amount of 5.00% Convertible Senior Notes issued was $86.25 million and total net proceeds were approximately $82.2 million. We incurred approximately $4.1 million of costs associated with the issuance of the 5.00% Convertible Senior Notes; these costs have been recorded in other assets on the balance sheet and are being amortized to interest expense using the straight-line interest rate method (which approximates the effective interest method) over the term of the 5.00% Convertible Senior Notes (i.e., from issuance to the earliest date on which holders may require the Company to repurchase all or a portion of their 5.00% Convertible Notes, in this case October 1, 2010). See “Note 19 — Subsequent Events.”

The net proceeds were used for general corporate purposes, including funding a portion of the Company’s 2005 and 2006 exploration and development activities.

The 5.00% Convertible Senior Notes bear interest at a rate of 5.00% 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 5.00% Convertible Senior Notes (equivalent to a conversion price of approximately $42.81 per share), subject to adjustment in the event of, among other things, a fundamental change (as defined in the indenture). We could have redeemed the 5.00% Convertible Senior Notes, in whole or in part, on or after October 6, 2008, and prior to October 1, 2010, for cash at a redemption price equal to 100% of the principal amount of 5.00% Convertible Senior Notes to be redeemed, plus any accrued and unpaid interest, if the closing price of our common stock exceeded 130% of the conversion price over a specified period. On or after October 1, 2010, we may redeem the 5.00% Convertible Senior Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of 5.00% Convertible Senior Notes to be redeemed, plus any accrued and unpaid interest, irrespective of the price of our common stock. Holders may convert their 5.00% Convertible Senior Notes at any time prior to the close of business on the business day immediately preceding their stated maturity, and holders may, upon the occurrence of certain fundamental changes, or on October 1, 2010, October 1, 2015, and October 1, 2020, require us to repurchase all or a portion of their 5.00% Convertible Senior Notes for cash in an amount equal to 100% of the principal amount of such 5.00% Convertible Senior Notes, plus any accrued and unpaid interest. See “Note 19 — Subsequent Events.”

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

As the debt instruments exchanged in the Convertible Notes Exchange have substantially different terms, the Company recognized the exchange of the 5.00% Convertible Senior Notes as extinguishment of debt. As a result, for the nine months ended September 30, 2010, the Company recognized a loss of $4.3 million including write off of loan original fee of $822,000 for the debt extinguishment. The New Convertible Senior Notes are recorded at a fair value of $35,065,000 on the date of exchange. The accretion expense on the Convertible Notes Exchange, which was determined using fair market value of the New Convertible Senior Notes, will be amortized to income over their term. The accretion impact (positive) of $348,430 was recorded for the nine months ended September 30, 2010.

As of September 30, 2010, approximately $32.4 million principal aggregate amount of the 5.00% Convertible Senior Notes was outstanding.

On October 1, 2010, the Company repurchased $32,256,000 principal amount of the 5.00% Convertible Senior Notes. See “Note 19 — Subsequent Events” for further information.

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

Table of Contents

We incurred approximately $1.9 million of costs associated with the issuance of the New Convertible Senior Notes; these costs have been recorded in other assets on the balance sheets and are being amortized to interest expense using the straight-line interest rate method (which approximates the effective interest method) over the term of the New Convertible Senior Notes (i.e., from issuance to the earliest date on which holders may require the Company to repurchase all or a portion of their New Convertible Senior Notes, in this case October 1, 2013).

The New Convertible Senior Notes are senior unsecured obligations of the Company, ranking equal in right of payment with the Company’s 5.00% Convertible Senior Notes and future unsubordinated indebtedness. The New Convertible Senior Notes will mature on October 1, 2025 and pay annual cash interest at 8.00% from February 1, 2010 until January 31, 2011 and at 7.00% per annum thereafter. Interest on the New Convertible Senior Notes will be payable on February 1 and August 1 of each year, beginning on August 1, 2010.

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

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

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

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

Table of Contents

CHANGE IN AMORTIZATION OF ISSUE PREMIUM AND DEBT ISSUANCE COSTS

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

Based on this early redemption, the Company has decided that for a debt instrument that is puttable by the holder prior to the debt’s stated maturity date, it is preferable to amortize the related issuance costs and purchase premium over a period no longer than through the first put option date. The issue premium on the Convertible Notes Exchange and the costs associated with the issuance of its convertible senior notes will now be amortized using the straight-line interest rate method (which approximates the effective interest method) over the term of the first puttable dates of these callable debts. In all prior periods, the issue premium and the debt issuance costs were amortized over the terms of the debt issuance (i.e., October 1, 2025 for both the 5.00% Convertible Senior Notes and the New Convertible Senior Notes). The effect of this change in estimate was to increase the interest expense by $1,260,060, increase the accretion impact (positive) by $202,314 (or increase net loss for $1,057,746) and decrease basic and diluted earnings per share by $0.04 for the three months ended September 30, 2010.

NOTE 6 — ASSET RETIREMENT OBLIGATIONS

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

As of September 30, 2010, we updated our asset retirement obligations and assets based on the last reserve life estimates available to the Company. The effect of this change in estimate was to decrease our asset retirement obligation by $2,582,000 and decrease our asset retirement obligations assets for the same amount.

The following table summarizes the changes in our asset retirement liability during the nine months ended September 30, 2010 and for the year ended December 31, 2009:

	Nine Months Ended September 30,			Year Ended December 31,
	2010			2009
Asset retirement obligation at January 1	$	6,733		$	6,037
Asset retirement accretion expense	189			507
Foreign currency exchange loss (gain)	(331		)	189
Change in reserve life estimate	(2,582		)	—
Property dispositions	—			—
Asset retirement obligation at the end of the period	$	4,009		$	6,733

Table of Contents

NOTE 7 — 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, and currently have operations in the United States and France and had operations in Hungary in 2009.

The following tables provide the geographic operating segment data required by ASC 280, “Segment Reporting”.

Three Months Ended September 30, 2010

	United States			France		Total
Revenues and other income	$	7		$	6,556	$	6,563
Costs and expenses	1,825			4,103		5,928
Operating income (loss)	$	(1,818	)	$	2,453	$	635

Three Months Ended September 30, 2009

	United States			France		Hungary		Total
Revenues and other income	$	63		$	5,141	$	—	$	5,204
Costs and expenses	3,307			3,705		—		7,012
Operating income (loss)	$	(3,244	)	$	1,436	$	—	$	(1,808	)

Nine Months Ended September 30, 2010

	United States			France		Total
Revenues and other income	$	16		$	33,004	$	33,020
Costs and expenses	6,124			14,050		20,174
Operating income (loss)	$	(6,108	)	$	18,954	$	12,846

Nine Months Ended September 30, 2009

	United States			France		Hungary		Total
Revenues and other income	$	338		$	12,879	$	—	$	13,217
Costs and expenses	12,850			11,501		—		24,351
Operating income (loss)	$	(12,512	)	$	1,378	$	—	$	(11,134	)

	Total Assets (1)
	United States		France
	Continuing Operations				Total
September 30, 2010	$	36,945	$	95,333	$	132,278

December 31, 2009	$	6,552	$	90,603	$	97,155

(1) All intercompany accounts and transactions are eliminated in consolidation.

NOTE 8 — INCOME TAXES AND DEFERRED INCOME TAXES

We are subject to income taxes in the United States and France. The current provision for taxes on income consists primarily of income taxes based on the tax laws and rates of the two countries in which operations were conducted during the three month period ended September 30, 2010. Deferred income taxes are determined under the liability method, based on differences between financial reporting and income tax basis of assets and liabilities and are measured using the enacted tax rates and laws. The measurement of deferred tax assets is adjusted by a valuation allowance, if necessary, to reduce the future tax benefits to the amount, based on available evidence it is more likely than not deferred tax assets will be realized.

Table of Contents

At September 30, 2010, we recorded a $6.3 million income tax payable as we expect to owe income tax within the next 12 months. The increase of tax provision associated with French operations is mainly due to the $15 million upfront payment received by TEF from Hess under the Investment Agreement (See “Note 16 — Agreement with Hess”). For the nine months ended September 30, 2010 and 2009 we paid income taxes of approximately $11,000 (with respect to income earned in 2009) and $4 million (with respect to income earned in 2008) respectively, related to French taxable income. The decrease in taxes paid in 2010 as compared to 2009 is due to higher taxable income for French operations in 2008. As of September 30, 2010, our French operations recorded a $5.8 million tax provision, and the U.S. operations recorded a tax benefit of $87,012 which resulted in a consolidated tax payable of $5.7 million.

As of September 30, 2010 and December 31, 2009, we recorded a $14.9 million and $15.4 million, respectively, deferred income taxes related to differences in oil and gas property capitalization and depletion methods.

We have adopted ASC 740 “Income Taxes”, formerly FIN No. 48, “Accounting for Uncertainty in Income Taxes”, on January 1, 2007. There are no tax positions for which a material change in the unrecognized tax benefit is reasonably possible in the next 12 months.

The Company recognizes potential accrued interest and penalties related to unrecognized tax benefits within its global operations in income tax expense. During the nine months ended September 30, 2010, the Company recognized no potential interest and penalties associated with uncertain tax positions. To the extent interest and penalties are not assessed with respect to uncertain tax positions, amounts accrued will be reduced and reflected as a reduction of the overall income tax provision.

In addition to U.S. federal tax returns, we file several state and foreign tax returns, many of which remain open for examination for five years.

NOTE 9 — CAPITAL

For the nine months ended September 30, 2010, the Company issued 266,750 shares of stock to employees and directors, of which 132,733 shares were immediately vested in accordance with the terms of the grants and 5,000 stock options were exercised under the terms of the option agreements. There were no forfeitures of restricted stock and stock options for the nine months ended September 30, 2010.

On February 12, 2010, we completed a registered underwritten public offering of 3,450,000 shares of common stock, including 450,000 shares of common stock acquired by the underwriters from us to cover over-allotment options. The net proceeds to Toreador from the offering were approximately $26.8 million, after deducting underwriting discounts, commissions and estimated offering expenses. We intended to use the net proceeds, together with cash on hand, to satisfy payment obligations arising from the holders’ exercise, if any, of their right on October 1, 2010 to require the Company to repurchase its 5.00% Convertible Senior Notes and for general corporate purposes, which may include working capital, capital expenditures and acquisitions. Pending such use, we invested the net proceeds in mutual and money market funds and/or bank certificates of deposit. As of September 30, 2010, approximately $32.4 million principal aggregate amount of the 5.00% Convertible Senior Notes was outstanding. On October 1, 2010, the Company repurchased $32,256,000 principal amount of the 5.00% Convertible Senior Notes. See “Note 19 — Subsequent Events” for further information.

NOTE 10 — CAPITALIZED INTEREST

We capitalize interest on major projects that require an extended period of time to complete. Capitalized interest for the three months ended September 30, 2010 and 2009 was $0 and $118,000 respectively. Capitalized interest for the nine months ended September 30, 2010 and 2009 was $0 and $355,000, respectively.

Table of Contents

NOTE 11 — COMMITMENTS AND CONTINGENCIES

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

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

On September 30, 2009, we completed the sale of Toreador Turkey, including with it Toreador Turkey’s remaining 10% interest in the SASB license, to Tiway. In connection with this sale, we agreed to indemnify Tiway against and in respect of any and all claims, liabilities, and losses arising from the Overriding Royalty. TRC is treating the said indemnity as extending to claims against Tiway Turkey Ltd (previously Tiway Turkey Ltd) as well. As of September 30, 2010, we had accrued approximately $880,000 (recorded under long-term accrued liabilities) as a contingent liability for these claims, and the expense of legal cost of $106,000. See “Note 12 — Discontinued Operations”.

As of September 30, 2010, we also accrued $220,000 (recorded under accounts payable and accrued liabilities) as a provision for the 1.5% Overriding Royalty the Company will have to pay on the net value to Hunnisett and Barker of all future production, if any, deriving from Madison Oil’s interest in such SASB licenses.

On September 6, 2010, English High Court proceedings were commenced by Hunnisett and Barker, as well as Netherby Investments Limited against Tiway Turkey Limited (previously Toreador Turkey Limited) and TRC. The proceedings were served on TRC on October 20, 2010 but so far as TRC is aware have not yet been served on Tiway Turkey Limited. In the said proceedings, Hunnisett and Barker now argue that an agreement was reached between the parties around November 2008 regarding the Netherby Payment Amount in the sum of $7.2 million. In addition they argue that on a proper construction of the Netherby Agreement, they are entitled to continuing Overriding Royalty including on the 26.75% interest in the SASB licenses that was sold to Petrol Ofisi in March 2009 and/or to a capitalized sum of “not less than” $7.2 million. In addition or in the alternative, Hunnisett and Barker raise a wholly new claim for rectification of the Netherby Agreement on the basis they claim it does not reflect the true agreement of the parties. They seek rectification of the Netherby Agreement so that upon a sale such as the sale of the 26.75% interest in the SASB licenses that was sold to Petrol Ofisi in March 2009, the Netherby Agreement parties are required to first agree on a capitalized sum to be paid to Hunnisett and Barker. Hunnisett and Barker also seek costs and interest. The Company does not believe that any agreement was ever reached entitling Hunnisett and Barker to the payment of the said sum of $7.2 million. The Company also does not agree with Hunnisett and Barker’s proposed construction of the Netherby Agreement. We are currently considering the new claim for rectification with our legal advisers but we intend to vigorously defend ourselves against any claim for payment of an amount in excess of the amount to which we believe that Hunnisett and Barker are entitled.

On June 17, 2009, The Scowcroft Group, Inc. (“Scowcroft”) filed a complaint in the U.S. District Court for the District of Columbia against us. The complaint alleged that we breached a contract (the “Scowcroft Contract”) between Scowcroft and us relating to the sale of our interests in the SASB and that Scowcroft was entitled to a success fee thereunder as a result of the sale of our interests in the SASB to Petrol Ofisi in March 2009.

Table of Contents

The complaint also alleged unjust enrichment/quantum meruit and fraud. Scowcroft sought damages in the amount of $2 million plus interest, costs and expenses. On April 30, 2010, Toreador and Scowcroft executed a settlement agreement (the “Settlement Agreement”), pursuant to which Toreador agreed to pay Scowcroft $495,000 and, subject to receipt of such payment, Scowcroft agreed to take actions to dismiss the suit and the parties agreed to a mutual release with respect to claims relating to the Scowcroft Contract. On April 30, 2010, Toreador made the settlement payment and the parties filed a stipulation of dismissal of the action. As of September 30, 2010, $657,000 has been expensed in discontinued operations consequently, consisting of the settlement amount and associated legal costs.

On January 25, 2010, we received a claim notice from Tiway under the Share Purchase Agreement, dated September 30, 2009, among us, Tiway Oil AS and Tiway relating to the sale of Toreador Turkey Ltd. (the “SPA”) in respect of a third-party claim asserted by Petrol Ofisi against Toreador Turkey Ltd. in the amount of TRY 7.6 million ($5.1 million), for which Tiway alleges we are liable for an estimated TRY 2.1 million ($1.4 million). No formal legal evaluation can be made at this time as to the extent of the Company’s liability, if any. On July 20, 2010, the Court appointed three experts to evaluate the case. A hearing was held on November 2, 2010, at which the Court adjourned pending the issuance of the experts’ report. The next hearing is scheduled for on February 1, 2011.

On October 6, 2010, Toreador received a claim notice from Tiway under the SPA in respect of an arbitration initiated by Türkiye Petrolleri A.O. (“TPAO”) against Tiway relating to alleged damages and losses suffered in connection with the Akçakoca-Çayağzi Pipeline Construction Project in 2005. Tiway asserts in the letter that the total relief sought is $2,993,038. We believe the arbitration initiated by TPAO is without merit.

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

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

On December 11, 2008, TEF filed an application for the extension of the validity of Châteaurenard Concession and the Saint-Firmin-des-Bois Concession for a period of 25 years. Pursuant to French law governing mines and underground storage, the French Minister in charge of energy must decide upon renewal of such concessions within a period of two years from the date the applications were filed, which requires the approval of both the Conseil Général de l’Industrie, de l’Energie et des Technologies and of the Conseil d’Etat (i.e. the French administrative supreme body). The Conseil Général de l’Industrie, de l’Energie et des Technologies approved the renewal of the Châteaurenard Concession and the Saint-Firmin-des-Bois Concession on October 11, 2010. In accordance with French law, the renewal of such concessions is now under review by the Conseil d’Etat. The main criteria for renewal are the technical and financial capacities of the applicant.

NOTE 12 — DISCONTINUED OPERATIONS

In the fourth quarter of 2008 and during the first quarter of 2009, Toreador farmed out or sold all of its working interests in Romania to three different companies and closed its office; thus, we no longer have any operational involvement in Romania. This resulted in a gain of $5.8 million, which was recorded in the first quarter of 2009.

Table of Contents

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

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

As of September 30, 2010, we had accrued approximately $880,000 as a contingent liability for indemnification claims in connection with the sales referred above and legal costs expense of $106,000 (See “Note 11 — Commitments and Contingencies”). In addition, we recorded $81,000 in discontinued operations for payments made to Hunnisett and Barker with regard to the Overriding Royalty.

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

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Revenue and other income
Sales and other operating revenue	$	—		$	1,632		$	—		$	4,545
Operating costs and expenses:
Lease operating expense	—			381			—			886
Exploration expense	—			136			—			868
Dry hole costs	—			1,318			—			1,318
Depreciation, depletion and amortization	—			52			—			157
Accretion on discounted assets and liabilities	—			—			—			—
Impairment of oil and natural gas properties	—			5,425			—			10,725
General and administrative expense	106			1,720			763		(1)	3,424
(Gain) loss on sale of properties and other assets	—			4,171			—			(1,675		)
Total operating costs and expenses	—			13,203			763			15,703
Operating loss	(106		)	(11,571		)	(763		)	(11,158		)
Other income (expense)
Foreign currency exchange gain	—			1,190			—			3,822
Interest and other income	—			18			—			414
Loss on early extinguishment of debt — revolving credit facility	—			—			—			(4,881		)
Other expense	81			—			246			—
Interest expense, net of interest capitalized	—			(155		)	—			(185		)
Loss before income taxes	(187		)	(10,518		)	(1,009		)	(11,988		)
Income tax provision	(104		)	—			(104		)	—
Net loss from discontinued operations	$	(291	)	$	(10,518	)	$	(1,113	)	$	(11,988	)

(1) Residual exit costs.

Table of Contents

NOTE 13 — DERIVATIVES

We periodically utilize derivative instruments such as futures and swaps for purposes of hedging our exposure to fluctuations in the sale price of crude oil. In December 2009, we entered into futures and swap contracts for approximately 15,208 Bbls per month for the months of January 2010 through December 2010. This resulted in a net unrealized derivative fair value gain of $709,000 at September 30, 2010. Presented in the table below is a summary of the contracts entered into for 2010:

Type	Period	Barrels	Floor		Ceiling		Unrealized loss for the three months ended September 30, 2010

Collar	January 1, 2010 - December 31, 2010	182,500	$	68.00	$	81.00	$	105

On November 2, 2010, we entered into futures and swaps contracts for 2011. See “Note 19 — Subsequent Events” for further information.

NOTE 14 — FAIR VALUE MEASUREMENTS

The carrying amounts of financial instruments including cash and cash equivalents, short-term investments, accounts receivable, accounts payable and accrued liabilities approximate fair value at September 30, 2010 and December 31, 2009, due to the short-term nature or maturity of the instruments.

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

On September 30, 2010, the 5.00% Convertible Senior Notes, which had a book value of $35.0 million, were trading at $95.2, which would equal a fair market value of approximately $31 million.

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

On September 30, 2010, the New Convertible Senior Notes, which had a book value of $31.6 million, were trading at $114.71 which would equal a fair market value of approximately $36.3 million.

Table of Contents

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

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

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

The impairment charge in Turkey of $5.3 million which is recorded in discontinued operations for the period ended September 30, 2009, is a result of a decline in the fair market value of the Company’s interest in South Akcakoca Sub-Basin asset. The fair market value declined during the first quarter of 2009 due to a 25.00% reduction in the posted sales price of natural gas produced in Turkey announced on May 1, 2009.

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

Asset Retirement Obligations — The initial measurement of asset retirement obligations at fair value is calculated using cash flows techniques and based on internal estimates of future retirement costs associated with oil and gas properties. Significant Level 3 inputs used in the calculation of asset retirement obligations include plugging costs and reserve lives. A reconciliation of the Company’s asset retirement obligation is presented in “Note 6 — Asset Retirement Obligations”.

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

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

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

Table of Contents

Level 3:

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

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

			Fair Value Measurements Using
Description	Fair Value Measurement		Quoted Prices in Active Markets (Level 1)	Significant Other Observable Inputs (Level 2)	Significant Unobservable Inputs (Level 3)		Total Inpaiment Loss
	(in thousands)
Nine Months Ended September 30, 2010

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

Nine Months Ended September 30, 2009

Impaired oil and natural gas properties	$	16,507	—	—	$	16,507	$	(10,725	)

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

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

As September 30, 2010:
Oil derivative contracts	$	—	$	—	$	177	$	177

Total	$	—	$	—	$	177	$	177

As December 31, 2009:
Oil derivative contracts	$	—	$	—	$	886	$	886
	$	—	$	—	$	886	$	886

Table of Contents

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

	Nine Months Ended			Year ended
	September 30, 2010			December 31, 2009
	Oil Derivative Contracts			Oil Derivative Contracts
Balance at beginning of period	$	886		$	—
Unrealized (gain) loss	(709		)	886

Balance at end of period	$	177		$	886

NOTE 15 — IMPAIRMENT OF ASSETS

We evaluate producing property costs for impairment and reduce such costs to fair value if the sum of expected undiscounted future cash flows is less than net book value pursuant to FASB ASC 360 “Property, Plant and Equipment,” formerly Statement of Financial Accounting Standard No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“Statement 144”). We assess impairment of non-producing leasehold costs and undeveloped mineral and royalty interests periodically on a field-by-field basis. We charge any impairment in value to expense in the period incurred. For the three and nine months ended September 30, 2010, there was no impairment charge for our continuing operations and discontinued operations.

The impairment charge in Turkey of $5.3 million (included in discontinued operations), as of September 30, 2009, was a result of a decline in the fair market value of the Company’s interest in South Akcakoca Sub-Basin asset. The fair market value declined during the first quarter of 2009 due to a 25.00% reduction in the posted sales price of natural gas produced in Turkey announced on May 1, 2009.

In the third quarter of 2009, the Company decided not to proceed with the construction of the Kiha pipeline in Hungary, due to the poor results of the Tompa Deep well and the impending sale of Toreador Hungary, which was completed on September 30, 2009. This resulted in an impairment of $5.4 million (included in discontinued operations) which represented our share of costs capitalized for the pipeline and the previously drilled Kiha 15 well.

NOTE 16— AGREEMENT WITH HESS

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

The Ministère de l’Ecologie, de l’Energie, du Développement Durable et de la Mer (Ministry of Ecology, Energy, Sustainable Development and the Sea) in France granted first-stage approval on June 25, 2010. An application for the grant to Hess of title (together with TEF) on each of the pending exploration permits in the Paris Basin has also been filed with the French Government.

Pursuant to the Investment Agreement, TEF has transferred 50% of its working interest in each Permit to Hess (collectively, the “Transfer Working Interests”) and, on June 10, 2010, Hess paid TEF $15 million plus VAT, i.e., an aggregate amount of $17.9 million (such payment having been recorded as other income for the nine months period ended September 30, 2010 as this revenue is not subject to any further obligation or performance by the Company nor is it dependent upon any approval).

Under the terms of the Investment Agreement, Phase 1 of the Work Program is expected to consist of an evaluation of the acreage underlying the Permits and the drilling of six wells. The parties have agreed to use reasonable endeavors to spud the first well by December 1, 2010, the second well by the March 31, 2011 and the third well by September 30, 2011. If Hess does not spend $50 million in fulfillment of the Work Program within 30 months of receipt of government approval (“Phase 1”), Hess must promptly transfer back to TEF the Transfer Working Interests.

Table of Contents

Under the terms of the Investment Agreement, if Hess spends $50 million in Phase 1, Hess will have the option to proceed to Phase 2 of the Work Program. If Hess elects not to proceed to Phase 2 of the Work Program, Hess must promptly transfer back to TEF a percentage of the Transfer Working Interests determined with reference to the amount of money spent by Hess in fulfillment of the Work Program during Phase 1.

Under the terms of the Investment Agreement, if Hess elects to proceed, Phase 2 of the Work Program is expected to consist of appraisal and development activities, depending on the results of the work in Phase 1. If Hess does not spend $70 million (less money spent by Hess in fulfillment of the Work Program in excess of $50 million in Phase 1) in fulfillment of the Work Program within 36 months (“Phase 2”), Hess must promptly transfer back to TEF a percentage of the Transfer Working Interests determined with reference to the amount of money spent by Hess in fulfillment of the Work Program during Phase 1. Following Phase 2, TEF and Hess will bear the costs of subsequent exploration, appraisal and development activities in accordance with individual participation agreements governing the joint operations on each Permit.

Under the terms of the Investment Agreement, Hess agrees to pay TEF: (x) a success fee based on proved developed oil reserves (as defined by Rule 4-10(a) of Regulation S-X), up to a maximum of $80 million and (y) a success fee if oil production exceeds an agreed threshold, up to a maximum of $50 million, each of which is subject to reduction under certain circumstances.

Under the terms of the Investment Agreement, TEF and Hess have designated an area of mutual interest within the Paris Basin (the “AMI”). If either party acquires or applies for a working interest in an exploration permit or exploitation concession within the AMI, such party would be required to offer to the other party 50% of such interest on the same terms and conditions.

Under the terms of the Investment Agreement, TEF is entitled to invoice Hess for all personal general and administrative costs associated with its activities as operator of the Permits. For the three and nine months ending September 30, 2010, $560,000 was invoiced to Hess and recorded as “Other income.”

NOTE 17 — PENSION, POST-RETIREMENT, AND POST-EMPLOYMENT OBLIGATIONS

Provisions for employee retirement obligations amounted to $273,000 and $0 for the nine months ended September 30, 2010 and September 30, 2009, respectively. Pension benefits, which only consist in retirement indemnities, have been defined only for the Company’s French subsidiaries.

NOTE 18 — STOCK COMPENSATION PLANS

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

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

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

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

Table of Contents

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

A summary of stock option transactions is as follows:

	2010				2009
	SHARES		WEIGHTED AVERAGE EXERCISE PRICE		SHARES		WEIGHTED AVERAGE EXERCISE PRICE
Outstanding at January 1	67,370		$	7.78	248,370		$	6.77
Granted	—		—		—		—
Exercised	(5,000	)	$	3.10	(31,000	)	$	3.67
Forfeited	—				(150,000	)	$	6.96
Outstanding at the end of the period	62,370		$	8.15	67,370		$	7.78
Exercisable at the end of the period	62,370		$	8.15	67,370		$	7.78

The intrinsic value of the options exercised at September 30, 2010 was zero. For the nine months ended September 30, 2010 and for the year ended December 31, 2009 we received cash from stock option exercises of $15,500 and $113,875, respectively. As of September 30, 2010, all outstanding options were 100% vested. As of September 30, 2010 and December 31, 2009, the total compensation cost related to non-vested stock options not yet recognized was zero.

The following table summarizes information about the fixed price stock options outstanding at September 30, 2010:

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

3.12	620	$	1		620	$	1		0.22
3.12	3,800	9			3,800	9			0.22
5.50	200	—			200	—			3.82
5.50	40,250	—			40,250	—			3.82
13.75	7,500	(62		)	7,500	(62		)	4.38
16.90	10,000	(114		)	10,000	(114		)	4.89
	62,370	$	(165	)	62,370	$	(165	)	2.89

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

At September 30, 2010 the Board of Directors has authorized a total of 266,750 shares of restricted stock to be granted to employees and non-employee directors. The compensation cost is measured by the difference between the quoted market price of the stock at the date of grant and the price, if any, to be paid by an employee or director and is recognized as an expense over the period the recipient performs related services. The restricted stock grants vest immediately or over up to a three-year period (depending on the grant), and the weighted average price of the stock on the date of the grants was $9.32 for the nine months ended September 30, 2010.

Table of Contents

Stock compensation expense of $0.4 million is included in the Statement of Operations for the three months ended September 30, 2010 and stock compensation expense of $ 2.6 million is included in the Statement of Operations for the nine months ended September 30, 2010, which represents the cost recognized from the date of the grants through September 30, 2010. As of September 30, 2010, the total compensation cost related to non-vested restricted stock grants not yet recognized is approximately $3.2 million. This amount will be recognized as compensation expense over the next 36 months.

On September 30, 2010, there were 1,339,421 remaining shares available for grant under the Plan.

The following table summarizes the changes in outstanding restricted stock grants along with their related grant-date fair values for the year ended September 30, 2010:

	Shares		Weighted Average Grant-Date Fair Value
Non-vested at December 31, 2009	378,130		$	10.25
Shares granted	266,750		$	9.32
Shares vested	(298,708	)	$	8.93
Shares forfeited	—		—
Non-vested at September 30, 2010	346,172		$	10.55

NOTE 19— SUBSEQUENT EVENTS

The Company evaluated its September 30, 2010 financial statements for subsequent events through the date the financial statements were issued. Except as indicated below, no subsequent events require disclosure.

In accordance with the terms, procedures and conditions outlined in the indenture and the 5.00% Convertible Senior Notes, each holder of the 5.00% Convertible Senior Notes had an option to require the Company to purchase all or a portion of its 5.00% Convertible Senior Notes on October 1, 2010. Pursuant to the exercise of this option, the Company repurchased $32,256,000 principal amount of the 5.00% Convertible Senior Notes on October 1, 2010. Interest on the repurchased 5.00% Convertible Senior Notes accrued up to, but not including, October 1, 2010 was been paid to record holders of 5.00% Convertible Senior Notes as of September 15, 2010. The repurchase on October 1, 2010 resulted in a loss of $1.1 million after writing off all deferred debt issuance costs pertaining to the 5.00% Convertible Senior Notes. The Company has elected to redeem the $129,000 principal aggregate amount of the 5.00% Convertible Senior Notes outstanding in accordance with the terms of the indenture, has provided notice to the holders of such redemption and expects to effect this redemption on November 24, 2010.

On October 6, 2010, Toreador received a claim notice from Tiway under the SPA in respect of an arbitration initiated by TPAO against Tiway relating to alleged damages and losses suffered in connection with the Akcakoca-cayagzi pipeline construction project in 2005. See “Note 11 — Commitments and Contingencies” for further information.

On October 20, 2010, English High Court proceedings, commenced by Hunnisett and Barker as well as Netherby Investments Limited against Tiway Turkey Limited and the Company, were served on the Company. See “Note 11 — Commitments and Contingencies” for further information.

We periodically utilize derivative instruments such as futures and swaps for purposes of hedging our exposure to fluctuations in the sale price of crude oil. On November 2, 2010, the Company entered into collars contracts with Vitol Trading SA for 500 Bbls per day (or approximately 15,208 Bbls per month) from January 1, 2011 to December 31, 2011 with a floor price at $78/Bbl and a ceiling price at $91/Bbl.

Table of Contents

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 Annual Report on Form 10-K for the year ended December 31, 2009, which was filed with the SEC on March 16, 2010. Certain prior-year amounts have been reclassified and adjusted to present the operations of Turkey, Hungary and Romania as discontinued operations.

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 within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) 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,” “will,” “would,” “could,” “should,” and similar expressions are intended to be among the statements that identify forward-looking statements. The factors that may affect our expectations regarding our operations include, among others, the following:

· our ability to raise necessary capital in the future;

· our ability to maintain or renew our existing exploration permits or exploitation concessions or obtain new ones;

· the effect of our indebtedness on our financial health and business strategy;

· our ability to execute our business strategy and be profitable;

· our ability to replace oil reserves;

· a change in the SEC position on our calculation of proved reserves;

· the loss of the current purchaser of our oil production;

· results of our hedging activities;

· the loss of senior management or key employees;

· political, legal and economic risks associated with having international operations;

· disruptions in production and exploration activities in the Paris Basin;

· currency fluctuations;

· failure to maintain adequate internal controls;

· indemnities granted by us in connection with dispositions of our assets;

· unfavorable results of legal proceedings;

· assessing and integrating acquisition prospects;

· declines in prices for crude oil;

· our ability to compete in a highly competitive oil and gas industry;

· our ability to obtain equipment and personnel;

· extensive regulation, including environmental regulation, to which we are subject;

· terrorist activities;

· our success in development, exploitation and exploration activities;

· reserves estimates turning out to be inaccurate; and

· differences between the present value and market value of our reserves.

In addition to these factors, important factors that could cause actual results to differ materially from our expectations (“Cautionary Statements”) are disclosed under “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2009, filed with the SEC on March 16, 2010, which are incorporated by reference herein.

Table of Contents

All written and oral forward-looking statements attributable to us are expressly qualified in their entirety by the Cautionary Statements. We undertake no obligation to update or revise publicly any forward-looking statements, whether as a result of new information, future events, or otherwise.

EXECUTIVE OVERVIEW

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

We currently operate solely in the Paris Basin, which covers approximately 170,000 km2 of northeastern France, centered 50 to 100 km east and south of Paris. At September 30, 2010, we held interests in approximately 683,000 gross exploration acres. According to Gaffney, Cline & Associates Ltd, an independent petroleum and geological engineering firm, or Gaffney Cline, as of December 31, 2009, our proved reserves were 5.8 MBbls, our proved plus probable reserves were 9.1 MBbls and our proved plus probable plus possible reserves were 14.3 MBbls. Our production for 2009 averaged approximately 900 bbl/d from two conventional oilfield areas in the Paris Basin - the Neocomian Complex and Charmottes fields. As of September 30, 2010, production from these oil fields represented substantially all of our sales and operating revenue. We intend to maintain production from these mature assets using when necessary suitable enhanced oil recovery techniques. In addition to this production base, we have identified several additional conventional exploration targets.

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

Operations Update

Hess Partnership

On May 10, 2010, Toreador Energy France S.C.S. (“TEF”), a company organized under the laws of France and an indirect subsidiary of the Company, entered into an Investment Agreement (the “Investment Agreement”) with Hess Oil France S.A.S. (“Hess”), a company organized under the laws of France and a wholly owned subsidiary of Hess Corporation, a Delaware corporation, relating to exploitation of our shale oil acreage in the Paris Basin. Pursuant to the Investment Agreement (x) Hess may become a 50% holder of TEF’s working interests in its awarded and pending exploration permits in the Paris Basin, France (the “Permits”) and (y) (1) Hess must make a $15 million upfront payment to TEF, (2) Hess will have the right to invest up to $120 million in fulfillment of a two-phase work program (the “Work Program”) and (3) TEF would be entitled to receive up to a maximum of $130 million of success fees based on reserves and upon the achievement of an oil production threshold. In accordance with the Investment Agreement, Hess made the $15 million upfront payment (plus applicable VAT of $2.9 million) to TEF on June 10, 2010.

Pursuant to the Investment Agreement, subject to such government approval, TEF has transferred 50% of its working interest in each Permit to Hess (collectively, the “Transfer Working Interests”). The Ministère de l’Ecologie, de l’Energie, du Développement Durable et de la Mer (Ministry of Ecology, Energy, Sustainable Development and the Sea) in France granted first-stage approval on June 25, 2010. An application for the grant to Hess of title (together with TEF) on the pending exploration permits in the Paris Basin has also been filed with the French Government.

On October 10, 2010, TEF and Hess obtained definitive approval and necessary environmental permits from the relevant French local and regional authorities (DRIE, DREAL and Préfecture) for the initial four well locations, for which we applied in the second quarter of 2010. The initial phase of the drilling program, expected to comprise six or more unconventional exploration wells, is forecast to begin in January 2011. The first well will be a vertical well located on the Chateau Thierry exploration permit located about 70 km east of Paris. TEF will remain operator of record in the near-term while work is carried out under Hess’s supervision. On October 22, 2010, TEF and Hess agreed on a firm budget of $56 million for 2011, which will be funded out of Hess’s commitments under the terms of the May 10, 2010 Investment Agreement. There is a possible additional $20 million of discretionary spending for 2011 that will be decided at a later date between Hess and TEF.

Table of Contents

La Garenne Well

The LGA-1 exploration well (La Garenne) was drilled and tested on the Rigny le Ferron exploration permit in late 2009 and early 2010. The well confirmed a five-meter reservoir within a 50-meter oil column in the target Dogger formation, but low permeability in the vicinity of the wellbore. A decision regarding whether or not to drill a horizontal appraisal well and to develop the reservoir will be made in the first quarter of 2011.

Concessions Renewal

On December 11, 2008, TEF filed an application for the extension of the validity of Châteaurenard Concession and the Saint-Firmin-des-Bois Concession for a period of 25 years. Pursuant to French law governing mines and underground storage, the French Minister in charge of energy must decide upon renewal of such concessions within a period of two years from the date the applications were filed, which requires the approval of both the Conseil Général de l’Industrie, de l’Energie et des Technologies and of the Conseil d’Etat (i.e. the French administrative supreme body). The Conseil Général de l’Industrie, de l’Energie et des Technologies approved the renewal of the Châteaurenard Concession and the Saint-Firmin-des-Bois Concession on October 11, 2010. In accordance with French law, the renewal of such concessions is now under review by the Conseil d’Etat. The main criteria for renewal are the technical and financial capacities of the applicant.

Strategy

The primary components of our strategy are:

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

· Capture, develop and accelerate conventional prospects. We have identified a number of conventional oil prospects, which we intend to evaluate for potential development, beginning with La Garenne.

· Target the prospective unconventional oil resource play. We are currently working with Hess on our proof of concept program and potential development of our Paris Basin shale oil acreage position.

· Seize the opportunities for external growth. We continue to evaluate and, where appropriate, intend to pursue acquisition opportunities on terms we consider favorable. In particular, we consider acquisitions of businesses or interests that will complement and allow us to expand our activities. However, currently, we have no binding commitments related to any acquisitions.

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

· Seek and maintain optimal capital structure. We intend to maintain a conservative capital structure over time.

Table of Contents

Financial Summary

For the nine months ended September 30, 2010:

· Revenues from continuing operations were $33.0 million.

· Operating costs from continuing operations were $20.2 million.

· Loss from discontinued operations, net of income taxes, was $1.1 million.

· Net loss available to common shares was $3.9 million.

· Production was 241 MBOE.

At September 30, 2010, we had:

· Cash and cash equivalents of $53.6 million.

· A current ratio (current assets/current liabilities) of 1.32 to 1.

· A debt to equity ratio of 3.24 to 1.

LIQUIDITY AND CAPITAL RESOURCES

This section should be read in conjunction with “Note 5 — Long Term Debt” and “Note 19 — Subsequent Events” in the Notes to the Condensed Consolidated Financial Statements included in this filing.

Liquidity

The Company’s liquidity depends on cash flow from operations and existing cash resources. As of September 30, 2010, we had cash and cash equivalents of $53.6 million, a current ratio of approximately 1.32 to 1 and a debt to equity ratio of 3.24 to 1. For the three months ended September 30, 2010, we had an operating income of $0.6 million. We had sales and other operating revenue of $6.0 million. We had no other capital expenditures apart from technical studies of La Garenne for $45,000. The Company does not currently have a credit facility and intends to rely on its cash balance to meet its immediate cash requirements.

Our cash flow from operations is highly dependent upon the prices received from our oil production, which are dependent on numerous factors beyond our control. Accordingly, significant changes to oil prices are likely to have a material impact on our financial condition, results of operation, cash flows and revenue. Oil prices have been very volatile over the first nine months of 2010, and we expect will continue to be volatile for the remainder of the fiscal year 2010. In order to reduce our exposure to crude oil price fluctuations, we have entered into a collar contract for approximately 15,208 Bbls per month for the months of January 2010 through December 2010 for which the floor price is $68.00 per bbl, and the ceiling price is $81.00 per bbl. On November 2, 2010, we entered into futures and swaps contracts for 2011. See “Note 19 — Subsequent Events” for further information.

On February 1, 2010, we consummated an exchange transaction (the “Convertible Notes Exchange”). In the Convertible Notes Exchange, in exchange for (a) $22,231,000 principal amount of our outstanding 5.00% Convertible Senior Notes (the “Old Notes”) and (b) $9.4 million cash, we issued $31,631,000 aggregate principal amount of our 8.00%/7.00% Convertible Senior Notes (the “New Convertible Senior Notes”) and paid accrued and unpaid interest on the Old Notes. See “Note 5 — 5.00% Convertible Senior Notes Due October 1, 2025”, and “Note 5 — 8.00%/7.00% Senior Convertible Notes Due October 1, 2025” for further details.

Table of Contents

We currently have no mandatory capital expenditures in 2010; however, we are currently evaluating the creation of a development plan for the La Garenne field. In addition, under French law, each of our exploration permits and exploitation concessions require that we commit to expenditures of a certain amount over the period of the applicable permit or concession. Though we consider these amounts discretionary, such expenditures would be required to renew such permits.

We believe we will have sufficient cash flow from operations and cash on hand to meet all of our 2010 obligations.

5.00% CONVERTIBLE SENIOR NOTES DUE OCTOBER 1, 2025

On September 27, 2005, we issued $75 million of Convertible Senior Notes due October 1, 2025 (the “5.00% Convertible Senior Notes”) to qualified institutional buyers pursuant to Rule 144A of the Securities Act of 1933, as amended (the “Securities Act”). The Company also granted the initial purchasers the option to purchase an additional $11.25 million aggregate principal amount of 5.00% Convertible Senior Notes to cover over-allotments. The over-allotment option was exercised on September 30, 2005. The total principal amount of 5.00% Convertible Senior Notes issued was $86.25 million and total net proceeds were approximately $82.2 million. We incurred approximately $4.1 million of costs associated with the issuance of the 5.00% Convertible Senior Notes; these costs have been recorded in other assets on the balance sheet and are being amortized to interest expense using the straight-line interest rate method (which approximates the effective interest method) over the term of the 5.00% Convertible Senior Notes (i.e., from issuance to the earliest date on which holders may require the Company to repurchase all or a portion of their 5.00% Convertible Notes, in this case October 1, 2010).

The net proceeds were used for general corporate purposes, including funding a portion of the Company’s 2005 and 2006 exploration and development activities.

Table of Contents

As of September 30, 2010, approximately $32.4 million principal aggregate amount of the 5.00% Convertible Senior Notes was outstanding.

On October 1, 2010, holders of $32,256,000 principal amount of the 5.00% Convertible Senior Notes exercised their right to require the Company to repurchase their 5.00% Convertible Senior Notes in accordance with the terms of the indenture. Following such repurchase by the Company on October 1, 2010, $129,000 principal aggregate amount of the 5.00% Convertible Senior Notes remained outstanding. The Company has elected to redeem the $129,000 principal aggregate amount of the 5.00% Convertible Senior Notes outstanding in accordance with the terms of the indenture, has provided notice to the holders of such redemption and expects to effect this redemption on November 24, 2010. For further information, see “Note 19 — Subsequent Events.”

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

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

Table of Contents

CHANGE IN AMORTIZATION OF ISSUE PREMIUM AND DEBT ISSUANCE COSTS

Dividends

Dividends on our common stock may be declared and paid out of funds legally available when and as determined by our Board of Directors. Our policy is to hold and invest corporate funds on a conservative basis, and, thus, we do not anticipate paying cash dividends on our common stock in the foreseeable future.

Table of Contents

Contractual Obligations

The following table sets forth our contractual obligations in thousands at September 30, 2010 for the periods shown:

	Total		Less Than One Year		One to Three Years		Four to Five Years		More Than Five Years
Long-term debt	$	67,101	$	32,385	$	34,716	$	—	$	—
Asset retirement obligation	4,009		—		—		155		3,854
Lease commitments	471		112		359		—		—
Total contractual obligations	$	71,581	$	32,497	$	35,075	$	155	$	3,854

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

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 1 — Significant Accounting Policies” to our consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2009. 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.

Table of Contents

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

Reserves Estimate

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

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

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

We emphasize that the volume of reserves are estimates that, by their nature are subject to revision. The estimates are made using geological and reservoir data, as well as production performance data. These estimates are reviewed annually and revised, either upward or downward, as warranted by additional performance data. These reserve revisions result primarily from improved or a decline in performance from a variety of sources such as an addition to or a reduction in recoveries below or above previously established lowest known hydrocarbon levels, improved or a decline in drainage from natural drive mechanisms, and the realization of improved or declined drainage areas. If the estimates of proved reserves were to decline, the rate at which we record depletion expense would increase.

For the year ended December 31, 2009, we had an upward reserve revision of 18.11% in total proved reserves. This increase can be correlated to a better long-term performance of our main producing asset, the Neocomian Complex, and a higher oil price. The reserves at December 31, 2009 were priced at $56.99 per Bbl, as compared to $34.29 at December 31, 2008.

Table of Contents

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 reserves estimate 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.

On May 1, 2009, the Prime Minister of Turkey, announced a 25.00% reduction in the posted price of natural gas in Turkey which caused us to reevaluate the fair value of our SASB and for management to estimate that the fair value of the asset has been impaired by approximately $5.3 million at September 30, 2009; accordingly, recorded an impairment to reflect this change in fair value.

We recorded no impairment in the nine months ended September 30, 2010.

Future Development and Abandonment Costs

Future development costs include costs to be incurred to obtain access to proved reserves, including drilling costs and the installation of production equipment. Future abandonment costs include costs to dismantle and relocate or dispose of our production equipment, gathering systems, wells and related structures and restoration costs of land. We develop estimates of these costs for each of our properties based upon the type of production structure, depth of water, reservoir characteristics, depth of the reservoir, market demand for equipment, currently available procedures and consultations with construction and engineering consultants. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including changing technology, the ultimate settlement amount, inflation factors, credit adjusted discount rates, timing of settlement and changes in the political, legal, environmental and regulatory environment. We review our assumptions and estimates of future abandonment costs on an annual basis. The accounting for future abandonment costs changed on January 1, 2003, with the adoption of FASB ASC 410 “Asset Retirement and Environmental Obligations”. ASC 410 requires that the fair value of a liability for an asset retirement obligation be recorded in the period in which it is incurred and the corresponding cost be capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. In 2005, two separate incidents occurred offshore Turkey in the Black Sea, which resulted in the sinking of the Fallen Structures and the loss of three natural gas wells. We have not been requested, or ordered by any governmental or regulatory body, to remove the Fallen Structures. Therefore, we believe it is unlikely that we will receive such a request or order, and no liability has been recorded.

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

Table of Contents

Income Taxes

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

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

Derivatives

We periodically utilize derivatives instruments such as futures and swaps for purposes of hedging our exposure to fluctuations in the price of crude oil sales. In accordance with FASB ASC 815, “Derivatives and Hedging,” we have elected not to designate the derivative financial instruments to which we are a party as hedges, and accordingly, we record such contracts at fair value as an asset or a liability and recognize changes in such fair value in current earnings as they occur. We determine the fair value of futures and swap contracts based on the difference between their fixed contract price and the underlying market price at the determination date. The realized and unrealized gains and losses on derivatives are recorded as a derivative fair value gain or loss in the income statement.

Foreign Currency Translation

The functional currency for France is the Euro. Translation gains and losses resulting from transactions in Euros are included in other comprehensive income for the current period. We periodically review the operations of our entities to ensure the functional currency of each entity is the currency of the primary economic environment in which we operate.

RESULTS OF OPERATIONS

COMPARISON OF THE THREE MONTHS ENDED SEPTEMBER 30, 2010 AND 2009

The discussion below, with the exception of the discussion under the heading “Discontinued Operations,” relates to our corporate activities in the United States and France and oil exploration and production operations in France. Certain prior-year amounts have been reclassified and adjusted to present the operations of Turkey, Hungary and Romania as discontinued operations and are discussed under the heading “Discontinued Operations.”

	For the Three Months Ended
	September 30,
	2010		2009
Production:
Oil (MBbls):
France	81		83

	For the Three Months Ended
	September 30,
	2010		2009
Average Price:
Oil ($/Bbl):
France	$	77.67	$	62.19

Table of Contents

Revenue and other income

Sales and other operating revenue

Sales and other operating revenue for the three months ended September 30, 2010 was $6.0 million, as compared to sales and other operating revenue of $5.2 million for the three months ended September 30, 2009, an increase primarily due to the increase in global oil prices over the period, which led to an increase in the prices at which we sell our oil from an average of $62.19 per barrel in the three months ended September 30, 2009 to an average of $77.67 per barrel in the three months ended September 30, 2010. Production remained relatively stable, decreasing from 83 MBbls in the three months ended September 30, 2009 to 81 MBbls in the three months ended September 30, 2010.

The above table compares both volumes and prices received for oil for the three months ended September 30, 2010 and 2009. Oil prices have been very volatile over the third quarter of 2010, and we expect will continue to be extremely volatile for the remainder of the fiscal year 2010. The results of our operations are highly dependent upon the prices received from our oil production, which are dependent on numerous factors beyond our control. Accordingly, significant changes to oil prices are likely to have a material impact on our financial condition, results of operation, cash flows and revenue.

Other income

Other income includes all personal general and administrative costs associated with TEF’s activities as operator of the exploration permits in the Paris Basin, which TEF is entitled to invoice to Hess under the Investment Agreement. As of September 30, 2010, $560,000 was invoiced to Hess and recorded as “Other income.”

Operating costs and expenses

Lease operating expense

Lease operating expense was $3.0 million, or $36.76 per BOE produced, for the three months ended September 30, 2010, as compared to $1.5 million, or $18.07 per BOE produced, for the three months ended September 30, 2009.

This increase is mainly due to the reclassification of certain costs associated with particular properties as lease operating expenses including (i) $280,000 relating to certain taxes associated with oil production and (ii) approximately $1.1 million relating to costs associated with production sites and additional Paris headquarter expenses (which in the three months ending September 30, 2009 were classified as general and administrative expenses, but following the formation of the strategic partnership with Hess are now mainly incurred in connection with our existing oil production and conventional reservoirs development and therefore have been reclassified as lease operating expenses). Lease operating expense for the three months ended September 30, 2010 also included expense due to crude oil inventory decrease for an amount of $134,000.

Exploration expense

Exploration expense for the three months ended September 30, 2010 was $201,000, as compared to $22,000 for the three months ended September 30, 2009. This increase is due primarily to expenses associated with geological and technical studies the Company conducted and commissioned in connection with the exploration of the Paris Basin and not invoiced to Hess.

Depreciation, depletion and amortization

Depreciation, depletion and amortization for the three months ended September 30, 2010 was $1.1 million or $14.00 per BOE produced, as compared to $1.3 million or $16.87 per BOE produced for the three months ended September 30, 2009. This decrease is due to a longer production life estimate for our existing wells according to a Gaffney, Cline & Associates Ltd. report of our reserves at December 31, 2009.

Table of Contents

Accretion on discounted assets and liabilities

Accretion expense for the three months ended September 30, 2010 was $246,000 (positive) as compared to $127,000 for the three months ended September 30, 2009. The accretion expense is composed of $11,000 as asset retirement obligation expense and $257,000 of accretion impact (positive) related to the fair value of the New Convertible Senior Notes.

General and administrative before stock compensation expense

General and administrative expense, excluding stock compensation expense, for the three months ended September 30, 2010 totaled $1.4 million, as compared to $3.5 million for the comparable period in 2009. This decrease is due to the effort started in 2009 to reduce general and administrative expense as well as to a reclassification of certain oil production related expenses from general and administrative expenses to lease operating expenses.

Stock compensation expense

Stock compensation expense was $0.4 million for the three months ended September 30, 2010 compared with $0.6 million for the three months ended September 30, 2009.

Impairment of oil and gas properties

There were no impairment charges for the three months ended September 30, 2010 and September 30, 2009.

Loss on oil and gas derivative contracts

We recorded an unrealized loss on oil and gas derivative contracts for the three months ended September 30, 2010 of $105,000 (as compared to an unrealized income of $7,000 in the three months ended September 30, 2009) representing the unrealized loss on the commodity derivative contracts with Vitol Trading. This increase in loss is due to an increase in oil prices over the third quarter of 2010. Presented in the table below is a summary of the contract entered into:

Type	Period	Barrels	Floor		Ceiling		Unrealized loss for the three months ended September 30, 2010

Collar	January 1, 2010 - December 31, 2010	182,500	$	68.00	$	81.00	$	105

Foreign currency exchange gain (loss)

We recorded a loss on foreign currency exchange of $1.2 million for the three months ended September 30, 2010 compared with a loss of $0.0 million for the three months ended September 30, 2009. This increase is mainly due to the fact that Toreador Energy France booked a loss on foreign currency exchange in its statutory accounts in Euro over the three months ended September 30, 2010 due to the receipt on June 10, 2010 of the $15 million upfront payment from Hess under the Investment Agreement combined with the weakening of the U.S. dollar compared to the Euro over the same period (this loss having been recorded in the financial statements of the Company for the third quarter of 2010 in accordance with FAS 52 “Foreign Currency Translation”).

Table of Contents

Interest expense, net of capitalized interest

Interest expense, net of capitalized interest was $2.7 million for the three months ended September 30, 2010 as compared to $0.4 million for the three months ended September 30, 2009. The increase is mainly due to the additional interest payments relating to the New Convertible Senior Notes issued in February 2010, which was offset by decreased interest payments relating to the 5.00% Convertible Senior Notes, of which $22.2 million of the aggregate principal amount outstanding were exchanged for a portion of the New Convertible Senior Notes in the Convertible Notes Exchange. Interest expense for the New Convertible Senior Notes was $633,000 for the three months ended September 30, 2010 as compared to zero for the three months ended September 30, 2009. Interest expense for the 5.00% Convertible Senior Notes was $404,000 for the three months ended September 30, 2010 as compared to $795,000 for the three months ended September 30, 2009. Amortization of $1,310,058 was recorded for the three months ended September 30, 2010 compared to $38,000 for the three months ended September 30, 2009, due to the change in estimate of the lives of the issue premium and debt issuance costs associated to 5.00% Convertible Senior Notes and to the New Convertible Senior Notes (See Note 5 — “Change in Depreciable Lives of Issue Premium and Debt Issuance Costs”).

Income tax (benefit) provision

An income tax benefit of $0.7 million was recorded in the three months ended September 30, 2010, compared to a tax benefit of $0.2 million recognized for the three months ended September 30, 2009. This benefit was due to the excess of provision for income tax payable in France recorded in the second quarter of 2010.

Discontinued operations

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

Table of Contents

	Three Months Ended
	September 30,
	2010			2009
Revenue and other income
Sales and other operating revenue	$	—		$	1,632
Operating costs and expenses:
Lease operating expense	—			381
Exploration expense	—			136
Dry hole costs	—			1,318
Depreciation, depletion and amortization	—			52
Accretion on discounted assets and liabilities	—			—
Impairment of oil and natural gas properties	—			5,425
General and administrative expense	106			1,720
(Gain) loss on sale of properties and other assets	—			4,171
Total operating costs and expenses	—			13,203
Operating loss	(106		)	(11,571		)
Other income (expense)
Foreign currency exchange gain	—			1,190
Interest and other income	—			18
Loss on early extinguishment of debt — revolving credit facility	—			—
Other expense	81			—
Interest expense, net of interest capitalized	—			(155		)
Loss before income taxes	(187		)	(10,518		)
Income tax provision	(104		)	—
Net loss from discontinued operations	$	(291	)	$	(10,518	)

We had no sales and other operating revenue from discontinued operations for the three months ended September 30, 2010 due to the sale of all our discontinued operations in 2009. We recorded in discontinued operations for the three months ended September 30, 2010 the following expenses: $106,000 of general administrative expense due to legal costs associated to the Netherby dispute, $81,000 for payments made to Hunnisett and Barker in connection with the Overriding Royalty and $104,000 of additional tax related to Toreador Hungary Limited activities in 2009. We thus recorded a loss of $291,000 fom discontinued operations in the three months ending September 30, 2010.

The following tables present production and average unit prices for Turkey:

	For the Three Months Ended
	September 30,
	2010	2009
Production:
Oil (MBbls):
Turkey	—	14
Gas (MMcf):
Turkey	—	105
MBOE:
Turkey	—	32

Table of Contents

	For the Three Months Ended
	September 30,
	2010	2009
Average Price:
Oil ($/Bbl):
Turkey	—	$	58.65
Gas ($/Mcf):
Turkey	—	$	7.62
$/BOE:
Turkey	—	$	51.52

Other comprehensive income

The most significant element of comprehensive income, other than net income, is foreign currency translation. For the three months ended September 30, 2010, we had accumulated an unrealized income of $7.3 million as compared to an unrealized loss of $2.0 million for the comparable period in 2009. This change is primarily due to the weakening of the U.S. dollar compared to the Euro for the three months ended September 30, 2010 compared to the three months ended September 30, 2009.

The functional currency of our operations in France is the Euro. The functional currency in Turkey and Hungary was the U.S. dollar. The exchange rates at September 30, 2010 and September 30, 2009 were:

	September 30,
	2010		2009
Euro	$	1.3648	$	1.4643
New Turkish Lira	—		$	0.0674
Hungarian Forint	—		$	0.0054

COMPARISON OF THE NINE MONTHS ENDED SEPTEMBER 30, 2010 AND 2009

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

	For the Nine Months Ended
	September 30,
	2010	2009
Production:
Oil (MBbls):
France	241	248

	For the Nine Months Ended
	September 30,
	2010		2009
Average Price:
Oil ($/Bbl):
France	$	74.81	$	51.93

Table of Contents

Revenue

Sales and other operating revenue

Sales and other operating revenue for the nine months ended September 30, 2010 were $17.5 million, as compared to $13.1 million for the nine months ended September 30, 2009. This increase is primarily due to the global increase in oil prices, which led to an increase in the prices at which we sell our oil from an average of $51.93 per barrel in the nine months ended September 30, 2009 to an average of $74.81 per barrel in the nine months ended September 30, 2010.

The above table compares both volumes and prices received for oil for the nine months ended September 30, 2010 and 2009. Oil prices have been very volatile over the nine months ended September 30, 2010, and we expect will continue to be extremely volatile for the remainder of the fiscal year 2010. The results of our operations are highly dependent upon the prices received from our oil production, which are dependent on numerous factors beyond our control. Accordingly, significant changes to oil prices are likely to have a material impact on our financial condition, results of operation, cash flows and revenue.

Other income

Other income for the nine months ended September 30, 2010 was $15.6 million, which represented (i) the $15 million upfront payment received from Hess on June 10, 2010 under the Investment Agreement and (ii) $560,000 invoiced to Hess under the terms of the Investment Agreement for all personal general and administrative costs associated with its activities as operator of the exploration permits in the Paris Basin, compared to $121,000 recorded for the same period of 2009 related to the sale of a royalty interest in producing properties located in Canada. These properties had a zero cost basis and were acquired in connection with the acquisition of Madison Oil in 2003.

Costs and expenses

Lease operating expense

Lease operating expense was $7.3 million, or $30.42 per BOE produced, for the nine months ended September 30, 2010, as compared to $5.0 million, or $20.16 per BOE produced for the nine months ended September 30, 2009.

This increase is mainly due to the reclassification of certain costs associated with particular properties as lease operating expenses including (i) $848,000 relating to taxes associated with oil production and (ii) approximately $1.6 million in the aggregate relating to costs associated with production sites and additional Paris headquarter expenses (which in the nine months ending September 30, 2009 were classified as general and administrative expenses, but following formation of the strategic partnership with Hess are mainly incurred in connection with our existing oil production and conventional reservoirs development and therefore reclassified as lease operating expenses). In addition, lease operating expense for the nine months ended September 30, 2010 also included expense due to crude oil inventory decrease for an amount of $336,000.

Exploration expense

Exploration expense for the nine months ended September 30, 2010 was $1.3 million, as compared to $130,000 for the nine months ended September 30, 2009. This increase is due primarily to expenses associated with geological and technical studies the Company conducted and commissioned in connection with the shale oil development project.

Table of Contents

Depreciation, depletion and amortization

Depreciation, depletion and amortization for the nine months ended September 30, 2010 was $2.8 million compared to $4.2 million for the nine months ended September 30, 2009. This decrease is due to a longer production life estimate for our existing wells according to a Gaffney, Cline & Associates Ltd. report of our reserves at December 31, 2009.

Accretion expense

Accretion expense for the nine months ended September 30, 2010 was $159,000 (positive) as compared to $365,000 for the nine months ended September 30, 2009. The accretion expense is composed of $189,000 as asset retirement obligation expense and $348,000 of accretion impact (positive) related to the fair value of the 8.00%/7.00% Convertible Senior Notes.

Impairment of oil and gas properties

We incurred no impairment charge for the nine months ended September 30, 2010. For the nine months ended, September 30, 2009, we recorded impairment to oil and gas properties totaling $5.3 million. We review our proved and unproved 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. For the period ended September 30, 2009, the impairment of $5.3 million (which is recorded in discontinued operations) is a result of a decline in the fair market value of the Company’s interest in South Akcakoca Sub-Basin asset in Turkey. The fair market value declined during the first quarter of 2009 due to a 25.00% reduction in the posted sales price of natural gas produced in Turkey announced on May 1, 2009.

General and administrative before stock compensation expense

General and administrative expense, excluding stock compensation expense, was $7.0 million for the nine months ended September 30, 2010 compared to $11.8 million for the nine months ended September 30, 2009. This decrease is due to the effort started in 2009 to reduce general and administrative expense as well as to the reclassification of certain oil production related expenses to lease operating expenses. In addition, the general and administrative expense for 2009 also included costs associated with the relocation of corporate headquarters, subsidiary sales and resignation of former officers.

Stock compensation expense

Stock compensation expense was $2.6 million for the nine months ended September 30, 2010 compared to $2.8 million for the nine months ended September 30, 2009. Stock compensation expense includes directors annual stock granting of immediately vested shares for $650,000.

Table of Contents

Gain on oil and gas derivative contracts

Gain on oil and gas derivative contracts for the nine months ended September 30, 2010 was $ 709,000 (as compared to an unrealized income of $7,000 for the nine months ended September 30, 2009) representing the unrealized gain on the commodity derivative contracts with Vitol Trading. We had derivative contracts covering only the period from July 1 to December 31 in 2009. Presented in the table below is a summary of the contract entered into:

Type	Period	Barrels	Floor		Ceiling		Unrealized gain for nine months September 30, 2010

Collar	January 1, 2010 - December 31, 2010	182,500	$	68.00	$	81.00	$	(709	)

Foreign currency exchange gain (loss)

We recorded a loss on foreign currency exchange of $1.3 million for the nine months ended September 30, 2010 compared with a gain of $0.1 for the nine months ended September 30, 2009. This increase is mainly due to the fact that Toreador Energy France booked a loss on foreign currency exchange in its statutory accounts in Euro over the three months ended September 30, 2010 due to the receipt on June 10, 2010 of the $15 million upfront payment from Hess under the Investment Agreement combined with the weakening of the U.S. dollar compared to the Euro over the same period (this loss having been recorded in the financial statements of the Company for the third quarter of 2010 in accordance with FAS 52 “Foreign Currency Translation”).

Loss (gain) on the early extinguishment of debt

We recorded a loss of $4.3 million on the early extinguishment of debt compared to a gain of $3.4 million for the nine months ended nine months ended September 30, 2009. This loss occurred following the Convertible Notes Exchange on February 1, 2010. In 2009 the Company repurchased $25.7 million face value of the 5.00% Convertible Senior Notes on the open market for $21.3 million, resulting in a gain on the early extinguishment of debt of $3.4 million after writing off deferred loan costs of approximately $1 million.

Interest expense, net of capitalized interest

Interest expense, net of capitalized interest was $4.4 million for the nine months ended September 30, 2010, as compared to $1.8 million for the nine months ended September 30, 2009. The increase is mainly due to the interest payments relating to the New Convertible Senior Notes issued in February 2010, which was offset by decreased interest payments relating to the 5.00% Convertible Senior Notes, of which $22.2 million of the aggregate principal amount outstanding were exchanged for a portion of the New Convertible Senior Notes in the Convertible Notes Exchange. Interest expense for the New Convertible Senior Notes was $1,687,000 for the nine months ended September 30, 2010 as compared to zero for the nine months ended September 30, 2009. Interest expense for the 5.00% Convertible Senior Notes was $1,307,000 for the nine months ended September 30, 2010 as compared to $2,611,000 for the nine months ended September 30, 2009. Amortization of $1,408,522 was recorded for the period ended September 30, 2010 compared to $145,280 for the period ended September 30, 2009, due to the change in estimate of the lives of the issue premium and debt issuance costs associated to 5.00% Convertible Senior Notes and to the New Convertible Senior Notes (See Note 5 — “Change in Depreciable Lives of Issue Premium and Debt Issuance Costs”).

Table of Contents

Income tax (benefit) provision

An income tax provision of $5.7 million was recorded in the nine months ended September 30, 2010, compared to a tax benefit of $1.0 million recognized for the nine months ended September 30, 2009. This increase is due to the provision for income tax payable in France for the year ended December 31, 2010 as a result of the $15 million upfront payment from Hess under the Investment Agreement together with earnings estimate for operations in France based on oil production activity.

Discontinued operations

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

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

Table of Contents

	Nine Months Ended
	September 30,
	2010			2009
Revenue and other income
Sales and other operating revenue	$	—		$	4,545
Operating costs and expenses:
Lease operating expense	—			886
Exploration expense	—			868
Dry hole costs	—			1,318
Depreciation, depletion and amortization	—			157
Accretion on discounted assets and liabilities	—			—
Impairment of oil and natural gas properties	—			10,725
General and administrative expense	763		(1)	3,424
(Gain) loss on sale of properties and other assets	—			(1,675		)
Total operating costs and expenses	763			15,703
Operating loss	(763		)	(11,158		)
Other income (expense)
Foreign currency exchange gain	—			3,822
Interest and other income	—			414
Loss on early extinguishment of debt — revolving credit facility	—			(4,881		)
Other expense	246			—
Interest expense, net of interest capitalized	—			(185		)
Loss before income taxes	(1,009		)	(11,988		)
Income tax provision	(104		)	—
Net loss from discontinued operations	$	(1,113	)	$	(11,988	)

We had no sales and other operating revenue from discontinued operations for the nine months ending September 30, 2010 due to the sale of all our discontinued operations in 2009. For the nine months ending September 30, 2010, we recorded $763,000 as general and administrative expense associated with the payment made to Scowcroft under the Settlement Agreement on April 30, 2010 and associated legal costs, $246,000 for legal costs associated to the Netherby dispute and payments made to Hunnisett and Barker with respect to the Overriding Royalty, and $104,000 of additional tax associated with Toreador Hungary Limited activities in 2009. We thus recorded a loss of $1.1 million from discontinued operations for the nine months ending September 30, 2010.

The following tables present production and average unit prices for Turkey:

	For the Nine Months Ended
	September 30,
	2010	2009
Production:
Oil (MBbls):
Turkey	—	39
Gas (MMcf):
Turkey	—	301
MBOE:
Turkey	—	89

Table of Contents

	For the Nine Months Ended
	September 30,
	2010	2009
Average Price:
Oil ($/Bbl):
Turkey	—	$	49.79
Gas ($/Mcf):
Turkey	—	$	8.64
$/BOE:
Turkey	—	$	50.94

Other comprehensive income

The most significant element of comprehensive income, other than net income, is foreign currency translation. For the nine months September 30, 2010, we had accumulated an unrealized income of $0.7 million as compared to an unrealized loss of $4.3 million for the comparable period in 2009. This change is primarily due to the weakening of the U.S. dollar compared to the Euro for the nine months September 30, 2010 compared to the nine months September 30, 2009.

The functional currency of our operations in France is the U.S. dollar. The functional currency in Turkey and Hungary was the U.S. dollar. The exchange rates at September 30, 2010 and September 30, 2009 were:

	September 30,
	2010		2009
Euro	$	1.3648	$	1.4643
New Turkish Lira	—		$	0.0674
Hungarian Forint	—		$	0.0054

Off-balance sheet arrangements

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

There have been no material changes in the Company’s market risk during the three months ended September 30, 2010. For additional information, refer to the market risk disclosure in Item 7A as presented in the Company’s Annual Report on Form 10-K, for the year ended December 31, 2009, which was filed with the SEC on March 16, 2010.

Table of Contents

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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

We carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this quarterly report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures as of September 30, 2010 were not effective due to the following material weakness identified in our Annual Report on Form 10-K filed on March 16, 2010 and still in existence today:

· Our accounting and financial reporting procedures were not sufficiently designed to ensure consistent and complete application of our accounting policies and to prepare financial statements in accordance with accounting principles generally accepted in the United States. This includes the lack of a sufficient review of sensitive calculations, reconciliations and critical spreadsheets by personnel in key financial reporting positions.

We are committed to improving our internal controls over financial reporting. As part of this commitment, the Company has reinforced during the third quarter of 2010 the initial measures taken over the six first months of 2010 to strengthen the control and review of sensitive calculations, reconciliations and critical spreadsheets. During 2010, we have taken the following actions to date to address the material weakness:

· Hired additional staff, as well as increased external resources provided by our independent registered public accounting firm with respect to the financial consolidation process, the preparation and review of sensitive calculations and spreadsheets.

· Implemented additional review and reconciliation policies and procedures. In addition, Deloitte Conseil is currently conducting a review of key accounting and financial reporting procedures and is expected to propose necessary additional changes, if any, by the end of November 2010.

· Initiated upgrade of certain accounting and consolidation software as well as implemented certain software designed to assist in the preparation of annual and quarterly reports.

The Company has also strengthened its internal control regarding contracts, guarantees and other commitments approval.

We will continue to monitor and evaluate the effectiveness of our internal controls and procedures and our internal controls over financial reporting on an ongoing basis and are committed to taking further action and implementing additional enhancements or improvements.

Change in Internal Control over Financial Reporting

Except as otherwise indicated above, there have been no changes in our internal control over financial reporting during the quarter ended September 30, 2010 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

Table of Contents

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

See “Note 11 — Commitments and Contingencies,” which is incorporated into this “Item 1. Legal Proceedings” by reference.

ITEM 1A. RISK FACTORS

There have been no material changes to the risk factors previously discussed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2009, which was filed with the SEC on March 16, 2010.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Share Repurchase Program

On May 27, 2010, the Board of Directors authorized a share repurchase program for the repurchase of up to $5 million of shares of Toreador common stock in the open market or in private transactions at the discretion of management over the next 12 months. The Company has no obligation to repurchase shares under the program, and the program may be suspended at any time. As of September 30, 2010, no shares of Toreador common stock have been repurchased pursuant to the share repurchase program.

ITEM 6. EXHIBITS

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

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

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

Table of Contents

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this Form 10-Q report to be signed on its behalf by the undersigned thereunto duly authorized.

	TOREADOR RESOURCES CORPORATION


November 9, 2010	/s/ Craig M. McKenzie

	Craig M. McKenzie
	President and Chief Executive Officer

November 9, 2010	/s/ Marc Sengès

	Marc Sengès
	Chief Financial Officer

TOREADOR RESOURCES CORP - FORM 10-Q - November 9, 2010

Attached files

TOREADOR RESOURCES CORP Reports