United States
Securities and Exchange Commission

Washington, D.C. 20549

Form 10-Q

(Mark One)

þ		Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
		For the Quarterly Period Ended March 31, 2011

o		Transition Report Under Section 13 or 15(d) of the Securities Exchange Act of 1934
		For the transition period from _________ to ___________

Commission file number: 1-32212

Endeavour International Corporation

(Exact name of registrant as specified in its charter)

Nevada		88-0448389
(State or other jurisdiction of incorporation		(I.R.S. Employer Identification No.)
or organization)

1001 Fannin Street, Suite 1600, Houston, Texas 77002
(Address of principal executive offices) (Zip code)

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. þ Yes o No

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

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

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

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

As of May 5, 2011, 37,131,979 shares of the registrant’s common stock were outstanding.

 

 

Index

Part I: Financial Information
Item 1: Financial Statements
Condensed Consolidated Balance Sheets			1
Condensed Consolidated Statements of Operations			3
Condensed Consolidated Statements of Cash Flows			4
Notes to Condensed Consolidated Financial Statements			5
Item 2: Management’s Discussion and Analysis of Financial Condition and Results of Operations			16
Item 3: Quantitative and Qualitative Disclosures About Market Risk			29
Item 4: Controls and Procedures			29
Part II. Other Information
Item 1A: Risk Factors			30
Item 6: Exhibits			30
Signatures			31
EX-31.1
EX-31.2
EX-32.1
EX-32.2

Quantities of natural gas are expressed in this report in terms of thousand cubic feet (Mcf) and million cubic feet (MMcf). Oil is quantified in terms of barrels (Bbls) and thousands of barrels (Mbbls). Natural gas is compared to oil in terms of barrels of oil equivalent (BOE), thousand barrels of oil equivalent (MBOE) or million barrels of oil equivalent (MMBOE). One Bbl of oil is the energy equivalent of six Mcf of natural gas. With respect to information relating to our working interest in wells or acreage, “net” oil and natural gas wells or acreage is determined by multiplying gross wells or acreage by our working interest therein. References to number of potential well locations are gross, unless otherwise indicated.

References to “GAAP” refer to U.S. generally accepted accounting principles.

Part I: Financial Information

Item 1: Financial Statements

Endeavour International Corporation

(Unaudited)

(Amounts in thousands)

		March 31,				December 31,
		2011				2010
Assets
Current Assets:
Cash and cash equivalents		$	152,146			$	99,267
Restricted cash			33,072				31,776
Accounts receivable			6,922				8,068
Prepaid expenses and other current assets			6,547				8,718
Total Current Assets			198,687				147,829
Property and Equipment, Net			444,728				364,677
Goodwill			211,886				211,886
Other Assets			22,256				25,895
Total Assets		$	877,557			$	750,287

See accompanying notes to condensed consolidated financial statements.

Endeavour International Corporation
Condensed Consolidated Balance Sheets
(Unaudited)
(Amounts in thousands)

		March 31,				December 31,
		2011				2010
Liabilities and Stockholders’ Equity
Current Liabilities:
Accounts payable		$	45,138			$	32,442
Current maturities of debt			100,350				21,600
Accrued expenses and other			20,564				22,642
Total Current Liabilities			166,052				76,684
Long-Term Debt			244,152				323,706
Deferred Taxes			92,604				77,200
Other Liabilities			56,839				64,927
Total Liabilities			559,647				542,517
Commitments and Contingencies
Series C Convertible Preferred Stock:
Face value (liquidation preference)			45,000				45,000
Net non-cash premiums under fair value accounting on redemption			8,152				8,152
Total Series C Convertible Preferred Stock			53,152				53,152
Stockholders’ Equity:
Series B preferred stock - Liquidation preference: $3,312
Common stock; shares issued and outstanding — 36,668 and 24,784 shares at 2011 and 2010, respectively			37				25
Additional paid-in capital			406,124				287,995
Treasury stock, at cost - 72 and 72 shares at 2011 and 2010, respectively			(587	)			(587	)
Accumulated deficit			(140,816	)			(132,815	)
Total Stockholders’ Equity			264,758				154,618
Total Liabilities and Stockholders’ Equity		$	877,557			$	750,287

See accompanying notes to condensed consolidated financial statements.

Endeavour International Corporation

(Unaudited)
(Amounts in thousands, except per share data)

		Three Months Ended
		March 31,
		2011				2010
Revenues		$	14,104			$	13,721
Cost of Operations:
Operating expenses			5,041				2,821
Depreciation, depletion and amortization			6,323				5,681
Impairment of oil and gas properties			—				7,692
General and administrative			4,713				4,431
Total Expenses			16,077				20,625
Loss From Operations			(1,973	)			(6,904	)
Other Income (Expense):
Derivatives:
Realized gains			—				232
Unrealized gains (losses)			4,464				(1,072	)
Interest expense			(12,523	)			(5,636	)
Interest income and other			(139	)			3,024
Total Other Expense			(8,198	)			(3,452	)
Loss Before Income Taxes			(10,171	)			(10,356	)
Income Tax Expense (Benefit)			(2,714	)			4,834
Net Loss			(7,457	)			(15,190	)
Preferred Stock Dividends			545				589
Net Loss to Common Stockholders		$	(8,002	)		$	(15,779	)
Net Loss per Common Share — Basic and Diluted		$	(0.30	)		$	(0.74	)
Weighted Average Number of Common Shares Outstanding:
Basic and Diluted			26,750				21,364

See accompanying notes to condensed consolidated financial statements.

Endeavour International Corporation

(Unaudited)
(Amounts in thousands)

		Three Months Ended March 31,
		2011				2010
Cash Flows from Operating Activities:
Net loss		$	(7,457	)		$	(15,190	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization			6,323				5,681
Impairment of oil and gas properties			—				7,692
Deferred tax expense (benefit)			(2,182	)			3,477
Unrealized (gains) losses on derivatives			(4,464	)			1,072
Amortization of non-cash compensation			875				1,153
Amortization of loan costs and discount			3,916				1,528
Non-cash interest expense			3,031				1,683
Other			2,602				(3,023	)
Changes in operating assets and liabilities:
Decrease in receivables			1,145				4,056
Increase in other current assets			(2,787	)			(2,166	)
Increase (decrease) in liabilities			(16,424	)			3,451
Net Cash Provided by (Used in) Operating Activities			(15,422	)			9,414
Cash Flows From Investing Activities:
Capital expenditures			(20,148	)			(21,768	)
Acquisitions			(20,964	)			(29,407	)
(Increase) decrease in restricted cash			(1,295	)			2,859
Net Cash Used in Investing Activities			(42,407	)			(48,316	)
Cash Flows From Financing Activities:
Repayments of borrowings			(5,400	)			—
Borrowings under debt agreements			—				25,000
Proceeds from issuance of common stock			116,822				20,011
Dividends paid			(506	)			(550	)
Other financing			(208	)			(923	)
Net Cash Provided by Financing Activities			110,708				43,538
Net Increase in Cash and Cash Equivalents			52,879				4,636
Cash and Cash Equivalents, Beginning of Period			99,267				27,287
Cash and Cash Equivalents, End of Period		$	152,146			$	31,923

See accompanying notes to condensed consolidated financial statements.

Endeavour International Corporation

(Unaudited)
(Amounts in thousands, except per unit data)

Note 1 — General

Endeavour International Corporation (a Nevada corporation) is an independent oil and gas company engaged in the acquisition, exploration and development of energy reserves. As used in these Notes to Condensed Consolidated Financial Statements, the terms “we,” “us,” “our” and similar terms refer to Endeavour International Corporation and, unless the context indicates otherwise, its consolidated subsidiaries. The accompanying financial statements should be read in conjunction with the audited consolidated financial statements and notes included in our Annual Report on Form 10—K for the year ended December 31, 2010.

The accompanying unaudited condensed consolidated financial statements have been prepared on the accrual basis of accounting in accordance with 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 materially 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 that it is reasonably possible that the following material estimates affecting the financial statements could change in the coming year:

•

proved oil and gas reserves,

•

expected future cash flow from proved oil and gas properties,

•

future dismantlement and restoration costs,

•

fair values used in purchase accounting; and

•

fair value of derivative instruments.

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 would be dilutive.

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 anti-dilutive.

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

The common shares potentially issuable arising from these instruments, which were outstanding during the periods presented in the financial statements consisted of:

		March 31,
		2011				2010
Warrants, options and stock-based compensation			148				96
Convertible debt			5,788				5,416
Convertible preferred stock			5,143				5,329
			11,079				10,841

Note 2 — Property and Equipment

Property and equipment included the following at the dates indicated below:

		March 31,				December 31,
		2011				2010
Oil and gas properties under the full cost method:
Subject to amortization		$	407,266			$	389,575
Not subject to amortization:
Acquired in 2011			72,025				—
Acquired in 2010			65,356				67,612
Acquired in 2009			30,867				31,134
Acquired prior to 2009			60,358				62,684
			635,872				551,005
Computers, furniture and fixtures			4,357				4,222
Total property and equipment			640,229				555,227
Accumulated depreciation, depletion and amortization			(195,501	)			(190,550	)
Net property and equipment		$	444,728			$	364,677

The costs not subject to amortization relate to unproved properties and properties being made ready to be placed in service, which are excluded from amortizable capital costs until it is determined whether or not proved reserves can be assigned to such properties. We capitalized $1.8 million and $0.7 million in interest related to exploration and development activities for the quarters ended March 31, 2011 and 2010, respectively.

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

In the first quarter of 2010, we recorded $7.7 million in impairments of our U.S. oil and gas properties, pre-tax, through the application of the full cost ceiling test at the end of each quarter. For 2011, the prices used in the full cost ceiling test for our U.S. properties were $83.76 per barrel for oil and $4.11 per Mcf for gas. For 2011, the prices used in the full cost ceiling test for our U.K. properties were $86.05 per barrel for oil and $7.31 per Mcf for gas.

Assets Acquisition

On February 23, 2011, we closed our acquisition of an additional 20% working interest in the Bacchus field for approximately $9.2 million in cash payable at closing and approximately $6.2 million in cash payable three months after first oil is produced In addition, we paid capital costs incurred by the seller of $9.4 million. Following the acquisition, we hold an aggregate 30% working interest.

Note 3 — Debt Obligations

Our debt consisted of the following at the dates indicated:

		March 31,				December 31,
		2011				2010
Senior notes, 6% fixed rate, due 2012		$	81,250			$	81,250
Convertible bonds, 11.5%, due 2016			57,426				55,821
Subordinated notes, 12.0%, due 2014			46,388				51,132
Senior term loan, 15%, due 2013			162,181				161,371
			347,245				349,574
Less: debt discount			(2,743	)			(4,268	)
Less: current maturities			(100,350	)			(21,600	)
Long-term debt		$	244,152			$	323,706
Standby letters of credit outstanding for abandonment liabilities		$	32,960			$	31,726

Our outstanding credit facilities contain certain financial ratio covenants. We were in compliance with all financial and restrictive covenants of our debt obligations as of March 31, 2011 and December 31, 2010.

The fair value of our debt obligations was $353 million and $361 million at March 31, 2011 and December 31, 2010, respectively. The fair values of long-term debt were determined based upon external market quotes for our Senior Notes and discounted cash flows for other debt.

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

On April 20, 2011, we redeemed all of our outstanding $81.25 million 6% Senior Notes, which were included in current maturities of debt at March 31, 2011, with a portion of the proceeds from our recently completed common stock offering. This planned redemption is also discussed in Note 11, “Subsequent Events.”

On March 11, 2011, we entered into an Amendment to the Trust Deed with Smedvig QIF PLC related to our 11.5% convertible bonds due 2014. The Amendment provides for:

•

the amendment of the maturity date of the 2014 Convertible Bonds from January 24, 2014 to January 24, 2016;

•

the amendment of the date upon which the holders of the 2014 Convertible Bonds may first exercise a put right, and the occurrence of the conversion price reset if such put right is not exercised, from January 24, 2012 to January 24, 2016; and

•

a reduction in the interest rate payable from 11.5% to 7.5% on and after March 31, 2014.

We recorded a loss of $0.8 million in other expenses related to this amendment, representing the difference between the fair value of the debt and the book value of the debt at March 11, 2011.

Senior Term Loan

On February 6, 2011, we amended our Senior Term Loan to increase the security reserved for potential letters of credit from $25 million to $35 million. Upon receipt of sufficient third party financing, this increase in the security amount should allow us to release the approximately $32 million of restricted cash that currently serves as collateral for existing letters of credit with an alternative letter of credit provider.

The Amendment of our 11.5% Convertible Bonds and the redemption of all $81.25 million of our outstanding 6% Convertible Senior Notes satisfied the two conditions precedent to extend the maturity date of the Senior Term Loan to August 16, 2013.

Note 4 — Asset Retirement Obligations

Our asset retirement obligations relate to obligations for the future plugging and abandonment of oil and gas properties. The following table provides a rollforward of our asset retirement obligations for the three months ended March 31, 2011 and 2010:

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

		Three Months Ended
		March 31,
		2011				2010
Carrying amount of asset retirement obligations as of beginning of period		$	42,997			$	47,362
Accretion expense			1,233				1,134
Impact of foreign currency exchange rate changes			1,765				(3,062	)
Payment of asset retirement obligation			(4,033	)			(483	)
Reduction in asset retirement obligation			—				(1,812	)
			41,962				43,139
Less: ARO Liability — Current			(6,667	)			(5,000	)
Carrying amount of asset retirement obligations as of end of period		$	35,295			$	38,139

Note 5 — Equity Transactions

New York Stock Exchange Listing of Common Stock

On March 15, 2011, we completed the transfer of the primary listing for our common stock from the NYSE Amex to the New York Stock Exchange under the symbol “END.”

Common Stock Offering

On March 30, 2011, we completed an underwritten public offering of 11,500,000 shares of common stock at a price of $11.00 per common share ($10.34 per common share, net of underwriting discounts) for net proceeds of $116.8 million. On April 20, 2011, we used a portion of the offering proceeds to redeem all of our outstanding $81.25 million 6% Senior Notes, due 2012. We intend to use the remaining offering proceeds for general corporate purposes.

Series C Convertible Preferred Stock

On April 12, 2011, a holder of a portion of our Series C Convertible Preferred Stock converted 4,000 preferred shares into 457,142 shares of our common stock. See Note 11 “Subsequent Events” for additional discussion of this transaction.

Note 6 — Stock-Based Compensation Arrangements

We grant restricted stock and stock options to employees and directors as incentive compensation. The restricted stock and options generally vest over three years. Non-cash stock-based compensation is recorded in general and administrative (“G&A”) expenses or capitalized G&A as follows:

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

		Three Months Ended
		March 31,
		2011				2010
G & A Expenses		$	642			$	883
Capitalized G & A			233				270
Total non-cash stock-based compensation		$	875			$	1,153

At March 31, 2011, total compensation cost related to awards not yet recognized was approximately $7.2 million and is expected to be recognized over a weighted average period of less than three years.

The fair value of each option award is estimated on the date of grant using the Black-Scholes option-pricing model. We have not granted any stock options during 2010 or the first three months of 2011. Information relating to stock options is summarized as follows:

						Weighted				Weighted
		Number of				Average				Average
		Shares				Exercise				Contractual				Aggregate
		Underlying				Price per				Life in				Intrinsic
		Options				Share				Years				Value
Balance outstanding January 1, 2011			464			$	10.04
Exercised			(55	)			6.81
Forfeited			(21	)			13.00
Expired			(45	)			24.57
Balance outstanding — March 31, 2011			343			$	8.46				6.7			$	1,603
Currently exercisable — March 31, 2011			299			$	9.08				6.6			$	1,232

The restricted stock awards were valued based on the closing price of our common stock on the measurement date, typically the date of grant. Status of the restricted shares as of March 31, 2011 and the changes during the three months ended March 31, 2011 are presented below:

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

						Weighted
						Average Grant
						Date Fair
		Number of				Value per
		Shares				Share
Balance outstanding — January 1, 2011			816			$	7.39
Granted			335				13.68
Vested			(244	)			7.03
Forfeited			(39	)			7.06
Balance outstanding — March 31, 2011			868			$	9.94
Total grant date fair value of shares vesting during the period		$	3,259

Note 7 — Fair Value Measurements

We apply fair value measurements to certain assets and liabilities, including 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. 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.

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 March 31, 2011:

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

		Quoted Market Prices				Significant Other				Significant
		in Active Markets -				Observable Inputs -				Unobservable Inputs				Total
		Level 1				Level 2				Level - 3				Fair Value
As of March 31, 2011:
Oil and gas puts		$	—			$	905			$	327			$	1,232
Embedded derivatives			—				—				(21,020	)			(21,020	)
Total		$	—			$	905			$	(20,693	)		$	(19,788	)
As of December 31, 2010:
Oil and gas puts		$	—			$	1,213			$	792			$	2,005
Embedded derivatives			—				—				(27,495	)			(27,495	)
Total		$	—			$	1,213			$	(26,703	)		$	(25,490	)

Our commodity derivative contracts were measured based on quotes from our counterparties, all of whom 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 are all observable market data, and as a result these instruments have been classified as Level 2.

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

Three months ended March 31, 2011 Balance at beginning of period		$	(26,703	)
Realized and unrealized gains (losses) included in earnings			6,010
Balance at end of period		$	(20,693	)
Changes in unrealized gains (losses) relating to derivatives assets and liabilities still held at March 31, 2011		$	5,984

Note 8 — Derivative Instruments

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

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

intended to reduce our exposure to declines in the market prices of crude oil and natural gas that we produce and sell or to increases in interest rates and to manage cash flows in support of our annual capital expenditure budget. We also have embedded derivatives related to our debt instruments and convertible preferred stock.

The fair market value of these derivative instruments is included in our balance sheet as follows for the periods indicated:

		March 31,				December 31,
		2011				2010
Derivatives not designated as hedges:
Oil and gas commodity derivatives:
Assets:
Prepaid expenses and other current assets		$	575			$	709
Other assets — long term			658				1,296
		$	1,233			$	2,005
Embedded derivatives related to debt and equity instruments:
Assets:
Other assets — long term			—				315
Liabilities:
Other liabilities — long-term			(21,020	)			(27,810	)

If all counterparties failed to perform, our maximum loss would be $1.2 million as of March 31, 2011.

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

		Three Months Ended
		March 31,
		2011				2010
Derivatives not designated as hedges:
Oil and gas commodity derivatives
Realized gains		$	—			$	232
Unrealized gains (losses)			(2,010	)			205
			(2,010	)			437
Embedded derivatives related to debt and equity instruments Unrealized gains (losses)		$	6,475			$	(1,277	)

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).

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

Under our Senior Term Loan, we are required to maintain commodity derivatives to manage our cash flows from operations. As of March 31, 2011, our outstanding commodity derivatives covered approximately 307 Mbbls and 1,433 MMcf cumulative through 2012 and consist of six natural gas and twelve oil option contracts with three major counterparties.

Note 9 — Supplemental Cash Flow Information

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

		Three Months Ended March 31,
		2011				2010
Interest paid		$	8,557			$	4,119
Income taxes paid		$	4,634			$	217

Note 10 — Commitments and Contingencies

We have previously disclosed a potential commitment on a drilling rig in our North Sea operations. We are in dispute with the rig operator in relation to this potential commitment and have also raised potential counterclaims. We will defend our position vigorously, but there can be no certainty that we will resolve this matter favorably.

Note 11 — Subsequent Events

On April 12, 2011, a holder of a portion of our Series C Convertible Preferred Stock converted 4,000 preferred shares into 457,142 shares of our common stock.

On April 18, 2011 we announced agreement of the commercial terms for the processing and transportation of East Rochelle production on the Scott Platform in the Central North Sea. As operator, we plan to award contracts and commence immediate construction of the production facilities. The Rochelle Field Development Plan (“FDP”) for Block 15/27 in East Rochelle was approved by the Department of Energy and Climate Change (“DECC”) on February 28, 2011. First production from East Rochelle is planned for the second half of 2012.

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

On April 20, 2011, we redeemed all $81.25 million of the 6% Senior Notes, included in current maturities of debt at March 31, 2011, with a portion of the proceeds from our March 2011 common stock offering.

Endeavour International Corporation
(Amounts in thousands, except per unit data)

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

The following discussion should be read in conjunction with our unaudited Condensed Consolidated Financial Statements and related notes thereto included elsewhere in this report. 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.

Overview

We are an independent oil and gas company engaged in the production, exploration, development and acquisition of crude oil and natural gas in the U.S. and the North Sea. Our strategy is to expand and exploit our balanced portfolio of exploration and development assets using conventional and unconventional technologies in basins that have historically generated and produced substantial quantities of oil and gas and that we believe will yield commercial quantities of reserves through improved drilling and completion technologies. Finding, developing and producing oil and gas reserves in the North Sea require both significant capital and time. Recognizing this, we have sought to balance our North Sea assets, which have large potential reserves but long production-cycles, with a portfolio of assets in the U.S. that have lower costs and shorter production-cycles. We also seek to achieve a balance of oil and gas reserves in our portfolio of assets, believing that both commodities present attractive opportunities for capital returns in the future.

Our North Sea activities and assets remain a key source of value that we are actively developing to increase our overall reserves and production. Our major development projects in the U.K. sector of the North Sea — Bacchus, Greater Rochelle, and Columbus — have the potential to significantly expand our total proved reserves and production levels. These projects are in various stages of development, with Bacchus currently expected to commence oil production in the second half of 2011. Additionally, we expect that production from our two-phase development of the Greater Rochelle area will commence with first production from East Rochelle in the second half of 2012 and from West Rochelle shortly thereafter. Finally, Columbus could commence production as early as 2012. We intend to continue to actively manage our North Sea assets in a manner that maximizes value and enables us to allocate resources to effectively pursue our growth strategy.

Currently, our primary focus in the U.S. is unconventional gas shale developments targeting reserve and production growth in the Haynesville area, including the East Texas Cotton Valley gas sands, and the Marcellus area. In the Haynesville area, we have approximately 7,500 net acres with acreage located in Red River, DeSoto, Bienville and Caddo Parishes in Louisiana and in Harrison and Gregg Counties in Texas. Our Marcellus acreage is comprised of approximately 18,600 net acres in Pennsylvania located between two of the most active parts of the Marcellus play. We also have exploratory plans in emerging gas and oil plays in Alabama and Montana where early well results will determine the pace and scope of our subsequent exploration and development initiatives.

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In 2011, we intend to expand upon our foundation of producing assets and undeveloped acreage in both established and emerging U.S. onshore resource plays, including the development of our leasehold positions in the Haynesville and Marcellus areas, while continuing to develop our existing assets in the North Sea. Specifically, during 2011 we intend to focus on achieving initial production from the Bacchus oil field in the North Sea. We believe that the following will support us in executing our core business strategies.

	•		On March 30, 2011, we closed a public offering of 11,500,000 shares of our common stock offering for net proceeds of $116.8 million.
	•		On March 15, 2011, we completed the transfer of the primary listing for our common stock from the NYSE Amex to the New York Stock Exchange.
	•		On March 11, 2011, we entered into an Amendment to the Trust Deed dated as of January 24, 2008 with Smedvig QIF PLC and the other parties thereto related to our 11.5% Convertible Bonds. The amendment provides for an extension of the maturity date of the 2014 Bonds; extends the date on which holders may exercise a put right, and the occurrence of price reset if not exercised; and a reduction in the interest rate payable after a designated date.
	•		On February 28, 2011, the Department of Energy and Climate Change (the “DECC”) approved the Rochelle FDP for Block 15/27 in East Rochelle. On April 18, 2011, we announced agreement of the commercial terms for the processing and transportation of East Rochelle production on the Scott Platform in the Central North Sea. As the operator, we plan to award contracts and commence immediate construction of the production facilities. First production from East Rochelle is planned for the second half of 2012. See Note 11 — Subsequent Events.
	•		On February 23, 2011, we finalized our acquisition of an additional 20% working interest in the Bacchus development for approximately $9.2 million in cash payable at closing and approximately $6.2 million in cash payable at the earlier of three months after first production or the last business day of 2011. In addition, we paid capital costs previously incurred by the seller of $9.4 million. Following the acquisition, we now hold an aggregate working interest of 30%.
	•		On February 6, 2011, we amended our Senior Term Loan to increase the security reserved for potential letters of credit from $25 million to $35 million. The increase in the security amount should allow us to release the approximately $32 million of restricted cash that is serving as collateral for existing letters of credit.

Results of Operations

Revenue, net income and cash flows from operating activities are very sensitive to changes in prices received for our products. With our business policy to utilize various oil and gas derivative instruments to achieve more predictable cash flows by reducing our exposure to price fluctuations, our realized commodity prices including the effect of derivatives, particularly for oil, were less volatile than commodity prices before the effect of derivatives.

Net loss to common shareholders for the three months ended March 31, 2011 was $8.0 million, or $0.30 per share, compared to $15.8 million, or $0.74 per share, for the same period in 2010. The change in the net loss to common shareholders for these periods is primarily due to

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(Amounts in thousands, except per unit data)

decreases in impairments of oil and gas properties and tax expense and unrealized gains on derivative instruments, partially offset by increased operating and interest expenses

In addition to our operations, our net income can be significantly affected by various non-cash items, such as unrealized gains and losses on our derivatives, impairment of oil and gas properties, currency impact of long-term liabilities and deferred taxes. Net loss as adjusted for the three months ended March 31, 2011 would have been $12.9 million without the effect of derivative transactions and impairment of oil and gas properties as compared to net income as adjusted of $6.4 million for the same period in 2010.

Adjusted EBITDA decreased to $4.1 million for the three months ended March 31, 2011 from $9.7 million for the same period in 2010, primarily due to increased operating and other expenses. For definitions of Net Income (Loss) as Adjusted and Adjusted EBITDA, and a reconciliation of each to the nearest comparable GAAP measure, please see “Reconciliation of Non-GAAP Accounting Measures.”

The cash flows used by operating activities decreased to $(15.4) million for the three months ended March 31, 2011 as compared to cash flows provided by operating activities of $9.4 million for the same period in 2010 primarily due to increased interest expense related to our 2010 debt issuances, increased operating expenses and increased current tax expense, partially offset by increased revenue.

Revenue and Sales Volume

Our revenues have increased from $13.7 million in the three months ended March 31, 2010 to $14.1 million in the same period of 2011 primarily as a result of a substantial increase in realized oil prices and increased sales from our U.S. operations, partially offset by a decrease in average realized natural gas prices and sales from our U.K. operations. The change in our average realized natural gas prices is the result of a combination of factors. While our overall gas sales volumes have remained consistent between the periods, our expanded operations in the U.S. have led to an increase in U.S. sales as a percentage of our total gas sales. In addition, the U.S. gas market is heavily impacted by the increased supply from shale drilling, which has kept U.S. gas prices from increasing and has kept U.S. prices lower than U.K. gas prices. The significant increase of supply from shale drilling on the U.S. gas markets and the significant shift in our gas sales from the U.K. to the U.S. resulted in the decrease in our average realized gas prices.

The following table shows our average sales volumes and sales prices for our operations for the periods presented. None of our current producing fields represent more than 15 percent of our total proved reserves during 2011 or 2010. However, certain of our non-producing North Sea development assets — the Rochelle and Columbus fields — each represent more than 15 percent of our proved reserves at March 31, 2011 or 2010. As these fields do not have any current sales or production, they have not been separately identified in the table below.

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(Amounts in thousands, except per unit data)

		Three Months Ended
		March 31,
		2011				2010
Sales volume (1)
Oil and condensate sales (Mbbls):
United Kingdom			100				113
United States			2				1
Total			102				114
Gas sales (MMcf):
United Kingdom			44				766
United States			965				280
Total			1,009				1,046
Oil equivalent sales (MBOE):
United Kingdom			108				241
United States			162				48
Total			270				289
Total BOE per day			3,001				3,209
Physical production volume (BOE per day): (2)
United Kingdom			1,307				3,118
United States			1,885				578
Total			3,192				3,696
Realized Prices (3)
Oil and condensate price ($  per Bbl):
Before commodity derivatives		$	98.79			$	70.24
Effect of commodity derivatives			—				(7.50	)
Realized prices including commodity derivatives		$	98.79			$	62.74
Gas price ($  per Mcf):
Before commodity derivatives		$	4.00			$	5.43
Effect of commodity derivatives			—				1.25
Realized prices including commodity derivatives		$	4.00			$	6.68
Equivalent oil price ($  per BOE):
Before commodity derivatives		$	52.22			$	47.51
Effect of commodity derivatives			—				1.55
Realized prices including commodity derivatives		$	52.22			$	49.06

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(Amounts in thousands, except per unit data)

Our revenues and cash flows from operating activities are very sensitive to changes in the prices we receive for the oil and natural gas we produce. Our production is sold at prevailing market prices which may be volatile and subject to numerous factors which are outside of our control. Further, the current tightly balanced supply and demand market allows a small variation in supply or demand to significantly impact the market prices for these commodities.

The markets in which we sell our oil and natural gas also materially impact our revenues and cash flows. Oil trades on a worldwide market, and consequently, price movements for all types and grades of crude oil generally trend in the same direction and within a relatively narrow price range. However, natural gas prices vary among geographic areas as the prices received are largely impacted by local supply and demand conditions as the global transportation infrastructure for natural gas is still developing. As such, the oil we produce and sell is typically sold at prices in line with global prices, whereas our natural gas is to a large extent impacted by regional supply and demand issues and to a lesser extent by global fuel prices, including oil and coal. With the recent increase in our U.S. operations and the shut-in of the Goldeneye field, the majority of our gas sales are in the U.S. The U.S. gas market is heavily impacted by the increased supply from shale drilling, which has served to depress natural gas prices relative to the U.K. market.

For the first quarter of 2011 and 2010, we had sales volume of 3,001 BOE per day and 3,209 BOE per day, respectively. Our physical daily production was approximately 3,192 BOE and 3,696 BOE for the first quarter of 2011 and 2010, respectively. The decrease in sales volume is primarily attributable to shut down of our Goldeneye field, although the negative impact of the shut-down was substantially offset by an increase in sales from our U.S. assets. Sales from our U.S. assets have increased as we have continued our drilling program since our initial acquisitions of these assets in late 2009.

In 2010, the Goldeneye field represented nearly all of our gas production in the U.K. The field was shut-in in early December 2010 due to flow assurance issues resulting from increased water production. During the first quarter of 2011, the field operator performed flow trials to study pipeline hydraulic performance which showed that production from the Goldeneye field was no longer economically sustainable. The operator is currently evaluating options to use the Goldeneye reservoir for carbon dioxide storage, which may reduce our abandonment obligations for the field.

Expenses

For the three months ended March 31, 2011, operating expenses increased to $5.0 million as compared to $2.8 million for the same period in 2010. The increase in operating expense from 2010 to 2011 is primarily related to increased workover expense and increases in transportation expense and production taxes as a result of increased U.S. sales volumes. Operating costs per BOE increased from $9.77 per BOE for the three months ended March 31, 2010 to $18.66 per BOE for the three months ended March 31, 2011. The increase in operating costs per BOE is the result of the decline in Goldeneye production which had low operating costs partially offset by increased U.S. production.

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Depreciation, depletions and amortization (“DD&A”) expense increased to $6.3 million from $5.7 million for the first quarter of 2011 and 2010, respectively, as a result of increased DD&A rates.

In the first quarter of 2010, we recorded $7.7 million in impairments of our U.S. oil and gas properties, pre-tax, through the application of the full cost ceiling test at the end of the quarter. For 2011, the prices used in the full cost ceiling test for our U.S. properties were $83.76 per barrel for oil and $4.11 per Mcf for gas. We did not record any impairment in the first quarter of 2011. For 2011, the prices used in the full cost ceiling test for our U.K. properties were $86.05 per barrel for oil and $7.31 per Mcf for gas. As discussed previously, the U.S. gas market is heavily impacted by the increased supply from shale drilling, which has kept U.S. gas prices from increasing. The risk that we will be required to record impairments of our oil and gas properties, through the application of the full cost ceiling test in subsequent periods, increases when oil and gas prices are low or volatile.

General and administrative (“G&A”) expenses increased to $4.7 million during the first quarter of 2011 as compared to $4.4 million for the corresponding period in 2010. This increase primarily resulted from higher compensation expense due to expanding U.S. operations and increased legal, accounting, and consulting fees that pertain to our expanding U.S. operations. Components of G&A expenses for these periods are as follows:

		Three Months Ended
		March 31,
		2011				2010
Compensation		$	5,038			$	4,243
Consulting, legal and accounting fees			1,721				1,527
Occupancy costs			365				249
Other expenses			503				173
Total gross cash G&A expenses			7,627				6,192
Non-cash stock-based compensation			875				1,153
Gross G&A expenses			8,502				7,345
Less: capitalized G & A expenses			(3,789	)			(2,914	)
Net G&A expenses		$	4,713			$	4,431

Interest expense increased by $6.9 million to $12.5 million for the three months ended March 31, 2011 as compared to $5.6 million for the corresponding period in 2010 due to increased interest costs related to the Senior Term Loan, partially offset by the corresponding absence of interest in 2011 from our previously existing senior and junior bank facilities which were repaid concurrently with the issuance of the Senior Term Loan. For the three months ended March 31, 2011 and 2010, we had non-cash interest expense, including amortization of loan costs and discount, of $6.9 million and $3.2 million, respectively.

Income Taxes

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

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(Amounts in thousands, except per unit data)

		UK				U.S.				Other				Total
Three Months Ended March 31, 2011
Net income (loss) before taxes		$	(3,881	)		$	(9,066	)		$	2,776			$	(10,171	)
Current tax expense (benefit)			(532	)			—				—				(532	)
Deferred tax expense (benefit)			(2,182	)			—				—				(2,182	)
Income tax expense (benefit)			(2,714	)			—				—				(2,714	)
Net income (loss)		$	(1,167	)		$	(9,066	)		$	2,776			$	(7,457	)
Three Months Ended March 31, 2010
Net income (loss) before taxes		$	4,127			$	(11,842	)		$	(2,641	)		$	(10,356	)
Current tax expense (benefit)			1,356				—				—				1,356
Deferred tax expense (benefit)			3,536				—				(58	)			3,478
Income tax expense (benefit)			4,892				—				(58	)			4,834
Net loss		$	(765	)		$	(11,842	)		$	(2,583	)		$	(15,190	)

The change in income tax expense (benefit) from $4.8 million to $(2.7) million for the three months ended March 31, 2010 and 2011, respectively, is primarily the result of taxes on decreased income relating to our UK operations. Our U.K. income decreased primarily due to lower sales volumes which generated lower revenues, partially offset by increased realized commodity prices.

In 2011 and 2010, we did not record 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.

Proposed 2011 U.K. Budget

On March 23, 2011, the U.K. Chancellor of the Exchequer introduced his 2011 budget which includes a proposed tax increase, raising the existing supplementary charge on profits from North Sea oil and gas production (which is in addition to the existing corporation tax rate of 30%) from 20% to 32% with effect from March 24, 2011. While we have made no determination as to the impact of the proposed budget on our financial condition, if the budget is enacted in the form proposed, we may be required to recognize an additional non-cash charge resulting from an adjustment to our deferred tax liabilities.

Reconciliation of 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 and net cash provided by operating activities, including non-financial performance indicators and non-GAAP measures as key metrics to manage our business. These metrics demonstrate our ability to maintain or grow production levels and

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(Amounts in thousands, except per unit data)

reserves, internally fund capital expenditures and service debt as well as provide comparisons to other oil and gas exploration and production companies. Net Income (Loss) as Adjusted and Adjusted EBITDA are internal, supplemental measures of our performance that are not required by, or presented in accordance with, GAAP. We view these non-GAAP measures, and we believe that others in the oil and gas industry, securities analysts, investors, and other interested parties view these, or similar, non-GAAP measures, as commonly used analytic indicators to compare performance among companies in our industry and in the evaluation of issuers.

Because Net Income (Loss) as Adjusted and Adjusted EBITDA are not measurements determined in accordance with GAAP and thus are susceptible to varying calculations, our non-GAAP measures as presented may not be comparable to similarly titled measures of other companies. Net Income (Loss) as Adjusted and Adjusted EBITDA have limitations as analytical tools, 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.

Provided below are reconciliations of net loss to the following non-GAAP financial measures: Net Income (Loss) as Adjusted and Adjusted EBITDA.

		Three Months Ended
		March 31,
		2011				2010
Net loss		$	(7,457	)		$	(15,190	)
Impairment of oil and gas properties (net of tax) (1)			—				7,692
Unrealized (gain) loss on derivatives (net of tax) (2)			(5,469	)			1,174
Currency impact on deferred taxes			—				(59	)
Net Loss as Adjusted		$	(12,926	)		$	(6,383	)
Net loss		$	(7,457	)		$	(15,190	)
Unrealized (gain) loss on derivatives			(4,464	)			1,072
Net interest expense			12,418				5,633
Depreciation, depletion and amortization			6,323				5,681
Impairment of oil and gas properties			—				7,692
Income tax expense (benefit)			(2,714	)			4,834
Adjusted EBITDA		$	4,106			$	9,722

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(Amounts in thousands, except per unit data)

Liquidity and Capital Resources

The following table summarizes our net cash flows from operating, investing and financing activities for the periods indicated. For additional details regarding the components of our primary cash flow amounts, see the Condensed Consolidated Statements of Cash Flows under Item 1 of this report.

		Three Months Ended March 31,
		2011				2010
Net cash provided by (used in) operating activities		$	(15,422	)		$	9,414
Net cash used in investing activities		$	(42,407	)		$	(48,316	)
Net cash provided by financing activities		$	110,708			$	43,538

The net cash flows provided by operating activities are primarily impacted by the earnings from our business activities. The cash flows used by operating activities decreased to $15.4 million for the first quarter of 2011 as compared to $9.4 million provided by operating activities for the first quarter of 2010 primarily due to increased interest expense related to our 2010 debt issuances, increased operating expenses and increased current tax expense, partially offset by increased revenue.

The cash provided by or used in investing activities represents expenditures for capital projects, including our acquisition of an additional 20% working interest in the Bacchus field in the North Sea. For the three months ended March 31, 2011, cash used in investing activities was $42.4 million.

The cash provided by financing activities consists of borrowings, payments of preferred dividends, payment of financing costs, and proceeds from the issuance of common stock. On March 30, 2011, we closed a public offering of 11,500,000 shares of our common stock offering for net proceeds of $116.8 million. On April 20, 2011, we used a portion of the net proceeds from this offering to redeem all $81.25 million of our 6% Convertible Senior Notes. We intend to use the remaining net offering proceeds for general corporate purposes.

On March 11, 2011, we entered into an Amendment to the Trust Deed with Smedvig QIF PLC related to our 11.5% convertible bonds due 2014. The Amendment provides for:

	•		the amendment of the maturity date of the 2014 Convertible Bonds from January 24, 2014 to January 24, 2016;
	•		the amendment of the date upon which the holders of the 2014 Convertible Bonds may first exercise a put right, and the occurrence of the conversion price reset if such put right is not exercised, from January 24, 2012 to January 24, 2016; and
	•		a reduction in the interest rate payable from 11.5% to 7.5% on and after March 31, 2014.

The Amendment of our 11.5% Convertible Bonds and the redemption of all $81.25 million of our outstanding 6% Convertible Senior Notes satisfied the two conditions precedent to extend the maturity date of the Senior Term Loan to be August 16, 2013.

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At January 1, 2011, restricted cash represented amounts held in escrow as collateral for lines of credit associated with abandonment liabilities related to our U.K. properties. On February 6, 2011, we amended our Senior Term Loan to increase the security reserved for potential letters of credit from $25 million to $35 million. Upon receipt of sufficient third party financing, this increase in the security amount should allow us to release the $32 million of restricted cash that currently serves as collateral for existing letters of credit with an alternative letter of credit provider

Capital Program

We anticipate spending approximately $150 million during 2011 to fund our oil and gas activities in the U.S. and U.K., with approximately 60% of those expenditures anticipated to be focused on our U.K. assets. During the first quarter of 2011, we spent $20.1 million in capital expenditures. We also spent an additional $21.0 million on acquisitions, primarily related to our purchase of an additional 20% interest in the Bacchus field. First production is expected begin in the second half of 2011.

In the U.K., our activity during 2011 will be primarily concentrated on the Bacchus and Greater Rochelle development projects. At the Bacchus project, we plan to drill three production wells and install the infrastructure to allow first production in the second half of 2011. At the Greater Rochelle project, our focus will be completing engineering and procuring long lead-time equipment to prepare Greater Rochelle for a 2012 first production date from the East Rochelle area. We also intend to begin actual construction of the subsea infrastructure and modifications to the Scott platform to prepare it for production from the Greater Rochelle area. Additionally, we expect to continue to further our development program at our Columbus project, including ongoing engineering assessments for future production and commercial off-take solutions.

Our primary focus during 2011 in the U.S. will be in the Haynesville, Cotton Valley and Marcellus areas as we believe this acreage contains near-term production potential. The ongoing U.S. program and expenditures will be tailored based on early drilling results and U.S. gas prices in 2011. During 2011, we expect to further evaluate our two existing frontier plays in Alabama and Montana through the drilling of additional test wells.

We intend to fund our capital expenditures through cash on hand and cash flow generated from operations. The timing, completion and progress of our 2011 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 technical work. Based on these and other factors, we may increase or decrease our planned capital program or prioritize certain projects over others.

United Kingdom Activity

Activity in the U.K. during 2011 continues to focus on three primary development projects — Bacchus, Columbus, and Greater Rochelle. In October 2010, we completed the sale of our

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Cygnus asset for cash consideration of $110 million. We plan to use the proceeds from the Cygnus sale to accelerate our development projects.

On February 23, 2011, we closed our acquisition of an additional 20% working interest in the Bacchus development for approximately $9.2 million in cash payable at closing and approximately $6.2 million in cash payable three months after first oil is produced. In addition, we paid capital costs incurred by the seller of $9.4 million. Following the acquisition, we hold an aggregate 30% working interest.

The Greater Rochelle area is comprised of three blocks in the North Sea, including our interests in blocks 15/27 and 15/26c. We refer to these blocks as our East Rochelle field and our West Rochelle field, respectively. On February 28, 2011, the DECC approved the Rochelle FDP for Block 15/27 in East Rochelle. On April 18, 2011, we announced agreement of the commercial terms for the processing and transportation of East Rochelle production on the Scott Platform in the Central North Sea. We own a 55.6% interest in East Rochelle and as the operator, we plan to award contracts and commence immediate construction of the production facilities. First production from East Rochelle is planned for the second half of 2012.

Columbus is a gas/condensate field in the Central Graben region of the North Sea in which we hold a 25% working interest. During 2010, we, along with our partners in Columbus, agreed to study an option of producing the field using a new bridge-linked platform connected to the Lomand Platform. We expect to file an updated FDP later in 2011 with project sanction by the DECC anticipated later in the year. We believe that first production from this field could occur as early as 2012.

United States Drilling

We believe that our U.S. acreage provides us with development projects with shorter timeframes to first production at lower costs than our North Sea assets. In addition, our U.S. acreage covers a broad spectrum of resource plays, from established areas, such as Haynesville, Cotton Valley and Marcellus, to emerging plays in Alabama and Montana.

Our strategy for our U.S. operations has been to employ a measured approach that seeks to balance U.S. natural gas prices with drilling costs.

We currently have positions in four U.S. shale resource plays, totaling 565,000 gross acres. Our drilling activity during 2011 has increased as we begin to pursue the potential of these recent acquisitions. During the first quarter of 2011, we had drilling activity at nine wells, primarily in the Haynesville and Cotton Valley areas.

2011 Outlook and Liquidity

Our primary sources of financial resources and liquidity are cash on hand, internally generated cash flows from operations and access to the credit and capital markets, to the extent available. We strive to synchronize our capital expenditures with our cash flow and cash on hand. We believe the combination of our available cash on hand and cash flow from operations will fund

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our capital expenditure program for 2011. In turn, our capital program should allow additional cash flows to be generated as Bacchus and additional U.S. wells begin production.

Our cash flows will be significantly impacted by the amount of oil and gas we produce and the price we obtain for our produced commodities. While we expect our 2011 production to be greater than our 2010 production, that increase will not occur evenly throughout the year. Instead, the anticipated production increase is expected to occur in the latter half of the year. We expect our production in 2011 will grow from current levels as Bacchus achieves first production and new wells in our U.S. drilling program begin production. Each of these operational activities will have an impact on our 2011 production as follows:

	•		Initial production date of the Bacchus field — We expect first production of the Bacchus field to commence in the second half of 2011. The precise initial production date and how long it may take for Bacchus to reach full production are key variables to our overall 2011 production levels.
	•		U.S. drilling program results — We are continuing our drilling operations in the U.S. and expect to have additional production as new successful wells are completed. Currently, we have 11 wells in the US that are either being completed or awaiting completion.
	•		Flow testing at the Goldeneye field — In early December 2010, the Goldeneye field was shut-in due to flow assurance issues resulting from increased water production. During the first quarter of 2011, the field operator performed flow trials to study pipeline hydraulic performance which showed that production from the Goldeneye field was no longer economically sustainable.

Oil prices continue to be impacted by supply and demand on a worldwide basis. Although oil and gas prices have remained volatile, 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 March 31, 2011, our outstanding commodity derivatives covered 50% of our estimated 2011 production from our proved developed reserves.

As discussed earlier, we completed an offering of common stock for net proceeds of $116.8 million in March 2011. In April 2011, we utilized a portion of the net proceeds to repay in full the $81.25 million of our 6% Senior Notes due 2012. The remainder of the net proceeds will be used for general corporate purposes.

Cautionary Statement for Forward-Looking Statements

Certain statements and information in this Quarterly Report on Form 10-Q may constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating

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(Amounts in thousands, except per unit data)

results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. In particular, this report contains forward-looking statement pertaining to the following:

	•		our future financial position;
	•		our business strategy;
	•		budgets;
	•		projected costs, savings and plans;
	•		objectives of management for future operations;
	•		legal strategies; and
	•		legal proceedings.

Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below:

	•		discovery, estimation, development and replacement of oil and gas reserves;
	•		decreases in proved reserves due to technical or economic factors;
	•		drilling of wells and other planned exploitation activities;
	•		timing and amount of future production of oil and gas;
	•		the volatility of oil and gas prices;
	•		availability and terms of capital;
	•		operating costs such as lease operating expenses, administrative costs and other expenses;
	•		our future operating or financial results;
	•		amount, nature and timing of capital expenditures, including future development costs;
	•		cash flow and anticipated liquidity;
	•		availability of drilling and production equipment;
	•		uncertainties related to drilling and production operations in a new region;
	•		business strategy and the availability of acquisition opportunities; and
	•		factors not known to us at this time.

Any of these factors, or a combination of these factors, could materially affect our future financial condition or results of operations and the ultimate accuracy of the forward-looking statements. The forward-looking statements are not guarantees of our future performance, and our actual results and future developments may differ materially from those projected in the forward-looking statements. In addition, any or all of our forward-looking statements in this Quarterly Report on Form 10-Q may turn out to be incorrect. They can be affected by inaccurate assumptions we might make or by known or unknown risks and uncertainties, including those mentioned in our Annual Report on Form 10-K for the year ended December 31, 2010. Except as required by law, we undertake no obligation to update publicly or release any revisions to these forward-looking statements to reflect events or circumstances after the date of report. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

Endeavour International Corporation
(Amounts in thousands, except per unit data)

Item 3: Quantitative and Qualitative Disclosures about Market Risk

Commodity Price Risk

We produce and sell crude oil and natural gas. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and regional gas spot market prices that have been volatile and unpredictable for several years. As a result, our financial results can be significantly impacted as these commodity prices fluctuate widely in response to changing market forces. We may engage in oil and gas hedging activities to realize commodity prices which we consider favorable. For additional information regarding our derivative instruments, see Note 8 to the Condensed Consolidated Financial Statements.

At March 31, 2011, we had the following commodity derivative instruments outstanding:

		2011				2012				Total
Oil:
Fixed Price Puts (Mbbl)			207				100				307
Weighted Average Price ($/Barrel)		$	94.98			$	90.74			$	93.60
Gas: (1)
Fixed Price Puts (MMcf)			885				548				1,433
Weighted Average Price ($/Mcf)		$	7.78			$	8.54			$	8.07

Item 4: Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this Report, our management carried out an evaluation, with the participation of our chief executive officer (the “CEO”) and chief financial officer (the “CFO”), of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(b) or 15d-15(b) of the Securities Exchange Act of 1934, as amended). Based on that evaluation, the CEO and CFO concluded:

(i) that our disclosure controls and procedures are designed to ensure that information we are required to disclose in our reports filed or submitted under the Securities Exchange Act of 1934, as amended, is (a) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (b) is accumulated and communicated to our management, including the CEO and CFO, as appropriate, to allow timely decisions regarding required disclosure; and

Endeavour International Corporation
(Amounts in thousands, except per unit data)

(ii)

that our disclosure controls and procedures were effective as of March 31, 2011.

Changes in Internal Control over Financial Reporting

There was no change in our system of internal control over financial reporting (as defined in Rules 13(a) — 15(f), and 15(d) — 15(f) under the Securities Exchange act of 1934, as amended), during the last fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Part II. Other Information

Item 1A: Risk Factors

In addition to the factors discussed elsewhere in this report, including the financial statements and related notes, you should consider carefully the risks and uncertainties described below and in our Annual Report on Form 10-K for the year ended December 31, 2010 under Item 1A "Risk Factors,” which could materially adversely affect our business, financial condition and results of operations. While these are the risks and uncertainties we believe are most important, you should know that they are not the only risks or uncertainties facing us or that may adversely affect our business. Additional risks and uncertainties not presently known to us or that we currently deem immaterial also could impair our business operations and financial condition. If any of these risks or uncertainties were to occur, our business, financial condition or results of operation could be adversely affected.

Item 6: Exhibits

The exhibits marked with the asterisk symbol (*) are filed or furnished (in the case of Exhibits 32.1 and 32.2) with this Form 10-Q.

3.1(a)

Amended and Restated Articles of Incorporation (Incorporated by reference to Exhibit 3.2 of our Quarterly Report on Form 10-Q (Commission File No. 001-32212) for the quarter ended June 30, 2004.)

3.1(b)

Certificate of Amendment dated June 1, 2006 (Incorporated by reference to Exhibit 4.2 of our Registration Statement on Form S-3 (Commission File No. 333-139304) filed on December 13, 2006.)

3.1(c)

Certificate of Amendment dated June 1, 2010 (Incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on June 3, 2010).

Endeavour International Corporation
(Amounts in thousands, except per unit data)

3.1(d)		Amendment to Articles of Incorporation, dated November 17, 2010 (Incorporated by reference to Exhibit 3.1(d) of our Annual Report on Form 10-K (Commission File No. 001-32212) for the year ended December 31, 2010).
3.2(a)		Amended and Restated Bylaws (Incorporated by reference to Exhibit 3.4 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on November 6, 2006.)
3.2(b)		Amendment to Amended and Restated Bylaws dated December 12, 2007 (Incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on December 13, 2007.)
10.1		First Amendment to Credit Agreement, U.S. Security Agreement and Subsidiaries Guaranty, dated February 3, 2011, by and among Endeavour International Corporation, Endeavour Energy UK Limited, Cyan Partners, LP, as administrative agent, and the lenders party thereto (Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on February 9, 2011).
10.2		Amendment Deed dated March 11, 2011, to Trust Deed dated January 24, 2008 by and among Endeavour International Corporation, Endeavour Energy Luxembourg S.a.r.l. and BNY Corporate Trustee Services Limited, as trustee (Incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on March 14, 2011).
31.1*		Certification of William L. Transier, Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*		Certification of J. Michael Kirksey, Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*		Certification of William L. Transier, Chief Executive Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*		Certification of J. Michael Kirksey, Chief Financial Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Signatures

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

Endeavour International Corporation
Date: May 5, 2011		/s/ J. Michael Kirksey				/s/ Robert L. Thompson
		J. Michael Kirksey				Robert L. Thompson
		Executive Vice President and				Senior Vice President and
		Chief Financial Officer				Chief Accounting Officer
		(Principal Financial Officer)				(Principal Accounting Officer)