8-K

United States
Securities and Exchange Commission

Washington, D.C. 20549

Form 8-K

Current Report
Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934

Date of Report (Date of earliest event reported) January 8, 2010

Endeavour International Corporation

(Exact name of registrant as specified in its charter)

Nevada	001-32212	88-0448389
(State or other jurisdiction of	(Commission file	(I.R.S. Employer
incorporation) 1001 Fannin, Suite 1600, Houston, Texas (Address of principal executive offices)	Number)	Identification No.) 77002 (Zip code)

(713) 307-8700
Registrant’s telephone number, including area code

None
(Former name, former address and former fiscal year, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o Written communications pursuant to Rule 425 under the Securities Act.

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act.

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act.

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act.

Endeavour International Corporation

ITEM 8.01. Other Events.

On May 14, 2009, we completed the divestiture of our Norwegian subsidiary, Endeavour Energy Norge AS, to Verbundnetz Gas AG for cash consideration of $150 million (the “Norway Sale”). As a result of the Norway Sale, we classified the results of operations and financial position of our Norwegian subsidiary as discontinued operations for all periods presented.

We have adjusted the information in Exhibits 99.1, 99.2 and 99.3 to this Current Report on Form 8-K the following information contained in our Form 10-K as filed on March 16, 2009 to reflect our Norwegian Operations as discontinued operations:

• Item 6. Selected Financial Data;

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

• Item 8. Financials Statements and Supplementary Data.

Please note that other than adjustments to present our Norwegian operations as discontinued operations in this Current Report, we have not otherwise updated or modified in this report the financial information or business discussion for activities or events occurring after March 16, 2009, the date we filed our 2008 Form 10-K. Therefore, this Current Report on Form 8-K should be read in conjunction with the 2008 Form 10-K, our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2009, June 30, 2009 and September 30, 2009 and our other Current Reports on Form 8-K.

Unless the context otherwise requires, references to “Endeavour”, “we”, “us” or “our” mean Endeavour International Corporation and our consolidated subsidiaries.

ITEM 9.01. Financial Statements and Exhibits.

(c) Exhibits.

23.1	Consent of Independent Registered Public Accounting Firm KPMG LLP.
99.1	Item 6. Selected Financial Data (adjusted to reflect the results of our Norwegian operations as discontinued operations).
99.2	Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (adjusted to reflect the results of our Norwegian operations as discontinued operations).
99.3	Financial Statements and Supplementary Data.

Endeavour International Corporation

SIGNATURES

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

Endeavour International Corporation
By:	/s/ Robert L. Thompson
Robert L. Thompson
Chief Accounting Officer

Date: January 8, 2010

EX-23.1

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

The Board of Directors
Endeavour International Corporation:

We consent to the incorporation by reference in the registration statements on Forms S-3 (Nos. 333-118503, 333-124145, 333-132684, 333-139304, 333-149744, 333-163781) and Forms S-8 (Nos. 333-119577, 333-128692, 333-143794, 333-149743, 333-157967) of Endeavour International Corporation of our report dated March 13, 2009, except for the effects of discontinued operations as discussed in Note 23 which is dated January 8, 2010, with respect to the consolidated balance sheets of Endeavour International Corporation and subsidiaries as of December 31, 2008 and 2007, and the related consolidated statements of operations, stockholders’ equity and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2008 which report appear in the Form 8-K of Endeavour International Corporation dated January 8, 2010.

Effective January 1, 2007, the Company changed its accounting for uncertain tax positions. Also, effective January 1, 2008, the Company changed its method of accounting and disclosures for fair value measurements and fair value reporting of financial assets and liabilities.

/S/ KPMG LLP

Houston, Texas
January 8, 2010

EX-99.1

Exhibit 99.1

Item 6. Selected Financial Data

The following table sets forth some of our historical consolidated financial data. The following data should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial Statements and Notes thereto included in Item 8. The selected consolidated financial data provided below are not necessarily indicative of our future results of operations or financial performance.

Selected Financial Data (1)
(Amounts in thousands, except per share data)	Year Ended December 31,
	2008		2007			2006			2005			2004
Summary Income Statement Data:
Revenues	$	170,781	$	135,876		$	24,881		$	—		$	8
Operating Profit (Loss)		18,236		23,778			(11,516	)		(43,281	)		(15,741	)
Net Income (Loss) to Common Shareholders		45,681		(60,315	)		(8,829	)		(31,531	)		(23,797	)
Net Income (Loss) Per Common Share - Basic:
Continuing Operations	$	0.12	$	(0.50	)	$	(0.08	)	$	(0.50	)	$	(0.36	)
Discontinued Operations		0.24		0.01			(0.02	)		0.08			(0.01	)
Total	$	0.36	$	(0.49	)	$	(0.10	)	$	(0.42	)	$	(0.37	)
Net Income (Loss) Per Common Share - Diluted:
Continuing Operations	$	0.15	$	(0.50	)	$	(0.08	)	$	(0.50	)	$	(0.36	)
Discontinued Operations		0.17		0.01			(0.02	)		0.08			(0.01	)
Total	$	0.32	$	(0.49	)	$	(0.10	)	$	(0.42	)	$	(0.37	)
Summary Balance Sheet Data:
Working Capital	$	22,902	$	37,198		$	47,431		$	49,638		$	4,699
Total Assets		737,470		747,623			774,470			186,966			101,737
Debt		227,855		266,250			306,250			81,250			2,150
Convertible Preferred Stock		125,000		125,000			125,000			—			—
Equity		117,971		70,149			116,828			40,344			56,972

⁽¹⁾ Includes the following:

• acquisition of Talisman Expro Limited in November 2006;

• acquisition of working interests in the Enoch and Bacchus prospects in 2006;

• disposition of Thailand assets in 2005;

• acquisition of Norwegian assets in November 2004 and January 2005;

• disposition of all U.S. assets in 2004;

• acquisition of NSNV, Inc. in 2004; and

• unrealized gains (losses) on derivatives of $76.7 million, $(89.1) million and $34.5 million in 2008, 2007 and 2006, respectively.

We completed the divestiture of our Norwegian subsidiary on May 14, 2009. The results of operations and financial position of this subsidiary are classified as discontinued operations for all periods presented.

Information regarding each of these transactions is included in the notes to the Consolidated Financial Statements.

EX-99.2

Exhibit 99.2

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

This Management’s Discussion and Analysis of Financial Condition and Results of Operations and other parts of this report contain forward-looking statements that involve risks and uncertainties. All forward-looking statements included in this report are based on information available to Endeavour on the date hereof, and we assume no obligation to update any such forward-looking statements. Our actual results could differ materially from those anticipated in these forward-looking statements as a result of a number of factors, including those set forth in the section captioned “Risk Factors” in Item 1A and elsewhere in this report. The following should be read in conjunction with the audited financial statements and the notes thereto included herein. The following discussion also includes non-GAAP financial measures, which may not be comparable to similarly titled measures presented by other companies. Accordingly, we strongly encourage investors to review our financial statements in their entirety and not rely on any single financial measure.

We have reissued this MD&A and filed it under cover of Form 8-K on January 8, 2010 to reflect the disposition of our Norwegian subsidiary and the related reclassification of its results of operation and financial position as discontinued operations as discussed below in detail.

Overview

We are an international oil and gas exploration and production company focused on the acquisition, exploration and development of energy reserves. To date, we have invested a significant amount of our resources on various development, acquisition and exploration projects. Over the last several years, we have principally used acquisitions to build our base of production, proved reserves and cash flow while continuing our exploration and development programs. Key items related to our acquisitions, drilling and operations in the last three years include:

• Acquisitions

o In late 2006, we completed the acquisition of various fields in the UK North Sea from Talisman.

o Enoch — Following our acquisition of an interest in this field in 2006, we completed the development program and began initial production in mid 2007.

• Exploration — During the last three years, we have drilled 17 exploration wells with four successes in the UK, seven in Norway and one in the U.S., including:

o Cygnus — The first of our wells in our 2006 drilling program, the Cygnus prospect, was spud in early February 2006 in the UK sector of the North Sea. In 2008 we submitted a development plan to the UK authorities and began drilling an appraisal well. We announced the success of the appraisal well in 2009.

o Columbus — In 2006, we drilled the Columbus exploratory prospect in the Central Graben region of the North Sea. We served as operator of the well. In December 2006, we completed successful testing of the well. In 2007, we drilled an appraisal well and its sidetrack effectively confirming the presence of gas/condensate bearing sands. In 2008, we submitted a development plan to the UK authorities and expect to receive approval in 2009.

o Rochelle — We began appraisal drilling in 2008 and announced successful results in 2009.

o United States — In 2008, we participated in two exploration wells in the United States. We announced first production from one well in January 2009 while the second well is still undergoing testing and evaluation.

• Producing assets — At the end of 2007, we completed a project that initiated gas production at the Njord field. Production from the Goldeneye field has continued at levels above our expectations,

Endeavour International Corporation

indicating the quality of this large gas field. Development drilling has been ongoing at Njord, Brage and Alba to maintain production levels.

Our realized price before derivatives increased 25% from 2007 to 2008 largely as a result of oil prices climbing to record levels in the summer of 2008 and gas prices in our markets improving. This substantial increase in prices in the first half of 2008 helped revenue grow from $135.9 million in 2007 to $170.8 million in 2008. With this higher revenue and strong fiscal discipline over expenses, we repaid $32.0 million in debt, spent $66.4 million in capital expenditures during 2008 and increased cash from year end by $17.6 million. At December 31, 2008, we held $31.4 million in cash and another $20.7 million in cash restricted for drilling rig commitments.

Even with the substantial growth in revenues, net income can be significantly affected by various non-cash items, such as unrealized gains and losses on our commodity derivatives, currency impact of long-term liabilities and deferred taxes. Cash flow provided by (used in) operations was $133.2 million in 2008 versus $128.5 million in 2007 and $(14.1) million in 2006. Discretionary cash flow was $120.8 million in 2008, compared to $113.0 million in 2007 and $5.1 million in 2006, respectively. This significant increase in our discretionary cash flow in the past two years has allowed us to repay debt in 2007 and 2008 while continuing to actively invest in our capital programs.

Net income available to common shareholders was $45.7 million for 2008, or $0.32 per diluted share. Net loss available to common shareholders for 2007 was $60.3 million, or $0.49 per share, reflecting the significant unrealized loss on the mark-to-market of commodity derivatives. For 2006, net loss was $8.8 million, or $0.10 per share. The net loss for 2006 reflects a significant unrealized gain on the mark-to-market of commodity derivatives.

Net income as adjusted for 2008 would have been $5.7 million without the effect of impairments, derivative transactions and currency impacts of deferred taxes. Net loss as adjusted for 2007 would have been $10.9 million, as compared to net loss as adjusted of $20.9 million in 2006. Adjusted EBITDA increased to $176.6 million in 2008, as compared to $124.1 million in 2007 and $9.2 million in 2006.

Given the significant impact that non-cash items may have on our net income, we use various measures in addition to net income, including non-financial performance indicators and non-GAAP measures as key metrics to manage our business. These key metrics demonstrate the company’s ability to maintain or grow production levels and reserves, internally fund capital expenditures and service debt as well as provide comparisons to other oil and gas exploration and production companies. These measures include, among others, debt and cash balances, production levels, oil and gas reserves, drilling results, discretionary cash flow, adjusted earnings before interest, taxes, depreciation, depletion and amortization (“Adjusted EBITDA”) and adjusted net income.

For definitions of Adjusted EBITDA and Discretionary Cash Flow, and a reconciliation of Adjusted EBITDA to net income as adjusted, please see “Reconciliation of Non-GAAP Accounting Measures.”

In connection with the Talisman Acquisition, we entered into various oil and gas derivative instruments to stabilize cash flows from the acquired assets and satisfy certain obligations under the financing agreements that funded the acquisition. Hedge accounting has not been elected for these instruments resulting in the application of mark-to-market accounting — effectively pulling forward into current periods the non-cash gains and losses from commodity price fluctuations relating to all future delivery periods. When we entered into these contracts, they covered nearly 5.2 million BOE beginning in 2007 and running through 2011 at a weighted average price of $68.35. As both oil and gas prices fell from the date we entered into the contracts through December 31, 2006, we recorded an unrealized gain of $34.5 million reflecting the decline in future commodity prices through 2011. However, in 2007, commodity prices reversed their 2006 declines, continuing to increase to record levels in the case of oil. With oil

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Endeavour International Corporation

prices reaching nearly $100 per barrel and gas prices recovering to levels close to our original contract prices, we recorded an $89.1 million unrealized loss in 2007 on contract volumes through 2011. As oil prices spiked to record levels in 2008 and then went into an unprecedented decline in the last half of the year, we recorded $77.8 million in an unrealized gain on contract volumes through 2011. We expect to continue to have fluctuations in net earnings each period as commodity prices fluctuate based on all remaining unsettled contracts at the end of each period. See Note 16 to the consolidated financial statements for additional information on these derivatives.

Revenues, Volumes and Operating Costs

Our revenues have increased significantly since 2006 primarily due to the following:

• In November 2006, we completed the Talisman Acquisition and each of 2008 and 2007 reflect a full year’s contribution of those assets.

• Similarly, our Enoch field began first production in mid 2007.

• The last three years have been turbulent times for the global oil market and, to a lesser extent, the North Sea gas markets. 2006 experienced seemingly high commodity prices, only to be followed by lower prices in 2007, new, unprecedented highs in mid 2008 and a precipitous drop by the end of 2008.

• To soften the extremes of the commodity markets, we have derivative instruments covering a portion of our anticipated sales through 2011.

• Natural production declines at certain of our fields have not been offset by infield drilling, resulting in small production decreases at certain fields.

• There was an increase in gas production from our discontinued operations at the end of 2007 with the completion of a gas project at Njord in the fourth quarter of 2007.

In general total operating costs increased from 2006 through 2008 as a result of production from the acquisitions discussed above. Operating costs per BOE declined for 2006 and 2007 due to the lower operating costs per BOE for our acquired UK properties. Operating costs per BOE increased from 2007 to 2008 primarily due to increased fuel costs at a non-operated facility where several of our fields deliver production.

The following table shows our annual average sales volumes, sales prices and average production costs.

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	Year Ended December 31,
	2008			2007			2006
Sales Volume (1):
Oil and condensate sales (Mbbl):
United Kingdom		1,032			1,274			209
Continuing operations		1,032			1,274			209
Discontinued operations - Norway		726			519			508
Total		1,758			1,793			717
Gas sales (MMcf):
United Kingdom		6,532			8,556			1,539
Continuing operations		6,532			8,556			1,539
Discontinued operations - Norway		2,322			328			203
Total		8,854			8,884			1,742
Total sales (MBOE):
United Kingdom		2,121			2,700			466
Continuing operations		2,121			2,700			466
Discontinued operations - Norway		1,113			574			542
Total		3,234			3,274			1,008
BOE per day		8,835			8,969			2,760
Physical Production Volume (1):
Total production (BOE per day)
United Kingdom		5,804			7,660			1,334
Continuing operations		5,804			7,660			1,334
Discontinued operations - Norway		3,033			1,608			1,566
Total		8,837			9,268			2,900
Realized Prices (2):
Oil and condensate price ($  per Bbl)
Before commodity derivatives	$	90.53		$	67.11		$	60.51
Effect of commodity derivatives		(14.50	)		(2.13	)		(7.63	)
Including commodity derivatives	$	76.03		$	64.98		$	52.88
Gas price ($  per Mcf)
Before commodity derivatives	$	11.44		$	6.27		$	9.30
Effect of commodity derivatives		(0.35	)		1.79			—
Including commodity derivatives	$	11.09		$	8.06		$	9.30
Equivalent oil price ($  per BOE)
Before commodity derivatives	$	80.54		$	53.78		$	59.15
Effect of commodity derivatives		(8.84	)		3.68			(5.43	)
Including commodity derivatives	$	71.70		$	57.46		$	53.72
Operating Statistics:
Operating costs ($  per BOE) (3)	$	14.40		$	12.56		$	15.45
G&A costs ($  per BOE)	$	6.07		$	6.07		$	21.76
Sales volume per employee (MBOE/employee)		52			54			17

⁽¹⁾ We record oil revenues on the sales method, i.e. when delivery has occurred. Actual production may differ based on the timing of tanker liftings. We use the entitlements method to account for sales of gas production.

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(2)	The average sales prices reflect both our continuing and discontinued operations and include realized gains and losses for derivative contracts we utilize to manage price risk related to our future cash flows.
(3)	Operating costs reflect both our continuing and discontinued operations and are costs incurred to operate and maintain our wells and related equipment and include cost of labor, well service and repair, location maintenance, power and fuel, transportation, cost of product and production related general and administrative costs.

DD&A and Impairment of Oil and Gas Properties

Decreased DD&A expense from 2007 to 2008 reflects the impact of a decrease in production from 2007 to 2008 partially offset by an increase in the DD&A rate. DD&A expense increased from 2006 to 2007 as a result of the acquisitions discussed above. In addition, DD&A for 2006 includes $1.2 million related to the impairment of our intangible asset.

In 2008, we recorded $37.0 million in impairment of oil and gas properties, pre-tax, through the application of the full cost ceiling test at year-end. The prices used to determine the impairment were $36.55 per barrel for oil and $8.70 per Mcf for gas. While our commodity derivatives had a fair value of $31.0 million at December 31, 2008, these derivatives were not included in the calculation of the full cost ceiling test as the derivatives are not accounted for as cash flow hedges.

During 2006, we recorded $0.8 million in impairment of oil and gas properties related to the abandonment costs of a well impaired in 2005.

General and Administrative Expenses

Our net G&A expenses have decreased since 2006 as we have been able to absorb our expanded operations without a corresponding increase in the number of employees. We had 62 employees at December 31, 2008, 61 employees at December 31, 2007, and 58 employees at December 31, 2006. Gross cash G&A expense increases since 2006 reflect increased foreign currency exchange rates, additional payroll taxes and salary expense related to the changes in staffing, occupancy costs and fees. Occupancy costs increased due to additional office leases at our four locations. Accounting, legal and tax consulting fees fluctuated with our acquisition and financing activity. Non-cash stock-based compensation decreased as a result of the final vesting of grants given in prior years, current year forfeitures and declining fair values on each year’s grants. Components of G&A expenses for these periods are as follows:

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Endeavour International Corporation

(Amounts in thousands)	Year Ended December 31,
	2008			2007			2006
Compensation	$	11,203		$	10,181		$	9,214
Consulting, legal and accounting fees		4,679			5,045			3,387
Occupancy costs		1,130			994			507
Other expenses		4,004			2,352			3,040
Total gross cash G&A expenses		21,016			18,572			16,148
Non-cash stock-based compensation		2,928			4,487			10,819
Gross G&A expenses		23,944			23,059			26,967
Less: capitalized G&A expenses		(8,012	)		(7,206	)		(9,322	)
Net G&A expenses	$	15,932		$	15,853		$	17,645

Interest Expense and Other

Interest expense increased to $23.0 million in 2008 primarily as a result of $4.3 million in expenses, including $2.1 million in cash, related to the early repayment of the second lien term loan. Interest expense increased to $19.3 million for 2007 versus only $8.6 million in 2006, reflecting the various debt instruments issued to fund the Talisman Acquisition. Interest income results from our investments of excess cash in short-term commercial paper and money market accounts.

Other income (expense) for 2006 includes $3.8 million in financing costs paid in connection with the Talisman Acquisition and $1.8 million impairment of long-term marketable securities with the remainder primarily representing foreign currency exchange losses.

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Endeavour International Corporation

Income Taxes

The following summarizes the components of tax expense (benefit):

										Total			Discontinued
										Continuing			Operations -
(Amounts in thousands)	UK			U.S.			Other			Operations			Norway			Total
Year Ended December 31, 2008
Net income (loss) before taxes	$	66,129		$	(11,969	)	$	(4,185	)	$	49,975		$	63,244		$	113,219
Current tax expense		11,158			—			10			11,168			27,879			39,047
Deferred tax expense		22,673			—			303			22,976			15,415			38,391
Foreign currency gains on deferred tax liabilities		(10,028	)		—			—			(10,028	)		(10,681	)		(20,709	)
Total tax expense		23,803			—			313			24,116			32,613			56,729
Net income (loss) after taxes	$	42,326		$	(11,969	)	$	(4,498	)	$	25,859		$	30,631		$	56,490
Year Ended December 31, 2007
Net income (loss) before taxes	$	(68,704	)	$	(10,233	)	$	6,584		$	(72,353	)	$	14,095		$	(58,258	)
Current tax (benefit) expense		2,898			(3	)		289			3,184			562			3,746
Deferred tax (benefit) expense		(27,430	)		—			711			(26,719	)		8,951			(17,768	)
Foreign currency losses on deferred tax liabilities		1,327			—			—			1,327			3,514			4,841
Total tax (benefit) expense		(23,205	)		(3	)		1,000			(22,208	)		13,027			(9,181	)
Net income (loss) after taxes	$	(45,499	)	$	(10,230	)	$	5,584		$	(50,145	)	$	1,068		$	(49,077	)
Year Ended December 31, 2006
Net income (loss) before taxes	$	33,275		$	(23,463	)	$	13		$	9,825		$	7,250		$	17,075
Current tax (benefit) expense		1,837			(45	)		69			1,861			9,014			10,875
Deferred tax (benefit) expense		10,105			—			—			10,105			(1,840	)		8,265
Foreign currency losses on deferred tax liabilities		2,904			—			—			2,904			1,869			4,773
Total tax (benefit) expense		14,846			(45	)		69			14,870			9,043			23,913
Net income (loss) after taxes	$	18,429		$	(23,418	)	$	(56	)	$	(5,045	)	$	(1,793	)	$	(6,838	)

Our income tax expense relates primarily to operations in the UK and our discontinued operations in Norway. Income tax expense in 2008 represents the significant increase in revenues as a result of higher realized prices, the strengthening of the U.S. dollar versus the UK pound and Norwegian kroner and the shift in anticipated capital expenditures from late 2008 to early 2009.

During 2007, we incurred taxes in all of the jurisdictions in which we do business, except for the U.S., whereas in 2006, we incurred taxes only on our discontinued Norwegian operations. After closing the Talisman Acquisition in 2006, we began recording tax expense (benefit) for our UK operations and removed the valuation allowances previously recorded. The change in income taxes from an expense of $23.9 million in 2006 to a benefit of $9.2 million in 2007 resulted from the impact of the mark-to-market changes on our derivatives and the activity of our UK operations. At December 31, 2008, we had net operating loss carryforwards of $61.6 million in the U.S.

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In 2008, 2007 and 2006, we have not recorded any income tax benefits in the U.S. as there was no assurance that we could generate any U.S. taxable earnings, resulting in a full valuation allowance of deferred tax assets generated.

As our deferred tax liabilities in the UK and the Netherlands are denominated in their respective currencies, we revalue those deferred tax liabilities to the applicable foreign currency exchange rate at the end of each period. Those foreign currency gains and losses are included in income tax expense.

Capital Program

We originally anticipated spending approximately $90 million during 2008 to fund oil and gas exploration and development in the North Sea. With delays in timing for delivery of the necessary drilling rigs, certain projects were delayed or rescheduled until 2009. We spent $88.5 million, $87.9 million and $56.6 million on oil and gas capital, excluding acquisitions, in 2008, 2007 and 2006, respectively. We spent $15 million to $20 million each year on development activities at our producing properties. The remaining costs were spent on exploration and appraisal activities, including $5.5 million in 2008 related to our new operations in the United States.

Liquidity and Capital Resources

(Amounts in thousands)	December 31, 2008			December 31, 2007
Cash	$	31,421		$	13,810
Restricted cash, related to rig commitments		20,739			22,000
Debt, including current maturities		(227,855	)		(266,250	)
Debt, net of cash	$	(175,695	)	$	(230,440	)

	Year Ended December 31,
(Amounts in thousands)	2008			2007			2006
Net cash provided by (used in):
Operating activities	$	133,180		$	128,506		$	(14,100	)
Investing activities	$	(64,851	)	$	(108,140	)	$	(427,118	)
Financing activities	$	(46,613	)	$	(43,740	)	$	403,369

Operating, Investing and Financing Activities include the net cash flows from our discontinued operations. For the years ended December 31, 2008, 2007 and 2006, our discontinued operations had net cash flows provided by (used in) operating activities of approximately $38.8 million, $26.3 million and $(1.4) million, respectively. These net cash flows were substantially offset by net cash used by investing activities of approximately $34.7 million, $25.5 million and $10.7 million during 2008, 2007 and 2006, respectively. We do not expect the sale of our discontinued operations to have a material effect on cash flows in 2009, excluding the proceeds from the sale.

In addition to cash flows from operations, we have utilized issuances of debt and equity securities to enhance our liquidity and support the execution of our strategic objectives. Significant issuances and repayments of debt and equity, as well as the uses of the net proceeds, in 2008, 2007 and 2006 were as follows:

• repaid the outstanding balance of the second lien term loan in the first quarter of 2008;

• issued $40 million of the 11.5% convertible bonds in the first quarter of 2008;

• in the fourth quarter of 2006 in conjunction with the Talisman Acquisition, we issued

• 37.8 million shares of common stock for $89 million in gross proceeds,

• 125,000 shares of Series C Convertible Preferred Stock for $125 million in gross proceeds,

• $150 million in a senior bank debt facility, before financing costs of $3.2 million, and

• $75 million in a second lien term loan, before financing costs of $2.6 million.

See Note 9 to the Consolidated Financial Statements for additional discussion of our debt.

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Cash flow from operations increased to $133.2 million for 2008 primarily due to higher realized commodity prices that were substantially offset by increased current taxes. The increased revenues generated by a full year of operations of our acquired assets were primarily responsible for the cash flows provided by operations of $128.5 million for 2007 versus the $13.2 million used by operations in 2006.

Our revenues and cash flows from operating activities are sensitive to changes in prices received for our products. Our production is sold at prevailing market prices which fluctuate in response to many factors that are outside of our control. Given the current tightly balanced supply-demand market, small variations in either supply or demand, or both, can have dramatic effects on prices we receive for our oil and natural gas production. While the market price received for oil and natural gas varies among geographic areas, oil trades in a worldwide market, whereas natural gas, which is still developing a global transportation system, is more subject to local supply and demand conditions. Consequently, price movements for all types and grades of crude oil generally move in the same direction. Natural gas prices in the North Sea have been influenced by fuel prices around the world, including crude oil and coal. These prices are also impacted by European gas supplies, particularly deliveries from Russian gas supplies. In addition, regional supply and demand issues affect gas prices. The majority of our natural gas is sold in the UK market. Market prices for both oil and natural gas were at historically high levels during 2006 and oil prices continued their high levels throughout much of 2007 and 2008. North Sea gas prices declined in the first quarter of 2007 but recovered in the second half of the year and remained strong during 2008. Both crude oil and natural gas prices have declined in 2009 as a result of the global economic decline.

Non-GAAP Measures

Net income can be significantly affected by various non-cash items, such as unrealized gains and losses on our commodity derivatives, currency impact of long-term liabilities and deferred taxes. Given the significant impact that non-cash items may have on our net income, we use various measures in addition to net income, including non-financial performance indicators and non-GAAP measures as key metrics to manage our business. These key metrics demonstrate the company’s ability to maintain or grow production levels and reserves, internally fund capital expenditures and service debt as well as provide comparisons to other oil and gas exploration and production companies. These measures include, among others, debt and cash balances, production levels, oil and gas reserves, drilling results, discretionary cash flow, adjusted earnings before interest, taxes, depreciation, depletion and amortization (“Adjusted EBITDA”) and adjusted net income.

Net Income (Loss) as Adjusted, Adjusted EBITDA and Discretionary Cash Flow are internal, supplemental measures of our performance that are not required by, or presented in accordance with, GAAP. We use these non-GAAP measures as internal measures of performance and to aid in our budgeting and forecasting processes. We view these non-GAAP measures, and we believe that others in the oil and gas industry view these, or similar, non-GAAP measures, as commonly used analytic indicators to compare performance among companies. We further believe that these non-GAAP measures are frequently used by securities analysts, investors, and other interested parties in the evaluation of issuers, many of which present these measures when reporting their results. We believe these non-GAAP measures provide useful information to both management and investors to gain an overall understanding of our current financial performance and provide investors with financial measures that most closely align to our internal measurement processes. Since the application of mark-to-market accounting has the effect of pulling forward into current periods non-cash gains and losses related to commodity derivatives relating to future delivery periods, analysis of results of operations from one period to another can be difficult. We believe that excluding these unrealized non-cash gains and losses related to commodity derivatives and currency exchange changes provides a more meaningful representation of our economic performance in the reporting period and is therefore useful to us, investors, analysts and others in

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facilitating the analysis of our results of operations from one period to another. These measures should not be considered as measures of financial performance under GAAP, and the items excluded from these measures are significant components in understanding and assessing financial performance.

These non-GAAP measures should not be considered in isolation or as an alternative to net income, operating income or any other performance measures derived in accordance with GAAP or as alternatives to cash flows generated by operating, investing or financing activities as a measure of our liquidity. Because Net Income (Loss) as Adjusted, Adjusted EBITDA and Discretionary Cash Flow are not measurements determined in accordance with GAAP and thus susceptible to varying calculations, Net Income (Loss) as Adjusted, Adjusted EBITDA and Discretionary Cash Flow as presented may not be comparable to other similarly titled measures of other companies.

Net Income (Loss) as Adjusted, Adjusted EBITDA and Discretionary Cash Flow have limitations as an analytical tool, and you should not consider these measures in isolation, or as a substitute for analysis of our financial statement data presented in the consolidated financial statements as reported under GAAP. For example, Net Income (Loss) as Adjusted, Adjusted EBITDA and Discretionary Cash Flow may not reflect:

• our cash expenditures, or future requirements, for capital expenditures or contractual commitments;

• changes in, or cash requirements for, our working capital needs;

• unrealized gains (losses) on derivatives;

• non-cash foreign currency gains (losses);

• our interest expense, or the cash requirements necessary to service interest and principal payments on our debts;

• our preferred stock dividend requirements; and

• depreciation, depletion and amortization.

Because of these limitations, Net Income (Loss) as Adjusted, Adjusted EBITDA and Discretionary Cash Flow should not be considered as measures of cash available to us to invest in the growth of our business. We compensate for these limitations by relying primarily on our GAAP results and by using Net Income (Loss) as Adjusted, Adjusted EBITDA and Discretionary Cash Flow only supplementally.

As required under Regulation G of the Securities Exchange Act of 1934, provided below are reconciliations of net income (loss) to the following non-GAAP financial measures: net income as adjusted, Adjusted EBITDA and discretionary cash flow.

(in thousands, except per share)	December 31,
	2008			2007			2006
Net income (loss)	$	56,490		$	(49,077	)	$	(6,838	)
Depreciation, depletion and amortization		81,734			76,850			20,164
Impairment of oil and gas properties		36,970			—			849
Deferred tax expense (benefit)		17,682			(12,926	)		13,038
Unrealized (gain) loss on derivative instruments		(76,666	)		89,132			(34,531	)
Amortization of non-cash compensation		3,226			4,968			11,573
Amortization of loan costs and discount		7,279			1,655			731
Other		(5,940	)		2,373			154
Discretionary cash flow	$	120,775		$	112,975		$	5,140

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Endeavour International Corporation

(in thousands, except per share)	December 31,
	2008			2007			2006
Net income (loss) to common shareholders, as reported	$	45,681		$	(60,315	)	$	(8,829	)
Impairment of oil and gas properties (net of 50% tax)		18,485			—			424
Unrealized (gains) losses on commodity derivatives (net of 50% tax)		(38,923	)		44,566			(17,266	)
Unrealized (gains) losses on embedded derivatives		1,180			—			—
Currency impact of deferred taxes		(20,709	)		4,842			4,773
Net income (loss) to common shareholders as adjusted	$	5,714		$	(10,907	)	$	(20,898	)
Net income (loss) to common shareholders, as reported	$	45,681		$	(60,315	)	$	(8,829	)
Unrealized (gains) losses on derivatives		(76,666	)		89,132			(34,531	)
Net interest expense		21,301			16,430			5,676
Depreciation, depletion and amortization		81,734			76,850			20,164
Impairment of oil and gas properties		36,970			—			849
Income tax expense (benefit)		56,729			(9,180	)		23,913
Preferred stock dividends		10,809			11,238			1,991
Adjusted EBITDA	$	176,558		$	124,155		$	9,233

Discretionary cash flow is equal to cash flow from operating activities before the changes in operating assets and liabilities.

Outlook

2009 Capital Program

We currently anticipate spending approximately $50 - $60 million during 2009 to fund oil and gas exploration, production and development activities in our core areas of operation in the North Sea and the U.S., excluding our discontinued operations. As in 2008, we intend to finance this capital program through our cash flow generated from operations. To the extent our cash flow from operations is unable to completely finance our capital program, we will postpone certain proposed capital projects until our capital spending does not exceed our available resources. However, we believe our existing production base, combined with our commodity derivatives in place, should generate sufficient cash flows to fund our ongoing operations and capital program.

A significant portion of our 2009 capital program will be directed towards developing our three major projects in the UK sector of the North Sea, the Rochelle, Cygnus and Columbus prospects. In addition, we expect to spend approximately $12 million to $15 million on infield drilling and facilities improvements to maintain production levels on our producing properties. Lastly, we also intend to continue our exploration activities in both the North Sea and the US, subject to the availability of sufficient capital.

The timing, completion and process of our 2009 capital program is subject to a number of factors, including availability of capital, drilling results, drilling and production costs, availability of drilling services and equipment, partner approvals and

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technical work. Based on these and other factors, we may increase or decrease our planned capital program or prioritize certain projects over others.

Revenues and Production

We expect production for 2009 to range from 4,000 to 5,000 BOE per day, with approximately 50% of that production as gas. We anticipate this decline in production from 2008 due to normal production declines and the suspension of production at three of our fields as discussed below. With development programs for Columbus, Cygnus and Rochelle, we expect significant increases in production beginning in the fourth quarter of 2010 when we anticipate the start of production at Rochelle. We anticipate Columbus and Cygnus to begin production in 2011. When all three projects are fully producing, they have the potential to equal our 2008 production levels from all other fields.

Our IVRRH, Renee and Rubie fields all produce to a single floating production facility that has experienced significant increases in operating costs in recent periods. With the decline in oil prices and the rising operating costs, the operator has decided to cease operations and begin removal and salvage procedures at that floating production facility. As a result, we expect to suspend production at these fields by the end of the first quarter 2009. The production from these fields will be suspended until the development activities at Rochelle are operational which we currently anticipate to be late 2010. After the start of Rochelle production, we expect to re-develop IVRRH, Renee and Rubie if economically feasible. We also expect to incur approximately $10 million of abandonment costs for the facility, before salvage value, by mid 2010.

Oil prices continued to be impacted by supply and demand on a worldwide basis, while natural gas prices are more impacted by regional economic and weather patterns. Oil prices continue to decrease since year-end 2008 and natural gas prices in the UK, the market for the majority of our gas production, have recovered due primarily to return to normal weather conditions. For 2009, we expect realized prices before derivatives to be $0.10 - $0.20 per Mcf less than the National Balance Point price for gas and $5.50 - $6.50 per Bbl less than the Dated Brent price for oil. We have commodity derivative instruments to secure our realized prices for a portion of our oil and gas production through 2011. See Note 16 to the Consolidated Financial Statements herein for more discussion of our commodity derivative instruments.

We expect operating costs per BOE to be in the range of $9.50 to $12.00 per BOE for 2009. Commodity prices can also affect our operating cash flow through an indirect effect on operating expenses. Significant commodity price volatility, as experienced in recent years, can lead to fluctuations in drilling and development activities. As a result, the demand and cost for people, services, equipment and materials may also increase or decrease following worldwide drilling levels, causing an impact on our cash flow.

Liquidity and Financial Resources

Our primary sources of financial resources and liquidity are internally generated cash flows from operations and access to the credit and capital markets, to the extent available. We believe the combination of our available cash on hand, cash flow from operations, our ability to time capital expenditures and our flexible 2009 capital program and related obligations will allow us to manage volatile markets while enabling us to further our strategic objectives.

We expect to fund our 2009 capital requirements through internally generated cash flow from operations. These cash flows will be significantly impacted by the amount of hydrocarbons we produce, and to a lesser extent, the price we obtain for our produced commodities. Oil prices continue to be impacted by supply and demand on a worldwide basis, while natural gas prices are more impacted by regional

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economic and weather patterns. Although oil prices have declined significantly since the record high prices in the summer of 2008, natural gas prices in the UK and Norway have not experienced as steep of a decline. While we expect revenues to decline from 2008 to 2009 as a result of the sharp decline in oil prices, the full impact on our cash flows will be partially mitigated by our balance of gas to oil production and our commodity derivative positions. As of December 31, 2008, our outstanding commodity derivatives covered 55% to 65% of expected 2009 production.

We have historically utilized a combination of borrowings under our bank facility and accessing the capital markets to fund our operations, capital projects or strategic acquisitions. The worldwide credit and capital markets have recently experience significant disruptions and exhibited adverse conditions. Continued volatility in the credit and capital markets may substantially restrict our ability to access these markets or increase costs associated with issuing debt instruments due to, among other things, increased spreads over relevant interest rate benchmarks and affect our ability to access those markets. We do not believe our liquidity has been materially affected by the recent events in the global financial markets as we have not required these financing alternatives. Further, we do not expect our liquidity to be materially impacted in the near future as we intend to exercise strict fiscal discipline in matching our future expenditures with cash flow from operations. Nevertheless, we will continue to monitor our capital requirements, the credit and capital markets and circumstances surrounding each of the lenders in our senior bank facility. To date we have experienced no disruptions in our ability to access additional funding through our senior facility. However, we cannot predict with any certainty the impact to us of any further disruption in the credit environment.

At December 31, 2008, we had $113 million outstanding under our senior bank facility. The senior bank facility has a current borrowing base capacity of $126 million, which is secured by our oil and gas assets. The borrowing base is subject to redetermination every six months (on April 1 and October 1), and we are required to provide our lenders with an independent reserve report every 12 months. Based on our reserve report at December 31 and June 30 each year, commodity prices set by our lenders and terms set forth in the credit agreement, the maximum capacity of our borrowing base is set, and any amounts outstanding over the redetermined borrowing base must be repaid within 45 days of the redetermination date. The senior bank facility is also subject to maximum commitment levels by the participating lenders that change over time.

We have reflected $13 million in current maturities of long-term debt at December 31, 2008 due to the borrowing base capacity and maximum commitment levels. The next scheduled redetermination of our borrowing base will occur on April 1, 2009. We are currently undergoing the redetermination process based on our reserve report as of December 31, 2008. We cannot estimate the level of the borrowing base capacity that will be in effect as of April 1, 2009 although we do expect the borrowing base capacity to decrease given the decline in commodity prices during 2008. We expect to repay amounts outstanding in excess of the redetermined borrowing base with cash on hand. This will reduce the amount of cash on hand that is immediately available for our capital program. Consistent with our strict financial discipline, we continue to manage our capital expenditures to stay within generated cash flows while anticipating additional debt repayments.

The terms of our credit agreement provide that the borrowing base capacity may be increased as projects are approved by the applicable authority. We currently have submitted development plans for approval for both our Cygnus and Columbus projects and anticipate submitting a plan for the Rochelle development during 2009. As these development plans are approved, we expect to include the new projects in the borrowing base assets and believe that this will result in an increase of our borrowing base capacity.

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The senior bank facility also provides for issuances of letters of credit of up to an aggregate $60 million. While all letters of credit issued under the senior bank facility will reduce the total amount available for drawing under the senior bank facility, letters of credit issued to secure abandonment liabilities in respect of borrowing base assets will not reduce the amount available under the borrowing base. As of December 31, 2008, we have $30.1 million of outstanding letters of credit related to abandonment liabilities on certain of our oil and gas properties.

In January 2008, we completed the refinancing of certain debt utilizing a strategic investment by the Smedvig Family Office in Norway. Included in this refinancing were: the repayment of our Second Lien Term Loan, plus accrued interest; issuance of $40 million under a private offering of 11.5% guaranteed convertible bonds due 2014; and borrowing of $25 million under a Junior Credit Facility. Amounts borrowed under the Junior Facility were repaid in full during 2008. The Smedvig Family also committed an additional $60 million for future investments with us.

Our income tax expense relates primarily to our operations in the UK (statutory income tax rate of 50%) and to our operations in Norway (statutory income tax rate of 78%). We are currently not able to record income tax benefits on our U.S. loss as there is no assurance that we can generate any U.S. taxable earnings. As operations commence in the U.S. during 2009, we will be able to record income tax benefits in the U.S. and do not anticipate paying current taxes in the U.S.

Off-Balance Sheet Arrangements

At December 31, 2008, we did not have any off-balance sheet arrangements.

Rig Commitments

Our rig commitments reflect two commitments for the use of drilling rigs in our North Sea operations. Our continuing operations include one commitment for the drilling rig that commenced drilling at the Rochelle field in December 2008. We have $21 million in escrow toward this commitment, included in “Restricted cash” on our Condensed Consolidated Balance Sheet. The reserved amounts in escrow will be released as payments are made for this drilling activity.

Our discontinued operations included a commitment for a semi-submersible rig in Norway through a consortium with several other operators in the Norwegian Continental Shelf. The contract committed us to 100 days (for two wells) for drilling services for $38 million. We estimated the rig to be initially delivered in the third quarter of 2009 and again in 2010.

Critical Accounting Policies and Estimates

The accompanying financial statements have been prepared on the accrual basis of accounting in accordance with accounting principles generally accepted in the United States of America and have been presented on a going concern basis, which contemplates the realization of assets and satisfaction of liabilities in the normal course of business. These accounting principles require management to use estimates, judgments and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements, and revenues and expenses during the reporting period. Management reviews its estimates, including those related to the determination of proved reserves, estimates of future dismantlement costs, income taxes and litigation. Actual results could differ from those estimates.

Management believes it is reasonably possible that the following material estimates affecting the financial statements could change in the coming year: (1) estimates of proved oil and gas reserves, (2) estimates as

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to the expected future cash flow from proved oil and gas properties, (3) estimates of future dismantlement and restoration costs, (4) estimates of fair values used in purchase accounting and (5) estimates of the fair value of derivative instruments. In addition, alternatives may exist among various accounting methods. In such cases, the choice of accounting method may also have a significant impact on reported amounts.

Our critical accounting policies are as follows:

Full Cost Accounting

Under the full cost method, all acquisition, exploration and development costs, including certain directly related employee costs and a portion of interest expense, incurred for the purpose of finding oil and gas are capitalized and accumulated in pools on a country-by-country basis. Capitalized costs include the cost of drilling and equipping productive wells, including the estimated costs of dismantling and abandoning these assets, dry hole costs, lease acquisition costs, seismic and other geological and geophysical costs, delay rentals and costs related to such activities. Employee costs associated with production and other operating activities and general corporate activities are expensed in the period incurred.

Capitalized costs are limited on a country-by-country basis (the ceiling test). The ceiling test limitation is calculated as the sum of the present value of future net cash flows related to estimated production of proved reserves, using end-of-the-current-period prices including the effect of derivative instruments that qualify as cash flow hedges, discounted at 10%, plus the lower of cost or estimated fair value of unproved properties, all net of expected income tax effects. Under the ceiling test, if the capitalized cost of the full cost pool, net of deferred taxes, exceeds the ceiling limitation, the excess is charged as an impairment expense.

We utilize a single cost center for each country where we have operations for amortization purposes. Any conveyances of properties are treated as adjustments to the cost of oil and gas properties with no gain or loss recognized unless the operations are suspended in the entire cost center or the conveyance is significant in nature.

Unproved property costs include the costs associated with unevaluated properties and properties under development and are not included in the full cost amortization base (where proved reserves exist) until the project is evaluated. These costs include unproved leasehold acreage, seismic data, wells and production facilities in progress and wells pending determination, together with interest costs capitalized for these projects. Seismic data costs are associated with specific unevaluated properties where the seismic data is acquired for the purpose of evaluating acreage or trends covered by a leasehold interest owned by us. Significant unproved properties are assessed periodically for possible impairment or reduction in value. If a reduction in value has occurred, these property costs are considered impaired and are transferred to the related full cost pool. Geological and geophysical costs included in unproved properties are transferred to the full cost amortization base along with the associated leasehold costs on a specific project basis. Costs associated with wells in progress and wells pending determination are transferred to the amortization base once a determination is made whether or not proved reserves can be assigned to the property. Costs of dry holes are transferred to the amortization base immediately upon determination that the well is unsuccessful. Unproved properties whose acquisition costs are not individually significant are aggregated, the portion of such costs estimated to be ultimately nonproductive, based on experience, are amortized to the full cost pool over an average holding period.

In countries where the existence of proved reserves has not yet been determined, unevaluated property costs remain capitalized in unproved property cost centers until proved reserves have been established, exploration activities cease or impairment and reduction in value occurs. If exploration activities result in

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the establishment of a proved reserve base, amounts in the unproved property cost center are reclassified as proved properties and become subject to amortization and the application of the ceiling test. When it is determined that the value of unproved property costs have been permanently diminished (in part or in whole) based on the impairment evaluation and future exploration plans, the unproved property cost centers related to the area of interest are impaired, and accumulated costs charged against earnings.

We capitalize interest on expenditures for significant exploration and development projects while activities are in progress to bring the assets to their intended use. Capitalized interest is calculated by multiplying our weighted-average interest rate on debt by the amount of qualifying costs and is limited to gross interest expense. As costs are transferred to the full cost pool, the associated capitalized interest is also transferred to the full cost pool.

Business Combinations

Accounting for the acquisition of a business requires the allocation of the purchase price to the various assets and liabilities of the acquired business and recording deferred taxes for any differences between the allocated values and tax basis of assets and liabilities. Any excess of the purchase price over the amounts assigned to assets and liabilities is recorded as goodwill. In connection with the several acquisitions, we recorded goodwill for the excess of the purchase price over the value assigned to individual assets acquired and liabilities assumed. Our fair value estimates for the acquisition are subject to change as additional information becomes available and is assessed.

Purchase Price Allocation

The purchase price allocation is accomplished by recording the asset or liability at its estimated fair value. We use all available information to make these fair value determinations, including information commonly considered by our engineers in valuing individual oil and gas properties and sales prices for similar assets. Estimated deferred taxes are based on available information concerning the tax basis of the acquired company’s assets and liabilities and carryforwards at the merger date, although such estimates may change in the future as additional information becomes known. The amount of goodwill recorded in any particular business combination can vary significantly depending upon the values attributed to assets acquired and liabilities assumed relative to the total acquisition cost.

Goodwill and Intangible Assets

Goodwill represents the excess of the purchase price over the estimated fair value of the assets acquired and liabilities assumed in an acquisition. Intangible assets represent the purchase price allocation to the assembled workforce as a result of the acquisition of NSNV, Inc. We assess the carrying amount of goodwill and other indefinite-lived intangible assets by testing the asset for impairment annually at year-end, or more frequently if events or changes in circumstances indicate that the asset might be impaired. The impairment test requires allocating goodwill and all other assets and liabilities to reporting units. The fair value of each reporting unit is determined and compared to the book value of the reporting unit. An impairment loss is recognized to the extent that the carrying amount exceeds the asset’s fair value.

At December 31, 2008, we had $282 million of goodwill recorded related to past business combinations. This goodwill is not amortized, but is required to be assessed for impairment annually, or more often as facts and circumstances warrant. The first step of that process is to compare the fair value of the reporting unit to which goodwill has been assigned to the carrying amount of the associated net assets and goodwill. The reporting units used to evaluate and measure goodwill for impairment are determined from the manner in which the business is managed. We have determined we have a single reporting unit. Goodwill is tested annually at year end. Although we cannot predict when or if goodwill will be

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impaired, impairment charges may occur if we are unable to replace the value of our depleting asset base or if other adverse events (for example, lower sustained oil and gas prices) reduce the fair value of the reporting unit.

We completed our 2008 annual goodwill impairment test with no impairment indicated. To determine the fair value of the company, we worked with a valuation consulting firm and used all available information, such as market multiples, the present values of expected cash flows and the effect of the announcement of drilling results (where such drilling had begun.)

In the determination of the present value of expected cash flows, we assumed production profiles consistent with our year-end estimation of reserves that are disclosed in our supplemental oil and gas disclosures, market prices considering the forward price curve for oil and gas, adjusted for location and quality differentials that we currently receive, as well as capital and operating costs consistent with year-end pricing, adjusted for management’s view that such costs should decline in the near term to realign with lower commodity prices, and discount rates that management believes a market participant would utilize to consider the risks inherent in our operations.

We also considered our market capitalization based on average stock prices for 20 days around December 31, 2008 and any premium a buyer might pay to obtain control of Endeavour. As part of this analysis, we considered the relatively few transactions in the market, trading multiples for peers to determine an appropriate multiple to apply against our projected EBITDA, cash flows and reserves and the material results of our drilling program that were not publicly available at December 31, 2008. In the first quarter of 2009, we announced the successful drilling results of wells at our Cygnus and Rochelle projects and the expansion of operations into the US. While these activities were initiated in 2008, the public markets were unaware of the positive outcomes until 2009. From December 31, 2008 through February 10, 2009 (the date of the last of these three announcements), our common stock price increased 50%, from $0.50 per share to $0.74 per share, respectively.

A lower fair value estimate in the future could result in impairment. Examples of factors that could cause a lower fair value estimate could be sustained declines in prices, increases in costs, and changes in discount rate assumptions due to market conditions.

Dismantlement, Restoration and Environmental Costs

We recognize liabilities for asset retirement obligations associated with tangible long-lived assets, such as producing well sites, offshore production platforms, and natural gas processing plants, with a corresponding increase in the related long-lived asset. The asset retirement cost is depreciated along with the property and equipment in the full cost pool. The asset retirement obligation is recorded at fair value and accretion expense, recognized over the life of the property, increases the liability to its expected settlement value. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded for both the asset retirement obligation and the asset retirement cost.

Revenue Recognition

We use the entitlements method to account for sales of gas production. We may receive more or less than our entitled share of production. Under the entitlements method, if we receive more than our entitled share of production, the imbalance is treated as a liability at the market price at the time the imbalance occurred. If we receive less than our entitled share, the imbalance is recorded as an asset at the lower of the current market price or the market price at the time the imbalance occurred. Oil revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred, title has transferred and collectibility of the revenue is probable.

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Derivative Instruments and Hedging Activities

From time to time, we may utilize derivative financial instruments to hedge cash flows from operations or to hedge the fair value of financial instruments. We may use derivative financial instruments with respect to a portion of our oil and gas production or a portion of our variable rate debt to achieve a more predictable cash flow by reducing our exposure to price fluctuations. These transactions are likely to be swaps, collars or options and to be entered into with major financial institutions or commodities trading institutions. Derivative financial instruments are intended to reduce our exposure to declines in the market prices of crude oil and natural gas that we produce and sell, to increases in interest rates and to manage cash flows in support of our annual capital expenditure budget. We also have two embedded derivatives related to our debt instruments.

We record all derivatives at fair market value in our Consolidated Balance Sheets at the end of each period. The accounting for the fair market value, and the changes from period to period, depends on the intended use of the derivative and the resulting designation. This evaluation is determined at each derivative’s inception and begins with the decision to account for the derivative as a hedge, if applicable. The accounting for changes in the fair value of a derivative instrument that is not accounted for as a hedge is included in other (income) expense as an unrealized gain or loss. Where we intend to account for a derivative as a hedge, we document, at its inception, the hedging relationship, the risk management objective and the strategy for undertaking the hedge. The documentation includes the identification of the hedging instrument, the hedged item or transaction, the nature of the risk being hedged, and the method that will be used to assess effectiveness of derivative instruments that receive hedge accounting treatment.

Changes in fair value to hedge instruments, to the extent the hedge is effective, are recognized in other comprehensive income until the forecasted transaction occurs. Hedge effectiveness is assessed at least quarterly based on total changes in the derivative’s fair value. Any ineffective portion of the derivative instrument’s change in fair value is recognized immediately in other (income) expense.

We discontinue hedge accounting prospectively when (1) we determine that the derivative is no longer effective in offsetting changes in the fair value or cash flows of a hedged item (including hedged items such as firm commitments or forecasted transactions); (2) the derivative expires; (3) it is no longer probable that the forecasted transaction will occur; (4) a hedged firm commitment no longer meets the definition of a firm commitment; or (5) management determines that designating the derivative as a hedging instrument is no longer appropriate.

Income Taxes

We use the liability method of accounting for income taxes under which deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities, and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized as part of the provision for income taxes in the period that includes the enactment date. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion of, or all of, the deferred tax assets will not be realized.

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Stock-Based Compensation Arrangements

We recognize all share-based payments to employees, including grants of employee stock options, based on their fair values. The share-based compensation cost is measured at the grant date, based on the calculated fair value of the award, and is recognized as general and administrative expense over the employee’s requisite service period (generally the vesting period of the equity award). We apply the fair value method in accounting for stock option grants to non-employees using the Black-Scholes Method.

It is our policy to use authorized but unissued shares of stock when stock options are exercised. At December 31, 2008, we had approximately 7.7 million additional shares available for issuance pursuant to our existing stock incentive plan.

Fair Value

We estimate fair value for the measurement of derivatives, long-lived assets during certain impairment tests, reporting units for goodwill impairment testing and the initial measurement of an asset retirement obligation. When we are required to measure fair value, and there is not a market observable price for the asset or liability, or a market observable price for a similar asset or liability, we generally utilize an income valuation approach. This approach utilizes management’s best assumptions regarding expectations of projected cash flows, and discounts the expected cash flows using a commensurate risk adjusted discount rate. Such evaluations involve a significant amount of judgment since the results are based on expected future events or conditions, such as sales prices; estimates of future oil and gas production; development and operating costs and the timing thereof; economic and regulatory climates and other factors. Our estimates of future net cash flows are inherently imprecise because they reflect management’s expectation of future conditions that are often outside of management’s control. However, assumptions used reflect a market participant’s view of long-term prices, costs and other factors, and are consistent with assumptions used in our business plans and investment decisions.

Recent Accounting Pronouncements

In December 2007, the FASB issued enhanced guidance related to the measurement of identifiable assets acquired, liabilities assumed and disclosure of information related to business combinations and their effect. The standard applies prospectively to business combinations in 2009 and is not subject to early adoption. We are currently evaluating the potential impact of this new guidance on business combinations and related valuations.

In December 2007, the FASB issued a new standard for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. Specifically, this statement requires the recognition of a noncontrolling interest (minority interest) as a component of consolidated equity. This is a change from the current practice to present noncontrolling interests in liabilities or between liabilities and stockholders’ equity. Similarly, the new standard requires consolidated net income and comprehensive income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interests. The standard is effective prospectively with respect to transactions involving noncontrolling financial interests that occur on or after January 1, 2009. We are currently evaluating the potential impact, if any, of this new guidance.

In March 2008, the FASB issued a new standard that requires entities to present expanded and detailed financial statement disclosures for their derivatives and hedged financial instruments. This standard applies to all derivatives and non-derivative instruments designated and qualifying as hedges, including bifurcated derivative instruments and related hedged items. The new standard is effective for interim

19

Endeavour International Corporation

periods and fiscal years beginning after November 15, 2008. We do not expect the adoption of this pronouncement to have a material impact on our financial position or results of operations.

In May 2008, the FASB posted a new staff position that applies to convertible debt that may be settled in part or in whole in cash upon conversion. The new staff position requires required issuers of this form of debt to account for its debt and equity components separately. The new position also expands the definition of convertible preferred shares of an entity’s stock that are mandatorily redeemable financial instruments classified as liabilities. The new FASB staff position is effective for financial statements issued for fiscal years after December 15, 2008 and interim period within those fiscal years. It must be applied retroactively to all presented periods. We are currently evaluating the potential impact, if any, of this new guidance.

In June 2008, the FASB issued a new staff position that addresses whether instruments that are granted in share-based payment transactions are participating securities prior to vesting; and therefore are required to be included in the earnings allocation in the calculation of earnings per share (EPS) under the two-class method as described in a prior FASB standard. The new staff position requires entities to treat unvested share-based payment awards with non-forfeitable rights to dividend or dividend equivalents as a separate class of securities in calculating EPS. The new staff position is effective for fiscal years beginning after December 15, 2008. We are currently evaluating the potential impact, if any, of this new guidance.

Disclosures about Contractual Obligations and Commercial Commitments

The following table sets forth our obligations and commitments for continuing operations to make future payments under its lease agreements and other long-term obligations as of December 31, 2008:

(Amounts in thousands)	Payments due by Period
			Less than 1
Contractual Obligations	Total		Year		1-3 Years		3-5 Years		After 5 Years
Long-term debt
Principal (1)	$	238,746	$	13,000	$	100,000	$	81,250	$	44,496
Interest (2)		55,839		7,766		13,125		406		34,542
Asset retirement obligations		38,776		9,680		160		160		28,776
Operating leases for office leases and equipment		2,743		1,157		1,349		237		—
Rig commitments (3)		20,739		20,739		—		—		—
Total Contractual Obligations	$	356,843	$	52,342	$	114,634	$	82,053	$	107,814

(1)	Repayment of the initial borrowing base on the senior bank facility is based on reserve estimates, which are reassessed every six months.
(2)	Assumes a 1.5% LIBOR rate. In addition, interest on our 11.5% convertible debt is added to the outstanding principal balance each quarter and reflected as due upon maturity.
(3)	As is common in the oil and gas industry, we operate in many instances through joint ventures under joint operating or similar agreements. Typically, the operator under a joint operating agreement enters into contracts, such as rig commitment contracts, for the benefit of all joint venture partners. Through the joint operating agreement, the non-operators reimburse, and in some cases advance, the funds necessary to meet the contractual obligations entered into by the operator. These obligations are typically shared on a “working interest” basis. The joint operating agreement provides remedies to the operator in the event that the non-operator does not satisfy its share of the contractual obligations. Occasionally, the operator is permitted by the joint operating agreement to enter into lease obligations and other contractual commitments that are

20

Endeavour International Corporation

then passed on to the non-operating joint interest owners as lease operating expenses, frequently without any identification as to the long-term nature of any commitments underlying such expenses.

21

EX-99.3

Exhibit 99.3

ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders
Endeavour International Corporation:

We have audited the accompanying consolidated balance sheets of Endeavour International Corporation and subsidiaries as of December 31, 2008 and 2007, and the related consolidated statements of operations, stockholders’ equity and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2008. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated 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 Endeavour International Corporation and subsidiaries as of December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 2 to the consolidated financial statements, effective January 1, 2007, the Company changed its accounting for uncertain tax positions. As also discussed in Note 2 to the consolidated financial statements, effective January 1, 2008, the Company changed its method of accounting and disclosures for fair value measurements and fair value reporting of financial assets and liabilities.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Endeavour International Corporation’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 13, 2009 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP
Houston, Texas
March 13, 2009, except for the effects of discontinued operations, as discussed in Note 23, which is as of January 8, 2010.

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Endeavour International Corporation
Consolidated Balance Sheets
(Amounts in thousands)

	December 31,
	2008			2007
Assets
Current Assets:
Cash and cash equivalents	$	31,421		$	13,810
Restricted cash, related to rig commitments		20,739			22,000
Accounts receivable		22,325			26,708
Prepaid expenses and other current assets		42,194			41,874
Current assets of discontinued operations		16,726			13,855
Total Current Assets		133,405			118,247
Property and Equipment, Net		232,346			273,324
Goodwill		213,949			215,330
Other Assets		9,165			11,029
Long Term Assets of Discontinued Operations		148,605			129,693
Total Assets	$	737,470		$	747,623
Liabilities and Stockholders’ Equity
Current Liabilities:
Accounts payable	$	38,630		$	25,484
Current maturities of debt		13,000			—
Accrued expenses and other		36,642			40,843
Current liabilities of Discontinued Operations		22,231			14,722
Total Current Liabilities		110,503			81,049
Long-Term Debt		214,855			266,250
Deferred Taxes		67,299			101,554
Other Liabilities		55,791			61,991
Long-term Liabilities of Discontinued Operations		46,051			41,630
Total Liabilities		494,499			552,474
Commitments and Contingencies
Series C Convertible Preferred Stock (Liquidation preference: $125,000)		125,000			125,000
Stockholders’ Equity:
Series B Preferred stock (Liquidation preference: $2,957)		—			—
Common stock; shares issued and outstanding – 128,572 at 2008 and 127,006 at 2007		129			127
Additional paid-in capital		244,471			241,539
Treasury stock		(450	)		—
Accumulated other comprehensive loss		(1,266	)		(923	)
Accumulated deficit		(124,913	)		(170,594	)
Total Stockholders’ Equity		117,971			70,149
Total Liabilities and Stockholders’ Equity	$	737,470		$	747,623

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

2

Endeavour International Corporation
Consolidated Statements of Operations
(Amounts in thousands, except per share data)

	For the Year Ended December 31,
	2008			2007			2006
Revenues	$	170,781		$	135,876		$	24,881
Expenses:
Operating expenses		32,317			27,263			4,477
Depreciation, depletion and amortization		67,326			68,982			13,831
Impairment of oil and gas properties		36,970			—			849
General and administrative		15,932			15,853			17,240
Total expenses		152,545			112,098			36,397
Operating Profit (Loss)		18,236			23,778			(11,516	)
Other Income (Expense):
Derivatives:
Unrealized gain (loss)		76,666			(89,132	)		34,531
Realized gain (loss)		(28,578	)		12,048			—
Interest expense		(22,975	)		(19,282	)		(8,571	)
Unrealized foreign currency exchange gain (loss)		5,569			(139	)		(598	)
Other		1,057			374			(4,021	)
Total Other Income (Expense)		31,739			(96,131	)		21,341
Income (Loss) Before Income Taxes		49,975			(72,353	)		9,825
Income Tax (Benefit) Expense		24,116			(22,208	)		14,870
Income (Loss) from Continuing Operations		25,859			(50,145	)		(5,045	)
Income (loss) from Discontinued Operations, net of tax		30,631			1,068			(1,793	)
Net Income (Loss)		56,490			(49,077	)		(6,838	)
Preferred Stock Dividends		10,809			11,238			1,991
Net Income (Loss) to Common Stockholders	$	45,681		$	(60,315	)	$	(8,829	)
Basic Net Income (Loss) Per Common Share:
Continuing operations	$	0.12		$	(0.50	)	$	(0.08	)
Discontinued operations		0.24			0.01			(0.02	)
Total	$	0.36		$	(0.49	)	$	(0.10	)
Diluted Net Income (Loss) per Common Share:
Continuing operations	$	0.15		$	(0.50	)	$	(0.08	)
Discontinued operations	$	0.17			0.01			(0.02	)
Total	$	0.32		$	(0.49	)	$	(0.10	)
Weighted Average Number of Common Shares Outstanding:
Basic		128,312			123,118			86,636
Diluted		178,312			123,118			86,636

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

3

Endeavour International Corporation
Consolidated Statements of Cash Flows
(Amounts in thousands)

	Year Ended December 31,
	2008			2007			2006
Cash Flows from Operating Activities:
Net income (loss)	$	56,490		$	(49,077	)	$	(6,838	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		81,734			76,850			20,164
Impairment of oil and gas properties		36,970			—			849
Deferred tax expense (benefit)		17,682			(12,925	)		13,038
Unrealized (gain) loss on derivative instruments		(76,666	)		89,132			(34,531	)
Amortization of non-cash compensation		3,226			4,968			11,573
Foreign currency exchange (gain) loss on non-operating liabilities		(10,508	)		1,078			1,012
Non-cash interest charges and other		11,879			2,948			5,396
Changes in assets and liabilities:
(Increase) Decrease in receivables		9,795			30,127			(32,165	)
(Increase) Decrease in prepaid expenses and other		(3,745	)		(984	)		(9,749	)
Increase (Decrease) in current liabilities		6,323			(13,611	)		17,151
Net Cash Provided by (Used in) Operating Activities		133,180			128,506			(14,100	)
Cash Flows From Investing Activities:
Capital expenditures		(66,370	)		(88,007	)		(55,496	)
Acquisitions, net of cash acquired		—			—			(376,915	)
(Increase) decrease in restricted cash and other investing activities		1,519			(20,133	)		5,293
Net Cash Used in Investing Activities		(64,851	)		(108,140	)		(427,118	)
Cash Flows From Financing Activities:
Repayment of borrowings		(120,000	)		(47,000	)		—
Proceeds from borrowings		88,000			7,000			225,000
Payment of preferred dividends		(10,625	)		(2,656	)		—
Financing costs paid		(3,538	)		(263	)		(9,565	)
Proceeds from common stock, net of issuance costs		—			—			83,967
Proceeds from preferred stock, net of issuance costs		—			—			100,657
Other financing activities		(450	)		(821	)		3,310
Net Cash Provided by (Used in) Financing Activities		(46,613	)		(43,740	)		403,369
Net Increase (Decrease) in Cash and Cash Equivalents		21,716			(23,374	)		(37,849	)
Effect of Foreign Currency Changes on Cash		—			—			1,536
Cash and Cash Equivalents, Beginning of Period		16,440			39,814			76,127
Cash and Cash Equivalents, End of Period	$	38,156		$	16,440		$	39,814

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

4

Endeavour International Corporation
Consolidated Statements of Stockholders’ Equity and Comprehensive Income (Loss)
(Amounts in thousands)

											Accumulated
											Other						Total			Total
	Common		Treasury		Additional			Deferred			Comprehensive			Accumulated			Stockholders’			Comprehensive
	Stock		Stock		Paid-In Capital			Compensation			Loss			Deficit			Equity			Income (Loss)
Balance, December 31, 2005	$	75	$	—	$	155,734		$	(9,437	)	$	(4,578	)	$	(101,450	)	$	40,344
Adoption of stock-based compensation accounting standards				—		(9,110	)		9,437			—			—			327
Issuance of common stock as deferred compensation		2		—		473			—			—			—			475
Exercise of warrants and options		2				3,308			—			—			—			3,310
Other issuances of common stock		40		—		89,353			—			—			—			89,393
Amortization of deferred compensation		—				11,573			—			—			—			11,573
Expenses related to Convertible Preferred Stock offering		—		—		(24,343	)		—			—			—			(24,343	)
Preferred stock dividend		—		—		—			—			—			(1,991	)		(1,991	)
Comprehensive Loss:				—
Net Loss		—		—		—			—			—			(6,838	)		(6,838	)	$	(6,838	)
Other comprehensive income (net of tax):				—
Unrealized loss on derivative instruments, net of tax		—		—		—			—			3,690			—			3,690			3,690
Unrealized gain (loss) on available-for- sale securities		—		—		—			—			888			—			888			888
Balance, December 31, 2006	$	119	$	—	$	226,988		$	—		$	—		$	(110,279	)	$	116,828		$	(2,260	)
Balance, December 31, 2006	$	119	$	—	$	226,988		$	—		$	—		$	(110,279	)	$	116,828
Preferred stock dividend		6		—		10,509			—			—			(11,238	)		(723	)
Amortization of deferred compensation		—		—		4,975			—			—			—			4,975
Other		2		—		(933	)		—			—			—			(931	)
Comprehensive Loss:
Net Loss		—		—		—			—			—			(49,077	)		(49,077	)	$	(49,077	)
Other comprehensive income (net of tax):
Unrealized loss on derivative instruments, net of tax		—		—		—			—			(852	)		—			(852	)		(852	)
Unrealized gain (loss) on available-for- sale securities		—		—		—			—			(71	)		—			(71	)		(71	)
Balance, December 31, 2007	$	127	$	—	$	241,539		$	—		$	(923	)	$	(170,594	)	$	70,149		$	(50,000	)

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

5

Endeavour International Corporation
Consolidated Statements of Stockholders’ Equity and Comprehensive Income (Loss)
(Amounts in thousands)

											Accumulated
											Other						Total			Total
	Common		Treasury			Additional			Deferred		Comprehensive			Accumulated			Stockholders’			Comprehensive
	Stock		Stock			Paid-In Capital			Compensation		Loss			Deficit			Equity			Income (Loss)
Balance, December 31, 2007	$	127	$	—		$	241,539		$	—	$	(923	)	$	(170,594	)	$	70,149
Preferred stock dividend		—		—			—			—		—			(10,809	)		(10,809	)
Amortization of deferred compensation		—		—			3,226			—					—			3,226
Treasury stock repurchase		—		(450	)		—			—		—			—			(450	)
Other		1		—			(294	)		—								(293	)
Comprehensive Loss:
Net Income		—		—			—					—			56,490			56,490		$	56,490
Other comprehensive income (net of tax):
Unrealized loss on derivative instruments, net of tax		—		—			—			—		(342	)		—			(342	)		(342	)
Unrealized gain (loss) on available-for- sale securities		—		—			—			—		(1	)		—			(1	)
Balance, December 31, 2008	$	128	$	(450	)	$	244,471		$	—	$	(1,266	)	$	(124,913	)	$	117,970		$	56,148

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

6

Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)

Note 1 – Description of Business

Endeavour International Corporation was incorporated under the laws of the state of Nevada on January 13, 2000. As used in these Notes to Consolidated Financial Statements, the terms “Endeavour”, “we”, “us”, “our” and similar terms refer to Endeavour International Corporation and, unless the context indicates otherwise, its consolidated subsidiaries.

Note 2 – Summary of Significant Accounting Policies

Basis of Presentation and Use of Estimates

The accompanying financial statements have been prepared on the accrual basis of accounting in accordance with accounting principles generally accepted in the United States of America (“US GAAP”) and have been presented on a going concern basis, which contemplates the realization of assets and satisfaction of liabilities in the normal course of business. These accounting principles require management to use estimates, judgments and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements, and revenues and expenses during the reporting period. Management reviews its estimates, including those related to the determination of proved reserves, estimates of future dismantlement costs, income taxes and litigation. Actual results could differ from those estimates. In the opinion of management, all normal recurring adjustments considered necessary for a fair presentation have been included in these financial statements. Certain amounts for prior periods have been reclassified to conform to the current presentation.

Management believes it is reasonably possible that the following material estimates affecting the financial statements could change in the coming year: (1) estimates of proved oil and gas reserves, (2) estimates as to the expected future cash flow from proved oil and gas properties, (3) estimates of future dismantlement and restoration costs, (4) estimates of fair values used in purchase accounting and (5) estimates of the fair value of derivative instruments.

Principles of Consolidation

The accompanying consolidated financial statements include all of the accounts of Endeavour and our consolidated subsidiaries. All significant intercompany accounts and transactions have been eliminated. Investments in entities over which we have significant influence, but not control, are carried at cost adjusted for equity in earnings or (losses) and distributions received.

Cash and Cash Equivalents

We consider all highly liquid instruments with an original maturity of 90 days or less at the time of purchase to be cash equivalents.

Inventories

Materials and supplies and oil inventories are valued at the lower of cost or market value (net realizable value).

1

Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)

Full Cost Accounting for Oil and Gas Operations

Under the full cost method, all acquisition, exploration and development costs, including certain directly related employee costs and a portion of interest expense, incurred for the purpose of finding oil and gas are capitalized and accumulated in pools on a country-by-country basis. Capitalized costs include the cost of drilling and equipping productive wells, including the estimated costs of dismantling and abandoning these assets, dry hole costs, lease acquisition costs, seismic and other geological and geophysical costs, delay rentals and costs related to such activities. Employee costs associated with production and other operating activities and general corporate activities are expensed in the period incurred.

Capitalized costs are limited on a country-by-country basis (the ceiling test). The ceiling test limitation is calculated as the sum of the present value of future net cash flows related to estimated production of proved reserves, using end-of-the-current-period prices including the effect of derivative instruments that qualify as cash flow hedges, discounted at 10%, plus the lower of cost or estimated fair value of unproved properties, all net of expected income tax effects. Under the ceiling test, if the capitalized cost of the full cost pool, net of deferred taxes, exceeds the ceiling limitation, the excess is charged as an impairment expense.

We utilize a single cost center for each country where we have operations for amortization purposes. Any conveyances of properties are treated as adjustments to the cost of oil and gas properties with no gain or loss recognized unless the operations are suspended in the entire cost center or the conveyance is significant in nature.

Unproved property costs include the costs associated with unevaluated properties and properties under development and are not initially included in the full cost amortization base (where proved reserves exist) until the project is evaluated. These costs include unproved leasehold acreage, seismic data, wells and production facilities in progress and wells pending determination, together with interest costs capitalized for these projects. Seismic data costs are associated with specific unevaluated properties where the seismic data is acquired for the purpose of evaluating acreage or trends covered by a leasehold interest owned by us. Significant unproved properties are assessed periodically for possible impairment or reduction in value. If a reduction in value has occurred, these property costs are considered impaired and are transferred to the related full cost pool. Geological and geophysical costs included in unproved properties are transferred to the full cost amortization base along with the associated leasehold costs on a specific project basis. Costs associated with wells in progress and wells pending determination are transferred to the amortization base once a determination is made whether or not proved reserves can be assigned to the property. Costs of dry holes are transferred to the amortization base immediately upon determination that the well is unsuccessful. Unproved properties whose acquisition costs are not individually significant are aggregated, the portion of such costs estimated to be ultimately nonproductive, based on experience, are amortized to the full cost pool over an average holding period.

In countries where the existence of proved reserves has not yet been determined, unevaluated property costs remain capitalized in unproved property cost centers until proved reserves have been established, exploration activities cease or impairment and reduction in value occurs. If exploration activities result in the establishment of a proved reserve base, amounts in the unproved property cost center are reclassified as proved properties and become subject to amortization and the application of the ceiling test. When it is determined that the value of unproved property costs have been permanently diminished (in part or in

2

Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)

whole) based on the impairment evaluation and future exploration plans, the unproved property cost centers related to the area of interest are impaired, and accumulated costs charged against earnings.

Other Property and Equipment

Other oil and gas assets, computer equipment and furniture and fixtures are recorded at cost, less accumulated depreciation. The assets are depreciated using the straight-line method over their estimated useful lives of two to five years.

Capitalized Interest

We capitalize interest on expenditures for significant exploration and development projects while activities are in progress to bring the assets to their intended use. Capitalized interest is calculated by multiplying our weighted-average interest rate on debt by the amount of qualifying costs and is limited to gross interest expense. As costs are transferred to the full cost pool, the associated capitalized interest is also transferred to the full cost pool.

Marketable Securities

The marketable securities reflected in these financial statements are deemed by management to be “available-for-sale” and, accordingly, are reported at fair value, with unrealized gains and losses reported in other comprehensive income and reflected as a separate component within the Statement of Stockholders’ Equity unless we determine that an other-than-temporary impairment has occurred. Realized gains and losses on securities available-for-sale are included in other income/expense and, when applicable, are reported as a reclassification adjustment, net of tax, in other comprehensive income. Gains and losses on the sale of available-for-sale securities are determined using the specific-identification method.

At December 31, 2006, we determined that our investment in equity securities were subject to an other-than-temporary impairment. Therefore, we recorded an impairment of $1.8 million for 2006 as we impaired the value of the equity securities to the fair market value of the securities, based on the quoted market price of the securities at December 31, 2006.

Goodwill and Intangible Assets

Goodwill represents the excess of the purchase price over the estimated fair value of the assets acquired and liabilities assumed in an acquisition. Intangible assets represent the purchase price allocation to the assembled workforce as a result of the acquisition in 2004. We assess the carrying amount of goodwill and other indefinite-lived intangible assets by testing the asset for impairment annually at year-end, or more frequently if events or changes in circumstances indicate that the asset might be impaired. The impairment test requires allocating goodwill and all other assets and liabilities to reporting units. The fair value of each reporting unit is determined and compared to the book value of the reporting unit. An impairment loss is recognized to the extent that the carrying amount exceeds the asset’s fair value.

Dismantlement, Restoration and Environmental Costs

We recognize liabilities for asset retirement obligations associated with tangible long-lived assets, such as producing well sites, offshore production platforms, and natural gas processing plants, with a

3

Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)

corresponding increase in the related long-lived asset. The asset retirement cost is depreciated along with the property and equipment in the full cost pool. The asset retirement obligation is recorded at fair value and accretion expense, recognized over the life of the property, increases the liability to its expected settlement value. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded for both the asset retirement obligation and the asset retirement cost.

Revenue Recognition

We use the entitlements method to account for sales of gas production. We may receive more or less than our entitled share of production. Under the entitlements method, if we receive more than our entitled share of production, the imbalance is treated as a liability at the market price at the time the imbalance occurred. If we receive less than our entitled share, the imbalance is recorded as an asset at the lower of the current market price or the market price at the time the imbalance occurred. Oil revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred, title has transferred and collectibility of the revenue is probable.

Significant Customers

Our oil sales are to a limited number of customers, each of which accounts for more than 10% of revenue: Chevron North Sea Ltd; Shell U.K. Limited, and Esso Exploration and Production. Our gas and natural gas liquids sales are to StatoilHydro, Shell UK Limited and Esso Exploration and Production UK Limited.

Derivative Instruments and Hedging Activities

From time to time, we may utilize derivative financial instruments to hedge cash flows from operations or to hedge the fair value of financial instruments. We may use derivative financial instruments with respect to a portion of our oil and gas production or a portion of our variable rate debt to achieve a more predictable cash flow by reducing our exposure to price fluctuations. These transactions are likely to be swaps, collars or options and to be entered into with major financial institutions or commodities trading institutions. Derivative financial instruments are intended to reduce our exposure to declines in the market prices of crude oil and natural gas that we produce and sell, to increases in interest rates and to manage cash flows in support of our annual capital expenditure budget. We also have two embedded derivatives related to our debt instruments.

We record all derivatives at fair market value in our Consolidated Balance Sheets at the end of each period. The accounting for the fair market value, and the changes from period to period, depends on the intended use of the derivative and the resulting designation. This evaluation is determined at each derivative’s inception and begins with the decision to account for the derivative as a hedge, if applicable. The accounting for changes in the fair value of a derivative instrument that is not accounted for as a hedge is included in other (income) expense as an unrealized gain or loss. Where we intend to account for a derivative as a hedge, we document, at its inception, the hedging relationship, the risk management objective and the strategy for undertaking the hedge. The documentation includes the identification of the hedging instrument, the hedged item or transaction, the nature of the risk being hedged, and the method that will be used to assess effectiveness of derivative instruments that receive hedge accounting treatment.

Changes in fair value to hedge instruments, to the extent the hedge is effective, are recognized in other comprehensive income until the forecasted transaction occurs. Hedge effectiveness is assessed at least

4

Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)

quarterly based on total changes in the derivative’s fair value. Any ineffective portion of the derivative instrument’s change in fair value is recognized immediately in other (income) expense.

We discontinue hedge accounting prospectively when (1) we determine that the derivative is no longer effective in offsetting changes in the fair value or cash flows of a hedged item (including hedged items such as firm commitments or forecasted transactions); (2) the derivative expires; (3) it is no longer probable that the forecasted transaction will occur; (4) a hedged firm commitment no longer meets the definition of a firm commitment; or (5) management determines that designating the derivative as a hedging instrument is no longer appropriate.

Concentrations of Credit and Market Risk

Financial instruments that potentially subject us to concentrations of credit risk consist principally of cash deposits at financial institutions. At various times during the year, we may exceed the federally insured limits. To mitigate this risk, we place our cash deposits only with high credit quality institutions. Management believes the risk of loss is minimal.

Derivative financial instruments that hedge the price of oil and gas, interest rates or currency exposure will be generally executed with major financial or commodities trading institutions which expose us to market and credit risks, and may at times be concentrated with certain counterparties or groups of counterparties. Although notional amounts are used to express the volume of these contracts, the amounts potentially subject to credit risk, in the event of non-performance by the counterparties, are substantially smaller. We review the credit ratings of our counterparties to derivative contracts (who are all lenders under our senior bank facility) on a regular basis and to date we have not experienced any non-performance by any of our counterparties, currently BNP Paribas S.A. and J. Aron & Company, a subsidiary of Goldman Sachs International. At December 31, 2008, our derivative instruments do not require either side to maintain collateral or margin accounts.

As an independent oil and gas producer, our revenue, profitability and future rate of growth are substantially dependent upon prevailing prices for oil and gas, which are dependent upon numerous factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. The energy markets have historically been very volatile, and there can be no assurance that oil and gas prices will not be subject to wide fluctuations in the future. A substantial or extended decline in oil and gas prices could have a material adverse effect on our financial position, results of operations, cash flows and our access to capital and on the quantities of oil and gas reserves that may be economically produced.

Foreign Currency Translation

The U.S. dollar is the functional currency for all of our existing operations, as a majority of all revenue and financing transactions in these operations are denominated in U.S. dollars. For foreign operations with the U.S. dollar as the functional currency, monetary assets and liabilities are remeasured into U.S. dollars at the exchange rate on the balance sheet date. Nonmonetary assets and liabilities are translated into U.S. dollars at historical exchange rates. Income and expense items are translated at exchange rates prevailing during each period. Adjustments are recognized currently as a component of foreign currency gain or loss and deferred income taxes. To the extent that business transactions are not denominated in U.S. dollars, we are exposed to foreign currency exchange rate risk.

5

Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)

Income Taxes

We use the liability method of accounting for income taxes under which deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities, and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized as part of the provision for income taxes in the period that includes the enactment date. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion of, or all of, the deferred tax assets will not be realized.

Share-Based Payments

We recognize all share-based payments to employees, including grants of employee stock options, based on their fair values. The share-based compensation cost is measured at the grant date, based on the calculated fair value of the award, and is recognized as general and administrative expense over the employee’s requisite service period (generally the vesting period of the equity award). We apply the fair value method in accounting for stock option grants using the Black-Scholes Method.

It is our policy to use authorized but unissued shares of stock when stock options are exercised. At December 31, 2008, we had approximately 7.7 million additional shares available for issuance pursuant to our existing stock incentive plan.

Adoption of Accounting for Uncertainty in Income Taxes

In July 2006, the Financial Accounting Standards Board issued a new interpretation that seeks to reduce the diversity in practice associated with certain aspects of measurement and recognition in accounting for income taxes. This new interpretation also provides guidance on classification, derecognition, interest, penalties and accounting in interim periods and also requires expanded disclosure with respect to the uncertainty in income taxes. The interpretation was effective for us as of January 1, 2007. Our adoption of this standard on January 1, 2007 did not have a material effect on our financial statements. We recognize interest and/or penalties related to income tax matters in income tax expense.

Adoption of Fair Value Standards

On January 1, 2008, we applied the new standard that permits entities to choose to measure many financial instruments and certain other items at fair value. This standard expanded the use of fair value measurement and applied to entities that elect the fair value option. The adoption of this pronouncement did not have a material impact on our financial position or results of operations.

On January 1, 2008, we applied the new standards which defined fair value, established a framework for measuring fair value in generally accepted accounting principles and expanded disclosures about fair value measurements. The new standards does not require new fair value measurements, rather, its provisions apply when fair value measurements are performed under other accounting pronouncements.

In February 2008, the standard was deferred for one year as it applies to nonfinancial assets and liabilities that are recognized or disclosed at fair value on a nonrecurring basis (e.g. those measured at fair value in a

6

Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)

business combination and goodwill impairment). We are reviewing the potential impact, if any, of this new guidance.

Recent Accounting Pronouncements

In December 2007, the FASB issued enhanced guidance related to the measurement of identifiable assets acquired, liabilities assumed and disclosure of information related to business combinations and their effect. The standard applies prospectively to business combinations in 2009 and is not subject to early adoption. We are currently evaluating the potential impact of this new guidance on business combinations and related valuations.

In December 2007, the FASB issued a new standard for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. Specifically, this statement requires the recognition of a noncontrolling interest (minority interest) as a component of consolidated equity. This is a change from the current practice to present noncontrolling interests in liabilities or between liabilities and stockholders’ equity. Similarly, the new standard requires consolidated net income and comprehensive income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interests. The standard is effective prospectively with respect to transactions involving noncontrolling financial interests that occur on or after January 1, 2009. We are currently evaluating the potential impact, if any, of this new guidance.

In March 2008, the FASB issued a new standard that requires entities to present expanded and detailed financial statement disclosures for their derivatives and hedged financial instruments. This standard applies to all derivatives and non-derivative instruments designated and qualifying as hedges, including bifurcated derivative instruments and related hedged items. The new standard is effective for interim periods and fiscal years beginning after November 15, 2008. We do not expect the adoption of this pronouncement to have a material impact on our financial position or results of operations.

In May 2008, the FASB posted a new staff position that applies to convertible debt that may be settled in part or in whole in cash upon conversion. The new staff position requires required issuers of this form of debt to account for its debt and equity components separately. The new position also expands the definition of convertible preferred shares of an entity’s stock that are mandatorily redeemable financial instruments classified as liabilities. The new FASB staff position is effective for financial statements issued for fiscal years after December 15, 2008 and interim period within those fiscal years. It must be applied retroactively to all presented periods. We are currently evaluating the potential impact, if any, of this new guidance.

In June 2008, the FASB issued a new staff position that addresses whether instruments that are granted in share-based payment transactions are participating securities prior to vesting; and therefore are required to be included in the earnings allocation in the calculation of earnings per share (EPS) under the two-class method as described in a prior FASB standard. The new staff position requires entities to treat unvested share-based payment awards with non-forfeitable rights to dividend or dividend equivalents as a separate class of securities in calculating EPS. The new staff position is effective for fiscal years beginning after December 15, 2008. We are currently evaluating the potential impact, if any, of this new guidance.

7

Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)

Note 3 – Earnings per Share

Basic loss per common share is computed by dividing net loss to common stockholders by the weighted average number of common shares outstanding for the period. Diluted loss per share includes the effect of our outstanding stock options, warrants and shares issuable pursuant to convertible debt, convertible preferred stock and certain stock incentive plans under the treasury stock method, if including such instruments is dilutive.

	December 31,
	2008		2007			2006
Net income (loss) to common stockholders
Basic	$	45,681	$	(60,315	)	$	(8,829	)
Add Effect of:
Preferred dividends		10,625		—			—
Diluted	$	56,306	$	(60,315	)	$	(8,829	)
Weighted Average Number of Common Shares Outstanding:
Basic		128,312		123,118			86,636
Add Effect of:
				—			—
Preferred stock		50,000		—			—
Diluted		178,312		123,118			86,636

For each of the periods presented, shares associated with stock options, warrants, convertible debt, convertible preferred stock and certain stock incentive plans are not included because their inclusion would be antidilutive (i.e., reduce the net loss per share). The common shares potentially issuable arising from these instruments, which were outstanding during the periods presented in the financial statements, consisted of:

	December 31,
	2008		2007		2006
Options and stock-based compensation		2		—		626
Warrants		—		—		219
Convertible debt		32,725		16,185		16,185
Convertible preferred stock		—		50,000		8,356
Common shares potentially issuable		32,727		66,185		25,386

Note 4 – Acquisitions and Dispositions

Acquisition of Talisman Expro Limited

On November 1, 2006, we completed the acquisition of all of the outstanding shares of Talisman Expro Limited for US $366 million, after purchase price adjustments and expenses (the “Talisman

8

Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)

Acquisition”). As a result of the Talisman Acquisition, we acquired interests in eight fields in the United Kingdom sector of the North Sea.

The following is an allocation of the purchase price of the Talisman Acquisition:

Purchase price	$	359,594
Legal, accounting and other direct expenses		6,051
Total purchase price	$	365,645
Allocation of purchase price:
Current assets	$	30,373
Property and equipment		209,534
Goodwill		254,147
Current liabilities		(14,345	)
Deferred tax liability		(89,175	)
Other long-term liabilities		(24,889	)
	$	365,645

The purchase price allocation is based on an assessment of the fair value of the assets acquired and liabilities assumed in the Talisman Acquisition. The assessment of the fair values of oil and gas properties acquired was based on projections of expected future net cash flows, discounted to present value. Other assets and liabilities were recorded at their historical book values which we believe represent the best current estimate of fair value.

The following is a reconciliation of the changes in goodwill for the year ended December 31, 2008 and 2007:

	December 31,
	2008		2007
Balance at beginning of year	$	283,324	$	291,752
Acquisition		1,225		(8,428	)
Balance at end of year	$	284,549	$	283,324

$68.0 million in goodwill has been allocated to our discontinued operations. See Footnote 23.

Purchase of Interest in Enoch Field

During the second quarter of 2006, we invested $12 million for the purchase of an eight percent interest in the Enoch Field located in Block 16/13a in the North Sea.

9

Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)

Note 5 – Prepaid Expenses and Other Current Assets

Prepaid expenses and other current assets consisted of the following:

	December 31,
	2008		2007
Current deferred tax asset	$	—	$	30,167
Fair market value of commodity derivatives – current		31,649		4,018
Prepaid insurance		1,322		1,255
Inventory		5,109		1,426
Current tax receivable		—		4,083
Other		4,114		925
	$	42,194	$	41,874

Note 6 – Property and Equipment

Property and equipment included the following:

	December 31,
	2008			2007
Oil and gas properties under the full cost method:
Subject to amortization	$	239,024		$	244,906
Not subject to amortization:
Acquired in 2008		37,288			—
Acquired in 2007		14,746			23,366
Acquired in 2006		70,368			90,177
Acquired prior to 2006		12,154			16,013
		373,580			374,462
Other oil and gas activities		4,875			4,875
Computers, furniture and fixtures		3,236			2,027
Total property and equipment		381,691			381,364
Accumulated depreciation, depletion and amortization		(149,345	)		(108,040	)
Net property and equipment	$	232,346		$	273,324

The majority of costs not subject to amortization relate to values assigned to unproved reserves acquired. The remainder of costs not subject to amortization relate to exploration costs such as drilling costs for projects awaiting approved development plan or the determination of whether or not proved reserves can be assigned and other seismic and geological and geophysical costs. These costs are transferred to the amortization base when it is determined whether or not proved reserves can be assigned to such properties. This analysis is dependent upon well performance, results of infield drilling, approval of development plans, drilling results and development of identified projects and periodic assessment of reserves. We expect acquisition costs excluded from amortization to be transferred to the amortization base over the next five years due to a combination of well performance and results of infield drilling

10

Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)

relating to currently producing assets and the drilling and development of identified projects acquired, such as the Rochelle field. We expect exploration costs not subject to amortization to be transferred to the amortization base over the next three years as development plans are completed and production commences on existing discoveries such as the Columbus, Cygnus and Rochelle projects.

The following is a summary of our oil and gas properties not subject to amortization as of December 31, 2008:

	Costs Incurred in the Year Ended December 31,
	2008		2007		2006		Prior to 2006		Total
Acquisition costs	$	803	$	—	$	48,816	$	—	$	49,619
Exploration costs		32,645		11,319		21,552		12,152		77,668
Capitalized interest		3,840		3,427		—		—		7,267
Total oil and gas properties not subject to amortization	$	37,288	$	14,746	$	70,368	$	12,152	$	134,554

During 2008, 2007 and 2006, we capitalized $8.0 million, $7.2 million and $9.3 million, respectively, in certain directly related employee costs. During 2008, 2007 and 2006, we capitalized $4.0 million, $6.4 million and $0.5 million, respectively, in interest.

Note 7 – Other Assets

Other long-term assets consisted of the following at December 31:

	2008			2007
Intangible assets – workforce in place:
Gross	$	4,800		$	4,800
Accumulated amortization		(3,363	)		(2,806	)
		1,437			1,994
Debt issuance costs		5,714			6,857
Fair market value of long-term portion of commodity derivatives		1,702			1,957
Other		312			221
	$	9,165		$	11,029

Intangible assets represent the purchase price allocated to the assembled workforce as a result an acquisition. During 2006, one of our co-chief executive officers became chairman of the board, president and chief executive officer. Concurrently, our other co-chief executive officer became vice chairman of the board and ceased being our employee although he continued in a consultancy role during 2007. As a result, we assessed the carrying amount of the intangible asset related to our workforce-in-place and determined an impairment of $1.2 million, included in DD&A expense, was necessary. The remaining value of the intangible asset is being amortized over its estimated life of six years using the straight-line method. Estimated amortization expense is $0.6 million for each year through December 31, 2010.

Debt issuance costs are amortized over the life of the related debt obligation.

11

Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)

Note 8 – Accrued Expenses

We had the following accrued expenses outstanding:

	December 31,
	2008		2007
Derivative liability	$	1,193	$	22,495
Foreign taxes payable		6,655		5,249
Deferred foreign taxes payable		15,825		—
Accrued interest		30		4,751
Preferred dividends		1,011		828
Accrued compensation		2,135		754
Crude oil imbalance		8,954		—
Other		839		6,766
	$	36,642	$	40,843

Note 9 – Debt and Notes Payable

Our debt and notes payable consisted of the following:

	December 31,
	2008			2007
Senior notes, 6% fixed rate, due 2012	$	81,250		$	81,250
Senior bank facility, variable rate, due 2011		113,000			110,000
Convertible bonds, due 2014		44,496			—
Second lien term loan, variable rate, due 2011		—			75,000
		238,746			266,250
Less: debt discount		(10,891	)		—
Less: current maturities		(13,000	)		—
Long-term debt	$	214,855		$	266,250

Principal maturities of debt at December 31, 2008 are as follows:

2009	$	13,000
2010		—
2011		100,000
2012		125,746
2013		—
Thereafter		—

6% Senior notes, due 2012

During 2005, we issued in a private offering $81.25 million aggregate principal amount of convertible senior notes due 2012. The notes bear interest at a rate of 6.00% per annum, payable in January and July. The notes are convertible into shares of our common stock at an initial conversion rate of 199.2032 shares

12

Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)

of common stock per $1,000 principal amount of notes, subject to adjustment, which represents an initial conversion price of approximately $5.02 per share. In connection with the issuance of these notes, we paid $3.6 million in financing and other costs. Upon specified change of control events, each holder of those notes may require us to purchase all or a portion of the holder’s notes at a price equal to 100% of the principal amount, plus accrued and unpaid interest, if any, up to but excluding the date of purchase.

Senior bank facility

As part of the financing for the Talisman Acquisition during the fourth quarter of 2006, we entered into a $225 million senior bank facility, subject to a borrowing base limitation. The borrowing base is subject to redetermination every six months with an independent reserve report required every 12 months. At December 31, 2008, the borrowing base capacity was $126 million, of which $113 million was outstanding. The senior bank facility also provides for issuances of letters of credit of up to an aggregate $60 million. While all letters of credit issued under the senior bank facility will reduce the total amount available for drawing under the senior bank facility, letters of credit issued to secure abandonment liabilities in respect of borrowing base assets will not reduce the amount available under the borrowing base. As of December 31, 2008, we have $30.1 million of outstanding letters of credit related to abandonment liabilities on certain of our oil and gas properties.

Indebtedness under the facility will be secured by cross guarantees from all of our subsidiaries, share pledges from all of our subsidiaries, floating charges over the operating assets held in the United Kingdom and a receivables pledge in Norway. Our borrowings under the senior bank facility will bear interest at LIBOR plus 1.3% for the first $112 million of availability, and LIBOR plus 1.7% for up to an additional $14 million of availability.

The senior bank facility contains customary covenants, which limit our ability to incur indebtedness, pledge our assets, dispose of our assets and make exploration and appraisal expenditures. In addition, the senior bank facility contains various financial and technical covenants, including:

• a maximum consolidated debt to earnings before interest, taxes, depreciation and amortization (“EBITDA”) ratio of 3.0:1;

• a minimum current assets to current liabilities ratio of 1.1:1;

• a minimum debt coverage ratio of 1.2:1 for the initial tranche and 1.15:1 for the second tranche;

• a minimum field life net present value (“NPV”) to loans outstanding coverage ratio of 1.4:1 for the period through March 31, 2009 and 1.5:1 thereafter for the initial tranche, and 1.25:1 for the period through March 31, 2009 and 1.3:1 thereafter for the second tranche; and

• a minimum loan life NPV to loans outstanding coverage ratio of 1.2:1 for the period through March 31, 2009 and 1.3:1 thereafter for the initial tranche, and 1.15:1 for the period through March 31, 2009 and 1.2:1 thereafter for the second tranche.

The final maturity is the earlier of five years or the reserve tail date, being the date when the remaining borrowing base reserves are projected to be 20% or less of the initially approved borrowing base reserves. The senior bank facility is subject to mandatory prepayment in the event of a change of control of any obligor under the senior bank facility agreement. It is prepayable at our option at any time without penalty.

At December 31, 2008, we had $113 million outstanding under our senior bank facility. The senior bank facility has a current borrowing base capacity of $126 million, which is secured by our oil and gas assets. The borrowing base is subject to redetermination every six months (on April 1 and October 1), and we are

13

Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)

required to provide our lenders with an independent reserve report every 12 months. Based on our reserve report at December 31 and June 30 each year, commodity prices set by our lenders and terms set forth in the credit agreement, the maximum capacity of our borrowing base is set, and any amounts outstanding over the redetermined borrowing base must be repaid within 45 days of the redetermination date. The senior bank facility is also subject to maximum commitment levels by the participating lenders that change over time.

We have reflected $13 million in current maturities of long-term debt at December 31, 2008 due to the borrowing base capacity and maximum commitment levels. The next scheduled redetermination of our borrowing base will occur on April 1, 2009. We are currently undergoing the redetermination process based on our reserve report as of December 31, 2008. We cannot estimate the level of the borrowing base capacity that will be in effect as of April 1, 2009 although we do expect the borrowing base capacity to decrease given the decline in commodity prices during 2008.

Second lien term loan

As part of the financing for the Talisman Acquisition during the fourth quarter of 2006, we entered into a $75 million second lien term loan. In January 2008, we terminated our obligations under this loan and repaid all of our outstanding indebtedness, including accrued interest and related fees.

Convertible Bonds

In January 2008, we issued 11.5% Convertible Bonds due 2014 (the “Convertible Bonds”) for gross proceeds of $40 million pursuant to a private offering to a sophisticated investor in Norway. The net proceeds from the issuance of the Convertible Bonds was used to repay a portion of our outstanding indebtedness. The $40 million Convertible Bonds bear interest at a rate of 11.5% per annum, compounded quarterly, and are unconditionally guaranteed by us on a senior unsecured basis. Interest is compounded quarterly and added to the outstanding principal balance each quarter. Interest is not payable in cash, but is instead payable in kind upon maturity of the bonds. The bonds are convertible into shares of our common stock at an initial conversion price of $2.36 per $1,000 of principal. The conversion price will be adjusted in accordance with the terms of the bonds upon occurrence of certain events, including payment of common stock dividends, common stock splits or issuance of common stock at a price below the then current market price.

Upon the fourth anniversary, the holders have the right to redeem the Convertible Bonds if the weighted average closing price of our common stock for the preceding 30 days is less than the conversion price, as adjusted. If the holders do not exercise this right, the right will lapse and the conversion price will be reset to the then current market price of our common stock if such price is lower than the conversion price, as adjusted.

If we undergo a “change of control” as defined, the holders of the bonds have the right, subject to certain conditions, to redeem the bonds and accrued interest. The bonds may become immediately due upon the occurrence of certain events of default, as defined.

Two derivatives are associated with the conversion and change in control features of the Convertible Bonds. At December 31, 2008, the combined fair market value of these derivatives is $14.6 million, reflecting a $0.7 million decrease during 2008 that was recorded in unrealized gains (losses) on derivatives.

14

Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)

Note 10 – Income Taxes

The loss before income taxes and the components of the income tax expense recognized on the Consolidated Statement of Income are as follows:

										Total			Discontinued
										Continuing			Operations -
	UK			U.S.			Other			Operations			Norway			Total
Year Ended December 31, 2008
Net income (loss) before taxes	$	66,129		$	(11,969	)	$	(4,185	)	$	49,975		$	63,244		$	113,219
Current tax expense		11,158			—			10			11,168			27,879			39,047
Deferred tax expense		22,673			—			303			22,976			15,415			38,391
Foreign currency gains on deferred tax liabilities		(10,028	)		—						(10,028	)		(10,681	)		(20,709	)
Total tax expense		23,803			—			313			24,116			32,613			56,729
Net income (loss) after taxes	$	42,326		$	(11,969	)	$	(4,498	)	$	25,859		$	30,631		$	56,490
Year Ended December 31, 2007
Net income (loss) before taxes	$	(68,704	)	$	(10,233	)	$	6,584		$	(72,353	)	$	14,095		$	(58,258	)
Current tax (benefit) expense		2,898			(3	)		289			3,184			562			3,746
Deferred tax (benefit) expense		(27,430	)		—			711			(26,719	)		8,951			(17,768	)
Foreign currency losses on deferred tax liabilities		1,327			—			—			1,327			3,514			4,841
Total tax (benefit) expense		(23,205	)		(3	)		1,000			(22,208	)		13,027			(9,181	)
Net income (loss) after taxes	$	(45,499	)	$	(10,230	)	$	5,584		$	(50,145	)	$	1,068		$	(49,077	)

15

Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)

									Total			Discontinued
									Continuing			Operations -
	UK		U.S.			Other			Operations			Norway			Total
Year Ended December 31, 2006
Net income (loss) before taxes	$	33,275	$	(23,463	)	$	13		$	9,825		$	7,250		$	17,075
Current tax (benefit) expense		1,837		(45	)		69			1,861			9,014			10,875
Deferred tax (benefit) expense		10,105		—			—			10,105			(1,840	)		8,265
Foreign currency losses on deferred tax liabilities		2,904		—			—			2,904			1,869			4,773
Total tax (benefit) expense		14,846		(45	)		69			14,870			9,043			23,913
Net income (loss) after taxes	$	18,429	$	(23,418	)	$	(56	)	$	(5,045	)	$	(1,793	)	$	(6,838	)

The following table presents the principal reasons for the difference between our effective tax rates and the United States federal statutory income tax rate of 35%.

	Year Ended December 31,
	2008			2007			2006
Federal income tax expense (benefit) at statutory rate	$	17,491		$	(25,323	)	$	3,439
Taxation of foreign operations		12,464			(1,790	)		6,292
Change in valuation allowance – US		4,150			3,515			8,286
Change in valuation allowance – UK		—			—			(6,013	)
Foreign currency (gain)/loss on deferred taxes		(10,028	)		1,328			2,904
Other		39			62			(38	)
Income Tax Expense, continuing operations	$	24,116		$	(22,208	)	$	14,870
Discontinued operations - Norway		32,613			13,027			9,043
Total Income Tax Expense		56,729			(9,181	)		23,913
Effective Income Tax Rate		45	%		(32	)%		117	%

During 2008, 2007 and 2006, we incurred taxes in all of the jurisdictions that we do business in except for the U.S. In 2008, 2007 and 2006, we had a loss before taxes of $8.3 million, $6.9 million and $20.6 million, respectively, in the U.S. and we did not record any income tax benefits as there was no assurance that we could generate any U.S. taxable earnings, and therefore recorded a valuation allowance of the full amount of deferred tax asset generated.

Deferred income taxes result from the net tax effects of temporary timing differences between the carrying amounts of assets and liabilities reflected on the financial statements and the amounts recognized for income tax purposes. The tax effects of temporary differences that give rise to significant portions of deferred tax assets and liabilities are as follows at December 31:

16

Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)

	2008			2007
Deferred tax asset:
Deferred compensation	$	5,771		$	6,834
Unrealized loss on derivative instruments		4,506			27,292
Asset retirement obligation		5,244			13,808
Net operating loss and capital loss carryforward		21,633			37,820
Other		621			1,767
Total deferred tax assets		37,775			87,521
Less valuation allowance		(23,701	)		(19,697	)
Total deferred tax assets after valuation allowance		14,074			67,824
Deferred tax liability:
Property, plant and equipment		(67,810	)		(133,367	)
Unrealized gain on derivative instruments		(23,628	)		—
Petroleum revenue tax, net of tax benefit		(1,642	)		(5,133	)
Debt discount		(3,267	)		—
Other		(850	)		(711	)
Total deferred tax liabilities		(97,197	)		(139,211	)
Net deferred tax liability	$	(83,123	)	$	(71,387	)

During 2006, we recognized a deferred tax liability of approximately $98 million due to the excess of book over tax basis of the assets acquired in the Enoch and Talisman acquisitions.

At December 31, 2008, we had the following carryforwards available to reduce future income taxes:

	Years of		Carryforward
Types of Carryforward	Expiration		Amounts
Continuing Operations - U.S. – Net operating loss		2022 - 2028	$	61,613
Discontinued Operations - Norway – Uplift	Indefinite		$	2,700

With the exception of $61.6 million of net operating loss carryforward attributable to our U.S. operations for which a valuation allowance has been established, the remaining carryforward amounts shown above have been recognized for financial statement reporting purposes to reduce deferred tax liability.

For U.S. federal income tax purposes, certain limitations are imposed on an entity’s ability to utilize its NOLs in future periods if a change of control, as defined for federal income tax purposes, has taken place. In general terms, the limitation on utilization of NOLs and other tax attributes during any one year is determined by the value of an acquired entity at the date of the change of control multiplied by the then-existing long-term, tax-exempt interest rate. The manner of determining an acquired entity’s value has not yet been addressed by the Internal Revenue Service. We have determined that, for federal income tax purposes, a change of control occurred during 2004. However, we do not believe such limitations will significantly impact our ability to utilize the NOL; rather our ability to generate future taxable income will have such an impact.

Recognition of the benefits of the deferred tax assets will require that we generate future taxable income. There can be no assurance that we will generate any earnings or any specific level of earnings in future years. Therefore, we have established a valuation allowance for deferred tax assets of approximately $23.7 million, $19.7 million and $17.3 million of December 31, 2008, 2007 and 2006, respectively.

17

Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)

During 2008, the valuation allowance in the U.S. increased $2.9 million due to net operating losses and increased $1.1 million for net operating losses in other jurisdictions. During 2007, the valuation allowance in the U.S. increased $2.4 million due to net operating losses and adjustments. During 2006, the valuation allowance decreased $6.0 million when our UK operations commenced and decreased an additional $11.1 million as a result of the deferred tax liabilities established in the purchase of Enoch and Talisman. The valuation allowance also increased $7.3 due to net operating losses in the U.S.

Effective January 1, 2007, we adopted the new guidance on uncertainty in income taxes. We determined there was no cumulative effect on our financial statements relating to this adoption.

At December 2007, we provided for a liability of $1.7 million for unrecognized tax benefits relating to various U.K. matters. The statute of limitations for assessing tax for these benefits expired during 2008, thus allowing the full recognition of these benefits. The benefit was recorded as a reduction to goodwill.

The following represents a reconciliation of the changes in our unrecognized tax benefits, included in “Accrued Expenses and Other” on the balance sheet, for the year ended December 31, 2008:

Balance at January 1, 2008	$	1,727
Increase (Decrease) in unrecognized tax benefits from current period tax positions		(1,727	)
Balance at December 31, 2008	$	—

As of December 31, 2008, we believe that no current tax positions that have resulted in unrecognized tax benefits will significantly increase or decrease within the next year.

Note 11 – Other Liabilities

Other liabilities included the following:

	December 31,
	2008		2007
Asset retirement obligations	$	38,776	$	30,790
Long-term derivative liabilities		17,015		31,201
	$	55,791	$	61,991

Our asset retirement obligations relate to obligation of the plugging and abandonment of oil and gas properties. The asset retirement obligation is recorded at fair value and accretion expense, recognized over the life of the property, increases the liability to its expected settlement value. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded for both the asset retirement obligation and the asset retirement cost. The following table provides a rollforward of the asset retirement obligations for the year ended December 31, 2008 and 2007:

18

Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)

	December 31,
	2008			2007
Carrying amount of asset retirement obligations as of beginning of year	$	30,790		$	26,284
Increase (decrease) due to revised estimates of asset retirement obligations		13,840			1,621
Accretion expense		2,795			2,764
Impact of foreign currency exchange rate changes		(8,649	)		121
Carrying amount of asset retirement obligations as of end of year	$	38,776		$	30,790

Note 12 – Equity

The activity in shares of our common and preferred stock during 2008, 2007 and 2006 included the following:

	Year Ended December 31,
	2008			2007		2006
Common Stock:
Outstanding at the beginning of the year		127,006			118,577		75,489
Issuance of common stock in the offering		—			—		39,257
Issuance of common stock to pay preferred dividends		—			6,403		—
Exercise of warrants and stock options		—			—		1,655
Other issuances		1,566			2,026		2,176
Outstanding at the end of the year		128,572			127,006		118,577
Series B Preferred Stock:
Outstanding at the end of the year		20			20		20
Convertible Preferred Stock:
Outstanding at the beginning of the year		125			125		—
Issuances of preferred stock		—			—		125
Outstanding at the end of the year		125			125		125
Treasury Stock:
Outstanding at the beginning of the year		—			—		—
Purchase of Treasury shares for stock vesting		(327	)		—		—
Outstanding at the end of the year		(327	)		—		—

Common Stock

The Common Stock is $0.001 par value common stock, 300,000,000 shares authorized.

In 2008, we issued inducement grants of 300,000 shares of Endeavour restricted common stock, and options to purchase 250,000 shares of our common stock at an exercise price of $0.75 per share upon commencement of employment of one executive officer. In 2007, we issued inducement grants of 800,000 shares of Endeavour restricted common stock, options to purchase 400,000 shares of our common stock at an exercise price of $2.00 per share and options to purchase 200,000 shares of our

19

Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)

common stock at an exercise price of $1.14 per share upon commencement of employment of two executive officers.

As part of the financing for the Talisman Acquisition during the fourth quarter of 2006, we issued 37.8 million shares of common stock at $2.35 per share. After expenses, proceeds from the offering were $84 million.

Convertible Preferred Stock

As part of the financing for the Talisman Acquisition during the fourth quarter of 2006, we issued $125 million of Series A Convertible Preferred Stock to a group of private institutional investors. In December 2006, our stockholders approved the conversion of the Series A Convertible Preferred Stock into the Series C Convertible Preferred Stock (the “Convertible Preferred Stock”). The Series A Convertible Preferred Stock and the Series C Convertible Preferred Stock are substantially similar in terms, except that the Series C Convertible Preferred Stock includes a “full-ratchet” antidilution protection provision, which would result in a favorable adjustment (in the number of shares of common stock issuable on conversion and the conversion price) for the holders of Convertible Preferred Stock in the event we were to issue shares of common stock at a price below the conversion price. The Convertible Preferred Stock ranks senior to any of our other existing or future shares of capital stock.

The Convertible Preferred Stock is fully convertible into common stock at any time at the option of the preferred stock investors, at (i) a conversion price of $2.50 (the “Conversion Price”) and (ii) in an amount of common stock equal to the quotient of the liquidation preference of $1,000 per share plus accrued but unpaid dividends (the “Liquidation Preference”) divided by the Conversion Price.

Dividends are payable in cash, or common stock if we are unable to pay such dividends in cash, and any dividends will be paid to the preferred stock investors prior to payment of any other dividend on any other shares of our capital stock. We will pay a cumulative dividend on the Convertible Preferred Stock equal to 8.5% per annum of the original issue price (compounded quarterly) if paid in cash and 8.92% per annum of the original issue price (compounded quarterly) if paid in stock (the “Original Dividend Rate”). The Convertible Preferred Stock also participates on an as-converted basis with respect to any dividends paid on the common stock.

Issuance of dividends in the form of common stock are subject to the following equity conditions (the “Equity Conditions”), which are waivable by two-thirds of the holders of the Convertible Preferred Stock: (i) such common stock is listed on the NYSE Alternext US LLC, the New York Stock Exchange or the Nasdaq Stock Market, and not subject to any trading suspension; (ii) we are not then subject to any bankruptcy event; and (iii) such common stock will be immediately re-saleable by the preferred stock investors pursuant to an effective registration statement and otherwise in compliance with all applicable laws. If we have not maintained the effectiveness of the registration statement pursuant to the Registration rights section below, then the dividend rate on the Convertible Preferred Stock will be increased by the product of 2.5% (if the dividend is paid in cash) or 2.63% (if the dividend is paid in stock) times the number of quarters (or portions thereof) in which the failure occurs or we fail to cure such failure.

After the fourth anniversary of the initial issuance of the Convertible Preferred Stock, we may redeem all of the Convertible Preferred Stock in exchange for a cash payment to the preferred stock investors of an amount equal to 102% of the sum of the Liquidation Preference. If we call the Convertible Preferred Stock for redemption, the holders thereof will have the right to convert their shares into a newly issued

20

Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)

preferred stock identical in all respects to the Convertible Preferred Stock except that such newly issued preferred stock will not bear a dividend (the “Alternate Preferred Stock”). We may not redeem the Convertible Preferred Stock if the Equity Conditions are not then satisfied with respect to the common stock into which the Alternate Preferred Stock is convertible.

Upon the tenth anniversary of the initial issuance of the Convertible Preferred Stock, we must redeem all of the Convertible Preferred Stock for an amount equal to the Liquidation Preference plus accrued and unpaid dividends payable by us in cash or common stock at our election. Issuance by us of common stock for such redemption is subject to the Equity Conditions and to the market value of the outstanding shares of common stock immediately prior to such redemption equaling at least $500 million.

In the event of a change of control of Endeavour, we will be required to offer to redeem all of the Convertible Preferred Stock for the greater of: (i) the amount equal to which such holder would be entitled to receive had the holder converted such Convertible Preferred Stock into common stock; (ii) 115% of the sum of the Liquidation Preference plus accrued and unpaid dividends; and (iii) the amount resulting in an internal rate of return to such holder of 15% from the date of issuance of such Convertible Preferred Stock through the date that Endeavour pays the redemption price for such shares.

Series B Preferred Stock

In September 2002, we authorized and designated 500,000 shares of Preferred Stock, as Series B Preferred Stock par value $.001 per share.

The Series B Preferred Stock is to pay dividends of 8% of the original issuing price per share per annum, which are cumulative prior to any dividends on the common stock and on parity with the payment of any dividend or other distribution on any other series of preferred stock that has similar characteristics. The holders of each share of Series B Preferred Stock are entitled to be paid out of available funds prior to any distributions to holders of common stock in the amount of $100.00 per outstanding share plus all accrued dividends. We may, upon approval of our Board, redeem all or a portion of the outstanding shares of Series B preferred stock at a cost of the liquidation preference and all accrued and unpaid dividends.

Note 13 – Stock-Based Compensation Arrangements

We grant restricted stock and stock options, including notional restricted stock and options, to employees and directors as incentive compensation. The notional restricted stock and options may be settled in cash or stock upon vesting, at our option, however it has been our practice to settle in stock. The restricted stock and options generally vest over three years and the options have a five to ten year expiration. The vesting of these shares and options is dependent upon the continued service of the grantees to Endeavour. Upon the occurrence of a change in control, each share of restricted stock and stock option outstanding on the date on which the change in control occurs will immediately become vested.

The fair value of each option award is estimated on the date of grant using the Black-Scholes option-pricing model. For the years 2007 and 2006, expected volatility is based on an average of our peer companies where there is a lack of relevant Endeavour volatility information for the length of the expected term and the expected term is the average of the vesting date and the expiration of the option. For 2008, expected volatility is based on historical Endeavour volatility for the length of the expected term, which was determined by historical data. We use historical data to estimate option exercises and employee terminations within the valuation model. The risk-free rate for periods within the contractual

21

Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)

life of the option is based on the U.S. treasury yield curve in effect at the time of grant. We do not include an estimated dividend yield since we have not paid dividends on our common stock historically.

The estimated fair value of each option granted was calculated using the Black-Scholes model. The following summarizes the weighted average of the assumptions used in the method.

	2008			2007			2006
Risk free rate		3.1	%		4.4	%		4.4	%
Expected years until exercise		4			4			4
Expected stock volatility		46	%		45	%		38	%
Dividend yield		—			—			—

At December 31, 2008, total compensation cost related to nonvested awards not yet recognized was approximately $4.1 million and is expected to be recognized over a weighted average period of less than two years. For the year ended December 31, 2008, we included approximately $0.8 million of stock-based compensation in capitalized G&A in property and equipment.

Stock Options

Information relating to stock options, including notional stock options, is summarized as follows:

			Weighted		Weighted
			Average		Average
			Exercise		Contractual		Aggregate
	Number of		Price per		Life in		Intrinsic
	Shares		Share		Years		Value
Balance outstanding – December 31, 2007		5,367	$	2.92
Granted		1,455		1.21
Exercised		—		—
Forfeited		406		3.07
Expired		1,610		3.04
Balance outstanding – December 31, 2008		4,807		2.35		3.47	$	10
Currently exercisable – December 31, 2008		2,454		2.92		0.97	$	—

The weighted average grant-date fair value of options granted during 2008, 2007 and 2006 was $0.50, $0.40 and $1.20, respectively.

Of options granted during 2008, 2007 and 2006, 1.2 million, 0.1 million and 1.0 million options, respectively, were granted pursuant to incentive plans which have been approved by our stockholders. All other stock options have been granted pursuant to stock option plans that were not subject to stockholder approval.

22

Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)

Information relating to stock options outstanding at December 31, 2008 is summarized as follows:

	Options Outstanding						Options Exercisable
			Weighted		Weighted				Weighted
			Average		Average				Average
	Number of		Remaining		Exercise				Exercise
Range of Exercise	Options		Contractual		Price Per		Number		Price Per
Prices	Outstanding		Life		Share		Exercisable		Share
Less than $3.00		3,426		4.3	$	1.66		1,444	$	1.99
$3.00 - $3.99		582		1.7	$	3.58		211	$	3.69
Greater than $4.00		799		1.1	$	4.41		799	$	4.41
		4,807		3.5	$	2.35		2,454	$	2.60

Restricted Stock

At December 31, 2008, our employees and directors held 4.0 million restricted shares of our common stock that vest over the service period of up to three years. The restricted stock awards were valued based on the closing price of our common stock on the measurement date, typically the date of grant, and compensation expense is recorded on a straight-line basis over the restricted share vesting period.

Status of the restricted shares as of December 31, 2008 and the changes during the year ended December 31, 2008 are presented below:

				Weighted
				Average Grant
	Number of			Date Fair Value
	Shares			per Share
Balance outstanding – December 31, 2007		4,539		$	2.70
Granted		2,259		$	1.22
Vested		(1,892	)	$	2.42
Forfeited		(940	)	$	3.16
Balance outstanding – December 31, 2008		3,966		$	1.88
Total fair value of shares vesting during the period	$	3,835

Note 14 – Financial Instruments

	December 31, 2008						December 31, 2007
				Carrying						Carrying
	Fair Value			Value			Fair Value			Value
Assets:
Derivative instruments	$	33,351		$	33,351		$	5,975		$	5,975
Liabilities:
Long-term debt		190,681			214,855			253,250			266,250
Derivative instruments		(18,208	)		(18,208	)		(53,696	)		(53,696	)

23

Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)

The carrying amounts reflected in the consolidated balance sheets for cash and equivalents, short-term receivables and short-term payables approximate their fair value due to the short maturity of the instruments. The fair values of commodity derivative instruments interest rate swaps and were determined based upon quotes obtained from brokers. The fair values of long-term debt were determined based upon quotes obtained from brokers for our senior notes, discounted cash flows for our 11.5% convertible debt and book value for other debt. Book value approximates fair value for our senior bank facility and second lien term loan as these instruments bear interest at a market rate.

Note 15 – Fair Value Measurements

Effective January 1, 2008, we adopted the new guidance for fair value measurements of financial assets and liabilities measured on a recurring basis. This new standard defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. It also clarifies that fair value should be based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. This includes not only the credit standing of counterparties involved and the impact of credit enhancements but also the impact of our own nonperformance risk on our liabilities. According to this new standard, fair value measurements are classified and disclosed in one of the following categories:

Level 1:	Fair value is based on actively-quoted market prices, if available.
Level 2:	In the absence of actively-quoted market prices, we seek price information from external sources, including broker quotes and industry publications. Substantially all of these inputs are observable in the marketplace during the entire term of the instrument, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace.
Level 3:	If valuations require inputs that are both significant to the fair value measurement and less observable from objective sources, we must estimate prices based on available historical and near-term future price information and certain statistical methods that reflect our market assumptions.

We apply fair value measurements to certain assets and liabilities including commodity and interest rate derivative instruments, marketable securities and embedded derivatives relating to conversion and change in control features in certain of our debt instruments. We seek to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The following table summarizes the valuation of our investments and financial instruments by pricing levels as of December 31, 2008:

24

Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)

	Quoted Market Prices		Significant Other			Significant
	in Active Markets –		Observable Inputs -			Unobservable Inputs			Total Fair
	Level 1		Level 2			- Level 3			Value
Oil and gas derivative contracts:
Oil and gas swaps	$	—	$	9,855		$	—		$	9,855
Oil and gas collars		—		18,538			2,583			21,121
Interest rate swaps		—		(1,334	)		—			(1,334	)
Embedded derivatives		—		—			(14,640	)		(14,640	)
Total derivative liabilities	$	—	$	27,059		$	(12,057	)	$	15,002

Our commodity and interest rate derivative contracts were measured based on quotes from our counterparties, which are major financial institutions or commodities trading institutions. Such quotes have been derived using models that consider various inputs including current market and contractual prices for the underlying instruments, quoted forward prices for natural gas and crude oil, volatility factors and interest rates, such as a LIBOR curve for a similar length of time as the derivative contract term. The inputs for the fair value models for our swaps and Brent oil collars are all observable market data and these instruments have been classified as Level 2. Although we utilize the same option pricing models to assess the reasonableness of the fair values of our gas collars, an active futures market does not exist for our UK gas options. We base the inputs to the option models for our UK gas collars on observable market data in other markets to verify the reasonableness of the counterparty quotes. These UK gas collars are classified as Level 3.

The following is a reconciliation of changes in fair value of net derivative assets and liabilities classified as Level 3:

	Twelve Months Ended
	December 31, 2008
Balance at beginning of period	$	—
Total gains or losses (realized/unrealized):
Included in earnings		4,614
Purchases, issuance and settlements (net)		(13,460	)
Transfers in and/or out of Level 3 (net)		(3,211	)
Balance at end of period	$	(12,057	)
Changes in unrealized gains (losses) relating to derivative assets and liabilities still held at December 31, 2008	$	6,078

Note 16 – Derivative Instruments

As discussed in Note 2 – Accounting Policies, we have oil and gas commodity derivatives, interest rate derivatives and embedded derivatives related to debt instruments. The fair market value of these derivative instruments is included in our balance sheet as follows:

25

Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)

	December 31,
	2008			2007
Derivatives not designated as hedges:
Oil and gas commodity derivatives:
Assets:
Prepaid expenses and other current assets	$	31,649		$	4,018
Other assets – long-term		1,702			1,957
Liabilities:
Accrued expenses and other		—			(22,210	)
Other liabilities – long-term		(2,375	)		(30,635	)
	$	30,976		$	(46,870	)
Embedded derivatives related to debt instrument
Liabilities:
Other liabilities – long-term		(14,640	)		—
Derivatives designated as cash flow hedge:
Interest rate swap
Liabilities:
Accrued expenses and other		1,334			—
Other liabilities – long-term		—			567

If all counterparties failed to perform, our maximum loss would be $33.4 million as of December 31, 2008.

The effect of the derivatives not designated as hedges on our results of operations was as follows:

	Year Ended December 31,
	2008			2007			2006
Derivatives not designated as hedges:
Oil and gas commodity derivatives
Realized gains (losses) on derivative instruments	$	(28,578	)	$	12,048		$	—
Unrealized gains (losses) on derivative instruments		77,846			(89,132	)		34,531
		49,268			(77,084	)		34,531
Embedded derivatives related to debt instrument
Unrealized gains (losses) on derivative instruments		(1,180	)		—			—

The effect of derivatives designated as cash flow hedges on our results of operations and other comprehensive income was as follows:

26

Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)

	Location of
	Reclassification
	into Income	2008			2007			2006
Interest rate swap
Gain (loss) recognized in other comprehensive income		$	428		$	(927	)	$	—
Gain (loss) reclassified from accumulated other comprehensive income into income	Interest expense		(770	)		75			—
Oil and gas commodity derivatives
Gain (loss) recognized in other comprehensive income			—			—			(1,012	)
Gain (loss) reclassified from accumulated other comprehensive income into income	Income from continuing operations		—			—			4,702

We did not exclude any component of the hedging instruments’ gain or loss when assessing effectiveness. The ineffective portion of the hedges is not material for the periods presented and is included in other income (expense).

As of December 31, 2008, our outstanding commodity derivatives covered approximately 2,150 Mbbl and 4,450 MMcf cumulative through 2011 and consist of a combination of fixed price swaps and collars. These include four oil and two gas swaps with J. Aron (Goldman) and three oil and five gas collars with BNP Paribas.

During 2007, we entered into an interest rate swap with BNP Paribas for a notional amount of $37.5 million whereby we pay a fixed rate of 5.05% and receive three-month LIBOR through November 2009.

Note 17 – Comprehensive Income (Loss)

The following summarizes the components of comprehensive loss:

	Year Ended December 31,
	2008			2007			2006
Net loss	$	56,490		$	(49,077	)	$	(6,838	)
Related to derivative instruments:
Unrealized loss		428			(852	)		(1,012	)
Reclassification adjustment for loss realized in net loss above		(770	)		—			4,702
Related to marketable securities:
Unrealized loss		(1	)		(71	)		(887	)
Reclassification adjustment for loss realized in net loss above		—			—			1,775
Unrealized gain (loss), net		(343	)		(923	)		4,578
Comprehensive loss	$	56,147		$	(50,000	)	$	(2,260	)

27

Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)

The components of accumulated other comprehensive income are:

	Year Ended December 31,
	2008			2007			2006
Related to derivative instruments:
Balance at beginning of year	$	(852	)	$	—		$	(3,690	)
Change during the year		(342	)		(852	)		3,690
Balance at end of year		(1,194	)		(852	)		—
Related to marketable securities:
Balance at beginning of year		(71	)		—			(888	)
Change during the year		(1	)		(71	)		888
Balance at end of year		(72	)		(71	)		—
Accumulated comprehensive loss	$	(1,266	)	$	(923	)	$	—

Note 18 – Supplementary Cash Flow Disclosures

Cash paid during the period for interest and income taxes was as follows:

	Year Ended December 31,
	2008		2007		2006
Interest paid	$	15,966	$	22,164	$	5,895
Income taxes paid	$	20,088	$	7,662	$	7,064

Non-Cash Investing and Financing Transactions

During the first quarter of 2006, we issued 1.5 million shares of our common stock in connection with the settlement of litigation.

We recorded $10.8 million, $11.2 million and $2.0 million in preferred stock dividends in 2008, 2007 and 2006, respectively. Prior to the fourth quarter of 2007, we paid outstanding dividends on the Convertible Preferred Stock through the issuance of common stock.

In 2008, we recorded $4.5 million in non-cash interest expense that was added to the principal balance of the 11.5% convertible notes.

Note 19 – Commitments and Contingencies

General

The oil and gas industry is subject to regulation by federal, state and local authorities. In particular, oil and gas production operations and economics are affected by environmental protection statutes, tax

28

Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)

statutes and other laws and regulations relating to the petroleum industry. We believe we are in compliance with all federal, state and local laws, regulations applicable to Endeavour and its properties and operations, the violation of which would have a material adverse effect on us or our financial condition.

Rig Commitments

Our rig commitments reflect two commitments for the use of drilling rigs in our North Sea operations. Our continuing operations include one commitment for the drilling rig that commenced drilling at the Rochelle field in December 2008. We have $21 million in escrow toward this commitment, included in “Restricted cash” on our Condensed Consolidated Balance Sheet. The reserved amounts in escrow will be released as payments are made for this drilling activity.

Our discontinued operations include a commitment for a semi-submersible rig in Norway through a consortium with several other operators in the Norwegian Continental Shelf. The contract committed us to 100 days (for two wells) for drilling services for $38 million. We estimated the rig to be initially delivered in the third quarter of 2009 and again in 2010.

Contingencies

In November 2006, we purchased various oil and gas properties, including the Ivanhoe, Rob Roy, Hamish (collectively, IVRRH), Renee and Rubie fields. Hess Limited, the operator of the facility supporting production from the IVRRH fields, has advised us that there has been a mis-measurement of the volumes of oil produced from the IVRRH fields. At December 31, 2008, the estimate of our liability from this mis-measurement was at $4.1 million.

Operating Leases

We have leases for office space and equipment with lease payments of $0.6 million, $1.2 million and $1.2 million for the years ended December 31, 2008, 2009 and 2010, respectively.

Note 20 – Segment and Geographic Information

We have determined we have one reportable operating segment being the acquisition, exploration and development of oil and gas properties. Our operations are conducted in geographic areas as follows:

29

Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)

	2008				2007				2006
			Long-lived				Long-lived				Long-lived
	Revenue		Assets		Revenue		Assets		Revenue		Assets
United States	$	—	$	12,125	$	—	$	6,920	$	—	$	33,120
United Kingdom		170,781		478,623		135,876		527,810		24,881		537,936
Other		—		2,140		—		4,386		—		1,889
Continuing Operations		170,781		492,888		135,876		539,116		24,881		572,945
Discontinued operations — Norway		89,660		108,921		40,188		90,260		29,250		72,957
Total International		260,441		589,684		176,064		622,456		54,131		612,782
Total	$	260,441	$	601,809	$	176,064	$	629,376	$	54,131	$	645,902

Note 21 – Quarterly Financial Data (Unaudited)

				Second			Third			Fourth
	First Quarter			Quarter			Quarter			Quarter
	2008
Revenues from continuing operations	$	45,809		$	55,343		$	44,160		$	25,469
Operating expenses from continuing operations		29,944			32,528			26,074			63,999
Operating profit from continuing operations		15,865			22,815			18,086			(38,530	)
Net income (loss) to common stockholders		(19,487	)		(66,733	)		75,487			56,414
Net income (loss)from continuing operations per common share – basic		(0.15	)		(0.56	)		0.48			0.35
Net income (loss) from continuing operations per common share – diluted		(0.15	)		(0.56	)		0.29			0.24
Net income (loss)from discontinued operations per common share – basic		(0.15	)		0.04			0.11			0.09
Net income (loss) from discontinued operations per common share – diluted		(0.15	)		0.04			0.07			0.05
	2007
Revenues from continuing operations	$	35,025		$	22,808		$	36,417		$	41,626
Operating expenses from continuing operations		29,056			23,924			29,228			29,890
Operating loss from continuing operations		5,969			(1,117	)		7,189			11,737
Net income (loss) to common stockholders		(5,987	)		(13,048	)		(11,681	)		(29,599	)
Net income (loss) from continuing operations per common share – basic and diluted		(0.05	)		(0.11	)		(0.08	)		(0.25	)
Net income (loss) from discontinued operations per common share – basic and diluted		(0.00	)		(0.00	)		(0.01	)		(0.02	)

30

Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)

Note 22 – Supplemental Oil and Gas Disclosures – Unaudited

Capitalized Costs Relating to Oil and Gas Producing Activities
											Discontinued
	United			United				Total Continuing			Operations
	Kingdom			States		Other		Operations			Norway (1)			Total
December 31, 2008:
Proved	$	232,730		$	629	$	9	$	233,368		$	65,522		$	298,890
Unproved		131,688			5,876		2,132		139,696			48,714			188,410
Total capitalized costs		364,418			6,505		2,141		373,064			114,236			487,300
Accumulated depreciation, depletion and amortization		(142,686	)		—		—		(142,686	)		(33,914	)		(176,600	)
Net capitalized costs	$	221,732		$	6,505	$	2,141	$	230,378		$	80,322		$	310,700
December 31, 2007:
Proved	$	216,572		$	—	$	—	$	216,572		$	53,729		$	270,301
Unproved		154,948			—		2,176		157,124			28,869			185,993
Total capitalized costs		371,520			—		2,176		373,696			82,598			456,294
Accumulated depreciation, depletion and amortization		(102,386	)		—		—		(102,386	)		(20,461	)		(122,847	)
Net capitalized costs	$	269,134		$	—	$	2,176	$	271,310		$	62,137		$	333,447

31

Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
								Total		Discontinued
	United							Continuing		Operations
	Kingdom		United States		Other			Operations		Norway (1)		Total
Year Ended December 31, 2008:
Acquisition costs:
Proved	$	—	$	—	$	—		$	—	$	—	$	—
Unproved		1,178		971		27			2,176		—		2,176
Exploration costs		34,641		5,515		(62	)		40,094		22,796		62,890
Development costs		16,752		19		—			16,771		8,808		25,579
Total costs incurred	$	52,571	$	6,505	$	(35	)	$	59,041	$	31,604	$	90,645
Year Ended December 31, 2007:
Acquisition costs:
Proved	$	—	$	—	$	—		$	—	$	—	$	—
Unproved		774		—		18			792		—		792
Exploration costs		54,916		—		268			55,184		10,392		65,576
Development costs		7,562		—		—			7,562		14,063		21,625
Total costs incurred	$	63,252	$	—	$	286		$	63,538	$	24,455	$	87,993
Year Ended December 31, 2006:
Acquisition costs:
Proved	$	139,456	$	—	$	—		$	139,456	$	—	$	139,456
Unproved		81,715		—		—			81,715		—		81,715
Exploration costs		35,002		—		295			35,297		5,089		40,386
Development costs		8,960		—		—			8,960		7,235		16,195
Total costs incurred	$	265,133	$	—	$	295		$	265,428	$	12,324	$	277,752

32

Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)

Results of Operations for Oil and Gas Producing Activities
								Discontinued
	United					Total Continuing		Operations -
	Kingdom		United States			Operations		Norway (1)		Total
Year Ended December 31, 2008:
Revenues	$	170,781	$	—		$	170,781	$	89,660	$	260,441
Production expenses		31,489		828			32,317		14,259		46,576
DD&A		65,764		—			65,764		14,078		79,842
Impairment of oil and gas properties		36,970		—			36,970		—		36,970
Income tax expense		18,279		(290	)		17,989		47,832		65,821
Results of activities	$	18,279	$	(538	)	$	17,741	$	13,491	$	31,232
Year Ended December 31, 2007:
Revenues	$	135,876	$	—		$	135,876	$	40,188	$	176,064
Production expenses		27,263		—			27,263		13,781		41,044
DD&A		67,338		—			67,338		7,722		75,060
Income tax expense		20,638		—			20,638		14,574		35,212
Results of activities	$	20,637	$	—		$	20,637	$	4,111	$	24,748
Year Ended December 31, 2006:
Revenues	$	24,881	$	—		$	24,881	$	29,250	$	54,131
Production expenses		4,477		—			4,477		11,091		15,568
DD&A		10,292		—			10,292		6,217		16,509
Impairment of oil and gas properties		849		—			849		—		849
Income tax expense		4,631		—			4,631		9,315		13,946
Results of activities	$	4,632	$	—		$	4,632	$	2,627	$	7,259

⁽¹⁾ We completed the divestiture of our Norwegian subsidiary on May 14, 2009. The results of operations and financial position of this subsidiary are classified as discontinued operations for all periods presented.

Oil and Gas Reserves

Proved reserves are estimated quantities of oil, 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 proved reserves that can reasonably be expected to be recovered through existing wells with existing equipment and operating methods. The reserve volumes presented are estimates only and should not be construed as being exact quantities. These reserves may or may not be recovered and may increase or decrease as a result of our future operations and changes in economic conditions. Our oil and gas reserves were prepared by independent reserve engineers at December 31, 2008, 2007 and 2006.

In December 2008, the U.S. Securities and Exchange Commission adopted revisions to oil and natural gas reserve reporting requirements, including the definition of proved reserves, pricing used to determine economic producibility and voluntary disclosure of probable and possible reserves. These revisions would be effective for the company at year-end 2009, unless the timing is subsequently amended. We are

33

Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)

evaluating these new rules and cannot predict how the new rules will affect our future reporting of oil and natural gas reserves.

						Total			Discontinued
	United			United		Continuing			Operations -
	Kingdom			States		Operations			Norway (1)			Total
Proved Oil Reserves (MBbls):
Proved reserves at January 1, 2006		—			—		—			1,164			1,164
Purchase of proved reserves, in place		4,593			—		4,593			—			4,593
Production		(210	)		—		(210	)		(508	)		(718	)
Revisions of previous estimates		183			—		183			530			713
Proved reserves at December 31, 2006		4,566			—		4,566			1,186			5,752
Production		(1,274	)		—		(1,274	)		(519	)		(1,793	)
Extensions and discoveries		—			—		—			340			340
Revisions of previous estimates		(8	)		—		(8	)		1,049			1,041
Proved reserves at December 31, 2007		3,284			—		3,284			2,056			5,340
Production		(1,032	)		—		(1,032	)		(726	)		(1,758	)
Extensions and discoveries		522			18		540			121			661
Revisions of previous estimates		(643	)		—		(643	)		(45	)		(688	)
Proved reserves at December 31, 2008		2,131			18		2,149			1,406			3,555
Proved Developed Oil Reserves (MBbls):
At December 31, 2006		3,400			—		3,400			737			4,137
At December 31, 2007		2,544			—		2,544			1,650			4,194
At December 31, 2008		1,468			7		1,475			1,302			2,777

						Total			Discontinued
	United					Continuing			Operations -
	Kingdom			United States		Operations			Norway (1)			Total
Proved Gas Reserves (MMcf):
Proved reserves at January 1, 2006		—			—		—			6,297			6,297
Purchase of proved reserves, in place		14,574			—		14,574			—			14,574
Production		(1,539	)		—		(1,539	)		(203	)		(1,742	)
Revisions of previous estimates		4,137			—		4,137			1,579			5,716
Proved reserves at December 31, 2006		17,172			—		17,172			7,673			24,845
Production		(8,556	)		—		(8,556	)		(328	)		(8,884	)
Extensions and discoveries		—			—		—			1,821			1,821
Revisions of previous estimates		3,196			—		3,196			(732	)		2,464
Proved reserves at December 31, 2007		11,812			—		11,812			8,434			20,246

34

Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)

						Total			Discontinued
	United					Continuing			Operations -
	Kingdom			United States		Operations			Norway (1)			Total
Production		(6,532	)		—		(6,532	)		(2,322	)		(8,854	)
Extensions and discoveries		20,370			690		21,060			52			21,112
Revisions of previous estimates		1,480			—		1,480			(1,187	)		293
Proved reserves at December 31, 2008		27,130			690		27,820			4,977			32,797
Proved Developed Gas Reserves (MMcf):
At December 31, 2006		13,184			—		13,184						13,184
At December 31, 2007		8,416			—		8,416			6,614			15,030
At December 31, 2008		6,761			234		6,995			4,917			11,912

						Total			Discontinued
	United					Continuing			Operations -
	Kingdom			United States		Operations			Norway (1)			Total
Proved Reserves (MBOE):
Proved reserves at January 1, 2006		—			—		—			2,214			2,214
Purchase of proved reserves, in place		7,022			—		7,022			—			7,022
Production		(466	)		—		(466	)		(542	)		(1,008	)
Revisions of previous estimates		872			—		872			793			1,665
Proved reserves at December 31, 2006		7,428			—		7,428			2,465			9,893
Production		(2,700	)		—		(2,700	)		(574	)		(3,274	)
Extensions and discoveries		—			—		—			643			643
Revisions of previous estimates		524			—		524			927			1,451
Proved reserves at December 31, 2007		5,252			—		5,252			3,461			8,713
Production		(2,121	)		—		(2,121	)		(1,113	)		(3,234	)
Extensions and discoveries		3,917			133		4,050			130			4,180
Revisions of previous estimates		(395	)		—		(395	))		(242	)		(637	)
Proved reserves at December 31, 2008		6,653			133		6,786			2,236			9,022
Proved Developed Reserves (MBOE):
At December 31, 2006		5,597			—		5,597			737			6,334
At December 31, 2007		3,947			—		3,947			2,752			6,699
At December 31, 2008		2,595			46		2,641			2,122			4,763

⁽¹⁾ We completed the divestiture of our Norwegian subsidiary on May 14, 2009. The results of operations and financial position of this subsidiary are classified as discontinued operations for all periods presented.

35

Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)

During the year ended December 31, 2006, we purchased 7,022 MBOE in the Enoch field and Talisman Acquisitions.

Standardized Measure of Discounted Future Net Cash Flows

Future cash inflows and future production and development costs are determined by applying year-end prices and costs to the estimated quantities of oil and gas to be produced. Estimated future income taxes are computed using current statutory income tax rates for where production occurs. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor.

Estimates of future cash inflows are based on prices at year-end. Oil, gas and condensate prices are escalated only for fixed and determinable amounts under provisions in some contracts. At December 31, 2008 and 2007, the prices used to determine the estimates of future cash inflows were $36.55 and $96.02 per barrel, respectively, for oil and $8.70 and $10.03 per Mcf, respectively, for gas. Estimated future cash inflows are reduced by estimated future development, production, abandonment and dismantlement costs based on year-end cost levels, assuming continuation of existing economic conditions, and by estimated future income tax expense. Income tax expense, both U.S. and foreign, is calculated by applying the existing statutory tax rates, including any known future changes, to the pretax net cash flows giving effect to any permanent differences and reduced by the applicable tax basis. The effect of tax credits is considered in determining the income tax expense.

The standardized measure of discounted future net cash flows is not intended to present the fair market value of our oil and gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves in excess of proved reserves, anticipated future changes in prices and costs, an allowance for return on investment and the risks inherent in reserve estimates.

Under the full cost method of accounting, a noncash charge to earnings related to the carrying value of our oil and gas properties on a country-by-country basis may be required when prices are low. Whether we will be required to take such a charge depends on the prices for crude oil and natural gas at the end of any quarter, as well as the effect of both capital expenditures and changes to proved reserves during that quarter. Given the volatility of natural gas and oil prices, it is reasonably possible that our estimate of discounted future net cash flows from proved oil and gas reserves will change in the near term. If a noncash charge were required, it would reduce earnings for the period and result in lower DD&A expense in future periods.

36

Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)

Standardized Measure of Discounted Future Net Cash Flows
										Discontinued
	United						Continuing			Operations -
	Kingdom			United States			Operations			Norway			Total
December 31, 2008:
Future cash inflows	$	306,021		$	4,599		$	310,620		$	88,039		$	398,659
Future production costs		(71,242	)		(1,005	)		(72,247	)		(25,157	)		(97,404	)
Future development costs		(157,984	)		(2,100	)		(160,084	)		(25,579	)		(185,663	)
Future income tax expense		(33,977	)		—			(33,977	)		(17,036	)		(51,013	)
Future net cash flows (undiscounted)		42,818			1,494			44,312			20,267			64,579
Annual discount of 10% for estimated timing		12,548			563			13,111			1,806			14,917
Standardized measure of future net cash flows	$	30,270		$	931		$	31,201		$	18,461		$	49,662
December 31, 2007:
Future cash inflows	$	423,911		$	—		$	423,911		$	256,455		$	680,366
Future production costs		(99,544	)		—			(99,544	)		(55,968	)		(155,512	)
Future development costs		(62,119	)		—			(62,119	)		(26,672	)		(88,791	)
Future income tax expense		(109,399	)		—			(109,399	)		(125,013	)		(234,412	)
Future net cash flows (undiscounted)		152,849			—			152,849			48,802			201,651
Annual discount of 10% for estimated timing		1,328			—			1,328			8,403			9,731
Standardized measure of future net cash flows	$	151,521		$	—		$	151,521		$	40,399		$	191,920

37

Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)

Principal Sources of Change in the Standardized Measure of Discounted Future Net Cash Flows
	Year Ended December 31,
	2008			2007			2006
Standardized measure, beginning of period	$	191,920		$	145,541		$	18,525
Net changes in prices and production costs		(144,547	)		199,343			(25,622	)
Future development costs incurred		8,912			21,625			16,195
Net changes in estimated future development costs		(105,784	)		(48,873	)		(20,371	)
Revisions of previous quantity estimates		(19,381	)		79,636			47,154
Extensions and discoveries		127,182			35,345			—
Accretion of discount		39,734			24,078			6,037
Changes in income taxes, net		163,445			(135,233	)		20,393
Sale of oil and gas produced, net of production costs		(213,865	)		(135,020	)		(38,592	)
Purchased reserves		—			—			101,533
Change in production, timing and other		2,046			5,478			20,289
Standardized measure, end of period	$	49,662		$	191,920		$	145,541

Note 23 – Subsequent Event, Discontinued Operations and Adjustments to Consolidated Financial Statements

On May 14, 2009, we completed the divestiture of our Norwegian subsidiary, Endeavour Energy Norge AS, to Verbundnetz Gas AG for cash consideration of $150 million (the “Norway Sale”). We recognized a gain upon closing the Norway Sale of $47 million, after the allocation of $68 million of goodwill to the assets sold.

As a result of the Norway Sale, we have classified the results of operations and financial position of our Norwegian subsidiary as discontinued operations for all periods presented. The following table details selected financial data for the assets included in the Norway Sale:

38

Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)

	December 31, 2008			December 31, 2007
Current Assets:
Cash	$	6,735		$	2,630
Accounts receivable		4,559			6,583
Prepaid expenses and other		5,432			4,642
		16,726			13,855
Long-term Assets:
Property, plant and equipment, net		80,611			61,699
Goodwill		67,994			67,994
		148,605			129,693
Current Liabilities:
Accounts payable		(3,717	)		(5,553	)
Accrued expenses and other		(18,514	)		(9,169	)
		(22,231	)		(14,722	)
Long-term Liabilities:
Deferred tax liability		(36,828	)		(33,998	)
Asset retirement obligation		(9,223	)		(7,632	)
		(46,051	)		(41,630	)
Net Assets and Liabilities	$	97,049		$	87,196

	Year Ended December 31,
	2008		2007		2006
Sales	$	89,660	$	40,188	$	29,250
Income before Taxes	$	63,244	$	14,095	$	7,250
Income Tax Expense		32,613		13,027		9,043
Net Income (Loss) from Discontinued Operations	$	30,631	$	1,068	$	(1,793	)

39