Toreador Resources 8K Other Events | TRGL 12 Nov 09

Exhibit 99.1

Item 6. Selected Financial Data

The following selected financial information (which is not covered by the report of an independent registered public accounting firm) is summarized from our results of operations for the five-year period ended December 31, 2008 and as well as selected consolidated balance sheet data as of December 31, 2008, 2007, 2006, 2005 and 2004 and should be read in conjunction with the consolidated financial statements and the notes thereto included herewith.

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 financial gain of $5.8 million which was recorded in the first quarter of 2009.

In February 2009, the Board of Directors authorized management to retain Stellar Energy Advisors, based in London, UK, to manage a process to monetize its wholly owned subsidiary, Toreador Turkey Ltd. (“Toreador Turkey”), including the Company’s remaining 10% interest in the SASB, in addition to the onshore production, and 2.2 million net acres in exploration licenses that are currently held in Turkey. On September 30, 2009, the Company entered into 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. The sale of Toreador Turkey was completed on October 7, 2009.

Additionally, on September 30, 2009, the Company entered into a Quota Purchase Agreement (the “Quota Purchase Agreement”) with RAG (Rohöl-Aufsuchungs Aktiengesellschaft), a corporation organized under the laws of Austria (“RAG”), pursuant to which the Company agreed to sell 100% of its equity interests in Toreador Hungary Limited (“Toreador Hungary”) to RAG. The sale of Toreador Hungary was completed on September 30, 2009.

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

	Years Ended December 31,
	2008			2007			2006			2005			2004
	(Amounts in thousands, except per share amounts)
Operating Results:
Revenues	$	34,150		$	25,907		$	27,294		$	20,594		$	12,771
Costs and expenses	(32,586		)	(29,473		)	(20,552		)	(17,296		)	(13,082		)
Operating income (loss)	1,564			(3,566		)	6,742			3,298			(311		)
Other income (expense)	(3,082		)	(2,384		)	3,373			19			(1,616		)
Income (loss) from continuing operations before income tax	(1,518		)	(5,950		)	10,115			3,317			(1,927		)
Income tax benefit (provision)	(5,502		)	1,402			(3,236		)	2,665			2,194
Income (loss) from continuing operations, net of tax	(7,020		)	(4,548		)	6,879			5,982			267
Income (loss) from discontinued operations, net of tax	(101,585		)	(69,873		)	(4,301		)	4,613			15,153
Dividends on preferred shares	—			(162		)	(162		)	(684		)	(714		)
Income (loss) available to common shares	$	(108,605	)	$	(74,583	)	$	2,416		$	9,911		$	14,706
Basic income (loss) available to common shares per share	$	(5.48	)	$	(4.07	)	$	0.16		$	0.69		$	1.54
Diluted income (loss) available to common shares per share	$	(5.48	)	$	(4.07	)	$	0.15		$	0.66		$	1.54
Weighted average shares outstanding
Basic	19,831			18,358			15,527			14,213			9,571
Diluted	19,831			18,358			15,884			15,140			9,571
Balance Sheet Data:
Working capital	$	73,286		$	203,591		$	188,029		$	168,802		$	24,293
Oil and natural gas properties, net	72,753			80,983			71,663			60,967			53,452
Oil and natural gas properties held for sale, net	91,959			190,968			179,352			77,191			28,942
Total assets	207,156			323,111			317,204			261,814			94,674
Debt, including current portion	110,275			116,250			112,800			92,060			9,022
Stockholders’ equity	52,560			163,825			147,151			132,359			63,250
Cash Flow Data:
Net cash provided by (used in) operating activities	$	16,766		$	(12,434	)	$	122		$	(138	)	$	(8,177	)
Capital expenditures for oil and natural gas property and equipment, including acquisitions	(770		)(1)	3,824			5,883			18,350			6,492
Capital expenditures for oil and natural gas property and equipment held for sale	11,472			86,820			99,282			31,813			9,493

(1) Due to an over accrual in 2007.

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

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

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

Executive Overview

We are an independent international energy company engaged in oil and natural gas exploration, development, production, leasing and acquisition activities. We have developed a corporate platform that will be the building blocks of our new corporate strategy that will be presented at the Annual Shareholder Meeting in June 2009. The Board and management are committed to restoring shareholder value, exercising financial discipline, transparency in all transactions, assessing strategic alternatives that lay outside and beyond the platform and strengthening the Company during the current economic crisis, so that we may outperform our peers.

We believe that the following proactive steps will be the base for the future growth of the Company:

· The $55 million sale of a 26.75% interest in the South Akcakoca Sub-Basin (SASB) to Petrol Ofisi was closed and $50 million was funded on March 3, 2009;

· A share buyback program has been adopted by the Board of Directors for the repurchase of up to 1 million common shares of Toreador that may be repurchased in the open market at any time over the next 12 months;

· The Company intends to buy back a portion of its currently outstanding Convertible Senior Notes;

· Notwithstanding that the Company is incorporated in Delaware and listed on the NASDAQ, its operations are located in Europe. With its current headquarters in Dallas costing over $7 million a year in overhead, there is considerable room to improve efficiency and integrate activities across the Company. The Company expects to have completed moving its headquarters to its Paris office by July 2009, reducing its presence in the United States to focus only on securities exchange requirements and investor relations;

· The Paris Basin will remain the Company’s core asset with current production of approximately 1,000 net barrels per day coming from low-decline, long-life assets. A comprehensive portfolio review of our fields and 461,000 net acres held pursuant to licenses is now underway. The results of the study will be launched as part of the three year strategic plan at the Annual Stockholders Meeting in June 2009.

· 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 agreement 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 by Petrol Ofisi on September 1, 2009.

· In accordance with the covenants of our revolving credit facility with the International Finance Corporation, a portion of the proceeds of the sale of our 26.75% interest in the SASB to Petrol Ofisi was used to fully repay the $36.4 million balance outstanding under the credit facility, which was comprised of $30 million principal, $5.9 million of 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.

· On September 30, 2009, the Company entered into a Quota Purchase Agreement (the “Quota Purchase Agreement”) with RAG (Rohöl-Aufsuchungs Aktiengesellschaft), a corporation organized under the laws

of Austria (“RAG”), pursuant to which the Company agreed to sell 100% of its equity interests in Toreador Hungary Limited (“Toreador Hungary”) to RAG. The sale of Toreador Hungary was completed on September 30, 2009.

· On September 30, 2009, the Company entered into the Share Purchase Agreement with Tiway, pursuant to which the Company agreed to sell 100% of the outstanding shares of Toreador Turkey to Tiway for total consideration consisting of: (1) a cash payment of $10.6 million to be paid at closing (subject to a post-closing adjustment), (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 closed on October 7, 2009.

Financial Summary

· For the year ended December 31, 2008, we had revenues of $34.2 million which is primarily due to the dramatic increase in worldwide oil prices received in 2008.

· Operating costs for the year ended December 31, 2008 were $32.6 million of which $2.3 million is attributable to the impairment of undeveloped leasehold costs in Trinidad.

· Net loss available to common shares was $108.6 million for the year ended December 31, 2008.

· Production was 365 MBOE for the year ended December 31, 2008.

· Capital expenditures were $11 million for the year ended December 31, 2008.

· Cash and cash equivalents of $14.9 million for the year ended December 31, 2008.

· Repurchase of $6 million of convertible notes at a discounted purchase price of $5.3 million for the year ended December 31, 2008.

· A current ratio of 2.38 to 1 at December 31, 2008.

· A debt (current portion of long-term debt and Convertible Senior Notes) to equity ratio of 2.10 to 1 at December 31, 2008.

· Oil and natural gas properties held for sale of $92 million, is the fair value of the assets in Turkey, Hungary and Romania, which are each classified as a current asset as the sale is expected to close within one year of the December 31, 2008.

Critical Accounting Policies and Management’s Estimates

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

Successful Efforts Method of Accounting

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

As of December 31, 2008, we had no costs associated with exploratory costs that had been capitalized for a period of one year or less.

As of December 31, 2008, we had $2.3 million associated with exploratory costs that have been capitalized for a period of greater than one year.

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

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

Reserve Estimates

Proved reserves are estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods as well as oil and natural gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery after testing by a pilot project or after the operation of an installed program has been confirmed through production response that increased recovery will be achieved. Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Proved undeveloped reserves on undrilled acreage are limited (i) to those drilling units offsetting productive units that are reasonably certain of production when drilled and (ii) to other undrilled units where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. We emphasize that the volume of reserves are estimates that, by their nature are subject to revision. The estimates are made using geological and reservoir data, as well as production performance data. These estimates are reviewed annually and revised, either upward or downward, as warranted by additional performance data. These reserve revisions 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, 2008, we had a downward reserve revision of 37.41%. At December 31, 2007 the price used for evaluating our oil reserves was $95.72 per barrel as compared to the December 31, 2008 price of $34.29 per barrel. This 65% decrease in oil price had a severe impact on the economic life of our wells, but also on the discounted present value at 10% and the standardized measure of proved reserves. This downward revision, which primarily affected our French oil reserves, was due to the following factors (i) decrease in economic life due to change in economics caused a net decrease of 1,682 MBbl; (ii) removing twelve proved undeveloped locations from the report caused a net decrease 1,889 MBbl; (iii) negative reserve revisions resulted in a decrease in reserves of 405 MBbl; (iv) fourteen wells were shut-in resulting in a decrease of 401 MBbl; (v) three drilled locations in prior years resulted in one producing well which was non-commercial at December 31, 2008 causing a net decrease of 280 MBbl;(vi) one well was lost during workover operations causing a net decrease 37 MBbl; (vii) 2008 production of 805 MBOE. In Hungary, we were able to secure a gas contract and were able to restore the reserves lost in 2007, this resulted in an increase of 159 MBOE and in Romania due to the poor performance of the field resulted in a decrease of 54 MBOE. In Turkey, we had downward revisions of 390 MBOE. which was due to a decrease in the economic life of the proved developed wells.

For the year ended December 31, 2007, we had a downward reserve revision of 4.8%. This downward revision was due to the following factors: (i) in Hungary, lack of a gas market caused a deletion of previously booked, technical recoverable reserves of 159 MBOE; (ii) in Romania, one gas well watered out and another is under performing based on previous projections resulting in a downward revision of 305.6 MBOE; (iii) in the South Akcakoca Sub-Basin in Turkey, new pressure information and early performance data refined the geological interpretation resulting in a downward revision of 1,369.4 MBOE. These downward revisions were partially offset by improved performance in the Neocomian Field in France and the Cendere Field in Turkey.

For the year ended December 31, 2006, we had a downward reserve revision of 9%. This downward revision was due to the following factors: (i) in the Charmottes Field in France, several high volume producing wells experienced rapidly increasing water production which caused performance declines resulting in a downward revision of 921 MBbl; (ii) in Romania, two gas wells watered out after producing for short periods of time resulting in a downward revision of 197 MBOE; (iii) in the South Akcakoca Sub-Basin, due to new drilling, a previous geological interpretation was refined resulting in a downward revision of 192 MBOE and (iv) there was a downward revision of 73 MBOE due to a decline in prices. These downward revisions were partially offset by upward revisions of 187 MBOE due to performance revisions over several fields, none of which individually contributed a significant portion of this upward revision.

Impairment of Oil and Natural Gas Properties and Intangible Assets

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

Impairment charged in 2008 was $85.2 million of which $82.9 million is attributable to discontinued operations and $2.3 million to continuing operations, as compared to $13.4 million in 2007, all of which was discontinued operations. The impairment was a result of the following:

Discontinued Operations

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

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

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

for this impairment is due to the fair value of the Turkish subsidiary, based on the discounted present value of the oil and gas reserves being less than the carrying value of the Turkish subsidiary. This resulted in an impairment charge of $833,000.

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

Continuing Operations

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

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

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 SFAS 143 “Accounting for Asset Retirement Obligations”. SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recorded in the period in which it is incurred and the corresponding cost 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. The Company has two fallen structures at the bottom of the Black Sea. There has been no liability recorded for the environmental remediation as the likelihood of having to remove the structures is remote.

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

Income Taxes

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

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

Derivatives

We periodically utilize derivatives instruments such as futures and swaps for purposes of hedging our exposure to fluctuations in the price of crude oil sales. In accordance with SFAS No. 133, Accounting for “Derivative Instruments and Hedging Activities,” we have elected not to designate the derivative financial instruments to which we are a party as hedges, and accordingly, we record such contracts at fair value and recognize changes in such fair value in current earnings as they occur. We determine the fair value of futures and swap contracts based on the difference between their fixed contract price and the underlying market price at the determination date. The realized and unrealized gains and losses on derivatives are recorded as a derivative fair value gain or loss in the income statement.

Foreign Currency Translation

The functional currency for Turkey, Romania and Hungary is the United States Dollar and in France the functional currency is the Euro. Translation gains or losses resulting from transactions in the New Turkish Lira in Turkey, the Lei in Romania and the Forint in Hungary are included in income available to common shares for the current period. 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.

New Accounting Pronouncements

In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement No. 157 “Fair Value Measurements” (“SFAS No. 157”). SFAS No. 157 provides guidance for using fair value to measure assets and liabilities. It applies whenever other standards require or permit assets or liabilities to be measured at fair value but it does not expand the use of fair value in any new circumstances. In November 2007, the FASB issued FSP No. 157-2 to defer the effective date of SFAS 157 to fiscal year beginning after November 15, 2008, and the interim period for that fiscal year for all non-financial assets and liabilities, except those that are recognized or disclosed at fair value on a recurring basis. We are currently evaluating the impact of our adoption of FSP No. 157-2 which was adopted effective January 1, 2009. The provisions of SFAS No. 157 that were not deferred were effective for financial statements issued for fiscal years beginning after November 15, 2007. The adoption of SFAS No. 157, effective January 1, 2008, did not have a significant effect on our reported financial position or earnings. In October 2008, the FASB issued FSP No. 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset is Not Active” (FSP 157-3). FSP 157-3 clarifies the application of SFAS 157, which the Company adopted as of January 1, 2008, in cases where a market is not active. The Company has considered FSP 157-3 in its determination of estimated fair values as of December 31, 2008, and the impact was not material.

In February 2007, the FASB issued Statement 159, “The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement 115” (“SFAS No. 159”). SFAS No. 159 permits entities to choose to measure certain financial instruments and other items at fair value. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. Unrealized gains and losses on any items for which we elect the fair value measurement option are to be reported in earnings. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. The Company elected not to measure any eligible items using the fair value option in accordance with SFAS No. 159 and therefore the adoption of SFAS No. 159, effective January 1, 2008, did not have an effect on our reported financial position or earnings.

In December 2007, the FASB issued Statement No. 141R, “Business Combinations” (“SFAS No. 141R”). Under SFAS No. 141R, a company is required to recognize the assets acquired, liabilities assumed, contractual contingencies, and any contingent consideration measured at their fair value at the acquisition date. It further requires that research and development assets acquired in a business combination that have no alternative future use are to be measured at their acquisition-date fair value and then immediately charged to expense, and that acquisition-related costs are to be recognized separately from the acquisition and expensed as incurred. Among other changes, this statement also requires that “negative goodwill” be recognized in earnings as a gain attributable to the acquisition, and any deferred tax benefits resultant in a business combination be recognized in income from continuing operations in the period of the combination. SFAS No. 141R is effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning after December 15, 2008. We are currently determining the effect of adopting SFAS No. 141R.

In December 2007, the FASB issued Statement No. 160, “Noncontrolling Interests in Consolidated Financial Statements” — an amendment of ARB No. 51 (“SFAS No. 160”). SFAS No. 160 amends ARB 51 to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary, which is sometimes referred to as minority interest, is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. Among other requirements, this statement requires consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interest. It also requires disclosure, on the face of the consolidated income statement, of the amounts of consolidated net income attributable to the parent and to the noncontrolling interest. SFAS No. 160 is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2008. The effect of adopting SFAS No. 160 is not expected to have an effect on our reported financial position or earnings.

In March 2008, the FASB issued Statement No. 161 — “Disclosures about Derivative Instruments and Hedging Activities” — an Amendment of FASB Statement No. 133 (“SFAS No. 161”). This statement changes the disclosure requirements for derivative instruments and hedging activities. Entities are required to provide enhanced disclosures about (i) how and why an entity uses derivative instruments, (ii) how derivative instruments and related hedged items are accounted for under FASB Statement No. 133 and its related interpretations, and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS No. 161 is effective for annual periods beginning after November 15, 2008. We are currently assessing the effect, if any, the adoption of SFAS No. 161 will have on our financial statements and related disclosures.

In May 2008, the FASB issued Statement No. 162 — “The Hierarchy of Generally Accepted Accounting Principles (“SFAS No. 162”). The new standard is intended to improve financial reporting by identifying a consistent framework, or hierarchy, for selecting accounting principles to be used in preparing financial statements that are presented in conformity with U.S. generally accepted accounting principles for nongovernmental entities. SFAS No. 162 will be effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board Auditing amendments to AU Section 411, The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles. We are currently assessing the effect, if any, the adoption of SFAS No. 162 will have on our financial statements and related disclosures.

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

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

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

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

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

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

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

discussions may delay the required compliance date. Absent any change in the effective date, we will comply with the disclosure requirements in our annual report on Form 10-K for the year ended December 31, 2009.

In November 2008, the FASB ratified EITF 08-6, “Equity Method Investment Accounting Considerations” (“EITF08-6”) which clarifies how to account for certain transactions involving equity method investments. The initial measurement, decreases in value and changes in the level of ownership of the equity method investment are addressed. EITF 08-6 is effective on a prospective basis for our fiscal year beginning January 1, 2009 and interim periods within the year. Early application by an entity that has previously adopted an alternative accounting policy is not permitted. Adoption is not expected to have a significant impact on our consolidated results of operations or cash flows.

In May 2008, the FASB issued FASB Staff Position (“FSP”) No. APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlement)” (“FSP APB No. 14-1”). FSP APB No. 14-1 specifies that issuers of such instruments should separately account for the liability and equity components in a manner that will reflect the entity’s nonconvertible debt borrowing rate when interest costs is recognized in subsequent periods. FSP APB No. 14-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008 and interim periods within those fiscal years. FSP ABP No. 14-1 should be applied retrospectively for all periods presented. The Company is currently evaluating what impact the adoption of this pronouncement will have on its consolidated financial statements.

LIQUIDITY AND CAPITAL RESOURCES

This section should be read in conjunction with Notes 7 and 8 to Notes to Consolidated Financial Statements included in this filing.

Liquidity

As of December 31, 2008, we had cash and cash equivalents of $14.9 million, a current ratio of approximately 2.38 to 1 and a debt (current portion of long-term debt and Convertible Senior Notes) to equity ratio of 2.10 to 1. For the twelve months ended December 31, 2008, we had an operating income of $1.6 million and capital expenditures were $11 million.

During 2008, we saw oil prices rise to unprecedented levels and then in September we saw the start of a deterioration in the credit and equity markets which has continued to deteriorate further in 2009. We also experienced a 50% - 60% decline in oil prices from the highest prices received in 2008. These severe economic conditions have caused the Company to reevaluate its capital expenditure program for 2009 and how the Company will operate on a go forward basis.

In February 2009, the Company announced a new platform from which a new strategy will be built. The platform is built on (i) reduction in overhead — through moving our corporate headquarters to Paris, France, significant savings of general and administrative expense due to a consolidation of job functions and the sale of all the Company’s remaining interest in Turkey. We estimate that these measures will result in a decrease of general and administrative expenses of approximately 50%; (ii) uses of cash — other than funding our mandatory capital expenditures, our primary use of discretionary cash will be used to reduce debt; (iii) a focused oil and natural gas portfolio — the Company will refocus its efforts to those areas that offer the best chance of success and have a proven infrastructure for the oil and natural gas industry. We believe that our current acreage positions in France and Hungary can serve as the platform for growth and offer the Company the best opportunity to create stockholder value; and (iv) performance management - the Board and management are committed to the best practices in corporate governance and will continually be reviewing and where necessary revising the procedures used to operate the Company. We intend to use third party expertise to review and challenge our procedures and methodologies, both operationally and administratively. Also performance management, actions followed by positive results, will become a driving principle in operating the Company.

On March 3, 2009, we closed the sale of a 26.75% interest in the South Akcakoca Sub-Basin project and associated licenses located in the Black Sea offshore Turkey, to Petrol Ofisi for US $55 million. In accordance with the revised assignment, $50 million of the proceeds was paid by Petrol Ofisi upon closing and the remaining $5 million is due on September 1, 2009.

Simultaneous with the closing of the sale to Petrol Ofisi, we repaid the Secured Revolving Credit Facility with the International Finance Corporation. The total amount of the payment was $36.4 million, which was comprised of $30 million principal, $5.9 million additional compensation due under the $10 million facility and $500,000 for accrued interest and fees. After giving effect to the repayment, our debt to equity ratio would be 1.53 to 1.

The remaining cash totaling $13.6 million after repaying the International Finance Corporation and cash and cash equivalents on hand of $19.4 million, will be used to retire a portion of the convertible notes and fund the 2009 capital program to meet minimum commitments associated with the Company’s licenses.

After the retirement of the credit facility with the International Finance Corporation, the Company will not have a credit facility and will rely on its cash balance to meet its immediate cash requirements. Management will consider securing a new facility in 2009, but given today’s economic environment there can be no assurance that a new facility can be obtained, and any draw down made if the facility is successfully secured would only be made to offset any further retirement of convertible notes beyond the amount referenced above.

Our capital expenditure budget for 2009 is currently set at $7.2 million and assumes a sale of our remaining interest in Turkey to be closed by September 1, 2009. This amount represents our 10% share of Phase II development cost in the South Akcakoca Sub-Basin, our estimated share of the cost in the drilling of a Thrace Black Sea well after we are carried on the first $10.7 million of costs and the cost of installing a pipeline in Hungary in order to produce the reserves associated with the Szolnok Permit. If the sale does not close as anticipated we could incur an additional $800,000 in capital expenditures in 2009.

We believe we will have sufficient cash flow from operations to meet all of our 2009 obligations. However, if the cash flow from our operations is less than anticipated and if we have used up our cash we may also seek additional capital by (i) forward selling our crude oil and natural gas production; (ii) selling our interest in prospects and or licenses; (iii) selling our working interest in properties; or (iv) a combination of these actions in addition to issuing new debt or equity securities We believe such actions will allow us to meet our capital commitments and that as a result, we will have sufficient liquidity for the remainder of 2009.

Secured Revolving Facility

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 funded on March 2, 2007. The total proceeds received on March 2, 2007 were approximately $25 million, of which $11 million was used to retire the outstanding balance on the $15 million credit facility and the remaining $14 million of funds was used to finance our capital expenditures in Turkey and Romania. The loan and guarantee agreement also provided for an unsecured $10 million facility which funded on December 28, 2006. Both the $25 million facility and the $10 million facility were to fund our operations in Turkey and Romania.

Interest accrued on any loans under the $25 million facility at a rate of 2% over the six month LIBOR rate. Interest accrued on the $10 million facility at a rate of 1.5% over the six month LIBOR rate until the $25 million facility funded on March 2, 2007 after which the rate for the $10 million facility was lowered to 0.5% over the six month LIBOR rate. As of December 31, 2008 the interest rate on the $10 million facility was 2.823% and 4.323% on the $25 million facility. Interest was to be paid on each June 15 and December 15.

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

We were to meet the following ratios on a consolidated basis: (i) the life of loan coverage ratio of not less than: (a) 1.2:1.0 in 2006 and 2007; (b) 1.3:1.0 in 2008; and (c) 1.4:1.0 in 2009 and each subsequent year thereafter; (ii) reserve tail ratio of not less than 25%; (iii) adjusted financed debt to EBITDAX ratio of not more than 3.0:1.0; (iv) liabilities to tangible net worth ratio of not more than 60:40; and (v) interest coverage ratio of not less than 3.0:1.0. At December 31, 2008, we were not in compliance with the liabilities to tangible net worth ratio, however we did not request a waiver from the IFC as the facility was subsequently retired on March 3, 2009

We were subject to certain negative covenants, including, but not limited to, the following: (i) except as required by law or to pay the dividends on the Series A-1 Convertible Preferred Stock, which is no longer outstanding, paying dividends; (ii) subject to certain exceptions, incurring debt, making guarantees or creating or permitting to exist any liens, (iii) subject to certain exceptions, making or permitting to exist loans or advances to, or deposits, with other persons or investments in any person or enterprise; (iv) subject to certain exceptions, selling, transferring, leasing or otherwise disposing of all or a material part of its borrowing base assets; and (v) subject to certain exceptions, undertaking or permitting any merger, spin-off, consolidation or reorganization.

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 was comprised of $30 million principal, $5.9 million additional compensation due under the $10 million facility and $500,000 for accrued interest and fees.

5% Convertible Senior Notes Due 2025

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

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

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

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

The registration rights agreement covering the Convertible Senior Notes provides for a penalty if the registration statement is filed and declared effective but thereafter ceases to be effective (a “Suspension Period”) for an aggregate of forty-five (45) days in any three month period or ninety (90) days in any twelve month period (an “Event Date”). Such penalty calls for an additional 0.25% per annum in interest expense on the aggregate principal amount of the Convertible Senior Notes for the first ninety (90) days following an Event Date and an additional 0.50% per annum in interest expense on the aggregate principal amount of the Convertible Senior Notes thereafter, until such Suspension Period ends upon the registration statement again becoming effective or not being required to be effective pursuant to the registration rights agreement. Because we did not file our Quarterly Report on Form 10-Q for the nine month period ended September 30, 2006 in a timely manner, the registration statement for the Convertible Senior Notes became ineffective and we entered a Suspension Period on November 15, 2006. Such Suspension Period ended on January 23, 2007 when we provided notice that the Form 10-Q had been filed and the Suspension Period was no longer in effect. Because the Suspension Period exceeded forty-five (45) days in any

three month period, we paid approximately $14,375 in additional interest expense. On March 16, 2007, the date we filed our Form 10-K for the year ended December 31, 2006, we again entered a Suspension Period until all the Convertible Senior Notes became eligible for sale pursuant to Rule 144(k) on September 30, 2007. On October 1, 2007, $155,000 was deposited with the trustee for the Convertible Senior Notes as the penalty for any holders of the Notes who were eligible on October 1, 2007 to receive a pro rate portion of such payment. Such eligible holders had to have registered their Notes on the registration statement and still held those Notes on October 1, 2007. On April 1, 2008, we requested that the trustee return $150,957 which represents the unclaimed portion of the penalty and on April 3, 2008 we received the funds from the trustee. Through December 31, 2008, we released $4,043 of the penalty deposit to eligible holders of Convertible Senior Notes.

On July 9, 2008, our Board of Directors authorized a program to repurchase up to $10 million of the Convertible Senior Notes by December 31, 2008. We repurchased $6 million of the Convertible Senior Notes for $5.3 million plus accrued interest of $109,347. Additionally, we expensed $241,965 of prepaid loan fees that attributable to the repurchased notes. This resulted in a $458,535 gain on the early extinguishment of debt. Any repurchases will be made in the open market or in privately negotiated transactions, subject to market conditions, applicable legal requirements and other factors. The plan does not obligate us to acquire any particular amount of the Convertible Senior Notes bonds and the plan may be suspended at any time at our discretion.

Preferred Stock

On February 22, 2005, 82,000 shares of Series A-1 Convertible Preferred Stock were exchanged for an aggregate of 512,000 shares of our common stock. As of December 31, 2006, there were 72,000 shares of Series A-1 Convertible Preferred Stock outstanding. At the option of the holder, the Series A-1 Convertible Preferred Stock could be converted into common shares at a price of $4.00 per common share. The Series A-1 Convertible Preferred Stock accrued dividends at an annual rate of $2.25 per share payable quarterly in cash. At any time on or after November 1, 2007, we had the right to redeem for cash any or all shares of Series A-1 Convertible Preferred Stock. In December 2007, the remaining 72,000 shares of Series A-1 Convertible Preferred Stock were converted into 450,000 shares of common stock.

Dividend and Interest Requirements

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

Dividends on our Series A-1 Convertible Preferred Stock were paid quarterly. For the year ended December 31, 2007 dividends totaled $162,000. The remaining shares of Series A-1 Convertible Preferred Stock were converted into common stock in December 2007.

The terms of the loan and guarantee agreement with the International Finance Corporation limit the payment of dividends only to those that are required by law and to dividends associated with our Series A-1 Convertible Preferred Stock, which is no longer outstanding.

Contractual Obligations

The following table sets forth our contractual obligations in thousands at December 31, 2008 for the periods shown:

	Total		Less than One Year		One to Three Years		Four to Five Years		More than Five Years
Continuing operations:
Long-term debt	$	110,275	$	30,000	$	—	$	—	$	80,275
Lease commitments	3,267		545		1,696		1,026		—
Discontinued Operations:
Lease commitments	916		225		628		63		—
Total contractual obligations	$	114,458	$	30,770	$	2,324	$	1,089	$	80,275

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

On March 3, 2009 the Company retired the outstanding amount due under the Secured Revolving Facility with the International Finance Corporation. The total amount paid was $36.4 million which was comprised of $30 million in principal, $5.9 million in additional compensation and $500,000 in accrued interest and fees.

Results of Continuing Operations

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

Comparison of Years Ended December 31, 2008 and 2007

	For the Years Ended December 31,
	2008		2007
Production:
Oil (MBbls):
France	365		383
Average Price:
Oil ($/Bbl):
France	$	93.32	$	67.49

Revenues

Oil sales

Oil sales for the twelve months ended December 31, 2008 were $34.2 million, as compared to $25.9 million for the comparable period in 2007. This increase is due to the increase in the average realized price for oil, $9.4 million partially offset by the decline in production $1.2 million.

Oil production decreased in France primarily due to the loss of production from a well that encountered mechanical and downhole problems during a workover operation that was eventually plugged and several wells that were shut-in in the fourth quarter waiting on rig availability to commence workover operations.

The above table compares both volumes and prices received for oil for the twelve months ended December 31, 2008 and 2007. Oil prices are and probably will continue to be extremely volatile and a significant change will have a material impact on our revenue.

Costs and expenses

Lease operating

Lease operating expense was $9.3 million, or $25.37 per BOE produced for the twelve months ended December 31, 2008, as compared to $7.3 million, or $19.17 per BOE produced for the comparable period in 2007. This increase is primarily due to increased operating costs in France due to the age of the fields and additional workover costs in 2008.

Exploration expense

Exploration expense for the twelve months ended December 31, 2008 was $1.2 million, as compared to $3.5 million for the comparable period in 2007. These costs are associated with our exploration departments in France and Dallas and the decrease is due primarily to the reduction of staff in the exploration department in Dallas.

Dry hole and abandonment

Dry hole and abandonment cost for the twelve months ended December 31, 2008 was zero, as compared to $3.8 million in 2007. During 2007 we drilled two dry holes in France costing $3.8 million. Additionally, the Company made a strategic decision to no longer drill 100% exploratory wells or fund 100% seismic programs on exploratory acreage. We have begun a systematic process of farming out our exploratory prospects to industry partners. The terms of farm outs have been and will generally be structured so that the farmee will pay at least a majority of all seismic costs and drill an exploratory well to casing point in order to earn a 50%-75% working interest in the prospect or concession.

Depreciation, depletion and amortization

For the twelve months ended December 31, 2008, depreciation, depletion and amortization expense was $5 million, or $13.70 per BOE produced, as compared to $4.4 million, or $11.49 per BOE produced for the twelve months ended December 31, 2007. This increase is primarily due to the reduction in proved reserves at December 31, 2008.

Impairment of oil and natural gas properties

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

General and administrative

General and administrative expense was $13 million for the twelve months ended December 31, 2008, compared with $12.5 million for the comparable period of 2007. General and administrative expense is divided into the following categories:

General and administrative before stock compensation and severance payments

General and administrative expense, not including stock compensation expense and amounts due the former employees upon their resignation, was $9.8 million for the twelve months ended December 31, 2008, compared with $7.5 million for the comparable period of 2007. This increase is due to no longer being able to allocate general and administrative expenses to the foreign subsidiaries due to the decreased exploration and development activities in 2008, as compared to 2007.

Stock compensation expense

Stock compensation expense was $2.3 million for the twelve months ended December 31, 2008, compared with $2.9 million for the comparable period of 2007. This decrease is primarily due to the forfeiture of most of the restricted stock granted to the executives that resigned in June 2008.

Cost incurred in relation to the resignation of former employees of the Company

In June 2008, Mr. Michael FitzGerald resigned as Executive Vice President — Exploration and Production and Mr. Edward Ramirez resigned as Senior Vice President — Exploration and Production. The Separation and Release Agreements provide for one year of salary for each individual which resulted in an expense of $600,000, and for Mr. FitzGerald the immediate vesting of 5,000 shares of restricted stock grants and for Mr. Ramirez the immediate vesting of 7,000 shares of restricted stock grants which resulted in an expense of $35,000.

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

In January 2007, Mr. G. Thomas Graves III resigned as President and Chief Executive Officer. The Separation Agreement between Mr. Graves and the Company called for the immediate vesting of all restricted stock grants which resulted in an expense of $1.1 million and two years of salary and one year of bonus of $1.1 million.

Gain/loss on oil and gas derivative contracts

Loss on oil and gas derivative contracts of $1.8 million for 2008 represents the recognized loss on the commodity derivative contracts with Total Oil Trading. Presented in the table below is a summary of the contracts entered into with the gain (loss) in thousands:

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

For the year ended December 31, 2007, we recorded a loss of $1 million for the net realized and unrealized loss on derivative financial instruments which fluctuate based on changes in the fair value of underlying commodities. We entered into futures and swap contracts for approximately 15,000 Bbls per month for the months of June 2007 through December 2008 and subsequently sold all contracts as of December 31, 2007.

Gain on the sale of properties and other assets

For the twelve months ended December 31, 2008, we recorded no gain or loss on the sale of properties and other assets, as compared to a gain of $3.2 million for 2007, which was primarily attributable to the gain on the sale of our unconsolidated investments.

Foreign currency exchange gain (loss)

We recorded a loss on foreign currency exchange of $145,000 for the year ended December 31, 2008 as compared with a $321,000 loss for the comparable period of 2007. This decrease is primarily due to the strengthening of the U. S. Dollar compared to the Euro in 2008.

Gain on the early extinguishment of debt

In 2008, we repurchased $6 million of the Convertible Senior Notes for $5.3 million plus accrued interest of $109,347. Additionally, we expensed $241,965 of prepaid loan fees that were attributable to the repurchased notes. This resulted in a $458,535 gain on the early extinguishment of debt. For the year ended December 31, 2007 we did not repurchase any of the Convertible Senior Notes.

Interest and other income

Interest and other income was $775,000 for the year ended December 31, 2008 as compared with $1.4 million in the comparable period of 2007. The decrease is due primarily to having a lower average cash balance in 2008, as compared to 2007 and a decline in interest rates during the later part of 2008..

Interest expense, net of interest capitalization

Interest expense was $4.2 million for the year ended December 31, 2008, as compared to $3.5 million for the comparable period of 2007. The increase is primarily due to $3.7 million of interest that was capitalized in 2007, as opposed to $1 million in 2008 and due to a full year of interest on the International Finance Corporation credit facility in 2008, as opposed to nine months of interest expense in 2007.

Provision for income taxes

For the year ended December 31, 2008 we reported income tax expense of $5.5 million, compared to a benefit of $1.4 million for the same period of 2007. This increase is primarily due to an increase in the French tax provision of $4 million due to higher taxable income in 2008 and an increase in the valuation allowance, relating to the United States, to reflect the likelihood that additional income tax would not be generated to offset losses of $2.9 million.

Loss available to common shares

For the year ended December 31, 2008, we reported a loss from continuing operations net of taxes of $7 million, compared with a loss of $4.5 million for the same period of 2007. For the twelve months ended December 31, 2008 we recorded a loss available to common shares of $108.6 million versus a loss available to common shares of $74.6 million for the year ended December 31, 2007.

Other comprehensive income (loss)

The most significant element of comprehensive income, other than net income, is foreign currency translation. As of December 31, 2008, we had accumulated an unrealized loss of $5.3 million. For the year ended December 31, 2007, we had an unrealized gain of $38.4 million. The decrease is a result of a change in accounting method regarding our intercompany accounts receivable due from our subsidiaries in Turkey, Romania and Hungary. Pursuant to a Board of Directors resolution, we expect to be repaid the intercompany accounts receivable from our subsidiaries in Turkey, Romania and Hungary in the foreseeable future. Due to this resolution subsequent to October 1, 2007, the foreign exchange in the intercompany accounts receivable balance is reflected in current earnings, as a foreign exchange gain or loss, rather than in accumulated other comprehensive income.

The functional currency of our operations in France is the Euro and in Romania, Turkey and Hungary, the functional currency is the United States Dollar. The exchange rates used to translate the financial position of the French, Turkish, Romanian and Hungarian operations at December 31, 2008 and 2007 are shown below:

	December 31,
	2008		2007
Euro	$	1.3917	$	1.4721

New Turkish Lira	$	0.6477	$	0.8574

Romania Lei	$	0.3460	$	0.4076

Hungarian Forint	$	0.0052	$	0.0058

Results of discontinued operations

On June 14, 2007, the Board of Directors authorized management to sell all our oil and natural gas properties in the United States. The sale of these properties completed the divestiture of the company’s non-core domestic assets and allowed us to focus exclusively on our International operations. The sale was closed on September 1, 2007. The sales price was $19.1 million which resulted in a pre-tax gain of $9.2 million.

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

Additionally, on September 30, 2009, the Company entered into the Quota Purchase Agreement with RAG, pursuant to which the Company agreed to sell 100% of its equity interests in Toreador Hungary to RAG. The sale of Toreador Hungary was completed on September 30, 2009. This resulted in a financial loss of $4.2 million which was recorded in the third quarter of 2009.

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

The table below compares discontinued operations for the years ended December 31, 2008 and 2007:

	Year Ended December 31
	2008			2007
	(In thousands)
Revenues:
Oil and natural gas sales	$	28,226		$	20,273
Costs and expenses:
Lease operating	7,971			6,892
Exploration expense	4,582			11,324
Impairment of oil and natural gas properties	82,951			13,446
Depreciation, depletion and amortization	28,148			17,466
Dry hole costs	—			18,096
General and administrative	2,445			5,131
(Gain) loss on sale of properties	123			(9,248		)
Total costs and expenses	126,220			63,107
Operating loss	(97,994		)	(42,834		)
Other income(expense)	(3,017		)	(26,361		)
Loss before taxes	(101,011		)	(69,195		)
Income tax provision	(574		)	(678		)
Loss from discontinued operations	$	(101,585	)	$	(69,873	)

Comparison of Years Ended December 31, 2008 and 2007

	For the Years Ended December 31,
	2008	2007
Production:
Oil (MBbls):
United States	—	38
Turkey	56	66
Romania	3	10
Total	59	114
Gas (MMcf):
United States	—	296
Turkey	1,840	905
Romania	446	689
Total	2,286	1,890
MBOE:
United States	—	87
Turkey	363	217
Romania	77	124
Total	440	428
Average Price:
Oil ($/Bbl):
United States	—	60.14
Turkey	93.21	61.98
Romania	57.97	57.59
Total average oil price	91.25	61.42
Gas ($/Mcf):
United States	—	6.67
Turkey	11.14	8.60
Romania	5.32	4.90
Total average gas price	10.00	6.92
$/ BOE:
United States	—	48.25
Turkey	70.88	54.77
Romania	32.99	31.55
Total average price per BOE	64.20	46.69

Revenues

Oil and natural gas sales

Oil and natural gas sales for the twelve months ended December 31, 2008 were $28.2 million, as compared to $20.3 million for the comparable period in 2007. This increase is due to 1) the increase in the average realized price for oil, $1.8 million; 2) the increase in the average realized price for gas, $2.6 million and 3) increased Turkish gas volumes, $10.4 million. This was partially offset by a 1) reduction in total oil production of 17 MBbls or $1 million; 2) a reduction in Romanian gas production of 243 MMcf or $1.3 million and 3) no United States revenue in 2008 compared to $4.4 in 2007.

The decline in Turkey oil production is normal decline and in Romania gas the field is depleting quicker than anticipated.

Costs and expenses

Lease operating

Lease operating expense was $7.9 million, or $17.95 per BOE produced for the twelve months ended December 31, 2008, as compared to $6.9 million, or $16.08 per BOE produced for the comparable period in 2007. This increase is primarily due to increased operating costs in offshore Turkey due primarily to the field being on production for all of 2008, as opposed to nine months in 2007 and workover costs incurred on the East Ayazli wells which developed problems sustaining adequate pressure in order for the wells to continue producing, increased operating expense in Romania due to increased workover cost incurred to increase production and due to inflation in the oil and gas industry during 2008 as compared to 2007.

Exploration expense

Exploration expense for the twelve months ended December 31, 2008 was $4.6 million, as compared to $11.3 million for the comparable period in 2007. This decrease is due primarily to the reduction of staff in the exploration department in Dallas. In 2008, there were no seismic surveys performed, compared to a $6.2 million 2D seismic survey that was done in Romania during the third quarter of 2007.

Dry hole and abandonment

Dry hole and abandonment cost for the twelve months ended December 31, 2008 was zero, as compared to $18 million in 2007. During 2008, we participated in the drilling of two exploratory wells in Hungary which were both dry holes. However, we incurred zero dry hole costs because our partners paid our share of the costs as per the farmout agreement. During 2007 we drilled three dry holes in Romania $10 million, two dry holes in Hungary costing $3.5 million and one dry hole in Turkey costing $4.5 million. Additionally, the Company made a strategic decision to no longer drill 100% exploratory wells or fund 100% seismic programs on exploratory acreage. We have begun a systematic process of farming out our exploratory prospects to industry partners. The terms of farm outs have been and will generally be structured so that the farmee will pay at least a majority of all seismic costs and drill an exploratory well to casing point in order to earn a 50%-75% working interest in the prospect or concession.

Depreciation, depletion and amortization.

For the twelve months ended December 31, 2008, depreciation, depletion and amortization expense was $28.1 million, or $63.86 per BOE produced, as compared to $17.5 million, or $40.79 per BOE produced for the twelve months ended December 31, 2007. This increase is primarily due to the start of natural gas production in offshore Turkey in May 2007, from two of the three platforms, and in May 2008 we began production from the third platform. The depreciation rate per BOE in Turkey is excessively high due to cost overruns in the development of the offshore gas field, in addition to the reduction in proved reserves at December 31, 2008.

Impairment of oil and natural gas properties

Impairment charged in 2008 was $83 million compared to $13.4 million in 2007. The impairment was a result of the following:

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

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

For the year ended December 31, 2007, we recorded an impairment due to the downward revisions of proved reserves in the Fauresti Field in Romania. At December 31, 2007 the cash flow before income tax and the discounted future cash flows attributable to our proved oil and natural gas reserves before income tax, discounted at 10% attributable to the 134 MBOE, in Romania, was $1.2 million and $1.1 million, respectively, and the net book value of asset was $14.5 million. This resulted in an impairment charge of $13.4 million.

General and administrative

General and administrative expense was $2.4 million for the twelve months ended December 31, 2008, compared with $5.1 million for the comparable period of 2007. The decrease is attributable to the reduced activity during 2008.

Results of Continuing Operations

Comparison of Years Ended December 31, 2007 and 2006

	For the Years Ended December 31,
	2007		2006
Production:
Oil (MBbls):
France	383		442
Average Price:
Oil ($/Bbl):
France	$	67.49	$	61.74

Revenues

Oil sales

Oil sales for the year ended December 31, 2007 were $25.9 million, as compared to $27.3 million for the comparable period in 2006. This decrease is due to a decrease in production of 59MBOE or $3.6 million, which was partially offset by an increase in the average realized price for oil and natural gas $2.2 million.

The above table compares both volumes and prices received for oil and natural gas for the years ended December 31, 2007 and 2006. Oil prices are and probably will continue to be extremely volatile and a significant change will have a material impact on our revenue.

Costs and expenses

Lease operating

Lease operating expense was $7.3 million, or $19.17 per BOE produced for the year ended December 31, 2007, as compared to $7.2 million, or $16.36 per BOE produced for the year ended 2006. This increase in the cost per BOE produced is primarily due to the decline in production.

Exploration expense

Exploration expense for the year ended December 31, 2007 was $3.5 million, as compared to $2.3 million for the comparable period in 2006. This change is primarily due increased staff in the Dallas office during 2007.

Dry hole and abandonment

Dry hole and abandonment cost for the year ended December 31, 2007 was $3.8 million, as compared to zero in 2006. During 2007 we drilled two dry holes in France costing $3.8 million.

Depreciation, depletion and amortization.

For the year ended December 31, 2007, depreciation, depletion and amortization expense was $4.4 million, or $11.48 per BOE produced, as compared to $3.4 million, or $7.69 per BOE produced for the twelve months ended December 31, 2006. This increase is primarily due to the decline in the value of the U. S. Dollar

General and administrative

General and administrative expense, not including stock compensation expense and amounts due the former President and CEO, was $7.4 million for the year ended December 31, 2007, compared with $4.9 million for the comparable period of 2006. This increase is primarily due to $2.6 million for restating the financial statements for the years ended December 31, 2003, 2004 and 2005 and the quarters ended March 31, 2006 and June 30, 2006, (accounting, legal and printing).

Stock compensation expense

Stock compensation expense was $2.9 million for the twelve months ended December 31, 2007, compared with $2.7 million for the comparable period of 2006. The increase is due to the restricted stock granted by the Board of Directors to certain employees, consultants and non-employee directors and the expensing of stock options as required by the adoption of SFAS 123 (R).

Cost incurred related to the resignation of former President and Chief Executive Officer

Loss on oil and gas derivative contracts

Loss on oil and gas derivative contracts represents the net realized loss on derivative financial instruments and fluctuates based on changes in the fair value of underlying commodities. We entered into futures and swap contracts for approximately 15,000 Bbls per month for the months of June 2007 through December 2008 and subsequently sold all contracts as of September 30, 2007. This resulted in a net derivative fair value loss of $1 million for the twelve months ended December 31, 2007. We were not a party to any derivative contracts in the comparable period of 2006.

Gain on the sale of properties and other assets

For the twelve months ended December 31, 2007, we recorded a gain on the sale of the properties and other assets of $3.2 million, which was primarily attributable to the gain on the sale of our unconsolidated investments.

Foreign currency exchange gain (loss)

We recorded a loss on foreign currency exchange of $321,000 for the twelve months ended December 31, 2007 compared with $1.4 million gain for the comparable period of 2006. This decrease is primarily due to currency hedges in effect in 2006.

Interest and other income

Interest and other income was $1.4 million for the period ended December 31, 2007 as compared with $2.2 million in the comparable period of 2006. For the twelve months ended December 31, 2006, our average cash balance was larger than our average cash balance for the twelve months ended December 31, 2007, which resulted in less interest income in the current period.

Interest expense, net of interest capitalization

Interest expense was $3.5 million for the twelve months ended December 31, 2007, as compared to $660,000 for the comparable period of 2006. The increase in interest expense is primarily due expensing the deferred loan fees on the Natixis facility and the Texas Capital Bank facility since these facilities were paid off in the first quarter of 2007

and the increased debt level for the twelve months ended December 31, 2007 as compared to the comparable period in 2006.

Provision for income taxes

For the year ended December 31, 2007 we reported an income tax benefit of $1.4 million, compared to a provision of $3.2 million for the same period of 2006. The decrease is primarily due to a higher taxable income in France in 2006 when compared to 2007.

Income (Loss) available to common shares

For the twelve months ended December 31, 2007 we recorded a loss available to common shares of $74.6 million versus income available to common shares of $2.4 million for the year ended December 31, 2006.

Other comprehensive income (loss)

The most significant element of comprehensive income, other than net income, is foreign currency translation. As of December 31, 2007, we had an unrealized gain of $38.4 million as compared to an unrealized gain of $6.7 million in 2006. The reason for the increase in the unrealized gain is due to the weakening of the United States dollar compared to the currencies in countries in which we operate. The functional currency of our operations in France is the Euro and in Romania, Turkey and Hungary the functional currency is the United States Dollar. The exchange rates used to translate the financial position of the French, Turkish, Romanian and Hungarian operations at December 31, 2007, 2006 and 2005 are shown below:

	December 31,
	2007		2006
Euro	$	1.4721	$	1.3170

New Turkish Lira	$	0.8574	$	0.7065

Romania Lei	$	0.4076	$	0.3886

Hungarian Forint	$	0.0058	$	0.0052

Results of discontinued operations

On June 14, 2007, the Board of Directors authorized management to sell all our oil and natural gas properties in the United States. The sale of these properties completed the divestiture of the company’s non-core domestic assets and allowed us to focus exclusively on our international operations. The sale was closed on September 1, 2007. The sales price was $19.1 million which resulted in a pre-tax gain of $9.2 million.

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

	Twelve Months Ended December 31.
	2007			2006
	(In thousands)
Revenues:
Oil and natural gas sales	$	20,273		$	13,104
Costs and expenses:
Lease operating	6,892			3,712
Exploration expense	11,324			1,631
Impairment of oil and natural gas properties	13,446			345
Depreciation, depletion and amortization	17,466			4,161
Dry hole costs	18,096			3,099
Allocated general and administrative	5,131			2,204
Gain on sale of properties	(9,248		)	(638		)
Total costs and expenses	(63,107		)	14,514
Operating income (loss)	(42,834		)	(1,410		)
Other income (expense)	(26,361		)	(2,480		)
Income before taxes	(69,195		)	(3,890		)
Income tax provision	(678		)	(411		)
Income from discontinued operations	$	(69,873	)	$	(4,301	)

Comparison of Years Ended December 31, 2007 and 2006

	For the Years Ended December 31,
	2007		2006
Production:
Oil (MBbls):
United States	38		58
Turkey	66		68
Romania	10		8
Total	114		134
Gas (MMcf):
United States	295		490
Turkey	905		—
Romania	689		502
Total	1,889		992
MBOE:
United States	87		140
Turkey	217		68
Romania	124		92
Total	428		300
Average Price:
Oil ($/Bbl):
United States	$	60.14	$	61.29
Turkey	61.98		56.10
Romania	57.59		52.71
Total average oil price	60.99		58.16
Gas ($/Mcf):
United States	$	6.67	$	6.38
Turkey	8.60		—
Romania	4.90		3.57
Total average gas price	6.92		4.96
$/ BOE:
United States	$	48.25	$	47.88
Turkey	54.77		56.10
Romania	31.55		24.06
Total average price per BOE	46.69		42.49

Revenues

Oil and natural gas sales

Oil and natural gas sales for the year ended December 31, 2007 were $20.2 million, as compared to $13.1 million for the comparable period in 2006. This increase is due to 1) the increase in the average realized price for oil and natural gas, $500,000 and 2) Turkish gas sales which were not in production in 2006, $7.8 million. This was partially offset by a reduction in total oil production of 20 MBbls or $1.2 million. Production increased by approximately 128 MBOE due primarily to the start of gas production in Turkey gas resulting in 151 MBOE and a full year of gas production in Romania resulting in an additional 33 MBOE.

Costs and expenses

Lease operating

Lease operating expense was $6.9 million, or $16.12 per BOE produced for the year ended December 31, 2007, as compared to $3.7 million, or $12.33 per BOE produced for the year ended 2006. This increase is primarily due to increased operating costs in offshore Turkey due primarily to the fact that fixed operating costs is for three tripods

while only two were on production, increased operating expense in Romania due to increased workover cost incurred to increase production.

Exploration expense

Exploration expense for the year ended December 31, 2007 was $11.3 million, as compared to $1.6 million for the comparable period in 2006. This change is primarily due to the 2D seismic survey that was done in Romania during the third quarter and increased interpretation of existing seismic in order to prepare prospects for farmout consideration.

Dry hole and abandonment

Dry hole and abandonment cost for the year ended December 31, 2007 was $18.1 million, as compared to $3.1 million in 2006. During 2007 we drilled three dry holes in Romania costing $10 million, two dry holes in Hungary costing $3.5 million and one dry hole in Turkey costing $4.5 million. In the comparable period for 2006 we drilled one dry hole in Hungary for $1.7 million and one in the United States for $1.4 million.

Depreciation, depletion and amortization.

For the year ended December 31, 2007, depreciation, depletion and amortization expense was $17.5 million, or $40.89 per BOE produced, as compared to $4.2 million, or $14.00 per BOE produced for the twelve months ended December 31, 2006. This increase is primarily due to offshore Turkey starting production in May 2007 resulting in an additional $9.4 million in depreciation, depletion and amortization, an increase in Romania of $4.6 million due to a full year of production and a decline in proved reserves. This was partially offset by 9 months of depreciation, depletion and amortization on United States properties in 2007, as compared to a full year in 2006 $700,000.

Impairment of oil and natural gas properties

Impairment charged in 2007 was $13.4 million compared to $345,000 in 2006. This increase was due to the downward revisions of proved reserves in the Fauresti Field in Romania. At December 31, 2007 the cash flow before income tax and the discounted future cash flows attributable to our proved oil and natural gas reserves before income tax, discounted at 10% attributable to the 134 MBOE, in Romania, was $1.2 million and $1.1 million, respectively, and the net book value of asset was $14.5 million. This resulted in an impairment charge of $13.4 million.

General and administrative

General and administrative expense was $5.1 million for the year ended December 31, 2007, compared with $2.2 million for the comparable period of 2006. This increase is primarily due to increased staff in 2007 compared to 2006.

Gain on the sale of properties and other assets

For the twelve months ended December 31, 2007, we recorded a gain on the sale of the properties and other assets of $9.2 million, which was primarily attributable to the gain on the sale of working interests properties in the United States. A gain of $638,000 was recorded in the comparable period of 2006.

Other expense

We recorded a loss on foreign currency exchange of $26 million for the twelve months ended December 31, 2007 compared with a $2 million loss for the comparable period of 2006. This loss is primarily due to the weakening of the U. S. Dollar as compared to the New Turkish Lira, Romanian Lei and the Hungarian Forint. In these countries the U. S. Dollar is the functional currency and foreign exchange translation gains and losses are charged to earnings.

Selected Quarterly Financial Data (Unaudited)

We derived the selected historical financial data in the table below from our unaudited interim consolidated financial statements. The sum of net income per share by quarter may not equal the net income per share for the year due to variations in the weighted average shares outstanding used in computing such amounts. The historical data

presented here is only a summary and should be read in conjunction with the consolidated financial statements, related notes and other financial information included elsewhere in this annual report.

	Three Months Ended
	March 31,			June 30,			September 30,			December 31,
	(in thousands, except per share data)

For the year ended December 31, 2008:
Total revenues	$	8,850		$	10,987		$	9,641		$	4,672
Total costs and expenses	9,488			18,032			5,844			7,806
Income (loss) from continuing operations, net of tax	(638		)	(7,045		)	3,797			(3,134		)
Income (loss) from discontinued operations, net of tax	(3,788		)	(58,723		)	(3,727		)	(35,347		)
Net income (loss)	(4,426		)	(65,768		)	70			(38,481		)
Income (loss) available to common shares	(4,426		)	(65,768		)	70			(38,481		)
Basic income (loss) available to common shares per share	(0.22		)	(3.33		)	—			(1.93		)
Diluted income (loss) available to common shares per share	(0.22		)	(3.33		)	—			(1.93		)

For the year ended December 31, 2007 :
Total revenues	$	5,134		$	6,192		$	6,724		$	7,857
Total costs and expenses	6,241			5,015			9,457			9,742
Income (loss) from continuing operations, net of tax	(1,107		)	1,177			(2,733		)	(1,885		)
Income (loss) from discontinued operations, net of tax	(7,668		)	(26,224		)	(18,007		)	(17,974		)
Net income (loss)	(8,775		)	(25,047		)	(20,740		)	(19,859		)
Income available to common shares	(8,816		)	(25,087		)	(20,780		)	(19,900		)
Basic income available to common shares per share	(0.55		)	(1.32		)	(1.09		)	(1.05		)
Diluted income available to common shares per share	(0.55		)	(1.32		)	(1.09		)	(1.05		)

Impairment

In the fourth quarter of 2008 we incurred an impairment of approximately $29.4 million. Included in the impairment charge was an impairment on our assets held for sale of $25.6 million which was a result of a revision to the purchase price of $55 million. In Turkey, we incurred an additional $2.4 million impairment charge on assets unrelated to the sale. This is a result of an exploratory well that was charged to expense due to the operator not making sufficient progress to develop the well and not having a plan for development in the foreseeable future. We also recorded an impairment of $833,000 for goodwill associated with our Turkish oil and natural gas properties. In Romania we recorded an impairment of $600,000, which was a result of the net book value of the oil and natural gas properties exceeding the future cash flows.

Item 8. Financial Statements

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firm	F-2

Financial Statements

Consolidated Balance Sheets as of December 31, 2008 and 2007	F-3

Consolidated Statements of Operations and Comprehensive Income (Loss) for each of the three years in the period ended December 31, 2008	F-4

Consolidated Statements of Changes in Stockholders’ Equity for each of the three years in the period ended December 31, 2008	F-5

Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 2008	F-6

Notes to Consolidated Financial Statements	F-7

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders

Toreador Resources Corporation

We have audited the accompanying consolidated balance sheets of Toreador Resources Corporation (a Delaware corporation) and subsidiaries (the ‘Company”) as of December 31, 2008 and 2007, and the related consolidated statements of operations and comprehensive income (loss), changes in stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2008. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Toreador Resources Corporation and subsidiaries as of December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated March 16, 2009 not separately included herein expressed an unqualified opinion.

	/s/ Grant Thornton LLP

Houston, Texas

March 16, 2009

(except for Note 14, as to which the date is November 12, 2009)

F-2

TOREADOR RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS

(in thousands, except share and per share data)

	December 31,
	2008			2007

ASSETS
Current assets:
Cash and cash equivalents	$	14,860		$	8,404
Accounts receivable	1,058			3,084
Oil and natural gas properties, net, held for sale	91,959			190,968
Other assets held for sale	14,963			18,216
Other	3,713			3,848
Total current assets	126,553			224,520

Oil and natural gas properties, net, using successful efforts method of accounting	72,753			80,983
Investments	200			500
Restricted Cash	—			8,685
Goodwill	3,838			4,059
Other assets	3,812			4,364
	$	207,156		$	323,111
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	7,700		$	6,629
Liabilities held for sale	11,251			13,251
Deferred lease payable	93			183
Fair value of oil and gas derivatives	—			192
Current portion of long-term debt	30,000			—
Income taxes payable	4,223			674
Total current liabilities	53,267			20,929

Accrued liabilities	501			522
Deferred lease payable	665			478
Long-term debt, net of current portion	—			30,000
Asset retirement obligations	6,037			5,106
Deferred income tax liabilities	13,851			16,001
Convertible subordinated notes	80,275			86,250
Total liabilities	154,596			159,286
Commitments and contingencies (Note 12)
Stockholders’ equity:
Common stock, $0.15625 par value, 30,000,000 shares authorized; 20,984,360 and 20,566,470 shares issued	3,279			3,214
Additional paid-in capital	166,484			163,955
Accumulated deficit	(151,169		)	(42,564		)
Accumulated other comprehensive income	36,500			41,754
Treasury stock at cost, 721,027 shares	(2,534		)	(2,534		)
Total stockholders’ equity	52,560			163,825
	$	207,156		$	323,111

See accompanying notes to the consolidated financial statements

F-3

TOREADOR RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)

(in thousands, except per share data)

	Year ended December 31,
	2008			2007			2006

Revenue:
Oil and natural gas sales	$	34,150		$	25,907		$	27,294

Operating costs and expenses:
Lease operating expense	9,263			7,344			7,229
Exploration expense	1,224			3,523			2,315
Dry hole and abandonment	—			3,847			—
Depreciation, depletion and amortization	4,994			4,402			3,383
Impairment of oil and natural gas properties and intangible assets	2,282			—			—
General and administrative	13,042			12,507			7,625
Loss on oil derivative contracts	1,781			1,005			—
Gain on sale of properties and other assets	—			(3,155		)	—
Total operating costs and expenses	32,586			29,473			20,552
Operating income (loss)	1,564			(3,566		)	6,742
Other income (expense):
Equity in earnings of unconsolidated investments	—			22			401
Foreign currency exchange (loss) gain	(145		)	(321		)	1,415
Interest and other income	775			1,384			2,217
Gain on the extinguishment of debt	458			—			—
Interest expense	(4,170		)	(3,469		)	(660		)
Total other income (expense)	(3,082		)	(2,384		)	3,373

Income (loss) from continuing operations before income taxes	(1,518		)	(5,950		)	10,115
Income tax benefit (provision)	(5,502		)	1,402			(3,236		)
Income (loss) from continuing operations, net of tax	(7,020		)	(4,548		)	6,879
Loss from discontinued operations, net of tax	(101,585		)	(69,873		)	(4,301		)
Net income (loss)	(108,605		)	(74,421		)	2,578
Preferred dividends	—			(162		)	(162		)
Income (Loss) available to common shares	$	(108,605	)	$	(74,583	)	$	2,416
Basic income (loss) available to common shares per share from:
Continuing operations	$	(0.35	)	$	(0.26	)	$	0.44
Discontinued operations	(5.13		)	(3.81		)	(0.28		)
	$	(5.48	)	$	(4.07	)	$	0.16
Diluted income (loss) available to common shares per share from:
Continuing operations	$	(0.35	)	$	(0.26	)	$	0.42
Discontinued operations	(5.13		)	(3.81		)	(0.27		)
	$	(5.48	)	$	(4.07	)	$	0.15
Weighted average shares outstanding:
Basic	19,831			18,358			15,527
Diluted	19,831			18,358			15,884
Statement of Comprehensive Income (Loss)
Net income (loss)	$	(108,605	)	$	(74,421	)	$	2,578
Foreign currency translation adjustments	(5,254		)	38,431			6,687
Comprehensive income (loss)	$	(113,859	)	$	(35,990	)	$	9,265

See accompanying notes to the consolidated financial statements.

F-4

TOREADOR RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

(in thousands)

	Preferred Stock (Shares)		Preferred Stock ($)		Common Stock (Shares)	Common Stock ($)		Additional Paid-in Capital			Retained Earnings			Accumulated Other Comprehensive Income (loss)			Treasury Stock ($)			Deferred Compensation			Total Stockholders’ Equity
Balance at December 31, 2005	72		72		16,143	2,522		108,001			29,564			(3,364		)	(2,534		)	(1,902		)	132,359
Transfer deferred compensation to additional paid-in capital	—		—		—	—		(1,902		)	—			—			—			1,902			—
Cash payment of preferred dividends	—		—		—	—		—			(162		)	—			—			—			(162		)
Conversion of convertible debenture	—		—		120	19		791			—			—			—			—			810
Exercise of stock options	—		—		175	27		839			—			—			—			—			866
Issuance of restricted stock	—		—		214	33		(33		)	—			—			—			—			—
Exercise of warrants	—		—		4	1		33			—			—			—			—			34
Issuance of warrants	—		—		—	—		883			—			—			—			—			883
Tax benefit of stock option exercises	—		—		—	—		293			—			—			—			—			293
Stock option expense	—		—		—	—		66			—			—			—			—			66
Amortization of deferred stock compensation	—		—		—	—		2,737			—			—			—			—			2,737
Net income	—		—		—	—		—			2,578			—			—			—			2,578
Foreign currency translation adjustment	—		—		—	—		—			—			6,687			—			—			6,687
Balance at December 31, 2006	72		72		16,656	2,602		111,708			31,980			3,323			(2,534		)	—			147,151
Cash payment of preferred dividends	—		—		—	—					(162		)	—			—			—			(162		)
Exercise of stock options	—		—		321	50		1,574			—			—			—			—			1,624
Issuance of restricted stock	—		—		103	16		(16		)	—			—			—			—			—
Issuance of common stock	—		—		3,037	476		49,937			—			—			—			—			50,413
Stock option expense	—		—		—	—		49			—			—			—			—			49
Amortization of deferred stock compensation expense	—		—		—	—		3,982			—			—			—			—			3,982
Adoption of FIN 48	—		—		—	—		—			(45		)	—			—			—			(45		)
Conversion of preferred stock to common stock	(72	)	(72	)	450	70		2			—			—			—			—			—
Net loss	—		—		—	—		—			(74,421		)	—			—			—			(74,421		)
Foreign currency translation adjustments	—		—		—	—		—			—			38,431			—			—			38,431
Tax effect of restricted stock	—		—		—	—		(316		)	—			—			—			—			(316		)
Payment of equity issuance costs	—		—		—	—		(2,965		)	—			—			—			—			(2,965		)
Other	—		—		—	—		—			84			—			—			—			84
Balance at December 31, 2007	—		—		20,567	$	3,214	$	163,955		$	(42,564	)	$	41,754		$	(2,534	)	$	—		$	163,825
Exercise of stock options	—		—		189	29		716			—			—			—			—			745
Issuance of restricted stock	—		—		228	36		(36		)	—			—			—			—			—
Stock option expense	—		—		—	—		94			—			—			—			—			94
Amortization of deferred stock compensation	—		—		—	—		2,231			—			—			—			—			2,231
Net loss	—		—		—	—		—			(108,605		)	—			—			—			(108,605		)
Foreign currency translation adjustments	—		—		—	—		—			—			(5,254		)	—			—			(5,254		)
Tax effect of restricted stock	—		—		—	—		(444		)	—			—			—			—			(444		)
Other	—		—		—	—		(32		)	—			—			—			—			(32		)
Balance at December 31, 2008	—		—		20,984	$	3,279	$	166,484		$	(151,169	)	$	36,500		$	(2,534	)	$	—		$	52,560

See accompanying notes to the consolidated financial statements.

F-5

TOREADOR RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Year Ended December 31
	2008			2007			2006

Cash flows from operating activities:
Net Income (loss)	$	(108,605	)	$	(74,421	)	$	2,578
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Depreciation and amortization	33,141			21,868			7,544
Amortization of deferred debt issuance costs	338			612			—
Issuance of warrants to non-employees	—			—			107
Impairment of oil and natural gas properties and intangible assets	85,233			13,446			345
Dry hole and abandonment costs	—			21,840			3,099
Deferred income taxes	—			(3,425		)	2,642
Unrealized loss on commodity derivatives	—			192			—
Loss (gain) on sale of properties and equipment	123			343			(638		)
Gain on the sale of discontinued operations	—			(9,244		)	—
Gain on the extinguishment of debt	(458		)	—			—
Equity in earnings of unconsolidated investments	—			(22		)	(401		)
Stock-based compensation	2,325			4,031			2,803
Gain on sale of unconsolidated investments	—			(3,502		)	—
Change in operating assets and liabilities, net of acquisitions
Decrease in accounts receivable	2,027			1,020			2,109
Decrease (increase) in income taxes receivable	—			715			(655		)
Decrease (increase) in other current assets	135			(130		)	(3,674		)
Decrease (increase) in assets held for sale	2,077			13,539			(17,776		)
Increase (decrease) in accounts payable and accrued liabilities	858			(1,826		)	(1,885		)
Increase (decrease) in lease payable	(19		)	661			—
Decrease (increase) in other assets	108			1,466			(264		)
Increase in income taxes payable	956			439			3,625
Increase (decrease) in liabilities held for sale	(1,473		)	(36		)	563
Net cash provided by (used in) operating activities	16,766			(12,434		)	122
Cash flows from investing activities:
Expenditures for property and equipment	(10,702		)	(90,644		)	(105,165		)
Restricted cash	8,685			1,243			(8,977		)
Proceeds from the sale of properties and equipment	—			21,002			1,672
Distributions from unconsolidated entities	—			60			250
Sale (purchase) of short-term investments	—			(500		)	40,000
Sale (purchase) of investments in unconsolidated entities	—			6,123			(257		)
Net cash used in investing activities	(2,017		)	(62,716		)	(72,477		)
Cash flows from financing activities:
Repayment of revolving credit facilities	—			—			(5,000		)
Net borrowings under revolving credit arrangements	—			3,450			26,550
Exercise of stock options	745			1,624			866
Proceeds from the exercise of warrants	—			—			33
Proceeds from issuance of common stock, net of issuance cost of $32, $2,965, and $0	(32		)	47,448			—
Tax benefit related to stock options	—			—			293
Payments of long term debt	(5,275		)	—			—
Payment of preferred dividends	—			(162		)	(162		)
Net cash provided by (used in) financing activities	(4,562		)	52,360			22,580
Net increase (decrease) in cash and cash equivalents	10,187			(22,790		)	(49,775		)
Effects of foreign currency translation on cash and cash equivalents	(3,731		)	26,806			6,870
Cash and cash equivalents, beginning of year	8,404			4,388			47,293
Cash and cash equivalents, end of year	$	14,860		$	8,404		$	4,388
Supplemental disclosures:
Cash paid during the period for interest, net of interest capitalized	$	5,626		$	2,927		$	—
Cash paid during the period for income taxes	$	3,058		$	2,761		$	2,414
Non-cash investing and financing activities
Conversion of preferred stock to common stock	—			72			—
Conversion of convertible debentures to common stock	—			—			810
Additions to oil and natural gas properties related to asset retirement obligations	1,294			1,964			882

F-6

TOREADOR RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 — DESCRIPTION OF BUSINESS

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

BASIS OF PRESENTATION

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

NOTE 2 — SIGNIFICANT ACCOUNTING POLICIES

USE OF ESTIMATES

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

The Company’s estimates of crude oil and natural gas reserves are the most significant estimates used. All of the reserve data in the Annual Report on Form 10-K for the year ended December 31, 2008 are estimates. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. The accuracy of any reserve estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may be different from the quantities of crude oil and natural gas that are ultimately recovered.

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

CASH AND CASH EQUIVALENTS AND SHORT-TERM INVESTMENTS

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

As of December 31, 2008 and 2007 we had $12.2 million and $6.4 million, respectively, on deposit in foreign banks.

CONCENTRATION OF CREDIT RISK AND ACCOUNTS RECEIVABLE

Financial instruments that potentially subject us to a concentration of credit risk consist principally of cash, accounts receivable, and our hedging and derivative financial instruments. We place our cash with high credit quality financial institutions. We sell oil and natural gas to various customers. Substantially all of our accounts receivable are due from purchasers of our oil production. We place our hedging and derivative financial instruments with financial institutions and other firms that we believe have high credit

F-7

ratings. For a discussion of the credit risks associated with our hedging activities, please see “Derivative Financial Instruments” below.

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

FINANCIAL INSTRUMENTS

The carrying amounts of financial instruments including cash and cash equivalents, short-term investments, accounts receivable, accounts payable and accrued liabilities approximate fair value, at December 31, 2008 and 2007, due to the short-term nature or maturity of the instruments.

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

On December 31, 2008 the convertible subordinate notes which had a book value of $80.28 million, were trading at $770.00, which would equal a fair market value of approximately $61.8 million.

DERIVATIVE FINANCIAL INSTRUMENTS

We periodically utilize derivatives instruments such as futures and swaps for purposes of hedging our exposure to fluctuations in the price of crude oil and natural gas sales. We entered into futures and swap contracts for approximately 16,000 Bbls per month for the months of January 2008 through September 2008. This resulted in a fair value loss of $1.8 million. For the comparable period in 2007, we entered into futures and swap contracts for approximately 15,000 Bbls per month for the months of June 2007 through December 2008 and subsequently sold all contracts as of September 30, 2007 which resulted in a net loss of $813,000. As of December 31, 2008 we had no open commodity derivative contracts.

At December 31, 2007 we had the following open commodity contract with Total Oil Trading SA:

Type	Period	Barrels	Floor		Ceiling

Collar	January 1 - March 31, 2008	48,000	$	84.75	$	92.75

As of December 31, 2007, we recorded a net unrealized loss of $192,000 on the above open derivative contract. For the year ended December 31, 2007 we recognized a total derivative fair value loss of $1 million.

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

INVENTORIES

At December 31, 2008 and 2007, other current assets included $727,000, and $2.5 million of inventory, respectively. Those amounts consist of tubular goods and crude oil held in storage tanks. Inventories are stated at the lower of actual cost or market based on the average cost method.

OIL AND NATURAL GAS PROPERTIES

We follow the successful efforts method of accounting for oil and natural gas exploration and development expenditures. Under this method, costs of successful exploratory wells and all development wells are capitalized. Costs to drill exploratory wells that do not find proved reserves are expensed.

F-8

Significant costs associated with the acquisition of oil and natural gas properties are capitalized. Upon sale or abandonment of units of property or the disposition of miscellaneous equipment, the cost is removed from the asset account, net of the accumulated depreciation or depletion, and the gain or loss is credited to or charged against operations.

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

We capitalize interest on major projects that require an extended period of time to complete. Interest capitalized in 2008, 2007 and 2006 was $1 million, $3.7 million, and $4.3 million, respectively.

We record furniture, fixtures and equipment at cost.

OIL AND NATURAL GAS PROPERTIES HELD FOR SALE

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

The net book balances of oil and gas properties has been reclassified to oil and natural gas properties held for sale. The table below reflects the amount that was transferred to oil and gas properties held for resale:

For the Year Ended	Turkey		Hungary		Romania		Total

December 31, 2008	$	74,740	$	17,219	$	—	$	91,959
December 31, 2007	$	173,502	$	15,592	$	1,874	$	190,968

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

	December 31
	2008			2007
	(in thousands)

Capitalized exploratory well cost, beginning of the year	$	17,109		$	5,256
Additions to capitalized exploratory costs pending determination of proved reserves	377			17,109
Reclassified to dry hole costs	—			(5,256		)
Reclassified to assets held for sale	(12,728		)	—
Impairments	(2,441		)	—
Capitalized exploratory well costs, end of year	$	2,317		$	17,109

F-9

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

	December 31
	2008		2007
	(in thousands)

Capitalized exploratory well cost that have been capitalized for a period of one year or less	$	—	$	17,109
Capitalized exploratory well costs that have been capitalized for a period greater than one year	2,317		—
Balance at end of year	$	2,317	$	17,109

DEPRECIATION, DEPLETION AND AMORTIZATION

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

IMPAIRMENT OF ASSETS

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

Impairment charged in 2008 for continuing operations was $2.3 million compared to zero in 2007. The impairment was a result of the following:

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

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

Impairment charged in 2008 for discontinued operations was $82.9 million compared to $13.4 million in 2007. The impairment was a result of the following:

F-10

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

ASSET RETIREMENT OBLIGATIONS

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

The following table summarizes the changes in our asset retirement liability during the years ended December 31, 2008 and 2007:

	2008			2007
	(in thousands)

Asset retirement obligation January 1	$	5,106		$	3,338
Asset retirement accretion expense	357			378
Foreign currency exchange (gain) loss	(279		)	394
Change in estimates	1,213			996
Property dispositions	(360		)	—
Asset retirement obligation at December 31	$	6,037		$	5,106

GOODWILL

We account for goodwill in accordance with Statement of Financial Accounting Standard No. 142, “Goodwill and Other Intangible Assets” (“Statement 142”). Under Statement 142, goodwill and indefinite-lived intangible assets are not amortized but are reviewed annually (or more frequently if impairment indicators arise) for impairment. Separable intangible assets that are not deemed to have an indefinite life are amortized over their useful lives. At December 31, 2008 and 2007 we did not have any intangible assets that did not have an indefinite life.

We review annually the value of goodwill recorded or more frequently if impairment indicators arise. We recognized $883,000, $0 and $0 goodwill impairment during 2008, 2007 and 2006 respectively, which was classified as discontinued operations The impairment of goodwill was due to the fair value of the Turkish subsidiary, based on the discounted present value of the oil and gas reserves being less than the carrying value of the Turkish subsidiary. Goodwill was adjusted $222,000 in 2008 and $391,000 in 2007 for the foreign currency translation adjustment. The balance of goodwill at December 31, 2008 and 2007 is approximately $3.8 million and $4.1 million, respectively.

F-11

REVENUE RECOGNITION

Our French crude oil production accounts for the majority of our sales. We sell our French crude oil to Elf Antar France S.A. (“ELF”), and recognize the related revenues when the production is delivered to ELF’s refinery, typically via truck. At the time of delivery to the plant, title to the crude oil transfers to ELF. The terms of the contract with ELF state that the price received for oil sold will be the arithmetic mean of all average daily quotations of Dated Brent published in Platt’s Oil Market Wire for the month of production less a specified differential per barrel. The pricing of oil sales is done on the first day of the month following the month of production. In accordance with the terms of the contract, payment is made within six working days of the date of issue of the invoice. The contract with ELF is automatically extended for a period of one year unless either party cancels it in writing no later than six months prior to the beginning of the next year. We periodically review ELF’s payment timing to ensure that receivables from ELF for crude oil sales are collectible. In 2008, 2007 and 2006 sales to ELF represents approximately 100% of the Company’s total revenue and approximately 71% and 87% of the Company’s accounts receivable at December 31, 2008 and 2007, respectively.

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

STOCK-BASED COMPENSATION

In December 2004, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 123 (revised 2004), “Share Based Payment,” (“SFAS 123R”). SFAS 123R establishes the accounting for transactions in which an entity pays for employee services in share-based payment transactions. SFAS 123R requires companies to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. The fair value of employee share options and similar instruments is estimated using option-pricing models adjusted for the unique characteristics of those instruments. That cost is recognized over the period during which an employee is required to provide service in exchange for the award. The Company adopted SFAS 123R effective January 1, 2006, using the modified-prospective transition method. Under this method, compensation cost is recognized for awards granted and for awards modified, repurchased or cancelled in the period after adoption. Compensation cost is also recognized for the unvested portion of awards granted prior to adoption. The Company’s results for the year ended December 31, 2006, include an additional compensation expense of $65,916, that is included in general and administrative expenses relating to the adoption of SFAS 123R. Additionally, upon adoption of SFAS 123R, excess tax benefits related to stock option exercises of $293,000 were presented as a cash inflow from financing activities.

FOREIGN CURRENCY TRANSLATION

The functional currency of the countries in which we operate is the U.S. dollar in the United States, Turkey, Romania and Hungary and the Euro in France. Gains and losses resulting from the translation of Euros into U.S. dollars are included in other comprehensive income for the current period. Gains and losses resulting from the transactions in the New Turkish Lira in Turkey, the Lei in Romania and the Forint in Hungary are included in income available to common shares for the current period. We periodically review the operations of our entities to ensure the functional currency of each entity is the currency of the primary economic environment in which we operate. In October 2007, we made a change in accounting method regarding intercompany accounts receivable due from our subsidiaries in Turkey, Romania and Hungary. Pursuant to a Board of Directors’ resolution, we expect to be repaid the intercompany accounts receivable from our subsidiaries in Turkey, Romania and Hungary in the foreseeable future. Due to this resolution,

F-12

subsequent to October 1, 2007, the change in intercompany accounts receivable balances is reflected in current earnings, as a foreign exchange gain or loss rather than accumulated other comprehensive income.

INCOME TAXES

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

Effective January 1, 2007, we adopted the provisions of FASB Interpretation (FIN) No. 48, Accounting for Uncertainty in Income Taxes — An Interpretation of FASB Statement No. 109 (FIN No. 48”). FIN No. 48 clarifies financial statement recognition and disclosure requirements for uncertain tax positions taken or expected to be taken in a tax return. Financial statement recognition of the tax position will be sustained upon examination, based on the technical merits of the position. Any interest and penalties related to uncertain tax positions are recorded as interest expense and general and administrative expenses, respectively. The adoption of FIN No. 48 did not have a significant effect on our reported financial position or earnings. See Note 9.

LEGAL FEES

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

DEFERRED DEBT ISSUE COST

Deferred debt issue costs are amortized on a straight line basis, which approximates the effective interest method over the term of the loan as a component of interest expense. Deferred debt issue costs, which are included in other assets, totaled approximately $3,183,000 and $3,625,000 net of accumulated amortization of $608,000 and $409,000 as of December 31, 2008 and 2007, respectively.

NEW ACCOUNTING PRONOUNCEMENTS

In September 2006, the FASB issued Statement No. 157 “Fair Value Measurements” (“SFAS No. 157”). SFAS No. 157 provides guidance for using fair value to measure assets and liabilities. It applies whenever other standards require or permit assets or liabilities to be measured at fair value but it does not expand the use of fair value in any new circumstances. In November 2007, the FASB issued FSP No. 157-2 (FASB No. 157-2”) to defer the effective date of SFAS 157 to fiscal year beginning after November 15, 2008, and the interim period for that fiscal year for all non-financial assets and liabilities, except those that are recognized or disclosed at fair value on a recurring basis. We are currently evaluating the impact of our adoption of FSP No. 157-2 which will be adopted effective January 1, 2009. The provisions of SFAS No. 157 that were not deferred were effective for financial statements issued for fiscal years beginning after November 15, 2007. The adoption of SFAS No. 157, effective January 1, 2008, did not have a significant effect on our reported financial position or earnings. In October 2008, the FASB issued FSP No. 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset is Not Active” (FSP 157-3). FSP 157-3 clarifies the application of SFAS 157, which the Company adopted as of January 1, 2008, in cases where a market is not active. The Company has considered FSP 157-3 in its determination of estimated fair values as of December 31, 2008, and the impact was not material.

F-13

F-14

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

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

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

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

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

We are currently evaluating the potential impact of adopting the Final Reporting Rule. The SEC is discussing the Final Reporting Rule with the FASB staff to align FASB accounting standards with the new SEC rules. These discussions may delay the required compliance date. Absent any change in the effective date, we will comply with the disclosure requirements in our annual report on Form 10-K for the year ended December 31, 2009.

In November 2008, the FASB ratified EITF 08-6, “Equity Method Investment Accounting Considerations” (EITF08-6”) which clarifies how to account for certain transactions involving equity method investments. The initial measurement, decreases in value and changes in the level of ownership of the equity method investment are addressed. EITF 08-6 is effective on a prospective basis for our fiscal year beginning January 1, 2009 and interim periods within the years. Early application by an entity that has previously adopted an alternative accounting policy is not permitted. Adoption is not expected to have a significant impact on our consolidated results of operations or cash flows.

NOTE 3 — EARNINGS PER SHARE

In accordance with the provisions of FASB Statement of Financial Accounting Standards No. 128, “Earnings per Share” (“Statement 128”), basic earnings per share are computed on the basis of the weighted-average number of common shares outstanding during the periods. Diluted earnings per share are

F-15

computed based upon the weighted-average number of common shares plus the assumed issuance of common shares for all potentially dilutive securities.

	Year ended December 31,
	2008			2007			2006
	(in thousands, except per share data)
Basic earnings (loss) per share:
Numerator
Income (loss) from continuing operations, net of income tax	$	(7,020	)	$	(4,548	)	$	6,879
Less: dividends on preferred shares	—			162			162
Income (loss) from continuing operations, net of tax	(7,020		)	(4,710		)	6,717
Loss from discontinued operations, net of tax	(101,585		)	(69,873		)	(4,301		)
Income (loss) available to common shares	$	(108,605	)	$	(74,583	)	$	2,416
Denominator
Common shares outstanding	19,831			18,358			15,527
Basic earnings (loss) available to common shares per share from:
Continuing operations	$	(0.35	)	$	(0.26	)	$	0.44
Discontinued operations	(5.13		)	(3.81		)	(0.28		)
Basic income (loss) per share	$	(5.48	)	$	(4.07	)	$	0.16
Diluted earnings (loss) per share:
Numerator
Income (loss) from continuing operations, net of income tax	$	(7,020	)	$	(4,548	)	$	6,879
Less: dividends on preferred shares	—			162			162
Income (loss) from continuing operations, net of tax	(7,020		)	(4,710		)	6,717
Loss from discontinued operations, net of tax	(101,585		)	(69,873		)	(4,301		)
	$	(108,605	)	$	(74,583	)	$	2,416
Denominator
Common shares outstanding	19,831			18,358			15,527
Stock options, restricted stock and warrants	—		(1)	—		(1)	357
Conversion of preferred shares	—		(2)	—		(2)	—		(2)
Conversion of 5.0% notes payable	—		(3)	—		(3)	—		(3)
Diluted shares outstanding	19,831			18,358			15,884
Diluted earnings (loss) available to common shares per share from:
Continuing operations	$	(0.35	)	$	(0.26	)	$	0.42
Discontinued operations	(5.13		)	(3.81		)	(0.27		)
Diluted income (loss) per share	$	(5.48	)	$	(4.07	)	$	0.15
Anti-dilutive securities not included above are as follows:
Stock options, restricted stock and warrants	25			148			—
Preferred shares	—			450			450
Debentures	—			—			26
5% notes payable (3)	1,966			2,015			2,015

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

(2) Conversion of these securities would be antidilutive; therefore there are no dilutive shares. These securities were converted on or prior to December 31, 2007.

(3) Conversion of the 5% Convertible Senior Notes would be antidilutive therefore, there are no dilutive shares.

F-16

NOTE 4 — ACCOUNTS RECEIVABLE

Accounts receivable consisted of the following:

	December 31,
	2008		2007
	(in thousands)

Accrued oil sales receivables	$	752	$	2,671
Other accounts receivable	306		413
	$	1,058	$	3,084

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

Other receivables and VAT at December 31, 2008 and 2007 consist of accrued interest receivable on time deposits, value added tax refunds and travel advances to employees.

NOTE 5 — OIL AND NATURAL GAS PROPERTIES

Oil and Natural Gas Properties consist of the following:

	December 31,
	2008			2007
	(in thousands)

Licenses and concessions	$	198		$	150
Non-producing leaseholds	—			1,982
Producing leaseholds and intangible drilling costs	108,130			115,266
Furniture, fixtures and office equipment	2,200			2,173
	110,528			119,571
Accumulated depreciation, depletion and amortization	(37,775		)	(38,588		)
Total oil and natural gas properties	$	72,753		$	80,983

NOTE 6 — INVESTMENTS IN UNCONSOLIDATED ENTITIES

In February 2004, we acquired 45% of ePsolutions. Based in Austin, Texas, ePsolutions is a software and energy services company in the electric industry and deregulated energy markets. ePsolutions is the developer of emPower system, a CIS, EDI and billing solution for energy companies within deregulated energy markets. We recorded equity in the earnings of ePsolutions of a gain of $41,000 in 2007 and a loss of $70,000 in 2006. In April 2007, we sold our interest in ePsolutions to ePsolutions for $3.9 million and recorded a gain on the sale of $2.3 million.

In July 2000, we acquired 35% of EnergyNet.com, Inc. (“EnergyNet”), an Internet based oil and natural gas property auction company. We recorded equity in the earnings of EnergyNet of a loss of $45,000 in 2007 and a gain of $340,000 in 2006. We received a dividend from EnergyNet of $175,000 in 2006. In April 2007, we sold our interest in EnergyNet.com to EnergyNet.com for $2 million and recorded a gain on the sale of $1.1 million.

In April 2000, we acquired a 50% interest in Capstone Royalty, LLC (“Capstone”), a joint venture formed to acquire mineral interests at county auctions in west Texas and develop those interests. We recorded equity in the earnings of Capstone amounting to $26,000 in 2007 and $131,000 in 2006. We received a distribution from Capstone of $60,000 in 2007 and $75,000 in 2006. In April 2007, we sold our interest in Capstone Royalty, LLC to Capstone Royalty, LLC for $250,000 and recorded a gain on the sale of $124,000.

F-17

NOTE 7 — LONG-TERM DEBT

Long-term debt consisted of the following:

	December 31,
	2008			2007
	(in thousands)

Secured revolving facility with the International Finance Corporation	$	30,000		$	30,000
Convertible senior notes	80,275			86,250
	110,275			116,250
Less: current portion	(30,000		)	—
	$	80,275		$	116,250

CONVERTIBLE SENIOR NOTES DUE OCTOBER 1, 2025

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

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

The Notes bear interest at a rate of 5% per annum and can be converted into common stock at an initial conversion rate of 23.3596 shares of common stock per $1,000 principal amount of Notes, subject to adjustment in an event of a fundamental change, as defined, (equivalent to a conversion price of approximately $42.81 per share). The Company may redeem the Notes, in whole or in part, on or after October 6, 2008, and prior to October 1, 2010, for cash at a redemption price equal to 100% of the principal amount of Notes to be redeemed, plus any accrued and unpaid interest, if the closing price of its common stock exceeds 130% of the conversion price over a specified period. On or after October 1, 2010, the Company may redeem the Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of Notes to be redeemed, plus any accrued and unpaid interest, irrespective of the price of our common stock. Holders may convert their Notes at any time prior to the close of business on the business day immediately preceding their stated maturity, and holders may, (i) upon the occurrence of certain fundamental changes, and also (ii) on October 1, 2010, October 1, 2015, and October 1, 2020, require the Company to repurchase all or a portion of their Notes for cash in an amount equal to 100% of the principal amount of such Notes, plus any accrued and unpaid interest. At December 31, 2008, the outstanding principal amount of the Notes was $80.3 million.

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

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

The registration rights agreement covering the Notes provided for a penalty if the registration statement was filed and declared effective but thereafter ceased to be effective (a “Suspension Period”) for an

F-18

aggregate of forty-five (45) days in any three month period or ninety (90) days in any twelve month period (an “Event Date”). Such penalty called for an additional 0.25% per annum in interest expense on the aggregate principal amount of the Notes for the first ninety (90) days following an Event Date and an additional 0.50% per annum in interest expense on the aggregate principal amount of the Notes thereafter, until such Suspension Period ended upon the registration statement again becoming effective or not being required to be effective pursuant to the registration rights agreement. Because we did not file our Quarterly Report on Form 10-Q for the nine month period ended September 30, 2006 in a timely manner, the registration statement for the Notes became ineffective and we entered a Suspension Period on November 15, 2006. Such Suspension Period ended on January 23, 2007 when we provided notice that the Form 10-Q had been filed and the Suspension Period was no longer in effect. Because the Suspension Period exceeded forty-five (45) days in any three month period, we paid approximately $14,375 in additional interest expense. On March 16, 2007, the date we filed our Form 10-K for the year ended December 31, 2006, we again entered a Suspension Period until all the Notes became eligible for sale pursuant to Rule 144(k) on September 30, 2007. On October 1, 2007, $155,000 was deposited with the trustee for the Notes as the penalty for any holders of the Notes who were eligible on October 1, 2007 to receive a pro rata portion of such payment. Such eligible holders had to have registered their Notes on the registration statement and still held those Notes on October 1, 2007. On April 1, 2008, we requested that the trustee return $150,957 which represents the unclaimed portion of the penalty and on April 3, 2008 we received the funds from the trustee. During the year we paid $4,043 of the penalty deposit to eligible holders of Notes.

On July 9, 2008, our Board of Directors authorized a program to repurchase up to $10 million of the Notes by December 31, 2008. During this period, we repurchased $6 million of the Notes for $5.3 million plus accrued interest of $109,347. Additionally, we expensed $241,965 of prepaid loan fees attributable to the repurchased notes. This resulted in a $458,535 gain on the early extinguishment of debt. The repurchases were made in the open market, or in privately negotiated transactions, subject to market conditions, applicable legal requirements and other factors.

SECURED REVOLVING FACILITY WITH THE INTERNATIONAL FINANCE CORPORATION

On December 28, 2006, we guaranteed the obligations of certain of our direct and indirect subsidiaries in a loan and guarantee agreement with the International Finance Corporation. The loan and guarantee agreement provides for the $25 million loan facility which is a secured revolving facility with a maximum facility amount of $25 million which maximum facility amount would have increase to $40 million when the projected total borrowing base amount exceeded $50 million. The $25 million facility was funded on March 2, 2007. The total proceeds received on March 2, 2007 were approximately $25 million, of which $11 million was used to retire the outstanding balance on the $15 million credit facility with Natixis Banques Populaires and the remaining $14 million of funds was used to finance our capital expenditures in Turkey and Romania. The loan and guarantee agreement also provided for a $10 million facility which was funded on December 28, 2006. In September 2007, we repaid $5 million on the $25 million facility from proceeds received on the U.S. oil and gas property sale. As of December 31, 2007, the International Finance Corporation reduced our borrowing base under both loans to $30 million from $35 million. Both the $25 million facility and $10 million facility were to fund our operations in Turkey and Romania.

Interest accrued on any loans under the $25 million facility at a rate of 2% over the six month LIBOR rate. Interest accrued on the $10 million facility at a rate of 1.5% over the six month LIBOR rate until the $25 million facility was funded after which the rate for the $10 million facility was lowered to 0.5% over the six month LIBOR rate. At December 31, 2008, the interest rate on the $10 million facility was 2.823% and the interest rate on the $25 million facility was 4.323%. Interest was to be paid on each June 15 and December 15.

The $25 million facility was secured as follows: (i) the lender has a first ranking security interest in (a) certain proceeds, receivables and contract rights relating to and from the sale of oil or gas production in France, Turkey and Romania and (b) funds held in certain bank accounts; (ii) the lender had an assignment of all rights and claims to any compensation or other special payments in respect of all concessions other

F-19

than those arising in the normal course of operations payable by the government of Turkey and Romania; and (iii) the lender has a first ranking pledge (a) by Toreador International Holding, LLC of all its shares in the borrowers; (b) by Madison Oil France SAS of all its shares in Toreador France; and (c) by the Company of all its shares in Toreador International Holding, LLC.

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

We were required to meet the following ratios on a consolidated basis: (i) the life of loan coverage ratio of not less than: (a) 1.2:1.0 in 2006 and 2007; (b) 1.3:1.0 in 2008; and (c) 1.4:1.0 in 2009 and each subsequent year thereafter; (ii) reserve tail ratio of not less than 25%; (iii) adjusted financial debt to EBITDAX (earnings before interest, taxes, depreciation and amortization and exploration expenses) ratio of not more than 3.0:1.0; (iv) liabilities to tangible net worth ratio of not more than 60:40; and (v) interest coverage ratio of not less than 3.0:1.0. On August 9, 2007, the ratios were amended to replace the adjusted financial debt to EBITDA ratio not being more than 3.0:1.0 with the adjusted financial debt to EBITDAX ratio not being more than 3.0:1.0 and the definition of interest coverage ratio was adjusted to substitute EBITDAX instead of EBITDA for calculation purposes. At December 31, 2007, we were not in compliance with the interest coverage ratio of not less than 3.0:1.0; the actual ratio was 2.8:1.0. The International Finance Corporation granted the Company a temporary waiver for the interest coverage ratio provided the Company maintained EBITDAX to net interest expense ratio of 2.7:1.0 until July 2, 2008 and EBITDA to net interest expense ratio of at least 2.7:1.0 during the remaining period of the waiver’s effectiveness. The waiver was effective until March 8, 2009.

At March 31, 2008, we were not in compliance with the adjusted financial debt to EBITDAX ratio threshold of not more than 3.0:1.0; the actual ratio was 4.5:1.00. The International Finance Corporation granted the Company a temporary waiver on the condition that the Company maintains the adjusted financial debt to EBITDA ratio for the (i) quarter ending March 31, 2008 of 4.5:1.0; (ii) quarter ending June 30, 2008 of 4.0:1.0; (iii) quarter ending September 30, 2008 of 3.5:1.0, and (iv) quarter ending December 31, 2008 of 3.25:1.0. We must also be compliant with the original requirement of adjusted financial debt to EBITDA of not more than 3.0:1.0 starting from the end of the first quarter ending March 31, 2009. The waiver is effective until April 1, 2009.

At December 31, 2008, we were not in compliance with the liabilities to tangible net worth ratio, however we did not request a waiver from the IFC as the facility was subsequently retired on March 3, 2009 as explained below.

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

Included in other income and expenses of discontinued operations for the year ended December 31, 2008, is $701,625 of additional compensation due to the IFC related to the prior year. This amount should have been recognized as additional interest expense in the prior year. Management does not believe the error had a material effect on the financial results for the year ended December 31, 2007 or that the correction of the error in the current period will have a material effect on the financial results for the year ended December 31, 2008. Also included in other income and expenses of discontinued operations for the year ended December 31, 2008 is an estimate of $2.1 million to be paid in 2009 relating to 2008 operations.

F-20

On March 3, 2009, we repaid the Secured Revolving Credit Facility with the International Finance Corporation with the proceeds from our sale of 26.75% of our 36.75% interest in the Black Sea Project. The total amount of the payment was $36.4 million, which was comprised of $30 million principal, $5.9 million additional compensation, as defined in the Loan and Guarantee Agreement among Toreador Resources Corporation and the International Finance Corporation dated December 28, 2006, due under the $10 million facility and $500,000 for accrued interest and fees.

The following table summarizes the principal maturities under our long-term debt arrangements at December 31, 2008, (in thousands):

	2009		2010		2011		2012		Thereafter		Total
Long-term debt	$	30,000	$	—	$	—	$	—	$	80,275	$	110,275

NOTE 8 — CAPITAL

On March 23, 2007, we closed a $45 million private placement of equity. In the transaction, we issued an aggregate of 2,710,843 shares of common stock to six institutional investors, providing us with $45 million of gross proceeds at closing. We also granted the investors the right to purchase an additional $8.1 million aggregate amount of common stock within the next 30-day period. On April 24, 2007, two of the institutional investors exercised their warrants for an aggregate of 326,104 additional shares of common stock, providing us with approximately $5.4 million of gross proceeds. The net proceeds from the private placement totaled approximately $47 million and were used to help fund our 2007 exploration and development activities.

In connection with the private placement, we entered into a registration rights agreement with the investors. The registration rights agreement provided that we would file a registration statement with the Securities and Exchange Commission covering the resale of the common stock within 60 days after the closing date. If the registration statement was not filed with the Securities and Exchange Commission within such time, we had to pay 1.0% of the aggregate purchase price, an additional 1.0% on the one month anniversary of the 60th day after closing if the registration statement had not been filed by such date and an additional 2.0% of the aggregate purchase price for each 30 day period after the one month anniversary if the registration statement was not filed by such date. We filed the registration statement with the Securities and Exchange Commission on May 8, 2007. If the registration statement was not declared effective by the Securities and Exchange Commission within 150 days after the closing date, we had to pay 1.0% of the aggregate purchase price, an additional 1.0% on the one month anniversary of the 150th day after the closing if the registration statement had not been declared effective by the Securities and Exchange Commission by such date and an additional 2.0% of the aggregate purchase price for each 30 day period after the one month anniversary if the registration statement was not declared effective by such date. The registration statement was declared effective July 26, 2007. Now that the registration statement has been declared effective by the Securities and Exchange Commission, if, subject to certain exceptions, future sales cannot be made pursuant to the registration statement after 60 days has elapsed, we must pay 1.0% of the aggregate purchase price on the date sales cannot be made pursuant to the registration statement, an additional 1% on the one month anniversary of the date sales are not permitted under the registration statement if sales are not permitted under the registration statement by such date and an additional 2.0% of the aggregate purchase price for each 30 day period after the one month anniversary if sales under the registration statement are not permitted by such date. Any one month or 30 day periods during which we cure the violation will cause the payment for such period to be made on a pro rata basis. As a result of the change in the resale restrictions under Rule 144, effective February 15, 2008, we amended the registration rights agreement to provide that we do not have to keep the registration statement effective if the holders of the shares covered by the registration rights agreement can sell all of the shares pursuant to Rule 144.

We account for registration rights agreements containing a contingent obligation to make future payments or otherwise transfer consideration under a registration payment arrangement, in accordance with EITF Issue No. 00-19-2, “Accounting for Registration Payment Arrangements”. Under this approach, the contingent obligation to make future payments or otherwise transfer consideration under a registration payment arrangement shall be recognized and measured separately in accordance with “FAS No. 5,

F-21

Accounting for Contingencies” and “FASB Interpretation No. 14, Reasonable Estimation of the Amount of a Loss”.

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

On July 22, 2004, we issued warrants for the purchase of 40,000 shares of our common stock at $8.20 per share. The warrant was issued pursuant to the terms of the letter agreement dated July 19, 2004. At December 31, 2008 there were 36,400 warrants outstanding all of which expire on July 22, 2009. We recognized $58,410 in expense relating to the issuance of the warrants.

On July 11, 2005, we issued warrants for the purchase of 50,000 shares of our common stock at $27.40 per share. The warrants were issued pursuant to the terms of the Fee Letter, dated February 21, 2005, between the Company, Natexis Banques Populaires and Madison Energy France. At December 31, 2008 all 50,000 warrants were outstanding and expire on December 23, 2009. In 2006, we recognized $836,000 in expense relating to the issuance of the warrants.

On January 3, 2006, we issued warrants for the purchase of 10,000 shares of our common stock at $27.65 per share. The warrant was issued pursuant to the terms of the Engagement Letter, dated January 3, 2006, between the Company and ParCon Consulting. At December 31, 2008 all 10,000 warrants were outstanding and expire on January 3, 2011. We recognized $106,800 of expense in 2006 relating to the issuance of the warrants.

NOTE 9 — INCOME TAXES

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

	2008			2007			2006
	(in thousands)
Current:
U.S. Federal	$	(5	)	$	(31	)	$	(581	)
U.S. State	(115		)	323			(7		)
Foreign	7,526			2,409			1,156
Deferred:
U.S. Federal	(443		)	(32		)	135
Foreign	(887		)	(3,393		)	2,944
	$	6,076		$	(724	)	$	3,647
The tax provision (benefit) has been allocated between continuing operations and discontinued operations as follows:
Provision (benefit) allocated to:
Continuing operations	$	5,502		$	(1,402	)	$	3,236
Discontinued operations	574			678			411
	$	6,076		$	(724	)	$	3,647

F-22

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

	2008			2007			2006
	(in thousands)

Statutory tax at 34%	$	(34,860	)	$	(25,549	)	$	2,113
Rate differences related to foreign operations	13,706			6,479			584
Use of NOL carryforwards	—			—			(121		)
Reduction in Turkish net operating loss	—			—			143
State income tax, net	(76		)	213			(5		)
Foreign currency gain (loss) not taxable in foreign jurisdictions	498			4,497			265
Effect of rate changes in foreign countries	—			—			(1,062		)
Adjustments to valuation allowance	26,440			14,172			1,846
Other	368			(536		)	(116		)
	$	6,076		$	(724	)	$	3,647

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities as of December 31, 2008 and 2007 were as follows:

	December 31,
	2008			2007
	(in thousands)
Deferred tax assets:
Net operating loss carryforward — United States	$	15,005		$	8,620
Net operating loss carryforward — State	135			135
Net operating loss carryforward — Foreign	9,617			12,265
Restricted stock	565			689
Impairment — Foreign	16,468			4,571
Impairment — US	5,453			—
Other	690			475
Gross deferred tax assets	47,933			26,755
Valuation allowance	(46,984		)	(20,900		)
Net deferred tax assets	$	949		$	5,855

Deferred tax liabilities:
Differences in oil and gas property capitalization and depletion methods— Foreign	(13,851		)	(20,768		)
Liabilities held for sale - Turkey	—			(633		)
Unrealized foreign currency translation gains	(949		)	(455		)
Gross deferred tax liabilities	(14,800		)	(21,856		)
Net deferred tax liabilities	$	(13,851	)	$	(16,001	)

At December 31, 2008, Toreador had the following carryforwards available to reduce future taxable income (in thousands):

Jurisdiction	Expiry	Amount
United States	2010 — 2023	$	44,132
Hungary	Unlimited	38,656
Turkey	2008 — 2012	12,956
France	Unlimited	2,523

F-23

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

	December 31,
	2008		2007
	(in thousands)

United States	$	15,005	$	8,755
Turkey	2,591		—
Hungary	6,185		6,024
France	841		841
	$	24,622	$	15,620

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

	Required
	Taxable Income

United States	$	44,132
Turkey	12,956
Hungary	38,656
France	2,523

A portion of the Hungarian net operating loss was acquired in a purchase; therefore realization of $25 million of the Hungarian net operating loss will be credited to oil and natural gas properties rather than a credit to income tax expense.

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

We adopted FIN No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN No. 48”) on January 1, 2007. As a result of the adoption the Company recognized an increase in the liability for unrecognized tax benefits of approximately $45,000, which was accounted for as a decrease to the January 1, 2007 balance of retained earnings. As of the date of adoption and after the impact of recognizing the increase in liability noted above, our unrecognized tax benefits totaled approximately $357,000, the disallowance of which would not materially affect the effective income tax rate. There are no tax positions for which a material change in the unrecognized tax benefit liability is reasonably possible in the next 12 months.

We recognize potential accrued interest and penalties related to unrecognized tax benefits within our global operations in income tax expense. In conjunction with the adoption of FIN No. 48, we recognized approximately $28,000 for the accrual of interest and penalties at January 1, 2007 which is included as a component of $357,000 unrecognized tax benefit noted above. During the year 2008 we recognized $0 in potential interest and penalties associated with uncertain tax positions. To the extent interest and penalties are not assessed with respect to uncertain tax positions, amounts accrued will be reduced and reflected as a reduction of the overall income tax provision.

The following table summarizes the changes in our liability for unrecognized tax benefits for the year ended December 31, 2008:

Unrecognized tax benefit at January 1, 2008	$	326
Tax Year Closed	(5		)
Unrecognized tax benefit at December 31, 2008	$	321

F-24

We have not paid any significant interest or penalties associated with our income taxes, but classify both interest expense and penalties as part of our income tax expense.

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

NOTE 10 — BENEFIT PLANS

We have a 401(k) retirement savings plan. Employees are eligible to defer portions of their salaries, limited by Internal Revenue Service regulations. The Company is subject to the 3% safe harbor rule and contributed $95,000 in 2008 and $115,000 in 2007. Discretionary employer matches are determined annually by the board of directors and such discretionary matches amounted to $0 in 2008, $112,500 in 2007 and $74,000 in 2006.

NOTE 11 — STOCK COMPENSATION PLANS

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

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

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

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

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

A summary of stock option transactions is as follows:

	2008				2007				2006
	SHARES		WEIGHTED AVERAGE EXERCISE PRICE		SHARES		WEIGHTED AVERAGE EXERCISE PRICE		SHARES		WEIGHTED AVERAGE EXERCISE PRICE
Outstanding at January 1	338,170		$	4.85	673,870		$	5.13	858,940		$	5.07
Granted	100,000		7.88		—		—		—		—
Exercised	(189,800	)	3.93		(320,700	)	5.06		(175,070	)	4.95
Forfeited	—		—		(15,000	)	13.18		(10,000	)	3.10
Outstanding at December 31	248,370		6.77		338,170		4.85		673,870		5.13
Exercisable at December 31	148,370		6.02		334,837		4.73		660,536		4.90

The intrinsic value of the options exercised in 2008 was $979,609. For the year ended December 31, 2008, 2007 and 2006 we received cash from stock option exercises of $745,000, $1.6 million and $866,000, respectively. During 2008, 3,333 shares vested. As of December 31, 2008, the total compensation cost related to non-vested stock options not yet recognized is approximately $255,000. This amount will be recognized as compensation expense over the next 29 months.

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

F-25

YEAR	OPTION TYPE	SHARES	WEIGHTED-AVERAGE EXERCISE PRICE		WEIGHTED-AVERAGE FAIR VALUE
2008	Exercise price equal to market price	100,000	$	7.88	$	3.61

The following table summarizes information about the fixed price stock options outstanding at December 31, 2008:

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

$	3.00	5,000	$	12		5,000	$	12		0.42
3.10		20,000	48			20,000	48			4.47
3.12		4,420	11			4,420	11			1.72
3.88		5,000	8			5,000	8			0.82
4.12		15,000	21			15,000	21			3.41
4.96		10,000	5			10,000	5			5.39
5.50		56,450	(1		)	56,450	(1		)	5.32
5.95		15,000	(7		)	15,000	(7		)	2.38
7.88		100,000	(239		)	—	—			9.38
13.75		7,500	(62		)	7,500	(62		)	5.88
16.90		10,000	(114		)	10,000	(114		)	6.38
		248,370	(318		)	148,370	(79		)	4.14

At December 31, 2008, there were 20,208, remaining shares available for grant under the plans collectively.

In May 2005, stockholders approved the Toreador Resources Corporation 2005 Long-Term Incentive Plan (the “Plan”). The Plan, as amended, authorizes the issuance of up to 750,000 shares of the Company’s common stock to key employees, key consultants and outside directors of the Company. The Board of Directors has authorized a total of 314,184 shares of restricted stock be granted to employees and non-employee directors. The compensation cost is measured by the difference between the quoted market price of the stock at the date of grant and the price, if any, to be paid by an employee and is recognized as an expense over the period the recipient performs related services. The restricted stock grants vest over a one to four year period depending on the grant and the weighted average price of the stock on the date of the grants was $8.08 for the year ended December 31, 2008. Stock compensation expense of $2.3 million and $3.9 million is included in the Statement of Operations for the years ended December 31, 2008 and 2007, which represents the cost recognized from the date of the grants through December 31, 2008 and 2007. During 2008, 172,463 shares vested having a fair value of approximately $1.5 million on the date of vesting. As of December 31, 2008, the total compensation cost related to non-vested restricted stock grants not yet recognized is approximately $2 million. This amount will be recognized as compensation expense over the next 24 months.

For the years ended December 31, 2008 and 2007 we recognized a current tax benefit related to restricted stock grants of approximately $0 and $0 and a deferred tax benefit of approximately $443,000 and $1.3 million, respectively.

The following table summarizes the changes in outstanding restricted stock grants along with their related grant-date fair values for the year ended December 31, 2008:

F-26

	Shares		Weighted Average Grant-Date Fair Value
Non-vested at January 1, 2008	222,599		$	25.91
Shares granted	314,184		8.08
Shares vested	(172,465	)	16.56
Shares forfeited	(86,094	)	26.38
Non-vested at December 31,2008	278,224		$	11.63

NOTE 12 — COMMITMENTS AND CONTINGENCIES

We lease our office space under non-cancelable operating leases, expiring during 2009 through 2014. The following is a schedule of minimum future rentals under our non-cancelable operating leases as of December 31, 2008 (in thousands):

2009	$	770
2010	816
2011	827
2012	681
2013	636
Thereafter	453
	$	4,183

Net rent expense totaled $952,000 in 2008, $818,000 in 2007 and $699,000 in 2006.

Black Sea Incidents. In October 2005, in an incident involving a vessel owned by Micoperi Srl, the Ayazli 2 and Ayazli 3 wells were damaged, and subsequently had to be re-drilled. We and our co-venturers made a claim in respect of the cost of re-drilling and repeating flow-testing. The amount claimed was approximately $10.8 million before interest, subject to adjustment when the actual cost of flow-testing the re-drilled wells was known. In addition, we and our co-venturers claimed to recover back from Micoperi a sum of about $8.2 million paid to Micoperi under the contract between us, our co-venturers and Micoperi. Micoperi made a cross-claim for about $7.1 million in respect of sums allegedly due to Micoperi under the contract between us, our co-venturers and Micoperi. Micoperi also asserted a claim that the arrest of the vessel “MICOPERI 30” at Palermo, Italy was wrongful and asserted a claim for damages in respect of such allegedly wrongful arrest. We and our co-ventures received security from Micoperi by way of a letter of undertaking from their insurers, and provided security to Micoperi in respect of their cross-claims by way of a bank guarantee of $8.2 million. The claims and cross-claims were subject to the jurisdiction of the English Court; however, neither side commenced any court proceedings. All the amounts stated above are gross and our share was equal to 36.75%. Following mediation in London, an agreement was reached on November 14, 2008 between Toreador, our co-venturers and Micoperi, whereby a full settlement of all claims related to the 2005 incident were reached. The settlement’s net proceeds to us were approximately $1.4 million and we were released of all cross-claims from Micoperi regarding the 2005 incident.

The Company has two fallen structures at the bottom of the Black Sea. There has been no liability recorded for the environmental remediation as the likelihood of having to remove the structures is remote.

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

NOTE 13 — RELATED PARTY TRANSACTIONS

William I. Lee (deceased), was a former director of the Company and the majority owner of Wilco Properties, Inc (“Wilco”). The Company subleased office space to Wilco pursuant to a sub-lease agreement. We recorded reductions to rent expense totaling $0 in 2008, $25,000 in 2007 and $50,000 in

F-27

2006 related to the sublease with Wilco. We had an informal agreement with Wilco under which one of the two companies incurs, on behalf of the other, certain miscellaneous expenses that are subsequently reimbursed by the other company. As of December 31, 2008 the informal lease agreement has been terminated and no amounts are owed or are due to the company.

On November 1, 2002, pursuant to a private placement we issued $925,000 of Series A-1 Convertible Preferred Stock to certain of our directors or entities controlled by certain of our directors. In connection with the securities purchase agreements, Toreador entered into a registration rights agreement effective November 1, 2002, among Toreador and the purchasers which provides for the registration of the common stock issuable upon conversion of the Series A-1 Convertible Preferred Stock. During 2003, pursuant to private placements we issued 41,000 shares of our Series A-1 Convertible Preferred Stock for the total amount of $1,025,000 to William I. Lee and Wilco as follows: (i) in October 2003, 34,000 shares were issued to William I. Lee and Wilco, an entity controlled by Mr. Lee; and (ii) in December 2003, 7,000 shares were issued to Wilco. The Series A-1 Convertible Preferred Stock was governed by a certificate of designation. The Series A-1 Convertible Preferred Stock was sold for a face value of $25.00 per share, and pays an annual cash dividend of $2.25 per share that result in an annual yield of 9.0%. At the option of the holder, the Series A-1 Convertible Preferred Stock was convertible into common shares at a price of $4.00 per common share. The $4.00 conversion price was higher than the market price of our common stock at the time of issuances. The Series A-1 Convertible Preferred Stock was redeemable at our option, in whole or in part, at any time on or after November 1, 2007. The optional redemption price per share was the sum of (1) $25.00 per share of the Series A-1 Convertible Preferred Stock plus (2) any accrued unpaid dividends, and such sum is multiplied by a declining multiplier. The multiplier is 105% until October 31, 2008, 104% until October 31, 2009, 103% until October 31, 2010, 102% until October 31, 2011, 101% until October 31, 2012, and 100% thereafter. In connection with the securities purchase agreements entered into with William I. Lee and Wilco, Toreador granted certain “piggy-back” registration rights relating to the common stock issuable upon conversion of the Series A-1 Convertible Preferred Stock. The sale of the Series A-1 Convertible Preferred Stock was effected in reliance upon the exemption from securities registration afforded by the provisions of Section 4(2) of the Securities Act of 1933, as amended, and Regulation D as promulgated by the Securities and Exchange Commission under the Securities Act of 1933, as amended. In December 2007, all the series A-1 Convertible Preferred Stock was converted into common shares.

NOTE 14 — DISCONTINUED OPERATIONS

On June 14, 2007, the Board of Directors authorized management to sell all oil and natural gas properties in the United States. The sale of these properties completed the divestiture of the company’s non-core domestic assets and allows us to focus exclusively on our international operations. The sale was closed on September 1, 2007. The sales price was $19.1 million which resulted in a pre-tax gain of $9.2 million. Prior year financial statements for 2007 and 2006 have been adjusted to present the operations of the U.S. properties as a discontinued operation.

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

Additionally, on September 30, 2009, the Company entered into the Quota Purchase Agreement with RAG, pursuant to which the Company agreed to sell 100% of its equity interests in Toreador Hungary to

F-28

RAG. The sale of Toreador Hungary was completed on September 30, 2009. This resulted in a financial loss of $4.2 million which was recorded in the third quarter of 2009.

The results of operations of assets in the United States, Romania, Turkey and Hungary have been presented as discontinued operations. The table below compares discontinued operations for the years ended December 31, 2008, 2007 and 2006:

	Year ended December 31,
	2008			2007			2006
Revenue:
Oil and natural gas sales	$	28,226		$	20,273		$	13,104

Operating costs and expenses:
Lease operating expense	7,971			6,892			3,712
Exploration expense	4,582			11,324			1,631
Depreciation, depletion and amortization	28,148			17,466			4,161
Dry hole expense	—			18,096			3,099
Impairment	82,951			13,446			345
General and administrative expense	2,445			5,131			2,204
(Gain) loss on sale of properties and other assets	123			(9,248		)	(638		)
Total operating costs and expenses	126,220			63,107			14,514

Operating loss	(97,994		)	(42,834		)	(1,410		)

Other expense	(3,017		)	(26,361		)	(2,480		)
Loss before taxes	(101,011		)	(69,195		)	(3,890		)
Income tax provision	574			678			411

Loss from discontinued operations	$	(101,585	)	$	(69,873	)	$	(4,301	)

The assets and liabilities of discontinued operations presented separately under the captions “Oil and natural gas properties, net, held for sale”, “Other assets held for sale” and “Liabilities held for sale” in balance sheets for the periods ended December 31, 2008 and December 31, 2007 are valued at the lower of cost or fair value less cost of selling such assets. The table below shows the components of the other assets held for sale and liabilities held for sale.

	December 31,, 2008		December 31, 2007

Current assets:
Cash	$	4,597	$	4,317
Restricted cash	2,922		2,133
Accounts receivable	4,392		9,256
Other	1,568		64
Total current assets	13,479		15,770
Other assets	1,484		2,446
Other assets held for sale	$	14,963	$	18,216

Current liabilities:
Accounts payable and accrued liabilities	$	9,223	$	11,018
Asset retirement obligations	2,028		2,233
Liabilities held for sale	$	11,251	$	13,251

NOTE 15 — INFORMATION ABOUT OIL AND NATURAL GAS PRODUCING ACTIVITIES AND OPERATING SEGMENTS

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

F-29

Romania and Turkey). Geographic operating segment income tax expenses have been determined based on statutory rates existing in the various tax jurisdictions where we have oil and natural gas producing activities.

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

The following tables provide the geographic operating segment data required by Statement of Financial Accounting Standards No. 131, “Disclosure about Segments of an Enterprise and Related Information”. The United States segment data for the years ended December 31, 2008, 2007, and 2006 has been adjusted to reflect the sale of oil and natural gas properties in the United States as of September 1, 2007 (see Note 14).

	United States			France			Total
	(In thousands)
For the year ended December 31, 2008
Revenues:
Oil and natural gas sales	$	52		$	34,098		$	34,150
Costs and expenses:
Lease operating	—			9,263			9,263
Exploration expense	1,080			144			1,224
Depreciation, depletion and amortization	307			4,687			4,994
Impairment of oil and natural gas properties and intangible assets	2,282			—			2,282
General and administrative	11,747			1,295			13,042
Loss on sale of oil and gas derivative contracts	—			1,781			1,781
Total costs and expenses	15,416			17,170			32,586
Operating income (loss)	(15,364		)	16,928			1,564
Other income (expense)	(3,154		)	72			(3,082		)
Income (loss) before income taxes	(18,518		)	17,000			(1,518		)
Benefit (provision) for income taxes	563			(6,065		)	(5,502		)
Income (loss) from continuing operations, net of tax	$	(17,955	)	$	10,935		$	(7,020	)
Selected assets:
Properties and equipment	$	1,860		$	108,669		$	110,529
Accumulated depreciation, depletion, and amortization	(1,163		)	(36,613		)	(37,776		)
Oil and natural gas properties, net	$	697		$	72,056		$	72,753
Goodwill	$	—		$	3,838		$	3,838
Total assets	$	276,434		$	93,691		$	370,125
Expenditures for additions to long-lived assets:
Development costs	$	—		$	431		$	431
Other	10			—			10
Total expenditures for long-lived assets	$	10		$	431		$	441

F-30

	United States			France			Total
	(In thousands)
For the year ended December 31, 2007
Revenues:
Oil and natural gas sales	$	34		$	25,873		$	25,907
Costs and expenses:
Lease operating	—			7,344			7,344
Exploration expense	2,668			855			3,523
Depreciation, depletion and amortization	265			4,137			4,402
Dry hole cost	—			3,847			3,847
General and administrative	9,675			2,832			12,507
Gain on sale of properties and other assets	(3,155		)	—			(3,155		)
Loss on sale of oil and gas derivative contracts	1,005			—			1,005
Total costs and expenses	10,458			19,015			29,473
Operating income (loss)	(10,424		)	6,858			(3,566		)
Other income (expense)	(1,914		)	(470		)	(2,384		)
Income (loss) before income taxes	(12,338		)	6,388			(5,950		)
Benefit (provision) for income taxes	3,692			(2,290		)	1,402
Income (loss) from continuing operations, net of tax	$	(8,646	)	$	4,098		$	(4,548	)
Selected assets:
Properties and equipment	$	3,905		$	115,666		$	119,571
Accumulated depreciation, depletion, and amortization	(928		)	(37,660		)	(38,588		)
Oil and natural gas properties, net	$	2,977		$	78,006		$	80,983
Goodwill	$	—		$	4,059		$	4,059
Total assets	$	298,949		$	83,683		$	382,632
Expenditures for additions to long-lived assets:
Exploration costs	$	—		$	3,847		$	3,847
Other	398			—			398
Total expenditures for long-lived assets	$	398		$	3,847		$	4,245

F-31

	United States			France			Total
	(In thousands)
For the year ended December 31, 2006
Revenues:
Oil and natural gas sales	$	20		$	27,274		$	27,294
Costs and expenses:
Lease operating	—			7,229			7,229
Exploration expense	1,883			432			2,315
Depreciation, depletion and amortization	264			3,119			3,383
General and administrative	5,720			1,905			7,625
Total costs and expenses	7,867			12,685			20,552
Operating income (loss)	(7,847		)	14,589			6,742
Other income (expense)	3,186			187			3,373
Income (loss) before income taxes	(4,661		)	14,776			10,115
Benefit (provision) for income taxes	1,020			(4,256		)	(3,236		)
Income (loss) from continuing operations, net of tax	$	(3,641	)	$	10,520		$	6,879
Selected assets:
Oil and natural gas properties	$	3,602		$	99,751		$	103,353
Accumulated depreciation, depletion, and amortization	(1,271		)	(30,439		)	(31,710		)
Oil and natural gas properties, net	$	2,331		$	69,312		$	71,643
Investments in unconsolidated entities	$	2,659		$	—		$	2,659
Goodwill	$	—		$	3,632		$	3,632
Total assets	$	251,422		$	80,574		$	331,996
Expenditures for additions to long-lived assets:
Development costs	$	—		$	15,931		$	15,931
Other	283			127			410
Total expenditures for long-lived assets	$	283		$	16,058		$	16,341

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

	December 31,
	2008			2007
	(in thousands)
Total assets for reportable segments	$	370,125		$	382,632
Total assets of entities held for sale	(100,609		)	2,839
Elimination of intersegment receivables and investments	(62,360		)	(62,360		)
Total consolidated assets	$	207,156		$	323,111

NOTE 16 — SUBSEQUENT EVENT

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 will be paid unconditionally on September 1, 2009.

In accordance with the covenants of the International Finance Corporation revolving credit facility, proceeds of the Petrol Ofisi sale will be used to fully repay and retire the outstanding balance of $36.4 million, which includes $5.9 million of additional compensation, accrued interest and fees. Remaining

F-32

proceeds will be used to retire a portion of the Notes and fund this year’s capital program to meet minimum commitments associated with the Company’s licenses.

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

NOTE 17 — SUPPLEMENTAL OIL AND NATURAL GAS RESERVES AND STANDARDIZED MEASURE INFORMATION (UNAUDITED)

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

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

F-33

			Discontinued Operations
	France		Turkey		Romania		Hungary		Total
	Natural Gas (MMcf)

PROVED RESERVES
December 31, 2005	—		6,476		3,486		—		9,962
Revisions of previous estimates	—		(1,151	)	(1,185	)	—		(2,336	)
Extensions, discoveries and other additions	—		16,099		1,186		950		18,235
Sale of reserves	—		—		—		—		—
Production	—		—		(446	)	—		(446	)
December 31, 2006	—		21,424		3,041		950		25,415
Revisions of previous estimates	—		(8,215	)	(1,671	)	(950	)	(10,836	)
Extensions, discoveries and other additions	—		741		—		—		741
Sale of reserves	—		—		—		—		—
Production	—		(1,011	)	(598	)	—		(1,069	)
December 31, 2007	—		12,939		772		—		13,711
Revisions of previous estimates	—		(819	)	(310	)	950		(179	)
Extensions, discoveries and other additions	—		—		—		—		—
Sale of reserves	—		—		—		—		—
Production	—		(1,643	)	(376	)	—		(2,019	)
December 31, 2008	—		10,477		86		950		11,513

PROVED DEVELOPED
December 31, 2006	—		—		3,040		950		3,990
December 31, 2007	—		4,248		772		—		5,020
December 31, 2008	—		2,437		86		950		3,473

	Oil (MBbls)
PROVED RESERVES
December 31, 2005	10,978		639		24		—		11,641
Revisions of previous estimates	(906	)	95		4		—		(807	)
Extensions, discoveries and other additions	—		—		19		1		20
Sale of reserves	—		—		—		—		—
Production	(444	)	(69	)	(6	)	—		(519	)
December 31, 2006	9,628		665		41		1		10,335
Revisions of previous estimates	661		481		(27	)	(1	)	1,114
Extensions, discoveries and other additions	39		—		—		—		39
Sale of reserves	—		(30	)	—		—		(30	)
Production	(360	)	(67	)	(8	)	—		(435	)
December 31, 2007	9,968		1,049		6		—		11,023
Revisions of previous estimates	(4,694	)	(253	)	(2	)	1		(4,948	)
Extensions, discoveries and other additions	—		—		—		—		—
Sale of reserves	—		—		—		—		—
Production	(360	)	(55	)	(3	)	—		(418	)
December 31, 2008	4,914		741		1		1		5,657

PROVED DEVELOPED
December 31, 2006	6,770		405		41		1		7,217
December 31, 2007	7,170		808		6		—		7,984
December 31, 2008	4,385		500		1		1		4,887

We have summarized the standardized measure of discounted future net cash flows related to our proved oil and natural gas reserves. We have based the following summary on a valuation of proved reserves using discounted cash flows based on year-end prices, costs and economic conditions and a 10% discount rate. The additions to proved reserves from purchase of reserves in place and new discoveries and extensions could vary significantly from year to year; additionally, the impact of changes to reflect current prices and costs of proved reserves in prior years could also be significant. Accordingly, investors should

F-34

not view the information presented below as an estimate of the fair value of our oil and natural gas properties, nor should investors consider the information indicative of any trends.

For the year ended December 31, 2008, we had a downward reserve revision of 37.4%. At December 31, 2007 the price used for evaluating our oil reserves was $95.72 per barrel as compared to the December 31, 2008 price of $34.29 per barrel. This 62% decrease in oil price had a severe impact on the economic life of our wells, but also on the discounted present value at 10% and the standardized measure of proved reserves. This downward revision, which primarily affected our French oil reserves, was due to the following factors (i) decrease in economic life due to change in economics caused a net decrease of 1,682 MBbl; (ii) removing twelve proved undeveloped locations from the report caused a net decrease 1,889 MBbl; (iii) negative reserve revisions resulted in a decrease in reserves of 405 MBbl; (iv) fourteen wells were shut-in resulting in a decrease of 401 MBbl; (v) three drilled locations in prior years resulted in one producing well which was non-commercial at December 31, 2008 causing a net decrease of 280 MBO;(vi) one well was lost during workover operations causing a net decrease 37 MBbl; (vii) 2008 production of 805 MBOE. In Hungary, we were able to secure a gas contract and were able to restore the reserves lost in 2007, this resulted in an increase of 159 MBOE and in Romania due to the poor performance of the field resulted in a decrease of 54 MBbl. In Turkey, we had downward revisions of 390 MBbl. which was due to a decrease in the economic life of the proved developed wells.

The prices of oil and natural gas at December 31, 2008, 2007, and 2006 used to estimate reserves in the table shown below, were $34.29, $95.72 and $57.75 per Bbl of oil, respectively, and $12.68, $8.91 and $6.98 per Mcf of natural gas, respectively.

			Discontinued Operations
	France		Turkey		Romania			Hungary		Total
					(In thousands)

As of and for the year ended December 31, 2006
Future cash inflows	$	551,139	$	185,815	$	21,163		$	5,732	$	763,849
Future production costs	214,474		20,407		5,198			1,658		241,737
Future development costs	33,580		20,757		159			800		55,296
Future income tax expense	95,067		7,114		(602		)	2,057		103,636
Future net cash flows	208,018		137,537		16,408			1,217		363,180
10% annual discount for estimated timing of cash flows	121,828		53,207		3,019			248		178,302
Standardized measure of discounted future net cash flows related to proved reserves	$	86,190	$	84,330	$	13,389		$	969	$	184,878

As of and for the year ended December 31, 2007
Future cash inflows	$	963,444	$	209,405	$	4,495		$	—	$	1,177,344
Future production costs	305,939		29,759		3,202			—		338,900
Future development costs	32,221		22,272		95			—		54,588
Future income tax expense	200,094		6,597		—			—		206,691
Future net cash flows	425,190		150,777		1,198			—		577,165
10% annual discount for estimated timing of cash flows	250,979		66,729		88			—		317,796
Standardized measure of discounted future net cash flows related to proved reserves	$	174,211	$	84,048	$	1,110		$	—	$	259,369

As of and for the year ended December 31, 2008
Future cash inflows	$	170,662	$	155,179	$	412		$	13,735	$	339,988
Future production costs	105,298		26,939		381			1,851		134,469
Future development costs	13,658		71,283		159			550		85,650
Future income tax expense	10,027		—		—			—		10,027
Future net cash flows (1)	41,679		56,957		(128		)	11,334		109,842
10% annual discount for estimated timing of cash flows	23,116		29,909		(7		)	2,056		55,074
Standardized measure of discounted future net cash flows related to proved reserves (1)	$	18,563	$	27,048	$	(121	)	$	9,278	$	54,768

F-35

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

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

				Discontinued Operations
	France			Turkey			Romania			Hungary			Total
							(In thousands)

Balance at December 31, 2005	$	109,129		$	15,788		$	10,675		$	—		$	135,592
Sales of oil and natural gas, net	(20,201		)	(3,041		)	(1,481		)	—			(24,723		)
Net changes in prices and production costs	(6,102		)	7,074			2,987						3,959
Net change in development costs	(2,101		)	970			(130		)	(641		)	(1,902		)
Extensions and discoveries	—			65,127			5,159			3,267			73,553
Revisions of previous quantity estimates	(13,781		)	(2,355		)	(4,617		)	—			(20,753		)
Previously estimated development costs incurred	(2,132		)	—			(552		)	—			(2,684		)
Net change in income taxes	9,312			(3,445		)	1,262			(1,656		)	5,473
Accretion of discount	13,570			1,679			989			—			16,238
Other	(1,504		)	2,533			(905		)	—			124
Balance at December 31, 2006	86,190			84,330			13,387			970			184,877
Sales of oil and natural gas, net	(18,529		)	(9,213		)	(1,271		)	—			(29,013		)
Net changes in prices and production costs	120,639			38,613			(7,953		)	—			151,299
Net change in development costs	(266		)	(5,701		)	59			641			(5,267		)
Extensions and discoveries	1,076			3,930			—			—			5,006
Revisions of previous quantity estimates	18,303			(28,262		)	(2,726		)	(3,267		)	(15,952		)
Previously estimated development costs incurred	(1,992		)	(8,523		)	—			—			(10,515		)
Net change in income taxes	(42,760		)	257			448			1,656			(40,399		)
Accretion of discount	11,871			8,492			(841		)	—			19,522
Sale of reserves	—			(967		)	—			—			(967		)
Other	(321		)	1,092			7			—			778
Balance at December 31, 2007	174,211			84,048			1,110			—			259,369
Sales of oil and natural gas, net	(24,834		)	(22,191		)	1,906			—			(45,119		)
Net changes in prices and production costs	(212,520		)	(7,298		)	(481		)	—			(220,299		)
Net change in development costs	7,795			(30,943		)	(62		)	(451		)	(23,661		)
Extensions and discoveries	—			—			—			—			—
Revisions of previous quantity estimates	(26,219		)	(11,419		)	(105		)	9,737			(28,006		)
Previously estimated development costs incurred	—			(5,475		)	—			—			(5,475		)
Net change in income taxes	81,846			5,329			(2,712		)	38			84,501
Accretion of discount	26,260			8,938			111			—			35,309
Sale of reserves	—			—			—			—			—
Other	(7,976		)	6,059			112			(46		)	(1,851		)
Balance at December 31, 2008	$	18,563		$	27,048		$	(121	)	$	9,278		$	54,768

F-36

Toreador Resources (TRGL) Inactive 8-KOther Events