e10vq
Table of Contents

 
 
United States
Securities and Exchange Commission
Washington, D.C. 20549
Form 10-Q
(Mark One)
     
þ   Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the Quarterly Period Ended September 30, 2011
or
     
o   Transition Report Under Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from _________ to ___________
Commission file number: 1-32212
Endeavour International Corporation
(Exact name of registrant as specified in its charter)
     
Nevada   88-0448389
     
(State or other jurisdiction of incorporation
or organization)
  (I.R.S. Employer Identification No.)
1001 Fannin Street, Suite 1600, Houston, Texas 77002
(Address of principal executive offices) (Zip code)
(713) 307-8700
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. þ Yes o No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). þ Yes o No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (check one):
             
Large accelerated filer o   Accelerated filer þ   Non-accelerated filer o   Smaller reporting company o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). o Yes þ No
As of November 3, 2011, 37,663,603 million shares of the registrant’s common stock were outstanding.
 
 

 


 

Index
         
       
       
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 EX-31.1
 EX-31.2
 EX-32.1
 EX-32.2
 EX-101 INSTANCE DOCUMENT
 EX-101 SCHEMA DOCUMENT
 EX-101 CALCULATION LINKBASE DOCUMENT
 EX-101 LABELS LINKBASE DOCUMENT
 EX-101 PRESENTATION LINKBASE DOCUMENT
 EX-101 DEFINITION LINKBASE DOCUMENT
Quantities of natural gas are expressed in this report in terms of thousand cubic feet (Mcf) and million cubic feet (MMcf). Oil is quantified in terms of barrels (Bbls) and thousands of barrels (Mbbls). Natural gas is compared to oil in terms of barrels of oil equivalent (BOE), thousand barrels of oil equivalent (MBOE) or million barrels of oil equivalent (MMBOE). One barrel of oil is the energy equivalent of six Mcf of natural gas. With respect to information relating to our working interest in wells or acreage, “net” oil and natural gas wells or acreage is determined by multiplying gross wells or acreage by our working interest therein. References to number of potential well locations are gross, unless otherwise indicated.
References to “GAAP” refer to U.S. generally accepted accounting principles.

 


Table of Contents

Part I: Financial Information
Item 1: Financial Statements
Endeavour International Corporation
Condensed Consolidated Balance Sheets

(Unaudited)
(Amounts in thousands)
                 
    September 30,     December 31,  
    2011     2010  
 
Assets
               
Current Assets:
               
Cash and cash equivalents
  $ 185,030     $ 99,267  
Restricted cash
          31,776  
Accounts receivable
    6,502       8,068  
Prepaid expenses and other current assets
    12,210       8,718  
 
Total Current Assets
    203,742       147,829  
 
               
Property and Equipment, Net ($235,074 and $161,430 not subject to amortization at 2011 and 2010, respectively)
    527,149       364,677  
Goodwill
    211,886       211,886  
Other Assets
    27,326       25,895  
 
 
               
Total Assets
  $ 970,103     $ 750,287  
 
See accompanying notes to condensed consolidated financial statements.

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Endeavour International Corporation
Condensed Consolidated Balance Sheets

(Unaudited)
(Amounts in thousands)
                 
    September 30,     December 31,  
    2011     2010  
 
Liabilities and Stockholders’ Equity
               
Current Liabilities:
               
Accounts payable
  $ 71,408     $ 32,442  
Current maturities of debt
    14,850       21,600  
Accrued expenses and other
    26,617       22,642  
 
Total Current Liabilities
    112,875       76,684  
 
               
Long-Term Debt
    454,286       323,706  
Deferred Taxes
    117,839       77,200  
Other Liabilities
    43,278       64,927  
 
Total Liabilities
    728,278       542,517  
 
               
Commitments and Contingencies
               
 
               
Series C Convertible Preferred Stock
               
Face value (liquidation preference)
    37,000       45,000  
Net non-cash premiums under fair value accounting on redemption
    6,703       8,152  
 
Total Series C Convertible Preferred Stock
    43,703       53,152  
 
               
Stockholders’ Equity:
               
Series B preferred stock — Liquidation preference: $3,391 and $3,273 at 2011 and 2010, respectively
           
Common stock; shares issued and outstanding — 37,650 and 24,784 shares at 2011 and 2010, respectively
    38       25  
Additional paid-in capital
    419,354       287,995  
Treasury stock, at cost - 72 and 72 shares at 2011 and 2010, respectively
    (587 )     (587 )
Accumulated deficit
    (220,683 )     (132,815 )
 
Total Stockholders’ Equity
    198,122       154,618  
 
 
               
Total Liabilities and Stockholders’ Equity
  $ 970,103     $ 750,287  
 
See accompanying notes to condensed consolidated financial statements.

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Endeavour International Corporation
Condensed Consolidated Statement of Operations

(Unaudited)
(Amounts in thousands, except per share data)
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2011     2010     2011     2010  
 
Revenues
  $ 10,302     $ 19,849     $ 43,459     $ 55,102  
 
Cost of Operations:
                               
Operating expenses
    3,496       4,595       14,888       10,881  
Depreciation, depletion and amortization
    5,372       7,697       18,698       21,290  
Impairment of oil and gas properties
    28,793             28,793       7,692  
General and administrative
    4,863       4,237       14,525       12,873  
 
Total Expenses
    42,524       16,529       76,904       52,736  
 
 
                               
Income (Loss) From Operations
    (32,222 )     3,320       (33,445 )     2,366  
 
 
                               
Other Income (Expense):
                               
Derivatives:
                               
Realized losses
          (452 )           (1,552 )
Realized loss on early termination
          (10,201 )           (10,201 )
Unrealized gains
    13,081       6,441       11,098       11,477  
Interest expense
    (12,253 )     (10,474 )     (32,607 )     (21,733 )
Interest income and other
    611       (2,327 )     424       1,281  
 
Total Other Income (Expense)
    1,439       (17,013 )     (21,085 )     (20,728 )
 
 
                               
Loss Before Income Taxes
    (30,783 )     (13,693 )     (54,530 )     (18,362 )
 
                               
Deferred Tax Expense Related to U.K. Tax Rate Change
    25,387             25,387        
Other Income Tax Expense (Benefit)
    7,120       (2,001 )     6,433       7,916  
 
Income Tax Expense (Benefit)
    32,507       (2,001 )     31,820       7,916  
 
Net Loss
    (63,290 )     (11,692 )     (86,350 )     (26,278 )
Preferred Stock Dividends
    466       546       1,518       1,682  
 
 
Net Loss to Common Stockholders
  $ (63,756 )   $ (12,238 )   $ (87,868 )   $ (27,960 )
 
 
                               
Net Loss per Common Share:
                               
Basic and Diluted
  $ (1.63 )   $ (0.51 )   $ (2.52 )   $ (1.22 )
 
 
Weighted Average Number of Common Shares Outstanding:
                               
Basic and Diluted
    39,064       23,949       34,854       22,829  
 
See accompanying notes to condensed consolidated financial statements.

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Table of Contents

Endeavour International Corporation
Condensed Consolidated Statement of Cash Flows

(Unaudited)
(Amounts in thousands)
                 
    Nine Months Ended September 30,  
    2011     2010  
 
Cash Flows from Operating Activities:
               
Net loss
  $ (86,350 )   $ (26,278 )
Adjustments to reconcile net loss to net cash
               
provided by (used in) operating activities:
               
Depreciation, depletion and amortization
    18,698       21,290  
Impairment of oil and gas properties
    28,793       7,692  
Deferred tax expense
    23,052       6,195  
Unrealized gains on derivatives
    (11,098 )     (11,477 )
Amortization of non-cash compensation
    2,733       2,786  
Amortization of loan costs and discount
    9,553       6,980  
Non-cash interest expense
    9,306       5,179  
Other
    1,839       (1,178 )
Changes in operating assets and liabilities:
               
Decrease in receivables
    1,616       4,988  
Increase in other current assets
    (7,944 )     (2,340 )
Increase (decrease) in liabilities
    (18,817 )     17,465  
 
Net Cash Provided by (Used in) Operating Activities
    (28,619 )     31,302  
 
Cash Flows From Investing Activities:
               
Capital expenditures
    (113,137 )     (75,677 )
Acquisitions
    (22,898 )     (39,279 )
(Increase) decrease in restricted cash
    31,726       (29,645 )
 
Net Cash Used in Investing Activities
    (104,309 )     (144,601 )
 
Cash Flows From Financing Activities:
               
Repayments of borrowings
    (97,638 )     (74,942 )
Borrowings under debt agreements
    210,000       175,000  
Proceeds from issuance of common stock
    118,444       30,181  
Dividends paid
    (1,400 )     (1,563 )
Financing costs paid
    (11,226 )     (26,219 )
Other financing
    511       82  
 
Net Cash Provided by Financing Activities
    218,691       102,539  
 
               
Net Increase (Decrease) in Cash and Cash Equivalents
    85,763       (10,760 )
Cash and Cash Equivalents, Beginning of Period
    99,267       27,287  
 
 
               
Cash and Cash Equivalents, End of Period
  $ 185,030     $ 16,527  
 
See accompanying notes to condensed consolidated financial statements.

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Endeavour International Corporation
Notes to Condensed Consolidated Financial Statements
(Unaudited)

(Amounts in tables in thousands, except per unit data)
Note 1 — General
Endeavour International Corporation (a Nevada corporation) is an independent oil and gas company engaged in the acquisition, exploration and development of energy reserves. As used in these Notes to Condensed Consolidated Financial Statements, the terms “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, 2010.
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 GAAP and have been presented on a going concern basis, which contemplates the realization of assets and satisfaction of liabilities in the normal course of business. These accounting principles require management to use estimates, judgments and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements, and revenues and expenses during the reporting period. Management reviews its estimates, including those related to the determination of proved reserves, estimates of future dismantlement costs, income taxes and litigation. Actual results could materially differ from those estimates. In the opinion of management, all normal recurring adjustments considered necessary for a fair presentation have been included in these financial statements. Certain amounts for prior periods have been reclassified to conform to the current presentation.
Management believes that it is reasonably possible that the following material estimates affecting the financial statements could change in the coming year:
    proved oil and gas reserves,
 
    expected future cash flow from proved oil and gas properties,
 
    future dismantlement and restoration costs,
 
    fair values used in purchase accounting; and
 
    fair value of derivative instruments.
New Accounting Developments
On January 1, 2010, we adopted the following new standards without material effects on our results of operations or financial position:
    Subsequent Events — Amended standards of accounting for and disclosure of events that occur after the balance sheet date but before the financial statements are issued; and
    Fair Value — New, expanded disclosures are required for recurring or nonrecurring fair-value measurements and the reconciliation of specific fair value measurements.

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Endeavour International Corporation
Notes to Condensed Consolidated Financial Statements
(Unaudited)

(Amounts in tables in thousands, except per unit data)
In May 2011, the Financial Accounting Standards Board (“FASB”) issued a new accounting standard on fair value measurements that clarifies the application of existing guidance and disclosure requirements, changes certain fair value measurement principles and requires additional disclosures about fair value measurements. The standard is effective for interim and annual periods beginning after December 15, 2011. Early adoption is not permitted. We do not expect the adoption of this accounting guidance to have a material impact on our consolidated financial statements and related disclosures.
In June 2011, the FASB issued guidance impacting the presentation of comprehensive income. The guidance eliminates the current option to report components of other comprehensive income in the statement of changes in equity or in a footnote to the financial statements. The guidance is intended to provide a more consistent method of presenting non-owner transactions that affect an entity’s equity. The guidance is effective for interim and annual periods beginning on or after December 15, 2011. We do not expect adoption of the comprehensive income presentation to have an impact on our financial position or results of operations.
In September 2011, the FASB amended the previously issued guidance on testing goodwill for impairment. The revised guidance provides entities with an option of performing a qualitative assessment prior to calculating the fair value of the reporting unit. The amended guidance is effective for annual and interim goodwill impairment tests that will be performed for fiscal years beginning after December 15, 2011. We do not expect the adoption of this amended guidance for goodwill impairment testing to have an impact on our financial position or on our consolidated financial statements and related disclosures.
Note 2 — Property and Equipment
Property and equipment included the following at the dates indicated below:

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Endeavour International Corporation
Notes to Condensed Consolidated Financial Statements
(Unaudited)

(Amounts in tables in thousands, except per unit data)
                 
    September 30,     December 31,  
    2011     2010  
 
Oil and gas properties under the full cost method:
               
Subject to amortization
  $ 492,657     $ 389,575  
Not subject to amortization:
               
Acquired in 2011
    107,024        
Acquired in 2010
    47,858       67,612  
Acquired in 2009
    23,382       31,134  
Acquired prior to 2009
    56,810       62,684  
 
 
    727,731       551,005  
Computers, furniture and fixtures
    4,869       4,222  
 
Total property and equipment
    732,600       555,227  
 
               
Accumulated depreciation, depletion and amortization
    (205,451 )     (190,550 )
 
 
               
Net property and equipment
  $ 527,149     $ 364,677  
 
The costs not subject to amortization relate to unproved properties and properties being made ready to be placed into service, which are excluded from amortizable capital costs until it is determined whether or not proved reserves can be assigned to such properties. We capitalized $4.0 million and $1.2 million in interest related to exploration activities for the quarters ended September 30, 2011 and 2010, respectively. For the nine months ended September 30, 2011 and 2010, we capitalized $9.9 million and $3.1 million, respectively, in interest related to exploration.
For the third quarter of 2011, we recorded an impairment of $28.8 million related to our U.S. oil and gas properties, including $18 million related to our decision to discontinue activities in Alabama, through the application of the full cost ceiling test at the end of the quarter. We completed our analysis of our test wells in the Alabama area and determined that the likely economic returns in the future would not warrant further investment and therefore reclassified these amounts as evaluated for full cost accounting purposes. The prices used to determine the impairment for the U.S. properties were $94.48 per barrel for oil and $4.20 per Mcf for gas. We did not have an impairment of U.K. oil and gas properties, pre-tax, through the application of the full cost ceiling test at the end of the third quarter 2011. The prices used for the full cost ceiling test for the U.K. properties were $105.30 per barrel for oil and $8.79 per Mcf for gas.
Assets Acquisition
On February 23, 2011, we closed our acquisition of an additional 20% working interest in the Bacchus field for approximately $9.2 million in cash paid at closing and approximately $6.2 million in cash payable at the earlier of three months after first oil is produced or the end of 2011. In addition, we paid capital costs incurred by the seller of $9.4 million. Following the acquisition, we hold an aggregate 30% working interest.

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Endeavour International Corporation
Notes to Condensed Consolidated Financial Statements
(Unaudited)

(Amounts in tables in thousands, except per unit data)
Pending Acquisition
On July 17, 2011, we entered into purchase and sale agreements, subject to the completion of due diligence and certain closing conditions, with SM Energy Company and certain other minority owners to acquire the leasehold and producing interests in the Marcellus shale in north central Pennsylvania, as well as a pipeline and related facilities in McKean and Potter Counties, Pennsylvania, for aggregate consideration of $110 million, including a $2 million deposit paid upon executing the agreement. In October 2011, we extended the period for completing our due diligence process by paying an additional $4 million deposit. We have until December 14, 2011 to close this acquisition.
Note 3 — Debt Obligations
At September 30, 2011, we had $471.7 million in outstanding debt. Our outstanding credit facilities contain certain financial ratio covenants. We were in compliance with all financial and restrictive covenants of our debt obligations as of September 30, 2011 and December 31, 2010. Our debt consisted of the following at September 30, 2011 and December 31, 2010:
                 
    September 30,     December 31,  
    2011     2010  
 
Senior notes, 6% fixed rate, due 2012
  $     $ 81,250  
Senior term loan, 15% fixed rate, due 2013
    239,123       161,371  
Subordinated notes, 12% fixed rate, due 2014
    36,828       51,132  
Convertible bonds, 11.5% until March 11, 2011 and 7.5% thereafter, due 2016
    60,776       55,821  
Convertible senior notes, 5.5% fixed rate, due 2016
    135,000        
 
 
    471,727       349,574  
Less: debt discount
    (2,591 )     (4,268 )
Less: current maturities
    (14,850 )     (21,600 )
 
 
               
Long-term debt
  $ 454,286     $ 323,706  
 
 
               
Standby letters of credit outstanding for abandonment liabilities
  $ 32,136     $ 31,726  
 
6% Senior Notes
On April 20, 2011, we redeemed all $81.25 million of our outstanding 6% Senior Notes due 2012 with a portion of the proceeds from our common stock offering completed in March 2011. The redemption was made at a price of 100% of the Senior Notes’ principal amount, plus accrued and unpaid interest to the redemption date.

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Endeavour International Corporation
Notes to Condensed Consolidated Financial Statements
(Unaudited)

(Amounts in tables in thousands, except per unit data)
Senior Term Loan
On February 6, 2011, we amended our Senior Term Loan due 2013 to increase the security reserved for potential letters of credit from $25 million to $35 million. In July 2011, we secured new letters of credit that allowed us to release the $33 million of restricted cash that served as collateral for previous letters of credit.
The Amendment of our 11.5% Convertible Bonds and the redemption of all $81.25 million of our outstanding 6% Senior Notes satisfied the two conditions precedent to extend the maturity date of the Senior Term Loan to August 16, 2013
On July 15, 2011, we amended our Senior Term Loan to provide for an increase of $75 million in the borrowings available under the Senior Term Loan. In connection with the increase, we drew down the full additional amounts available and our quarterly scheduled amortization payments on the Senior Term Loan increased from $400,000 to $587,500. The other primary provisions of the amendment include:
    consent and approval by the lenders of the issuance of the 5.5% Convertible Senior Notes and certain conforming amendments with respect to the issuance of those notes, including an increase in the basket available for the issuance of junior debt from $100 million to $135 million;
 
    an amendment to the negative pledge provision to allow us to provide up to $10 million of cash margin to secure hedging obligations and;
 
    an extension by one additional quarter to the scheduled step up in the minimum secured debt coverage ratio.
11.5% Convertible Bonds
On March 11, 2011, we entered into an amendment to the Trust Deed with Smedvig QIF PLC related to our 11.5% Convertible Bonds due 2014. The amendment provides for:
    the amendment of the maturity date of the 11.5% Convertible Bonds from January 24, 2014 to January 24, 2016;
 
    the amendment of the date upon which the holders of the 11.5% Convertible Bonds may first exercise a put right, and the occurrence of the conversion price reset if such put right is not exercised, from January 24, 2012 to January 24, 2016; and
 
    a reduction in the interest rate payable from 11.5% to 7.5% on and after March 31, 2014.
We recorded a loss of $0.8 million in other expenses related to this amendment, representing the difference between the fair value of the debt and the book value of the debt at March 11, 2011.

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Endeavour International Corporation
Notes to Condensed Consolidated Financial Statements
(Unaudited)

(Amounts in tables in thousands, except per unit data)
5.5% Convertible Senior Notes
On July 18, 2011, we issued $135 million aggregate principal amount of our 5.5% Convertible Senior Notes due 2016. Interest on these notes will be payable semiannually 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. We issued the 5.5% Convertible Senior Notes, expecting to utilize the majority of the net proceeds of this offering to fund our pending acquisition of acreage and related midstream assets in the Marcellus shale play. If we are unable to complete the Marcellus acquisition, these proceeds may be used for general corporate purposes.
Letter of Credit Agreement
On July 25, 2011, we entered into a letter of credit facility agreement (the “LC Agreement”) with Commonwealth Bank of Australia (“CBA”), pursuant to which CBA issued letters of credit to us in the amount of £20.6 million (approximately $35 million as of July 25, 2011). Concurrent with the issuance of the letters of credit, the restrictions on £20.6 million of our restricted cash were removed and the cash returned for general corporate purposes. The letters of credit secure decommissioning obligations in connection with certain of our United Kingdom Continental Shelf Petroleum Production Licences. The LC Agreement provides that we pay a quarterly fee computed at a rate of 4.5% per year on the outstanding amount of each letter of credit issued under the LC Agreement. The LC Agreement contains similar financial covenants and other covenants as the credit agreement governing our Senior Term Loan. The CBA letters of credit are renewable at our option on October 31, 2012 and through the expiration of the LC Agreement on October 31, 2013.
Fair Value
The fair value of our outstanding debt obligations was $424 million and $361 million at September 30, 2011 and December 31, 2010, respectively. The fair values of long-term debt were determined based upon external market quotes for our Senior Notes and discounted cash flows for other debt.
Note 4 — Asset Retirement Obligations
Our asset retirement obligations relate to obligations for the future plugging and abandonment of oil and gas properties. The following table provides a rollforward of our asset retirement obligations for the nine months ended September 30, 2011 and 2010:

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Endeavour International Corporation
Notes to Condensed Consolidated Financial Statements
(Unaudited)

(Amounts in tables in thousands, except per unit data)
                 
    Nine Months Ended  
    September 30,  
    2011     2010  
 
Carrying amount of asset retirement obligations as of beginning of period
  $ 42,997     $ 47,362  
Accretion expense (included in DD&A expense)
    3,472       3,444  
Impact of foreign currency exchange rate changes
    833       (1,379 )
Payment of asset retirement obligations
    (12,616 )     (3,012 )
Reduction in asset retirement obligations
          (1,812 )
 
Carrying amount of asset retirement obligations as of end of period
    34,686       44,603  
Less: Current portion
    (6,480 )     (2,588 )
 
Long-term asset retirement obligations
  $ 28,206     $ 42,015  
 
Note 5 — Equity Transactions
New York Stock Exchange Listing of Common Stock
On March 15, 2011, we completed the transfer of the primary listing for our common stock from the NYSE Amex to the New York Stock Exchange under the symbol “END.”
Common Stock Offering
On March 30, 2011, we completed an underwritten public offering of 11.5 million shares of common stock at a price of $11.00 per common share ($10.34 per common share, net of underwriting discounts) for net proceeds of $118.4 million. On April 20, 2011, we used a portion of the offering proceeds to redeem all $81.25 million of our outstanding 6% Senior Notes.
Series C Convertible Preferred Stock
At September 30, 2011, we had 37,000 shares of Series C Convertible Preferred Stock outstanding, convertible into 4.2 million shares of common stock. The Series C Preferred Stock pays dividends in cash at 4.5% and is convertible into common stock at any time at the option of the preferred stock investors, at a conversion price of $8.75. On April 12, 2011, a holder of a portion of our Series C Convertible Preferred Stock converted 4,000 preferred shares, with a face value of $4 million, into 457,142 shares of our common stock. On July 25, 2011, an additional 4,000 preferred shares of our Series C Convertible Preferred Stock, with a face value of $4 million, were converted by a holder into 457,142 shares of our common stock.

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Notes to Condensed Consolidated Financial Statements
(Unaudited)

(Amounts in tables in thousands, except per unit data)
Note 6 — Stock-Based Compensation Arrangements
We grant restricted stock and stock options to employees and directors as incentive compensation. The restricted stock and options generally vest over three years. Non-cash stock-based compensation is recorded in general and administrative (“G&A”) expenses or capitalized G&A as follows:
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2011     2010     2011     2010  
 
G & A Expenses
  $ 771     $ 656     $ 2,216     $ 2,474  
Capitalized G & A
    252       211       768       711  
 
 
                               
Total non-cash stock-based compensation
  $ 1,023     $ 867     $ 2,984     $ 3,185  
 
At September 30, 2011, total compensation cost related to awards not yet recognized was approximately $6.0 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 have not granted any stock options during 2010 or the first nine months of 2011. Information relating to stock options is summarized as follows:
                                 
            Weighted     Weighted        
    Number of     Average     Average        
    Shares     Exercise     Contractual     Aggregate  
    Underlying     Price per     Life in     Intrinsic  
    Options     Share     Years     Value  
 
Balance outstanding — January 1, 2011
    464     $ 10.03                  
Exercised
    (91 )     5.63                  
Forfeited
    (21 )     12.95                  
Expired
    (48 )     24.16                  
 
 
                               
Balance outstanding — September 30, 2011
    304     $ 8.90       6.2     $ 373  
 
 
Currently exercisable — September 30, 2011
    261     $ 9.68       6.0     $ 210  
 

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Notes to Condensed Consolidated Financial Statements
(Unaudited)

(Amounts in tables in thousands, except per unit data)
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. Status of the restricted shares as of September 30, 2011 and the changes during the nine months ended September 30, 2011 are presented below:
                 
            Weighted  
            Average Grant  
            Date Fair  
    Number of     Value per  
    Shares     Share  
 
Balance outstanding — January 1, 2011
    816     $ 7.39  
Granted
    405       13.45  
Vested
    (330 )     7.63  
Forfeited
    (44 )     7.51  
 
 
               
Balance outstanding — September 30, 2011
    847     $ 10.19  
 
 
               
Total grant date fair value of shares vesting during the period
  $ 4,386          
 
Note 7 — 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.
The common shares potentially issuable arising from these instruments, which were outstanding during the periods presented in the financial statements consisted of:

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Notes to Condensed Consolidated Financial Statements
(Unaudited)

(Amounts in tables in thousands, except per unit data)
                 
    September 30,  
    2011     2010  
 
Warrants, options and stock-based compensation
    137       100  
Convertible debt
    10,972       5,597  
Convertible preferred stock
    4,229       5,143  
 
 
    15,338       10,840  
 
Note 8 — Fair Value Measurements
We apply fair value measurements to certain assets and liabilities including derivative instruments, marketable securities and embedded derivatives relating to conversion and change in control features in certain of our debt instruments. We seek to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Fair value measurements are classified and disclosed in one of the following categories:
Level 1:    Fair value is based on actively-quoted market prices, if available.
 
Level 2:    In the absence of actively-quoted market prices, we seek price information from external sources, including broker quotes and industry publications. Substantially all of these inputs are observable in the marketplace during the entire term of the instrument, derived from observable data, or supported by observable levels at which transactions are executed in the marketplace.
 
Level 3:    If valuations require inputs that are both significant to the fair value measurement and less observable from objective sources, we must estimate prices based on available historical and near-term future price information and certain statistical methods that reflect our market assumptions.
Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The following table summarizes the valuation of our investments and financial instruments by pricing levels as of September 30, 2011 and December 31, 2010:

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Notes to Condensed Consolidated Financial Statements
(Unaudited)

(Amounts in tables in thousands, except per unit data)
                                 
    Quoted Market Prices     Significant Other     Significant        
    in Active Markets -     Observable Inputs -     Unobservable Inputs     Total  
    Level 1     Level 2     Level - 3     Fair Value  
 
As of September 30, 2011:
                               
Oil and gas derivative contracts:
                               
Oil and gas puts
  $     $ 1,295     $ 98     $ 1,393  
Embedded derivatives
                (14,547 )     (14,547 )
 
 
                               
Total derivative liabilities
  $     $ 1,295     $ (14,449 )   $ (13,154 )
 
 
                               
As of December 31, 2010:
                               
Oil and gas derivative contracts:
                               
Oil and gas puts
  $     $ 1,213     $ 792     $ 2,005  
Embedded derivatives
                (27,495 )     (27,495 )
 
 
                               
Total derivative liabilities
  $     $ 1,213     $ (26,703 )   $ (25,490 )
 
Our commodity derivative contracts have been derived using models that consider various inputs including current market and contractual prices for the underlying instruments, quoted forward prices for natural gas and crude oil, volatility factors and interest rates, such as a LIBOR curve for a similar length of time as the derivative contract term. The inputs for the fair value models for our swaps are all observable market data, and as a result these instruments have been classified as Level 2.
The following is a reconciliation of changes in fair value of net derivative assets and liabilities classified as Level 3:
                 
    Nine Months Ended  
    September 30,  
    2011     2010  
 
Balance at beginning of period
  $ (26,703 )   $ (28,843 )
Realized and unrealized gains (losses) included in earnings
    12,254       (1,338 )
 
Balance at end of period
  $ (14,449 )   $ (30,181 )
 
 
               
Changes in unrealized gains (losses) relating to derivatives assets and liabilities still held at the end of the period
  $ 12,254     $ (1,338 )
 
Note 9 — Derivative Instruments
From time to time, we may utilize derivative financial instruments to hedge cash flows from operations or to hedge the fair value of financial instruments. We may use derivative financial instruments with respect to a portion of our oil and gas production or a portion of our variable rate debt to achieve a more predictable cash flow by reducing our exposure to price fluctuations.

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Notes to Condensed Consolidated Financial Statements
(Unaudited)

(Amounts in tables in thousands, except per unit data)
These transactions are likely to be swaps, collars or options and to be entered into with major financial institutions or commodities trading institutions. Derivative financial instruments are intended to reduce our exposure to declines in the market prices of crude oil and natural gas that we produce and sell, or to increases in interest rates and to manage cash flows in support of our annual capital expenditure budget. We also have embedded derivatives related to our debt instruments and convertible preferred stock.
The fair market value of these derivative instruments is included in our balance sheet as follows for the periods indicated:
                 
    September 30,     December 31,  
    2011     2010  
 
Derivatives not designated as hedges:
               
Oil and gas commodity derivatives:
               
Assets:
               
Prepaid expenses and other current assets
  $ 1,062     $ 709  
Other assets — long term
    331       1,296  
 
 
  $ 1,393     $ 2,005  
 
               
Embedded derivatives related to debt and equity instruments:
               
Assets:
               
Other assets — long-term
  $     $ 315  
Liabilities:
               
Other liabilities — long-term
  $ (14,547 )   $ (27,810 )
If all counterparties failed to perform, our maximum loss would have been $1.4 million as of September 30, 2011.
The effect of the derivatives not designated as hedges on our results of operations was as follows for the periods indicated:
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2011     2010     2011     2010  
 
Derivatives not designated as hedges:
                               
Oil and gas commodity derivatives
                               
Realized gains (losses)
  $     $ (452 )   $     $ (1,552 )
Realized loss on early termination
          (10,201 )           (10,201 )
Unrealized gains (losses)
    538       8,057       (1,850 )     12,815  
 
 
    538       (2,596 )     (1,850 )     1,062  
 
                               
Embedded derivatives related to debt and equity instruments
                               
Unrealized gains (losses)
  $ 12,543     $ (1,616 )   $ 12,948     $ (1,338 )
 

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Notes to Condensed Consolidated Financial Statements
(Unaudited)

(Amounts in tables in thousands, except per unit data)
Under our Senior Term Loan, we are required to maintain commodity derivatives to manage our cash flows from operations. As of September 30, 2011, our outstanding commodity derivatives covered approximately 169 Mbbls of oil and 842 MMcf of natural gas cumulative through 2012 and consisted of twelve oil and six natural gas option contracts with three major counterparties.
Note 10 — Supplemental Cash Flow Information
Cash paid during the period for interest and income taxes was as follows:
                 
    Nine Months Ended September 30,  
    2011     2010  
 
Interest paid
  $ 23,762     $ 10,313  
 
 
               
Income taxes paid (refunded)
  $ 7,765     $ (172 )
 
Note 11 — Commitments and Contingencies
We have previously disclosed a potential commitment on a drilling rig in our North Sea operations relating to a dispute with the rig operator. On June 6, 2011, we entered into a settlement agreement with the rig operator whereby the parties were mutually released from all future claims. We incurred costs of $14 million related to the settlement, which are included in capital expenditures.

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Item 2: Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion should be read in conjunction with our unaudited Condensed Consolidated Financial Statements and related notes thereto included elsewhere in this report. The following discussion also includes non-GAAP financial measures, which may not be comparable to similarly titled measures presented by other companies. Accordingly, we strongly encourage investors to review our financial statements in their entirety and not rely on any single financial measure.
Overview
We are an independent oil and gas company engaged in the production, exploration, development and acquisition of crude oil and natural gas in the U.S. and the North Sea. Our strategy is to expand and exploit our balanced portfolio of exploration and development assets using conventional and unconventional technologies in basins that have historically generated and produced substantial quantities of oil and gas and that we believe will yield commercial quantities of reserves through improved drilling and completion technologies. Finding, developing and producing oil and gas reserves in the North Sea require both significant capital and time. Recognizing this, we have sought to balance our North Sea assets, which have large potential reserves but long production-cycles, with a portfolio of assets in the U.S. that have lower costs and shorter production-cycles. We also seek to achieve a balance of oil and gas reserves in our portfolio of assets, believing that both commodities present attractive opportunities for capital returns in the future.
Our North Sea activities and assets remain a key source of value that we are actively developing to increase our overall reserves and production. Our major development projects in the U.K. sector of the North Sea — Bacchus and Greater Rochelle — have the potential to significantly expand our total proved reserves and production levels. These projects are in various stages of development, with Bacchus currently expected to commence oil production during early 2012. Additionally, we expect that production from our development of the Greater Rochelle area will commence during the fourth quarter of 2012.
Through the first nine months of 2011, our primary focus in the U.S. has been unconventional gas developments targeting reserve and production growth in the Haynesville area, including the Louisiana Haynesville Shale and East Texas Cotton Valley Sands, and the Marcellus Shale play in Pennsylvania. In the Haynesville area, we have approximately 7,200 net acres with acreage located in Red River, DeSoto, Bienville and Caddo Parishes in Louisiana and in Harrison and Gregg Counties in Texas. Our Marcellus acreage is comprised of approximately 18,400 net acres in Pennsylvania located between two of the most active parts of the Marcellus play. We also initiated exploratory plans in emerging gas and oil plays in Alabama and Montana. In Montana, we recently drilled four vertical pilot tests and evaluation of those results will determine the pace and scope of our subsequent exploration and development initiatives. In Alabama, we have decided to discontinue further efforts there due to economic considerations.

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We are expanding upon our foundation of producing assets and undeveloped acreage in both established and emerging U.S. onshore resource plays, including the development of our leasehold positions in the Haynesville and Marcellus areas, while continuing to develop our existing assets in the North Sea. Specifically, we have continued to focus on achieving initial production from the Bacchus oil field in the North Sea. We believe that the following will support us in executing our core business strategies.
    In July 2011, we secured new letters of credit that allowed us to release the $33 million of restricted cash into operations that served as collateral for previous letters of credit.
    In July 2011, we entered into purchase and sale agreements, subject to the completion of due diligence and certain closing conditions, with SM Energy Company and certain other minority owners to acquire the leasehold and producing interests held by SM Energy and its partners in the Marcellus shale in north central Pennsylvania, as well as a pipeline and related facilities, for aggregate consideration of $110 million.
    In July 2011, we issued $135 million aggregate principal amount of our 5.5% Convertible Senior Notes. We issued the 5.5% Convertible Senior Notes, expecting to utilize the majority of the net proceeds of this offering to fund our pending acquisition of acreage and related midstream assets in the Marcellus shale play. If we are unable to complete the Marcellus acquisition, these proceeds may be used for general corporate purposes.
    In July 2011, we entered into an amendment to our Senior Term Loan providing for an increase of $75 million in the amounts available under the Senior Term Loan. The proceeds will be used for general corporate purposes.
    In April 2011, we redeemed all $81.25 million of our outstanding 6% Senior Notes with a portion of the proceeds from our common stock offering completed in March 2011.
    In March 2011, we closed a public offering of 11.5 million shares of our common stock offering for net proceeds of $118.4 million.
    In March 2011, we completed the transfer of the primary listing for our common stock from the NYSE Amex to the New York Stock Exchange.
    In March 2011, we entered into an Amendment to the Trust Deed dated as of January 24, 2008 with Smedvig QIF PLC and the other parties thereto related to our 11.5% Convertible Bonds. The amendment provides for an extension of the maturity date of the 11.5% Convertible Bonds; extends the date on which holders may exercise a put right, and the occurrence of price reset if not exercised; and a reduction in the interest rate payable after March 31, 2014 to 7.5%.
    In February 2011, the Department of Energy and Climate Change (the “DECC”) approved the Rochelle FDP for Block 15/27 in East Rochelle. In April 2011, we announced the agreement of the commercial terms for the processing and transportation of East Rochelle production on the Scott Platform in the Central North Sea. As the operator, we plan to award contracts and commence immediate construction of the production facilities. First production from East Rochelle is planned for the second half of 2012.
    In February 2011, we finalized our acquisition of an additional 20% working interest in the Bacchus development for approximately $9.2 million in cash paid at closing and approximately $6.2 million in cash payable at the earlier of three months after first oil is produced or the end of 2011. In addition, we paid capital costs previously incurred by the

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      seller of $9.4 million. Following the acquisition, we now hold an aggregate working interest of 30%.
    In February 2011, we amended our Senior Term Loan to increase the security reserved for potential letters of credit from $25 million to $35 million. In July 2011, we secured new letters of credit that allowed us to release the $33 million of restricted cash that served as collateral for previous letters of credit. ·
Results of Operations
Revenue, net income and cash flows from operating activities are very sensitive to changes in prices received for our products. With our business policy to utilize various oil and gas derivative instruments to achieve more predictable cash flows by reducing our exposure to price fluctuations, our realized commodity prices including the effect of derivatives, particularly for oil, were less volatile than commodity prices before the effect of derivatives.
Net loss to common shareholders for the nine months ended September 30, 2011 was $87.9 million, or $2.52 per share, compared to $28.0 million, or $1.22 per share, for the same period in 2010. The change in the net loss to common shareholders for these periods is primarily due to an impairment of oil and gas properties, increased deferred tax expense related to an increase in the tax rate in the U.K., decreased revenue and increased operating and interest expenses.
Net loss to common shareholders for the third quarter September 30, 2011 increased to $63.8 million compared to $12.2 million for the same period in 2010 primarily due to an impairment of oil and gas properties, increased deferred tax expense related to an increase in the tax rate in the U.K., decreased revenue and increased interest expenses.
In addition to our operations, our net income can be significantly affected by various non-cash items, such as unrealized gains and losses on our derivatives, impairment of oil and gas properties, and currency impact of long-term liabilities. Excluding these non-cash items, net loss as adjusted for the nine months ended September 30, 2011 was $44.4 million as compared to net loss as adjusted of $23.7 million for the same period in 2010. Net loss as adjusted for the third quarter September 30, 2011 was $22.1 million s as compared to net loss as adjusted of $14.0 million for the same period in 2010. The increases in net loss as adjusted are primarily due to decreased revenue and increased operating and interest expenses.
Adjusted EBITDA was $14.1 million for the nine months ended September 30, 2011 compared to $31.0 million for the same period in 2010, primarily due to decreased revenue related to the loss of production after the shut-in of our Goldeneye field and increased operating and other expenses. Adjusted EBITDA was $2.4 million for the third quarter September 30, 2011 compared to $8.2 million for the same period in 2010 due to decreased revenue related to the loss of production after the shut-in of our Goldeneye field. For definitions of Net Income (Loss) as Adjusted and Adjusted EBITDA, and a reconciliation of each to the nearest comparable GAAP measure, please see “Reconciliation of Non-GAAP Measures.”
Our cash flows used by operating activities decreased to $(28.6) million for the nine months ended September 30, 2011 as compared to cash flows provided by operating activities of $31.3

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million for the same period in 2010, primarily due to a loss of revenue from decreased production, increased interest expense related to debt incurred in the third quarters of 2010 and 2011 and increased operating expenses.
Revenue and Sales Volume
Our revenues decreased from $55.1 million in the nine months ended September 30, 2010 to $43.5 million in the same period of 2011 primarily as a result of the shutdown of our U.K. Goldeneye field and lower averaged realized natural gas prices, partially offset by increased U.S. gas sales volumes and higher oil prices. The change in our average realized natural gas prices is the result of a combination of factors. Our expanded operations in the U.S. along with the shutdown of Goldeneye have led to U.S. sales becoming the majority of our total gas sales. The significant increase of supply of natural gas from shale drilling has heavily impacted the U.S. gas markets and prices, and combined with the significant shift in our gas sales from the U.K. to the U.S., resulted in the decrease in our average realized gas prices.
For the third quarter of 2011 and 2010, we had sales volume of 2,972 BOE per day and 4,755 BOE per day, respectively. Our physical daily production was approximately 3,274 BOE and 4,988 BOE for the third quarter of 2011 and 2010, respectively. The decrease in sales volume is primarily attributable to the shutdown of our Goldeneye field and production interruptions at our producing Bittern field in the U.K. that prevented oil liftings, partially offset by an increase in sales volumes from our U.S. assets. Sales from our U.S. assets have increased as we have continued our drilling program since our initial acquisitions of these assets in late 2009.
The following table shows our average sales volumes and realized sales prices for our operations for the periods presented.

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    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2011     2010     2011     2010  
 
Sales volume (1)
                               
Oil and condensate sales (Mbbls):
                               
United Kingdom
    49       127       274       429  
United States
    3       2       5       5  
 
Total
    52       129       279       434  
 
 
                               
Gas sales (MMcf):
                               
United Kingdom
          869       78       2,614  
United States
    1,329       978       3,305       1,699  
 
Total
    1,329       1,847       3,383       4,313  
 
 
                               
Oil equivalent sales (MBOE)
                               
United Kingdom
    49       272       287       864  
United States
    225       165       556       288  
 
Total
    274       437       843       1,152  
 
 
                               
Total BOE per day
    2,972       4,755       3,089       4,222  
 
 
                               
Physical production volume (BOE per day) (1):
                               
United Kingdom
    838       2,993       1,152       3,130  
United States
    2,436       1,995       2,036       1,117  
 
Total
    3,274       4,988       3,188       4,247  
 
 
                               
Realized Prices (2)
                               
Oil and condensate price ($  per Bbl):
                               
Before commodity derivatives
  $ 106.57     $ 75.64     $ 108.57     $ 74.72  
Effect of commodity derivatives
          (3.11 )           (7.12 )
 
Including commodity derivatives
  $ 106.57     $ 72.53     $ 108.57     $ 67.60  
 
 
                               
Gas price ($  per Mcf):
                               
Before commodity derivatives
  $ 3.59     $ 5.44     $ 3.88     $ 5.26  
Effect of commodity derivatives
          (0.03 )           0.36  
 
Including commodity derivatives
  $ 3.59     $ 5.41     $ 3.88     $ 5.62  
 
 
                               
Equivalent oil price ($  per BOE):
                               
Before commodity derivatives
  $ 37.68     $ 45.37     $ 51.53     $ 47.81  
Effect of commodity derivatives
          (1.03 )           (1.35 )
 
Including commodity derivatives
  $ 37.68     $ 44.34     $ 51.53     $ 46.46  
 

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(1)   We record oil revenues using the sales method, i.e. when delivery has occurred. Actual production may differ based on the timing of tanker liftings. We use the entitlements method to account for sales of gas production.
 
(2)   The average sales prices include gains and losses for derivative contracts we utilize to manage price risk related to our future cash flows.
We have taken important steps to balance our asset portfolio in several dimensions: U.S. versus U.K. properties; oil versus natural gas; and short-term versus long-term realizations. We have constructed our asset portfolio in this manner in an attempt to mitigate the risks of over-emphasizing any one of these variables. Specifically, we believe that the resource-rich plays in the U.S., with less capital-intensive and shorter production-cycles relative to our North Sea development projects, will provide a stable platform for the successful execution of our strategy by helping to provide cash flows from operations as we develop our longer-term, more capital-intensive North Sea development projects.
Our revenues and cash flows from operating activities are very sensitive to changes in the prices we receive for the oil and natural gas we produce. Our production is sold at prevailing market prices which may be volatile and subject to numerous factors which are outside of our control. Further, the current tightly-balanced supply and demand market allows a small variation in supply or demand to significantly impact the market prices for these commodities.
The markets in which we sell our oil and natural gas also materially impact our revenues and cash flows. Oil trades on a worldwide market and consequently, price movements for all types and grades of crude oil generally trend in the same direction and within a relatively narrow price range. However, natural gas prices vary among geographic areas as the prices received are largely impacted by local supply and demand conditions as the global transportation infrastructure for natural gas is still developing. As such, the oil we produce and sell is typically sold at prices in line with global prices, whereas our natural gas is to a large extent impacted by regional supply and demand issues and to a lesser extent by global fuel prices, including oil and coal. With the recent increase in our U.S. operations and the shut-in of the Goldeneye field, the majority of our gas sales are in the U.S. The U.S. gas market is heavily impacted by the increased supply from shale drilling, which has served to depress natural gas prices relative to the U.K. market.
Expenses
For the third quarter of 2011, operating expenses decreased to $3.5 million as compared to $4.6 million for the same period in 2010. For the nine months ended September 30, 2011, operating expenses increased to $14.9 million as compared to $10.9 million for the same period in 2010. The increase in operating expense for the nine months ended September 30, 2010 to 2011 is primarily related to increased U.S. workover expense and increases in transportation expense and production taxes as a result of increased U.S. sales volumes. Operating costs per BOE increased from $10.50 per BOE for the third quarter of 2010 to $12.79 per BOE for the same period in 2011. Operating costs per BOE increased from $9.44 per BOE for the nine months ended September 30, 2010, to $17.65 per BOE for the nine months ended September 30, 2011. The

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significant increases in operating costs per BOE are due to the impact of both the increases in the dollar levels of operating expenses and the decreased volumes discussed above.
Depreciation, depletion and amortization (“DD&A”) expense decreased to $5.4 million from $7.7 million for the third quarter of 2011 and 2010, respectively, as a result of the decreased sales volumes. DD&A also decreased to $18.7 million from $21.3 million for the nine months ended September 30, 2011 and 2010, respectively, also as a result of the decreased sales volumes.
For the third quarter of 2011, the prices used in the full cost ceiling test for our U.S. properties were $94.48 per barrel for oil and $4.20 per Mcf for gas. We have completed our analysis of our test wells in the Alabama area and determined that the likely economic returns in the future would not warrant further investment and therefore reclassified these amounts as evaluated for full cost accounting purposes. We recorded an impairment of $28.8 during the third quarter of 2011 for our U.S. properties, including $18 million related to our decision to discontinue activities in Alabama. For the third quarter of 2011, the prices used in the full cost ceiling test for our U.K. properties were $105.30 per barrel for oil and $8.79 per Mcf for gas. 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.
General and administrative (“G&A”) expenses increased to $4.9 million during the third quarter of 2011 as compared to $4.2 million for the corresponding period in 2010. G&A expenses increased to $14.5 million during the nine months ended September 30, 2011 as compared to $12.9 million for the corresponding period in 2010. These increases primarily resulted from higher compensation expense due to expanding U.S. operations and increased legal, accounting, and consulting fees that pertain to our expanding U.S. operations. Components of G&A expenses for these periods are as follows:
                                 
    Three Months Ended     Nine Months Ended  
(Amounts in thousands)   September 30,     September 30,  
    2011     2010     2011     2010  
 
Compensation
  $ 5,034     $ 4,209     $ 14,901     $ 12,618  
Consulting, legal and accounting fees
    1,833       1,357       4,991       4,433  
Occupancy costs
    516       315       1,265       837  
Other expenses
    2       694       1,717       1,948  
 
Total gross cash G&A expenses
    7,385       6,575       22,874       19,836  
 
                               
Non-cash stock-based compensation
    940       789       2,733       2,786  
 
Gross G&A expenses
    8,325       7,364       25,607       22,622  
Less: capitalized G & A expenses
    (3,462 )     (3,127 )     (11,082 )     (9,749 )
 
Net G&A expenses
  $ 4,863     $ 4,237     $ 14,525     $ 12,873  
 
Interest expense increased by $1.8 million to $12.3 million for the third quarter of 2011 as compared to $10.5 million for the corresponding period in 2010. Interest expense increased by $10.9 million to $32.6 million for the nine months ended September 30, 2011 as compared to $21.7 million for the corresponding period in 2010. These increases were primarily due to

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increased interest costs related to the Senior Term Loan and the 5.5% Convertible Senior Notes, partially offset by the absence of interest in 2011 from our previously existing senior and junior debt which were repaid concurrently with the issuance of the Senior Term Loan. For the nine months ended September 30, 2011 and 2010, we had non-cash interest expense, including amortization of loan costs and discount, of $18.9 million and $12.2 million, respectively.
Income Taxes
The following summarizes the components of tax expense (benefit) (amounts in thousands):
                                 
    U.K.     U.S.     Other     Total  
 
Nine Months Ended September 30, 2011:
                               
Net income (loss) before taxes
  $ (7,094 )   $ (55,966 )   $ 8,530     $ (54,530 )
 
                               
Current tax expense
    8,764       4             8,768  
Deferred tax expense related to U.K. tax rate change
    25,387                   25,387  
Deferred tax benefit
    (2,335 )                 (2,335 )
 
Income tax expense (benefit)
    31,816       4             31,820  
 
 
                               
Net income (loss)
  $ (38,910 )   $ (55,970 )   $ 8,530     $ (86,350 )
 
 
                               
Nine Months Ended September 30, 2010:
                               
 
                               
Net income (loss) before taxes
  $ 6,249     $ (22,214 )   $ (2,397 )   $ (18,362 )
 
                               
Current tax expense (benefit)
    1,892             (171 )     1,721  
Deferred tax expense (benefit)
    7,174             (979 )     6,195  
 
Income tax expense (benefit)
    9,066             (1,150 )     7,916  
 
 
                               
Net loss
  $ (2,817 )   $ (22,214 )   $ (1,247 )   $ (26,278 )
 
The change in income tax expense (benefit) from $7.9 million to $31.8 million for the nine months ended September 30, 2010 and 2011, respectively, is primarily the result of the increase in the U.K. supplementary charge from 20% to 32%. The current tax expense in both 2011 and 2010 is related to Petroleum Revenue Tax on our Alba field in the U.K.
In July 2011, a tax increase was enacted by the U.K. government that raised the existing supplementary charge on profits from North Sea oil and gas production from 20% to 32%, effective March 24, 2011. This supplementary charge is in addition to the existing corporation tax rate of 30%. As we do not currently anticipate paying corporate or supplementary tax in the U.K. for the next several years, we expect the tax increase to have little effect on our cash flow from operations during that time period. During the third quarter of 2011, we recorded a one time increase in deferred tax liabilities of $25.4 million, with a corresponding increase in deferred tax expense as a result of the recent U.K. legislation.
In 2011 and 2010, we did not record any income tax benefits in the U.S. as there was no assurance that we could generate any U.S. taxable earnings, resulting in a full valuation allowance of deferred tax assets generated.

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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 Income (Loss) as Adjusted and Adjusted EBITDA are internal, supplemental measures of our performance that are not required by, or presented in accordance with, GAAP. We view these non-GAAP measures, and we believe that others in the oil and gas industry, securities analysts, investors, and other interested parties view these, or similar, non-GAAP measures, as commonly used analytic indicators to compare performance among companies in our industry and in the evaluation of issuers.
Because Net Income (Loss) as Adjusted and Adjusted EBITDA are not measurements determined in accordance with GAAP and thus are susceptible to varying calculations, our non-GAAP measures as presented may not be comparable to similarly titled measures of other companies. Net Income (Loss) as Adjusted and Adjusted EBITDA have limitations as analytical tools, and you should not consider these measures in isolation, or as a substitute for analysis of our financial statement data presented in the consolidated financial statements as reported under GAAP.
Provided below are reconciliations of net loss to the following non-GAAP financial measures: Net Income (Loss) as Adjusted and Adjusted EBITDA (amounts in thousands):

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    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2011     2010     2011     2010  
 
Net loss
  $ (63,290 )   $ (11,692 )   $ (86,350 )   $ (26,278 )
Impairment of oil and gas properties (net of tax) (1)
    28,793             28,793       7,692  
Unrealized (gain) loss on derivatives (net of tax) (2)
    (13,034 )     (2,413 )     (12,245 )     (5,070 )
Deferred tax expense related to U.K. tax rate change
    25,387             25,387        
Currency impact on deferred taxes
          95             (51 )
 
 
                               
Net Loss as Adjusted
  $ (22,144 )   $ (14,010 )   $ (44,415 )   $ (23,707 )
 
 
                               
Net loss
  $ (63,290 )   $ (11,692 )   $ (86,350 )   $ (26,278 )
 
                               
Unrealized (gain) loss on derivatives
    (13,081 )     (6,441 )     (11,098 )     (11,477 )
Realized loss on early termination of derivatives
          10,201             10,201  
Net interest expense
    12,084       10,467       32,234       21,704  
Depreciation, depletion and amortization
    5,372       7,697       18,698       21,290  
Impairment of oil and gas properties
    28,793             28,793       7,692  
Income tax expense (benefit)
    32,507       (2,001 )     31,820       7,916  
 
 
                               
Adjusted EBITDA
  $ 2,385     $ 8,231     $ 14,097     $ 31,048  
 
 
(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) expense of $(47) and $(4,029) and $1,147 and $(6,408), respectively.
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)   Nine Months Ended September 30,  
    2011     2010  
 
Net cash provided by (used in) operating activities
  $ (28,619 )   $ 31,302  
 
Net cash used in investing activities
  $ (104,309 )   $ (144,601 )
 
Net cash provided by financing activities
  $ 218,691     $ 102,539  
 
The net cash flows provided by operating activities are primarily impacted by the earnings from our business activities. The cash flows used by operating activities were $28.6 million for the nine months ended September 30, 2011 as compared to $31.3 million provided by operating

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activities for the nine months ended September 30, 2010 primarily due to increased interest expense related to our 2010 debt issuances, increased operating expenses, increased current tax expense and decreased revenue from lower sales volumes and average released prices.
The cash provided by or used in investing activities represents expenditures for capital projects, including our acquisition of an additional 20% working interest in the Bacchus field in the North Sea. Our entry into a new letter of credit facility agreement allowed us to release $33 million of restricted cash into general operations (see additional discussion, below). For the nine months ended September 30, 2011, cash used in investing activities was $104.3 million as opposed to $144.6 million in the corresponding period of the prior year, primarily due to the release of restricted cash associated with lines of credit.
At the end of 2010, we expected to spend approximately $150 million on our 2011 oil and gas capital program and that our available cash at that time and our cash flow from operations would be sufficient to fund our capital expenditure program for the upcoming year. Those expectations included cash flow assumptions based on an expected mid-year production start for our Bacchus development, additional production from our U.S. drilling operations and some continued level of production at our Goldeneye field. We anticipated that our production would increase in the latter half of the year as Bacchus and U.S. production ramped up.
The delay in production increases during 2011 is due to the three items that we expected to have the most impact on our 2011 production: Bacchus timing, U.S. drilling program results and the status of the Goldeneye field. We expect our production to remain consistent with our current levels until we achieve first production at Bacchus. Due to the following factors, we will not experience production increases at the levels we originally anticipated.
    The operator at Bacchus experienced delays in moving the drilling rig to the location and drilling began in August 2011. Due to additional equipment difficulties on the rig, the operator has experienced further delays. Production is now anticipated early next year.
 
    In the U.S., we have had drilling success and continue to tie in new wells, but due to infrastructure issues in Marcellus, we have not increased production at the rate that we had originally expected. We are working with the operators to increase access to major pipelines, expand pipeline infrastructure or other alternatives to market production. In addition, U.S. gas prices have declined and have impacted our decisions on the timing of drilling.
 
    As discussed earlier, the Goldeneye field ceased production during the first quarter of 2011.
The cash provided by financing activities includes repayments and borrowings of debt, payments of preferred dividends, payment of financing costs, and proceeds from the issuance of common stock. In March 2011, we closed a public offering of 11.5 million shares of our common stock for net proceeds of $118.4 million. In April 2011, we used a portion of the net proceeds from this offering to redeem all $81.25 million of our 6% Senior Notes.

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In March 2011, we entered into an Amendment to the Trust Deed with Smedvig QIF PLC related to our 11.5% Convertible Bonds. The Amendment provided for:
    the amendment of the maturity date of the 11.5% Convertible Bonds from January 24, 2014 to January 24, 2016;
 
    the amendment of the date upon which the holders of the 11.5% Convertible Bonds may first exercise a put right, and the occurrence of the conversion price reset if such put right is not exercised, from January 24, 2012 to January 24, 2016; and
 
    a reduction in the interest rate payable from 11.5% to 7.5% on and after March 31, 2014.
The Amendment of our 11.5% Convertible Bonds and the redemption of all $81.25 million of our outstanding 6% Senior Notes satisfied the two conditions precedent to extend the maturity date of the Senior Term Loan to be August 16, 2013.
In February 2011, we amended our Senior Term Loan to increase the security reserved for potential letters of credit from $25 million to $35 million. In July 2011, we amended our Senior Term Loan to provide for an increase of $75 million in the borrowings available under the Senior Term Loan. In connection with the increase, we drew down the full additional amounts available and our quarterly scheduled amortization payments on the Senior Term Loan increased from $400,000 to $587,500. The other primary provisions of the amendment include:
    consent and approval by the lenders of the issuance of the 5.5% Convertible Senior Notes and certain conforming amendments with respect to the issuance of those notes, including an increase in the basket available for the issuance of junior debt from $100 million to $135 million;
 
    an amendment to the negative pledge provision to allow us to provide up to $10 million of cash margin to secure hedging obligations and;
 
    an extension by one additional quarter to the scheduled step up in the minimum secured debt coverage ratio.
At January 1, 2011, restricted cash represented amounts held in escrow as collateral for lines of credit associated with abandonment liabilities related to our U.K. properties. In July 2011, we entered into a new letter of credit facility agreement (the “LC Agreement”) pursuant to which we secured new letters of credit. Our entry into the LC Agreement allowed us to release the $33 million of restricted cash that served as collateral for previous letters of credit into operations. The new letters of credit secure obligations in connection with our U.K. production licenses. The LC Agreement provides that we must pay a quarterly fee computed at a rate of 4.5% per year on the outstanding amount of each letter of credit issued under the LC Agreement. The LC Agreement contains similar financial covenants and other covenants as the credit agreement governing our Senior Term Loan. The CBA letters of credit are renewable at our option on October 31, 2012 and through the expiration of the LC Agreement on October 31, 2013.
In July 2011, we issued $135 million aggregate principal amount of our 5.5% Convertible Senior Notes due 2016. Interest on these notes will be payable semiannually at a rate of 5.5% per annum. The 5.5% Convertible Senior Notes are convertible into shares of our common stock at a price equivalent to $18.51 per share.

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Capital Program
We anticipate spending approximately $155 — $165 million during 2011 to fund our oil and gas activities in the U.S. and U.K., with approximately 60% of those expenditures anticipated to be focused on our U.K. assets. These capital budget numbers do not include $14 million of costs incurred in the settlement of the rig contract dispute in June 2011, which is included in U.K. capital expenditures. As of September 30, 2011, we had spent $113.1 million in capital expenditures. We also spent an additional $22.9 million on acquisitions, primarily related to our purchase of an additional 20% working interest in the Bacchus field.
In the U.K., our activity during 2011 is primarily concentrated on the Bacchus and Greater Rochelle development projects. At the Bacchus project, we are drilling three production wells and installing the infrastructure to allow first production to begin early next year. At the Greater Rochelle project, our focus will be completing engineering and procuring long lead-time equipment to prepare Greater Rochelle for a 2012 first production date. We also intend to begin actual construction of the subsea infrastructure and the required modifications to the Scott platform have been commenced to prepare it for production from the Greater Rochelle area in 2012.
Our primary focus during 2011 in the U.S. has been in the Haynesville, and Marcellus play areas. The ongoing U.S. program and expenditures will be tailored based on drilling results and U.S. gas prices.
We intend to fund our capital expenditures through cash on hand and cash flow generated from operations and borrowings under our Senior Term Loan, which was recently amended to increase the borrowing under the facility by $75 million. The majority of our cash on hand has been generated through our debt and equity offerings and results of operations. The timing, completion and progress of our 2011 capital program is subject to a number of factors, including availability of capital, drilling results, drilling and production costs, availability of drilling services and equipment, partner approvals and technical work. Based on these and other factors, we may increase or decrease our planned capital program or prioritize certain projects over others.
United Kingdom Activity
Activity in the U.K. during 2011 continues to focus on our primary development projects — Bacchus and Greater Rochelle. In October 2010, we completed the sale of our Cygnus asset for cash consideration of $110 million and utilized the proceeds to accelerate our development projects.
On February 23, 2011, we closed our acquisition of an additional 20% working interest in the Bacchus development for approximately $9.2 million in cash payable at closing and approximately $6.2 million in cash payable at the earlier of three months after first oil is produced or the end of 2011. In addition, we paid capital costs incurred by the seller of $9.4 million. Following the acquisition, we hold an aggregate 30% working interest. The field

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development plan (“FDP”) to drill for the Bacchus field calls for a subsea development with three wells to be drilled and linked to production facilities at the nearby Forties field. We are currently drilling our production wells and expect to commence production early next year.
The Greater Rochelle area is comprised of three blocks in the North Sea. In July 2011, the unitization of the Greater Rochelle area, including our interests in blocks 15/27 and 15/26c, was completed resulting in a single set of interest across the field for the interest owners. After the unitization, our working interest in the Greater Rochelle area is now 44%, as compared to a 55.6% working interest in East Rochelle, a 50% working interest in West Rochelle and no working interest in the third block of the Greater Rochelle area. In addition, we retain operatorship of the field. In February 2011, the DECC approved the Rochelle FDP for Block 15/27 in East Rochelle. In April 2011, we announced agreement of the commercial terms for the processing and transportation of East Rochelle production on the Scott Platform in the Central North Sea. We have awarded contracts and commenced construction of the production facilities. We have contracted for a drilling rig which is expected to arrive in the spring of 2012 to commence drilling of the two planned production wells. First production from Greater Rochelle is planned for the second half of 2012.
During the fourth quarter of 2011, we also expect to drill an appraisal well in the Tudor Rose prospect, Block 14/30a, to evaluate an oil discovery that was drilled in 1983. We have a 20% working interest in the prospect.
United States Drilling
We believe that our U.S. acreage provides us with development projects with shorter timeframes to first production at lower costs than our North Sea assets. In addition, our U.S. acreage covers a broad spectrum of established resource plays including the Haynesville, Cotton Valley and Marcellus, to emerging plays in Montana. Our drilling efforts in Alabama did not produce gas at commercial levels and we have decided to discontinue further efforts there.
Our strategy for our U.S. operations has been to employ a measured approach that seeks to balance U.S. natural gas prices with drilling costs. We believe this approach in the U.S. should provide flexibility to adjust our drilling activity in accordance with current and future commodity prices and our operating results, while still allowing our U.S. production to grow and provide near-term return on capital to balance our longer production-cycle U.K. projects.
We currently have positions in three U.S. shale resource plays. In the Haynesville area, we have had drilling activity in the Woodardville, Jamestown, Bull Bayou, Metcalf and Grand Cane fields in Louisiana, and the Willow Springs field in East Texas. During 2010, 12 Haynesville area wells were drilled on our acreage, all of which were successful. We currently have a one rig program operating in the Haynesville area, and during the third quarter of 2011 we brought six new wells on production. We are targeting drilling a total of 15 Haynesville area wells in 2011.
In the Marcellus area, we successfully drilled and cased two horizontal wells in the Daniel Field in Cameron County during 2011. One of these wells is expected to be completed later this year. In parallel, we are working on expanding the Daniel Field gathering pipeline infrastructure,

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including options to connect with one of three major pipelines in Cameron County. We have obtained rights-of-way, and are currently in the process of obtaining permits and conducting a habitat study. Upon completion of these items, we expect to begin construction of a gathering line to tie our production to an existing pipeline.
In Montana, we have drilled four vertical pilot wells to evaluate the Heath shale potential of our acreage and are currently evaluating the results to define possible horizontal re-entry target zones for next year.
Pending Acquisition
In July 2011, we entered into purchase and sale agreements, subject to due diligence and other closing conditions, with SM Energy Company and certain other minority owners to acquire the leasehold and producing interests held by SM Energy and its partners in the Marcellus shale in north-central Pennsylvania, as well as a pipeline and related facilities in McKean and Potter Counties, Pennsylvania, for aggregate consideration of $110 million.
The assets include the following:
    Approximately 50,000 net acres of leasehold with 100 percent operated working interests in McKean and Potter counties;
 
    Current production from three existing wells of approximately three to four million cubic feet of natural gas per day, including the Potato Creek #3H well that initially flowed 11 million cubic feet of gas per day and is expected to recover in excess of 4 billion cubic feet of gas;
 
    100 percent ownership of Potato Creek LLC, which owns a midstream gathering system and related facilities in southern McKean County, including a 10-mile 16” trunkline connected and flowing to Tennessee Gas Pipeline’s 24” mainline; and
 
    Proprietary and fully processed 3-D seismic survey covering the entire Potato Creek lease block.
A new 7-year lease will be issued at closing on the key 21,000 net acre Potato Creek block that requires only five wells to be drilled in the first three years to hold the acreage. Over the next three years, minimal capital is required to hold all acreage in McKean County, including the key Potato Creek leasehold.
Outlook
As we near the end of 2011, we expect to conserve capital and focus on two development projects in the U.K. — Bacchus and Rochelle. Capital expenditures for Bacchus currently have our highest priority as we plan to reach first production early next year. Once Bacchus begins producing, we expect to earmark a substantial portion of the cash flows from its production to complete the necessary development program for the Greater Rochelle area to allow East Rochelle to reach first production in the second half of 2012. Any remaining capital will be divided among smaller commitments such as our Tudor Rose exploration well in the U.K., evaluation of our Montana vertical pilot wells and complete drilling in the Marcellus and

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Haynesville areas. The extent of our U.S. drilling program will be determined by our anticipated available cash and any changes in the U.S. natural gas markets and prices.
Our primary sources of financial resources and liquidity are cash on hand, internally generated cash flows from operations and access to the credit and capital markets, to the extent necessary. Oil prices continue to be impacted by supply and demand on a worldwide basis. Although oil and gas prices have remained volatile, the full impact on our cash flows will be partially mitigated by our balance of gas and oil production and our commodity derivative positions.
At September 30, 2011, we had $471.7 million in outstanding debt. Our outstanding debt instruments contain certain financial ratio covenants. We were in compliance with all financial covenants in our debt obligations as of September 30, 2011 and December 31, 2010, respectively. However, the delay in the start up of production from Bacchus will have an adverse impact on our ability to maintain compliance with the minimum EBITDA covenant included in our Senior Term Loan at year end. If we are unable to maintain compliance, we are confident in our ability to work with our lenders to provide for an appropriate amendment or waiver.
We also announced a potential high-yield debt offering in June. When global economic worries created instability in the high-yield debt market we chose to exercise financial discipline and avoid issuing debt at that time. However, we remain optimistic that the market will regain its stability and be available to us should we decide to access it at a later date.
As we pushed our U.K. and U.S. capital programs forward, we reviewed opportunities to add resources that matched our strategic plan at reasonable rates of return for our shareholders. In July 2011, we finalized an opportunity to add to our position in the Marcellus area by acquiring property that had undeveloped acreage, the ability to increase our production and reserves over the next several years and a relatively new gathering pipeline in the area that connected to a major pipeline. We secured financing for this pending acquisition by issuing $135 million of 5.5% Convertible Senior Notes, at a time when the market value of our common stock was near its high for the previous 12 months. However, there is no requirement to use these proceeds for the Marcellus or any other acquisition. The net proceeds may be used for general corporate purposes.
While we expect our 2012 production to be greater than our 2011 production, that increase will not occur evenly throughout the year. Instead, the anticipated production increase is highly sensitive to the timing of first production from Bacchus and Rochelle. We expect our production will grow from current 2011 levels as Bacchus and, eventually, Rochelle achieve first production. Each of these operational activities will have an impact on our production as follows:
    Initial production date of the Bacchus field — We are currently drilling the initial production wells and completing infrastructure. Production is expected to commence early next year. The precise initial production date, rate of production and how long it may take for Bacchus to reach full production from all three wells are key variables to our overall production levels.

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    Initial production date of the Greater Rochelle field — We are working to complete engineering and procure long-lead time equipment. We have contracted for a drilling rig which is expected to arrive in the spring of 2012 to commence drilling of the two planned production wells. The operator of the Scott platform, Rochelle’s off-take solution, has commenced the required modifications to prepare it for production from the Greater Rochelle area in 2012. First production from Greater Rochelle is planned for the fourth quarter of 2012.
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 September 30, 2011:
                                         
(Amounts in thousands)                   Payments due by Period        
    Total     Less than 1 Year     1-3 Years     3-5 Years     After 5 Years  
 
Long-term debt
                                       
 
                                       
Principal
  $ 471,727     $ 14,850     $ 256,773     $ 200,104     $  
Interest (1)
    145,647       47,335       51,795       46,517        
Asset retirement obligations
    34,686       6,480       9,599       1,467       17,140  
Operating leases for office leases and equipment
    2,246       298       961       658       329  
 
 
                                       
Total Contractual Obligations
  $ 654,306     $ 68,963     $ 319,128     $ 248,746     $ 17,469  
 
 
(1)   Interest on our certain of our debt instruments is added to the outstanding principal balance each quarter and reflected as due upon maturity.
Cautionary Statement for Forward-Looking Statements
Certain statements and information in this Quarterly Report on Form 10-Q may constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential

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impact of any future acquisitions. In particular, this report contains forward-looking statement pertaining to the following:
    our future financial position;
 
    our business strategy;
 
    pending acquisitions;
 
    budgets;
 
    projected costs, savings and plans;
 
    objectives of management for future operations;
 
    legal strategies; and
 
    legal proceedings.
Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below:
    discovery, estimation, development and replacement of oil and gas reserves;
 
    decreases in proved reserves due to technical or economic factors;
 
    drilling of wells and other planned exploitation activities;
 
    timing and amount of future production of oil and gas;
 
    the volatility of oil and gas prices;
 
    availability and terms of capital;
 
    operating costs such as lease operating expenses, administrative costs and other expenses;
 
    our future operating or financial results;
 
    amount, nature and timing of capital expenditures, including future development costs;
 
    cash flow and anticipated liquidity;
 
    availability of drilling and production equipment;
 
    uncertainties related to drilling and production operations in a new region;
 
    cost and access to natural gas gathering, treatment and pipeline facilities;
 
    business strategy and the availability of acquisition opportunities; and
 
    factors not known to us at this time.
Any of these factors, or a combination of these factors, could materially affect our future financial condition or results of operations and the ultimate accuracy of the forward-looking statements. The forward-looking statements are not guarantees of our future performance, and our actual results and future developments may differ materially from those projected in the forward-looking statements. In addition, any or all of our forward-looking statements in this Quarterly Report on Form 10-Q may turn out to be incorrect. They can be affected by inaccurate assumptions we might make or by known or unknown risks and uncertainties, including those mentioned in Part I, “Item A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2010. Except as required by law, we undertake no obligation to update publicly or release any revisions to these forward-looking statements to reflect events or

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circumstances after the date of 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. For additional information regarding our derivative instruments, see Note 9 to the Condensed Consolidated Financial Statements.
At September 30, 2011, we had the following commodity derivative instruments outstanding:
                         
    2011     2012     Total  
 
Oil:
                       
Fixed Price Puts (Mbbl) — Brent
    69       100       169  
Weighted Average Price ($/Barrel)
  $ 95.16     $ 90.74     $ 92.54  
 
                       
Gas: (1)
                       
Fixed Price Puts (MMcf) — Heren National Balancing Point
    295       548       842  
Weighted Average Price ($/Mcf)
  $ 7.57     $ 8.30     $ 8.04  
 
(1)   Gas derivative contracts are designated in therms and have been converted to Mcf at a rate of 10 therm to 1 Mcf. The exchange rate at September 30, 2011 was $1.56 to £1.00.
Item 4: Controls and Procedures
Evaluation of Disclosure Controls and Procedures
As required by Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended, 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”), of 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 Securities Exchange Act of 1934, as amended) as of the end of the period covered by this 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 Securities Exchange Act of 1934, as amended, is (a) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (b) is

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accumulated and 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 September 30, 2011.
Changes in Internal Control over Financial Reporting
There was no change in our system of internal control over financial reporting (as defined in Rules 13a-15(f), and 15d-15(f) under the Securities Exchange act of 1934, as amended), during the last fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Part II. Other Information
Item 1A: Risk Factors
In addition to the factors discussed below and elsewhere in this report, including the financial statements and related notes, you should consider carefully the risks and uncertainties described below and in our Annual Report on Form 10-K for the year ended December 31, 2010 under Item 1A “Risk Factors,” which could materially adversely affect our business, financial condition and results of operations. 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.
Recently Proposed Rules Regulating Air Emissions from Oil and Gas Operations Could Cause Us to Incur Increased Capital Expenditures and Operating Costs
On July 28, 2011, the Environmental Protection Agency (“EPA”) proposed rules that would establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s proposed rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The EPA’s proposal would require the reduction of VOC emissions from oil and natural gas production facilities by mandating the use of “green completions” for hydraulic fracturing, which requires the operator to recover rather than vent the gas and natural gas liquids that come to the surface during completion of the fracturing process. The proposed rules also would establish specific requirements regarding emissions from compressors, dehydrators, storage tanks, and other production equipment. In addition, the rules would establish new leak detection requirements for natural gas processing plants. The EPA will receive public comment and hold hearings regarding the proposed rules and must take final action on them by February 28, 2012. If finalized, these rules could require a number of modifications to our operations, including the installation of new equipment.

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Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.
Item 6: Exhibits
The exhibits marked with the asterisk symbol (*) are filed or furnished (in the case of Exhibits 32.1, 32.2 and 101) with this Form 10-Q. Portions of the exhibits marked with the dagger symbol (†) have been omitted pursuant to a request for confidential treatment under Rule 24b-2 of the Securities Exchange Act of 1934, and the omitted material has been separately filed with the Securities and Exchange Commission.
     
2.1 †
  Purchase and Sale Agreement, dated as of July 17, 2011, by and among Endeavour Operating Corporation, SM Energy Company, Potato Creek LLC, Open Flow Gas Supply Corporation and SJ Exploration LLC (Incorporated by reference to Exhibit 2.1 of our Quarterly Report on Form 10-Q (Commission File No. 001-32212) for the quarter ended June 30, 2011).
 
   
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).
 
   
3.2(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).
 
   
4.1
  Indenture dated as of July 22, 2011 among Endeavour International Corporation, the Guarantors named therein and Well Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on July 22, 2011).
 
   
4.2
  Form of 5.5% Rule 144A Global Note, dated July 22, 2011 (included in Exhibit 4.1).
 
   
10.1
  Third Amendment to Credit Agreement, U.S. Security Agreement and Subsidiaries Guaranty, dated as of July 15, 2011, by and among Endeavour International Corporation, Endeavour Energy UK Limited, Cyan Partners, LP, as administrative agent, and certain lenders party thereto (Incorporated by reference to Exhibit 10.2

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  of our Quarterly Report on Form 10-Q (Commission File No. 001-32212) for the quarter ended June 30, 2011).
 
   
10.2
  Letter of Credit Facility Agreement dated as of July 25, 2011 by and between Endeavour International Corporation and Commonwealth Bank of Australia (Incorporated by reference to Exhibit 10.3 of our Quarterly Report on Form 10-Q (Commission File No. 001-32212) for the quarter ended June 30, 2011).
 
   
31.1 *
  Certification of William L. Transier, Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
   
31.2 *
  Certification of J. Michael Kirksey, Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
   
32.1 *
  Certification of William L. Transier, Chief Executive Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
   
32.2 *
  Certification of J. Michael Kirksey, Chief Financial Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
   
101.INS*
  XBRL Instance Document.
 
   
101.SCH*
  XBRL Taxonomy Extension Schema Document.
 
   
101.CA*
  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.

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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: November 8, 2011
  /s/ J. Michael Kirksey   /s/ Robert L. Thompson
 
       
 
  J. Michael Kirksey
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)
  Robert L. Thompson
Senior Vice President and
Chief Accounting Officer
(Principal Accounting Officer)

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