United States Securities and Exchange Commission
Washington, D.C. 20549
Form 10-Q
(Mark One) [X] Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the Quarterly Period Ended June 30,2013 or [  ]  Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the transition period from _________ to ___________
Commission file number:001-32212
Endeavour International Corporation
(Exact name of registrant as specified in its charter)
Nevada	88-0448389
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
811 Main Street, Suite 2100, 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   ¨   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).  þ Yes   ¨   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 ¨Accelerated filer  þ Non-accelerated filer  ¨ (Do not check if a smaller reporting company)Smaller reporting company  ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨  Yes   þNo
As of August 7, 2013, 47.1 million shares of the registrant’s common stock were outstanding.

Index

	Page
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	29
Operations
Item 3:  Quantitative and Qualitative Disclosures About Market Risk	47
Item 4:  Controls and Procedures	47
Part II.  Other Information
Item 1A:  Risk Factors	48
Item 6:  Exhibits	48
Signatures	50

Quantities of natural gas are expressed in this report in terms of thousand cubic feet (Mcf) and million cubic feet (MMcf).  Oil, which includes natural gas liquids, 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 barrel of oil is the energy equivalent of six Mcf of natural gas. This is a physical correlation and does not reflect a value or price relationship between the commodities. 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

Condensed Consolidated Balance Sheets

(Unaudited)

(Amounts in thousands)

	June 30,		December 31,
	2013		2012
Assets
Current Assets:
Cash and cash equivalents	$	130,790	$	59,185
Accounts receivable		28,612		46,181
Prepaid expenses and other current assets		33,933		20,995
Total Current Assets		193,335		126,361
Property and Equipment, Net ($384,003 and $349,433 not subject to
amortization at June 30, 2013 and December 31, 2012, respectively)		1,054,834		1,003,441
Goodwill		259,238		262,764
Other Assets		39,065		49,906
Total Assets	$	1,546,472	$	1,442,472

See accompanying notes to condensed consolidated financial statements.

1

Endeavour International Corporation

Condensed Consolidated Balance Sheets

(Unaudited)

(Amounts in thousands)

	June 30,		December 31,
	2013		2012
Liabilities and Stockholders’ Equity
Current Liabilities:
Accounts payable	$	72,212	$	60,153
Current maturities of debt		115,163		15,713
Monetary production payment, current portion		20,833		-
Accrued expenses and other		96,154		90,100
Total Current Liabilities		304,362		165,966
Long-Term Debt		749,894		843,793
Deferred Taxes		125,146		141,887
Monetary production payment, long-term portion		104,167		-
Other Liabilities		134,075		147,692
Total Liabilities		1,417,644		1,299,338
Commitments and Contingencies
Series C Convertible Preferred Stock:
Series C preferred stock - Liquidation preference:  $37,000 and $37,000
at June 30, 2013 and December 31, 2012, respectively		43,703		43,703
Stockholders’ Equity:
Series B preferred stock - Liquidation preference:  $3,666 and $3,588
at June 30, 2013 and December 31, 2012, respectively		-		-
Common stock; shares issued and outstanding – 47,137 and 46,691
at June 30, 2013 and December 31, 2012, respectively		47		47
Additional paid-in capital		508,340		493,803
Treasury stock, at cost - 72 and 72 shares at June 30, 2013
and December 31, 2012, respectively		(587)		(587)
Accumulated deficit		(422,675)		(393,832)
Total Stockholders’ Equity		85,125		99,431
Total Liabilities and Stockholders’ Equity	$	1,546,472	$	1,442,472

See accompanying notes to condensed consolidated financial statements.

2

Endeavour International Corporation

Condensed Consolidated Statements of Operations

(Unaudited)

(Amounts in thousands, except per share data)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012
Revenues	$	126,165	$	23,003	$	183,837	$	38,169
Cost of Operations:
Operating expenses		38,103		5,742		55,593		10,640
Depreciation, depletion and amortization		51,923		10,627		74,870		18,533
Impairment of oil and gas properties		-		19,960		3,534		35,700
General and administrative		4,882		5,030		10,364		10,353
Total Expenses		94,908		41,359		144,361		75,226
Income (Loss) From Operations		31,257		(18,356)		39,476		(37,057)
Other Income (Expense):
Unrealized gains (losses) on derivatives		(1,277)		3,805		303		(973)
Interest expense		(24,447)		(25,256)		(45,885)		(44,963)
Loss on early extinguishment of debt		-		(21,661)		-		(21,661)
Letter of credit fees		(7,128)		(3,064)		(18,508)		(3,064)
Other income (expense)		(1,009)		(611)		8,871		(3,282)
Total Other Expense		(33,861)		(46,787)		(55,219)		(73,943)
Loss Before Income Taxes		(2,604)		(65,143)		(15,743)		(111,000)
Income Tax Expense (Benefit)		11,281		(14,335)		12,189		(24,929)
Net Loss		(13,885)		(50,808)		(27,932)		(86,071)
Preferred Stock Dividends		456		456		911		911
Net Loss to Common Stockholders	$	(14,341)	$	(51,264)	$	(28,843)	$	(86,982)
Net Loss per Common Share:
Basic and Diluted	$	(0.30)	$	(1.31)	$	(0.61)	$	(2.26)
Weighted Average Number of Common Shares Outstanding:
Basic and Diluted		47,092		39,020		47,076		38,438

See accompanying notes to condensed consolidated financial statements.

3

Endeavour International Corporation

Condensed Consolidated Statements of Cash Flows

(Unaudited)

(Amounts in thousands)

	Six Months Ended
		June 30,
	2013		2012
Cash Flows from Operating Activities:
Net loss	$	(27,932)	$	(86,071)
Adjustments to reconcile net loss to net cash
provided by (used in) operating activities:
Depreciation, depletion and amortization		74,870		18,533
Impairment of oil and gas properties		3,534		35,700
Deferred tax benefit		(2,457)		(24,008)
Unrealized (gains) losses on derivatives		(303)		973
Amortization of non-cash compensation		1,632		3,114
Amortization of loan costs and discount		8,695		7,311
Non-cash interest expense		3,454		5,153
Loss on early extinguishment of debt		-		21,661
Other		(2,444)		4,687
Changes in operating assets and liabilities:
(Increase) decrease in receivables		17,568		(15,670)
(Increase) decrease in other current assets		2,355		(23,970)
Increase (decrease) in liabilities		(7,361)		24,500
Net Cash Provided by (Used in) Operating Activities		71,611		(28,087)
Cash Flows From Investing Activities:
Capital expenditures		(107,314)		(116,458)
Acquisitions, net of cash acquired		(1,472)		(228,105)
Increase in restricted cash		-		(178)
Net Cash Used in Investing Activities		(108,786)		(344,741)
Cash Flows From Financing Activities:
Repayments of borrowings		-		(244,565)
Borrowings under debt agreements, net of debt discount		-		580,000
Proceeds from issuance of common stock		-		61,088
Proceeds from issuance of monetary production payment		125,000		-
Dividends paid		(416)		(416)
Payments for early extinguishment of debt		-		(7,248)
Financing costs paid		(15,804)		(27,500)
Other financing		-		3
Net Cash Provided by Financing Activities		108,780		361,362
Net Increase (Decrease) in Cash and Cash Equivalents		71,605		(11,466)
Cash and Cash Equivalents, Beginning of Period		59,185		106,036
Cash and Cash Equivalents, End of Period	$	130,790	$	94,570

See accompanying notes to condensed consolidated financial statements.

4

Endeavour International Corporation

Notes to Condensed Consolidated FinancialStatements

(Unaudited)

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

Note 1 – General

Description of Business

Endeavour International Corporation is an independent oil and gas company engaged in the exploration, development, production and acquisition of energy reserves in the U.S. and the U.K.  Endeavour was incorporated under the laws of the state of Nevada on January 13, 2000.  As used in these Notes to Condensed 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.  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, 2012.

2013 Liquidity and Capital Resources

Being highly leveraged, required development capital expenditures, debt service and other long-term obligations will continue to require a significant portion of our cash flow from operations and available cash on hand.  The combination of these debt servicing requirements, capital expenditures and the delay in cash flow resulting from the Rochelle mechanical issues may exceed the cash flow from our current operations.

During the remainder of 2013, our primary uses of financial resources are expected to be:

· our capital expenditures, primarily related to our drilling activities at our Alba, Bacchus and Rochelle fields in the U.K.; and

· interest payments on existing credit facilities and payments in support of our reimbursement agreements covering our abandonment obligations.

We believe we should be able to fund operations for the foreseeable future including our capital expenditures and other expenditure requirements based on our projections of funds generated from operations, cash available and existing sources of financing.  Since year-end 2012, we have also completed several transactions to improve our liquidity position and extended the maturities of some of our debt and other obligations.  The completion of these financing activities are designed to provide sufficient liquidity to bring the Rochelle development on line, drill a third well at Bacchus and allow sufficient time for a thoughtful and disciplined strategic review process.  These transactions include:

· extending or replacing reimbursement agreements covering certain of our abandonment liabilities in the U.K. which would have matured in 2013;

· entering into a forward sale agreement, which was repaid during the second quarter of 2013;

· entering into a monetary production payment; and

· extending the maturity of the commitments under our revolving credit facility.

5

Endeavour International Corporation

Notes to Condensed Consolidated FinancialStatements

(Unaudited)

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

If we are unable to meet any short-term liquidity needs out of cash on hand, we would attempt to refinance debt, sell forward our production, sell assets, issue debt or equity or perform any other alternatives.  No assurance can be given however that we could successfully consummate any of these alternatives.

Note 2 – Summary of Significant Accounting Policies

Basis of Presentation and Use of Estimates

The accompanying unaudited condensed consolidated 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 regularly 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; and

· fair value of derivative instruments.

Note 3 – Business Combinations

On December 23, 2011, we entered into a Sale and Purchase Agreement (the “Purchase Agreement”), through our wholly owned subsidiary Endeavour Energy UK Limited (“EEUK”), with ConocoPhillips (U.K.) Limited, ConocoPhillips Petroleum Limited and ConocoPhillips (U.K.) Lambda Limited, subsidiaries of ConocoPhillips (collectively, the “Sellers”), to acquire their interest in three producing U.K. oil fields in the Central North Sea.

6

Endeavour International Corporation

Notes to Condensed Consolidated FinancialStatements

(Unaudited)

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

On May 31, 2012, we closed the Alba field portion of the acquisition, which consisted of an additional 23.43% interest in the Alba field.  This increased our total working interest in the Alba field to 25.68%.  The Alba Acquisition was closed for aggregate cash consideration of approximately $229.6 million.

The acquisition of the additional interest in the Alba field was accounted for using the business combination method.  The following summarizes the allocation of the purchase price for the Alba field acquisition:

Purchase price	$	255,400
Purchase price adjustments for estimated after-tax cash flows from the acquired asset and
interest costs from economic date of January 1, 2011 to closing		(25,823)
Total purchase price	$	229,577
Allocation of purchase price:
Property and equipment	$	191,507
Goodwill		47,353
Current assets		24,632
Current liabilities		(12,815)
Deferred tax liability		(6,999)
Other long-term liabilities		(14,101)
Total purchase price	$	229,577

Goodwill was the excess of the consideration transferred over the net assets recognized and represents the future economic benefits arising from assets acquired that could not be individually identified and separately recognized. 

The purchase price allocation is based on an assessment of the fair value of the assets acquired and liabilities assumed in the Alba field acquisition.  The assessments of the fair values of oil and gas properties acquired were based on projections of expected future net cash flows, discounted to present value. 

The following table sets forth unaudited pro forma condensed combined financial and operating data which are presented to give effect to the Alba acquisition as if it had occurred on January 1, 2012.  The information does not purport to be indicative of actual results, if any of these transactions had been in effect for the periods indicated, or future results.

		Pro Forma
		Three Months Ended		Six Months Ended
		June 30, 2012		June 30, 2012
Revenues	$	23,013	$	110,685
Net income (loss) to common shareholders	$	(25,186)	$	(50,642)
Net income (loss) per share - basic and diluted	$	(0.65)	$	(1.32)

7

Endeavour International Corporation

Notes to Condensed Consolidated FinancialStatements

(Unaudited)

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

Revenues and income from operations associated with the acquired interest in the Alba field for the three months ended June 30, 2013 were $94.9 million and $11.5 million, respectively.  Revenues and income from operations associated with the acquired interest in the Alba field for the six months ended June 30, 2013 were $116.2 million and $15 million, respectively.  Revenues and income from operations associated with the acquired interest in the Alba field for the period from May 31, 2012 through June 30, 2012 did not have a significant impact on our revenues and results of operations.

After substantial effort and extensions, we and the Sellers were unable to reach the agreement required to transfer the interests in the two remaining U.K. oil fields under the Purchase Agreement due to failure to agree on certain commercial terms related to the future timing and amount of collateral required to be posted for future decommissioning costs.

As a result of the parties being unable to reach agreement to enable the additional transfers to occur, the Purchase Agreement terminated in accordance with its terms on December 14, 2012.  As previously disclosed, we paid a $10 million deposit in connection with the acquisition of the interests in the two remaining fields, which ConocoPhillips retained.

Note 4 –  Property and Equipment

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

		June 30,		December 31,
		2013		2012
Oil and gas properties under the full cost method:
Subject to amortization	$	996,270	$	915,801
Not subject to amortization:
Incurred in 2013		52,508		-
Incurred in 2012		144,865		141,837
Incurred in 2011		99,971		107,510
Incurred prior to 2011		86,659		100,086
		1,380,273		1,265,234
Computers, furniture and fixtures		8,733		8,863
Total property and equipment		1,389,006		1,274,097
Accumulated depreciation, depletion and amortization		(334,172)		(270,656)
Net property and equipment	$	1,054,834	$	1,003,441

8

Endeavour International Corporation

Notes to Condensed Consolidated FinancialStatements

(Unaudited)

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

The costs not subject to amortization include:

· values assigned to unproved reserves acquired,

· exploration costs such as drilling costs for projects awaiting approved development plans 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 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.

For the three months ended June 30, 2013 and 2012, we capitalized $7.6 million and $6.3 million, respectively, in interest related to exploration and development. For the six months ended June 30, 2013 and 2012, we capitalized $13.8 million and $11.9 million, respectively, in interest related to exploration and development, primarily related to our U.K. activities. For the three months ended June 30, 2013 and 2012, we capitalized $1.8 million and $5.3 million, respectively, in certain directly related employee costs.  For the six months ended June 30, 2013 and 2012, we capitalized $6.8 million, and $9.8 million, respectively, in certain directly related employee costs. 

For the second quarter of 2013, we did not record a pre-tax impairment for any of our oil and gas properties after the application of the full cost ceiling test.  The prices used for our U.S. impairment analysis were $91.60 per barrel for oil and $3.46 per Mcf for gas.  Our U.K. impairment analysis utilized prices of $107.58 per barrel for oil and $10.24 per Mcf for gas.

For the second quarter of 2012, we recorded a pre-tax impairment of $20.0 million related to our U.S. oil and gas properties through the application of the full cost ceiling test at the end of the quarter.  For the six months ended June 30, 2012, we recorded a pre-tax impairment of $35.7 million related to our U.S. oil and gas properties.  The impairment was primarily due to the decline in U.S. gas prices.  The prices used to determine the impairment for our U.S. properties were $95.54 per barrel for oil and $3.13  per Mcf for gas. We did not have an impairment of U.K. oil and gas properties through the application of the full cost ceiling test at the end of the second quarter of 2012, which utilized prices of $112.40 per barrel for oil and $8.68 per Mcf for gas.

9

Endeavour International Corporation

Notes to Condensed Consolidated FinancialStatements

(Unaudited)

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

Note 5 – Debt Obligations

At June 30, 2013, we had $878.3 million in outstanding debt.  Our debt consisted of the following at June 30, 2013 and December 31, 2012:

		June 30,		December 31,
		2013		2012
Senior notes, 12% fixed rate, due 2018	$	554,000	$	554,000
Convertible senior notes, 5.5% fixed rate, due 2016		135,000		135,000
Revolving credit facility, 13% fixed rate, due 2014		115,163		115,163
Convertible bonds, 11.5% until March 31, 2014 and 7.5% thereafter, due 2016		74,114		70,029
		878,277		874,192
Less:  debt discount, net of premium		(13,220)		(14,686)
Less:  current maturities		(115,163)		(15,713)
Long-term debt	$	749,894	$	843,793

Senior Notes

On February 23, 2012, we closed the private placement of $350 million aggregate principal amount of 12% first priority notes due 2018 (the “First Priority Notes”) and $150 million aggregate principal amount of 12% second priority notes due 2018 (the “Second Priority Notes,” and, together with the First Priority Notes, the “2018 Notes”),with an aggregate $20 million discount.  We also paid approximately $21 million in other financing costs related to the 2018 Notes.

On October 15, 2012 we completed our private placement offering of $54 million aggregate principal amount of additional First Priority Notes.

5.5% Convertible Senior Notes

In July 2011, we issued $135 million aggregate principal amount of our 5.5% Convertible Senior Notes due July 15, 2016.  Interest on these notes is payable semi-annually at a rate of 5.5% per annum.  The 5.5% Convertible Senior Notes are convertible into shares of our common stock at an initial conversion rate of 54.019 shares (equivalent to $18.51 per share) of common stock per $1,000 principal amount of the notes, subject to certain anti-dilution adjustments.

10

Endeavour International Corporation

Notes to Condensed Consolidated FinancialStatements

(Unaudited)

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

Revolving Credit Facility

During 2012, we entered into a $100 million Credit Agreement (the “Revolving Credit Facility”), with Cyan Partners, LP (“Cyan”), as administrative agent, which was subsequently increased to $125 million.  In connection with the increase, we agreed to pay a fee of $1.25 million to Cyan.

Borrowings under the Revolving Credit Facility bear interest at a rate of 13%per year. As of June 30, 2013 and December 31, 2012, we had $115.2 million outstanding under the Revolving Credit Facility.

In the first half of 2013, we entered into amendments to the Revolving Credit Facility whereby (i) the lenders consented to the Production Payment Transaction (discussed in Note 14) and (ii) extended the maturity of the commitments under the under the Revolving Credit Facility was extended from October 12, 2013 to June 30, 2014.

11.5% Convertible Bonds

Our 11.5% Convertible Bonds bear interest at a rate of 11.5% per annum until March 31, 2014 and 7.5% thereafter.  Interest is compounded quarterly and added to the outstanding principal balance each quarter.  The bonds are convertible into shares of our common stock at an initial conversion price of $16.52 per $1,000 of principal, which represents a conversion rate of approximately 61 shares of our common stock per $1,000 of principal.

Fair Value

The fair value of our outstanding debt obligations was $770 million and $870 million at June 30, 2013 and December 31, 2012, respectively.  The fair values of long-term debt were determined based upon external market quotes for our Senior Notes and an income approach for other debt, using a credit adjusted discount rate at the reporting date, and classified as Level 3 in the fair value hierarchy.

Note 6 – Income Taxes 

Our U.S. operations are taxed at a statutory rate of 35%.  However, we currently do not record tax benefits due to losses in the U.S. as there is no assurance that we will generate any U.S. taxable earnings, resulting in a full valuation allowance of all deferred tax assets generated.

Our income tax expense relates primarily to our operations in the U.K. which are taxed at a statutory rate of 62% plus an additional Petroleum Revenue Tax on our Alba field.  The current tax expense (benefit) is related to Petroleum Revenue Tax on our Alba field. 

Note 7 – Long-Term Liabilities

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 six months ended June 30, 2013 and 2012:

		Six Months Ended
		June 30,
		2013		2012
Carrying amount of asset retirement obligations as of beginning of period	$	176,076	$	47,258
Accretion expense (included in DD&A expense)		11,355		3,750
Impact of foreign currency exchange rate changes		(10,594)		1,162
Payment of asset retirement obligations		(14,268)		(4,741)
Liabilities incurred and assumed		(5,756)		16,742
Carrying amount of asset retirement obligations, as of end of period		156,813		64,171
Less:  Current portion of asset retirement obligations		(30,459)		(2,117)
Long-term asset retirement obligations	$	126,354	$	62,054

Monetary Production Payment

Our monetary production payment liability consisted of the following at June 30, 2013 and December 31, 2012:

		June 30,		December 31,
		2013		2012
Monetary production payment	$	125,000	$	-
Less:  current portion		(20,833)		-
Long-term monetary production payment	$	104,167	$	-

In 2013, our wholly-owned subsidiary, EEUK, entered into a sale and purchase agreement for (i) $125 million providing for a monetary production payment (the “Production Payment”) over the proceeds of sale from a portion of EEUK’s entitlement to production from its interests in the Alba and Bacchus fields located in the U.K. sector of the North Sea and (ii) the issuance of warrants (discussed below).  Repayment of the production payment will come solely from the

11

Endeavour International Corporation

Notes to Condensed Consolidated FinancialStatements

(Unaudited)

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

proceeds from the sale of production from EEUK’s entitlement from the Alba and Bacchus fields.  Obligations under the Production Payment will cease upon the earlier of the repayment of amounts outstanding under the Production Payment or production from the Alba and Bacchus licences permanently ceasing.  We currently expect repayment of the Production Payment to occur by the end of 2014.  If the Production Payment remains outstanding as expected through the end of 2014, the total repayment will be approximately $145.8 million.  We incurred $21.2 million in costs related to the issuance of the Production Payment, including $7.6 million related to the fair market value of the warrants issued.

Our obligations under the Production Payment are secured by first priority liens over our interests in the licences and joint operating agreements relating to the Alba and Bacchus fields and the accounts into which proceeds from the sale of production from such fields are paid.  Our obligations are also secured by second priority liens over certain of our other licences, joint operating agreements and assets.

In connection with the Production Payment, we issued warrants to purchase a total of 3,440,000 shares of our common stock at an exercise price of $3.014 per share, expiring on April 30, 2018, and warrants to purchase a total of 560,000 shares of our common stock at an exercise price of $3.685 per share, expiring on May 21, 2018.

Both warrant agreements are subject to customary anti-dilution provisions and include a cashless exercise provision entitling the investors to surrender a portion of the underlying common stock that has a value equal to the aggregate exercise price in lieu of paying cash upon exercise of a warrant.

Note 8 – 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:

		Three Months Ended				Six Months Ended
		June 30,				June 30,
	2013		2012		2013		2012
G & A Expenses	$	1,314	$	1,141	$	1,632	$	2,258
Capitalized G & A		203		415		1,575		856
Total non-cash stock-based compensation	$	1,517	$	1,556	$	3,207	$	3,114

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Endeavour International Corporation

Notes to Condensed Consolidated FinancialStatements

(Unaudited)

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

At June 30, 2013, total compensation cost related to awards not yet recognized was approximately $9.6 million and is expected to be recognized over a weighted average period of less than three years.

Stock Options

The fair value of each option award is estimated on the date of grant using the Black-Scholes option-pricing model. We did not grant any stock options during 2012 or 2013.  Information relating to outstanding 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, 2013	188	$	6.72
Forfeited	(1)		8.72
Balance outstanding - June 30, 2013	187	$	6.71	5.0	$	4
Currently exercisable - June 30, 2013	187	$	6.71	5.0	$	4

Restricted Stock

Restricted stock awards are valued based on the closing price of our common stock on the measurement date, which is typically the date of grant.  The status of the restricted shares granted as of June 30, 2013 and the changes during the six months ended June 30, 2013 are presented below:

				Weighted
				Average Grant
				Date Fair
		Number of		Value per
		Shares		Share
Balance outstanding - January 1, 2013		754	$	10.11
Granted		562		5.23
Vested		(335)		10.14
Forfeited		(116)		7.29
Balance outstanding - June 30, 2013		865	$	7.37
Total grant date fair value of shares vesting during the period	$	3,397

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Endeavour International Corporation

Notes to Condensed Consolidated FinancialStatements

(Unaudited)

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

Performance-Based Share Awards

Certain of our executive officers were granted a target number of performance shares under individual Performance Unit Award Agreements.  The performance shares will be earned as the relative total shareholder return ranking is measured among a designated peer group at the end of a three-year performance period.  Payouts will be based on a predetermined schedule at the end of the performance period. The shares issued may range from 0% to 200% of the number of Performance Units specified in the agreements. The fair value of each performance-based award is estimated on the date of grant using a Monte Carlo simulation model.

The status of the performance-based share awards as of June 30, 2013  and the changes during the six months ended June 30, 2013 are presented below:

			Weighted
			Average Grant
			Date Fair
	Number of		Value per
	Shares		Share
Balance outstanding - January 1, 2013	357	$	16.72
Granted	562		7.41
Forfeited	(16)		10.56
Balance outstanding - June 30, 2013	903	$	11.04

Note 9 – Loss 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 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 were not included because their inclusion would be anti-dilutive.

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Endeavour International Corporation

Notes to Condensed Consolidated FinancialStatements

(Unaudited)

(Amounts in tables 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:

	June 30,
	2013	2012
Warrants, options and stock-based compensation	8,098	2,896
Convertible debt	11,779	11,298
Convertible preferred stock	4,229	4,229
	24,106	18,423

Note 10 – Related Party Transactions

The Founding Partner and Chief Investment Officer of Cyan, Ashok Nayyar, became a member of our Board of Directors in September 2012.  In September 2012, we increased the amount available for borrowing under the Revolving Credit Facility to $125 million and borrowed $15 million of the additional capacity.  In connection with the increase, we agreed to pay a fee of $1.25 million to Cyan.  Mr. Nayyar resigned from our Board of Directors in March 2013.

Note 11 – Fair Value Measurements

We measure the fair value of financial assets and liabilities on a recurring basis, defining 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.  The fair value is 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.  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, derived from observable data, or supported by observable levels at which transactions are executed in the marketplace.

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Endeavour International Corporation

Notes to Condensed Consolidated FinancialStatements

(Unaudited)

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

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 derivative instruments 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 financial instruments by pricing levels as of June 30, 2013 and December 31, 2012:

	Quoted Market Prices			Significant Other			Significant
	in Active Markets -			Observable Inputs -			Unobservable Inputs			Total
	Level 1			Level 2			Level - 3			Fair Value
Embedded derivative liabilities:
As of June 30, 2013		$	-		$	-		$	(7,099)		$	(7,099)
As of December 31, 2012		$	-		$	-		$	(7,402)		$	(7,402)

We use a derivative valuation model to derive the value of our embedded derivatives.  Key inputs into this valuation model are our current stock price, risk-free interest rates, the stock volatility and our implied credit spread. The first two aforementioned inputs are based on observable market data and are considered Level 2 inputs while the last two aforementioned inputs are unobservable and thus require management’s judgment and are considered Level 3 inputs.  A decrease or increase in the implied credit spread of 5% would increase or decrease, respectively, the liability by approximately $0.7 million.  A similar 5% decrease or increase in the stock volatility has an inverse effect to the change in the liability and would result in an approximately $0.5 million decrease or increase, respectively. 

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

	Six Months Ended
	June 30,
		2013		2012
Balance at beginning of period	$	(7,402)	$	(15,858)
Realized and unrealized gains (losses) included in earnings		303		754
Balance at end of period	$	(7,099)	$	(15,104)
Changes in unrealized gains (losses) relating to derivatives assets and liabilities
still held at the end of the period	$	303	$	754

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Endeavour International Corporation

Notes to Condensed Consolidated FinancialStatements

(Unaudited)

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

Note 12 – Derivative Instruments

We had embedded derivatives related to debt and equity instruments at June 30, 2013.

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

		June 30,		December 31,
		2013		2012
Derivatives not designated as hedges:
Other liabilities - long-term	$	(7,099)	$	(7,402)

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012
Derivatives not designated as hedges:
Unrealized losses on oil and gas commodity derivatives	$	-	$	(887)	$	-	$	(1,904)
Unrealized gains (losses) on embedded derivatives
related to debt and equity instruments	$	(1,277)	$	(2,918)	$	303	$	931

Note 13 – Supplemental Cash Flow Information

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

		Six Months Ended June 30,
		2013		2012
Interest paid	$	44,485	$	25,147
Income taxes paid	$	6,365	$	2,089

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Endeavour International Corporation

Notes to Condensed Consolidated FinancialStatements

(Unaudited)

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

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Endeavour International Corporation

Note 14 – Commitments and Contingencies

Commitments Related to Asset Retirement Obligations

We have several agreements related to abandonment liabilities for certain of our U.K. oil and gas properties.  Under these agreements, unaffiliated third parties pledged cash to secure letters of credit covering certain of our abandonment liabilities and we agreed to reimburse the pledged cash in the event that the letters of credit are drawn and pledged cash is utilized to satisfy the commitment.  We have no cash collateral associated with these agreements and the commitments under the agreements are not recorded as liabilities.  The associated abandonment obligations are recorded in other long-term liabilities as part of our asset retirement obligations.  Fees and expenses related to these agreements are included in “Letter of credit fees” in other expenses on our condensed consolidated statement of operations.

Procurement Agreement

On January 9, 2013, we entered into a LOC Procurement agreement (the “Procurement Agreement”) with an unaffiliated third party entity, which matures on July 9, 2014.  The Procurement Agreement was entered into in connection with the unaffiliated third party’s entry into a credit support arrangement with a providing bank. Pursuant to this credit support arrangement, the third party pledged cash, contributed by one of our shareholders, to secure letters of credit in the amount of $33.0 million. The letters of credit secure decommissioning obligations in connection with certain of our U.K. license agreements.

Under the Procurement Agreement, we agreed:

· to reimburse the third party in the event that the letters of credit are drawn and the pledged cash must be paid to the letter of credit provider;

· pay a quarterly fee computed at a rate of 9% per year on the outstanding amount of each letter of credit, along with an initial fee equal to 1% on the initial outstanding amount of each letter of credit;

· pay a fee of 2% on the outstanding amount of each letter of credit upon termination; and

· pay a fee of 0.65% per year on the aggregate balance of any outstanding letters of credit.

The Procurement Agreement contains customary representations, warranties and non-financial covenants.  We also issued warrants to purchase a total of 1,000,000 shares of our common stock at an exercise price of $7.31 per share to the investor.  The warrants expire on January 9, 2018 and are subject to customary anti-dilution provisions.

Reimbursement Agreements

During 2012, we entered into reimbursement agreements related to abandonment liabilities for certain of our U.K. oil and gas properties. 

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Endeavour International Corporation

One of the reimbursement agreements (the “IVRRH Reimbursement Agreement”) covered approximately $33 million and was related to our decommissioning obligations at the Ivanhoe, Rob Roy, Hamish (collectively, “IVRRH”), Renee and Rubie fields where we are currently paying certain asset retirement costs.  In connection with the execution of the Procurement Agreement, on January 10, 2013, we terminated the IVRRH Reimbursement Agreement and paid all outstanding and accrued fees totaling approximately $3.8 million.

The second reimbursement agreement covers approximately $120 million related to our decommissioning obligations for the Alba field (the “Alba Reimbursement Agreement”).  We pay a fee of 13% per year, payable quarterly, computed based on the outstanding amount of each letter of credit.  In addition, our obligations under the reimbursement agreement are secured on a pari passu basis with our obligations under the Revolving Credit Facility by a first lien on substantially all of our assets.  As of June 30, 2013, we do not expect to begin decommissioning activities for the Alba field for many years.  The timing of decommissioning activities will be determined by the ultimate performance and life of the reservoir.

On March 5, 2013, we amended the Alba Reimbursement Agreement to (i) allow us to enter the Production Payment Transaction (defined below), (ii) extend the maturity of the obligations under the Alba Reimbursement Agreement from December 31, 2013 to June 30, 2014, and (iii) the parties agreed to take the steps necessary to extend the letter of credit issued pursuant to the Alba Reimbursement Agreement from December 31, 2013 to December 31, 2014.

Terminated Acquisition of Marcellus Assets

On July 17, 2011, we entered into agreements with SM Energy Company (“SM Energy”) named therein for the purchase of oil and gas leases, producing properties, geophysical data, a pipeline and related assets in the Marcellus shale play in Pennsylvania for aggregate consideration of approximately $110 million (the “SM Purchase Agreements”).  We terminated the agreements on December 14, 2011, based on our conclusion that: (i) the title defects we identified, after analyzing SM Energy’s responses to the notice of defects and valuation of the defects, exceeded the contractual threshold of 15% of the purchase price for the applicable asset group ($85 million); and (ii) the condition of the pipeline was not in compliance with applicable regulatory standards, which would constitute a material violation of a representation and warranty contained in the applicable SM Purchase Agreement.

SM Energy filed a lawsuit against us in Texas state court on December 20, 2011 alleging that we breached the SM Purchase Agreements by terminating them and refusing to close on the transactions.  Specifically, SM Energy has alleged, among other things, that most of our asserted title defects are without merit and, in any event, would not exceed 15% of the applicable purchase price.  SM Energy seeks the award of unspecified actual damages, including costs and reasonable attorney’s fees, and specific performance.  On January 17, 2012, we filed an answer and counterclaim denying the allegations and seeking the return of our $6 million deposit, which we believe we are entitled to recover pursuant to the terms of the SM Purchase Agreements, and for the damages that we suffered as a result of SM Energy’s misrepresentations.  We intend to contest the case vigorously.

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Endeavour International Corporation

Note 15 – Guarantor Subsidiaries

Certain of our wholly-owned domestic subsidiaries have, jointly and severally, fully and unconditionally guaranteed the Senior Notes.  Pursuant to Securities and Exchange Commission (“SEC”) regulations, we have presented in columnar format the condensed consolidating financial information for Endeavour International Corporation, the guarantor subsidiaries on a combined basis, and all non-guarantor subsidiaries on a combined basis.

The subsidiary guarantees are unsecured obligations of each subsidiary guarantor and rank equally in right of payment with all senior indebtedness of that subsidiary guarantor and senior in right of payment to all subordinated indebtedness of that subsidiary guarantor.  The subsidiary guarantees are effectively subordinated to any secured indebtedness of the subsidiary guarantor with respect to the assets securing the indebtedness.  In addition, the subsidiary guarantees may be released in certain customary circumstances, including (i) the sale of all or substantially all of the properties or assets or a guarantor, (ii) the sale of the capital stock of a guarantor, (iii) the designation of a guarantor as an “Unrestricted Subsidiary,” (iv) upon legal defeasance of the Senior Notes or satisfaction and discharge of the indentures governing the Senior Notes, (v) upon the liquidation or dissolution of the guarantor or (vi) if the guarantor ceases to guarantee other of our indebtedness and ceases to be a material subsidiary, each of which is subject to important limitations in the indentures governing the Senior Notes.

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Endeavour International Corporation

Condensed consolidating financial statements for our guarantor subsidiaries and non-guarantor subsidiaries are presented in the following tables:

As of June 30, 2013
	Endeavour International Corporation		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Cash and cash equivalents	$	-	$	2,622	$	128,168	$	-	$	130,790
Accounts receivable		-		2,305		26,307		-		28,612
Current receivables due from affiliates		913,633		22,459		37,414		(973,506)		-
Prepaid expenses and other		-		1,291		32,642		-		33,933
Current Assets		913,633		28,677		224,531		(973,506)		193,335
Property, plant and equipment, net		-		94,711		960,123		-		1,054,834
Goodwill		-		-		259,238		-		259,238
Long-term receivables due from affiliates		-		599,000		-		(599,000)		-
Investments in subsidiaries		57,662		120,058		-		(177,720)		-
Other assets		23,213		6,056		9,796		-		39,065
Total Assets	$	994,508	$	848,502	$	1,453,688	$	(1,750,226)	$	1,546,472
Accounts payable	$	-	$	3,760	$	68,452	$	-	$	72,212
Current maturities of debt		-		-		115,163		-		115,163
Monetary production payment, current portion		-		-		20,833		-		20,833
Current liabilities due to affiliates		22,712		928,335		22,459		(973,506)		-
Accrued expenses and other		28,219		2,654		65,281		-		96,154
Current Liabilities		50,931		934,749		292,188		(973,506)		304,362
Long-term debt		677,632		-		72,262		-		749,894
Long-term liabilities due to affiliates		-		-		599,000		(599,000)		-
Deferred taxes		-		-		125,146		-		125,146
Monetary production payment, long-term portion		-		-		104,167		-		104,167
Other liabilities		3,408		658		130,009		-		134,075
Total Liabilities		731,971		935,407		1,322,772		(1,572,506)		1,417,644
Series C convertible preferred stock		43,703		-		-		-		43,703
Stockholders' equity		218,834		(86,905)		130,916		(177,720)		85,125
Total Liabilities and Equity	$	994,508	$	848,502	$	1,453,688	$	(1,750,226)	$	1,546,472

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Endeavour International Corporation

As of December 31, 2012
	Endeavour International Corporation		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Cash and cash equivalents	$	-	$	27,800	$	31,385	$	-	$	59,185
Accounts receivable		-		2,695		43,486		-		46,181
Current receivables due from affiliates		950,210		36,725		71,964		(1,058,899)		-
Prepaid expenses and other		-		508		20,487		-		20,995
Current Assets		950,210		67,728		167,322		(1,058,899)		126,361
Property, plant and equipment, net		-		92,692		910,749		-		1,003,441
Goodwill		-		-		262,764		-		262,764
Long-term receivables due from affiliates		-		599,000		-		(599,000)		-
Investments in subsidiaries		57,662		120,058		-		(177,720)		-
Other assets		25,200		6,085		18,621		-		49,906
Total Assets	$	1,033,072	$	885,563	$	1,359,456	$	(1,835,619)	$	1,442,472
Accounts payable	$	-	$	2,622	$	57,531	$	-	$	60,153
Current maturities of debt		-		-		15,713		-		15,713
Deferred revenue		-		-		-		-		-
Monetary production payment deposit		-		-		-		-		-
Current liabilities due to affiliates		34,509		987,664		36,726		(1,058,899)		-
Accrued expenses and other		27,548		1,517		61,035		-		90,100
Current Liabilities		62,057		991,803		171,005		(1,058,899)		165,966
Long-term debt		676,413		-		167,380		-		843,793
Long-term liabilities due to affiliates		-		-		599,000		(599,000)		-
Deferred taxes		-		-		141,887		-		141,887
Monetary production payment, long-term portion		-		-		-		-		-
Other liabilities		3,033		561		144,098		-		147,692
Total Liabilities		741,503		992,364		1,223,370		(1,657,899)		1,299,338
Series C convertible preferred stock		43,703		-		-		-		43,703
Stockholders' equity		247,866		(106,801)		136,086		(177,720)		99,431
Total Liabilities and Equity	$	1,033,072	$	885,563	$	1,359,456	$	(1,835,619)	$	1,442,472

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Endeavour International Corporation

For the Three Months Ended June 30, 2013
	Endeavour International Corporation		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Revenue	$	-	$	2,315	$	123,850	$	-	$	126,165
Operating expenses		-		1,844		36,259		-		38,103
DD&A expense		-		1,007		50,916		-		51,923
Impairment of oil and gas properties		-		-		-		-		-
G&A expenses		577		1,701		2,604		-		4,882
Income (loss) from Operations		(577)		(2,237)		34,071		-		31,257
Derivatives:
Unrealized gains (losses)		323		-		(1,600)		-		(1,277)
Interest expense		(20,814)		898		(19,531)		15,000		(24,447)
Letter of credit fees		-		-		(7,128)		-		(7,128)
Other income (expense)		-		14,520		(529)		(15,000)		(1,009)
Income (loss) before taxes		(21,068)		13,181		5,283		-		(2,604)
Income tax expense		-		-		11,281		-		11,281
Net income (loss)		(21,068)		13,181		(5,998)		-		(13,885)
Preferred stock dividends		456		-		-		-		456
Net income (loss) to common shareholders	$	(21,524)	$	13,181	$	(5,998)	$	-	$	(14,341)

For the Six Months Ended June 30, 2013
	Endeavour International Corporation		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Revenue	$	-	$	4,851	$	178,986	$	-	$	183,837
Operating expenses		-		5,459		50,134		-		55,593
DD&A expense		-		2,146		72,724		-		74,870
Impairment of oil and gas properties		-		3,534		-		-		3,534
G&A expenses		1,308		4,313		4,743		-		10,364
Income (loss) from Operations		(1,308)		(10,601)		51,385		-		39,476
Derivatives:
Unrealized gains (losses)		(377)		-		680		-		303
Interest expense		(40,973)		1,500		(36,411)		29,999		(45,885)
Letter of credit fees		-		-		(18,508)		-		(18,508)
Other income (expense)		(1)		28,998		9,873		(29,999)		8,871
Income (loss) before taxes		(42,659)		19,897		7,019		-		(15,743)
Income tax expense		-		-		12,189		-		12,189
Net income (loss)		(42,659)		19,897		(5,170)		-		(27,932)
Preferred stock dividends		911		-		-		-		911
Net income (loss) to common shareholders	$	(43,570)	$	19,897	$	(5,170)	$	-	$	(28,843)

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Endeavour International Corporation

For the Three Months Ended June 30, 2012
	Endeavour International Corporation		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Revenue	$	-	$	2,863	$	20,140	$	-	$	23,003
Operating expenses		-		1,603		4,139		-		5,742
DD&A expense		-		2,474		8,153		-		10,627
Impairment of oil and gas properties		-		19,960		-		-		19,960
G&A expenses		643		2,450		1,937		-		5,030
Income (loss) from Operations		(643)		(23,624)		5,911		-		(18,356)
Derivatives:
Unrealized gains (losses)		(1,448)		-		5,253		-		3,805
Interest expense		(10,281)		(789)		(20,788)		6,602		(25,256)
Letter of credit fees		-		-		(3,064)		-		(3,064)
Loss on early extinguishment of debt		-		-		(21,661)		-		(21,661)
Other income (expense)		-		5,004		987		(6,602)		(611)
Loss before taxes		(12,372)		(19,409)		(33,362)		-		(65,143)
Income tax benefit		-		-		(14,335)		-		(14,335)
Net loss		(12,372)		(19,409)		(19,027)		-		(50,808)
Preferred stock dividends		456		-		-		-		456
Net loss to common shareholders	$	(12,828)	$	(19,409)	$	(19,027)	$	-	$	(51,264)

For the Six Months Ended June 30, 2012
	Endeavour International Corporation		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Revenue	$	-	$	6,620	$	31,549	$	-	$	38,169
Operating expenses		-		3,237		7,403		-		10,640
DD&A expense		-		5,888		12,645		-		18,533
Impairment of oil and gas properties		-		35,700		-		-		35,700
G&A expenses		1,234		5,808		3,311		-		10,353
Income (loss) from Operations		(1,234)		(44,013)		8,190		-		(37,057)
Derivatives:
Unrealized losses		(379)		-		(594)		-		(973)
Interest expense		(13,494)		(2,115)		(38,097)		8,743		(44,963)
Letter of credit fees		-		-		(3,064)		-		(3,064)
Loss on early extinguishment of debt		-		-		(21,661)		-		(21,661)
Other income (expense)		(1)		4,774		688		(8,743)		(3,282)
Loss before taxes		(15,108)		(41,354)		(54,538)		-		(111,000)
Income tax benefit		-		-		(24,929)		-		(24,929)
Net loss		(15,108)		(41,354)		(29,609)		-		(86,071)
Preferred stock dividends		911		-		-		-		911
Net loss to common shareholders	$	(16,019)	$	(41,354)	$	(29,609)	$	-	$	(86,982)

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Endeavour International Corporation

For the Six Months Ended June 30, 2013
	Endeavour International Corporation		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations (1)		Consolidated
Cash Flows from Operating Activities:
Net loss	$	(42,659)	$	19,897	$	(5,170)	$		$	(27,932)
Adjustments to reconcile net loss to
net cash provided by (used in) operations
DD&A expense		-		2,146		72,724		-		74,870
Impairment of oil and gas properties		-		3,534		-		-		3,534
Deferred tax benefit		-		-		(2,457)		-		(2,457)
Unrealized (gains) losses on derivatives		377		-		(680)		-		(303)
Amortization of non-cash compensation		318		-		-		1,314		1,632
Amortization of loan costs and discount		3,913		-		4,782		-		8,695
Non-cash interest expense		-		(582)		4,036		-		3,454
Loss on early extinguishment of debt		-		-		-		-		-
Other		44		(8)		(2,480)		-		(2,444)
Changes in operating assets and liabilities:
(Increase) decrease in receivables		-		(19,895)		37,463		-		17,568
(Increase) decrease in other current assets		(8)		16,294		(13,931)		-		2,355
Increase (decrease) in liabilities		39,131		(33,720)		(9,883)		(2,889)		(7,361)
Net Cash Provided by (Used in)
Operating Activities		1,116		(12,334)		84,404		(1,575)		71,611
Cash Flows From Investing Activities:
Capital expenditures		-		(6,694)		(102,195)		1,575		(107,314)
Acquisitions, net of cash acquired		-		(390)		(1,082)		-		(1,472)
Proceeds from sales, net of cash		-		-		-		-		-
Issuance of note receivable to affiliate		-		-		-		-		-
Increase in restricted cash		-		-		-		-		-
Net Cash Used in Investing Activities		-		(7,084)		(103,277)		1,575		(108,786)
Cash Flows From Financing Activities:
Repayments of borrowings		-		-		-		-		-
Borrowings under debt agreements, net
of debt discount		-		-		-		-		-
Borrowings from affiliates		-		-		-		-		-
Proceeds from issuance of MPP		-		-		125,000		-		125,000
Proceeds from issuance of common stock		-		-		-		-		-
Dividends paid		(416)		-		-		-		(416)
Payments for early extinguishment of debt		-		-		-		-		-
Financing costs paid		(700)		(5,760)		(9,344)		-		(15,804)
Other financing		2,232		-		-		(2,232)		-
Net Cash Provided by (Used in)
Financing Activities		1,116		(5,760)		115,656		(2,232)		108,780
Net Change in Cash and Cash Equivalents		-		(25,178)		96,783		-		71,605
Cash and Cash Equivalents, Beginning
of Period		-		27,800		31,385		-		59,185
Cash and Cash Equivalents, End of Period	$	-	$	2,622	$	128,168	$	-	$	130,790

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Endeavour International Corporation

For the Six Months Ended June 30, 2012
	Endeavour International Corporation		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations (1)		Consolidated
Cash Flows from Operating Activities:
Net loss	$	(15,108)	$	(41,354)	$	(29,609)	$		$	(86,071)
Adjustments to reconcile net loss to
net cash provided by (used in) operations
DD&A expense		-		5,888		12,645		-		18,533
Impairment of oil and gas properties		-		35,700		-		-		35,700
Deferred tax benefit		-		-		(24,008)		-		(24,008)
Unrealized (gains) losses on derivatives		379		-		594		-		973
Amortization of non-cash compensation		337		-		-		2,777		3,114
Amortization of loan costs and discount		2,899		3,893		519		-		7,311
Non-cash interest expense		160		1,971		3,022		-		5,153
Loss on early extinguishment of debt		-		-		21,661		-		21,661
Other		149		3,351		1,187		-		4,687
Changes in operating assets and liabilities:
(Increase) decrease in receivables		-		74,690		(90,360)		-		(15,670)
(Increase) decrease in other current assets		-		(19,958)		(4,012)		-		(23,970)
Increase (decrease) in liabilities		(508,978)		470,470		65,785		(2,777)		24,500
Net Cash Provided by (Used in)
Operating Activities		(520,162)		534,651		(42,576)		-		(28,087)
Cash Flows From Investing Activities:
Capital expenditures		-		(13,455)		(103,003)		-		(116,458)
Acquisitions, net of cash acquired		-		(26,925)		(201,180)		-		(228,105)
Proceeds from sales, net of cash		-		178		(178)		-		-
Issuance of note receivable to affiliate		-		(500,000)		-		500,000		-
Increase in restricted cash		-		(178)		-		-		(178)
Net Cash Used in Investing Activities		-		(540,380)		(304,361)		500,000		(344,741)
Cash Flows From Financing Activities:
Repayments of borrowings		-		(4,323)		(240,242)		-		(244,565)
Borrowings under debt agreements, net
of debt discount		480,000		-		100,000		-		580,000
Borrowings from affiliates		-		-		500,000		(500,000)		-
Proceeds from issuance of MPP		-		-		-		-		-
Proceeds from issuance of common stock		61,088		-		-		-		61,088
Dividends paid		(416)		-		-		-		(416)
Payments for early extinguishment of debt		-		-		(7,248)		-		(7,248)
Financing costs paid		(20,514)		20,514		(27,500)		-		(27,500)
Other financing		3		(1)		-		1		3
Net Cash Provided by (Used in)
Financing Activities		520,161		16,190		325,010		(499,999)		361,362
Net Change in Cash and Cash Equivalents		-		10,461		(21,927)		-		(11,466)
Cash and Cash Equivalents, Beginning
of Period		-		2,951		103,085		-		106,036
Cash and Cash Equivalents, End of Period	$	-	$	13,412	$	81,158	$	-	$	94,570

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Endeavour International Corporation

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.K. North Sea and U.S. onshore.  Our U.K. operations have been focused on development projects and acquisition, while our U.S. operations have focused primarily on strategic positioning and new reservoir plays.  In 2012 and 2013, our primary focus has been on completing the acquisition of additional interests in the Alba field and then moving the Bacchus and Rochelle fields from development to first production.  We achieved first production from Bacchus and completed the Alba acquisition during the second quarter of 2012.

We began drilling the first of two planned development wells at Rochelle in mid-2012.  We completed the hook-up of the pipelines and flow-lines to the subsea manifolds for the field but encountered operational difficulties following severe weather in early 2013.  As a result, we suspended drilling operations on the East Rochelle well and moved the rig to the second well site at West Rochelle.  The West Rochelle well was completed and flow tested at the end of June 2013.  During a 56-hour flow test, the well flowed up to 60 million standard cubic feet per day, which was the limit of the well test equipment on the drilling rig.  Final installation of the subsea pipeline infrastructure has been completed and the well is connected back to the Scott Platform. First production from the West Rochelle well is expected in September 2013 following the completion of the annual maintenance period at the Scott Platform.

Wehave acquired both producing and exploration acreage in U.S. onshore unconventional oil and gas shale developments targeting reserve and production growth. Our ongoing U.S. program and expenditures have been tailored based on drilling results and the decline in U.S. gas prices over the last several years.  We have limited capital expenditures to those necessary to fulfill drilling commitments and maintain acreage positions.

In the last two years, we have incurred substantial capital expenditures and acquisition costs as we advanced development projects at Bacchus and Rochelle and completed acquisitions.  We also experienced delays in the timing of first production from Bacchus and Rochelle developments, a decline of production from our U.S. drilling operations as we curtailed U.S. capital expenditures in response to declining U.S. gas prices, increased capital costs due to the production delays at the Bacchus and Rochelle projects and increased debt service costs required to finance the drilling and acquisition program.  The production delays and increased capital

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costs and debt service costs placed a strain on our cash flow from operations and our ability to reduce our debt leverage.

Strategic Alternatives

In February 2013, we initiated a review of strategic alternatives and will announce the results of the effort once a course of action is chosen.  The primary objective of the strategic review is to accelerate the deleveraging of the balance sheet and unlock the value of our underlying assets.  The Board of Directors is considering a full range of options, including:

· a sale, joint venture or partnershipin respect of our activities in the North Sea;

· a sale of specific assets;

· a sale or merger of the Company; or

· continuing to execute on our operational plan.

Tudor, Pickering, Holt & Co. and Lambert Energy Advisory Ltd. have been engaged as our financial advisors in this process.  There is no assurance that this strategic alternatives review will result in a change to our current business plan, pursuing a particular transaction or completing any such transaction.

Since year-end 2012,we havealso completed several transactions to improve our liquidityposition and extended the maturities of some of our debt and other obligations.The completion of these recent financing activities are designed to provide sufficient liquidity to bring the Rochelle development on line, drill a third well at Bacchus and allow sufficient time for a thoughtful and disciplined strategic review process.  These transactions include:

· extended or replaced reimbursement agreements covering certain of our abandonment liabilities in the U.K. which would have matured in 2013;

· entered into a forward sale agreement for a payment of approximately $22.5 million in return for a specified volume of crude oil in excess of 200,000 barrels from our U.K. North Sea production, which was fully delivered by June 30, 2013;

· entered into a monetary production payment for $125 million; and

· extended the maturity of the commitments under our revolving credit facility (“Revolving Credit Facility”) from October 12, 2013 to June 30, 2014.

These transactions are discussed in the Notes to our condensed consolidated financial statements.

2013 Liquidity and Capital Resources

During the remainder of 2013, our primary uses of financial resources are expected to be:

· our drilling activities, principally at our Alba, Bacchus and Rochelle fields in the U.K.; and

· interest payments on existing credit facilities and fees related to our reimbursement agreements covering our abandonment obligations.

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As of June 30, 2013, we had $747.5 million in outstanding indebtedness, net of $130.8 million in cash.  Being highly leveraged, required development capital expenditures, debt service and other long-term obligations will continue to require a significant portion of our cash flow from operations and available cash on hand.  The combination of these debt servicing requirements, capital expenditures and the delay in cash flow resulting from the mechanical issues experienced at the Rochelle field may exceed the cash flow from our current operations.

If we are unable to meet any short-term liquidity needs out of cash on hand, we would attempt to refinance debt, sell forward our production, sell assets, issue debt or equity, delay discretionary capital expenditures, decline to participate in non-operated drilling or perform any other alternatives resulting from our strategic review.  No assurance can be given however that we could successfully consummate any of these alternatives.

Results of Operations

Net loss to common stockholders for the six months ended June 30, 2013 was $28.8 million, or $0.61 per share, compared to $87.0 million, or $2.26 per share, for the same period in 2012.  The change in the net loss to common stockholders for these periods is primarily due to increased revenues related to our Bacchus field and the purchase of our additional interest in the Alba field, lower impairments of oil and gas properties and the loss on early extinguishment of debt in 2012, partially offset by increased income tax expense and expenses related to reimbursement agreements covering certain of our abandonment liabilities and increased tax expense.

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, and foreign currency impact of long-term liabilities.  Excluding these non-cash items, Net Loss as Adjusted for the second quarter 2013 was $12.6 million as compared to Net Loss as Adjusted of $17.4 million for the same period in 2012.  The decrease in Net Loss as Adjusted is primarily due to increased revenues, partially offset by increased income tax expense and expenses related to our reimbursement agreements covering certain of our abandonment liabilities.  These impacts on Net Loss as Adjusted were primarily attributable to increased sales volumes at Bacchus and the purchase of our additional interest in the Alba field.

Adjusted EBITDA increased to $82.2 million for the second quarter of 2013 from $11.5 million for the same period in 2012 due to increased revenue from the initial production at Bacchus and our additional interest in Alba, partially offset by foreign currency losses on long-term liabilities and expenses related to our reimbursement agreements covering certain of our abandonment liabilities.  For definitions of Net Loss as Adjusted and Adjusted EBITDA, and a reconciliation of each to the nearest comparable GAAP measure, please see “Reconciliation of Non-GAAP Measures.”

Our cash flows provided by operating activities increased to $71.6 million for the six months ended June 30, 2013 as compared to cash flows used in operating activities of $(28.1) million for the same period in 2012.  The change was primarily due to increased revenue from the initial

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production at Bacchus and our additional interest in Alba and the proceeds of the Forward Sale, partially offset by increased interest expense related to our outstanding indebtedness.

Revenue and Sales Volume

Our physical daily production was 9,498 BOE and 6,437 BOE for the second quarter of 2013 and 2012, respectively, and 9,427 BOE and 5,205 BOE for the six months ended June 30, 2013 and 2012, respectively, reflecting the impact of the initial production from Bacchus and our increased interest in Alba.

For the second quarter of 2013 and 2012, we had sales volume of 14,497 BOE per day and 4,677 BOE per day, respectively.  For the six months ended June 30, 2013and 2012, we had sales volume of 10,862 BOE per day and 4,426 BOE per day, respectively. The increases in sales volume were primarily attributable to the initial production from Bacchus and our increased interest in Alba.

Our revenues increased from $23.0 million during the second quarter of 2012 to $126.2 million in the same period of 2013.  These increases are primarily a result of the initial production from Bacchus, partially offset by lower commodity prices in both the U.S. and U.K. and less than expected production at Alba.

We record oil revenues when deliveries have occurred and legal ownership of the oil transfers to the customer.  While certain of our U.K. oil fields produce into pipelines and thereby allow us to record revenue each month, the remaining fields, including the Alba field, are dependent upon tanker liftings to deliver oil production to the buyers.  For certain of our U.K. fields, including the Alba field, we sell production on a monthly basis, although the production remains in the field’s storage tanks until the tanker lifting.  The inventory associated with these sales remains on our balance sheet and the revenue is deferred until the production is shipped out of our storage tanks.During the first quarter of 2013, production at the Alba field was impacted by an unplanned five-day shutdown and lower than expected production levels due to continuing processing problems.  The lower production levels during the first quarter of 2013 delayed the tanker lifting until the second quarter.  As a result, we had two tanker liftings at Alba during the second quarter of 2013.  The May 31, 2012 closing of the Alba field portion of the COP Acquisition did not allow sufficient time for our production at the field to satisfy a full tanker lifting.  While the timing of tanker liftings affect when we record revenue from Alba, physical production and cash receipts are unaffected.

We may utilize financial commodity derivatives and negotiated pricing in our marketing contracts to achieve a more predictable cash flow by reducing our exposure to price fluctuations.  At June 30, 2013, we had the following floors and ceilings embedded within our marketing contracts:

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Endeavour International Corporation

	Third Quarter	Fourth Quarter	Total
Oil:
Volumes (Mbbl)	276	276	552
Weighted Average Ceiling Price ($/Barrel)	$ 107.56	$ 105.30	$ 106.43
Weighted Average Floor Price ($/Barrel)	$ 96.01	$ 95.00	$ 95.51

The following table shows our average sales volumes and realized sales prices for our operations for the periods presented.

		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2013		2012		2013		2012
Sales volume (1)
Oil and condensate sales (Mbbls):
United Kingdom		1,205		191		1,713		287
United States		1		1		1		2
Total		1,206		192		1,714		289
Gas sales (MMcf):
United Kingdom		15		30		26		51
United States  (2)		667		1,375		1,489		3,052
Total		682		1,405		1,515		3,103
Oil equivalent sales (MBOE)
United Kingdom		1,207		196		1,717		295
United States  (2)		112		230		249		510
Total		1,319		426		1,966		805
Total BOE per day		14,497		4,677		10,862		4,426
Physical production volume (BOE per day) (1)
United Kingdom		8,083		3,910		7,973		2,401
United States  (2)		1,415		2,527		1,454		2,804
Total		9,498		6,437		9,427		5,205
Realized Price, before and after derivatives
Oil and condensate price ($ per Bbl)	$	102.67	$	104.46	$	104.37	$	108.67
Gas price ($ per Mcf)	$	3.50	$	2.14	$	3.30	$	2.20
Equivalent oil price ($ per BOE)	$	95.64	$	54.05	$	93.51	$	47.39

⁽¹⁾ We record oil revenues when deliveries have occurred and legal ownership of the oil transfers to the customer.  Physical production may differ based on the timing of tanker liftings for international sales.

⁽²⁾ In October 2012, we completed an exchange with domestic co-venturer, J-W Operating Company (“J-W”), whereby we exchanged our Bull Bayou Haynesville and Willow 32     Table Of Contents   Endeavour International Corporation   Springs Cotton Valley properties for all of J-W’s upstream and midstream interests in the Pennsylvania Marcellus area.  The transaction added 15,500 net acres to our position in the Marcellus area, bringing the total to 31,000 net acres, and decreased our position in the Haynesville area by 2,100 net acres and approximately 3.2 MMcf equivalent per day (530 BOE per day) of declining net production.

Our revenues, profitability and cash flow depend substantially upon the prices and demand for oil and gas and are subject to numerous operational and financial risks, some of which are beyond our control.  The markets for these commodities are volatile, and even relatively modest drops in prices can significantly affect our financial results and impede our growth.

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.  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.

Expenses

For the second quarter of 2013, operating expenses increased to $38.1 million as compared to $5.7 million for the same period in 2012.  For the six months ended June 30, 2013 and 2012, operating expenses were $55.6 million and $10.6 million, respectively.  These increases were primarily due to costs related to our increased interest in the Alba field and initial production from the Bacchus field. 

Operating costs per BOE increased from $13.49 per BOE for the second quarter of 2012 to $28.88 per BOE for the same period in 2013 primarily due to the increasing portion of U.K. operations contributing to our total expenses.  On average, our U.K. operations have higher operating costs per BOE than our U.S. operations, thereby increasing our overall operating costs per BOE as more of our production comes from the U.K.

Depreciation, depletion and amortization (“DD&A”) expense increased to $51.9 million from $10.6 million for the second quarter of 2013 and 2012, respectively, and to $74.9 million from $18.5 million for the six months ended June 30, 2013 and 2012, respectively.  These increases were primarily a result of the increased sales volumes discussed previously and additional accretion expense related to the increased abandonment liabilities assumed upon the closing of the Alba field acquisition.

We did not record an impairment during the second quarter of 2013.  For the second quarter of 2013, the prices used in the full cost ceiling test for our U.S. properties were $91.60 per barrel for oil and $3.46 per Mcf for gas.  For the second quarter of 2013, the prices used in the full cost

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ceiling test for our U.K. properties were $107.58 per barrel for oil and $10.24 per Mcf for gas.  We have not recorded any impairment related to our U.K. properties.  The risk that we will be required to record additional 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. If U.S. gas prices continue to face the adverse effects of high gas supply or other factors, we may experience further ceiling test write-downs or other impairments in the future.

General and administrative (“G&A”) expenses decreased slightly to $4.9 million during the second quarter of 2013 as compared to $5.0 million for the corresponding period in 2012 as a result of a decrease in employee compensation expense.  Components of G&A expenses for these periods are as follows:

(Amounts in thousands)		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2013		2012		2013		2012
Compensation	$	4,597	$	5,308	$	10,988	$	10,506
Consulting, legal and accounting fees		2,369		2,331		4,938		4,105
Amounts recovered from joint interest partners		(3,967)		(1,043)		(5,054)		(1,733)
Other expenses		2,149		1,738		3,122		3,501
Total gross cash G&A expenses		5,148		8,334		13,994		16,379
Non-cash stock-based compensation		1,517		1,556		3,207		3,114
Gross G&A expenses		6,665		9,890		17,201		19,493
Less:  capitalized G&A expenses		(1,783)		(4,860)		(6,837)		(9,140)
Net G&A expenses	$	4,882	$	5,030	$	10,364	$	10,353

As discussed in “Liquidity and Capital Resources,” we have completed several financing transactions during 2013 and 2012 that have had a significant impact on our interest expense.  Interest expense has increased as a result of borrowings under the Revolving Credit Facility, and the issuance of the 2018 Notes in February 2012. This increase has been partially offset by our repayment of the Senior Term Loan in May 2012 and the Subordinated Notes in October 2012.  In addition, we capitalize a portion of interest as a result of our increased drilling activity at Bacchus and Rochelle.  The components of interest expense are as follows:

(Amounts in thousands)	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012
Interest expense on debt outstanding
at June 30, 2013	$	26,781	$	20,820	$	50,954	$	30,796
Interest expense on retired debt		-		7,120		-		18,707
Amortization of loan costs and discount		5,257		3,642		8,695		7,311
Gross interest expense		32,038		31,582		59,649		56,814
Less:  capitalized interest		(7,591)		(6,326)		(13,764)		(11,851)
Net interest expense	$	24,447	$	25,256	$	45,885	$	44,963

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Interest expense decreased slightly to $24.4 million for the second quarter of 2013 as compared to $25.3 million for the corresponding period in 2012, primarily due to increased capitalized interest associated with our drilling activities at Rochelle.  For the three months ending June 30, 2013 and 2012, we had non-cash interest expense, including amortization of loan costs and discount, of $12.1 million and $12.5 million, respectively.

Letter of credit fees were $7.1 million, $3.1 million, $18.5 million and $3.1 million for the second quarter of 2013 and 2012 and the six months ended June 30, 2013 and 2012, respectively.  The letter of credit fees are expenses related to our reimbursement agreements covering certain of our abandonment liabilities.  The increases in letter of credit fees were primarily due to the reimbursement agreement issued upon our acquisition of additional interest in Alba.

Other income (expense) increased to $8.9 million during the six months ended June 30, 2013 as compared to $(3.3) million for the corresponding period in 2012.  The changes in other income (expense) are primarily attributable to the effects of foreign currency fluctuations on our abandonment liabilities.

Income Taxes

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

(amounts in thousands)	U.K.		U.S.		Other		Total
Six Months Ended June 30, 2013:
Net income (loss) before taxes	$	10,139	$	(22,761)	$	(3,121)	$	(15,743)
Current tax expense (1)		14,646		-		-		14,646
Deferred tax benefit		(2,457)		-		-		(2,457)
Income tax expense		12,189		-		-		12,189
Net loss	$	(2,050)	$	(22,761)	$	(3,121)	$	(27,932)
Six Months Ended June 30, 2012:
Net loss before taxes	$	(52,449)	$	(56,462)	$	(2,089)	$	(111,000)
Current tax benefit (1)		(921)		-		-		(921)
Deferred tax benefit		(24,008)		-		-		(24,008)
Income tax benefit		(24,929)		-		-		(24,929)
Net loss	$	(27,520)	$	(56,462)	$	(2,089)	$	(86,071)

⁽¹⁾ The current tax expense (benefit) in both 2013 and 2012 is related to Petroleum Revenue Tax on our Alba field in the U.K.

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During July 2012, the U.K. government enacted legislation (retroactive to March 2012) to restrict decommissioning expenditures to 20% for supplemental corporate tax, in addition to the U.K. corporate tax of 30%, resulting in total tax relief available for decommissioning at 50%. 

The change in income tax expense (benefit) from $(24.9) million to $12.2 million for the six months ended June 30, 2012 and 2013, respectively, was primarily the result of increased income in the U.K. due to the initial production from Bacchus and our increased interest in Alba.

In 2013 and 2012, 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 against the deferred tax assets generated.

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 and measure our results of operations.  These metrics demonstrate our 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.  Net 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 Loss as Adjusted and Adjusted EBITDA are not determined in accordance with GAAP and thus are susceptible to varying calculations among companies, our non-GAAP measures as presented may not be comparable to similarly titled measures of other companies.  Net 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.

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Endeavour International Corporation

Provided below are reconciliations of net loss to Net Loss as Adjusted and Adjusted EBITDA:

(Amounts in thousands)	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012
Net Loss	$	(13,885)	$	(50,808)	$	(27,932)	$	(86,071)
Impairment of oil and gas properties (net of tax) (1)		-		19,960		3,534		35,700
Unrealized gains (losses) on derivatives (net of tax) (2)		1,277		(4,355)		(303)		(207)
Loss on early extinguishment of debt (net of tax) (3)		-		17,762		-		17,762
Net Loss as Adjusted	$	(12,608)	$	(17,441)	$	(24,701)	$	(32,816)
Net Loss	$	(13,885)	$	(50,808)	$	(27,932)	$	(86,071)
Unrealized loss on derivatives		1,277		(3,805)		(303)		973
Net interest expense		24,427		25,134		45,849		44,784
Letter of credit fees		7,128		3,064		18,508		3,064
Loss on early extinguishment of debt		-		21,661		-		21,661
Depreciation, depletion and amortization		51,923		10,627		74,870		18,533
Impairment of oil and gas properties		-		19,960		3,534		35,700
Income Tax Expense (Benefit)		11,281		(14,335)		12,189		(24,929)
Adjusted EBITDA	$	82,151	$	11,498	$	126,715	$	13,715

⁽¹⁾ Since the impairments related to U.S. oil and gas properties, we recognized no tax benefits as there was no assurance that we could generate any U.S. taxable earnings.

⁽²⁾ Net of tax benefit of none,$550, none and $1,180, respectively.

⁽³⁾ Net of tax benefit of $3,899 for the three and six months ended June 30, 2012.

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.

(amounts in thousands)	Six Months Ended June 30,
		2013		2012
Net cash provided by (used in) operating activities	$	71,611	$	(28,087)
Net cash used in investing activities	$	(108,786)	$	(344,741)
Net cash provided by financing activities	$	108,780	$	361,362

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Endeavour International Corporation

The net cash flows used in operating activities are primarily impacted by the earnings from our business activities.  The cash flows provided by (used in) operating activities were $71.6 million for the six months ended June 30, 2013 as compared to $(28.1) million used in operating activities for the six months ended June 30, 2012, primarily due to our increased revenue from the Alba Acquisition and the proceeds of the Forward Sale.

Our debt facilities, letters of credit, reimbursement agreements, monetary production payment and related transactions for 2013 and 2012 are as follows:

· Revolving Credit Facility:  In April 2012, we entered into a $100 million Credit Agreement with Cyan, as administrative agent, which was subsequently increased to $125 million.  At June 30, 2013 and December 31, 2012, we had $115 million outstanding under the Revolving Credit Facility.

· 2018 Notes:  In 2012, we closed the private placement of $554 million of 12% notes due 2018 (the “2018 Notes”).  The private placement took place in three parts:

o $350 million aggregate principal amount of the First Priority Notes in February;

o $150 million aggregate principal amount of the Second Priority Notes also in February; and

o an additional $54 million aggregate principal amount of the First Priority Notes in October.

o The net proceeds were used to fund the acquisition and repay all outstanding amounts under the Senior Term Loan.

· Commitments related to Asset Retirement Obligations:  During 2012 and 2013, we entered into agreements related to abandonment liabilities for certain of our U.K. oil and gas properties that replaced previously outstanding letters of credit and assisted in the closing of the Alba Acquisition.  Under these agreements, we agreed to reimburse the issuers of letters of credit covering approximately $153 million of certain of our abandonment liabilities in the event that the letters of credit are drawn.  We have no cash collateral associated with these agreements and the commitments have not been recorded as liabilities.

· Monetary Production Payment:  During 2013, we entered into a $125 million monetary production payment to be repaid from our entitlements from the Alba and Bacchus fields.

· Senior Term Loan: In May 2012, obligations under our credit agreement with Cyan, as administrative agent, and various lenders for a senior, secured term loan in the aggregate amount of $235 million (the “Senior Term Loan”) were repaid with a portion of the proceeds from our 2018 Notes offering.

· $50 million Subordinated Notes:  In October 2012, we repaid the outstanding balance of our subordinated notes due 2014 (the “Subordinated Notes”) with a portion of the proceeds from our October 2012 offering of additional First Priority Notes.

Our equity issuances for 2013 and 2012 are as follows:

· June 2012:  a public offering of 8.6 million shares of our common stock offering for net proceeds of $61.3 million.

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Endeavour International Corporation

Certain of our outstanding debt instruments contain certain financial ratio covenants.  We were in compliance with all financial covenants in our debt obligations as of June 30, 2013 and December 31, 2012.

Drilling Program

Our capital expenditures were as follows:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(Amounts in thousands)	2013		2012		2013		2012
Direct Oil & Gas Capital Expenditures:
U.K.	$	63,854	$	40,348	$	96,426	$	83,888
U.S		2,174		1,868		2,555		12,064
		66,028		42,216		98,981		95,952
Acquisitions		655		190,100		1,472		191,611
		66,683		232,316		100,453		287,563
Capitalized G&A, Interest and Other		9,098		12,405		20,471		24,101
Asset Retirement Obligations		(7,668)		-		(3,511)		-
Total Capital Expenditures and Acquisitions	$	68,113	$	244,721	$	117,413	$	311,664
Asset Retirement Obligations Paid	$	9,382	$	2,765	$	14,268	$	4,741

North Sea Acquisition

On December 23, 2011, we entered into a purchase agreement, through our wholly owned subsidiary Endeavour Energy UK Limited (“EEUK”), with ConocoPhillips (U.K.) Limited, ConocoPhillips Petroleum Limited and ConocoPhillips (U.K.) Lambda Limited, subsidiaries of ConocoPhillips, to acquire their interest in three producing U.K. oil fields in the Central North Sea.  On May 31, 2012, we closed the Alba field portion of this acquisition (the “Alba Acquisition”), which consisted of an additional 23.43% interest in the Alba field.  This increased our total working interest in the Alba field to 25.68%.  The Alba Acquisition was closed for aggregate cash consideration of approximately $229.6 million.

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United Kingdom Capital Program

Our capital program is focused on two large projects in the North Sea, the Bacchus and Rochelle fields, as well as infield drilling at Alba.

Alba

In April 2013, operations commenced on the three-well infield drilling program at the Alba field.  The timing of the drilling program has been accelerated into the first half of the year.  The first of the three planned development wells at the field was completed in June and a second subsea well was completed during August 2013.  We expect the drilling, in combination with improvements in the processing systems, to result in increased production levels from the field during the second half of the year.  We have a 25.68% working interest in the Alba field.

Bacchus

We hold a 30% working interest in our Bacchus field asset, which is operated by Apache Corporation, who owns a 50% working interest.  During 2012, we drilled the first and second development wells and achieved production.  With the additional positive data gained from the second development well, the Bacchus partners decided to observe production results before making a final decision on the placement of the third development well to ensure optimization of the entire reservoir.  That analysis has been completed and drilling began in April 2013.  Dduring the third quarter of 2013, the third well was completed and flowed at 9,600 barrels per day.  The well logged 2,057 feet net oil pay along a horizontal completion segment in high quality Jurassic-aged Fulmar sandstone in the field’s western fault block.  Production performance from the three wells was over 17,600 barrels per day gross.  The third well was completed ahead of schedule and below estimated cost.

Rochelle

Our working interest in the Rochelle area is 44%, which is comprised of Blocks 15/26b, 15/26c and 15/27.  We began drilling the first of two planned development wells in the latter part of 2012.  With drilling delays, the Rochelle project subsea infrastructure outpaced the drilling operations.  The joint interest partners decided to suspend the first well due to the inability to perform simultaneous pipe-lay and development drilling operations.  In October 2012, the drilling rig moved off location to allow for the hook-up of the pipelines and flow-lines to the subsea manifolds, thereby delaying our estimated start of production from the fourth quarter of 2012 to the first quarter of 2013.  The pipeline system, umbilicals and tie-ins to the offtake solution at the Scott Platform were completed and tested.  In January 2013, the rig returned to the East Rochelle site to continue final drilling.

In February 2013, following a severe storm lasting several days, we performed a routine inspection of the conductor, well head and blow out preventer systems which revealed that the cement around the top of the conductor pipe, which anchors the well to the seabed floor, had been lost creating a non-uniform hole around the conductor.  As a result of this finding, drilling

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operations were suspended on the East Rochelle well and the well will be plugged and abandoned.

To mitigate delays while we conducted our analysis of the East Rochelle well, we moved the rig to the West Rochelle area and commenced drilling of the second production well.  Drilling began on the West Rochelle well in the first quarter of 2013.  The West Rochelle well has been successfully drilled, completed and flow tested.  The final pipe spool pieces have been installed connecting the well to the subsea pipeline infrastructure to the Scott Platform.

Once production begins, the Rochelle field will deliver production to the Scott Platform, operated by Nexen Petroleum UK Limited (“Nexen”) who owns a 41% interest in Rochelle.  With the basic development of the work completed for readiness to first production, we have effected a transition of operatorship to Nexen effective on July 1, 2013.  This transition is expected to facilitate production from Rochelle across the Scott Platform as Nexen will operate both Rochelle and the Scott Platform.  The owners of the Scott Platform commenced a shutdown period starting on July 11, 2013.  The shutdown period is expected to last approximately eight weeks to complete the planned work program.  Due to the timing of this shutdown, first production at the Rochelle field is now expected in September 2013.

In addition, the Transocean Prospect rig returned to the Rochelle field and commenced drilling the E-2 well at East Rochelle on July 25^th.  The second well of the development, E-2, is expected to be on-line during the fourth quarter.

Centurion

In March 2013, we began drilling an exploration well at our Centurion prospect, where we hold a 33.3% interest.  We have now reached target depth on the exploration well and commenced plugging and abandonment operations.  The well confirmed the presence of hydrocarbon-bearing Fulmar reservoir sands; however these sands were thinner than anticipated and we are now evaluating the well results and their impact on the Centurion discoveries.

United States Capital Program

Our primary focus in the U.S. has been onshore unconventional oil and gas developments.  With U.S. gas prices expected to remain relatively depressed, we are limiting drilling our capital expenditures in 2013 to primarily those expenditures necessary to maintain our acreage positions and fulfill minor drilling commitments.

In the Piceance Basin Northwest Colorado, we drilled, cored and logged our first Wiley federal unit vertical pilot well, targeting the liquids-rich Niobrara and Frontier formations in the region.  We are evaluating the results and will likely drill a horizontal re-entry later this year.  In this play, we have accumulated leasehold and drill-to-earn options totaling about 40,000 gross acres.

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Outlook

2013 Planned Capital Expenditures

With the uncertainties around our strategic review, we have not finalized our total capital expenditures budget for 2013.  While we perform our strategic review, we are monitoring our capital expenditures and delaying discretionary or other spending where appropriate.  Previously for 2013, direct capital expenditures for the U.K. North Sea were expected to be in the $140 million to $150 million range.  While we expect to incur some cost overruns on Rochelle, primarily from the extended drilling duration of the West well and the drilling of the second East well, these overruns are expected to be partially offset by the lower than expected costs associated with the drilling of the third well at the Bacchus development.  As a result, we now anticipate that 2013 direct capital expenditures, in the U.K. North Sea, will be in the $170 million - $180 million range, as follows:

	Preliminary Capital Budget
United Kingdom:
Drilling and completions	$120 million to $130 million
Maintenance capital	$35 million
Exploration, seismic and other	$15 million
Total U.K.	$170 million to $180 million
United States	$10 million to $30 million (*)
Total direct oil and gas capital	$180 million to $210 million

^(*)Primarily discretionary and dependent on the outcome of our strategic review.  The U.S. capital expenditures are anticipated to primarily occur in the latter half of 2013.

In the U.K., the anticipated capital expenditures are primarily to bring the Rochelle development on line, drill the third well at Bacchus, maintain production at Alba and plug and abandon the well the initial East Rochelle well.  Anticipated exploration expenditures in the U.K. include the drilling of an exploration well at our Centurion prospect, where we hold a 33.3% interest.

The U.S. anticipated capital expenditures are primarily discretionary and will be re-evaluated once Rochelle production is on-line and after the completion of the strategic review process.

Our 2013 anticipated capital expenditures arealso subject to change depending on a number of factors, including the result of our strategic review, the availability and costs of drilling and completion equipment, crews, economic and industry conditions, prevailing and anticipated prices for oil and gas, the availability of sufficient capital resources, drilling success and other normal factors affecting the oil and gas industry.

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Decommissioning Expenditures

Production from each of our Ivanhoe, Rob Roy, Hamish (collectively, “IVRRH”), Renee, Rubie and Goldeneye fields has ceased and we have performed minor maintenance and decommissioning activities over the last several years.  Previously, we expected to re-develop our IVRRH, Renee and Rubie fields if commercially attractive and practicable once the development activities at Rochelle are operational.  During 2012, we determined that it was no longer practicable to re-develop these fields.  As a result, decommissioning work on the fields will be accelerated and we expect to incur approximately $30 million to $35 million in decommissioning charges during 2013.  For the six months ended June 30, 2013, we spent $14.3 million in decommissioning charges.

Third Quarter 2013 Production

Each year during the third quarter, routine maintenance work is performed on platforms and infrastructure in the U.K. North Sea.  Due to this planned downtime, physical production levels for the third quarter are expected to be in the range of 8,000 – 9,000 BOE per day.  In addition to the maintenance at the Scott Platform, the operator of Alba will commence a planned 28-day summer maintenance program that will address both the produced water and well-related issues.  Production for the Alba field is expected to ramp back to full potential by year-end. With the planned summer maintenance work at the field, there are no liftings scheduled at Alba during the third quarter and two liftings planned for the fourth quarter. While the lack of liftings will impact the reported sales volumes and revenue during the third quarter, we continue to receive cash monthly as a result of an on-going marketing agreement put in place at the beginning of 2013.

Disclosures About Contractual Obligations and Commercial Commitments

The following table sets forth our obligations and commitments to make future payments under our lease agreements and other long-term obligations as of June 30, 2013:

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(Amounts in thousands)		Payments due by Period
		Total		Less than 1 Year		1-3 Years		3-5 Years		After 5 Years
Long-term debt (1):
Principal	$	878,277	$	115,163	$	74,114	$	689,000	$	-
Interest (2)		370,829		89,167		166,053		115,609		-
Monetary production payment (1):
Principal		125,000		20,833		104,167		-		-
Effective interest		20,768		16,962		3,806		-		-
Asset retirement obligations		156,813		30,459		63,238		30,472		32,644
Letter of credit fees (1)		19,068		19,068		-		-		-
Leases for offices and equipment		5,269		1,561		2,842		866		-
Total Contractual Obligations	$	1,576,024	$	293,213	$	414,220	$	835,947	$	32,644

(1) Our debt, monetary production payment and letter of credit fees reflect the amounts outstanding as of June 30, 2013.

(2) Interest on out 11.5% convertible bonds is added to the outstanding principal balance each quarter and reflected as due upon maturity.

Off-Balance Sheet Arrangements

At June 30, 2013, our reimbursement agreements related to abandonment liabilities were off-balance sheet arrangements.  The reimbursement agreements cover approximately $153 million of our abandonment liabilities for certain of our U.K. oil and gas properties.  Under these agreements, unaffiliated third parties pledged cash to secure letters of credit covering certain of our abandonment liabilities and we agreed to reimburse the pledged cash in the event that the letters of credit are drawn and pledged cash is utilized to satisfy the commitment.  We have no cash collateral associated with the reimbursement agreements and the commitments under the reimbursement agreements are not recorded as liabilities.  The associated abandonment obligations are recorded in other long-term liabilities as part of our asset retirement obligations.  Fees and expenses related to the reimbursement agreements are included in other expenses on our condensed consolidated statement of operations.  See Note 14 to our unaudited consolidated financial statements for additional information concerning these agreements.

Cautionary Statement Regarding 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, as amended (the “Exchange Act”).  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

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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 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 liquidity and financial position;

· the outcome of our strategic review;

· our business strategy;

· success refinancing our debt;

· recent and pending acquisitions;

· budgets;

· projected costs, savings and plans;

· objectives of management for future operations;

· legal strategies; and

· legal proceedings.

We have based these forward-looking statements on our current expectations and assumptions about future events.  While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control.  These risks, contingencies and uncertainties, which may not be exhaustive, relate to, among other matters, the following:

· 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;

· our high level of indebtedness;

· adverse weather conditions;

· 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;

· cost and access to natural gas gathering, treatment and pipeline facilities;

· outcome of legal disputes;

· environmental hazards, such as natural gas leaks, oil spills and discharges of toxic gases;

· business strategy and the availability of acquisition opportunities;

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· the outcome of our strategic review; 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 risks and uncertainties, as mentioned in “Item 1A. Risk Factors” and elsewhere in our Annual Report on Form 10-K for the year ended December 31, 2012.  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 this report. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

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.

Item 4:  Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) of the Exchange Act we have evaluated, under the supervision and with the participation of our management, including our chief executive officer (the “CEO”) and chief financial officer (the “CFO”),  the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) or 15d-15(e) of the Exchange Act) as of the end of the period covered by this Quarterly Report on Form 10-Q.  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 Exchange Act is (a) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (b) is accumulated and 46     Table Of Contents   Endeavour International Corporation   communicated to our management, including the CEO and CFO, as appropriate, to allow timely decisions regarding required disclosure; and

(ii) that our disclosure controls and procedures were effective as of June 30, 2013.

Changes in Internal Control over Financial Reporting

There was no change in our system of internal control over financial reporting (as defined in Rules 13a-15(f), and 15d-15(f) under the Exchange Act), 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 in our Annual Report on Form 10-K for the year ended December 31, 2012 under Item 1A “Risk Factors,” which could materially adversely affect our business, financial condition and results of operations.  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

Exhibit Number		Description
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).
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).
3.1(e)		Amendment to Amended and Restated Articles of Incorporation, dated May 24, 2012 (Incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on May 29, 2012).
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).
3.2(c)		Amendment to Amended and Restated Bylaws dated January 14, 2013 (Incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on January 15, 2013).
3.2(d)		Amendment to Amended and Restated Bylaws dated May 22, 2013 (Incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on May 23, 2013).
4.1	*	Form of Warrant to Purchase Common Stock (Included as Exhibit A to Exhibit 10.2 herein).
4.2	*	Form of Warrant to Purchase Common Stock (Included as Exhibit A to Exhibit 10.3 herein).
10.1		Deed of Grant of Production Payment between Endeavour Energy UK Limited and Cidoval S.à r.l. dated April 30, 2013(Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on May 1, 2013).
10.2	*	Warrant Agreement for the Purchase of Shares of Common Stock between Endeavour International Corporation and certain holders party theretodated April 30, 2013.
10.3	*	Warrant Agreement for the Purchase of Shares of Common Stock between Endeavour International Corporation and Macquarie Bank Limited dated May 21, 2013.
10.4	*	Supplemental Deed of Amendment and Restatement between Endeavour Energy UK Limited and Cidoval S.à.r.l. dated May 21, 2013.
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 Catherine L. Stubbs, 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 Catherine L. Stubbs, Chief Financial Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS	*	XBRL Instance Document.
101.SCH	*	XBRL Taxonomy Extension Schema Document.
101.CAL	*	XBRL Taxonomy Extension Calculation Linkbase.
101.DEF	*	XBRL Taxonomy Extension Definition Linkbase.
101.LAB	*	XBRL Taxonomy Extension Label Linkbase.
101.PRE	*	XBRL Taxonomy Extension Presentation Linkbase.
*		Filed or furnished (in the case of Exhibits 32.1 and32.2) with this Form 10-Q.
†		Management contracts and compensatory plans or arrangements.

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Endeavour International Corporation

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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 thereunto duly authorized.

Endeavour International Corporation

Date: August 9, 2013 /s/  Catherine L. Stubbs/s/  Stanley W. FarmerCatherine L. StubbsStanley W. Farmer

Senior Vice President andVice President and

Chief Financial OfficerChief Accounting Officer

(Principal Financial Officer)(Principal Accounting Officer)

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