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EX-32.2 - EX-32.2 - ENDEAVOUR INTERNATIONAL CORPh70183exv32w2.htm
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EX-23.1 - EX-23.1 - ENDEAVOUR INTERNATIONAL CORPh70183exv23w1.htm
EX-12.1 - EX-12.1 - ENDEAVOUR INTERNATIONAL CORPh70183exv12w1.htm
EX-10.7 - EX-10.7 - ENDEAVOUR INTERNATIONAL CORPh70183exv10w7.htm
EX-99.1 - EX-99.1 - ENDEAVOUR INTERNATIONAL CORPh70183exv99w1.htm
EX-31.2 - EX-31.2 - ENDEAVOUR INTERNATIONAL CORPh70183exv31w2.htm
EX-21.1 - EX-21.1 - ENDEAVOUR INTERNATIONAL CORPh70183exv21w1.htm
EX-23.2 - EX-23.2 - ENDEAVOUR INTERNATIONAL CORPh70183exv23w2.htm
EX-3.6.C - EX-3.6.C - ENDEAVOUR INTERNATIONAL CORPh70183exv3w6wc.htm
EX-10.26.B - EX-10.26.B - ENDEAVOUR INTERNATIONAL CORPh70183exv10w26wb.htm
EX-10.15.B - EX-10.15.B - ENDEAVOUR INTERNATIONAL CORPh70183exv10w15wb.htm
EX-10.13.C - EX-10.13.C - ENDEAVOUR INTERNATIONAL CORPh70183exv10w13wc.htm
Table of Contents

 
 
United States
Securities and Exchange Commission
Washington, D.C. 20549
Form 10-K
     
þ   Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the Fiscal Year Ended December 31, 2009
     
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: 001-32212
Endeavour International Corporation
(Exact name of registrant as specified in its charter)
     
Nevada   88-0448389
     
(State or other jurisdiction of incorporation or organization)   (I.R.S. Employer Identification No.)
     
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)
Securities registered pursuant to Section 12(b) of the Act:
     
Title of Each Class of Stock   Name of Each Exchange on Which Registered
     
Common Stock - $0.001 par value per share   NYSE-Amex
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer as defined in Rule 405 of the Securities Act. o Yes þ No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. o Yes þ No
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 (§ 232.405 of this chapter) during the preceding 2 months (or for such shorter period that the registrant was required to submit and post such files). o Yes o No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ
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
        (Do not check if a smaller reporting company)    
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
The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant was $154.0 million computed by reference to the closing sale price of the registrant’s common stock on the NYSE-Amex on June 30, 2009, the last business day of the registrant’s most recently completed second fiscal quarter. Shares of common stock held by executive officers and directors of the registrant are not included in the computation. However, the registrant has made no determination that such individuals are “affiliates” within the meaning of Rule 405 of the Securities Act of 1933.
As of March 12, 2010, 160,247,205 shares of the registrant’s common stock were outstanding.
Documents Incorporated By Reference:
Portions of the registrant’s definitive proxy statement relating to the 2010 Annual Meeting of Stockholders, which will be filed within 120 days of December 31, 2009, are incorporated by reference into Part III of this Form 10-K.
 
 

 


 

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Part III
       
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 EX-3.6.C
 EX-10.7
 EX-10.13.C
 EX-10.15.B
 EX-10.26.B
 EX-12.1
 EX-12.2
 EX-21.1
 EX-23.1
 EX-23.2
 EX-31.1
 EX-31.2
 EX-32.1
 EX-32.2
 EX-99.1
Quantities of natural gas are expressed in this Annual Report on Form 10-K 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 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

Endeavour International Corporation
Part I
Item 1. Business
Endeavour International Corporation is an independent oil and gas company engaged in the exploration, development and acquisition of energy reserves in the U.S. and U.K. Unless the context otherwise requires, references to “Endeavour”, “we”, “us” or “our” mean Endeavour International Corporation and our consolidated subsidiaries.
General
Since commencing operations in 2004, we have built a strong asset base and achieved steady reserve growth through acquisitions and exploration and development activities. Historically, we have focused our operations in the North Sea, but have recently expanded our focus to target unconventional U.S. onshore resource shale plays with shorter production-cycle times and compelling risk/return profiles. As a result, we have established a strong foundation of producing assets and undeveloped acreage in both established and emerging U.S. onshore resource plays, including approximately 66,000 gross (27,000 net) acres within the Haynesville and Marcellus Shale regions, complemented by our four development assets in the UK North Sea.
Our strategic shift to expand our focus to include U.S. onshore asset development has been achieved through measured and specific steps taken in 2009. In May 2009, we sold our assets and operations in the Norwegian sector of the North Sea for $150 million. Proceeds from this sale enabled us to enter into a joint venture relationship with an established U.S. gas shale operator, providing us with acreage positions and production in the Haynesville and Marcellus gas shales. We also entered into additional joint venture agreements with other selected operators, providing exposure to emerging shale plays in Alabama and Montana.
The primary focus of our U.S. unconventional gas shale development efforts will target reserve and production growth in the Haynesville and Marcellus Shales. We have approximately 7,250 net acres with over 200 potential drilling locations in the Northern Louisiana and East Texas Haynesville Shale, with acreage located in Red River, DeSoto, Bienville and Caddo Parishes in Louisiana and Harrison and Gregg Counties in Texas. Our Marcellus gas shale acreage is comprised of 19,750 net acres and over 300 potential drilling locations, with acreage between two of the most active parts of the play. We also have exploratory plans in emerging shale plays in Alabama and Montana, with 63,000 and 75,000 net acres, respectively. Early well results will determine the pace and scope of subsequent development initiatives in each of these plays.
In addition to our recent expansion into the onshore U.S. shale plays, we intend to continue to actively manage our North Sea assets in a manner that maximizes value and enables us to allocate resources to effectively pursue our strategic objectives. Our North Sea activities and assets remain a key source of value that can be further developed to increase our overall reserves and production. Our major development projects – Bacchus, Columbus, Cygnus and Rochelle – have the potential to significantly expand our total proved reserves and production levels.

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Further exploration and development efforts will continue on our current and nearby properties, as appropriate, to best achieve maximum risk-adjusted value for our North Sea assets.
With the recent volatility in commodity prices and concerns over the financial markets, we will continue to pursue our strategy of exploiting a balanced portfolio of exploration and development assets through a disciplined approach. We are attempting to balance the capital intensive, long lead-time nature of our North Sea assets with our recent entry into the onshore U.S. shale plays. We believe the resource-rich shale plays provide us with less expensive, shorter lead time opportunities in some of the most active hydrocarbon producing areas in the U.S. We intend to develop our existing assets in the North Sea, which we expect to enter production beginning in 2011, while simultaneously pursuing the development of our leasehold positions in the Haynesville and Marcellus Shales.
Strategic Alternatives for North Sea Assets
On March 15, 2010, we announced that our board of directors has approved a review of strategic alternatives for its North Sea assets. In an effort to unlock the value of our underlying North Sea assets, we will study a full range of options, including:
    Continuing to execute current operations plan;
 
    Entering into a joint venture to accelerate activities in the North Sea; and
 
    Selling specific assets or the North Sea entire business.
We will announce the results of the effort once a course of action is chosen. At the end of this review process, we may elect to make no changes.
Our Areas of Operation
North Sea
The exploitation of North Sea oil reserves has been ongoing for a number of decades and the resulting increase in international oil prices made the large investments needed for extraction attractive. Although production costs are relatively high, the quality of the oil, the political stability of the region, and the proximity of important markets in Western Europe has made the North Sea an important oil producing region.
Our development assets in the Bacchus, Columbus, Cygnus and Rochelle fields comprise the primary component of our UK North Sea portfolio. We currently have development plans under way in each of these primary fields. When these projects are fully producing, they have the potential to exceed our current production levels from all other fields. We also hold interests in producing and non-producing properties in the UK sector of the North Sea. Our producing properties include the Alba, Bittern, Enoch and Goldeneye fields and recently suspended production from certain of our fields. We anticipate re-developing these suspended fields, if commercially advisable and practicable, once additional production commences from the nearby Rochelle field. We believe our assets in the North Sea possess significant value that can continue to be harvested or monetized in a manner that maximizes shareholder value.

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Endeavour International Corporation
Primary Development Fields
Rochelle
We hold a 55.6% working interest in and operate our Rochelle field assets. Our interests in the Rochelle field account for 6.3 MMBOE of our proved reserves at December 31, 2009. The environmental impact study for the subsea development and pipeline corridor has been completed with no sensitivities identified.
Moreover, recent seismic studies in the area near our Rochelle field in the North Sea indicate that the natural gas formation may be larger than we had previously understood. We believe this larger Rochelle area can be developed using the current infrastructure. We are planning to drill a well to test the westward expansion of the Rochelle play in 2010. The Rochelle development is scheduled to achieve first production in 2011. This first production is dependent on approval of the Field Development Plan from the Department of Energy and Climate Change (“DECC”), which is further dependent on receiving acceptable commercial terms from the infrastructure holders for the off-take solution.
Cygnus
We hold a 12.5% working interest in our Cygnus field assets, which are operated by Gaz de France. Our interests in the Cygnus field account for 5.7 MMBOE of our proved reserves at December 31, 2009. These proved reserves are associated with the eastern portion of the field. Appraisal drilling to test two additional fault blocks in the western portion of the field has begun, with drilling underway of a well in the fourth fault block. A field development plan has been filed, with production from the eastern portion of the field expected to begin in 2011.
Columbus
We hold a 25% working interest in our Columbus field assets, which are operated by Serica Energy plc. Our interests in the Columbus field account for 1.8 MMBOE of our proved reserves at December 31, 2009. The host platform has been identified and commercial agreements are under negotiation with first production expected in 2012.
Bacchus
We hold a 10% working interest in our Bacchus field assets, which are operated by Apache Corporation. The development of the Bacchus field is expected to be sanctioned in 2010 by the DECC with first production expected to commence in 2011. The discovery well was drilled in 2005, followed by a down-dip sidetrack appraisal well that tested the upper part of the reservoir. A three-well subsea development tie-back to the Forties field is planned.

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Endeavour International Corporation
Producing Fields
We have four producing fields in the U.K. – Alba, Bittern, Enoch and Goldeneye. Combined these fields held 2.5 MMBOE of proved reserves at December 31, 2009. The Goldeneye field represents nearly all of our current gas production in the U.K.
Our Ivanhoe, Rob Roy, Hamish (collectively, “IVRRH”), Renee and Rubie fields all produced to a single floating production facility that has experienced significant increases in operating costs in recent periods. As a result, production was suspended in the first quarter of 2009 and will remain suspended until the development activities at Rochelle are operational, which we currently anticipate to be during 2011. After the start of Rochelle production, we expect to re-develop these fields if commercially advisable and practicable.
United States
We have made significant recent acquisitions to bolster our holdings in unconventional U.S. onshore resource shale plays. As of March 16, 2010, our U.S. acreage consisted of approximately 165,000 net acres. We believe that our U.S. acreage provides us with development projects with shorter timeframes compared to our North Sea assets, and a strong return/risk profile. We anticipate that development of our U.S. acreage will be less expensive than our North Sea assets and reduce our overall finding and development costs. In addition, our U.S. acreage covers a broad spectrum of resource plays, from established and explored areas, such as the Haynesville and Marcellus Shales, to “frontier” areas, in Alabama and Montana.
Haynesville Shale
The Haynesville Shale has become one of the most active natural gas plays in the U.S. This area is defined by a Jurassic shale formation located approximately 1,000 to 1,500 feet below the base of the Cotton Valley formation at depths ranging from approximately 10,500 feet to 13,000 feet. The formation is 125 to 250 feet thick and is composed of organic-rich, black shale. It is located across numerous parishes in Northwest Louisiana, primarily in Caddo, Bossier, Red River, DeSoto, Webster and Bienville parishes and also in East Texas. Numerous shallower secondary objectives exist in the Haynesville Shale play area, including the overlying Jurassic Cotton Valley Sandstone and Bossier Shale intervals.
To facilitate our entrance into the Haynesville Shale, we have entered into a joint venture relationship with Cohort Energy, a subsidiary of J-W Operating Company (“J-W Operaing”). J-W Operating, a privately-held company, is a proven operator that has drilled over 130 horizontal wells in the Barnett, Haynesville, Marcellus and other shale formations since 2004. In separate transactions, we have acquired interests in both producing wells and acreage that is prospective for the Haynesville Shale. We have not acquired any meaningful Haynesville Shale interests outside of our relationship with Cohort Energy. Both the Haynesville and the Marcellus Shale project wells (described below) will be operated by J-W Operating, which has substantial experience in the Haynesville and Marcellus Shales.

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In October 2009, we purchased 50% of Cohort’s working interest in 24 wells located in five fields and certain proved undeveloped locations associated with Cohort’s proved developed assets in North Louisiana and East Texas for $15 million in cash. These 24 wells, some of which produce from the Cotton Valley trend and some of which produce from the Haynesville Shale, are associated with net proved reserves of approximately 1.6 MMBOE.
In addition to these wells, through our joint venture with Cohort Energy, we hold interests in approximately 17,700 gross (7,250 net) acres with Haynesville Shale potential. In connection with this acreage, we have identified over 200 potential drilling locations. Of this acreage, approximately 13,500 gross (5,800 net) acres are located in the Haynesville Shale core area in Louisiana with over 150 potential drilling locations.
Our most recent Haynesville well in Red River Parish, Louisiana, the Indigo Minerals 3#1-H, initially flowed approximately 21 MMcf/d and has produced over 2 Bcf (gross) gas in its first 6 months of production. Currently, we are drilling the Bachelor 3#1-H as a direct offset to the Indigo Minerals well. We are also drilling the Longview North 1H in Gregg County, Texas as a horizontal Cotton Valley Sandstone test.
Marcellus Shale
The Marcellus Shale is a Middle Devonian-aged shale that underlies much of Pennsylvania, New York, Ohio, West Virginia and adjacent states. The Marcellus Shale is an organic-rich shale gas target which we believe is analogous to the Mississippian Barnett Shale in Texas. Within the past few years, advances in two technologies, fracture stimulation and horizontal drilling, have produced promising results in the Marcellus Shale. These developments have resulted in significantly increased leasing and drilling activity in the area. As with our Haynesville Shale acreage, we have acquired all of our interests in the Marcellus Shale through a 50/50 joint venture relationship with Cohort Energy/J-W Operating who will operate the project. We acquired interests in approximately 48,300 gross (19,750 net) acres prospective for the Marcellus Shale in several project areas, including portions of Cameron, Elk, Potter, McKean, Jefferson and Clarion counties, Pennsylvania. In connection with this acreage, we have over 300 potential drilling locations. Currently, we are planning to complete the Pardee C-9H horizontal well in Cameron County followed by vertical pilot tests in other selected project areas.
Alabama Gas Shales
Through our joint venture with Hillwood Energy Alabama LP, an affiliate of Hillwood International Energy, we hold a 50% non-operating interest in approximately 160,000 gross (63,000 net) acres with exposure to emerging gas shale plays in western Alabama. Hillwood has an extensive and successful background as a participant and an operator in the Barnett shale play. Our position allows us to target multiple gas shale intervals. If successful, we believe this acreage could yield in excess of 400 potential drilling locations. We intend to participate in the drilling of vertical pilot wells during the first half of 2010, which may be followed by horizontal re-entries. We will monitor the results of these wells before formulating an appropriate development plan.

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Endeavour International Corporation
Central Montana Oil-prone Shales
Through our joint venture with a private company, we own a 25% non-operating interest in approximately 300,000 gross (75,000 net) acres in central Montana. In this region, historical conventional oil production from Cretaceous through Mississippian reservoirs has totaled over 130 MMBoe. Our acreage contains approximately 900 potential drilling locations and has exposure to both the Mississippian Heath and Devonian Bakken oil-prone source shales. We currently plan to participate in the drilling of pilot wells during 2010. As with our Alabama acreage, we intend to monitor the results of these wells before determining further appraisal or development plans.
Reserves
Our proved oil and gas reserves at December 31, 2009, 2008 and 2007 included the following:
                         
    Oil   Gas   Oil Equivalents
 
    (MBbls)   (MMcf)   (MBOE)
2009:
                       
United Kingdom
    3,348       78,316       16,401  
United States
    18       10,784       1,815  
 
 
    3,366       89,100       18,216  
 
 
                       
2008:
                       
United Kingdom
    2,131       27,130       6,653  
United States
    18       690       133  
Discontinued operations — Norway
    1,406       4,977       2,236  
 
 
    3,555       32,797       9,022  
 
 
                       
2007:
                       
United Kingdom
    3,284       11,812       5,252  
Discontinued operations — Norway
    2,056       8,434       3,461  
 
 
    5,340       20,246       8,713  
 

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Endeavour International Corporation
Our proved developed and undeveloped oil and gas reserves at December 31, 2009, 2008 and 2007 included the following:
                         
    Proved   Proved    
    Developed   Undeveloped   Total Proved
    Reserves   Reserves   Reserves
 
    (MBOE)   (MBOE)   (MBOE)
2009:
                       
United Kingdom
    2,103       14,298       16,401  
United States
    792       1,023       1,815  
 
 
    2,895       15,321       18,216  
 
 
2008:
                       
United Kingdom
    2,595       4,058       6,653  
United States
    46       87       133  
Discontinued Operations — Norway
    2,122       114       2,236  
 
 
    4,763       4,259       9,022  
 
 
2007:
                       
United Kingdom
    3,947       1,305       5,252  
Discontinued Operations — Norway
    2,752       709       3,461  
 
 
    6,699       2,014       8,713  
 
Preparation of Oil and Gas Reserve Information
We have established internal controls over reserve estimation processes and procedures to support the accurate and timely preparation and disclosure of reserve estimations in accordance with SEC and GAAP requirements. These controls include oversight of the reserves estimation reporting processes by our technical staff, annual external audits of all of our proved reserves by independent reserve engineers and secured access to reservoir databases and systems. Proved reserve estimates are prepared by our technical staff and reviewed and approved by our executive team, including our Executive Vice President of Exploration. Reserves are reviewed internally with senior management quarterly and presented to our Board of Directors in summary form on an annual basis.
For 2009, our oil and gas reserve estimates were prepared by our internal reservoir engineers and audited by independent reserve engineers, Netherland, Sewell & Associates, Inc. (“NSAI”). For 2008 and 2007, our proved oil and gas reserves were estimated by NSAI.
Each year, our internal technical staff use reliable technologies to evaluate all technical data available on each field including production data, wells logs, pressure data, petrophysical analysis, fluid properties, seismic data, seismic interpretations and well control along with offset well data. We estimate the quantity of oil and gas reserves and provide our estimates, analysis and data to our independent reserve engineers.

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Endeavour International Corporation
For 2008 and 2007, we provided our analysis and data to NSAI for their independent estimates using the Securities and Exchange Commission, or SEC, definitions of proved reserves. The independent engineers then performed their own analysis of the same raw data including analysis of all production data, pressure data, well logs, petrophysical analysis, fluid analysis, seismic data and mapping based on that seismic data to determine their own reserves in place and ultimately estimated the quantity of proved oil and gas reserves attributable to a specific property.
Qualification of Reserves Preparers and Auditors
We employ oil and gas technical professionals, including geophysicists, petrophysicists, geologists, petroleum engineers, and production and reservoir engineers, who have an average of 10 to 35 years of experience in their technical fields. In addition, we engage experienced and qualified consultants to perform various comprehensive seismic acquisitions, processing, reprocessing, interpretation, and other related services.
NSAI provides worldwide petroleum property analysis services for energy clients, financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-002699. The technical persons responsible for conducting this audit for NSAI meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. NSAI opined that the overall proved reserves for the reviewed properties as estimated by us are, in the aggregate, reasonable, prepared in accordance with generally accepted petroleum engineering and evaluation principles and conform to the SEC’s definition of proved reserves as set forth in Rule 210.4-10(a) of Regulation S-X. NSAI has informed us that the tests and procedures used during its reserves audit conform to the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Paragraph 2.2(f) of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information defines a reserves audit as the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed, (2) the adequacy and quality of the data relied upon, (3) the depth and thoroughness of the reserves estimation process, (4) the classification of reserves appropriate to the relevant definitions used, and (5) the reasonableness of the estimated reserve quantities. A reserve audit is not the same as a financial audit and is less rigorous in nature than an independent reserve report where the independent reserve engineer determines the reserves on his or her own.
2010 Planned Capital Expenditures
We anticipate spending approximately $90 million during 2010 to fund oil and gas activities in the U.S. and U.K. The majority of this amount is controllable by Endeavour. Our primary focus during 2010 in the U.S. will be in the Haynesville area as we believe this acreage contains near-term production potential. The ongoing U.S. program and expenditures will be tailored based on early drilling results. During 2010, we also expect to begin the evaluation program of our other

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Endeavour International Corporation
U.S. assets in the Marcellus area and the two frontier plays in Alabama and Montana. Four U.K. wells have been or will be drilled in 2010; two Cygnus appraisal wells in the western portion of the field; the Deacon well that began in 2009 and finished in 2010, and the exploration well west of the Rochelle development. While this drilling is occurring, we expect to continue to further our development programs at our four existing development projects, including ongoing engineering assessments for future production and commercial off-take solutions. We intend to fund these development activities through cash on hand, and cash flow generated from operations, as well as expansion of our credit facilities as needed.
The timing, completion and process of our 2010 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.
Company History
Endeavour International Corporation (a Nevada corporation formed in 2000) is an independent oil and gas company engaged in the acquisition, exploration and development of energy reserves.
In November 2004, we purchased a 76.66% majority interest in OER oil AS (“OER”), a privately held Norwegian exploration and production company. In January 2005, we purchased the remaining 23.34% interest in OER from the minority interest holders.
In May 2006, we announced our largest acquisition to date – the purchase of producing properties in the U.K. (the “Talisman Acquisition”). On October 31, 2006, we completed this acquisition of all the outstanding shares of Talisman Expro Limited for $366 million, after purchase price adjustments and expenses. As a result of the Talisman Acquisition, we acquired interests in eight fields in the United Kingdom sector of the North Sea and over seven million BOE of proved reserves as of the closing date.
In the second quarter of 2006, we purchased an eight percent interest in the Enoch Field in the North Sea for approximately $11.7 million. The field is one of the first discoveries to be developed along the median line between the United Kingdom and Norway after the ratification of the U.K./Norway Framework Treaty concerning cross-boundary petroleum cooperation.
While working to complete and integrate these acquisitions, we also moved forward in our drilling program. During 2004 and 2005, we gained approval in the U.K. and Norway to act as an operator or licensee in both countries and began participating in the license round process. We continue to participate in the licensing rounds in the U.K. and Norway. We have also pursued various farm-in and license transfer opportunities to build acreage and exploration potential and spread the risk of exploration drilling among multiple prospects. Most notably, we have four significant development projects ongoing in the U.K. – Bacchus, Columbus, Cygnus and Rochelle. In 2008, we initiated operations in the U.S. and announced our first production there in January 2009.

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On May 14, 2009, we completed the divestiture of our Norwegian subsidiary, Endeavour Energy Norge AS, to VerbundnetzGas AG, a German utility company, for cash consideration of $150 million. We used the proceeds from this divestiture primarily to pay down our outstanding debt and streamline our capital structure, acquire new properties in the U.S. and support our ongoing drilling program. This divestiture allows us to focus our efforts on our acquired positions in our U.S. resource plays, as wells as develop our significant North Sea assets.
In the fourth quarter of 2009, we purchased producing properties and exploration acreage in the U.S. We purchased additional exploration acreage in the U.S. in January 2010. This accumulation of acreage in the U.S. reflects our expansion into resource plays in the U.S.
Geographical Data
We operate in one industry segment, that being oil and gas exploration and production, in two geographical areas. See Note 21 to our consolidated financial statements in “Item 8, Financial Statements and Supplementary Data” for geographic operating segment information, including results of operations and segment assets.
Competition
We encounter intense competition from other oil and gas companies in all areas of our operations, including the acquisition of producing properties and undeveloped acreage. Our competitors include major integrated oil and gas companies, numerous independent oil and gas companies and individuals. Many of our competitors are large, well-established companies with substantially larger operating staffs and greater capital resources and have been engaged in the oil and gas business for a much longer time than our company.
Petroleum and natural gas producers also compete with other suppliers of energy and fuel to industrial, commercial and individual customers. Competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the governments and/or agencies thereof and other factors out of our control including, international political conditions, overall levels of supply and demand for oil and gas, and the markets for synthetic fuels and alternative energy sources.
Significant Customers
Our sales in the U.K. are to a limited number of customers, each of which accounts for more than 10% of revenue: Chevron North Sea Ltd; Shell U.K. Limited, and Esso Exploration and Production. Our sales in the U.S. are sold through our arrangements with the operators of the fields, with substantially all of the sales being to Cohort Energy.
Employees
As of March 16, 2010, we have 43 full-time employees. We believe that we maintain good relationships with our employees, none of whom are covered by a collective bargaining agreement.

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Environmental Matters and Regulation
Endeavour was established on a commitment to find and develop energy resources in a manner that protects the health and safety of people and preserves the quality of the environment. Adhering to high performance standards in the areas of health, safety and the environment (“HSE”) is an integral part of our operations in our efforts to end each day “injury and incident free.”
North Sea
Our operations in the U.K. portions of the North Sea are subject to numerous U.K. and European Union laws and regulations relating to environmental matters, health and safety. Environmental matters are addressed before oil and gas production activities commence and during the exploration and production activities. Before a U.K. licensing round begins, the DECC will consult with various public bodies that have responsibility for the environment. Applicants for production licenses are required to submit a summary of its management systems and how those systems will be applied to the proposed work program. Additionally, the Offshore Petroleum Production and Pipelines (Assessment of Environmental Effects) Regulations 1999 require the Secretary of State to exercise his licensing powers under the U.K. Petroleum Act in such a way to ensure that an environmental assessment is undertaken and considered before consent is given to certain projects.
United States
With our entry into the U.S. onshore shale plays, our U.S. operations are subject to stringent federal, state and local laws and regulations relating to environmental protection, as well as controlling the manner in which various substances, including wastes generated in connection with oil and gas industry operations, are released into the environment. Compliance with these laws and regulations require the acquisition of permits authorizing air emissions and wastewater discharge from operations and can affect the location or size of wells and facilities, limit or prohibit the extent to which exploration and development may be allowed, and require proper closure of wells and restoration of properties that are being abandoned. Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties, imposition of remedial obligations, incurrence of capital costs to comply with governmental standards, and even injunctions that limit or prohibit exploration and production operations or the disposal of substances generated in connection with oil and gas industry operation.
We currently lease a number of properties that for many years have been used for the exploration and production of oil and gas. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or wastes may have been disposed of or released on or under the properties operated or leased by us or on or under other locations where such hydrocarbons or wastes have been taken for recycling or disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or wastes was not under our control. These properties and the hydrocarbons and

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wastes disposed thereon may be subject to laws and regulations imposing joint and several, strict liability, without regard to fault or the legality of the original conduct, that could require us to remove or remediate previously disposed wastes or environmental contamination, or to perform remedial plugging or pit closure to prevent future contamination.
In June 2009, the U.S. House of Representatives passed a bill — the “American Clean Energy and Security Act of 2009,” also known as the “Waxman-Markey cap-and-trade legislation” (“ACESA”) — to control and reduce the emission of “greenhouse gases” (“GHGs”), such as carbon dioxide and methane, that may be contributing to warming of the Earth’s atmosphere and other climatic changes. The U.S. Senate is currently considering similar legislation that seeks to reduce emission of GHGs in the U.S. through the granting of emission allowances which would gradually be decreased over time. Moreover, more than one-third of the states, either individually or through multi-state initiatives, already have begun implementing legal measures to reduce emissions of GHGs. Also, on December 15, 2009, the U.S. Environmental Protection Agency (“EPA”) published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. EPA has also proposed regulations that would require a reduction in emissions of GHGs from motor vehicles, and this regulatory action, if finalized, could also lead to the imposition of GHG emission limitations in Clean Air Act permits for certain stationary sources. In addition, on September 22, 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S. beginning in 2011 for emissions occurring in 2010. Although our facilities were not subject to the EPA’s GHG reporting rule adopted in September 2009, EPA has indicated that it is evaluating whether the rule should be applied to oil and gas production activities, perhaps on a field-wide basis. While it is not possible at this time to fully predict how legislation or new regulations that may be adopted in the U.S. to address GHG emissions would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions, and could have an adverse effect on demand for the oil and natural gas that we produce.
The U.S. Congress is currently considering legislation to amend the federal Safe Drinking Water Act (“SDWA”), to subject hydraulic fracturing operations to regulation under the SDWA and to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate oil and gas production. Sponsors of bills currently pending before the U.S. Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. Proposed legislation would require, among other things, the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings against producers. In addition, these bills, if adopted, could establish an additional level of regulation and permitting of hydraulic fracturing operations at the federal level, which could lead to operational delays, increased operating costs and additional regulatory burdens that could make it more difficult for us to perform hydraulic fracturing, which is an important component of well development. Any impairment of our ability to perform hydraulic fracturing could have an adverse effect on our ability to produce oil and gas from new wells.

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We have made, and will continue to make, expenditures in our effort to comply with environmental laws and regulations. We believe that we are in substantial compliance with applicable environmental laws and regulations in effect and that continued compliance with existing requirements will not have a material adverse impact on us. However, we also believe that it is reasonably likely that the trend in environmental legislation and regulation will continue toward stricter standards and, thus, we cannot give any assurance that we will not be adversely affected in the future.
We have established internal guidelines to be followed in order to comply with environmental laws and regulations in the U.S. We employ a safety department whose responsibilities include providing assurance that our operations are carried out in accordance with applicable environmental guidelines and safety precautions. Although we maintain pollution insurance to cover a portion of the costs of cleanup operations, public liability and physical damage, there is no assurance that such insurance will be adequate to cover all such costs or that such insurance will continue to be available in the future. To date, we believe that compliance with existing requirements of such governmental bodies has not had a material effect on our operations.
Other Regulation of the Oil and Gas Industry
The oil and gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.
Legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including oil and gas facilities. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.
Production Regulation
Our operations are subject to various types of regulation at federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties and municipalities, in which we operate, also regulate one or more of the following:
    the location of wells;
 
    the method of drilling and casing wells;
 
    the surface use and restoration of properties upon which wells are drilled;

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    the plugging and abandoning of wells; and
 
    notice to surface owners and other third parties.
The various states regulate the drilling for, and the production of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowable from oil and gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, and to limit the number of wells or locations we can drill.
Regulation
The exploration, production and sale of oil and gas are extensively regulated by governmental bodies. Applicable legislation is under constant review for amendment or expansion. Oil and gas mineral rights may be held by individuals, corporations or governments having jurisdiction over the area in which such mineral rights are located. As a general rule, parties holding such mineral rights grant licenses or leases to third parties to facilitate the exploration and development of these mineral rights. The terms of the leases and licenses are generally established to require timely development. Notwithstanding the ownership of mineral rights, the government of the jurisdiction in which mineral rights are located generally retains authority over the manner of development of those rights.
Title to Properties
We believe that our title to the various interests set forth above is satisfactory and consistent with generally accepted industry standards, subject to exceptions that would not materially detract from the value of the interests or materially interfere with their use in our operations. Individual properties may be subject to burdens such as royalty, overriding royalty and other outstanding interests customary in the industry. In addition, interests may be subject to obligations or duties under applicable laws or burdens such as production payments, net profits interest, liens incident to operating agreements and for current taxes, development obligations under crude oil and natural gas leases or capital commitments under production sharing contracts or exploration licenses.
Offices
Our principal executive offices are located at 1001 Fannin Street, Suite 1600, Houston, Texas 77002, and our telephone number is (713) 307-8700. Many of our executive officers are also located in our offices at 114 St. Martin’s Lane, London WC2N 4BE England. We also have offices in Aberdeen, United Kingdom and Denver, Colorado.

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Available Information
We file annual and quarterly financial reports, as well as interim updates of a material nature to investors, with the SEC. The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains a website that contains reports, proxy and information statements and other information regarding issuers, including Endeavour, that file electronically with the SEC. The public can obtain any document we file at the SEC web page; http://www.sec.gov.
Our website is available at http://www.endeavourcorp.com. We make available, free of charge, on our website, the annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. Also, our Governance Guidelines, the charters of the Audit Committee, the Compensation Committee and the Governance and Nominating Committee, and the Code of Conduct and Code of Ethics for Senior Officers are available on our website and in print to any stockholder who provides a written request to the Corporate Secretary at 1001 Fannin Street, Suite 1600, Houston, Texas 77002. Our Code of Conduct applies to all directors, officers and employees, including the chief executive officer and senior financial officer.
Information contained on or connected to our website is not incorporated by reference into this Form 10-K and should not be considered part of this report or any other filing that we make with the SEC.
Financial Information about Segment and Geographical Areas
Our revenues and long-lived assets by geographic area is included in Note 21 to our consolidated financial statements in Item 8 and incorporated herein by reference.
Average Sales Prices and Production Costs by Geographical Area
Information on average sales prices and production costs by geographic area is included in Item 7 and incorporated herein by reference.
Item 1A. Risk Factors
Cautionary Statement Concerning Forward-Looking Statements
Certain matters discussed in this Annual Report on Form 10-K are “forward-looking statements” intended to qualify for the safe harbors from liability established by the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. These forward-looking statements include statements that express a belief,

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expectation, or intention, as well as those that are not statements of historical fact, and may include projections and estimates concerning the timing and success of specific projects and our future production, revenues, income and capital spending. Our forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “plan,” “goal” or other words that convey the uncertainty of future events or outcomes. We caution you not to rely on them unduly. In particular, this Annual Report on Form 10-K contains forward-looking statements pertaining to the following:
    our future financial position;
 
    our business strategy;
 
    budgets;
 
    projected costs, savings and plans;
 
    objectives of management for future operations;
 
    legal strategies; and
 
    legal proceedings.
We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks, contingencies and uncertainties, which may not be exhaustive, relate to, among other matters, the following:
    discovery, estimation, development and replacement of oil and gas reserves;
 
    decreases in proved reserves due to technical or economic factors;
 
    drilling of wells and other planned exploitation activities;
 
    timing and amount of future production of oil and gas;
 
    the volatility of oil and gas prices;
 
    availability and terms of capital;
 
    operating costs such as lease operating expenses, administrative costs and other expenses;
 
    our future operating or financial results;
 
    amount, nature and timing of capital expenditures, including future development costs;
 
    cash flow and anticipated liquidity;
 
    availability of drilling and production equipment;
 
    uncertainties related to drilling and production operations in a new region;
 
    business strategy and the availability of acquisition opportunities; and
 
    factors not known to us at this time.
Any of these factors, or a combination of these factors, could materially affect our future financial condition or results of operations and the ultimate accuracy of the forward-looking statements. The forward-looking statements are not guarantees of our future performance, and our actual results and future developments may differ materially from those projected in the forward-looking statements. In addition, any or all of our forward-looking statements in this Annual Report on Form 10-K 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 “Item 1A. Risk Factors” and elsewhere in this Annual Report on Form 10-K.

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Except as required by law, we undertake no obligation to update publicly or release any revisions to these forward-looking statements to reflect events or circumstances after the date of this Annual Report on Form 10-K. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.
Risks related to our business
We operate internationally and are subject to political, economic and other uncertainties.
We currently have operations in the U.S., U.K. and the Netherlands. We may expand our operations to other countries or regions. International operations are subject to political, economic and other uncertainties, including:
    the risk of war, acts of terrorism, revolution, border disputes, expropriation, renegotiation or modification of existing contracts, and import, export and transportation regulations and tariffs;
 
    taxation policies, including royalty and tax increases and retroactive tax claims;
 
    exchange controls, currency fluctuations and other uncertainties arising out of foreign government sovereignty over our international operations;
 
    laws and policies of the U.S. affecting foreign trade, taxation and investment; and
 
    the possibility of being subject to the exclusive jurisdiction of foreign courts in connection with legal disputes and the possible inability to subject foreign persons to the jurisdiction of courts in the U.S.
The exploration, production and sale of oil and gas are extensively regulated by governmental bodies. Applicable legislation is under constant review for amendment or expansion. These efforts frequently result in an increase in the regulatory burden on companies in our industry and consequently an increase in the cost of doing business and decrease in profitability. Numerous governmental departments and agencies are authorized to, and have, issued rules and regulations imposing additional burdens on the oil and gas industry that often are costly to comply with and carry substantial penalties for failure to comply. Production operations are affected by changing tax and other laws relating to the petroleum industry, by constantly changing administrative regulations and possible interruptions or termination by government authorities.
Oil and gas mineral rights may be held by individuals, corporations or governments having jurisdiction over the area in which such mineral rights are located. As a general rule, parties holding such mineral rights grant licenses or leases to third parties to facilitate the exploration and development of these mineral rights. The terms of the leases and licenses are generally established to require timely development. Notwithstanding the ownership of mineral rights, the government of the jurisdiction in which mineral rights are located generally retains authority over the manner of development of those rights.

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Future economic conditions in the U.S. and key international markets may materially adversely impact our operating results, which could hinder or prevent us from meeting our future capital needs.
The U.S. and other world economies are slowly recovering from a recession which began in 2008 and extended into 2009. Growth has resumed, but is modest. There are likely to be significant long-term effects resulting from the recession and credit market crisis, including a future global economic growth rate that is slower than what was experienced in recent years. In addition, more volatility may occur before a sustainable, yet lower, growth rate is achieved. Global economic growth drives demand for energy from all sources, including fossil fuels. A lower future economic growth rate will result in decreased demand growth for our crude oil and natural gas production as well as lower commodity prices, which will reduce our cash flows from operations and our profitability and may adversely affect our ability to obtain funding for our projects.
In addition, we may be unable to obtain adequate funding under our current senior bank facility because (i) our lending counterparties may be unwilling or unable to meet their funding obligations or (ii) our borrowing base under our current senior bank facility is redetermined at least twice per year and was reduced twice in 2009 as a result of lower oil or gas prices, declines in reserves, sales of assets and lending requirements or regulations.
Due to these factors, we cannot be certain that funding will be available if needed, and to the extent required, on acceptable terms or at all. If funding is not available as needed, or is available only on unfavorable terms, we may be unable to meet our obligations as they come due, or we may be unable to implement our capital program, enhance our existing business, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations.
Oil and gas prices are volatile, and a decline in oil and gas prices would reduce our revenues, profitability and cash flow and impede our growth.
Our revenues, profitability and cash flow depend substantially upon the prices and demand for oil and gas. The markets for these commodities are volatile, and even relatively modest drops in prices can significantly affect our financial results and impede our growth. Oil and gas prices increased to, and then declined significantly from, historical highs in 2008 and may fluctuate and decline significantly in the near future. Prices for oil and gas fluctuate in response to relatively minor changes in the supply and demand for oil and gas, market uncertainty and a variety of additional factors beyond our control, such as:
    global supply of oil and gas;
 
    level of consumer product demand;
 
    technological advances affecting oil and gas consumption;
 
    global economic conditions;
 
    price and availability of alternative fuels;

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    actions of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil price and production controls;
 
    governmental regulations and taxation;
 
    political conditions in or affecting other oil-producing and gas-producing countries;
 
    weather conditions;
 
    the proximity, capacity, cost and availability of pipeline and other transportation facilities; and
 
    the impact of energy conservation efforts.
Lower oil and gas prices may not only decrease our revenues on a per unit basis, but significant or extended price declines may also reduce the amount of oil and gas that we can produce economically. A reduction in production could result in a shortfall in expected cash flows and require us to reduce capital spending or borrow funds to cover any such shortfall. Any of these factors could negatively impact our ability to replace our production and our future rate of growth.
In addition, we may, from time to time, enter into long-term contracts based upon our reasoned expectations for commodity price levels. If commodity prices subsequently decrease significantly for a sustained period, we may be unable to perform our obligations or otherwise breach the contract and be liable for damages.
Competition for oil and gas properties and prospects is intense and some of our competitors have larger financial, technical and personnel resources that give them an advantage in evaluating, obtaining and developing properties and prospects.
We operate in a highly competitive environment for reviewing prospects, acquiring properties, marketing oil and gas and securing trained personnel. Many of our competitors are major or independent oil and gas companies that have longer operating histories in our areas of operation and employ superior financial resources which allow them to obtain substantially greater technical and personnel resources and which better enable them to acquire and develop the prospects that they have identified. We also actively compete with other companies when acquiring new licenses or oil and gas properties. Our relatively small size could adversely affect our ability to obtain new prospects and opportunities. Specifically, competitors with greater resources than our own have certain advantages that are particularly important in reviewing prospects and purchasing properties. Competitors may be able to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Competitors may also be able to pay more for producing oil and gas properties and exploratory prospects than we are able or willing to pay. If we are unable to compete successfully in these areas in the future, our future revenues and growth may be diminished or restricted.
These competitors may also be better able to withstand sustained periods of unsuccessful drilling or downturns in the economy, including decreases in the price of commodities as experienced in 2008 and 2009. Larger competitors may also be able to absorb the burden of any changes in laws and regulations more easily than we can, which would also adversely affect our competitive position. In addition, most of our competitors have been operating for a much longer time and have demonstrated the ability to operate through industry cycles.

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We are dependent on our executive officers and need to attract and retain additional qualified personnel.
Our future success depends in large part on the service of our executive officers. The loss of these executives could have a material adverse effect on our business. Although we have employment agreements with certain of our executive officers, there can be no assurance that we will have the ability to retain their services. Further, we do not maintain key-person life insurance on any executive officers.
Our future success also depends upon our ability to attract, assimilate and retain highly qualified technical and other management personnel who are essential for the identification and development of our prospects. There can be no assurance that we will be able to attract, integrate and retain key personnel, and our failure to do so would have a material adverse effect on our business.
Our use of derivative transactions may limit future revenues from price increases and involves the risk that our counterparties may be unable to satisfy their obligations to us.
To manage our exposure to price or interest rate risk with our production, we routinely enter into commodity derivative contracts. The goal of these derivative contracts is to limit volatility and increase the predictability of cash flow. Although the use of derivative contracts limits the downside risk of price declines, their use also may limit future revenues from price increases. In addition, derivative contracts may expose us to the risk of financial loss in certain circumstances, including instances in which our production is less than expected or a sudden, unexpected event materially impacts oil or gas prices.
Derivative contracts also involve the risk that counterparties, which generally are financial institutions, may be unable to satisfy their obligations to us. If any of our counterparties were to default on its obligations to us under the derivative contracts or seek bankruptcy protection it could have a material adverse effect on our ability to fund our planned activities and could result in a larger percentage of our future production being subject to commodity price changes. In addition, in the current economic environment and tight financial markets, the risk of a counterparty default is heightened and it is possible that fewer counterparties will participate in future derivative transactions, which could result in greater concentration of our exposure to any one counterparty or a larger percentage of our future production being subject to commodity price changes.
Risks related to executing our strategy and operations
To maintain and grow our production and cash flow, we must continue to develop and produce existing reserves and discover or acquire new oil and gas reserves to develop and produce.
Our future oil and gas production is highly dependent upon our level of success in finding or acquiring additional reserves. Producing oil and gas reserves are generally characterized by

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declining production rates that vary depending on reservoir characteristics and other factors. Our reserves will decline unless we acquire properties with proved reserves or conduct successful development and exploration drilling activities. We accomplish this through successful drilling programs and the acquisition of properties. However, we may be unable to find, develop or acquire additional reserves or production at an acceptable cost or at all. Acquisition opportunities in the oil and gas industry are very competitive, which can increase the cost of, or cause us to refrain from, completing acquisitions.
If we are unable to find, develop or acquire additional reserves to replace our current and future production, our production rates will decline even if we drill the undeveloped locations that were included in our estimated proved reserves. Our future oil and gas reserves and production, and therefore our cash flow and income, are dependent on our success in economically finding or acquiring new reserves and efficiently developing our existing reserves.
We may be unable to make attractive acquisitions, and any acquisition we complete is subject to substantial risks that could impact our business.
As part of our growth strategy, we intend to pursue strategic acquisitions of new properties or businesses that expand our current asset base and potentially offer unexploited reserve potential. Our growth strategy following the full development of our existing properties could be impeded if we are unable to acquire additional interests in oil and gas prospects on a profitable basis. Acquisition opportunities in the oil and gas industry are very competitive, which can increase the cost of, or cause us to refrain from, completing acquisitions. The success of any acquisition will depend on a number of factors and involves potential risks, including among other things:
    the inability to estimate accurately the costs to develop the interests in oil and gas prospects, the recoverable volumes of reserves, rates of future production and future net cash flows attainable from the reserves;
 
    the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which the indemnity we receive is inadequate;
 
    the validity of assumptions about costs, including synergies;
 
    the impact on our liquidity or financial leverage of using available cash or debt to finance acquisitions;
 
    the diversion of management’s attention from other business concerns; and
 
    an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets.
All of these factors affect whether an acquisition will ultimately generate cash flows sufficient to provide a suitable return on investment. Even though we perform a review of the properties we seek to acquire that we believe is consistent with industry practices, such reviews are often limited in scope. As a result, among other risks, our initial estimates of reserves may be subject to revision following an acquisition, which may materially and adversely impact the desired benefits of the acquisition.

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Our expectations for future drilling activities will be realized over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing.
We have identified drilling locations and prospects for future drilling opportunities, including development, exploratory and other drilling and enhanced recovery activities. These drilling locations and prospects represent a significant part of our future drilling plans. Our ability to drill and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, third-party operators, regulatory approvals, negotiation of agreements with third parties, commodity prices, costs and drilling results. Because of these uncertainties, we cannot give any assurance as to the timing of these activities or that they will ultimately result in the realization of proved reserves or meet our expectations for success. As such, our actual drilling and enhanced recovery activities may materially differ from our current expectations, which could have a significant adverse effect on our financial condition and results of operations.
Our drilling projects are based in part on seismic data, which cannot ensure the commercial success of the project.
Our decisions to purchase, explore, develop and exploit prospects or properties depend in part on data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often uncertain. Even when used and properly interpreted, seismic data and visualization techniques only assist geoscientists and geologists in identifying subsurface structures and hydrocarbon indicators. Seismic data do not enable an interpreter to conclusively determine whether hydrocarbons are present or producible economically. In addition, the use of seismic and other advanced technologies may require greater predrilling expenditures than other drilling strategies. Because of these factors, we could incur losses as a result of exploratory drilling expenditures. Poor results from drilling activities could have a material adverse effect on our future cash flows, ability to replace reserves and results of operations.
Reserve estimates depend on many assumptions that may turn out to be inaccurate and any material inaccuracies in the reserve estimates or underlying assumptions of our assets will materially affect the quantities and present value of those reserves.
Estimating oil and gas reserves is complex and inherently imprecise. It requires interpretation of the available technical data and making many assumptions about future conditions, including price and other economic factors. In preparing such estimates, projection of production rates, timing of development expenditures and available geological, geophysical, production and engineering data are analyzed. The extent, quality and reliability of these data can vary. This process also requires economic assumptions about matters such as oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. If our interpretations or assumptions used in arriving at our reserve estimates prove to be inaccurate, the amount of oil and gas that will ultimately be recovered may differ materially from the estimated quantities and net present value of reserves owned by us.

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A significant portion of our total estimated net proved reserves at December 31, 2009 were undeveloped, and those reserves may not ultimately be developed.
At December 31, 2009, approximately 84 percent of our total estimated net proved reserves were undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling. Our reserve data assumes that we can and will make these expenditures and conduct these operations successfully. These assumptions, however, may not prove correct. If we choose not to spend the capital to develop these reserves or if we are not otherwise able to successfully develop these reserves we may be required to write-off these reserves. Any such write-offs of our reserves could reduce our ability to borrow money and could reduce the value of our securities.
Our offshore operations involve special risks that could increase our cost of operations and adversely affect our ability to produce oil and gas.
Offshore operations are subject to a variety of operating risks specific to the marine environment, such as capsizing, collisions and damage or loss from hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production. As a result, we could incur substantial liabilities that could reduce or eliminate the funds available for exploration, development or leasehold acquisitions, or result in loss of equipment and properties. Offshore drilling in the North Sea generally requires more time and more advanced drilling technologies, involving a higher risk of technological failure and usually higher drilling costs. Moreover, offshore projects often lack proximity to the physical and oilfield service infrastructure, necessitating significant capital investment in subsea flow line infrastructure. Subsea tieback production systems require substantial time and the use of advanced and very sophisticated installation equipment supported by remotely operated vehicles. These operations may encounter mechanical difficulties and equipment failures that could result in significant cost overruns. As a result, a significant amount of time and capital must be invested before we can market the associated oil or gas, increasing both the financial and operational risk involved with these operations. Because of the lack and high cost of infrastructure, some offshore reserve discoveries may never be produced economically.
We have recently commenced exploration, production and development operations in the United States, and as a result, our ability to successfully achieve our goals is subject to greater risk and uncertainty.
In 2008, we began to pursue exploration, production and development activities in the U.S. Moreover, we did not have a significant U.S. presence in our assets and operations until late 2009. Because we have limited production history in this geographic region and do not have extensive experience in unconventional resource plays, we are less able to use past operational results to help predict future results. Our lack of operational experience in the U.S. may result in our not being able to fully execute our expected drilling programs in this region, and the return on investment from our United States operations may not be as attractive as expected. We cannot assure you that our efforts in the U.S. will be successful, or if successful will achieve the resource potential levels that we currently anticipate or achieve the anticipated economic returns based on our current financial models.

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We will not be the operator of all of the interests we own or acquire, and therefore we may not be in a position to control the timing of development efforts, the associated costs, or the rate of production of the reserves in respect of such interests.
A significant number of our interests, including all of our producing fields, are currently operated by third parties. As a result, we may have limited ability to exercise influence over the operations of these interests or their associated costs. Dependence on the operator and other working interest owners for these projects, and limited ability to influence operations and associated costs could prevent the realization of expected returns on capital in drilling or acquisition activities. The success and timing of development and exploitation activities on properties operated by others depend upon a number of factors that will be largely outside our control, including:
  the operator’s expertise and financial resources;
 
  the timing and amount of their capital expenditures;
 
  the rate of production of the reserves;
 
  approval of other participants to drill wells and implement other work programs;
 
  the availability of suitable drilling rigs, drilling equipment, support vessels, production and transportation infrastructure and qualified operating personnel; and
 
  selection of technology.
Our inability to control the development efforts, costs and timing on the interests where we are not the operator could have a material adverse effect on our financial conditions, results of operations and business prospects.
Actual production could differ significantly from forecasts.
From time to time we provide forecasts of expected quantities of future oil and gas production. These forecasts are based on a number of estimates, including expectations of production decline rates from existing wells and the outcome of future drilling activity. Should these estimates prove inaccurate, actual production could be adversely impacted. Downturns in commodity prices could make certain drilling activities or production uneconomical, which would also adversely impact production. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which are beyond our control.
Our insurance may not protect us against business and operating risks, including an operator of a prospect in which we participate failing to maintain or obtain adequate insurance.
Oil and gas operations are subject to particular hazards incident to the drilling and production of oil and gas, such as blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires and pollution and other environmental risks. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. We maintain insurance for some, but not

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all, of the potential risks and liabilities associated with our business. If a significant accident or other event resulting in damage to our operations, including severe weather, terrorist acts, war, civil disturbances, pollution or environmental damage, occurs and is not fully covered by insurance, it could adversely affect our financial condition and results of operations. We do not currently operate all of our oil and gas properties. In the projects in which we own non-operating interests, the operator may maintain insurance of various types to cover our operations with policy limits and retention liability customary in the industry. The occurrence of a significant adverse event that is not fully covered by insurance could result in the loss of our total investment in a particular prospect and additional liability for us, which could have a material adverse effect on our financial condition and results of operations and prospects.
The cost of decommissioning is uncertain.
We expect to incur obligations to abandon and decommission certain structures associated with our producing properties. To date, the industry has little experience of removing oil and gas structures from the North Sea. Few of the structures in the North Sea have been removed. Certain groups have been established to study issues relating to decommissioning and abandonment and how the costs will be borne. Because experience is limited, we cannot precisely predict the costs of any future decommissions for which we might become obligated. If actual decommission or abandonment costs exceed our estimates or reserves to satisfy such obligations, our financial condition, results of operations and prospects could be materially adversely affected.
Risks related to environmental and other regulations
We are subject to environmental regulations that can have a significant impact on our operations.
Our operations are subject to a variety of national, state, local and international laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Failure to comply with these laws and regulations can result in the imposition of substantial fines and penalties as well as potential orders suspending or terminating our rights to operate. Some environmental laws to which we are subject to provide for strict liability for pollution damages, rendering a person liable without regard to negligence or fault on the part of such person. In addition, we may be subject to claims alleging personal injury or property damage as a result of alleged exposure to hazardous substances such as oil and gas related products. Aquatic environments in which we operate are often particularly sensitive to environmental impacts, which may expose us to greater potential liability than that associated with exploration, development and production at many onshore locations.
Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly requirements for oil and gas exploration and production activities could require us, as well as others in our industry, to make significant expenditures to attain and maintain compliance which could have a corresponding material adverse effect on our competitive position, financial condition or results of operations. We cannot provide assurance that we will be able to comply with future laws and regulations to the same extent that we

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believe we have in the past. Similarly, we cannot always precisely predict the potential impact of environmental laws and regulations which may be adopted in the future, including whether any such laws or regulations would restrict our operations in any area.
Current and future environmental regulations, including restrictions on greenhouse gases due to concerns about climate change, could reduce the demand for our products. Our business, financial condition and results of operations could be materially and adversely affected if this were to occur.
Under certain environmental laws and regulations, we could be subject to liability arising out of the conduct of operations or conditions caused by others, or for activities that were in compliance with all applicable laws at the time they were performed. Such liabilities can be significant, and if imposed could have a material adverse effect on our financial condition or results of operations.
Governmental regulations to which we are subject could expose us to significant fines and/or penalties and our cost of compliance with such regulations could be substantial.
Oil and gas exploration, development and production are subject to various types of regulation by local, state and national agencies. Regulations and laws affecting the oil and gas industry are comprehensive and under constant review for amendment and expansion. These regulations and laws carry substantial penalties for failure to comply. The regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, adversely affects our profitability. In addition, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the governments and/or agencies thereof.
Federal legislation and state legislative regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affect our support services.
The U.S. Congress is currently considering two companions bills for the “Fracturing Responsibility and Awareness of Chemicals Act,” or “FRAC Act.” The bills would repeal an exemption in the federal Safe Drinking Water Act (“SWDA”) for the underground injection of hydraulic fracturing fluids near drinking water sources. Hydraulic fracturing is an important and commonly used process for the completion of natural gas, and to a lesser extent, oil wells in shale formations, and involves the pressurized injection of water, sand and chemicals into rock formations to stimulate natural gas production. Sponsors of the FRAC Act have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. If enacted, the FRAC Act could result in additional regulatory burdens such as permitting, construction, financial assurance, monitoring, recordkeeping, and plugging and abandonment requirements. The FRAC Act also proposes requiring the disclosure of chemical constituents used in the fracturing process to state or federal regulatory authorities, who would then make such information publicly available. The availability of this information could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect

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groundwater. In addition, various state and local governments are considering increased regulatory oversight of hydraulic fracturing through additional permit requirements, operational restrictions, and temporary or permanent bans on hydraulic fracturing in certain environmentally sensitive areas such as watersheds. The adoption of the FRAC Act or any other federal or state laws or regulations imposing reporting obligations on, or otherwise limiting, the hydraulic fracturing process could make it more difficult to complete natural gas wells in shale formations, increase our costs of compliance and doing business.
Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the crude oil and natural gas that we produce.
On December 15, 2009, the U.S. Environmental Protection Agency (“EPA”) published its findings that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings allow the EPA to adopt and implement regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. Accordingly, the EPA has proposed regulations that would require a reduction in emissions of greenhouse gases from motor vehicles and could trigger permit review for greenhouse gas emissions from certain stationary sources. In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the U.S. beginning in 2011 for emissions occurring in 2010. Also, on June 26, 2009, the U.S. House of Representatives passed the “American Clean Energy and Security Act of 2009,” or “ACESA,” which would establish an economy-wide cap-and-trade program to reduce U.S. emissions of greenhouse gases, including carbon dioxide and methane. ACESA would require a 17% reduction in greenhouse gas emissions from 2005 levels by 2020 and just over an 80% reduction of such emissions by 2050. Under this legislation, the EPA would issue a capped and steadily declining number of tradable emissions allowances authorizing emissions of greenhouse gases into the atmosphere. These reductions would be expected to cause the cost of allowances to escalate significantly over time. The net effect of ACESA will be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products, and natural gas. The U.S. Senate has begun work on its own legislation for restricting domestic greenhouse gas emissions and the Obama Administration has indicated its support for legislation to reduce greenhouse gas emissions through an emission allowance system. At the state level, more than one-third of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of greenhouse gases. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur costs to reduce emissions of greenhouse gases associated with our operations or could adversely affect demand for the crude oil and natural gas that we produce. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our assets and operations.

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The adoption of derivatives legislation by the U.S. Congress could have an adverse impact on our ability to hedge risks associated with our business.
The U.S. Congress is currently considering legislation to impose restrictions on certain transactions involving derivatives, which could affect the use of derivatives in hedging transactions. ACESA contains provisions that would prohibit private energy commodity derivative and hedging transactions. ACESA would expand the power of the Commodity Futures Trading Commission, or CFTC, to regulate derivative transactions related to energy commodities, including oil and natural gas, and to mandate clearance of such derivative contracts through registered derivative clearing organizations. Under ACESA, the CFTC’s expanded authority over energy derivatives would terminate upon the adoption of general legislation covering derivative regulatory reform. The CFTC is considering whether to set limits on trading and positions in commodities with finite supply, particularly energy commodities, such as crude oil, natural gas and other energy products. The CFTC also is evaluating whether position limits should be applied consistently across all markets and participants. Separately, the House of Representatives adopted financial regulatory reform legislation on December 11, 2009, that among other things would impose comprehensive regulation on the over-the-counter (OTC) derivatives marketplace. This legislation would subject swap dealers and “major swap participants” to substantial supervision and regulation, including capital standards, margin requirements, business conduct standards, recordkeeping and reporting requirements. It also would require central clearing for transactions entered into between swap dealers or major swap participants, and would provide the CFTC with authority to impose position limits in the OTC derivatives markets. A major swap participant generally would be someone other than a dealer who maintains a “substantial” net position in outstanding swaps, excluding swaps used for commercial hedging or for reducing or mitigating commercial risk, or whose positions create substantial net counterparty exposure that could have serious adverse effects on the financial stability of the U.S. banking system or financial markets. Although it is not possible at this time to predict whether or when Congress may act on derivatives legislation or how any climate change bill approved by the Senate would be reconciled with ACESA, any laws or regulations that may be adopted that subject us to additional capital or margin requirements relating to, or to additional restrictions on, our trading and commodity positions could have an adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activity.
Certain federal income tax deductions currently available with respect to oil and natural gas exploration and development may be eliminated as a result of future legislation.
President Obama’s Proposed Fiscal Year 2010 Budget includes proposed legislation that would, if enacted into law, make significant changes to U.S. tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether any such changes will be enacted or how soon any such changes could become effective. The passage of any legislation as a result of these

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proposals or any other similar changes in U.S. federal income tax laws could eliminate or otherwise limit certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could negatively impact our financial condition and results of operations.
Risks related to access to capital and financing
Our development and exploration operations, including our recent North Sea discoveries, require substantial capital, and we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our oil and gas reserves.
The oil and gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business and operations for the exploration, development, production and acquisition of oil and gas reserves, including expenditures relating to the development of our discoveries in the North Sea and our acreage position in the Haynesville Shale and other U.S. plays. We intend to finance our future capital expenditures primarily with cash flow from operations and borrowings under our senior bank facility. Our cash flow from operations and access to capital is subject to a number of variables, including:
    our proved reserves;
 
    the level of natural gas and crude oil we are able to produce from existing wells;
 
    the prices at which natural gas and crude oil are sold; and
 
    our ability to acquire, locate and produce new reserves.
If our revenues decrease as a result of lower oil and gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels or to further develop and exploit our current properties, or for exploratory activity. In order to fund our capital expenditures, we may need to seek additional financing. Our credit agreements contain covenants restricting our ability to incur additional indebtedness without the consent of the lenders. Our lenders may withhold this consent in their sole discretion. In addition, if our borrowing base is redetermined resulting in a lower borrowing base under our senior bank facility, we may be unable to obtain financing otherwise available under our senior bank facility.
Furthermore, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. In particular, the cost of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets generally has diminished significantly. Also, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity on terms that are similar to existing debt, and reduced, or in some cases ceased, to provide funding to borrowers. The failure to obtain additional financing could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could lead to

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a possible loss of properties and a decline in our natural gas, crude oil and natural gas liquids reserves.
Our debt level could negatively impact our financial condition, results of operations and business prospects.
As of December 31, 2009, we had $231.2 million in outstanding indebtedness. Our level of indebtedness could have important consequences on our operations, including
    placing restrictions on certain operating activities;
 
    making it more difficult for us to satisfy our obligations under our indentures or the terms of our other debt instruments and increasing the risk that we may default on our debt obligations;
 
    requiring us to dedicate a substantial portion of our cash flow from operating activities to required payments on debt, thereby reducing the availability of cash flow for working capital, capital expenditures and other general business activities;
 
    limiting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and other general business activities;
 
    decreasing our ability to withstand a downturn in our business or the economy generally; and
 
    placing us at a competitive disadvantage against other less leveraged competitors.
We may not have sufficient funds to repay our outstanding debt. If we are unable to repay our debt out of cash on hand, we could attempt to refinance such debt, sell assets or repay such debt with the proceeds from an equity offering. In addition, we cannot assure you that we will be able to generate sufficient cash flow from operating activities to pay the interest on our debt or that future borrowings, equity financings or proceeds from the sale of assets will be available to repay or refinance such debt. Factors that will affect our ability to raise cash through an offering of our capital stock, a refinancing of our debt or a sale of assets include financial market conditions, our market value, our reserve levels and our operating performance at the time of such offering or other financing. We cannot assure you that any such offering, refinancing or sale of assets can be successfully completed. The inability to repay or refinance our debt, could have a material adverse effect on our operations and negatively impact our capital program.
A change of control may adversely affect our liquidity and require refinancing of certain debt instruments.
At December 31, 2009, we had $231.2 million outstanding under our debt agreements. Upon specified change of control events, each lender under our debt agreements may cancel the facility and declare outstanding loans, plus accrued and unpaid interest, outstanding letters of credit and other outstanding fees, if any, due and payable. We cannot assure you we would have sufficient financial resources to purchase the notes for cash or repay the lenders under our Debt Agreements upon the occurrence of a change of control. If a change of control occurs, we may be required to refinance our indebtedness. There can be no assurance that we would be able to refinance our indebtedness or, if a refinancing were to occur, that the refinancing would be on terms favorable to us.

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If we are unable to fulfill commitments under any of our oil and gas interests, we will lose our interest, and our entire investment, in such interest.
Our ability to retain oil and gas interests will depend on our ability to fulfill the commitments made with respect to each interest. We cannot assure you that we or the other participants in the projects will have the financial ability to fund these potential commitments. If we are unable to fulfill commitments under any of our interests, we will lose our interest, and our entire investment, in such interest.
Risks relating to our common stock
The trading price of our common stock may be volatile.
Smaller capitalized companies like ours often experience substantial fluctuations in the trading price of their securities. The trading price of our common stock has fluctuated significantly and in the future may be subject to similar fluctuations. The trading price may be affected by a number of factors, including those set forth elsewhere herein, as well as our operating results, financial condition, announcements or drilling activities, general conditions in the oil and gas exploration and development industry, and other events or factors, some of which may be unrelated to our performance or prospects or to conditions in the industry as a whole.
If we, our existing stockholders or holders of our securities that are convertible into shares of our common stock sell additional shares of our common stock, the market price of our common stock could significantly decline.
The market price of our common stock could decline as a result of sales of a large number of shares of common stock in the public market or the perception that such sales could occur. These sales, or the possibility that these sales may occur, might make it more difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate.
As of March 12, 2010, we had approximately 160.2 million shares of common stock outstanding. Of those shares, approximately 5.0 million shares are restricted shares subject to vesting periods of up to three years. The remainder of these shares is freely tradable.
In addition, approximately 2.8 million shares are issuable upon the exercise of presently outstanding stock options under our employee incentive plans and 0.9 million shares are issuable upon the exercise of presently outstanding options and warrants outside our employee incentive plans. Also 16.2 million shares are issuable upon the conversion of our convertible senior notes due 2012 and 48.8 million shares are issuable upon conversion of our Series C Preferred Stock, based upon the conversion price of $1.25, and 21.5 million shares are issuable upon conversion of our 11.5% convertible bonds, based on a conversion price of $2.36.

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Provisions in our articles of incorporation, bylaws and the Nevada Revised Statutes may discourage a change of control.
Certain provisions of our amended and restated articles of incorporation and amended and restated bylaws and the Nevada Revised Statutes (“NRS”) could delay or make more difficult a change of control transaction or other business combination that may be beneficial to stockholders. These provisions include, but are not limited to, the ability of our board of directors to issue a series of preferred stock, classification of our board of directors into three classes and limiting the ability of our stockholders to call a special meeting.
We are subject to the “Combinations With Interested Stockholders Statute” and the “Control Share Acquisition Statute” of the NRS. The Combinations Statute provides that specified persons who, together with affiliates and associates, own, or within three years did own, 10% or more of the outstanding voting stock of a corporation cannot engage in specified business combinations with the corporation for a period of three years after the date on which the person became an interested stockholder, unless the combination or the transaction by which the person first became an interested stockholder is approved by the corporation’s board of directors before the person first became an interested stockholder.
The Control Share Acquisition Statute provides that persons who acquire a “controlling interest” as defined by the statute, in a company may only be given full voting rights in their shares if such rights are conferred by the stockholders of the company at an annual or special meeting. However, any stockholder that does not vote in favor of granting such voting rights is entitled to demand that the company pay fair value for their shares if the acquiring person has acquired at least a majority of all of the voting power of the company. As such, persons acquiring a controlling interest may not be able to vote their shares.
Risks related to potential impairments
Lower oil and gas prices and other factors resulted in a ceiling test write-down and may in the future result in additional ceiling test write-downs or other impairments.
We capitalize the costs to acquire, find and develop our oil and gas properties under the full cost accounting method. The net capitalized costs of our oil and gas properties may not exceed the present value of estimated future net cash flows from proved reserves, using period-end oil and gas prices and a 10% discount factor, plus the lower of cost or fair market value for unproved properties. If net capitalized costs of our oil and gas properties exceed this limit, we must charge the amount of the excess to earnings. This is called a “ceiling test write-down.” Although a ceiling test write-down does not impact cash flow from operating activities, it does reduce net income and our shareholders’ equity. Once recorded, a ceiling test write-down is not reversible at a later date even if oil and gas prices increase.
We review the net capitalized costs of our properties quarterly, based on prices in effect (excluding the effect of our hedging contracts that are not designated for hedge accounting) as of the end of each quarter or as of the time of reporting our results. The net capitalized costs of oil and gas properties are computed on a country-by-country basis. Therefore, while our properties

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in one country may be subject to a write-down, our properties in other countries could be unaffected. We also assess investments in unproved properties periodically to determine whether impairment has occurred.
The risk that we will be required to further write down the carrying value of our oil and gas properties increases when oil and gas prices are low or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves or our unproved property values, or if estimated future development costs increase. We may experience further ceiling test write-downs or other impairments in the future. In addition, any future ceiling test cushion would be subject to fluctuation as a result of acquisition or divestiture activity.
Our financial results could be adversely affected by goodwill impairments.
As a result of mergers, acquisitions and dispositions, at December 31, 2009 we had $211.9 million of goodwill on our balance sheet. Goodwill is not amortized, but instead must be tested at least annually for impairment by applying a fair-value-based test. Goodwill is deemed impaired to the extent that its carrying amount exceeds the fair value of the reporting unit. Although our latest tests indicate that no goodwill impairment is currently required, future deterioration in market conditions could lead to goodwill impairments that could have a substantial negative effect on our profitability.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
Drilling Statistics
A well is considered productive for purposes of the following table if it justifies the installation of permanent equipment for the production of oil or gas. The information contained in the table should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. The following table shows the results of the oil and gas wells in which we participated, drilled and tested during 2009, 2008 and 2007:

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    Productive Wells   Dry Holes   In Progress Wells
 
    Gross   Net   Gross   Net   Gross   Net
 
Exploration
                                               
2009:
                                               
United Kingdom
    3.00       0.82       2.00       0.52       1.00       0.10  
United States
    3.00       1.32       1.00       0.22       3.00       1.04  
 
                                               
2008:
                                               
United Kingdom
                            2.00       0.68  
United States
    1.00       0.20                   1.00       0.10  
Discontinued Operations — Norway
    5.00       0.14                          
 
                                               
2007:
                                               
United Kingdom
    2.00       0.50       3.00       0.75              
Discontinued Operations — Norway
    2.00       0.05       1.00       0.04              
 
                                               
Development
                                               
2009:
                                               
United Kingdom
    2.00       0.05                   1.00       0.02  
 
                                               
2008:
                                               
United Kingdom
                            1.00       0.02  
Discontinued Operations — Norway
    3.00       0.08                          
 
                                               
2007:
                                               
United Kingdom
    1.00       0.02                          
Discontinued Operations — Norway
    3.00       0.13       1.00       0.04              
We do not own any drilling rigs, and all of our drilling activities are conducted by independent drilling contractors.

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Productive Well Summary
At December 31, 2009, our productive wells included the following:
                                 
    Oil   Gas
 
    Gross   Net   Gross   Net
 
United Kingdom
    32.00       0.79       2.00       0.14  
United States
    2.00       1.12       25.00       7.16  
 
 
                               
Total
    34.00       1.91       27.00       7.30  
 
Acreage
The following table sets forth certain information regarding our developed and undeveloped acreage as of December 31, 2009, in the areas indicated.
                                 
    Developed   Undeveloped
 
    Gross   Net   Gross   Net
 
United Kingdom
    31,790       8,108       325,610       86,566  
United States
    39,360       11,690       427,518       102,342  
Ireland
                172,797       34,559  
 
 
                               
Total
    71,150       19,798       925,925       223,467  
 
As of December 31, 2009, we had approximately 34,559, 28,473 and no net acres that are scheduled to expire by December 31, 2010, 2011 and 2012, respectively, if we take no action to continue the term of the underlying license through operational or administrative actions. We currently have plans to continue the terms of various licenses through operational or administrative actions and do not expect a significant portion of our net acreage position to expire before such actions occur.
Sales Volumes and Prices
Information regarding our annual average sales volumes, sales prices and average production costs is contained in Item 7 of this Form 10-K. Additional detail of production costs is contained in Note 24 to our consolidated financial statements under Item 8 of this Form 10-K.
Reserves
Our estimates of proved reserves, proved developed reserves and proved undeveloped reserves at December 31, 2009, 2008 and 2007 and changes in proved reserves during the last three years

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are contained in Note 24 Note to our consolidated financial statements under Item 8 of this Form 10-K.
Item 3. Legal Proceedings
We are a party to various lawsuits, claims, and proceedings from time to time in the ordinary course of business. These proceedings are subject to uncertainties inherent in any litigation, and the outcome of these matters is inherently difficult to predict with any certainty. We believe that the amount of any potential loss associated with these proceedings would not be material to our consolidated financial position; however, in the event of an unfavorable outcome, the potential loss could have an adverse effect on our results of operations and cash flow in the reporting periods in which any such actions are resolved.
Part II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our common stock currently trades on the NYSE-Amex, formerly the American Stock Exchange, under the symbol “END” and on the London Stock Exchange under the symbol “ENDV.” The following table sets forth the range of high and low prices per share of our common stock for each of the calendar quarters identified below as reported by the NYSE-Amex. These quotations represent inter-dealer prices, without retail mark-up, markdown or commission, and may not represent actual transactions.
                                 
    2009   2008
 
    High   Low   High   Low
 
First Quarter
  $ 1.03     $ 0.46     $ 1.46     $ 1.13  
Second Quarter
    2.21       0.83       2.56       1.20  
Third Quarter
    1.50       1.02       2.30       1.01  
Fourth Quarter
    1.30       0.82       1.45       0.33  
 
Holders
As of March 12, 2010, the number of holders of record of our common stock was 222. We believe that there are a number of additional beneficial owners of our common stock who hold such shares in street name.

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Dividends
We have not paid any cash dividends on our common stock to date, and have no intention of declaring or paying any cash dividends on our common stock in the foreseeable future. Our Series B Preferred Stock is subject to a cumulative 8% dividend. Unless the full amount of the foregoing dividends accrued for the Series B Preferred Stock is paid in full, we cannot declare or pay any dividend on our common stock. In addition, our senior bank facility contains restrictions on the payment of dividends to the holders of our common stock. The declaration and payment of dividends is subject to the discretion of our Board of Directors and to certain limitations imposed under Nevada corporate laws. The timing, amount and form of dividends, if any, will depend on, among other things, our results of operations, financial condition, cash requirements and other factors deemed relevant by our Board of Directors.
In 2006, we issued the Series C Preferred Stock. Dividends on the Series C Preferred Stock are:
    cumulative;
 
    compounded quarterly based on the original issue price;
 
    payable in cash or common stock; and
 
    payable to the preferred stock investors prior to payment of any other dividend on any other shares of our capital stock.
In November 2009, we amended the terms of the Series C Preferred Stock in connection with a partial redemption. In connection with this transaction, the Series C Preferred Stock dividend rates were changed from 8.5% or 8.92% when payable in cash or common stock, respectively, to 4.5% or 4.92%, respectively. The Series C Preferred Stock continues to participate in any dividends paid on our common stock. We paid the Series C Preferred Stock dividends in common stock until the fourth quarter of 2007. Thereafter, we have paid the Series C Preferred Stock dividends in cash.
Item 6. Selected Financial Data
The following table sets forth some of our historical consolidated financial data. We completed the divestiture of our Norwegian subsidiary on May 14, 2009. The results of operations and financial position of this subsidiary are classified as discontinued operations for all periods presented.
The following data should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial Statements and Notes thereto included in “Item 8. Financial Statements and Supplementary Data.” The selected consolidated financial data provided below are not necessarily indicative of our future results of operations or financial performance.

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Endeavour International Corporation
                                         
Summary Financial Data(1)
    Year Ended December 31,
(Amounts in thousands, except per share data)   2009   2008   2007   2006   2005
 
Summary Income Statement Data:
                                       
Revenues
  $ 62,293     $ 170,781     $ 135,876     $ 24,881     $  
Operating Profit (Loss)
    (50,398 )     18,236       23,778       (11,516 )     (43,281 )
 
                                       
Net Income (Loss) to Common Shareholders
    (62,206 )     45,681       (60,315 )     (8,829 )     (31,531 )
 
                                       
Net Income (Loss) Per
                                       
Common Share — Basic:
                                       
Continuing Operations
  $ (0.84 )   $ 0.12     $ (0.50 )   $ (0.08 )   $ (0.50 )
Discontinued Operations
    0.36       0.24       0.01       (0.02 )     0.08  
 
Total
  $ (0.48 )   $ 0.36     $ (0.49 )   $ (0.10 )   $ (0.42 )
 
 
                                       
Net Income (Loss) Per Common Share — Diluted:
                                       
Continuing Operations
  $ (0.84 )   $ 0.15     $ (0.50 )   $ (0.08 )   $ (0.50 )
Discontinued Operations
    0.36       0.17       0.01       (0.02 )     0.08  
 
Total
  $ (0.48 )   $ 0.32     $ (0.49 )   $ (0.10 )   $ (0.42 )
 
 
                                       
Summary Balance Sheet Data:
                                       
Working Capital
  $ 24,885     $ 22,902     $ 37,198     $ 47,431     $ 49,638  
Total Assets
    538,879       737,470       747,623       774,470       186,966  
Debt
    223,385       227,855       266,250       306,250       81,250  
Convertible Preferred Stock
    59,058       125,000       125,000       125,000        
Equity
    60,133       117,971       70,149       116,828       40,344  
 
 
(1)   Includes the following:
    acquisition of producing properties and exploration acreage in the U.S. in 2009;
 
    acquisition of Talisman Expro Limited in November 2006;
 
    acquisition of working interests in the Enoch and Bacchus prospects in 2006;
 
    disposition of Thailand assets in 2005;
 
    acquisition of Norwegian assets in November 2004 and January 2005;
 
    disposition of non-core assets in 2004;
 
    acquisition of NSNV, Inc. in 2004; and
 
    unrealized gains (losses) on derivatives of $(55.6) million, $76.7 million, $(89.1) million and $34.5 million in 2009, 2008, 2007 and 2006, respectively.
Information regarding each of these transactions is included in the notes to the Consolidated Financial Statements included elsewhere in this report.

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Item 7.   Management’s Discussion and Analysis of Financial Condition and Results of Operations
This Management’s Discussion and Analysis of Financial Condition and Results of Operations and other parts of this Annual Report on Form 10-K contain forward-looking statements that involve risks and uncertainties. All forward-looking statements included in this Annual Report on Form 10-K are based on information available to us on the date hereof, and we assume no obligation to update any such forward-looking statements. Our actual results could differ materially from those anticipated in these forward-looking statements as a result of a number of factors, including those set forth in the section captioned “Risk Factors” in Item 1A and elsewhere in this Annual Report on Form 10-K. The following should be read in conjunction with the audited financial statements and the notes thereto included in “Item 8. Financial Statements and Supplementary Data.” 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 international oil and gas exploration and production company focused on the acquisition, exploration and development of energy reserves. Historically, we have focused our operations in the North Sea, but have recently expanded our focus to target unconventional U.S. onshore resource shale plays with shorter production-cycle times and compelling risk/return profiles.
On May 14, 2009, we completed the sale of our Norwegian subsidiary, Endeavour Energy Norge AS, to Verbundnetz Gas AG for cash consideration of $150 million (the “Norway Sale”). We recognized a gain upon closing the Norway Sale of $47.0 million, after the allocation of $68 million of goodwill to the assets sold. Proceeds from this sale enabled us to enter into a joint venture relationship with an established U.S. shale operator, providing us with acreage positions and production in the Haynesville and Marcellus Shales. We also entered into additional joint venture agreements with other selected operators, providing exposure to emerging shale plays in Alabama and Montana.
Our North Sea activities and assets represented the majority of our activity in 2007 and 2008,. Our major development projects – Bacchus, Columbus, Cygnus and Rochelle – have continued to move toward development with appraisal wells drilled at Cygnus and Rochelle in early 2009. Further appraisal drilling is planned for 2010 at Cygnus.
Our realized price per BOE, before derivatives, decreased from $71.70 per BOE in 2008 to $64.15 per BOE in 2009 largely as a result of lower gas prices in the U.K. Our realized price per BOE, before derivatives, increased 25% from 2007 to 2008 largely as a result of oil prices climbing to record levels in the summer of 2008 and gas prices in our markets improving. This substantial increase in prices in the first half of 2008 helped revenue grow from $135.9 million in

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2007 to $170.8 million in 2008. At December 31, 2009, we held $27.3 million in cash and another $2.9 million in restricted cash.
Even with the substantial growth in revenues, net income can be significantly affected by various non-cash items, such as unrealized gains and losses on our commodity derivatives, currency impact of long-term liabilities and deferred taxes. Cash flow provided by (used in) operations was $55.7 million in 2009 versus $133.2 million in 2008 and $128.5 million in 2007. Discretionary cash flow was $71.4 million in 2009 compared to $120.8 million in 2008 and $113.0 million in 2007.
Net loss to common stockholders was $62.2 million for 2009, representing $(0.48) per diluted share and reflecting significant unrealized losses on the mark-to-market of commodity derivatives and a non-cash preferred stock dividend upon the valuation of the redemption and modification of a portion of our preferred stock. Net income to common stockholders was $45.7 million for 2008, or $0.32 per diluted share. Net loss to common stockholders for 2007 was $60.3 million, or $0.49 per share, reflecting the significant unrealized loss on the mark-to-market of commodity derivatives.
Net income as adjusted for 2009 would have been $41.1 million without the effect of impairments, derivative transactions and currency impacts of deferred taxes. Net income as adjusted for 2008 would have been $16.5 million, as compared to net loss as adjusted of $0.3 million in 2007.
Given the significant impact that non-cash items may have on our net income, we use various measures in addition to net income, including non-financial performance indicators and non-GAAP measures as key metrics to manage our business. These key metrics demonstrate the company’s ability to maintain or grow production levels and reserves, internally fund capital expenditures and service debt as well as provide comparisons to other oil and gas exploration and production companies. These measures include, among others, debt and cash balances, production levels, oil and gas reserves, drilling results, discretionary cash flow, adjusted earnings before interest, taxes, depreciation, depletion and amortization (“Adjusted EBITDA”) and adjusted net income.
For definitions of Adjusted EBITDA and Discretionary Cash Flow, and a reconciliation of Adjusted EBITDA to net income as adjusted, please see “Reconciliation of Non-GAAP Accounting Measures.”
Results of Operations
Our revenues have increased significantly since 2006 primarily due to the following:
    Our Enoch field began first production in mid 2007 and each of 2009 and 2008 reflect a full year’s contribution of this asset.
 
    U.S. production reflects the results of our successful drilling of the Garwood well at the end of 2008 and the purchase of producing assets in October 2009.

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    In the first quarter of 2009, we suspended production at the IVRRH, Renee and Rubie fields due to high operating costs.
 
    Natural production declines at certain of our fields have not been offset by infield drilling resulting in production decreases at certain fields, particularly in 2009 at our largest gas field – Goldeneye.
 
    There was an increase in gas production from our discontinued operations at the end of 2007 with the completion of a gas project at Njord in the fourth quarter of 2007.
The following table shows our annual average sales volumes, sales prices and average production costs.

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Endeavour International Corporation
                         
    Year Ended December 31,
    2009   2008   2007
 
Sales volume (1)
                       
Oil and condensate sales (Mbbls):
                       
United Kingdom
    690       1,032       1,274  
United States
    4              
 
Continuing operations
    694       1,032       1,274  
Discontinued operations — Norway
    310       726       519  
 
Total
    1,004       1,758       1,793  
 
 
                       
Gas sales (MMcf):
                       
United Kingdom
    3,743       6,532       8,556  
United States
    320              
 
Continuing operations
    4,063       6,532       8,556  
Discontinued operations — Norway
    686       2,322       328  
 
Total
    4,749       8,854       8,884  
 
 
                       
Oil equivalent sales (MBOE)
                       
United Kingdom
    1,314       2,121       2,700  
United States
    58              
 
Continuing operations
    1,372       2,121       2,700  
Discontinued operations — Norway
    425       1,113       574  
 
Total
    1,797       3,234       3,274  
 
 
                       
Total BOE per day
    4,923       8,835       8,969  
 
 
                       
Physical production volume (BOE per day):
                       
United Kingdom
    3,669       5,804       7,660  
United States
    162              
 
Continuing operations
    3,831       5,804       7,660  
Discontinued operations — Norway
    1,156       3,033       1,608  
 
Total
    4,987       8,837       9,268  
 
 
                       
Realized Prices (2)
                       
Oil and condensate price ($  per Bbl):
                       
Before commodity derivatives
  $ 52.15     $ 90.53     $ 67.11  
Effect of commodity derivatives
    22.51       (14.50 )     (2.13 )
 
Realized prices including commodity derivatives
  $ 74.66     $ 76.03     $ 64.98  
 
 
                       
Gas price ($  per Mcf):
                       
Before commodity derivatives
  $ 5.77     $ 11.44     $ 6.27  
Effect of commodity derivatives
    2.69       (0.35 )     1.79  
 
Realized prices including commodity derivatives
  $ 8.46     $ 11.09     $ 8.06  
 
 
                       
Equivalent oil price ($  per BOE):
                       
Before commodity derivatives
  $ 44.44     $ 80.54     $ 53.78  
Effect of commodity derivatives
    19.71       (8.84 )     3.68  
 
Realized prices including commodity derivatives
  $ 64.15     $ 71.70     $ 57.46  
 
 
                       
Operating Costs ($  per BOE)
  $ 12.97     $ 14.40     $ 12.56  
 

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  (1)   We record oil revenues on the sales method, i.e. when delivery has occurred. Actual production may differ based on the timing of tanker liftings. We use the entitlements method to account for sales of gas production.
 
  (2)   The average sales prices reflect both our continuing and discontinued operations and include realized gains and losses for derivative contracts we utilize to manage price risk related to our future cash flows.
 
  (3)   Operating costs reflect both our continuing and discontinued operations and are costs incurred to operate and maintain our wells and related equipment and include cost of labor, well service and repair, location maintenance, power and fuel, transportation, cost of product and production related general and administrative costs.
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 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. Specifically, we sell a majority of our gas into the U.K. market, which is very sensitive to and impacted by tighter European gas supplies and gas deliveries from Russia. Therefore, the price for natural gas in the U.K. market is typically higher than the price for natural gas in other geographic regions and markets, including the U.S.
We utilize various oil and gas derivative instruments to achieve a more predictable cash flow by reducing our exposure to price fluctuations. Hedge accounting has not been elected for these instruments resulting in the application of mark-to-market accounting — effectively pulling forward into current periods the non-cash gains and losses from commodity price fluctuations relating to all future delivery periods. The derivative instruments cover a portion of our production through 2011. The significant volatility in commodity prices and the multi-year nature of the derivative instruments leads to large fluctuations in the fair market value of the derivative instruments at the end of each year. This non-cash change in the fair market value are recorded in unrealized gains (losses) on derivatives in the income statement. The realized prices above show the effect of the cash settlements for our derivative instruments each year. We expect to continue to have fluctuations in net earnings for the change in the fair market value each period as commodity prices fluctuate based on all remaining unsettled contracts. See Note 18 to the consolidated financial statements for additional information on these derivatives.

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Endeavour International Corporation
Operating Expenses
For 2009, operating expenses decreased to $17.8 million as compared to $32.3 million for 2008. Operating costs per BOE decreased to $12.97 per BOE for 2009 from $14.40 per BOE for 2008. In general, the changes in operating costs reflect the increase in fuel costs in 2008 at a non-operated facility which gathered the production from the IVRRH, Renee and Rubie and then the absence of those costs when we suspended production from those fields in 2009.
DD&A and Impairment of Oil and Gas Properties
Decreased depreciation, depletion and amortization (“DD&A”) expense from 2008 to 2009 reflects the impact of a decrease in production and the lower DD&A rates as a result of impairments in oil and gas properties in 2008 and earlier 2009. Decreased DD&A expense from 2007 to 2008 reflects the impact of a decrease in production from 2007 to 2008 partially offset by an increase in the DD&A rate.
In 2009, we recorded $43.9 million in impairment of oil and gas properties, pre-tax, through the application of the full cost ceiling test. At December 31, 2009, the prices used to determine the estimates of future cash inflows were $60.40 per Bbl for oil and $4.96 per Mcf for gas.
In 2008, we recorded $37.0 million in impairment of oil and gas properties, pre-tax, through the application of the full cost ceiling test at year-end. The prices used to determine the impairment were $36.55 per barrel for oil and $8.70 per Mcf for gas. While our commodity derivatives had a fair value of $31.0 million at December 31, 2008, these derivatives were not included in the calculation of the full cost ceiling test as the derivatives are not accounted for as cash flow hedges.
General and Administrative (“G&A”) Expenses
Our have only slightly increased since 2007 as we have been able to absorb a significant amount of our expanded operations without a corresponding increase in the number of employees. The increase in G&A expenses to $17.0 million for 2009 is a result of an increase in employee compensation and consulting fees associated with the additional staff to pursue our expanding development projects in the U.K. Much of this increase in staff costs was offset by recoveries from our partner on the development project we operate, Rochelle. Non-cash stock-based compensation decreased as a result of the final vesting of grants given in prior years, current year forfeitures and declining fair values on each year’s grants. Components of G&A expenses for these periods are as follows:

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Endeavour International Corporation
                         
    Year Ended December 31,
    2009   2008   2007
 
Compensation
  $ 14,659     $ 11,203     $ 10,181  
Consulting, legal and accounting fees
    5,118       4,679       5,045  
Occupancy costs
    982       1,130       994  
Other expenses
    1,364       4,004       2,352  
 
Total gross cash G&A expenses
    22,123       21,016       18,572  
 
                       
Non-cash stock-based compensation
    2,612       2,928       4,487  
 
Gross G&A expenses
    24,735       23,944       23,059  
Less: capitalized G & A expenses
    (7,769 )     (8,012 )     (7,206 )
 
Net G&A expenses
  $ 16,966     $ 15,932     $ 15,853  
 
Interest Expense and Other
The decrease in interest expense from $23.0 million in 2008 to $16.6 million in 2009 reflects the partial repayment of outstanding balances under our senior bank facility with a portion of the proceeds from the sale of our Norwegian operations. Interest expense increased to $23.0 million in 2008 primarily as a result of $4.3 million in expenses, including $2.1 million in cash, related to the early repayment of the second lien term loan.
Income Taxes
The following summarizes the components of tax expense (benefit):

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                            Total   Discontinued    
                            Continuing   Operations –    
(Amounts in thousands)   U.K.   U.S.   Other   Operations   Norway   Total
 
Year Ended December 31, 2009:
                                               
Net income (loss) before taxes
  $ (52,041 )   $ (31,167 )   $ (11,479 )   $ (94,687 )   $ 51,963     $ (42,724 )
 
                                               
Current tax (benefit) expense
    (5,739 )     40       (26 )     (5,725 )     (603 )     (6,328 )
Deferred tax (benefit) expense
    (20,260 )     (20 )     (35 )     (20,315 )     4,791       (15,524 )
Foreign currency losses on deferred tax liabilities
    18,882                   18,882       1,241       20,123  
 
Total tax (benefit) expense
    (7,117 )     20       (61 )     (7,158 )     5,429       (1,729 )
 
Net income (loss) after taxes
  $ (44,924 )   $ (31,187 )   $ (11,418 )   $ (87,529 )   $ 46,534     $ (40,995 )
 
 
                                               
Year Ended December 31, 2008:
                                               
Net income (loss) before taxes
  $ 66,129     $ (11,969 )   $ (4,185 )   $ 49,975     $ 63,244     $ 113,219  
 
                                               
Current tax expense
    11,158             10       11,168       27,879       39,047  
Deferred tax expense
    22,673             303       22,976       15,415       38,391  
Foreign currency gains on deferred tax liabilities
    (10,028 )                 (10,028 )     (10,681 )     (20,709 )
 
Total tax expense
    23,803             313       24,116       32,613       56,729  
 
Net income (loss) after taxes
  $ 42,326     $ (11,969 )   $ (4,498 )   $ 25,859     $ 30,631     $ 56,490  
 
 
                                               
Year Ended December 31, 2007:
                                               
Net income (loss) before taxes
  $ (68,704 )   $ (10,233 )   $ 6,584     $ (72,353 )   $ 14,095     $ (58,258 )
 
                                               
Current tax (benefit) expense
    2,898       (3 )     289       3,184       562       3,746  
Deferred tax (benefit) expense
    (27,430 )           711       (26,719 )     8,951       (17,768 )
Foreign currency losses on deferred tax liabilities
    1,327                   1,327       3,514       4,841  
 
Total tax (benefit) expense
    (23,205 )     (3 )     1,000       (22,208 )     13,027       (9,181 )
 
Net income (loss) after taxes
  $ (45,499 )   $ (10,230 )   $ 5,584     $ (50,145 )   $ 1,068     $ (49,077 )
 
Our income tax expense during the periods indicated relates primarily to our operations in the U.K. and our discontinued operations in Norway. Income taxes decreased in 2009 to a benefit of $7.2 million reflecting the decrease in revenues and the weakening of the U.S. dollar versus the U.K. pound. Income tax expense in 2008 represents the significant increase in revenues as a result of higher realized prices, the strengthening of the U.S. dollar versus the U.K. pound and the shift in anticipated capital expenditures from late 2008 to early 2009. During 2007, we incurred taxes in all of the jurisdictions in which we do business, except for the U.S.
At December 31, 2009, we had net operating loss carryforwards of $77.6 million in the U.S.
In 2009, 2008 and 2007, we have not recorded any income tax benefits in the U.S. as there was no assurance that we could generate any U.S. taxable earnings, resulting in a full valuation allowance of deferred tax assets generated.

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Endeavour International Corporation
Capital Program
We spent $88.6 million, $88.5 million and $87.9 million on our oil and gas capital program, excluding acquisitions, in 2009, 2008 and 2007, respectively. We spent $16.5 million in 2009 and $15 million to $20 million in both 2008 and 2007 on development activities at our producing properties. The remaining costs were spent on exploration and appraisal activities, including $11.4 million and $5.5 million in 2009 and 2008, respectively, related to our new operations in the U.S. Expenditures for 2009 also included $32.2 million for our acquisitions, primarily located in the U.S.
2009 Capital Resources
                 
    Year Ended December 31,
(Amounts in thousands)   2009   2008
 
Cash
  $ 27,287     $ 31,421  
Restricted Cash, related to rig commitments
  $ 2,879     $ 20,739  
Debt, including current maturities
  $ (223,385 )   $ (227,855 )
 
Debt, net of Cash
  $ (193,219 )   $ (175,695 )
 
                 
    Year Ended December 31,
    2009   2008
 
Net cash provided by operating activities
  $ 55,711     $ 133,180  
 
Net cash provided by (used in) investing activities
  $ 31,120     $ (64,851 )
 
Net cash used in financing activities
  $ (97,700 )   $ (46,613 )
 
Our primary sources of financial resources and liquidity are internally generated cash flows from operations and access to the credit and capital markets, to the extent available. During 2009, we principally relied on cash flow from operations and proceeds from our sale of Norwegian assets to fund our capital needs and repay a portion of outstanding debt and preferred stock. Going forward, we believe the combination of our available cash on hand, cash flow from operations and our ability to control capital expenditures will allow us to manage our business effectively while enabling us to further our strategic objectives.
Operating, Investing and Financing Activities include the net cash flows from our discontinued operations. For the years ended December 31, 2009, 2008, and 2007, our discontinued operations had net cash flows provided by (used in) operating activities of approximately $9.0 million, $38.8 million and $26.3 million, respectively. These net cash flows were substantially offset by net cash used by investing activities of approximately $9.0 million, $34.7 million and $25.5 million during 2009, 2008, and 2007, respectively.
Cash flow from operations decreased to $55.7 million for 2009 from $133.2 million for 2008 primarily due to lower realized commodity prices and lower sales volumes, particularly the reduction in gas sales as a result of production declines at Goldeneye.

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In addition to cash flows from operations, we have utilized issuances of debt and equity securities to enhance our liquidity and support the execution of our strategic objectives. Significant issuances and repayments of debt and equity, as well as the uses of the net proceeds, in 2009, 2008, and 2007 were as follows:
    repaid the outstanding balance of the second lien term loan in the first quarter of 2008;
 
    issued $40 million of the 11.5% convertible bonds in the first quarter of 2008;
 
    repaid $63.0 million of net debt in 2009; and
 
    repaid $75 million of the Series C Convertible Preferred Stock in the fourth quarter of 2009 with $25 million in cash and a $50 million note payable.
On November 17, 2009, we redeemed 60% of the outstanding shares of Series C Preferred Stock, for face value of $75 million, and amended the terms of the remaining shares of Series C Preferred Stock. The redemption price consisted of a $25 million cash payment and the issuance of $50 million Subordinated Notes.
The redemption and modification of the Series C Preferred Stock required the modified Series C Preferred Stock to be recorded at fair market value at the redemption date. As there was not a market observable price for the Series C Preferred Stock, we utilized a valuation approach to estimate the price that would be paid to transfer the Series C Preferred Stock in an orderly transaction between market participants. The fair value of the modified Series C Preferred Stock was greater than the carrying value by $11.5 million. This excess of fair value over carrying value was recorded as a non-cash charge to preferred stock dividends and increased the carrying value of the Series C Preferred Stock. As holders convert the Series C Preferred Stock, the $11.5 million non-cash charge will be transferred to equity on a ratio of shares converted to shares of Series C Preferred Stock outstanding.
In the November 2009 amendment, we amended terms of the Series C Preferred Stock to reduce the annual dividend rate to 4.5% (from 8.5%), adjust the conversion price to $1.25 per share (from $2.50) and remove certain anti-dilution provisions.
See Note 9 to the Consolidated Financial Statements for additional discussion of our debt.
Our future revenues and cash flows from operating activities will continue to be sensitive to changes in prices received for our products. Our production is sold at prevailing market prices which fluctuate in response to many factors that are outside of our control. Given the current tightly balanced supply-demand market, small variations in either supply or demand, or both, can have dramatic effects on prices we receive for our oil and natural gas production. While the market price received for oil and natural gas varies among geographic areas, oil trades in a worldwide market, whereas natural gas, which is still developing a global transportation system, is more subject to local supply and demand conditions. Consequently, price movements for all types and grades of crude oil generally move in the same direction.
Natural gas prices in the North Sea have been influenced by fuel prices around the world, including crude oil and coal. These prices are also impacted by European gas supplies,

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particularly deliveries from Russian gas supplies. In addition, regional supply and demand issues affect gas prices. The majority of our natural gas is sold in the U.K. market. Market prices for both oil and natural gas were at high levels throughout much of 2007 and 2008. North Sea gas prices declined in the first quarter of 2007 but recovered in the second half of the year and remained strong during 2008 and 2009.
Our cash flows will be significantly impacted by the amount of hydrocarbons we produce, the price we obtain for our produced commodities and taxes paid on operations. Oil prices continue to be impacted by supply and demand on a worldwide basis, while natural gas prices are more impacted by regional economic and weather patterns. Although oil and gas prices have remained volatile, the full impact on our cash flows will be partially mitigated by our balance of gas to oil production and our commodity derivative positions. As of December 31, 2009, our outstanding commodity derivatives covered 30% to 45% of expected 2010 production.
Recent Financing Arrangements
In February 2010, we issued 23.5 million shares of common stock in a private placement for aggregate net proceeds of $20.5 million. We also entered $25 million junior lending facility, with a maturity date of February 5, 2011, and interest at LIBOR plus 8%. Upon entering the new junior lending facility, we borrowed $15 million against the facility. The net proceeds from the private placement and the borrowing under the junior facility will be used to partially fund our 2010 capital budget.
Non-GAAP Measures
Net income can be significantly affected by various non-cash items, such as unrealized gains and losses on our commodity derivatives, currency impact of long-term liabilities and deferred taxes. Given the significant impact that non-cash items may have on our net income, we use various measures in addition to net income, including non-financial performance indicators and non-GAAP measures as key metrics to manage our business. These key metrics demonstrate the company’s ability to maintain or grow production levels and reserves, internally fund capital expenditures and service debt as well as provide comparisons to other oil and gas exploration and production companies. These measures include, among others, debt and cash balances, production levels, oil and gas reserves, drilling results, discretionary cash flow, adjusted earnings before interest, taxes, depreciation, depletion and amortization (“Adjusted EBITDA”) and adjusted net income.
Net Income (Loss) as Adjusted, Adjusted EBITDA and Discretionary Cash Flow are internal, supplemental measures of our performance that are not required by, or presented in accordance with, GAAP. We use these non-GAAP measures as internal measures of performance and to aid in our budgeting and forecasting processes. We view these non-GAAP measures, and we believe that others in the oil and gas industry view these, or similar, non-GAAP measures, as commonly used analytic indicators to compare performance among companies. We further believe that these non-GAAP measures are frequently used by securities analysts, investors, and other interested parties in the evaluation of issuers, many of which present these measures when reporting their results. We believe these non-GAAP measures provide useful information to both

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management and investors to gain an overall understanding of our current financial performance and provide investors with financial measures that most closely align to our internal measurement processes. Since the application of mark-to-market accounting has the effect of pulling forward into current periods non-cash gains and losses related to commodity derivatives relating to future delivery periods, analysis of results of operations from one period to another can be difficult. We believe that excluding these unrealized non-cash gains and losses related to commodity derivatives and currency exchange changes provides a more meaningful representation of our economic performance in the reporting period and is therefore useful to us, investors, analysts and others in facilitating the analysis of our results of operations from one period to another. These measures should not be considered as measures of financial performance under GAAP, and the items excluded from these measures are significant components in understanding and assessing financial performance.
These non-GAAP measures should not be considered in isolation or as an alternative to net income, operating income or any other performance measures derived in accordance with GAAP or as alternatives to cash flows generated by operating, investing or financing activities as a measure of our liquidity. Because Net Income (Loss) as Adjusted, Adjusted EBITDA and Discretionary Cash Flow are not measurements determined in accordance with GAAP and thus susceptible to varying calculations, Net Income (Loss) as Adjusted, Adjusted EBITDA and Discretionary Cash Flow as presented may not be comparable to other similarly titled measures of other companies.
Net Income (Loss) as Adjusted, Adjusted EBITDA and Discretionary Cash Flow have limitations as an analytical tool, and you should not consider these measures in isolation, or as a substitute for analysis of our financial statement data presented in the consolidated financial statements as reported under GAAP. For example, Net Income (Loss) as Adjusted, Adjusted EBITDA and Discretionary Cash Flow may not reflect:
    our cash expenditures, or future requirements, for capital expenditures or contractual commitments;
 
    changes in, or cash requirements for, our working capital needs;
 
    unrealized gains (losses) on derivatives;
 
    non-cash foreign currency gains (losses);
 
    our interest expense, or the cash requirements necessary to service interest and principal payments on our debts;
 
    our preferred stock dividend requirements; and
 
    depreciation, depletion and amortization.
Because of these limitations, Net Income (Loss) as Adjusted, Adjusted EBITDA and Discretionary Cash Flow should not be considered as measures of cash available to us to invest in the growth of our business. We compensate for these limitations by relying primarily on our GAAP results and by using Net Income (Loss) as Adjusted, Adjusted EBITDA and Discretionary Cash Flow only supplementally.

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As required under Regulation G of the Securities Exchange Act of 1934, provided below are reconciliations of net income (loss) to the following non-GAAP financial measures: Net Income (Loss) as Adjusted, Adjusted EBITDA and Discretionary Cash Flow.
                         
    Year Ended December 31,
    2009   2008   2007
 
Net income (loss)
  $ (40,995 )   $ 56,490     $ (49,077 )
 
                       
Depreciation, depletion and amortization
    38,701       81,734       76,850  
Impairment of oil and gas properties
    43,929       36,970        
Deferred tax expense (benefit)
    4,599       17,682       (12,925 )
Gain on asset sales
    (47,308 )            
Unrealized (gain) loss on derivatives
    55,598       (76,666 )     89,132  
Other
    16,835       4,597       8,994  
 
 
                       
Discretionary Cash Flow (1)
  $ 71,359     $ 120,807     $ 112,974  
 
 
                       
Net income (loss)
  $ (40,995 )   $ 56,490     $ (49,077 )
Impairment of oil and gas properties (net of tax) (2)
    28,263       18,485        
Unrealized (gain) loss on derivatives (net of tax) (3)
    33,702       (37,743 )     44,566  
Currency impact on deferred taxes
    20,123       (20,709 )     4,842  
 
 
                       
Net Income as Adjusted
  $ 41,093     $ 16,523     $ 331  
 
 
                       
Net income (loss)
  $ (40,995 )   $ 56,490     $ (49,077 )
 
                       
Unrealized (gain) loss on derivatives
    55,598       (76,666 )     89,132  
Net interest expense
    16,420       21,301       16,430  
Depreciation, depletion and amortization
    38,701       81,734       76,850  
Impairment of oil and gas properties
    43,929       36,970        
Income tax expense (benefit)
    (1,729 )     56,729       (9,180 )
Gain on asset sales
    (47,308 )            
 
 
                       
Adjusted EBITDA
  $ 64,616     $ 176,558     $ 124,155  
 
 
(1)   Discretionary cash flow is equal to cash flow from operating activities before the changes in operating assets and liabilities.
 
(2)   Net of tax benefits of $ (15,666) and $ (18,485) for 2009 and 2008, respectively.
 
(3)   Net of tax expense (benefit) of $ (21,896), $38,923 and (44,566), respectively.

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Outlook
2010 Planned Capital Expenditures
We anticipate spending approximately $90 million during 2010 to fund oil and gas activities in the U.S. and U.K. The majority of this amount is controllable by Endeavour. Our primary focus during 2010 in the U.S. will be in the Haynesville area as we believe this acreage contains near-term production potential. The ongoing U.S. program and expenditures will be tailored based on early drilling results. During 2010, we also expect to begin the evaluation program of our other U.S. assets in the Marcellus area and the two frontier plays in Alabama and Montana. Four U.K. wells have been or will be drilled in 2010; two Cygnus appraisal wells in the western portion of the field; the Deacon well that began in 2009 and finished in 2010, and the exploration well west of the Rochelle development. While this drilling is occurring, we expect to continue further our development programs at our four existing development projects, including ongoing engineering assessments for future production and commercial off-take solutions. We intend to fund these development activities through cash on hand, and cash flow generated from operations, as well as expansion of our credit facilities as needed.
The timing, completion and process of our 2010 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.
                         
Estimated Average Production (A)
                       
Daily Production (BOE per day)
    4,500     to     6,000  
 
                       
Differentials (B)
                       
Oil ($/Bbl)
  $ (5.00 )   to   $ (6.00 )
Gas ($Mcf)
  $ (0.50 )   to   $ (0.60 )
 
                       
Gas Percentage of Total
    55 %   to     60 %
Lease Operating Expense ($  per barrel)
  $ 8.00     to   $ 10.00  
 
(A)   Actual results may differ materially from these estimates.
 
(B)   For purposes of the estimates, assumptions of price differentials are based on location, quality and other factors, excluding the effects of derivative financial instruments. Gas price differentials are stated as premiums (discounts) from Henry Hub pricing, and oil price differentials are stated as premiums (discounts) from West Texas Intermediate pricing.
Liquidity and Financial Resources
Our primary sources of financial resources and liquidity are internally generated cash flows from operations and access to the credit and capital markets, to the extent available. We believe the

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combination of our available cash on hand, cash flow from operations and our ability to control capital expenditures will allow us to manage our business effectively while enabling us to further our strategic objectives.
Our cash flows will be significantly impacted by the amount of hydrocarbons we produce, the price we obtain for our produced commodities and taxes paid on operations. Oil prices continue to be impacted by supply and demand on a worldwide basis, while natural gas prices are more impacted by regional economic and weather patterns. Although oil and gas prices have remained volatile, the full impact on our cash flows will be partially mitigated by our balance of gas to oil production and our commodity derivative positions. As of December 31, 2009, our outstanding commodity derivatives covered 30% to 45% of expected 2010 production.
Our income tax expense relates primarily to our operations in the UK (statutory income tax rate of 50%). We are currently not able to record income tax benefits on our U.S. loss as there is no assurance that we can generate any U.S. taxable earnings. As operations expand in the U.S., we will be able to record income tax benefits in the U.S., however we do not anticipate paying current federal income taxes in the U.S. for quite some time.
In February 2010, we issued 23.5 million shares of common stock for an aggregate net proceeds of $20.5 million. We also entered into a $25 million junior lending facility, with a maturity date of February 5, 2011, and interest at LIBOR plus 8%. Upon entering the new junior lending facility, we borrowed $15 million against the facility. The net proceeds from these transactions will be used to partially fund our 2010 capital budget.
At December 31, 2009, we had $49.9 million outstanding under our senior bank facility. The senior bank facility has a current borrowing base capacity of $50 million, which is secured by our oil and gas assets. In February 2010, the maturity date of the senior bank facility was changed to January 31, 2011. We also have $50.1 million of Subordinated Notes that amortize over four years commencing in March 2011.
With the Junior Facility and Senior Bank Facility, we will have $65 million in debt due in the first quarter of 2011, based on outstanding balances at February 28, 2010. During 2010, we plan to utilize our existing U.K. oil and gas assets, as well as our growing U.S. reserve base, as a basis for refinancing and expansion of our credit facilities. We are currently in discussions with several parties concerning this process. We strive to synchronize our capital expenditures with our cash flow. However, we believe our existing U.K. reserves, including probable reserves, are of significant value and together with our U.S. assets can be used as support for increased financial resources when necessary to fund our on-going activities or refinance indebtedness. We continually monitor the capital markets to evaluate the most appropriate actions to fund our activities.
On March 15, 2010, we announced that our board of directors has approved a review of strategic alternatives for its North Sea assets. In an effort to unlock the value of our underlying North Sea assets, we will study a full range of options, including:
    Continuing to execute current operations plan;

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    Entering into a joint venture to accelerate activities in the North Sea; and
    Selling specific assets or the North Sea entire business.
We will announce the results of the effort once a course of action is chosen. At the end of this review process, we may elect to make no changes.
Disclosures about Contractual Obligations and Commercial Commitments
The following table sets forth our obligations and commitments to make future payments under its lease agreements and other long-term obligations as of December 31, 2009:
                                         
    Payments due by Period
            Less            
            than 1   1-3   3-5   After 5
(Amounts in thousands)   Total   Year   Years   Years   Years
 
Long-term debt
                                       
Principal
  $ 231,152     $     $ 161,192     $ 69,960     $  
Interest (1)
    56,962       11,323       13,728       31,911        
Asset retirement obligations
    47,362       3,249       51             44,062  
Operating leases for office leases and equipment
    1,073       638       393       42        
Rig commitments (2)
    17,055       17,055                    
 
 
                                       
Total Contractual Obligations
  $ 353,604     $ 32,265     $ 175,364     $ 101,913     $ 44,062  
 
 
(1)   Assumes a 1.5% LIBOR rate. In addition, interest on our 11.5% convertible debt and $50 million note is added to the outstanding principal balance each quarter and reflected as due upon maturity.
 
(2)   As is common in the oil and gas industry, we operate in many instances through joint ventures under joint operating or similar agreements. Typically, the operator under a joint operating agreement enters into contracts, such as rig commitment contracts, for the benefit of all joint venture partners. Through the joint operating agreement, the non-operators reimburse, and in some cases advance, the funds necessary to meet the contractual obligations entered into by the operator. These obligations are typically shared on a “working interest” basis. The joint operating agreement provides remedies to the operator in the event that the non-operator does not satisfy its share of the contractual obligations. Occasionally, the operator is permitted by the joint operating agreement to enter into lease obligations and other contractual commitments that are then passed on to the non-operating joint interest owners as lease operating expenses, frequently without any identification as to the long-term nature of any commitments underlying such expenses. Once the timing for rig delivery and the specific well to be drilled are determined, this obligation will be shared with the other working interest owners.
Off-Balance Sheet Arrangements
At December 31, 2010, we did not have any off-balance sheet arrangements.

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Rig Commitments
Our rig commitments represent one commitment for 46 days of a rig in the U.K. We are currently considering the timing of rig deliverability and completion of the commitment.
Critical Accounting Policies and Estimates
The accompanying financial statements have been prepared on the accrual basis of accounting in accordance with accounting principles generally accepted in the United States of America and have been presented on a going concern basis, which contemplates the realization of assets and satisfaction of liabilities in the normal course of business. These accounting principles require management to use estimates, judgments and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements, and revenues and expenses during the reporting period. Management reviews its estimates, including those related to the determination of proved reserves, estimates of future dismantlement costs, income taxes and litigation. Actual results could differ from those estimates.
Management believes it is reasonably possible that the following material estimates affecting the financial statements could change in the coming year: (1) estimates of proved oil and gas reserves, (2) estimates as to the expected future cash flow from proved oil and gas properties, (3) estimates of future dismantlement and restoration costs, (4) estimates of fair values used in purchase accounting and (5) estimates of the fair value of derivative instruments. In addition, alternatives may exist among various accounting methods. In such cases, the choice of accounting method may also have a significant impact on reported amounts.
Our critical accounting policies are as follows:
Full Cost Accounting
Under the full cost method, all acquisition, exploration and development costs, including certain directly related employee costs and a portion of interest expense, incurred for the purpose of finding oil and gas are capitalized and accumulated in pools on a country-by-country basis. Capitalized costs include the cost of drilling and equipping productive wells, including the estimated costs of dismantling and abandoning these assets, dry hole costs, lease acquisition costs, seismic and other geological and geophysical costs, delay rentals and costs related to such activities. Employee costs associated with production and other operating activities and general corporate activities are expensed in the period incurred.
Capitalized costs are limited on a country-by-country basis (the ceiling test). The ceiling test limitation is calculated as the sum of the present value of future net cash flows related to estimated production of proved reserves, using the average, first-day-of-the-month price during the 12-month period before the end of the year for 2009 and the year-end price for 2008 and 2007, including the effect of derivative instruments that qualify as cash flow hedges, discounted at 10%, plus the lower of cost or estimated fair value of unproved properties, all net of expected

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income tax effects. Under the ceiling test, if the capitalized cost of the full cost pool, net of deferred taxes, exceeds the ceiling limitation, the excess is charged as an impairment expense.
We utilize a single cost center for each country where we have operations for amortization purposes. Any conveyances of properties are treated as adjustments to the cost of oil and gas properties with no gain or loss recognized unless the operations are suspended in the entire cost center or the conveyance is significant in nature.
Unproved property costs include the costs associated with unevaluated properties and properties under development and are not included in the full cost amortization base (where proved reserves exist) until the project is evaluated. These costs include unproved leasehold acreage, seismic data, wells and production facilities in progress and wells pending determination, together with interest costs capitalized for these projects. Seismic data costs are associated with specific unevaluated properties where the seismic data is acquired for the purpose of evaluating acreage or trends covered by a leasehold interest owned by us. Significant unproved properties are assessed periodically for possible impairment or reduction in value. If a reduction in value has occurred, these property costs are considered impaired and are transferred to the related full cost pool. Geological and geophysical costs included in unproved properties are transferred to the full cost amortization base along with the associated leasehold costs on a specific project basis. Costs associated with wells in progress and wells pending determination are transferred to the amortization base once a determination is made whether or not proved reserves can be assigned to the property. Costs of dry holes are transferred to the amortization base immediately upon determination that the well is unsuccessful. Unproved properties whose acquisition costs are not individually significant are aggregated, the portion of such costs estimated to be ultimately nonproductive, based on experience, are amortized to the full cost pool over an average holding period.
In countries where the existence of proved reserves has not yet been determined, unevaluated property costs remain capitalized in unproved property cost centers until proved reserves have been established, exploration activities cease or impairment and reduction in value occurs. If exploration activities result in the establishment of a proved reserve base, amounts in the unproved property cost center are reclassified as proved properties and become subject to amortization and the application of the ceiling test. When it is determined that the value of unproved property costs have been permanently diminished (in part or in whole) based on the impairment evaluation and future exploration plans, the unproved property cost centers related to the area of interest are impaired, and accumulated costs charged against earnings.
We capitalize interest on expenditures for significant exploration and development projects while activities are in progress to bring the assets to their intended use. Capitalized interest is calculated by multiplying our weighted-average interest rate on debt by the amount of qualifying costs and is limited to gross interest expense. As costs are transferred to the full cost pool, the associated capitalized interest is also transferred to the full cost pool.

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Business Combinations
Assets and liabilities acquired through a business combination are recorded at estimated fair value. We use all available information to make these fair value determinations, including information commonly considered by our engineers in valuing individual oil and gas properties and sales prices for similar assets. Estimated deferred taxes are based on available information concerning the tax basis of the acquired company’s assets and liabilities and carryforwards at the merger date.
Any excess of the acquisition cost of the acquired business over the fair value amounts assigned to assets and liabilities is recorded as goodwill. Any excess of the amounts assigned to assets and liabilities over the acquisition of the acquired business is recorded as a gain on acquisition on the income statement. The amount of goodwill recorded in any particular business combination can vary significantly depending upon the fair values attributed to assets acquired and liabilities assumed relative to the total acquisition cost.
Goodwill and Intangible Assets
Goodwill represents the excess of the purchase price over the estimated fair value of the assets acquired and liabilities assumed in an acquisition. Intangible assets represent the purchase price allocation to the assembled workforce as a result of the acquisition of NSNV, Inc. We assess the carrying amount of goodwill and other indefinite-lived intangible assets by testing the asset for impairment annually at year-end, or more frequently if events or changes in circumstances indicate that the asset might be impaired. The impairment test requires allocating goodwill and all other assets and liabilities to reporting units. The fair value of each reporting unit is determined and compared to the book value of the reporting unit. An impairment loss is recognized to the extent that the carrying amount exceeds the asset’s fair value.
At December 31, 2009, we had $211.9 million of goodwill recorded related to past business combinations. This goodwill is not amortized, but is required to be assessed for impairment annually, or more often as facts and circumstances warrant. The first step of that process is to compare the fair value of the reporting unit to which goodwill has been assigned to the carrying amount of the associated net assets and goodwill. The reporting units used to evaluate and measure goodwill for impairment are determined from the manner in which the business is managed. We have determined we have a single reporting unit. Goodwill is tested annually at year end. Although we cannot predict when or if goodwill will be impaired, impairment charges may occur if we are unable to replace the value of our depleting asset base or if other adverse events (for example, lower sustained oil and gas prices) reduce the fair value of the reporting unit.
We completed our 2009 annual goodwill impairment test with no impairment indicated as the estimated fair value of our reporting unit was substantially greater than its book value. We considered our market capitalization based on average stock prices for 20 days before December 31, 2009.

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A lower fair value estimate in the future could result in impairment. Examples of factors that could cause a lower fair value estimate could be sustained declines in prices, increases in costs, and changes in discount rate assumptions due to market conditions.
Dismantlement, Restoration and Environmental Costs
We recognize liabilities for asset retirement obligations associated with tangible long-lived assets, such as producing well sites, offshore production platforms, and natural gas processing plants, with a corresponding increase in the related long-lived asset. The asset retirement cost is depreciated along with the property and equipment in the full cost pool. The asset retirement obligation is recorded at fair value and accretion expense, recognized over the life of the property, increases the liability to its expected settlement value. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded for both the asset retirement obligation and the asset retirement cost.
Revenue Recognition
We use the entitlements method to account for sales of gas production. We may receive more or less than our entitled share of production. Under the entitlements method, if we receive more than our entitled share of production, the imbalance is treated as a liability at the market price at the time the imbalance occurred. If we receive less than our entitled share, the imbalance is recorded as an asset at the lower of the current market price or the market price at the time the imbalance occurred. Oil revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred, title has transferred and collectability of the revenue is probable.
Derivative Instruments and Hedging Activities
From time to time, we may utilize derivative financial instruments to hedge cash flows from operations or to hedge the fair value of financial instruments. We may use derivative financial instruments with respect to a portion of our oil and gas production or a portion of our variable rate debt to achieve a more predictable cash flow by reducing our exposure to price fluctuations. These transactions are likely to be swaps, collars or options and to be entered into with major financial institutions or commodities trading institutions. Derivative financial instruments are intended to reduce our exposure to declines in the market prices of crude oil and natural gas that we produce and sell, to increases in interest rates and to manage cash flows in support of our annual capital expenditure budget. We also have embedded derivatives related to our debt instruments and convertible preferred stock.
We record all derivatives at fair market value in our Consolidated Balance Sheets at the end of each period. The accounting for the fair market value, and the changes from period to period, depends on the intended use of the derivative and the resulting designation. This evaluation is determined at each derivative’s inception and begins with the decision to account for the derivative as a hedge, if applicable. The accounting for changes in the fair value of a derivative

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instrument that is not accounted for as a hedge is included in other (income) expense as an unrealized gain or loss. Where we intend to account for a derivative as a hedge, we document, at its inception, the hedging relationship, the risk management objective and the strategy for undertaking the hedge. The documentation includes the identification of the hedging instrument, the hedged item or transaction, the nature of the risk being hedged, and the method that will be used to assess effectiveness of derivative instruments that receive hedge accounting treatment.
Changes in fair value to hedge instruments, to the extent the hedge is effective, are recognized in other comprehensive income until the forecasted transaction occurs. Hedge effectiveness is assessed at least quarterly based on total changes in the derivative’s fair value. Any ineffective portion of the derivative instrument’s change in fair value is recognized immediately in other (income) expense.
We discontinue hedge accounting prospectively when (1) we determine that the derivative is no longer effective in offsetting changes in the fair value or cash flows of a hedged item (including hedged items such as firm commitments or forecasted transactions); (2) the derivative expires; (3) it is no longer probable that the forecasted transaction will occur; (4) a hedged firm commitment no longer meets the definition of a firm commitment; or (5) management determines that designating the derivative as a hedging instrument is no longer appropriate.
Income Taxes
We use the liability method of accounting for income taxes under which deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities, and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized as part of the provision for income taxes in the period that includes the enactment date. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion of, or all of, the deferred tax assets will not be realized.
Stock-Based Compensation Arrangements
We recognize all share-based payments to employees, including grants of employee stock options, based on their fair values. The share-based compensation cost is measured at the grant date, based on the calculated fair value of the award, and is recognized as general and administrative expense over the employee’s requisite service period (generally the vesting period of the equity award). We apply the fair value method in accounting for stock option grants to non-employees using the Black-Scholes Method.
It is our policy to use authorized but unissued shares of stock when stock options are exercised. At December 31,2009, we had approximately 7.0 million additional shares available for issuance pursuant to our existing stock incentive plan.

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Endeavour International Corporation
Fair Value
We estimate fair value for the measurement of derivatives, long-lived assets during certain impairment tests, reporting units for goodwill impairment testing, the initial measurement of an asset retirement obligation and the initial measurement of our Series C Preferred Stock upon its redemption and modification. When we are required to measure fair value, and there is not a market observable price for the asset or liability, or a market observable price for a similar asset or liability, we generally utilize an income valuation approach. This approach utilizes management’s best assumptions regarding expectations of projected cash flows, and discounts the expected cash flows using a commensurate risk adjusted discount rate. Such evaluations involve a significant amount of judgment since the results are based on expected future events or conditions, such as sales prices; estimates of future oil and gas production; development and operating costs and the timing thereof; economic and regulatory climates and other factors. Our estimates of future net cash flows are inherently imprecise because they reflect management’s expectation of future conditions that are often outside of management’s control. However, assumptions used reflect a market participant’s view of long-term prices, costs and other factors, and are consistent with assumptions used in our business plans and investment decisions.
Item 7A.   Quantitative and Qualitative Disclosures About Market Risk
Foreign Exchange Risk
The international scope of our business operations exposes us to the risk of fluctuations in foreign currency markets. As a result, we are subject to foreign currency exchange rate risk due to effects that foreign exchange rate movements have on our costs and on the cash flows that we receive from foreign operations. Our oil revenues are received in U.S. dollars while gas revenues in the U.K. are received in pounds sterling. Capital expenditures, payroll and operating expenses may be denominated in U.S. dollars or pounds sterling. We operate a centralized currency management operation to take advantage of potential opportunities to naturally offset exposures against each other. To date, we have addressed our foreign currency exchange rate risks principally by maintaining our liquid assets in interest-bearing accounts, until payments in foreign currency are required. We have not reduced this risk by hedging to date as the timing expenditures in pounds sterling has been predictable and we have been able to match revenues received in pounds sterling and foreign currency purchases to minimize our exposure to foreign currency exchange rate 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 which 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

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Endeavour International Corporation
may engage in oil and gas hedging activities to realize commodity prices which we consider favorable.
At December 31, 2009, we had the following commodity derivative instruments outstanding:
                         
    2010   2011   Total
 
Oil:
                       
Fixed Price Swaps (Mbbl)
    533       487       1,020  
Weighted Average Price ($/Barrel)
  $ 68.39     $ 66.01     $ 67.25  
 
                       
Gas: (1)
                       
Fixed Price Swaps (MMcf)
    1,032       627       1,659  
Weighted Average Price ($/Mcf)
  $ 8.68     $ 8.32     $ 8.54  
 
(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 December 31, 2009 was $1.62 to £1.00.
At December 31, 2009 and 2008, the prices used to determine the estimates of future cash inflows were $60.40 and $36.55 per barrel, respectively, for oil and $4.96 and $8.70 per Mcf, respectively, for gas. The fair value of our commodity derivatives was $12.8 million at December 31, 2009.
Interest Rate Risk
We are exposed to changes in interest rates. Changes in interest rates affect the interest earned on cash and cash equivalents and the interest rate paid on certain borrowings under debt. A 250 point change in basis points on LIBOR would not result in a material change in our annual interest expense, given our floating rate debt at December 31, 2009.

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Endeavour International Corporation
Item 8.   Financial Statements and Supplementary Data
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Endeavour International Corporation:
We have audited the accompanying consolidated balance sheets of Endeavour International Corporation and subsidiaries as of December 31, 2009 and 2008, and the related consolidated statements of operations, stockholders’ equity and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2009. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Endeavour International Corporation and subsidiaries as of December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles.
As discussed in note 2 to the consolidated financial statements, effective January 1, 2008, the Company changed its method of accounting and disclosures for fair value measurements and fair value reporting of financial assets and liabilities. Also as discussed in note 2 to the consolidated financial statements, effective December 31, 2009, the Company has changed it reserve estimates and related disclosures as a result of adopting new oil and gas reserve estimation and disclosure requirements.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Endeavour International Corporation’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 16, 2010 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
/S/ KPMG LLP
Houston, Texas
March 16, 2010

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Endeavour International Corporation
Consolidated Balance Sheets

(Amounts in thousands)
                 
    December 31,
    2009   2008
 
Assets
               
Current Assets:
               
Cash and cash equivalents
  $ 27,287     $ 31,421  
Restricted cash
    2,879       20,739  
Accounts receivable
    14,800       22,325  
Prepaid expenses and other current assets
    10,118       42,194  
Current assets of discontinued operations
          16,726  
 
Total Current Assets
    55,084       133,405  
 
               
Property and Equipment, Net
    266,587       232,346  
Goodwill
    211,886       213,949  
Other Assets
    5,322       9,165  
Long Term Assets of Discontinued Operations
          148,605  
 
 
               
Total Assets
  $ 538,879     $ 737,470  
 
See accompanying notes to condensed consolidated financial statements.

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Endeavour International Corporation
Consolidated Balance Sheets

(Amounts in thousands)
                 
    December 31,
    2009   2008
 
Liabilities and Stockholders’ Equity
               
Current Liabilities:
               
Accounts payable
  $ 12,401     $ 38,630  
Current maturities of debt
          13,000  
Accrued expenses and other
    17,798       36,642  
Current liabilities of discontinued operations
          22,231  
 
Total Current Liabilities
    30,199       110,503  
 
               
Long-Term Debt
    223,385       214,855  
Deferred Taxes
    80,692       67,299  
Other Liabilities
    85,412       55,791  
Long-term Liabilities of Discontinued Operations
          46,051  
 
Total Liabilities
    419,688       494,499  
 
               
Commitments and Contingencies
               
 
               
Series C Convertible Preferred Stock:
               
Face value (liquidation preference)
    50,000       125,000  
Net non-cash premiums under fair value accounting on redemption
    9,058        
 
Total Series C Convertible Preferred Stock
    59,058       125,000  
 
               
Stockholders’ Equity:
               
Series B preferred stock (Liquidation preference: $3,115 and $2,983 at 2009 and 2008, respectively)
           
Common stock; shares issued and outstanding - 131,618 and 128,572 shares at 2009 and 2008, respectively
    132       129  
Additional paid-in capital
    247,707       244,471  
Treasury stock, at cost (498 and 327 shares at 2009 and 2008), respectively
    (587 )     (450 )
Accumulated other comprehensive loss
          (1,266 )
Accumulated deficit
    (187,119 )     (124,913 )
 
Total Stockholders’ Equity
    60,133       117,971  
 
 
               
Total Liabilities and Stockholders’ Equity
  $ 538,879     $ 737,470  
 
See accompanying notes to condensed consolidated financial statements.

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Endeavour International Corporation
Consolidated Statement of Operations

(Amounts in thousands, except per share data)
                         
    Year Ended December 31,
    2009   2008   2007
 
Revenues
  $ 62,293     $ 170,781     $ 135,876  
 
                       
Cost of Operations:
                       
Operating expenses
    17,776       32,317       27,263  
Depreciation, depletion and amortization
    34,020       67,326       68,982  
Impairment of oil and gas properties
    43,929       36,970        
General and administrative
    16,966       15,932       15,853  
 
Total Expenses
    112,691       152,545       112,098  
 
Income (Loss) From Operations
    (50,398 )     18,236       23,778  
 
 
                       
Other Income (Expense):
                       
Derivatives:
                       
Realized gains (losses)
    35,422       (28,578 )     12,048  
Unrealized gains (losses)
    (55,598 )     76,666       (89,132 )
Interest expense
    (16,630 )     (22,975 )     (19,282 )
Interest income and other
    (7,483 )     6,626       235  
 
Total Other Income (Expense)
    (44,289 )     31,739       (96,131 )
 
 
                       
Income (Loss) Before Income Taxes
    (94,687 )     49,975       (72,353 )
Income Tax Expense (Benefit)
    (7,158 )     24,116       (22,208 )
 
Income (Loss) from Continuing Operations
    (87,529 )     25,859       (50,145 )
 
                       
Discontinued Operations, net of tax:
                       
Income (loss) from operations
    (774 )     30,631       1,068  
Gain on sale
    47,308              
 
Income from Discontinued Operations
    46,534       30,631       1,068  
 
 
                       
Net Income (Loss)
    (40,995 )     56,490       (49,077 )
 
                       
Preferred Stock Dividends:
                       
Dividends declared
    9,757       10,809       11,238  
Non-cash charge under fair value accounting upon redemption
    11,454              
 
Total Preferred Stock Dividends
    21,211       10,809       11,238  
 
 
                       
Net Income (Loss) to Common Stockholders
  $ (62,206 )   $ 45,681     $ (60,315 )
 
 
                       
Basic Net Income (Loss) per Common Share:
                       
Continuing operations
  $ (0.84 )   $ 0.12     $ (0.50 )
Discontinued operations
    0.36       0.24       0.01  
 
Total
  $ (0.48 )   $ 0.36     $ (0.49 )
 
 
                       
Diluted Net Income (Loss) per Common Share:
                       
Continuing operations
  $ (0.84 )   $ 0.15     $ (0.50 )
Discontinued operations
    0.36       0.17       0.01  
 
Total
  $ (0.48 )   $ 0.32     $ (0.49 )
 
 
                       
Weighted Average Number of Common Shares Outstanding:
                       
Basic
    130,291       128,312       123,118  
 
Diluted
    130,291       178,312       123,118  
 
See accompanying notes to condensed consolidated financial statements.

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Endeavour International Corporation
Consolidated Statement of Cash Flows

(Amounts in thousands)
                         
    Year Ended December 31,
    2009   2008   2007
Cash Flows from Operating Activities:
                       
Net income (loss)
  $ (40,995 )   $ 56,490     $ (49,077 )
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
                       
Depreciation, depletion and amortization
    38,701       81,734       76,850  
Impairment of oil and gas properties
    43,929       36,970        
Deferred tax expense (benefit)
    4,599       17,682       (12,925 )
Unrealized (gains) losses on derivatives
    55,598       (76,666 )     89,132  
Gain on sale of Norwegian operations
    (47,308 )            
Other
    16,835       4,597       8,994  
Changes in operating assets and liabilities:
                       
Decrease in receivables
    3,978       9,795       30,127  
(Increase) decrease in other current assets
    7,489       (3,745 )     (984 )
Increase (decrease) in liabilities
    (27,115 )     6,323       (13,611 )
 
Net Cash Provided by Operating Activities
    55,711       133,180       128,506  
 
                       
Cash Flows From Investing Activities:
                       
Capital expenditures
    (131,393 )     (66,370 )     (88,007 )
Proceeds from sales, net of cash
    144,653       259        
(Increase) decrease in restricted cash
    17,860       1,260       (20,133 )
 
 
Net Cash Provided by (Used in) Investing Activities
    31,120       (64,851 )     (108,140 )
 
                       
Cash Flows From Financing Activities:
                       
 
Repayments of borrowings
    (64,458 )     (120,000 )     (47,000 )
Borrowings under debt agreements
    1,400       88,000       7,000  
Redemption of preferred stock
    (25,000 )            
Dividends paid
    (9,625 )     (10,625 )     (2,656 )
Financing costs paid
          (3,538 )     (263 )
Other financing
    (17 )     (450 )     (821 )
 
Net Cash Used in Financing Activities
    (97,700 )     (46,613 )     (43,740 )
 
                       
Net Increase (Decrease) in Cash and Cash Equivalents
    (10,869 )     21,716       (23,374 )
Cash and Cash Equivalents, Beginning of Period
    38,156       16,440       39,814  
 
 
                       
Cash and Cash Equivalents, End of Period
  $ 27,287     $ 38,156     $ 16,440  
 
 
                       
Cash and Cash Equivalents, End of Period:
                       
Continuing operations
  $ 27,287     $ 31,421     $ 13,810  
Discontinued operations
          6,735       2,630  
 
Total
  $ 27,287     $ 38,156     $ 16,440  
 
See accompanying notes to condensed consolidated financial statements.

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Endeavour International Corporation
Consolidated Statement of Stockholders’ Equity

(Amounts in thousands)
                                                         
                            Accumulated                
                    Additional   Other           Total   Total
    Common   Treasury   Paid-In   Comprehensive   Accumulated   Stockholder’s   Comprehensive
    Stock   Stock   Capital   Loss   Deficit   Equity   Income (Loss)
 
Balance, December 31, 2006
  $ 119     $     $ 226,988     $     $ (110,279 )   $ 116,828     $    
Preferred stock dividend
    6             10,509             (11,238 )     (723 )        
Amortization of deferred compensation
                4,975                   4,975          
Other
    2             (933 )                 (931 )        
Comprehensive Loss:
                                                       
Net Loss
                            (49,077 )     (49,077 )     (49,077 )
Other comprehensive loss (net of tax):
                                                       
Unrealized loss on derivative instruments, net of tax
                      (852 )           (852 )     (852 )
Unrealized gain (loss) on available-for-sale securities
                      (71 )           (71 )     (71 )
 
Balance, December 31, 2007
  $ 127     $     $ 241,539     $ (923 )   $ (170,594 )   $ 70,149     $ (50,000 )
 
 
                                                       
Preferred stock dividend
                            (10,809 )     (10,809 )        
Amortization of deferred compensation
                3,226                   3,226          
Treasury stock repurchase
          (450 )                       (450 )        
Other
    1             (294 )                 (293 )        
Comprehensive Loss:
                                                       
Net Loss
                            56,490       56,490       56,490  
Other comprehensive loss (net of tax):
                                                       
Unrealized loss on derivative instruments, net of tax
                      (342 )           (342 )     (342 )
Unrealized gain (loss) on available-for-sale securities
                      (1 )           (1 )        
 
Balance, December 31, 2008
  $ 128     $ (450 )   $ 244,471     $ (1,266 )   $ (124,913 )   $ 117,970     $ 56,148  
 
See accompanying notes to condensed consolidated financial statements.

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Endeavour International Corporation
Consolidated Statement of Stockholders’ Equity

(Amounts in thousands)
                                                         
                            Accumulated                
                    Additional   Other           Total   Total
    Common   Treasury   Paid-In   Comprehensive   Accumulated   Stockholder’s   Comprehensive
    Stock   Stock   Capital   Loss   Deficit   Equity   Income (Loss)
 
Balance, December 31, 2008
  $ 128     $ (450 )   $ 244,471     $ (1,266 )   $ (124,913 )   $ 117,970     $ 56,148  
 
                                                       
Preferred stock dividend
                            (21,211 )     (21,211 )        
Amortization of deferred compensation
                3,163                   3,163          
Treasury stock repurchase
          (137 )                       (137 )        
Other
    4             73                   77          
Comprehensive Loss:
                                                       
Net Loss
                            (40,995 )     (40,995 )     (40,995 )
Other comprehensive income (net of tax):
                                                       
Unrealized loss on derivative instruments, net of tax
                      1,194             1,194       1,194  
Unrealized gain (loss) on available-for-sale securities
                      72             72       72  
 
Balance, December 31, 2009
  $ 132     $ (587 )   $ 247,707     $     $ (187,119 )   $ 60,133     $ (39,729 )
 
See accompanying notes to condensed consolidated financial statements.

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
Note 1 Description of Business
Endeavour International Corporation was incorporated under the laws of the state of Nevada on January 13, 2000. As used in these Notes to Consolidated Financial Statements, the terms “Endeavour”, “we”, “us”, “our” and similar terms refer to Endeavour International Corporation and, unless the context indicates otherwise, its consolidated subsidiaries.
Note 2 Summary of Significant Accounting Policies
Basis of Presentation and Use of Estimates
The accompanying financial statements have been prepared on the accrual basis of accounting in accordance with accounting principles generally accepted in the United States of America (“US GAAP”) and have been presented on a going concern basis, which contemplates the realization of assets and satisfaction of liabilities in the normal course of business. These accounting principles require management to use estimates, judgments and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements, and revenues and expenses during the reporting period. Management reviews its estimates, including those related to the determination of proved reserves, estimates of future dismantlement costs, income taxes and litigation. Actual results could differ from those estimates. In the opinion of management, all normal recurring adjustments considered necessary for a fair presentation have been included in these financial statements. Certain amounts for prior periods have been reclassified to conform to the current presentation.
Management believes it is reasonably possible that the following material estimates affecting the financial statements could change in the coming year: (1) estimates of proved oil and gas reserves, (2) estimates as to the expected future cash flow from proved oil and gas properties, (3) estimates of future dismantlement and restoration costs, (4) estimates of fair values used in purchase accounting and (5) estimates of the fair value of derivative instruments.
Principles of Consolidation
The accompanying consolidated financial statements include all of the accounts of Endeavour and our consolidated subsidiaries. All significant intercompany accounts and transactions have been eliminated. Investments in entities over which we have significant influence, but not control, are carried at cost adjusted for equity in earnings or (losses) and distributions received.
Cash and Cash Equivalents
We consider all highly liquid instruments with an original maturity of 90 days or less at the time of purchase to be cash equivalents.

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
Restricted Cash
Restricted cash includes amounts held in escrow for drilling rig commitments and for purchase price of the acquisition of properties from Hillwood Energy. The escrow for the Hillwood Energy properties was release upon closing of the acquisition in January 2010. The remaining reserved amounts in escrow will be released as payments are made for this drilling activity.
Inventories
Materials and supplies and oil inventories are valued at the lower of cost or market value (net realizable value).
Full Cost Accounting for Oil and Gas Operations
Under the full cost method, all acquisition, exploration and development costs, including certain directly related employee costs and a portion of interest expense, incurred for the purpose of finding oil and gas are capitalized and accumulated in pools on a country-by-country basis. Capitalized costs include the cost of drilling and equipping productive wells, including the estimated costs of dismantling and abandoning these assets, dry hole costs, lease acquisition costs, seismic and other geological and geophysical costs, delay rentals and costs related to such activities. Employee costs associated with production and other operating activities and general corporate activities are expensed in the period incurred.
Capitalized costs are limited on a country-by-country basis (the ceiling test). The ceiling test limitation is calculated as the sum of the present value of future net cash flows related to estimated production of proved reserves, using the average, first-day-of-the-month price during the 12-month period before the end of the year for 2009 and the year-end price for 2008 and 2007, including the effect of derivative instruments that qualify as cash flow hedges, discounted at 10%, plus the lower of cost or estimated fair value of unproved properties, all net of expected income tax effects. Under the ceiling test, if the capitalized cost of the full cost pool, net of deferred taxes, exceeds the ceiling limitation, the excess is charged as an impairment expense.
We utilize a single cost center for each country where we have operations for amortization purposes. Any conveyances of properties are treated as adjustments to the cost of oil and gas properties with no gain or loss recognized unless the operations are suspended in the entire cost center or the conveyance is significant in nature.
Unproved property costs include the costs associated with unevaluated properties and properties under development and are not initially included in the full cost amortization base (where proved reserves exist) until the project is evaluated. These costs include unproved leasehold acreage, seismic data, wells and production facilities in progress and wells pending determination,

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
together with interest costs capitalized for these projects. Seismic data costs are associated with specific unevaluated properties where the seismic data is acquired for the purpose of evaluating acreage or trends covered by a leasehold interest owned by us. Significant unproved properties are assessed periodically for possible impairment or reduction in value. If a reduction in value has occurred, these property costs are considered impaired and are transferred to the related full cost pool. Geological and geophysical costs included in unproved properties are transferred to the full cost amortization base along with the associated leasehold costs on a specific project basis. Costs associated with wells in progress and wells pending determination are transferred to the amortization base once a determination is made whether or not proved reserves can be assigned to the property. Costs of dry holes are transferred to the amortization base immediately upon determination that the well is unsuccessful. Unproved properties whose acquisition costs are not individually significant are aggregated, the portion of such costs estimated to be ultimately nonproductive, based on experience, are amortized to the full cost pool over an average holding period.
In countries where the existence of proved reserves has not yet been determined, unevaluated property costs remain capitalized in unproved property cost centers until proved reserves have been established, exploration activities cease or impairment and reduction in value occurs. If exploration activities result in the establishment of a proved reserve base, amounts in the unproved property cost center are reclassified as proved properties and become subject to amortization and the application of the ceiling test. When it is determined that the value of unproved property costs have been permanently diminished (in part or in whole) based on the impairment evaluation and future exploration plans, the unproved property cost centers related to the area of interest are impaired, and accumulated costs charged against earnings.
Other Property and Equipment
Other oil and gas assets, computer equipment and furniture and fixtures are recorded at cost, less accumulated depreciation. The assets are depreciated using the straight-line method over their estimated useful lives of two to five years.
Capitalized Interest
We capitalize interest on expenditures for significant exploration and development projects while activities are in progress to bring the assets to their intended use. Capitalized interest is calculated by multiplying our weighted-average interest rate on debt by the amount of qualifying costs and is limited to gross interest expense. As costs are transferred to the full cost pool, the associated capitalized interest is also transferred to the full cost pool.

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
Marketable Securities
The marketable securities reflected in these financial statements are deemed by management to be “available-for-sale” and, accordingly, are reported at fair value, with unrealized gains and losses reported in other comprehensive income and reflected as a separate component within the Statement of Stockholders’ Equity unless we determine that an other-than-temporary impairment has occurred. Realized gains and losses on securities available-for-sale are included in other income/expense and, when applicable, are reported as a reclassification adjustment, net of tax, in other comprehensive income. Gains and losses on the sale of available-for-sale securities are determined using the specific-identification method.
Business Combinations
Assets and liabilities acquired through a business combination are recorded at estimated fair value. We use all available information to make these fair value determinations, including information commonly considered by our engineers in valuing individual oil and gas properties and sales prices for similar assets. Estimated deferred taxes are based on available information concerning the tax basis of the acquired company’s assets and liabilities and carryforwards at the merger date.
Any excess of the acquisition cost of the acquired business over the fair value amounts assigned to assets and liabilities is recorded as goodwill. Any excess of the amounts assigned to assets and liabilities over the acquisition of the acquired business is recorded as a gain on acquisition on the income statement. The amount of goodwill recorded in any particular business combination can vary significantly depending upon the fair values attributed to assets acquired and liabilities assumed relative to the total acquisition cost.
Goodwill and Intangible Assets
We assess the carrying amount of goodwill and other indefinite-lived intangible assets by testing the asset for impairment annually at year-end, or more frequently if events or changes in circumstances indicate that the asset might be impaired. The impairment test requires allocating goodwill and all other assets and liabilities to reporting units. The fair value of each reporting unit is determined and compared to the book value of the reporting unit. An impairment loss is recognized to the extent that the carrying amount exceeds the asset’s fair value.
Dismantlement, Restoration and Environmental Costs
We recognize liabilities for asset retirement obligations associated with tangible long-lived assets, such as producing well sites, offshore production platforms, and natural gas processing plants, with a corresponding increase in the related long-lived asset. The asset retirement cost is depreciated along with the property and equipment in the full cost pool. The asset retirement

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
obligation is recorded at fair value and accretion expense, recognized over the life of the property, increases the liability to its expected settlement value. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded for both the asset retirement obligation and the asset retirement cost.
Revenue Recognition
We use the entitlements method to account for sales of gas production. We may receive more or less than our entitled share of production. Under the entitlements method, if we receive more than our entitled share of production, the imbalance is treated as a liability at the market price at the time the imbalance occurred. If we receive less than our entitled share, the imbalance is recorded as an asset at the lower of the current market price or the market price at the time the imbalance occurred. Oil revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred, title has transferred and collectability of the revenue is probable.
Significant Customers
Our sales in the U.K. are to a limited number of customers, each of which accounts for more than 10% of revenue: Chevron North Sea Ltd; Shell U.K. Limited, and Esso Exploration and Production. Our sales in the U.S. are sold through our arrangements with the operators of the fields, with substantially all of the sales being to Cohort Energy.
Derivative Instruments and Hedging Activities
From time to time, we may utilize derivative financial instruments to hedge cash flows from operations or to hedge the fair value of financial instruments. We may use derivative financial instruments with respect to a portion of our oil and gas production or a portion of our variable rate debt to achieve a more predictable cash flow by reducing our exposure to price fluctuations. These transactions are likely to be swaps, collars or options and to be entered into with major financial institutions or commodities trading institutions. Derivative financial instruments are intended to reduce our exposure to declines in the market prices of crude oil and natural gas that we produce and sell, to increases in interest rates and to manage cash flows in support of our annual capital expenditure budget. We also have embedded derivatives related to our debt instruments and convertible preferred stock.
We record all derivatives at fair market value in our Consolidated Balance Sheets at the end of each period. The accounting for the fair market value, and the changes from period to period, depends on the intended use of the derivative and the resulting designation. This evaluation is determined at each derivative’s inception and begins with the decision to account for the derivative as a hedge, if applicable. The accounting for changes in the fair value of a derivative instrument that is not accounted for as a hedge is included in other (income) expense as an

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
unrealized gain or loss. At December 31, 2009, we have no outstanding derivatives that are accounted for as a hedge.
Where we intend to account for a derivative as a hedge, we document, at its inception, the hedging relationship, the risk management objective and the strategy for undertaking the hedge. The documentation includes the identification of the hedging instrument, the hedged item or transaction, the nature of the risk being hedged, and the method that will be used to assess effectiveness of derivative instruments that receive hedge accounting treatment.
Changes in fair value to hedge instruments, to the extent the hedge is effective, are recognized in other comprehensive income until the forecasted transaction occurs. Hedge effectiveness is assessed at least quarterly based on total changes in the derivative’s fair value. Any ineffective portion of the derivative instrument’s change in fair value is recognized immediately in other (income) expense.
We discontinue hedge accounting prospectively when (1) we determine that the derivative is no longer effective in offsetting changes in the fair value or cash flows of a hedged item (including hedged items such as firm commitments or forecasted transactions); (2) the derivative expires; (3) it is no longer probable that the forecasted transaction will occur; (4) a hedged firm commitment no longer meets the definition of a firm commitment; or (5) management determines that designating the derivative as a hedging instrument is no longer appropriate.
Concentrations of Credit and Market Risk
Financial instruments that potentially subject us to concentrations of credit risk consist principally of cash deposits at financial institutions. At various times during the year, we may exceed the federally insured limits. To mitigate this risk, we place our cash deposits only with high credit quality institutions. Management believes the risk of loss is minimal.
Derivative financial instruments that hedge the price of oil and gas, interest rates or currency exposure will be generally executed with major financial or commodities trading institutions which expose us to market and credit risks, and may at times be concentrated with certain counterparties or groups of counterparties. Although notional amounts are used to express the volume of these contracts, the amounts potentially subject to credit risk, in the event of non-performance by the counterparties, are substantially smaller. We review the credit ratings of our counterparties to derivative contracts (who are all lenders under our senior bank facility) on a regular basis and to date we have not experienced any non-performance by any of our counterparties, currently BNP Paribas S.A. At December 31, 2009 our derivative instruments do not require either side to maintain collateral or margin accounts.
As an independent oil and gas producer, our revenue, profitability and future rate of growth are substantially dependent upon prevailing prices for oil and gas, which are dependent upon

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
numerous factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. The energy markets have historically been very volatile, and there can be no assurance that oil and gas prices will not be subject to wide fluctuations in the future. A substantial or extended decline in oil and gas prices could have a material adverse effect on our financial position, results of operations, cash flows and our access to capital and on the quantities of oil and gas reserves that may be economically produced.
Foreign Currency Translation
The U.S. dollar is the functional currency for all of our existing operations, as a majority of all revenue and financing transactions in these operations are denominated in U.S. dollars. For foreign operations with the U.S. dollar as the functional currency, monetary assets and liabilities are remeasured into U.S. dollars at the exchange rate on the balance sheet date. Nonmonetary assets and liabilities are translated into U.S. dollars at historical exchange rates. Income and expense items are translated at exchange rates prevailing during each period. Adjustments are recognized currently as a component of foreign currency gain or loss and deferred income taxes. To the extent that business transactions are not denominated in U.S. dollars, we are exposed to foreign currency exchange rate risk.
Income Taxes
We use the liability method of accounting for income taxes under which deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities, and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized as part of the provision for income taxes in the period that includes the enactment date. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion of, or all of, the deferred tax assets will not be realized.
Share-Based Payments
We recognize all share-based payments to employees, including grants of employee stock options, based on their fair values. The share-based compensation cost is measured at the grant date, based on the calculated fair value of the award, and is recognized as general and administrative expense over the employee’s requisite service period (generally the vesting period of the equity award). We apply the fair value method in accounting for stock option grants using the Black-Scholes Method.

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
It is our policy to use authorized but unissued shares of stock when stock options are exercised. At December 31, 2009, we had approximately 7.0 million additional shares available for issuance pursuant to our existing stock incentive plan.
Adoption of New Accounting Standards
On January 1, 2008, we adopted the following new standards without material effects on our results of operations or financial position:
    Fair value option — Guidance allowing entities to choose to measure many financial instruments and certain other items at fair value. This standard expanded the use of fair value measurement and applied to entities that elect the fair value option.
    Fair value measurement and disclosure — Framework for measuring fair value and expanded disclosures about such measurements. The new standards do not require new fair value measurements, rather, the provisions apply when fair value measurements are performed under other accounting pronouncements.
On January 1, 2009, we adopted the following new standards without material effects on our results of operations or financial position:
    Business combinations — Guidance related to the measurement of identifiable assets acquired, liabilities assumed and disclosure of information related to business combinations and their effect.
    Noncontrolling interests — Guidance for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. Specifically, this standard requires the recognition of a noncontrolling interest (minority interest) as a component of consolidated equity. Similarly, the new standard requires consolidated net income and comprehensive income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interests.
    Expanded disclosures of derivatives — Expanded and detailed financial statement disclosures for derivatives and hedged financial instruments. This standard applies to all derivatives and non-derivative instruments designated and qualifying as hedges, including bifurcated derivative instruments and related hedged items.
    Convertible debt — Guidance for convertible debt that may be settled in part or in whole in cash upon conversion requiring issuers of this form of debt to account for its debt and equity components separately. The new guidance also expands the definition of mandatorily redeemable convertible preferred shares that should be classified as liabilities.
    Share-based payments — Guidance for instruments that are granted in share-based payment transactions to treat unvested share-based payment awards with non-forfeitable rights to dividend or dividend equivalents as a separate class of securities in calculating earnings per share (“EPS”). The impact of the adoption of this standard on our weighted

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
      average shares outstanding and EPS was not material, therefore, we have not restated prior periods.
    Fair value — Framework for measuring fair value and expanded disclosures about fair value measurements. New fair value measurements are not required; rather, the provisions apply when fair value measurements are performed under other accounting pronouncements.
On June 30, 2009, we adopted the following new standard that did not have a material effect on our results of operations or financial position:
    Subsequent Events — Standards of accounting for and disclosure of events that occur after the balance sheet date but before the financial statements are issued.
On December 31, 2009, we adopted the following new standard:
    Oil and gas modernization — Revised oil and gas reserve estimation and disclosure requirements. The accounting standards update revised the definition of proved oil and gas reserves to require that the average, first-day-of-the-month price during the 12-month period before the end of the year rather than the year-end price, must be used when estimating whether reserve quantities are economical to produce and when calculating the aggregate amount of (and changes in) future cash inflows related to the standardized measure of discounted future net cash flows.
Note 3 — Discontinued Operations
On May 14, 2009, we completed the divestiture of our Norwegian subsidiary, Endeavour Energy Norge AS, to Verbundnetz Gas AG for cash consideration of $150 million (the “Norway Sale”). We recognized a gain upon closing the Norway Sale of $47.0 million, after the allocation of $68 million of goodwill to the assets sold.
As a result of the Norway Sale, we have classified the results of operations and financial position of our Norwegian subsidiary as discontinued operations for all periods presented. The following table details selected financial data for the assets included in the Norway Sale:

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
                         
    December 31, 2009   December 31, 2008        
 
Current Assets:
                       
Cash
  $     $ 6,735          
Accounts receivable
          4,559          
Prepaid expenses and other
          5,432          
 
 
          16,726          
 
                       
Long-term Assets:
                       
Property, plant and equipment, net
          80,611          
Goodwill
          67,994          
 
 
          148,605          
 
                       
Current Liabilities:
                       
Accounts payable
          (3,717 )        
Accrued expenses and other
          (18,514 )        
 
 
          (22,231 )        
 
                       
Long-term Liabilities:
                       
Deferred tax liability
          (36,828 )        
Asset retirement obligation
          (9,223 )        
 
 
            (46,051 )        
 
                       
Net Assets and Liabilities
  $     $ 97,049          
 

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
                         
    Year Ended December 31,
    2009   2008   2007
 
Sales
  $ 17,550     $ 89,660     $ 40,188  
 
 
                       
Income before Taxes
  $ 4,654     $ 63,244     $ 14,096  
Income Tax Expense
    (5,428 )     (32,613 )     (13,028 )
 
Income (Loss) from Operations
    (774 )     30,631       1,068  
 
                       
Gain on sale
    47,308              
 
Net Income from Discontinued Operations
  $ 46,534     $ 30,631     $ 1,068  
 
Note 4 Prepaid Expenses and Other Current Assets
Prepaid expenses and other current assets consisted of the following:
                 
    December 31,
    2009   2008
 
Fair market value of commodity derivatives — current
  $ 2,890     $ 31,649  
Prepaid insurance
    1,506       1,322  
Inventory
    4,450       5,109  
Other
    1,272       4,114  
 
 
               
 
  $ 10,118     $ 42,194  
 

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
Note 5 Property and Equipment
Property and equipment included the following:
                 
    December 31,
    2009   2008
 
Oil and gas properties under the full cost method:
               
Subject to amortization
  $ 275,278     $ 239,024  
Not subject to amortization:
               
Acquired in 2009
    51,797        
Acquired in 2008
    32,970       37,288  
Acquired in 2007
    10,235       14,746  
Acquired prior to 2007
    59,551       82,522  
 
 
    429,831       373,580  
 
               
Other oil and gas assets
          4,875  
 
               
Computers, furniture and fixtures
    3,560       3,236  
 
Total property and equipment
    433,391       381,691  
 
               
Accumulated depreciation, depletion and amortization
    (166,804 )     (149,345 )
 
 
               
Net property and equipment
  $ 266,587     $ 232,346  
 
The majority of costs not subject to amortization relate to values assigned to unproved reserves acquired. The remainder of costs not subject to amortization relate to exploration costs such as drilling costs for projects awaiting approved development plans or the determination of whether or not proved reserves can be assigned and other seismic and geological and geophysical costs. These costs are transferred to the amortization base when it is determined whether or not proved reserves can be assigned to such properties. This analysis is dependent upon well performance, results of infield drilling, approval of development plans, drilling results and development of identified projects and periodic assessment of reserves. We expect acquisition costs excluded from amortization to be transferred to the amortization base over the next five years due to a combination of well performance and results of infield drilling relating to currently producing assets and the drilling and development of identified projects acquired, such as the Rochelle field. We expect exploration costs not subject to amortization to be transferred to the amortization base over the next three years as development plans are completed and production commences on existing discoveries including the Bacchus, Columbus, Cygnus and Rochelle projects.
The following is a summary of our oil and gas properties not subject to amortization as of December 31, 2009:

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Endeavour International Corporation
Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)
                                         
Costs Incurred in the Year Ended December 31,
    2009   2008   2007   Prior to 2007   Total
 
Acquisition costs
  $ 10,662     $ 807     $     $ 30,292     $ 41,761  
Exploration costs
    38,158       28,528       9,260       29,261       105,207  
Capitalized interest
    2,977       3,635       975             7,587  
 
 
                                       
Total oil and gas properties not subject to amortization
  $ 51,797     $ 32,970     $ 10,235     $ 59,553     $ 154,555  
 
During 2009, 2008 and 2007, we capitalized $7.8 million, $8.0 million and $7.2 million, respectively, in certain directly related employee costs. During 2009, 2008 and 2007, we capitalized $3.1 million, $4.0 million and $6.4 million, respectively, in interest.
Note 6 — Goodwill
In connection with the several acquisitions, we recorded goodwill for the excess of the purchase price over the value assigned to individual assets acquired and liabilities assumed. With the 2009 settlement of a liability for a metering mis-measurement liability at a purchased field, the goodwill was reduced by $2.1 million. The following is a reconciliation of the changes in goodwill for the year ended December 31, 2009 and 2008:
                 
    December 31,
    2009   2008
 
Balance at beginning of year
  $ 281,943     $ 283,324  
Allocation of goodwill to discontinued operations sold
    (67,994 )      
Adjustments
    (2,063 )     (1,381 )
 
 
               
Balance at end of year
  $ 211,886     $ 281,943  
 

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Endeavour International Corporation
Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)
Note 7 — Other Assets
Other long-term assets consisted of the following at December 31:
                 
    2009   2008
 
Intangible assets — workforce in place:
               
Gross
  $ 4,800     $ 4,800  
Accumulated amortization
    (3,919 )     (3,363 )
 
 
    881       1,437  
 
               
Debt issuance costs
    3,875       5,714  
Fair market value of long-term portion of commodity derivatives
    318       1,702  
Other
    248       312  
 
 
 
  $ 5,322     $ 9,165  
 
Intangible assets represent the purchase price allocated to the assembled workforce as a result of an acquisition and is being amortized over its estimated life using the straight-line method. Estimated amortization expense is $0.6 million and $0.3 million in 2010 and 2011, respectively.
Debt issuance costs are amortized over the life of the related debt obligation.
Note 8 Accrued Expenses
We had the following accrued expenses outstanding:
                 
    December 31,  
    2009   2008
 
Derivative liability
  $ 6,817     $ 1,193  
Foreign taxes payable
    1,926       6,655  
Deferred foreign taxes payable
          15,825  
Accrued interest
    2,432       30  
Preferred dividends
    1,143       1,011  
Accrued compensation
    4,311       2,135  
Crude oil imbalance
          8,954  
Other
    1,169       839  
 
 
               
 
  $ 17,798     $ 36,642  
 

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Endeavour International Corporation
Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)
Note 9 — Debt Obligations
Our debt consisted of the following at the indicated dates:
                 
    December 31,   December 31,
    2009   2008
 
Senior notes, 6% fixed rate, due 2012
  $ 81,250     $ 81,250  
Senior bank facility, variable rate, due 2011
    49,942       113,000  
Convertible bonds, 11.5%, due 2014
    49,838       44,496  
Subordinated notes, 12.5%, due 2014
    50,122        
 
 
    231,152       238,746  
Less: debt discount
    (7,767 )     (10,891 )
Less: current maturities
          (13,000 )
 
 
               
Long-term debt
  $ 223,385     $ 214,855  
 
 
               
Standby letters of credit outstanding for abandonment liabilities
  $ 33,388     $ 30,115  
 
Principal maturities of debt at December 31, 2009 are as follows:
         
2010
  $  
2011
    69,942  
2012
    91,250  
2013
    10,000  
2014
    59,960  
Thereafter
     
 
The fair value of our debt obligations was $219 million and $191 million at December 31, 2009 and 2008, respectively. The fair values of long-term debt were determined based upon quotes obtained from banks for our senior notes, discounted cash flows for our 11.5% convertible debt and book value for other debt. Book value approximates fair value for our senior bank facility as this instrument bears interest at a market rate.
6% Senior notes, due 2012
During 2005, we issued in a private offering $81.25 million aggregate principal amount of convertible senior notes due 2012. The notes bear interest at a rate of 6.00% per annum, payable in January and July. The notes are convertible into shares of our common stock at an initial conversion rate of 199.2032 shares of common stock per $1,000 principal amount of notes,

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Endeavour International Corporation
Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)
subject to adjustment, which represents an initial conversion price of approximately $5.02 per share. In connection with the issuance of these notes, we paid $3.6 million in financing and other costs. Upon specified change of control events, each holder of those notes may require us to purchase all or a portion of the holder’s notes at a price equal to 100% of the principal amount, plus accrued and unpaid interest, if any, up to but excluding the date of purchase.
Senior bank facility
We have a $225 million senior bank facility, which is subject to a borrowing base limitation. The borrowing base is subject to redetermination every six months with an independent reserve report required every 12 months. At December 31, 2009, the borrowing base capacity was $50 million, which was fully drawn at year-end. The senior bank facility also provides for issuances of letters of credit of up to an aggregate $60 million. As of December 31, 2009, we have $33.4 million of outstanding letters of credit related to abandonment liabilities on certain of our oil and gas properties.
Indebtedness under the facility is secured by cross guarantees from all of our subsidiaries, share pledges from all of our subsidiaries and floating charges over the operating assets held in the United Kingdom. Our borrowings under the senior bank facility bear interest at LIBOR plus 1.3% for the first $46.1 million of availability, and LIBOR plus 1.7% for up to an additional $3.9 million of availability.
The senior bank facility contains customary covenants, which limit our ability to incur indebtedness, pledge our assets and dispose of our assets. In addition, the senior bank facility contains various financial and technical covenants, including:
    a maximum consolidated debt to earnings before interest, taxes, depreciation and amortization (“EBITDA”) ratio of 3.0:1;
 
    a minimum current assets to current liabilities ratio of 1.1:1;
 
    a minimum debt coverage ratio of 1.2:1 for the initial tranche and 1.15:1 for the second tranche;
 
    a minimum field life net present value (“NPV”) to loans outstanding coverage ratio of 1.5:1 for the initial tranche, and 1.3:1 for the second tranche; and
 
    a minimum loan life NPV to loans outstanding coverage ratio of 1.3:1 for the initial tranche, and 1.2:1 for the second tranche.
The final maturity is the earlier of January 31, 2011 or the reserve tail date, being the date when the remaining borrowing base reserves are projected to be 20% or less of the initially approved borrowing base reserves. The senior bank facility is subject to mandatory prepayment in the event of a change of control of any obligor under the senior bank facility agreement. It is prepayable at our option at any time without penalty.

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Endeavour International Corporation
Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)
The borrowing base is subject to redetermination every six months (on April 1 and October 1), and we are required to provide our lenders with an independent reserve report every 12 months. Based on our reserve report at December 31 and June 30 each year, commodity prices set by our lenders and terms set forth in the credit agreement, the maximum capacity of our borrowing base is set, and any amounts outstanding over the redetermined borrowing base must be repaid within 45 days of the redetermination date. The senior bank facility is also subject to maximum commitment levels by the participating lenders that change over time. We are currently undergoing the redetermination process based on our reserve report as of December 31, 2009, which will be effective as of April 1, 2010. We cannot estimate the level of the borrowing base capacity that will be in effect as of April 1, 2010.
Convertible Bonds
In January 2008, we issued 11.5% Convertible Bonds due 2014 (the “Convertible Bonds”) for gross proceeds of $40 million pursuant to a private offering to a sophisticated investor in Norway. The net proceeds from the issuance of the Convertible Bonds were used to repay a portion of our outstanding indebtedness. The Convertible Bonds bear interest at a rate of 11.5% per annum, compounded quarterly. Interest is compounded quarterly and added to the outstanding principal balance each quarter. The bonds are convertible into shares of our common stock at an initial conversion price of $2.36 per $1,000 of principal, which represents a conversion rate of approximately 424 shares of our common stock per $1,000 of principal. The conversion price will be adjusted in accordance with the terms of the bonds upon occurrence of certain events, including payment of common stock dividends, common stock splits or issuance of common stock at a price below the then current market price.
Upon the fourth anniversary of the issuance of the Convertible Bonds, the holders have the right to cause us to redeem the Convertible Bonds if the weighted average closing price of our common stock for the preceding 30 days is less than the conversion price, as adjusted. If the holders do not exercise this right, the right will lapse and the conversion price will be reset to the then current market price of our common stock if such price is lower than the conversion price, as adjusted.
If we undergo a “change of control” as defined, the holders of the bonds have the right, subject to certain conditions, to redeem the bonds and accrued interest. The bonds may become immediately due upon the occurrence of certain events of default, as defined.
Two derivatives are associated with the conversion and change in control features of the Convertible Bonds. At December 31, 2009, the combined fair market value of these derivatives is $26.9 million, reflecting a $12.3 million increase during 2009 that was recorded in unrealized gains (losses) on derivatives.

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Endeavour International Corporation
Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)
Subordinated Notes
On November 17, 2009, we entered into Stock Redemption Agreements with each of the holders of our outstanding shares of Series C convertible preferred stock (“Series C Preferred Stock”) whereby we redeemed 60% of the outstanding shares of Series C Preferred Stock, for face value of $75 million, and amended the terms of the remaining shares of Series C Preferred Stock. The redemption price consisted of a $25 million cash payment and the issuance of $50 million Subordinated Notes.
The Subordinated Notes bear interest at an annual rate of 10%, plus 2% capitalized to the outstanding principal amount. We will pay interest, in cash, on the unpaid principal amount of the Subordinated Notes quarterly on March 31, June 30, September 30 and December 31 of each year commencing on December 31, 2009. The Subordinated Notes are payable over four years commencing in March 2011, but may be prepaid at any time at face value. The Subordinated Notes are unsecured and subordinated to our outstanding obligations under our senior bank facility and rank on parity with our other existing debt obligations.
Note 10 Other Liabilities
Other liabilities included the following:
                 
    December 31,
    2009   2008
 
Asset retirement obligations
  $ 47,362     $ 38,776  
Long-term derivative liabilities
    38,050       17,015  
 
 
               
Total Other Liabilities
  $ 85,412     $ 55,791  
 
Our asset retirement obligations relate to obligation of the plugging and abandonment of oil and gas properties. The asset retirement obligation is recorded at fair value and accretion expense, recognized over the life of the property, increases the liability to its expected settlement value. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded for both the asset retirement obligation and the asset retirement cost. The following table provides a rollforward of the asset retirement obligations for the year ended December 31, 2009 and 2008:

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Endeavour International Corporation
Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)
                 
    Year Ended
    December 31,
    2009   2008
 
Carrying amount of asset retirement obligations as of beginning of period
  $ 38,776     $ 30,790  
Increase (decrease) due to revised estimates of asset retirement obligations
    7,762       13,840  
Accretion expense
    4,117       2,795  
Impact of foreign currency exchange rate changes
    4,280       (8,649 )
Payment of asset retirement obligation
    (7,325 )      
Sale of assets
    (248 )      
 
 
               
Carrying amount of asset retirement obligations as of end of period
  $ 47,362     $ 38,776  
 
Note 11 Equity
The activity in shares of our common and preferred stock during 2009, 2008 and 2007 included the following:

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Endeavour International Corporation
Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)
                         
    Year Ended December 31,
    2009   2008   2007
 
Common Stock:
                       
 
                       
Outstanding at the beginning of the year
    128,572       127,006       118,577  
Issuance of common stock to pay preferred dividends
                6,403  
Exercise of stock options
    164              
Issuance of stock based compensation
    2,882       1,566       2,026  
 
 
                       
Outstanding at the end of the year
    131,618       128,572       127,006  
 
 
                       
Series B Preferred Stock:
                       
Outstanding at the end of the year
    20       20       20  
 
 
                       
Convertible Preferred Stock:
                       
Outstanding at the beginning of the year
    125       125        
Redemptions
    (75 )                
Issuance of preferred stock
                125  
 
 
                       
Outstanding at the end of the year
    50       125       125  
 
 
                       
Treasury Stock:
                       
Outstanding at the beginning of the year
    (327 )            
Purchase of treasury shares for stock vesting
    (171 )     (327 )      
 
 
                       
Outstanding at the end of the year
    (498 )     (327 )      
 
Common Stock
The Common Stock is $0.001 par value common stock, 300,000,000 shares authorized.
In 2008, we issued inducement grants of 300,000 shares of our restricted common stock, and options to purchase 250,000 shares of our common stock at an exercise price of $0.75 per share upon commencement of employment of one executive officer. In 2007, we issued inducement grants of 800,000 shares of our restricted common stock, options to purchase 400,000 shares of our common stock at an exercise price of $2.00 per share and options to purchase 200,000 shares of our common stock at an exercise price of $1.14 per share upon commencement of employment of two executive officers.

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Endeavour International Corporation
Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)
Convertible Preferred Stock
The Series C Preferred Stock ranks senior to any of our other existing or future shares of capital stock. Dividends are cumulative and payable in cash, or common stock if we are unable to pay such dividends in cash, and any dividends will be paid to the preferred stock investors prior to payment of any other dividend on any other shares of our capital stock. The Series C Preferred Stock also participates on an as-converted basis with respect to any dividends paid on the common stock.
We initially agreed to pay a cumulative dividend on the Series C Preferred Stock equal to 8.5% per annum of the original issue price (compounded quarterly) if paid in cash and 8.92% per annum of the original issue price (compounded quarterly) if paid in stock. On November 17, 2009, we redeemed 60% of the outstanding shares of Series C Preferred Stock, for face value of $75 million, and amended the terms of the remaining shares of Series C Preferred Stock. The redemption price consisted of a $25 million cash payment and the issuance of $50 million Subordinated Notes.
The redemption and modification of the Series C Preferred Stock required the modified Series C Preferred Stock to be recorded at fair market value at the redemption date. The fair value of the modified Series C Preferred Stock was greater than the carrying value by $11.5 million. This excess of fair value over carrying value was recorded as a non-cash charge to preferred stock dividends and increased the carrying value of the Series C Preferred Stock. As holders convert the Series C Preferred Stock, the $11.5 million non-cash charge will be transferred to equity on a ratio of shares converted to shares of Series C Preferred Stock outstanding.
In addition, the modification of the Series C Preferred Stock, we also recorded an embedded derivative are associated with the change in control features of the Series C Preferred Stock of $2.4 million. This embedded derivative was recorded in other liabilities and reduced the premium on the Series C Preferred Stock at the date of issuance. At December 31, 2009, the fair market value of this derivative was $1.9 million, reflecting a $0.5 million gain during 2009 that was recorded in unrealized gains (losses) on derivatives.
Prior to the November 2009 amendment, the Series C Preferred Stock was convertible into common stock at any time at the option of the preferred stock investors, at (i) a conversion price of $2.50 (the “Conversion Price”) and (ii) in an amount of common stock equal to the quotient of the liquidation preference of $1,000 per share plus accrued but unpaid dividends (the “Liquidation Preference”) divided by the Conversion Price.
In the November 2009 amendment, we amended terms of the Series C Preferred Stock to reduce the annual dividend rate to 4.5% (from 8.5%), adjust the conversion price to $1.25 per share (from $2.50) and remove certain anti-dilution provisions.

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Endeavour International Corporation
Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)
Issuance of dividends in the form of common stock are subject to the following equity conditions (the “Equity Conditions”), which are waivable by two-thirds of the holders of the Series C Preferred Stock: (i) such common stock is listed on the NYSE AMEX, the New York Stock Exchange or the Nasdaq Stock Market, and not subject to any trading suspension; (ii) we are not then subject to any bankruptcy event; and (iii) such common stock will be immediately re-saleable by the holders pursuant to an effective registration statement and otherwise in compliance with all applicable laws. If we have not maintained the effectiveness of the registration statement pursuant to the registration rights section below, then the dividend rate on the Series C Preferred Stock will be increased by the product of 2.5% (if the dividend is paid in cash) or 2.63% (if the dividend is paid in stock) times the number of quarters (or portions thereof) in which the failure occurs or we fail to cure such failure.
After the fourth anniversary of the initial issuance of the Series C Preferred Stock, we may redeem all of the Series C Preferred Stock in exchange for a cash payment to the preferred stock investors of an amount equal to 102% of the sum of the Liquidation Preference. If we call the Series C Preferred Stock for redemption, the holders thereof will have the right to convert their shares into a newly issued preferred stock identical in all respects to the Convertible Preferred Stock except that such newly issued preferred stock will not bear a dividend (the “Alternate Preferred Stock”). We may not redeem the Convertible Preferred Stock if the Equity Conditions are not then satisfied with respect to the common stock into which the Alternate Preferred Stock is convertible.
Upon the tenth anniversary of the initial issuance of the Convertible Preferred Stock, we must redeem all of the Convertible Preferred Stock for an amount equal to the Liquidation Preference plus accrued and unpaid dividends payable by us in cash or common stock at our election. Issuance by us of common stock for such redemption is subject to the Equity Conditions and to the market value of the outstanding shares of common stock immediately prior to such redemption equaling at least $500 million.
In the event of a change of control of Endeavour, we will be required to offer to redeem all of the Convertible Preferred Stock for the greater of: (i) the amount equal to which such holder would be entitled to receive had the holder converted such Convertible Preferred Stock into common stock; (ii) 115% of the sum of the Liquidation Preference plus accrued and unpaid dividends; and (iii) the amount resulting in an internal rate of return to such holder of 15% from the date of issuance of such Convertible Preferred Stock through the date that Endeavour pays the redemption price for such shares.
Series B Preferred Stock
In September 2002, we authorized and designated 500,000 shares of Preferred Stock, as Series B Preferred Stock par value $.001 per share.

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Endeavour International Corporation
Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)
The Series B Preferred Stock is to pay dividends of 8% of the original issuing price per share per annum, which are cumulative prior to any dividends on the common stock and on parity with the payment of any dividend or other distribution on any other series of preferred stock that has similar characteristics. The holders of each share of Series B Preferred Stock are entitled to be paid out of available funds prior to any distributions to holders of common stock in the amount of $100.00 per outstanding share plus all accrued dividends. We may, upon approval of our Board, redeem all or a portion of the outstanding shares of Series B preferred stock at a cost of the liquidation preference and all accrued and unpaid dividends.
Note 12 Income Taxes
The loss before income taxes and the components of the income tax expense recognized on the Consolidated Statement of Income are as follows:

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Endeavour International Corporation
Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)
                                                 
                            Total   Discontinued    
                            Continuing   Operations -    
(Amounts in thousands)   U.K.   U.S.   Other   Operations   Norway   Total
 
Year Ended December 31, 2009:
                                               
Net income (loss) before taxes
  $ (52,041 )   $ (31,167 )   $ (11,479 )   $ (94,687 )   $ 51,963     $ (42,724 )
 
                                               
Current tax (benefit) expense
    (5,739 )     40       (26 )     (5,725 )     (603 )     (6,328 )
Deferred tax (benefit) expense
    (20,260 )     (20 )     (35 )     (20,315 )     4,791       (15,524 )
Foreign currency losses on deferred tax liabilities
    18,882                   18,882       1,241       20,123  
 
Total tax (benefit) expense
    (7,117 )     20       (61 )     (7,158 )     5,429       (1,729 )
 
Net income (loss) after taxes
  $ (44,924 )   $ (31,187 )   $ (11,418 )   $ (87,529 )   $ 46,534     $ (40,995 )
 
 
Year Ended December 31, 2008:
                                               
Net income (loss) before taxes
  $ 66,129     $ (11,969 )   $ (4,185 )   $ 49,975     $ 63,244     $ 113,219  
 
                                               
Current tax expense
    11,158             10       11,168       27,879       39,047  
Deferred tax expense
    22,673             303       22,976       15,415       38,391  
Foreign currency gains on deferred tax liabilities
    (10,028 )                 (10,028 )     (10,681 )     (20,709 )
 
Total tax expense
    23,803             313       24,116       32,613       56,729  
 
Net income (loss) after taxes
  $ 42,326     $ (11,969 )   $ (4,498 )   $ 25,859     $ 30,631     $ 56,490  
 
 
Year Ended December 31, 2007:
                                               
Net income (loss) before taxes
  $ (68,704 )   $ (10,233 )   $ 6,584     $ (72,353 )   $ 14,095     $ (58,258 )
 
                                               
Current tax (benefit) expense
    2,898       (3 )     289       3,184       562       3,746  
Deferred tax (benefit) expense
    (27,430 )           711       (26,719 )     8,951       (17,768 )
Foreign currency losses on deferred tax liabilities
    1,327                   1,327       3,514       4,841  
 
Total tax (benefit) expense
    (23,205 )     (3 )     1,000       (22,208 )     13,027       (9,181 )
 
Net income (loss) after taxes
  $ (45,499 )   $ (10,230 )   $ 5,584     $ (50,145 )   $ 1,068     $ (49,077 )
 
The following table presents the principal reasons for the difference between our effective tax rates and the United States federal statutory income tax rate of 35%.

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
                         
    Year Ended December 31,
    2009   2008   2007
 
Federal income tax expense (benefit) at statutory rate
  $ (33,141 )   $ 17,491     $ (25,323 )
Taxation of foreign operations
    1,572       12,464       (1,790 )
Change in valuation allowance — US
    10,464       4,150       3,515  
Foreign tax benefit from foreign currency tax law change
    (5,400 )            
Foreign currency (gain)/loss on deferred taxes
    18,882       (10,028 )     1,327  
Other
    465       39       63  
 
 
                       
Income Tax Expense, continuing operations
    (7,158 )     24,116       (22,208 )
Discontinued operations — Norway
    5,429       32,613       13,207  
 
Total Income Tax Expense
  $ (1,729 )   $ 56,729     $ (9,001 )
 
Effective Income Tax Rate
    8 %     45 %     (32 )%
 
During 2009, 2008 and 2007, we incurred taxes in all of the jurisdictions that we do business in except for the U.S. In 2009, 2008 and 2007, we had a loss before taxes of $31.2 million, $8.3 million and $6.9 million, respectively, in the U.S. and we did not record any income tax benefits as there was no assurance that we could generate any U.S. taxable earnings, and therefore recorded a valuation allowance of the full amount of deferred tax asset generated.
Deferred income taxes result from the net tax effects of temporary timing differences between the carrying amounts of assets and liabilities reflected on the financial statements and the amounts recognized for income tax purposes. The tax effects of temporary differences that give rise to significant portions of deferred tax assets and liabilities are as follows at December 31:

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
                 
    2009   2008
 
Deferred tax asset:
               
Deferred compensation
  $ 6,236     $ 5,771  
Unrealized loss on derivative instruments
    16,560       4,506  
Asset retirement obligation
    7,026       5,244  
Net operating loss and capital loss carryforward
    34,635       21,633  
Other
    621       621  
 
 
               
Total deferred tax assets
    65,078       37,775  
Less valuation allowance
    (38,771 )     (23,701 )
 
Total deferred tax assets after valuation allowance
    26,307       14,074  
 
               
Deferred tax liability:
               
Property, plant and equipment
    (97,111 )     (67,810 )
Unrealized gain on derivative instruments
          (23,628 )
Petroleum revenue tax, net of tax benefit
    (1,264 )     (1,642 )
Debt discount
    (2,330 )     (3,267 )
Other
    (6,294 )     (850 )
 
Total deferred tax liabilities
    (106,999 )     (97,197 )
 
 
               
Net deferred tax liability
  $ (80,692 )   $ (83,123 )
 
At December 31, 2009, we had the following carryforwards available to reduce future income taxes:
                 
    Years of   Carryforward
Types of Carryforward   Expiration   Amounts
 
U.S. — Net operating loss
    2022 – 2029     $ 77,630  
U.K. — Corporate tax net operating loss
  Indefinite     24,570  
With the exception of $77.6 million of net operating loss carryforward attributable to our U.S. operations for which a valuation allowance has been established, the remaining carryforward amounts shown above have been recognized for financial statement reporting purposes to reduce deferred tax liability.
Recognition of the benefits of the deferred tax assets will require that we generate future taxable income. There can be no assurance that we will generate any earnings or any specific level of earnings in future years. Therefore, we have established a valuation allowance for deferred tax assets of approximately $38.8 million, $23.7 million and $19.7 million as of December 31, 2009, 2008 and 2007, respectively. During 2009, the valuation allowance in the U.S. increased $10.5 million due to net operating losses and increased $4.6 million in other jurisdictions. During 2008, the valuation allowance in the U.S. increased $2.9 million due to net operating losses and

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
increased $1.1 million for net operating losses in other jurisdictions. During 2007, the valuation allowance in the U.S. increased $2.4 million due to net operating losses and adjustments.
For U.S. federal income tax purposes, certain limitations are imposed on an entity’s ability to utilize its NOLs in future periods if a change of control, as defined for federal income tax purposes, has taken place. In general terms, the limitation on utilization of NOLs and other tax attributes during any one year is determined by the value of an acquired entity at the date of the change of control multiplied by the then-existing long-term, tax-exempt interest rate. The manner of determining an acquired entity’s value has not yet been addressed by the Internal Revenue Service. We have determined that, for federal income tax purposes, a change of control occurred during 2004 and 2007, however, we do not believe such limitations will significantly impact our ability to utilize the NOL. The timing of NOL utilization will be determined by our future net income.
At December 2007, we provided for a liability of $1.7 million for unrecognized tax benefits relating to various U.K. matters. The statute of limitations for assessing tax for these benefits expired during 2008, thus allowing the full recognition of these benefits. The benefit was recorded as a reduction to goodwill.
As of December 31, 2009, we believe that no current tax positions that have resulted in unrecognized tax benefits will significantly increase or decrease within the next year.
As of December 31, 2009, we had unremitted earnings in our foreign subsidiaries. If these unremitted earnings had been dividend to the U.S., the U.S. NOL’s not subject to the limitations mentioned above would be fully available to offset any incremental U.S. federal income tax. Further, the foreign tax credits associated with the unremitted earnings would be sufficient to offset any incremental U.S. tax liabilities associated with the dividend.
Note 13 — 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. The vesting of these shares and options is dependent upon the continued service of the grantees with Endeavour. Upon the occurrence of a change in control, each outstanding share of restricted stock and stock option will immediately vest.
Non-cash stock-based compensation is recorded in general and administrative (“G&A”) expenses or capitalized G&A as follows:

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
                                 
    Fourth Quarter   Year Ended
    December 31,   December 31,
    2009   2008   2009   2008
 
G & A Expenses
  $ 705     $ 723     $ 2,786     $ 2,641  
Capitalized G & A
    227       299       573       901  
 
 
                               
Total non-cash stock-based compensation
  $ 932     $ 1,022     $ 3,359     $ 3,542  
 
Stock-Based Compensation Arrangements
We grant restricted stock and stock options, including notional restricted stock and options, to employees and directors as incentive compensation. The notional restricted stock and options may be settled in cash or stock upon vesting, at our option, however it has been our practice to settle in stock. The restricted stock and options generally vest over three years and the options have a five to ten year expiration. The vesting of these shares and options is dependent upon the continued service of the grantees to Endeavour. Upon the occurrence of a change in control, each share of restricted stock and stock option outstanding on the date on which the change in control occurs will immediately become vested.
The fair value of each option award is estimated on the date of grant using the Black-Scholes option-pricing model. For 2007, expected volatility is based on an average of our peer companies where there is a lack of relevant Endeavour volatility information for the length of the expected term and the expected term is the average of the vesting date and the expiration of the option. After 2007, expected volatility is based on historical Endeavour volatility for the length of the expected term, which was determined by historical data. We use historical data to estimate option exercises and employee terminations within the valuation model. The risk-free rate for periods within the contractual life of the option is based on the U.S. treasury yield curve in effect at the time of grant. We do not include an estimated dividend yield since we have not paid dividends on our common stock historically.
The following summarizes the weighted average of the assumptions used in the method:
                         
    For the Year Ended December 31,
    2009   2008   2007
 
Risk-free rate
    1.5 %     3.1 %     4.4 %
Expected years until exercise
    4.25       4.00       4.00  
Expected stock volatility
    56 %     46 %     45 %
Dividend yield
                 
 

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
At December 31, 2009, total compensation cost related to nonvested awards not yet recognized was approximately $2.3 million and is expected to be recognized over a weighted average period of less than two years. For the year ended December 31, 2009, we included approximately $0.6 million of stock-based compensation in capitalized G&A in property and equipment.
Stock Options
Information relating to stock options, including notional stock options, is summarized as follows:
                                 
            Weighted   Weighted    
    Number of   Average   Average    
    Shares   Exercise   Contractual   Aggregate
    Underlying   Price per   Life in   Intrinsic
    Options   Share   Years   Value
 
Balance outstanding January 1, 2009
    4,807     $ 2.35                  
Granted
    1,181       0.54                  
Exercised
    (164 )     0.81                  
Forfeited
    (680 )     3.39                  
Expired
    (932 )     2.09                  
 
 
                               
Balance outstanding — December 31, 2009
    4,212     $ 1.87       6.2     $ 665  
 
 
                               
Currently exercisable — December 31, 2009
    2,124     $ 2.79       4.1     $ 42  
 
The weighted average grant-date fair value of options granted during 2009, 2008 and 2007 was $0.25, $0.50 and $0.40, respectively.
Of options granted during 2009, 2008 and 2007, 1.2 million, 1.2 million and 0.1 million options, respectively, were granted pursuant to incentive plans which have been approved by our stockholders. All other stock options have been granted pursuant to stock option plans that were not subject to stockholder approval.
Information relating to stock options outstanding at December 31, 2009 is summarized as follows:

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
                                         
    Options Outstanding   Options Exercisable
            Weighted   Weighted           Weighted
            Average   Average           Average
    Number of   Remaining   Exercise           Exercise
Range of Exercise   Options   Contractual   Price Per   Number   Price Per
Prices   Outstanding   Life   Share   Exercisable   Share
 
Less than $1.00
    1,329       9.00     $ 0.58       123     $ 0.74  
$1.00 – $2.00
    1,597       7.84       1.48       741       1.54  
$2.00 – $3.00
    265       3.88       2.44       238       2.48  
$3.00 – $4.00
    386       0.86       3.57       386       3.57  
Greater than $4.00
    635       0.79       4.28       635       4.28  
 
 
                                       
Total
    4,212       6.25     $ 1.87       2,123     $ 2.79  
 
The weighted average grant-date fair value of options granted for the year ended December 31, 2009 was $0.25 per option.
Restricted Stock
At December 31, 2009, our employees and directors held 3,420,703 million restricted shares of our common stock that vest over the service period of up to three years. The restricted stock awards were valued based on the closing price of our common stock on the measurement date, typically the date of grant, and compensation expense is recorded on a straight-line basis over the restricted share vesting period.
Status of the restricted shares as of December 31, 2009 and the changes during the year ended December 31, 2009 are presented below:

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
                 
            Weighted
            Average Grant
            Date Fair
    Number of   Value per
    Shares   Share
 
Balance outstanding — January 1, 2009
    3,966     $ 1.88  
Granted
    2,545       0.72  
Vested
    (2,917 )     1.92  
Forfeited
    (174 )     1.46  
 
 
               
Balance outstanding — December 31, 2009
    3,420     $ 1.00  
 
 
               
Total grant date fair value of shares vesting during the period
  $ 5,594          
 
Note 14 — Earnings per Share
Basic income (loss) per common share is computed by dividing net income (loss) to common stockholders by the weighted average number of common shares outstanding for the period. Diluted income (loss) per share includes the effect of our outstanding stock options, warrants and shares issuable pursuant to convertible debt, convertible preferred stock and certain stock incentive plans under the treasury stock method, if including such instruments is dilutive.
                                 
    Year Ended December 31,        
    2009   2008   2007        
 
Net income (loss) to common shareholders
                               
Basic
  $ (62,206 )   $ 45,681     $ (60,315 )        
Add Effect of:
                               
Preferred dividends
          10,625                
 
Diluted
  $ (62,206 )   $ 56,306     $ (60,315 )        
 
 
                               
Weighted Average Number of Common Shares Outstanding:
                               
Basic
    130,291       128,312       123,118          
Add Effect of:
                               
Preferred stock
          50,000                
 
Diluted
    130,291       178,312       123,118          
 
For each of the periods presented, shares associated with stock options, warrants, convertible debt, convertible preferred stock and certain stock incentive plans are not included because their inclusion would be antidilutive (i.e., reduce the net loss per share). The common shares potentially issuable arising from these instruments, which were outstanding during the periods presented in the financial statements, consisted of:

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
                         
    December 31,
    2009   2008   2007
 
Options and stock-based compensation
    1,910       2        
Convertible debt
    37,303       32,725       16,185  
Convertible preferred stock
    40,000             50,000  
 
 
                       
Common shares potentially issuable
    79,213       32,727       66,185  
 
Note 15 Comprehensive Income (Loss)
The following summarizes the components of comprehensive loss:
                         
    Year Ended December 31,
    2009   2008   2007
 
Net income (loss)
  $ (40,995 )   $ 56,490     $ (49,077 )
 
                       
Related to derivative instruments:
                       
Unrealized gain (loss)
          428       (852 )
Reclassification adjustment for gain (loss) realized in net income (loss) above
    1,194       (770 )      
 
                       
Related to marketable securities:
                       
Unrealized loss
          (1 )     (71 )
Reclassification adjustment for loss realized in net income (loss) above
    72              
 
 
                       
Net impact on comprehensive income (loss)
    1,266       (343 )     (923 )
 
 
                       
Comprehensive income (loss)
  $ (39,729 )   $ 56,147     $ (50,000 )
 
The components of accumulated other comprehensive income (loss) are:

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
                                 
    Year Ended December 31,        
    2009   2008   2007        
 
Related to derivative instruments:
                               
Balance at beginning of year
  $ (1,194 )   $ (852 )   $          
Change during the year
    1,194       (342 )     (852 )        
 
Balance at end of year
          (1,194 )     (852 )        
 
                               
Related to marketable securities:
                               
Balance at beginning of year
    (72 )     (71 )              
Change during the year
    72       (1 )     (71 )        
 
Balance at end of year
          (72 )     (71 )        
 
 
                               
Accumulated other comprehensive loss
  $     $ (1,266 )   $ (923 )        
 
Note 16 — Financial Instruments
                                 
    December 31, 2009   December 31, 2008
    Fair   Carrying           Carrying
    Value   Value   Fair Value   Value
Assets:
                               
Derivative instruments
  $ 3,208     $ 3,208     $ 33,351     $ 33,351  
 
                               
Liabilities:
                               
Long-term debt
    219,959       223,385       190,681       214,855  
Derivative instruments
    (44,866 )     (44,866 )     (18,208 )     (18,208 )
The carrying amounts reflected in the consolidated balance sheets for cash and equivalents, short-term receivables and short-term payables approximate their fair value due to the short maturity of the instruments. The fair values of commodity derivative instruments interest rate swaps and were determined based upon quotes obtained from brokers. The fair values of long-term debt were determined based upon quotes obtained from brokers for our senior notes, discounted cash flows for our 11.5% convertible debt and book value for other debt. Book value approximates fair value for our senior bank facility and second lien term loan as these instruments bear interest at a market rate.

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
Note 17 — Fair Value Measurements
Effective January 1, 2008, we adopted the new guidance for fair value measurements of financial assets and liabilities measured on a recurring basis. This new standard defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. It also clarifies that fair value should be based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. This includes not only the credit standing of counterparties involved and the impact of credit enhancements but also the impact of our own nonperformance risk on our liabilities. According to this new standard, fair value measurements are classified and disclosed in one of the following categories:
     
Level 1:
  Fair value is based on actively-quoted market prices, if available.
 
   
Level 2:
  In the absence of actively-quoted market prices, we seek price information from external sources, including broker quotes and industry publications. Substantially all of these inputs are observable in the marketplace during the entire term of the instrument, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace.
 
   
Level 3:
  If valuations require inputs that are both significant to the fair value measurement and less observable from objective sources, we must estimate prices based on available historical and near-term future price information and certain statistical methods that reflect our market assumptions.
We apply fair value measurements to certain assets and liabilities including commodity and interest rate derivative instruments, marketable securities and embedded derivatives relating to conversion and change in control features in certain of our debt instruments. We seek to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.
Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The following table summarizes the valuation of our investments and financial instruments by pricing levels as of December 31, 2009:

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
                                 
    Quoted Market Prices   Significant Other   Significant    
    in Active Markets -   Observable Inputs -   Unobservable Inputs -   Total
    Level 1   Level 2   Level 3   Fair Value
 
Oil and gas derivative contracts:
                               
Oil and gas swaps
  $     $ (12,816 )   $     $ (12,816 )
Embedded derivatives
                (28,843 )     (28,843 )
 
 
                               
Total derivative liabilities
  $     $ (12,816 )   $ (28,843 )   $ (41,659 )
 
Our commodity and interest rate derivative contracts were measured based on quotes from our counterparties, which are major financial institutions or commodities trading institutions. Such quotes have been derived using models that consider various inputs including current market and contractual prices for the underlying instruments, quoted forward prices for natural gas and crude oil, volatility factors and interest rates, such as a LIBOR curve for a similar length of time as the derivative contract term. The inputs for the fair value models for our swaps and Brent oil collars were all observable market data and these instruments have been classified as Level 2. Although we utilized the same option pricing models to assess the reasonableness of the fair values of our gas collars, an active futures market does not exist for our U.K. gas options. We based the inputs to the option models for our U.K. gas collars on observable market data in other markets to verify the reasonableness of the counterparty quotes. These U.K. gas collars are classified as Level 3. There are no outstanding oil or gas collars at December 31, 2009.
The following is a reconciliation of changes in fair value of net derivative assets and liabilities classified as Level 3:
         
    Year Ended
    December 31,
    2009
 
Balance at beginning of period
  $ (12,057 )
Total gains or losses (realized/unrealized)
       
Included in earnings
    (14,390 )
Purchases, issuance and settlements
    (2,396 )
 
Balance at end of period
  $ (28,843 )
 
 
       
Changes in unrealized gains (losses) relating to derivatives assets and liabilities still held at December 31, 2009
  $ (9,713 )
 
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Certain assets and liabilities are reported at fair value on a nonrecurring basis in our consolidated balance sheets. The following methods and assumptions were used to estimate the fair values:

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
Goodwill — Goodwill is tested annually at year end for impairment. The first step of that process is to compare the fair value of the reporting unit to which goodwill has been assigned to the carrying amount of the associated net assets and goodwill. Significant Level 3 inputs may be used in the determination of the fair value of the reporting unit, including present values of expected cash flows from operations.
When we are required to measure fair value, and there is not a market observable price for the asset or liability, or a market observable price for a similar asset or liability, we generally utilize an income valuation approach. This approach utilizes management’s best assumptions regarding expectations of projected cash flows, and discounts the expected cash flows using a commensurate risk adjusted discount rate. Such evaluations involve a significant amount of judgment since the results are based on expected future events or conditions, such as sales prices; estimates of future oil and gas production; development and operating costs and the timing thereof; economic and regulatory climates and other factors. Our estimates of future net cash flows are inherently imprecise because they reflect management’s expectation of future conditions that are often outside of management’s control. However, assumptions used reflect a market participant’s view of long-term prices, costs and other factors, and are consistent with assumptions used in our business plans and investment decisions.
Note 18 — Derivative Instruments
As discussed in Note 2 — Accounting Policies, we have oil and gas commodity derivatives, interest rate derivatives and embedded derivatives related to debt instruments. The fair market value of these derivative instruments is included in our balance sheet as follows:

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
                 
    December 31,   December 31,
    2009   2008
 
Derivatives not designated as hedges:
               
Oil and gas commodity derivatives:
               
Assets:
               
Prepaid expenses and other current assets
  $ 2,890     $ 31,649  
Other assets — long term
    318       1,702  
Liabilities:
               
Accrued expenses and other
    (6,817 )      
Other liabilities — long-term
    (9,207 )     (2,375 )
 
 
  $ (12,816 )   $ 30,976  
 
               
Embedded derivatives related to debt instrument:
               
Liabilities:
               
Other liabilities — long-term
    (28,843 )     (14,640 )
 
               
Derivatives designated as cash flow hedge:
               
Interest rate swap
               
Liabilities:
               
Accrued expenses and other
          (1,334 )
 
If all counterparties failed to perform, our maximum loss would be $3.2 million as of December 31, 2009.
The effect of the derivatives not designated as hedges on our results of operations was as follows:
                         
    Year Ended December 31,
    2009   2008   2007
 
Derivatives not designated as hedges:
                       
Oil and gas commodity derivatives
                       
Realized gains (losses)
  $ 35,422     $ (28,578 )   $ 12,048  
Unrealized gains (losses)
    (43,791 )     77,846       (89,132 )
 
 
    (8,369 )     49,268       (77,084 )
 
                       
Embedded derivatives related to debt instrument
                       
Unrealized gains (losses)
  $ (11,807 )   $ (1,180 )   $  
 
The effect of derivatives designated as cash flow hedges on our results of operations and other comprehensive income was as follows:

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
                                 
            Year Ended December 31,
    Location of            
    Reclassification            
    into Income   2009   2008   2007
 
Interest rate swap
                               
(Gain) loss recognized in other comprehensive income, net of tax
          $     $ 428     $ (852 )
(Gain) loss reclassified from accumulated other comprehensive income into income
  Interest expense     1,194       (770 )      
 
We did not exclude any component of the hedging instruments’ gain or loss when assessing effectiveness. The ineffective portion of the hedges is not material for the periods presented and is included in other income (expense).
As of December 31, 2009, our outstanding commodity derivatives covered approximately 1,020 Mbbl of oil and 1,659 MMcf of gas cumulative through 2011 and consist of fixed price swaps with BNP Paribas.
During 2007, we entered into an interest rate swap with BNP Paribas for a notional amount of $37.5 million whereby we paid a fixed rate of 5.05% and received three-month LIBOR through November 2009.
Note 19 Supplementary Cash Flow Disclosures
Cash paid during the period for interest and income taxes was as follows:
                         
    Year Ended December 31,
    2009   2008   2007
 
Interest paid
  $ 7,074     $ 15,966     $ 22,164  
 
 
                       
Income taxes paid
  $ 4,738     $ 20,088     $ 7,662  
 
Non-Cash Investing and Financing Transactions
As discussed in Note 9, we redeemed 60% of the outstanding shares of Series C Preferred Stock, for face value of $75 million with a $25 million cash payment and the issuance of $50 million Subordinated Notes.

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
We recorded $11.4 million in preferred stock dividends in 2009 for a non-cash valuation under fair value accounting relating to the redemption and modification of our Series C Preferred Stock. Prior to the fourth quarter of 2007, we paid outstanding dividends on the Series C Preferred Stock through the issuance of common stock.
In 2009 and 2008, we recorded $5.3 million and $4.5 million, respectively, in non-cash interest expense that was added to the principal balance of the 11.5% convertible notes.
Note 20 — Commitments and Contingencies
General
The oil and gas industry is subject to regulation by federal, state and local authorities. In particular, oil and gas production operations and economics are affected by environmental protection statutes, tax statutes and other laws and regulations relating to the petroleum industry. We believe we are in compliance with all federal, state and local laws, regulations applicable to Endeavour and its properties and operations, the violation of which would have a material adverse effect on us or our financial condition.
Operating Leases
We have leases for office space and equipment with lease payments of $0.6 million, $0.2 million and $0.2 million for the years ended December 31, 2010, 2011 and 2012, respectively.
Rig Commitments
Our rig commitments represent one commitment for 46 days of a rig in the U.K. We are currently considering the timing of rig deliverability and completion of the commitment.
Participation Agreement
In April 2009, we executed an agreement with Caza Petroleum Inc., a subsidiary of Caza Oil and Gas, Inc., (“Caza”) to participate in a jointly established exploration and development program covering Caza’s onshore acreage position and opportunity portfolio in the United States. We have the option but not the obligation to participate in the acquisition, exploration and appraisal activities of selected assets. Caza provides economic and engineering analysis on projects submitted for our selection. We receive 75% of Caza’s interest in exchange for $250,000 per

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
month and payment of our share of all external costs on any projects we select. We have elected to terminate the agreement effective April 2010.
Contingencies
Hess Limited, the operator of the facility supporting production from the Ivanhoe, Rob Roy, and Hamish fields (collectively, “IVRRH”), had advised us that there had been a mis-measurement of the volumes of oil produced from the IVRRH fields. As of December 31, 2009, the estimated liability from this mis-measurement was extinguished. As the settlement of the mis-measurement liability is covered under the purchase agreement for these assets, the decrease in our net liability was recorded as a decrease to goodwill during the third quarter of 2009.
Note 21 Segment and Geographic Information
We have determined we have one reportable operating segment being the acquisition, exploration and development of oil and gas properties. Our operations are conducted in geographic areas as follows:
                                                 
    2009   2008   2007
            Long-           Long           Long
            lived           lived           lived
    Revenue   Assets   Revenue   Assets   Revenue   Assets
     
United States
  $ 1,627     $ 46,172     $     $ 12,125     $     $ 6,920  
 
                                               
United Kingdom
    60,666       436,016       170,782       441,195       135,876       488,377  
Other
          1,607             2,140             4,386  
 
 
                                               
Continuing Operations
    62,293       483,795       170,782       455,460       135,876       499,683  
 
                                               
Discontinued operations — Norway
    17,550             89,660       148,605       40,188       129,693  
 
 
                                               
Total
  $ 79,843     $ 483,795     $ 260,442     $ 604,065     $ 176,064     $ 629,376  
 
 
                                               
Total International
  $ 78,216     $ 437,623     $ 260,442     $ 583,943     $ 176,064     $ 622,456  
 

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
Note 22 — Quarterly Financial Data (Unaudited)
                                 
            Second   Third   Fourth
    First Quarter   Quarter   Quarter   Quarter
    2009
Revenues from continuing operations
  $ 16,338     $ 18,082     $ 7,759     $ 20,113  
Operating expenses from continuing operations
    50,743       17,614       13,613       30,722  
Operating profit (loss) from continuing operations
    (34,405 )     468       (5,854 )     (10,609 )
Net income (loss) to common stockholders
    (19,532 )     7,124       (7,179 )     (42,618 )
Net loss from continuing operations per common share
                               
Basic
    (0.15 )     (0.31 )     (0.06 )     (0.33 )
Diluted
    (0.15 )     (0.31 )     (0.06 )     (0.33 )
Net income (loss) from discontinued operations per common share
                               
Basic
          0.36              
Diluted
          0.36              
 
                               
    2008
Revenues from continuing operations
  $ 45,809     $ 55,343     $ 44,160     $ 25,469  
Operating expenses from continuing operations
    29,944       32,528       26,074       63,999  
Operating profit (loss) from continuing operations
    15,865       22,815       18,086       (38,530 )
Net income (loss) to common stockholders
    (19,487 )     (66,733 )     75,487       56,414  
Net income (loss) from continuing operations per common share
                               
Basic
    (0.15 )     (0.56 )     0.48       0.35  
Diluted
    (0.15 )     (0.56 )     0.29       0.24  
Net income (loss) from discontinued operations per common share
                               
Basic
    (0.15 )     0.04       0.11       0.09  
Diluted
    (0.15 )     0.04       0.07       0.05  

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
Note 23 — Subsequent Events
Asset Acquisitions
On January 6, 2010, we acquired significant positions in several U.S. resource plays. We funded the initial cash contributions for these new joint ventures from existing cash reserves.
We entered into a participation agreement with Cohort Energy Company (a subsidiary of J-W Operating Company) and acquired 50 percent of Cohort’s interests in certain acreage in North Louisiana/East Texas and Western Pennsylvania, primarily in the Haynesville and Marcellus gas shale plays. Our initial investment is $15 million cash and we will pay a share of Cohort’s drilling and completion expenditures as wells are drilled over the next few years.
We also acquired 50 percent of Hillwood Energy Alabama LP’s position in Hillwood’s unproven, but highly prospective new multi-target gas shale play in Alabama with an initial net investment of approximately $8.0 million.
Series C Convertible Preferred Stock
On January 29, 2010, we and the holders of our outstanding Series C Convertible Preferred Stock corrected a technical oversight in the Subscription and Registration Rights Agreement of our Series C Convertible Preferred Stock. The amendment aligns the number of common shares reserved for the potential conversion of the Series C Convertible Preferred Stock to the terms of the Series C Convertible Preferred Stock after our partial redemption in November 2009. On March 10, 2010, we also amended in the Certificate of Designation for the Series C Convertible Preferred Stock and the $50 million Note issued to the holders of the Series C Convertible Preferred Stock for technical changes. These technical changes align certain definitions and provisions relating to potential repurchases of securities by Endeavour.
In February and March 2010, a combined 2,100 shares of our Series C Convertible Preferred Stock were converted into 1.8 million shares of our common stock.
Common Stock Issuance
On February 4, 2010, we entered into and closed a private placement of common stock pursuant to a Common Stock Purchase Agreement primarily with existing stockholders and certain directors and with certain other third-party investors to sell 23.5 million shares of our common stock, par value $0.001 per share, for aggregate net cash consideration of approximately $20.5 million. The purchase price per Share was $0.90, the closing price of our shares on the NYSE Amex on February 3, 2010. We intend to use the net proceeds from the Private Placement to partially fund our 2010 capital budget.

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
The Private Placement was made in reliance upon an exemption from the registration requirements of the Securities Act of 1933, pursuant to Section 4(2) thereof.
Junior Facility
On February 5, 2010, we announced the closing of a $25 million lending facility between us, our subsidiaries and Bank of Scotland PLC (the “Junior Facility”), with a maturity date of February 5, 2011, and interest at LIBOR plus 8%. Upon entering the Junior Facility, we borrowed $15 million against the facility. Our indebtedness under the Junior Facility remains secured by cross guarantees from our subsidiaries and a second ranking interest in the security package provided under our senior bank facility. Outstanding amounts under the Junior Facility may be prepaid.
The Junior Facility contains customary covenants, similar to those in our senior bank facility, which limit our ability to incur indebtedness, create certain liens; dispose of our assets and, make dividend payments or other distributions with respect to equity securities. The Junior Facility also includes mandatory prepayment terms for the amount of net proceeds received upon a capital raise of more than $50 million or the sale of an asset. The Junior Facility also contains a covenant to maintain a minimum fair market value of proved plus probable reserves to consolidated secured debt ratio of 2:1.
Senior Bank Facility
On February 5, 2010, we also amended our senior bank facility. Previously, the final maturity date of the Senior Bank Facility was the earlier of October 31, 2011 or the reserve tail date, being the date when the remaining borrowing base reserves are projected to be 20% or less of the initially approved borrowing base reserves. The amendment brings the maturity date of the senior bank facility into alignment with the originally expected reserve tail date and maturity of the Junior Facility by changing the final maturity date to the earlier of January 31, 2011 or the reserve tail date.
2011 Debt Maturities
With the Junior Facility and Senior Bank Facility, we will have $65 million in debt due in the first quarter of 2011, based on outstanding balances at February 28, 2010. We plan to utilize our existing U.K. oil and gas assets, as well as our growing U.S. reserve base, as a basis for refinancing and expansion of our credit facilities. We are currently in discussions with several parties concerning this process. We strive to synchronize our capital expenditures with our cash flow. However, we believe our existing U.K. reserves, including probable reserves, are of significant value and together with our U.S. assets can be used as support for increased financial resources when necessary to fund our on-going activities. We continually monitor the capital markets to evaluate the most appropriate actions in our capital market activities.

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
Strategic Alternatives for North Sea Assets
On March 15, 2010, we announced that our board of directors has approved a review of strategic alternatives for its North Sea assets. In an effort to unlock the value of our underlying North Sea assets, we will study a full range of options, including:
    Continuing to execute current operations plan;
 
    Entering into a joint venture to accelerate activities in the North Sea; and
 
    Selling specific assets or the North Sea entire business.
We will announce the results of the effort once a course of action is chosen. At the end of this review process, we may elect to make no changes.

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
Note 24 — Supplemental Oil and Gas Disclosures (Unaudited)
Capitalized Costs Relating to Oil and Gas Producing Activities
                                                 
                            Total   Discontinued    
    United   United           Continuing   Operations    
    Kingdom   States   Other   Operations   Norway (1)   Total
 
December 31, 2009:
                                               
Proved
  $ 266,893     $ 8,385     $     $ 275,278     $     $ 275,278  
Unproved
    125,996       26,817       1,740       154,553             154,553  
 
Total capitalized costs
    392,889       35,202       1,740       429,831             429,831  
 
                                               
Accumulated depreciation, depletion and amortization
    (164,703 )     (810 )           (165,513 )           (165,513 )
 
 
                                               
Net capitalized costs
  $ 228,186     $ 34,392     $ 1,740     $ 264,318     $     $ 264,318  
 
 
                                               
December 31, 2008:
                                               
Proved
  $ 232,730     $ 629     $ 9     $ 233,368     $ 65,522     $ 298,890  
Unproved
    131,688       5,876       2,132       139,696       48,714       188,410  
 
Total capitalized costs
    364,418       6,505       2,141       373,064       114,236       487,300  
 
                                               
Accumulated depreciation, depletion and amortization
    (142,686 )                 (142,686 )     (33,914 )     (176,600 )
 
 
                                               
Net capitalized costs
  $ 221,732     $ 6,505     $ 2,141     $ 230,378     $ 80,322     $ 310,700  
 

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
                                                 
                            Total   Discontinued    
    United   United           Continuing   Operations    
    Kingdom   States   Other   Operations   Norway (1)   Total
 
Year Ended December 31, 2009:
                                               
Acquisition costs:
                                               
Proved
  $ 7,589     $ 8,999     $     $ 16,588     $       $ 16,588  
Proved
    1,450       14,091       23       15,564               15,564  
Exploration costs
    49,937       17,757       (382 )     67,312       4,776       72,088  
Development costs
    11,443                   11,443       5,067       16,510  
 
 
                                               
Total costs incurred
  $ 70,419     $ 40,847     $ (359 )   $ 110,907     $ 9,843     $ 120,750  
 
 
                                               
Year Ended December 31, 2008:
                                               
Acquisition costs:
                                               
Proved
    1,178       971       27       2,176             2,176  
Exploration costs
    34,641       5,515       (62 )     40,094       22,796       62,890  
Development costs
    16,752       19             16,771       8,808       25,579  
 
 
                                               
Total costs incurred
  $ 52,571     $ 6,505     $ (35 )   $ 59,041     $ 31,604     $ 90,645  
 
 
                                               
Year Ended December 31, 2007:
                                               
Acquisition costs:
                                               
Proved
    774             18       792             792  
Exploration costs
    54,916             268       55,184       10,392       65,576  
Development costs
    7,562                   7,562       14,063       21,625  
 
 
                                               
Total costs incurred
  $ 63,252     $     $ 286     $ 63,538     $ 24,455     $ 87,993  
 

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
Results of Operations for Oil and Gas Producing Activities
                                         
                    Total   Discontinued    
    United   United   Continuing   Operations -    
    Kingdom   States   Operations   Norway (1)   Total
 
Year Ended December 31, 2009:
                                       
 
                                       
Revenues
  $ 60,666     $ 1,627     $ 62,293     $ 17,550     $ 79,843  
Production expenses
    16,911       865       17,776       5,536       23,312  
DD&A
    31,915       817       32,732       4,595       37,327  
Impairment of oil and gas properties
    31,332       12,597       43,929             43,929  
Income tax expense
    (9,746 )     (4,428 )     (14,174 )     5,787       (8,387 )
 
 
                                       
Results of activities
  $ (9,746 )   $ (8,224 )   $ (17,970 )   $ 1,632     $ (16,338 )
 
 
                                       
Year Ended December 31, 2008:
                                       
 
                                       
Revenues
  $ 170,781     $     $ 170,781     $ 89,660     $ 260,441  
Production expenses
    31,489       828       32,317       14,259       46,576  
DD&A
    65,764             65,764       14,078       79,842  
Impairment of oil and gas properties
    36,970             36,970             36,970  
Income tax expense
    18,279       (290 )     17,989       47,832       65,821  
 
 
                                       
Results of activities
  $ 18,279     $ (538 )   $ 17,741     $ 13,491     $ 31,232  
 
 
                                       
Year Ended December 31, 2007:
                                       
 
                                       
Revenues
  $ 135,876     $     $ 135,876     $ 40,188     $ 176,064  
Production expenses
    27,263             27,263       13,781       41,044  
DD&A
    67,338             67,338       7,722       75,060  
Income tax expense
    20,638             20,638       14,574       35,212  
 
 
                                       
Results of activities
  $ 20,637           $ 20,637     $ 4,111     $ 24,748  
 
(1)   We completed the divestiture of our Norwegian subsidiary on May 14, 2009. The results of operations and financial position of this subsidiary are classified as discontinued operations for all periods presented.
Oil and Gas Reserves
Proved reserves are estimated quantities of oil, gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can reasonably be expected to be recovered through existing wells with existing equipment and operating methods. The reserve volumes presented are estimates only and should not be construed as being exact quantities. These reserves may or may not be recovered and may increase or decrease as a result of our future operations and changes in economic conditions. During 2009, our oil and gas reserves were audited by independent reserve engineers. Our oil and gas reserves were prepared by independent reserve engineers at December 31, 2008 and 2007.
In the fourth quarter of 2009, we adopted revised oil and gas reserve estimation and disclosure requirements. The primary impact of the new disclosures is to conform the definition of proved reserves to the SEC Modernization of Oil and Gas Reporting rules, which were issued by the SEC at the end of 2008. The accounting standards update revised the definition of proved oil and gas reserves to require that the average, first-day-of-the-month price during the 12-month period before the end of the year rather than the year-end price, must be used when estimating whether reserve quantities are economical to produce. This same 12-month average price is also used in calculating the aggregate amount of (and changes in) future cash inflows related to the standardized measure of discounted future net cash flows. The rules also allow for the use of reliable technology to estimate proved oil and gas reserves if those technologies have been demonstrated to result in reliable conclusions about reserve volumes. The unaudited supplemental information on oil and gas exploration and production activities for 2009 has been presented in accordance with the new reserve estimation and disclosure rules, which may not be applied retrospectively. The 2008, 2007 and 2006 data are presented in accordance with FASB oil and gas disclosure requirements effective during those periods.

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
                                         
                    Total   Discontinued    
    United   United   Continuing   Operations -    
    Kingdom   States   Operations   Norway (1)   Total
 
Proved Oil Reserves (MBbls):
                                       
Proved reserves at January 1, 2006
    4,566             4,566       1,186       5,752  
Production
    (1,274 )           (1,274 )     (519 )     (1,793 )
Extensions and discoveries
                      340       340  
Revisions of previous estimates
    (8 )           (8 )     1,049       1,041  
 
Proved reserves at December 31, 2007
    3,284             3,284       2,056       5,340  
 
                                       
Production
    (1,032 )           (1,032 )     (726 )     (1,758 )
Extensions and discoveries
    522       18       540       121       661  
Revisions of previous estimates
    (643 )           (643 )     (45 )     (688 )
 
Proved reserves at December 31, 2008
    2,131       18       2,149       1,406       3,555  
 
                                       
Production
    (690 )     (4 )     (694 )     (310 )     (1,004 )
Purchases of reserves
          2       2             2  
Sales of reserves in place
                      (1,107 )     (1,107 )
Extensions and discoveries
    1,209       3       1,212             1,212  
Revisions of previous estimates
    698       (1 )     697       11       708  
 
Proved reserves at December 31, 2009
    3,348       18       3,366             3,366  
 
 
                                       
Proved Developed Oil Reserves (MBbls):
                                       
At December 31, 2007
    2,544             2,544       1,650       4,194  
 
At December 31, 2008
    1,468       7       1,475       1,302       2,777  
 
At December 31, 2009
    1,381       8       1,389             1,389  
 

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
                                         
                    Total   Discontinued    
    United   United   Continuing   Operations -    
    Kingdom   States   Operations   Norway (1)   Total
 
Proved Gas Reserves (MMcf):
                                       
Proved reserves at January 1, 2006
    17,172             17,172       7,673       24,845  
Production
    (8,556 )           (8,556 )     (328 )     (8,884 )
Extensions and discoveries
                      1,821       1,821  
Revisions of previous estimates
    3,196             3,196       (732 )     2,464  
 
Proved reserves at December 31, 2007
    11,812             11,812       8,434       20,246  
 
                                       
Production
    (6,532 )           (6,532 )     (2,322 )     (8,854 )
Extensions and discoveries
    20,370       690       21,060       52       21,112  
Revisions of previous estimates
    1,480             1,480       (1,187 )     293  
 
Proved reserves at December 31, 2008
    27,130       690       27,820       4,977       32,797  
 
                                       
Production
    (3,743 )     (320 )     (4,063 )     (686 )     (4,749 )
Purchases of reserves
          10,037       10,037             10,037  
Sales of reserves in place
                      (4,241 )     (4,241 )
Extensions and discoveries
    52,895       6       52,901             52,901  
Revisions of previous estimates
    2,034       371       2,405       (50 )     2,355  
 
Proved reserves at December 31, 2009
    78,316       10,784       89,100             89,100  
 
 
                                       
Proved Developed Gas Reserves (MMcf):
                                       
At December 31, 2007
    8,416             8,416       6,614       15,030  
 
At December 31, 2008
    6,761       234       6,995       4,917       11,912  
 
At December 31, 2009
    4,329       4,707       9,036             9,036  
 

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
                                         
                    Total   Discontinued    
    United   United   Continuing   Operations -    
    Kingdom   States   Operations   Norway   Total
 
Proved Reserves (MBOE):
                                       
Proved reserves at January 1, 2007
    7,428             7,428       2,465       9,893  
Extensions and discoveries
                      643       643  
Production
    (2,700 )           (2,700 )     (574 )     (3,274 )
Revisions of previous estimates
    524             524       927       1,451  
 
Proved reserves at December 31, 2007
    5,252             5,252       3,461       8,713  
Production
    (2,121 )           (2,121 )     (1,113 )     (3,234 )
Extensions and discoveries
    3,917       133       4,050       130       4,180  
Revisions of previous estimates
    (395 )           (395 )     (242 )     (637 )
 
Proved reserves at December 31, 2008
    6,653       133       6,786       2,236       9,022  
Production
    (1,314 )     (57 )     (1,371 )     (424 )     (1,795 )
Extensions and discoveries
    10,025       4       10,029             10,029  
Purchae of Reserves
          1,675       1,675             1,675  
Sales of Reserves
                      (1,815 )     (1,815 )
Revisions of previous estimates
    1,037       60       1,097       3       1,100  
 
 
                                       
Proved reserves at December 31, 2009
    16,401       1,815       18,216             18,216  
 
 
                                       
Proved Developed Reserves (MBOE):
                                       
At December 31, 2007
    3,947             3,947       2,752       6,699  
 
At December 31, 2008
    2,595       46       2,641       2,122       4,763  
 
At December 31, 2009
    2,103       792       2,895             2,895  
 
Standardized Measure of Discounted Future Net Cash Flows
Future cash inflows and future production and development costs are determined by applying year-end prices and costs to the estimated quantities of oil and gas to be produced. Estimated future income taxes are computed using current statutory income tax rates for where production occurs. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor.
Estimates of future cash inflows are based on prices at year-end. Oil, gas and condensate prices are escalated only for fixed and determinable amounts under provisions in some contracts. At December 31, 2009 and 2008, the prices used to determine the estimates of future cash inflows were $60.40 and $36.55 per barrel, respectively, for oil and $4.96 and $8.70 per Mcf, respectively, for gas. Estimated future cash inflows are reduced by estimated future

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
development, production, abandonment and dismantlement costs based on year-end cost levels, assuming continuation of existing economic conditions, and by estimated future income tax expense. Income tax expense, both U.S. and foreign, is calculated by applying the existing statutory tax rates, including any known future changes, to the pretax net cash flows giving effect to any permanent differences and reduced by the applicable tax basis. The effect of tax credits is considered in determining the income tax expense.
The standardized measure of discounted future net cash flows is not intended to present the fair market value of our oil and gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves in excess of proved reserves, anticipated future changes in prices and costs, an allowance for return on investment and the risks inherent in reserve estimates.
Under the full cost method of accounting, a noncash charge to earnings related to the carrying value of our oil and gas properties on a country-by-country basis may be required when prices are low. Whether we will be required to take such a charge depends on the prices for crude oil and natural gas at the end of any quarter, as well as the effect of both capital expenditures and changes to proved reserves during that quarter. Given the volatility of natural gas and oil prices, it is reasonably possible that our estimate of discounted future net cash flows from proved oil and gas reserves will change in the near term. If a noncash charge were required, it would reduce earnings for the period and result in lower DD&A expense in future periods.

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
Standardized Measure of Discounted Future Net Cash Flows
                                                 
                            Discontinued            
    United   United   Continuing   Operations -            
    Kingdom   States   Operations   Norway   Total        
 
December 31, 2009:
                                               
Future cash inflows
  $ 424,007     $ 36,799     $ 460,806     $     $ 460,806          
Future production costs
    (89,696 )     (9,893 )     (99,589 )           (99,589 )        
Future development costs
    (274,456 )     (12,602 )     (287,058 )           (287,058 )        
Future income tax expense
    (17,433 )           (17,433 )           (17,433 )        
 
 
                                               
Future net cash flows (undiscounted)
    42,422       14,304       56,726             56,726          
Annual discount of 10% for estimated timing
    (6,770 )     7,798       1,028               1,028          
 
Standardized measure of future net cash flows
  $ 49,192     $ 6,506     $ 55,698     $     $ 55,698          
 
 
                                               
December 31, 2008:
                                               
Future cash inflows
  $ 306,021     $ 4,599     $ 310,620     $ 88,039     $ 398,659          
Future production costs
    (71,242 )     (1,005 )     (72,247 )     (25,157 )     (97,404 )        
Future development costs
    (157,984 )     (2,100 )     (160,084 )     (25,579 )     (185,663 )        
Future income tax expense
    (33,977 )           (33,977 )     (17,036 )     (51,013 )        
 
Future net cash flows (undiscounted)
    42,818       1,494       44,312       20,267       64,579          
Annual discount of 10% for estimated timing
    12,548       563       13,111       1,806       14,917          
 
Standardized measure of future net cash flows
  $ 30,270     $ 931     $ 31,201     $ 18,461     $ 49,662          
 

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Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
Principal Sources of Change in the Standardized Measure
of Discounted Future Net Cash Flows
                         
    Year Ended December 31,
    2009   2008   2007
 
Standardized measure, beginning of period
  $ 49,662     $ 191,920     $ 145,541  
Net changes in prices and production costs
    (30,155 )     (144,547 )     199,343  
Future development costs incurred
    16,511       8,912       21,625  
Net changes in estimated future development costs
    (81,864 )     (105,784 )     (48,873 )
Revisions of previous quantity estimates
    22,318       (19,381 )     79,636  
Extensions and discoveries
    128,090       127,182       35,345  
Accretion of discount
    8,139       39,734       24,078  
Changes in income taxes, net
    (1,054 )     163,445       (135,233 )
Sale of oil and gas produced, net of production costs
    (56,531 )     (213,865 )     (135,020 )
Purchased reserves
    8,827              
Sales of reserves in place
    (11,514 )            
Change in production, timing and other
    3,269       2,046       5,478  
 
 
                       
Standardized measure, end of period
  $ 55,698     $ 49,662     $ 191,920  
 

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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
Under the supervision and with the participation of our management, including our chief executive officer, chief financial officer and chief accounting officer, we evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this Annual Report on Form 10-K, December 31, 2009. Based on that evaluation, our chief executive officer, chief financial officer and chief accounting officer concluded that our disclosure controls and procedures are effective 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 accumulated and communicated to management as appropriate to allow timely decisions regarding required disclosures.
Management’s Report on Internal Control Over Financial Reporting
Management of the Company is responsible for establishing and maintaining adequate internal controls over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended. Our internal controls were designed to provide reasonable assurance as to the reliability of our financial reporting and the preparation and presentation of the consolidated financial statements for external purposes in accordance with accounting principles generally accepted in the United States.
Because of its inherent limitations, internal control over financial reporting may not detect or prevent misstatements. Projections of any evaluation of the effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2009. In making this assessment, our management used the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our assessment, our internal control over financial reporting was effective as of December 31, 2009.

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KPMG LLP, an independent registered public accounting firm, audited management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2009 and issued their attestation report set forth in this Item 9A.
Changes in Internal Control over Financial Reporting
There were no changes in our internal controls over financial reporting during the quarterly period ended December 31, 2009 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Endeavour International Corporation:
We have audited Endeavour International Corporation’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Endeavour International Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Endeavour International Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Endeavour International Corporation and subsidiaries as of December 31, 2009 and 2008, and the related consolidated statements of operations, stockholders’ equity and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2009, and our report dated March 16, 2010 expressed an unqualified opinion on those consolidated financial statements.
/s/ KPMG LLP
Houston, Texas
March 16, 2010

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Item 9B. Other Information
On March 10, 2010, we amended the Certificate of Designation for the Series C Convertible Preferred Stock and the $50 million Note issued to the holders of the Series C Convertible Preferred Stock to correct technical oversights. The technical changes align certain definitions and provisions relating to potential repurchases of securities by Endeavour.
Item 10. Directors, Executive Officers and Corporate Governance of the Registrant
Our Definitive Proxy Statement for our 2010 Annual Meeting of Stockholders, when filed pursuant to Regulation 14A under the Securities Exchange Act of 1934, will be incorporated by reference into this annual report on Form 10-K pursuant to General Instruction G(3) of Form 10-K and will provide the information required under Part III, Item 10.
Our Code of Business Conduct and the Code of Ethics for Senior Officers can be found on our internet located at www.endeavourcorp.com. Any stockholder may request a printed copy of these codes by submitting a written request to our Corporate Secretary.
Item 11. Executive Compensation
Our Definitive Proxy Statement for our 2010 Annual Meeting of Stockholders, when filed pursuant to Regulation 14A under the Securities Exchange Act of 1934, will be incorporated by reference into this annual report on Form 10-K pursuant to General Instruction G(3) of Form 10-K and will provide the information required under Part III, Item 11.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholders Matters
Our Definitive Proxy Statement for our 2010 Annual Meeting of Stockholders, when filed pursuant to Regulation 14A under the Securities Exchange Act of 1934, will be incorporated by reference into this annual report on Form 10-K pursuant to General Instruction G(3) of Form 10-K and will provide the information required under Part III, Item 12.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Our Definitive Proxy Statement for our 2010 Annual Meeting of Stockholders, when filed pursuant to Regulation 14A under the Securities Exchange Act of 1934, will be incorporated by

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reference into this annual report on Form 10-K pursuant to General Instruction G(3) of Form 10-K and will provide the information required under Part III, Item 13.
Item 14. Principal Accounting Fees and Services
Our Definitive Proxy Statement for our 2010 Annual Meeting of Stockholders, when filed pursuant to Regulation 14A under the Secu