Attached files

file filename
EX-3.4 - EX-3.4 - ENDEAVOUR INTERNATIONAL CORPh80198exv3w4.htm
EX-2.2 - EX-2.2 - ENDEAVOUR INTERNATIONAL CORPh80198exv2w2.htm
EX-2.1 - EX-2.1 - ENDEAVOUR INTERNATIONAL CORPh80198exv2w1.htm
EX-12.1 - EX-12.1 - ENDEAVOUR INTERNATIONAL CORPh80198exv12w1.htm
EX-3.1.D - EX-3.1.D - ENDEAVOUR INTERNATIONAL CORPh80198exv3w1wd.htm
EX-10.22 - EX-10.22 - ENDEAVOUR INTERNATIONAL CORPh80198exv10w22.htm
EX-32.2 - EX-32.2 - ENDEAVOUR INTERNATIONAL CORPh80198exv32w2.htm
EX-99.1 - EX-99.1 - ENDEAVOUR INTERNATIONAL CORPh80198exv99w1.htm
EX-23.1 - EX-23.1 - ENDEAVOUR INTERNATIONAL CORPh80198exv23w1.htm
EX-14.1 - EX-14.1 - ENDEAVOUR INTERNATIONAL CORPh80198exv14w1.htm
EX-31.1 - EX-31.1 - ENDEAVOUR INTERNATIONAL CORPh80198exv31w1.htm
EX-31.2 - EX-31.2 - ENDEAVOUR INTERNATIONAL CORPh80198exv31w2.htm
EX-12.2 - EX-12.2 - ENDEAVOUR INTERNATIONAL CORPh80198exv12w2.htm
EX-23.2 - EX-23.2 - ENDEAVOUR INTERNATIONAL CORPh80198exv23w2.htm
EX-32.1 - EX-32.1 - ENDEAVOUR INTERNATIONAL CORPh80198exv32w1.htm
EX-21.1 - EX-21.1 - ENDEAVOUR INTERNATIONAL CORPh80198exv21w1.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, 2010
     
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 definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act:
Large accelerated filer o Accelerated filer  þ 
Non-accelerated filer o
(Do not check if a smaller reporting company)
Smaller reporting company  o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). o Yes þ No
The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant was $152.0 million computed by reference to the closing sale price of the registrant’s common stock on the NYSE-Amex on June 30, 2010, 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.
As of February 28, 2011, 24,882,292 shares of the registrant’s common stock were outstanding.
Documents Incorporated By Reference:
Portions of the registrant’s definitive proxy statement relating to the 2011 Annual Meeting of Stockholders, which will be filed within 120 days of December 31, 2010, are incorporated by reference into Part III of this Annual Report on Form 10-K.
 
 

 


 

Table of Contents
             
Part I  
 
    1  
      1  
      19  
      37  
      38  
      40  
Part II  
 
    40  
      40  
      42  
      43  
      65  
      67  
      125  
      125  
      128  
Part III  
 
       
      128  
      128  
      128  
      128  
      129  
Part IV  
 
    129  
      129  
Signatures  
 
    130  
 EX-2.1
 EX-2.2
 EX-3.1.D
 EX-3.4
 EX-10.22
 EX-12.1
 EX-12.2
 EX-14.1
 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 approximate energy equivalent of six Mcf of natural gas. This is a physical correlation and does not reflect a value or price relationship between the commodities. With respect to information relating to our working interest in wells or acreage, “net” oil and 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
Unless the context otherwise requires, references to “Endeavour,” “we,” “us” or “our” mean Endeavour International Corporation and its consolidated subsidiaries.
Our Company
We are an independent oil and gas company engaged in the production, exploration, development and acquisition of crude oil and natural gas in the U.S. and the North Sea. Our strategy is to expand and exploit our balanced portfolio of exploration and development assets using conventional and unconventional technologies in basins that have historically generated and produced substantial quantities of oil and gas and that we believe will yield commercial quantities of reserves through improved drilling and completion technologies. Finding, developing and producing oil and gas reserves in the North Sea require both significant capital and time. Recognizing this, we have sought to balance our North Sea assets, which have large potential reserves but long production-cycles, with a portfolio of assets in the U.S. that have lower costs and shorter production-cycles. We also seek to achieve a balance of oil and gas reserves in our portfolio of assets, believing that both commodities present attractive opportunities for capital returns in the future.
Our North Sea activities and assets remain a key source of value that we are actively developing to increase our overall reserves and production. Our major development projects in the U.K. sector of the North Sea — Bacchus, Greater Rochelle, and Columbus — have the potential to significantly expand our total proved reserves and production levels. These projects are in various stages of development, with Bacchus currently expected to commence oil production in the second half of 2011. Additionally, we expect that production from our two-phase development of the Greater Rochelle area will commence with first production from East Rochelle in the second half of 2012 and from West Rochelle shortly thereafter. Finally, Columbus could commence production as early as 2012. We intend to continue to actively manage our North Sea assets in a manner that maximizes value and enables us to allocate resources to effectively pursue our growth strategy.
Currently, our primary focus in the U.S. is unconventional gas shale developments targeting reserve and production growth in the Haynesville area, including the East Texas Cotton Valley gas sands, and the Marcellus area. In the Haynesville area, we have approximately 7,500 net acres with acreage located in Red River, DeSoto, Bienville and Caddo Parishes in Louisiana and in Harrison and Gregg Counties in Texas. Our Marcellus acreage is comprised of approximately 18,600 net acres in Pennsylvania located between two of the most active parts of the Marcellus play. We also have exploratory plans in emerging gas and oil plays in Alabama and Montana where early well results will determine the pace and scope of our subsequent exploration and development initiatives.
In 2011, we intend to expand upon our foundation of producing assets and undeveloped acreage in both established and emerging U.S. onshore resource plays, including the development of our leasehold positions in the Haynesville and Marcellus areas, while continuing to develop our existing assets in the North Sea. Specifically, during 2011 we intend to focus on achieving initial production from the Bacchus oil field in the North Sea.
As of December 31, 2010, our estimated proved reserves were 18.4 MMBOE, up 1.1% from 18.2 MMBOE as of December 31, 2009, of which approximately 70% were located in the U.K. and approximately 30% were located in the U.S., and 19.4% of which were proved developed reserves. Our 1.7 MMBOE of net reserve additions before production in 2010 replaced 111% of our production during the year. We also achieved average sales volume of 4,115 BOE/d for the year ended December 31, 2010, a 7.7% increase from 2009, implying a reserve life index of approximately 12.2 years based on our reserves as of December 31, 2010.
Our Business Strategy
We pursue a strategy of exploiting a balanced portfolio of exploration and development assets that has evolved over the last several years. When we commenced operations in 2004, our focus was exclusively in the North Sea. By 2009, we had built a portfolio of production and development assets in the U.K. and Norway sectors of the North Sea. In May 2009, we sold our assets and operations in the Norwegian sector of the North Sea for $150 million, and we used the proceeds from that sale to complete acquisitions of U.S. onshore interests, providing us with acreage positions and production in the Haynesville and Marcellus areas and our two emerging plays in Alabama and Montana. We believe the resource-rich plays in the U.S., with lower costs and shorter production-cycles, help provide a stable platform upon which to execute our strategy. We intend to continue developing our existing assets in the North Sea, while simultaneously pursuing the development of our domestic positions in the Haynesville and Marcellus areas and our positions in the emerging Alabama and Montana plays.
We believe this strategy will best enable us to provide an attractive return on capital for our stockholders. Several of the key elements of our business strategy include:
    Efficiently develop and commence production from our North Sea development assets. We currently have three large development projects in the North Sea — the Bacchus, Greater Rochelle and Columbus fields — which have the potential to significantly increase our current production levels over the next several years. We intend to efficiently manage our interests in each of these prospects in order to commence production in a timely and cost-effective manner. We expect to achieve first production from the Bacchus field in the second half of 2011. We expect that production from our two-phase development of the Greater Rochelle area will commence with first production from East Rochelle in the second half of 2012 and from West Rochelle shortly thereafter. Finally, Columbus is expected to commence production as early as 2012.
 
    Develop and exploit existing acreage in resource-rich plays. We have established a mix of U.S. producing assets and undeveloped acreage in both established and emerging resource plays, including the Haynesville and Marcellus areas and our emerging plays in Alabama and Montana. We have the ability to adjust our domestic drilling activities in accordance with current and future commodity prices and our operating results.
 
    Maintain a balanced portfolio of production, development and exploration assets. We intend to actively manage our assets in a manner that maximizes value and enables us to allocate resources to effectively pursue our balanced growth strategy. Recognizing this, we have established a portfolio that balances assets that are characterized by shorter production-cycles with assets that have larger potential reserves with longer production-cycles.
    Exploit potential growth opportunities in our emerging domestic plays. We have approximately 73,000 and 61,000 net acres, respectively, in exploratory plays in central Montana and western Alabama, which give us exposure to emerging oil and natural gas shale plays, respectively. We believe that the relatively modest capital investment required to drill pilot wells in each of these two areas helps to mitigate the inherent risk in attempting to develop assets in emerging plays. We may seek to explore these emerging plays following a review of the projected return on capital from these plays based on early well results.
 
    Reduce leverage and simplify our capital structure. To fund our growth over the last several years, we relied primarily on financing structures available to small and developing companies, some of which were considered relatively complicated. These financial instruments include several series of convertible notes and our senior term loan. We are currently exploring our options to replace these instruments with more traditional financing arrangements. We plan to continue strengthening our balance sheet and lowering our overall cost of capital, which we believe will give us access to a wider variety of more favorable financing options on a long-term basis.

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Table of Contents

Endeavour International Corporation
Our Competitive Strengths
We believe the following competitive strengths will help us achieve our business strategy:
    Significant North Sea development assets and attractive positions in resource-rich shale plays. We believe that successful development of our three primary development assets in the North Sea could have the potential to significantly increase our production levels over the next several years. Moreover, our assets in the U.S. cover a broad spectrum of resource plays, from established areas, such as Haynesville and Marcellus, to emerging plays, in Alabama and Montana. This combination should allow us to balance the capital intensive, long lead-time nature of our North Sea assets with the shorter development times and lower capital requirements of our U.S. properties.
 
    Balanced producing and development and exploration assets. We have taken important steps to balance our asset portfolio in several dimensions: U.S. versus U.K. properties; oil versus natural gas; and short-term versus long-term realizations. We have constructed our asset portfolio in this manner in an attempt to mitigate the risks of over-emphasizing any one of these variables. Specifically, we believe that the resource-rich plays in the U.S., with less capital-intensive and shorter production-cycles relative to our North Sea development projects, will provide a stable platform for the successful execution of our strategy by helping to provide cash flows from operations as we develop our longer-term, more capital-intensive North Sea development projects.
 
    Improving exposure to liquids. With the expected first production from our Bacchus asset in the second half of 2011, we expect that our liquids production will increase significantly. In addition, our current portfolio of assets includes other liquids-rich opportunities in the North Sea as well as upside development acreage in the Heath oil shale play in Montana. These assets and prospects should provide us with both near- and long-term liquids exposure.
    Experienced and skilled management team with proven track records. We were co-founded in 2004 by William L. Transier, our President and Chief Executive Officer, and John N. Seitz, one of our directors. Our management team has extensive technical expertise and industry experience across the full cycle of development of oil and gas assets and operations. The members of our management team, including our senior geoscience and engineering professionals, average more than 24 years of experience in the oil and gas industry. Under this management team, we have executed several significant transactions, including the sale of our Norwegian subsidiary, the sale of our Cygnus reserves in the North Sea, our recent Bacchus acquisition and several acquisitions of U.S. onshore properties. Substantially all of the members of the team have previously worked for a major oil company or a large independent producer.
  o   Our President and Chief Executive Officer, William L. Transier, was the former Chief Financial Officer of Ocean Energy, which merged with Devon Energy in 2003, and has over 35 years of experience in the oil and gas industry.
 
  o   Our Chief Financial Officer, J. Michael Kirksey, has an extensive background in both operational and financial management in the energy industry, having served in various executive roles for Metals USA, Input Output, Inc. and Keystone International, Inc.
 
  o   Carl D. Grenz, our Executive Vice President — International, has 33 years of experience in the oil and gas industry, having spent a majority of his career working for BHP Billiton and Hamilton Oil, focused in the North Sea.
 
  o   Our Executive Vice President — North America, James J. Emme, has 30 years of experience in the oil and gas industry, with an extensive background in unconventional hydrocarbon exploration and development while working for Anadarko Petroleum Corporation and Source Exploration, LLC.
Our Areas of Operation
North Sea
The North Sea is a proven resource area where we have several significant development projects, producing properties and additional exploration licenses. Although production costs are higher than conventional developments in the U.S., the quality of the oil, the political stability of the region, and the proximity of important markets with strong demand in Western Europe has made the North Sea an important oil and natural gas producing region. We believe our assets in the U.K. sector of the North Sea possess significant value that can continue to be realized in a manner that will provide us with an attractive return on invested capital.
Our development assets in the Bacchus, Greater Rochelle, and Columbus fields comprise the primary components of our U.K. North Sea portfolio, and we currently have development plans under way in each of these fields. When these projects are fully producing, they have the potential to significantly increase our current production levels over the next several years. We also have producing properties — the Alba, Bittern, Enoch and Goldeneye fields — and certain other fields where we have suspended production. We anticipate re-developing production from our suspended fields, if commercially attractive and practicable, once additional production commences from the nearby East Rochelle field.
We believe that constraints on available capital and consolidation have reduced the number of companies operating in the North Sea, which in turn has reduced competition and given us an increased ability to pursue opportunities consistent with our balanced strategy.

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Table of Contents

Endeavour International Corporation
Primary Development Fields
Bacchus
At December 31, 2010, we held a 10% working interest in our Bacchus field asset, which is operated by Apache Corporation, who owns a 50% working interest. On February 23, 2011, we closed our acquisition of an additional 20% working interest in the Bacchus development for approximately $9.2 million in cash payable at closing and approximately $6.2 million in cash payable three months after first oil is produced. In addition, we paid capital costs previously incurred by the seller of $9.4 million. Following the acquisition, we hold an aggregate working interest of 30%. As of December 31, 2010, our 0.2 MMBOE of estimated proved reserves in the Bacchus area were 95% oil.
The development of the Bacchus field was sanctioned in the second quarter of 2010 by the Department of Energy and Climate Change (“DECC”). The discovery well was drilled in 2005, followed by a down-dip sidetrack appraisal well that tested the upper part of the reservoir. The field development plan (“FDP”) for the Bacchus field calls for a subsea development with three wells to be drilled and linked to production facilities at the nearby Forties field. The 6.5 kilometer subsea bundled pipeline launched from Wick on the east coast of Scotland in early March 2011, and first production is expected to commence in the second half of 2011.
Greater Rochelle
The Greater Rochelle area is comprised of three blocks in the North Sea, including our interests in blocks 15/27 and 15/26c. We refer to these blocks as our East Rochelle field and our West Rochelle field, respectively. In the East Rochelle field in block 15/27, we hold a 55.6% working interest and are the operator, while our partner Nexen Petroleum U.K. Limited (“Nexen”) holds the remaining working interest. In the West Rochelle field in block 15/26c, we hold a 50% working interest and are the operator. Nexen and Premier Oil plc (“Premier”) have each farmed into block 15/26c for a 25% working interest. In the third block of the Greater Rochelle area, block 15/26b, Nexen and Premier are partners, each with a 50% working interest.

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Endeavour International Corporation
East Rochelle
Our reserves at the East Rochelle field are a gas/condensate mix and account for 7.5 MMBOE of our proved reserves at December 31, 2010. On February 28, 2011, the DECC approved the Rochelle FDP for Block 15/27 in the Central North Sea, now known as East Rochelle. This approval represents phase one of the development of the Greater Rochelle area. The current East Rochelle FDP calls for the subsea development to be linked, by a 30 kilometer pipeline, to production facilities on the Scott Platform. First production is planned for the second half of 2012.
West Rochelle
Nexen operated the first well in block 15/26b, which was drilled in September 2010 and encountered natural gas with an oil rim in a reservoir similar to that discovered at East Rochelle. The well was sidetracked to the north and encountered hydrocarbons that extend the Greater Rochelle area. This well confirmed the reserves on our interest in block 15/26c.
Columbus
We hold a 25% working interest in the Columbus field, which is operated by Serica Energy plc. Columbus is a gas/condensate field in the Central Graben region of the North Sea. During 2010, we, along with our partners in Columbus, agreed to study an option of producing the field using a new bridge-linked platform connected to the Lomand Platform. We expect to file an updated FDP later in 2011 with project sanction by the DECC anticipated later in the year. We believe that first production from this field could occur as early as 2012.
Producing Fields
Our four producing fields in the U.K. — Alba, Bittern, Enoch and Goldeneye — held a combined 1.6 MMBOE of proved reserves as of December 31, 2010. Sales from these fields totaled 1,057 MBOE for the year ended December 31, 2010. In addition, we hold interests in the Ivanhoe, Rob Roy, Hamish (collectively, “IVRRH”), Renee and Rubie fields, each of which is currently shut in.
In 2010, the Goldeneye field represented nearly all of our gas production in the U.K. The field was shut-in in early December 2010 due to flow assurance issues resulting from increased water production. The Goldeneye field is a mature gas field, nearing the end of its production life. When we acquired the Goldeneye field in October 2006, it contained estimated proved reserves of approximately 2,237 MBOE. From our acquisition through December 31, 2010, the Goldeneye field has produced approximately 4,571 MBOE.
In February 2011, production from the Goldeneye field was re-started to commence flow trials to study pipeline hydraulic performance. These trials are continuing and we are monitoring progress along with the field operator. The trials, when concluded, should help us determine how much more production may be expected from the Goldeneye field. In addition, the operator is evaluating options to use the Goldeneye reservoir as a carbon-capture facility, which may reduce our abandonment obligations for the field.
Production from each of our IVRRH, Renee and Rubie fields is currently suspended. Previously, each of these fields produced to a single floating production facility that experienced significant increases in operating costs. As a result, production was suspended in the first quarter of 2009 and will remain suspended until the development activities at East Rochelle are operational, which we currently anticipate to be during 2012. After the start of East Rochelle production, we expect to re-develop these fields if commercially attractive and practicable.

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Endeavour International Corporation
United States
During 2009, we began acquiring acreage in U.S. onshore resource plays. Our U.S. assets held 5.4 MMBOE of proved reserves as of December 31, 2010. We believe that our U.S. acreage provides us with development projects with shorter timeframes to first production at lower costs than our North Sea assets. In addition, our U.S. acreage covers a broad spectrum of resource plays, from established areas such as Haynesville and Marcellus areas, to emerging plays in Alabama and Montana.
Our strategy for our U.S. operations has been to employ a measured approach that seeks to balance U.S. natural gas prices with drilling costs. We plan to continue this disciplined approach, which includes:
    a one to two rig drilling program in Louisiana and East Texas for our interests in the Haynesville area and Cotton Valley trend;
 
    a measured drilling program to delineate our position in the Marcellus area while pipeline infrastructure issues are resolved; and
 
    a thorough analysis of test well results in Alabama and Montana before finalizing any development plans in these exploratory areas.
We believe this approach in the U.S. should provide flexibility to adjust our drilling activity in accordance with current and future commodity prices and our operating results, while still allowing our U.S. operations to grow and provide near-term return on capital to balance our longer production-cycle U.K. projects.
Haynesville Area
The Haynesville area 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 area, including the overlying Jurassic Cotton Valley Sandstone and Bossier Shale intervals.
Through several transactions, we have acquired non-operated interests in both producing wells and prospective acreage in the Haynesville area. In October 2009, we purchased interests in 24 wells and certain proved undeveloped locations in North Louisiana and East Texas for $15 million in cash. These 24 wells produce primarily from the Cotton Valley trend. In 2010, we acquired additional acreage in the Haynesville and Marcellus areas for a combined $22.5 million.
In the Haynesville area, we have had drilling activity in the Woodardville, Jamestown, Bull Bayou, Metcalf and Grand Cane fields in Louisiana, and the Willow Springs field in East Texas. During 2010, we drilled 12 Haynesville Shale wells, all of which were successful.

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Endeavour International Corporation
Marcellus Area
The Marcellus area is a Middle Devonian-aged shale that underlies much of Pennsylvania, New York, Ohio, West Virginia and adjacent states. Within the past few years, advances in two technologies, fracture stimulation and horizontal drilling, have produced promising results in the Marcellus area. These developments have resulted in significantly increased leasing and drilling activity in the area. We have acquired interests in the Marcellus area in several project areas, including portions of Cameron, Elk, Potter, McKean, Jefferson, Clarion and Clearfield counties, Pennsylvania.
During 2010, we successfully completed one well, which is now on production, and commenced drilling the first of two planned horizontal tests to further evaluate the Daniel Field in Cameron County. The first horizontal test well was successfully drilled and is waiting on completion. We are currently drilling the second test well and may drill additional wells to delineate the area. In parallel, we are working on expanding pipeline infrastructure, including options to connect with one of three major pipelines in Cameron County.
Alabama
We hold non-operating interests in approximately 61,000 net acres with exposure to emerging gas shale plays in western Alabama. We believe that our position allows us to target multiple gas shale intervals, with a primary focus on the Devonian shale. We drilled two vertical pilot wells during 2010 and are evaluating the results of these wells for future horizontal re-entries and/or completion tests before formulating an appropriate completion and development plan.
Central Montana
We own non-operating interests in approximately 73,000 net acres in central Montana, with exposure to the Mississippian Heath oil-prone source shale. This region has historically produced a significant amount of oil from the Cretaceous through the Mississippian reservoirs. We currently plan to participate in the drilling of three vertical pilot wells during 2011. 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, 2010, 2009 and 2008 included the following:

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Endeavour International Corporation
                         
    Oil   Gas   Oil Equivalents
 
 
  (MBbls)   (MMcf)   (MBOE)
2010:
                       
United Kingdom
    3,664       56,177       13,027  
United States
    59       31,777       5,355  
 
 
    3,723       87,954       18,382  
 
 
                       
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  
 
Our proved undeveloped reserves are primarily related to our development projects in the UK and the results of successful exploration drilling during 2010 in the U.S. We expect our proved undeveloped reserves in the UK to become proved developed reserves over the next three years as development plans are completed and production commences on existing development projects at Bacchus, Rochelle and Columbus. In the U.S., we have four wells that are either being completed or awaiting completion at December 31, 2010. Once completed, the proved undeveloped reserves associated with these wells will transfer to proved developed reserves. See Note 5 to our consolidated financial statements in this Annual Report on Form 10-K for additional information on the costs associated with our proved developed reserves and unproved properties. Our proved developed and undeveloped oil and gas reserves at December 31, 2010, 2009 and 2008 included the following:

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Endeavour International Corporation
                         
    Proved   Proved    
    Developed   Undeveloped   Total Proved
    Reserves   Reserves   Reserves
 
 
  (MBOE)   (MBOE)   (MBOE)
2010:
                       
United Kingdom
    1,333       11,694       13,027  
United States
    2,227       3,128       5,355  
 
 
    3,560       14,822       18,382  
 
 
                       
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  
 
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 — International and Executive Vice President — North America. In the third quarter of 2010, we established a new “Technology and Reserves” committee of the board of directors. The committee supports the board by providing increased focus on emerging technologies in the upstream industry and oversight of our reserve evaluation and reporting processes. Reserves are reviewed internally with senior management quarterly and presented to the Technology and Reserves Committee and our Board of Directors on an annual basis for their review.
For 2010 and 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, our proved oil and gas reserves were estimated by NSAI.
Each year, our internal technical staff evaluates 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

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the quantity of oil and gas reserves and provide our estimates, analysis and data to our independent reserve engineers.
For 2008, we provided our analysis and data to NSAI for their independent estimates using the Securities and Exchange Commission (“SEC”), 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 estimate of 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, and reservoir engineers, who have 10 to 35 years of experience in their technical fields. Our Director of Reservoir Engineering, who has over 25 years of experience and a masters degree in petroleum engineering, supervises our technical professionals in the evaluation and estimation of our oil and gas reserves. 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.

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2011 Planned Capital Expenditures
We anticipate spending approximately $150 million during 2011 to fund our oil and gas activities in the U.S. and U.K., with approximately 60% of those expenditures anticipated to be focused on our U.K. assets. In the U.K., our activity during 2011 will be primarily concentrated on the Bacchus and Greater Rochelle development projects. At the Bacchus project, we plan to drill three production wells and install the infrastructure to allow first production in the second half of 2011. At the Greater Rochelle project, our focus will be completing engineering and procuring long lead-time equipment to prepare Greater Rochelle for a 2012 first production date from the East Rochelle area. We also intend to begin actual construction of the subsea infrastructure and modifications to the Scott platform to prepare it for production from the Greater Rochelle area. Additionally, we expect to continue to further our development program at our Columbus project, including ongoing engineering assessments for future production and commercial off-take solutions.
Our primary focus during 2011 in the U.S. will be in the Haynesville and Marcellus areas as we believe this acreage contains near-term production potential. The ongoing U.S. program and expenditures will be tailored based on early drilling results and U.S. gas prices in 2011. During 2011, we expect to further evaluate our two existing frontier plays in Alabama and Montana through the drilling of additional test wells.
We intend to fund our capital expenditures through cash on hand and cash flow generated from operations. The majority of our cash on hand was acquired through our capital raising activities in 2010, including our 15.0% senior term loan due 2013 (the “Senior Term Loan”) and the sale of our Cygnus reserves. The timing, completion and progress of our 2011 capital program is subject to a number of factors, including availability of capital, drilling results, drilling and production costs, availability of drilling services and equipment, partner approvals and technical work. Based on these and other factors, we may increase or decrease our planned capital program or prioritize certain projects over others.
For a complete discussion of our available sources of liquidity and our expected financing needs, please see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Financial Resources.”
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 and resources.
On October 31, 2006, we purchased producing properties in the U.K. (the “Talisman Acquisition”) through the purchase 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.

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While working to complete and integrate these acquisitions, we also moved forward in our drilling program. 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 three significant development projects ongoing in the U.K. — Bacchus, Columbus, and Rochelle.
In 2008, we initiated operations in the U.S. and announced our first production there in January 2009.
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 (the “Norway Sale”). 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 allowed 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. signified our expansion into resource plays in the onshore U.S.
In October 2010, we sold our interests in the Cygnus reserves in the Southern Gas Basin of the North Sea for $110 million (the “Cygnus Sale”).
Also in October 2010, our Board of Directors authorized a consolidation of our common stock, in the form of a one-for-seven share reverse stock split. This consolidation was effective at the opening of trading on November 18, 2010. As a result of the share consolidation, every seven shares of our common stock outstanding were automatically combined into one share of our common stock.
In November 2010, we signed a definitive agreement to acquire an additional 20% working interest in the Bacchus development, for a cash consideration at closing of $9.6 million and $6.4 million three months after first oil production. Closing was completed February 2011.
Our activities have been funded through various debt and equity offerings since our inception. During the year ended December 31, 2010, we had the following debt and equity outstanding in addition to our common stock:
    6% Senior Convertible Notes — During 2005, we issued in a private offering $81.25 million aggregate principal amount of convertible senior notes due in January 2012.
 
    11.5% Convertible Senior Bonds — In January 2008, we issued 11.5% Convertible Bonds due 2014 for gross proceeds of $40 million pursuant to a private offering to a sophisticated investor in Norway.
 
    Senior Term Loan — In August 2010, we entered into a credit agreement with Cyan Partners, LP, as administrative agent, and various lenders for a senior, secured term loan, in the aggregate amount of $150 million, which was subsequently increased to $160 million.

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    Senior Bank Facility — In 2006, we issued a $225 million senior bank facility, which was subject to a borrowing base limitation with interest of LIBOR plus 1.3%. We terminated the Senior Bank Facility and repaid the outstanding indebtedness in its entirety on August 16, 2010
 
    Junior Facility — In the first quarter of 2010, we entered into the $25 million junior facility, which had a maturity date of February 5, 2011, and bore interest at LIBOR plus 8%. We terminated the Junior Facility and repaid the outstanding indebtedness in its entirety on August 16, 2010.
 
    $50 million Subordinated Notes — In November 2009, we issued an aggregate $50 million of subordinated notes due 2014.
 
    Series C Preferred Stock — In 2006, we issued $125 million of convertible preferred stock. In November 2009, we redeemed 60% of the outstanding shares of Series C Preferred Stock 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 of Subordinated Notes.
Each of these debt and equity offerings is explained more fully in Note 9 and Note 12 to the Consolidated Financial Statements herein for.
Geographical Data
We operate in one industry segment, that being oil and gas exploration and production, in two geographical areas. See Note 24 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

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Production. Our sales in the U.S. are sold through our arrangements with the operators of the fields, with the majority of the sales being to Cohort Energy.
Employees
As of March 4, 2011, we have 46 full-time employees and 12 consultants, primarily in the operations area. We believe that we maintain good relationships with our employees, none of whom are covered by a collective bargaining agreement.
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 a primary goal of our operations and an integral part 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.
There are a number of new and forthcoming rules that may impact our North Sea operations. In response to the Deepwater Horizon Incident, the DECC has announced plans to increase rig inspections. In addition, early this year the European Commission intends to impose new rules for offshore platforms that will require spill response plans; increase regulatory requirements for equipment, such as blowout preventers; and require operators to pay for any environmental damage within 200 miles of a blowout. Our operations in the North Sea will also be subject to the European Union’s REACH program, which requires the registration and ultimate phase out of certain hazardous chemicals. In order to implement the requirements of the REACH program in the offshore production sector, the DECC has issued amendments to the Offshore Chemicals Regulations that will enter into force in early 2011. These regulations will control all operational and non-operational discharges from offshore production platforms. Finally, depending on the scale of our operations, our offshore production facilities may be subject to compliance obligations under the EU Emissions trading system or impacted by carbon tax proposals under consideration in the U.K. Compliance with the above regulations may cause us to incur additional costs in our North Sea operations.

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United States
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 our operations.
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 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 well plugging or pit closure to prevent future contamination.
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. We routinely utilize hydraulic fracturing techniques in many of our natural gas well drilling and completion programs. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. However, the EPA recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s Underground Injection Control Program. While the EPA has yet to take any action to enforce or implement this newly asserted regulatory authority, industry groups have filed suit challenging the EPA’s recent decision. At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, and a committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices. Legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In addition, some states have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations. For example, Pennsylvania, Colorado, and Wyoming have each adopted a variety of well construction, set back, and disclosure regulations limiting how fracturing can be performed

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and requiring various degrees of chemical disclosure. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, our fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.
Climate Change
Globally, our operations may be impacted by various international, national, and local efforts to respond to climate change by controlling greenhouse gas (“GHG”) emissions. With the first commitment period of the Kyoto Protocol due to expire in 2012, there is substantial uncertainty as to the structure of a future international climate change regime. However, any new international agreements and domestic laws to implement them may adversely impact our operations by imposing GHG emission limits on our activities and potentially reducing demand for our products. Within Europe, the European Union has announced its plans for the next phase of the emissions trading system, running from 2013 to 2020, and therefore our activities in the North Sea are still potentially subject to the impacts of GHG limitations. Many other countries, including the United States, are weighing a variety of legislative and regulatory strategies that may impose controls on GHG emissions.
Beginning in 2009, the United States Environmental Protection Agency (“EPA’) took a series of steps to begin regulating GHG emissions under the Clean Air Act. As of January 2, 2011, the EPA’s rules impose limitations on GHG emissions from motor vehicles and certain large stationary sources. In addition, the EPA has issued regulations requiring certain sectors to monitor and report their greenhouse gas emissions. Petroleum refineries must report their emissions for the 2010 calendar year in 2011. On January 1, 2011, our exploration and production activities also became subject to the monitoring and reporting requirements, and we will incur costs related to compliance with these regulations.
In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal.
The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases in areas where we operate could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we

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produced. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations.
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 financial condition and results of operations.
We have made, and will continue to make, expenditures in connection with our effort to comply with environmental laws and regulations. We believe that we are in compliance with applicable environmental laws and regulations currently 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 potential costs of cleanup obligations, 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.

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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;
 
    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.

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Offices
Our principal executive offices are located at 1001 Fannin Street, Suite 1600, Houston, Texas 77002, and our telephone number is (713) 307-8700. Certain of our executive officers are also located in our offices at 114 St. Martin’s Lane, London WC2N 4BE England and 1125 17th Street, Suite 1525, Denver, Colorado 80202. We also have an office in Aberdeen, United Kingdom.
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, Nominating Committee and Technology & Reserves 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 chief financial officer.
Information contained on or connected to our website is not incorporated by reference into this Annual Report on 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.

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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, 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;
 
    cost and access to natural gas gathering, treatment and pipeline facilities;
 
    business strategy and the availability of acquisition opportunities; and

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    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. 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. and U.K. and 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, which subjects us to increased costs in order to comply with applicable laws and regulations as well as significant uncertainties due to the potential for such laws and regulations to change and evolve. Applicable legislation and regulations are 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.

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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. As such, we may become subject to certain requirements, obligations and timelines as established or demanded by the holder of the oil and gas mineral rights and such requirements or obligations may adversely impact our operations, cash flow and capital plans.
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., U.K. and other world economies are slowly recovering from a recession which began in 2008 and extended into 2009. Growth has resumed, but remains 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. Because 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.
Due to these and other 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 (i) meet our obligations as they come due, (ii) refinance or extend the maturity of our outstanding 6% Senior Convertible Notes which would result in the Senior Term Loan maturing and becoming due and payable in full on October 14, 2011, or (iii) 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, results of operations and prospects.
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

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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;
 
    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 future rate of growth and ability to replace our production.
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. 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.

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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.
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 one 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 expected cash flows and 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.
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.

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Our operations are sensitive to currency rate fluctuations.
Our operations are sensitive to fluctuations in foreign currency exchange rates, particularly between the U.S. dollar and the British pound. Our financial statements, presented in U.S. dollars, are affected by foreign currency fluctuations through both translation risk and transaction risk. Volatility in exchange rates may adversely affect our results of operation, particularly through the weakening of the U.S. dollar relative to other currencies.
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 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 continue to pursue strategic acquisitions of new properties or businesses that expand our current asset base and potentially offer unexploited reserve potential. Our growth strategy 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;

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    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. Consistent with industry practices, we typically are only able to perform limited reviews of the properties we seek to acquire. As a result, among other risks, our initial estimates of reserves, and the costs associated with developing those estimated reserves, may be subject to revision following an acquisition, which may materially and adversely impact the desired benefits of the acquisition.
Our expectations for future drilling and development activities will be realized over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of such activities.
We have identified drilling locations, prospects for future drilling opportunities and development plans for our commercial discoveries, including development, exploratory and other drilling and enhanced recovery activities. These drilling and development locations and prospects represent a significant part of our future drilling and development 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. In particular, delays in obtaining regulatory approvals relating to our field development programs for our North Sea discoveries can materially impact our ability to commence production at these discoveries which would materially impact our reserves, cash flow and results of operations. Furthermore, 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 and other technical data, which cannot ensure the commercial success of a prospect.
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. Seismic data and visualization techniques only assist geoscientists and geologists in identifying subsurface structures and hydrocarbon indicators and 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 and the inherent uncertainties surrounding the evaluation of exploration prospects, we could incur losses as a result of exploratory drilling expenditures. Poor results

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from drilling activities would 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 and adversely from the estimated quantities and net present value of reserves owned by us.
A significant portion of our total estimated net proved reserves at December 31, 2010 were undeveloped, and those reserves may not ultimately be developed.
At December 31, 2010, approximately 81% 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 materially reduce our ability to borrow money and 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

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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 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 the U.S. 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.
We are not the operator of our producing fields and 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.

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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, outcomes from future drilling activity and assumptions relating to ongoing operations and maintenance of producing wells. Should these estimates prove inaccurate, actual production could be adversely impacted. Furthermore, downturns in commodity prices could make certain drilling activities or production uneconomical, which would also adversely impact production. We may also 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 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, because few of the structures in the North Sea have been removed. Because experience in limited, we cannot precisely predict the costs of any future decommissions for which we might become obligated. Furthermore, we are required to post collateral as security over certain of our decommissioning liabilities in the North Sea. If actual decommission or abandonment costs exceed our estimates or reserves to satisfy such obligations, or we are required to provide a significant amount of collateral in cash or other security for these future costs, our financial condition, results of operations and prospects could be materially adversely affected.

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Risks related to access to capital and financing
Our development and exploration operations 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 Term Loan. Our cash flow from operations and access to capital is subject to a number of variables, including:
    our oil and gas 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.
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 a possible loss of properties and a decline in our natural gas, crude oil and natural gas liquids reserves.
Our debt levels could negatively impact our financial condition, results of operations and business prospects.
As of December 31, 2010, we had $349.6 million in outstanding indebtedness. Our level of indebtedness could have important consequences on our operations, including:

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    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. Furthermore, some of our existing debt instruments contain certain restrictions on our ability to repay other debt. For example, our Senior Term Loan prohibits cash on hand from being used to repay any debt other than that extended pursuant to the related Credit Agreement.
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.
Failure to satisfy certain covenants in our Senior Term Loan could cause this debt to come due prematurely.
Unless we are able to successfully refinance or extinguish our outstanding 6% Convertible Senior Notes due 2012 and extend the ability of the holders of our 11.5% Convertible Senior Bonds due 2014 to require us to repurchase such notes, our Senior Term Loan will mature and become payable in full on October 14, 2011. If required to repay our Senior Term Loan in full on that date, our available cash would be severely impacted. We would also need to find alternative sources of liquidity to fund the repayment of the Senior Term Loan and our ongoing development and exploration operations. Therefore, our failure to repay the Senior Term Loan when due would be an event of default with respect to our other outstanding indebtedness, which could cause all $349.6 million of our debt outstanding at December 31, 2010 to become immediately due and payable. We can provide no assurance that we would be able to find alternative sources of liquidity on commercially reasonable terms, or at all, if required.

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A change of control may adversely affect our liquidity and require refinancing of certain debt instruments.
Upon certain specified change of control events, each lender under our debt agreements may cancel the facility and declare as due and payable any outstanding loans plus accrued and unpaid interest, outstanding letters of credit and other outstanding fees. 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.
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 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 and cleanup costs, 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 have complied in the past. Similarly, we cannot always precisely predict the potential impact of

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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 emissions of 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 and state legislative regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. We routinely utilize hydraulic fracturing techniques in many of our natural gas well drilling and completion programs. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. However, the EPA recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s Underground Injection Control Program. While the EPA has yet to take any action to enforce or implement this newly asserted regulatory authority, industry groups have filed suit challenging the EPA’s recent decision. At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities. Legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In addition, some states have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations. For example, Pennsylvania, Colorado, and Wyoming have each adopted a variety of well construction, set back, and disclosure regulations limiting how fracturing can be performed and requiring various degrees of

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chemical disclosure. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, our fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.
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.
There are a number of programs at the international, national, and local levels that aim to reduce greenhouse gas emissions. Changes to the existing laws or the enactment of new laws and regulations could increase our operating costs and reduce demand for our products. At this time, there is substantial uncertainty about the future of GHG emission limitations in the areas where we operate. For example, the first commitment period of the Kyoto Protocol is due to expire in 2012. Because the Cancun negotiations failed to reach a binding global agreement on climate change, we face uncertainty regarding the structure of a future international regime and potential implementing national laws addressing GHGs.
Rapidly evolving domestic legal and regulatory structures governing GHG emissions may increase the costs imposed upon our operations. For example, since December 2009, the United States Environmental Protection Agency has declared that GHGs threaten the environment, imposed limitations on GHGs from mobile sources and certain large stationary sources, and required certain industries to monitor and report their GHG emissions. These rules are all currently subject to legal challenges, but to this point, federal courts have refused to prevent EPA from implementing them. In addition, by the end of 2012, the EPA intends to impose New Source Performance Standards under the Clean Air Act that will apply to all fossil-fuel fired power plants and petroleum refineries. To the extent we or our customers are subject to any of these regulations, we may face increased costs and decreased demand for our product.
The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produced. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations.
The recent adoption of derivatives legislation by the United States Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.
The United States Congress adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The new legislation, known as the Dodd-Frank Wall Street

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Reform and Consumer Protection Act (the “Act”), was signed into law by the President on July 21, 2010 and requires the Commodities Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. In its rulemaking under the Act, the CFTC has proposed regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or positions would be exempt from these position limits. It is not possible at this time to predict when the CFTC will finalize these regulations. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks that we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material, adverse effect on us, our financial condition, and our results of operations.
Certain federal income tax deductions currently available with respect to oil and natural gas exploration and development may be eliminated as a result of proposed legislation.
Legislation has been proposed that would, if enacted into law, make significant changes to U.S. federal income tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development 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 these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of this legislation or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could negatively impact the value of an investment in our common stock.

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Risks related to potential impairments
Our financial results could be adversely affected by goodwill impairments.
As a result of mergers, acquisitions and dispositions, at December 31, 2010 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.
Lower oil and gas prices and other factors may result in 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, plus the lower of cost or fair market value for unproved properties. This quarterly test is called a “ceiling test.” If net capitalized costs of our oil and gas properties exceed this ceiling test, we must charge the amount of the excess to earnings. 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. 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.
Risks relating to our common stock
An active liquid trading market for our common stock may not be maintained and the trading price of our common stock may be volatile.
Liquid and active trading markets usually result in less price volatility and more efficiency in carrying out stockholders’ purchase and sale orders. Smaller capitalized companies like ours often experience substantial fluctuations in the trading price of their securities. An active and liquid trading market for our common stock may not be maintained. In 2010, we undertook a

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one-for-seven share consolidation which significantly reduced the number of shares outstanding and eligible for trading. The trading price of our common stock has fluctuated significantly and may be subject to similar fluctuations in the future. The market price of our common stock could vary significantly as a result of a number of factors, some of which are beyond our control.
If we, our existing stockholders or holders of our securities that are convertible into shares of our common stock sell any 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 February 28, 2011, we had approximately 24.9 million shares of common stock outstanding. Of those shares, approximately 0.9 million shares are restricted shares subject to vesting periods of up to three years. The remainder of these shares is freely tradable.
In addition, 0.3 million shares are issuable upon the exercise of presently outstanding stock options under our employee incentive plans and 0.1 million shares are issuable upon the exercise of presently outstanding options and warrants outside our employee incentive plans. Also 2.3 million shares are issuable upon the conversion of our 6% Convertible Senior Notes and 5.1 million shares are issuable upon conversion of our Series C Preferred Stock, based upon the conversion price of $8.75 per share, and 3.4 million shares are issuable upon conversion of our 11.5% Convertible Bonds, based on a conversion price of $16.52.
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.

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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.
Item 1B. Unresolved Staff Comments
None.

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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 2010, 2009 and 2008:
                                                 
    Productive Wells     Dry Holes     In Progress Wells  
    Gross     Net     Gross     Net     Gross     Net  
 
Exploration
                                               
2010:
                                               
United Kingdom
    3       0.38       1       0.10              
United States
                            2       1.00  
 
                                               
2009:
                                               
United Kingdom
    3       0.82       2       0.52       1       0.10  
United States
    3       1.32       1       0.22       3       1.04  
 
                                               
2008:
                                               
United Kingdom
                            2       0.68  
United States
    1       0.20                   1       0.10  
Discontinued Operations — Norway
    5       0.14                          
 
                                               
Development
                                               
2010:
                                               
United Kingdom
                            2       0.05  
United States
    13       3.00                   2       1.00  
 
                                               
2009:
                                               
United Kingdom
    2       0.05                   1       0.02  
 
                                               
2008:
                                               
United Kingdom
                            1       0.02  
Discontinued Operations — Norway
    3       0.08                          
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, 2010, our productive wells included the following:
                                 
    Oil   Gas
    Gross   Net   Gross   Net
 
 
                               
United Kingdom
    44       4.74       5       0.35  
United States
    2       1.12       42       12.15  
 
 
                               
Total
    46       5.86       47       12.50  
 
Acreage
The following table sets forth certain information regarding our developed and undeveloped acreage as of December 31, 2010, in the areas indicated.
                                 
    Developed   Undeveloped
    Gross   Net   Gross   Net
 
 
                               
United Kingdom
    31,790       8,108       252,052       70,047  
United States
    12,425       5,561       574,871       165,065  
 
 
                               
Total
    44,215       13,669       826,923       235,112  
 
As of December 31, 2010, we had approximately 45,912, 25,123 and 51,423 net acres that are scheduled to expire by December 31, 2011, 2012 and 2013, respectively, if we take no action to continue the term of the underlying license through operational or administrative actions. This includes all of our acreage in Alabama and Montana, where we have 134,420 net acres. We intend to monitor the results of test wells and continue to evaluate our current drilling before determining further appraisal or development plans in these two states. For our other acreage in the U.S. and U.K., 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 Annual Report Form 10-K. Additional detail of production costs is contained in Note 24 to our consolidated financial statements under Item 8 of this Annual Report on Form 10-K.

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Reserves
Our estimates of proved reserves, proved developed reserves and proved undeveloped reserves at December 31, 2010, 2009 and 2008 and changes in proved reserves during the last three years are contained in Note 24 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.”
Reverse Stock Split
In October 2010, our Board of Directors authorized a share consolidation of our common stock, in the form of a one-for-seven reverse stock split. This consolidation was effective at the opening of trading on November 18, 2010. As a result of the share consolidation, every seven shares of our common stock outstanding were automatically combined into one share of our common stock. Each shareholder continues to hold the same percentage of our outstanding common shares. The shares were rounded up to the next whole share for those holders who would have otherwise received fractional shares. The share consolidation was intended to make our common stock available to a broader range of investors and reposition the company’s trading metrics.
All share information and prices per share discussed in this Annual Report have been restated to reflect the share consolidation.

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Historical Stock Prices
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.
                                 
    2010   2009
    High   Low   High   Low
 
 
                               
First Quarter
  $ 10.36     $ 5.60     $ 7.21     $ 3.22  
Second Quarter
    12.18       8.68       15.47       5.81  
Third Quarter
    10.22       6.72       10.50       7.14  
Fourth Quarter
    14.16       8.12       9.10       5.74  
Holders
As of February 28, 2011, the number of holders of record of our common stock was 199. We believe that there are a number of additional beneficial owners of our common stock who hold such shares in street name.
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. 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 and the agreements governing our debt obligations. 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.
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, certain of our debt facilities contain restrictions on the payment of dividends to the holders of our common stock.
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, at 4.5% or 4.92%, respectively, since November 2009 and at 8.5% or 8.92%, respectively, in prior periods; and
 
    payable to the preferred stock investors prior to payment of any other dividend on any other shares of our capital stock.

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The Series C Preferred Stock will participate in any dividends paid on our common stock. Since 2007, 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 for each of the five years ended December 31, 2010. Significant property acquisitions and dispositions during these periods have materially affected the comparability of our year-to-year 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.
                                         
Summary Financial Data (1)
    Year Ended December 31,
(Amounts in thousands, except per share data)    2010   2009   2008   2007   2006
 
Summary Income Statement Data:
                                       
Revenues
  $ 71,675     $ 62,293     $ 170,781     $ 135,876     $ 24,881  
Operating Profit (Loss)
    1,327       (50,398 )     18,236       23,778       (11,516 )
Net Income (Loss) to Common Shareholders
    54,304       (62,206 )     45,681       (60,315 )     (8,829 )
 
                                       
Net Income (Loss) Per
                                       
Common Share — Basic:
                                       
Continuing Operations
  $ 2.34     $ (5.84 )   $ 0.82     $ (3.50 )   $ (0.56 )
Discontinued Operations
          2.50       1.67       0.07       (0.14 )
 
Total
  $ 2.34     $ (3.34 )   $ 2.49     $ (3.43 )   $ (0.70 )
 
 
                                       
Net Income (Loss) Per Common Share — Diluted:
                                       
Continuing Operations
  $ 1.95     $ (4.70 )   $ 0.59     $ (3.50 )   $ (0.56 )
Discontinued Operations
          2.50       1.20       0.07       (0.14 )
 
Total
  $ 1.95     $ (2.20 )   $ 1.79     $ (3.43 )   $ (0.70 )
 
 
                                       
Summary Balance Sheet Data:
                                       
Working Capital
  $ 71,145     $ 24,885     $ 22,902     $ 37,198     $ 47,431  
Total Assets
    750,287       538,879       737,470       747,623       774,470  
Debt
    345,306       223,385       227,855       266,250       306,250  
Convertible Preferred Stock
    53,152       59,058       125,000       125,000       125,000  
Equity
    154,618       60,133       117,971       70,149       116,828  

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(1)   Includes the following:
 
    •   acquisition of producing properties and exploration acreage in the U.S. in 2009 and 2010;
 
    •   disposition of our interests in the Cygnus reserves in 2010 for a gain of $87.2 million;
 
    •   acquisition of Talisman Expro Limited in November 2006;
 
    •   acquisition of working interests in the Enoch and Bacchus prospects in 2006; and
 
    •   unrealized gains (losses) on derivatives of $12.3 million, $(55.6) million, $76.7 million, $(89.1) million and $34.5 million in 2010, 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.
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 and resources. Historically, we have focused our operations in the North Sea, but have expanded our focus to target U.S. onshore resource plays with shorter production-cycle times and compelling risk/return profiles.
Implementing this shift in strategy over the last several years has required measured and specific steps. From inception in 2004 through the end of 2007, we built a portfolio of production and development assets in the UK and Norway through acquisition, exploration and development activities. During 2008, these assets generated sufficient cash flow to repay $32 million of debt while continuing to support our capital program. We sought to identify opportunities that would shorten production-cycle times and provide cash flow while still fitting into our balanced,

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disciplined approach. To strike that new balance in our portfolio, the 2008 capital program included participation in our first two U.S. exploration wells.
In May 2009, we sold our assets and operations in the Norwegian sector of the North Sea for $150 million. We then looked to further balance the capital intensive, long lead-time nature of our North Sea assets with entry into the onshore U.S. in active hydrocarbon producing areas. We targeted U.S. onshore petroleum systems that we believe have shorter production-cycle times and compelling risk/return profiles. Proceeds from the sale of our Norwegian operations enabled us to complete acquisitions of U.S. onshore interests, providing us with acreage positions and production in the Haynesville and Marcellus areas. We also purchased additional acreage, providing exposure to emerging resource plays in Alabama and Montana.
On October 19, 2010 we completed the Cygnus Sale for $110 million. Upon the closing of this transaction, we recognized a gain of $87.2 million. The cash proceeds were not burdened by any taxes payable and are primarily being used to accelerate our development projects and fund our purchase of an additional 20% in the Bacchus field, which we closed this acquisition in February 2011.
Our North Sea activities and assets represented the majority of our activity in 2008. During 2009, our North Sea assets continued to represent the primary focus of our activities, but we also began pursuing activity in the U.S. and sold our Norwegian assets and operations. Our major development projects — Bacchus, Columbus, Cygnus and Rochelle — continued to move toward development throughout the year with appraisal wells drilled at Cygnus and Rochelle in early 2009. In the U.S., we expanded our operations primarily by completing the acquisitions of exploration acreage and producing properties in 2009. During 2010, we expanded our U.S. production and operations and sold Cygnus, while advancing our remaining development projects in the U.K.
Our realized price per BOE, before derivatives, increased from $44.44 per BOE in 2009 to $47.72 per BOE in 2010. Our revenues have increased from $62.3 million for the year ended December 31, 2009 to $71.7 million for 2010 primarily as a result of higher commodity prices before the effect of our hedging activities, and higher production volumes from our producing assets. Increases in prices in the first half of 2008, largely as a result of oil prices climbing to record levels in the summer of 2008 and gas prices in our markets improving, helped our revenue grow to $170.8 million in 2008, however the subsequent decrease in commodity prices and normal declines in our production during 2009 let to a substantial reduction in our revenues to $62.3 million for the year. In addition, we had revenues from our Norwegian assets included in discontinued operations of $17.6 million and $89.7 million for the years ended December 31, 2009 and 2008, respectively. We sold our Norwegian assets in May 2009.
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 $17.0 million in 2010 versus $55.7 million in 2009 and $133.2 million in 2008. Discretionary Cash Flow was $21.1 million in 2010 compared to $71.4 million in 2009 and $121.1 million in 2008. The decreases in cash flow provided by operations and Discretionary Cash Flow primarily reflect our declines in realized prices and

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increasing interest costs, partially offset by lower operating expenses. Adjusted EBITDA was $124.8 million in 2010, as compared to $64.6 million in 2009 and $176.6 million in 2008. These fluctuations in Adjusted EBITDA are also primarily due to the changes in our realized prices, interest expense and operating costs. In addition, Adjusted EBITDA for 2010 includes the gain on the Cygnus Sale.
For 2010, net income to common stockholders was $54.3 million for 2010, representing $1.95 per diluted share, including the gain on the Cygnus Sale of $87.2 million. Net loss to common stockholders was $(62.2) million for 2009, or $(2.20) per diluted share, including a gain on the sale of our discontinued operations, an impairment of oil and gas properties, 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 Series C Preferred Stock. Net income to common stockholders for 2008 was $45.7 million, or $1.79 per diluted share, including impairment of oil and gas properties and significant unrealized gains on the mark-to-market of commodity derivatives.
Net income as adjusted for 2010 would have been $57.4 million without the effect of impairments, derivative transactions and currency impacts of deferred taxes. Net income as adjusted for 2009 would have been $41.1 million, as compared to net income as adjusted of $16.5 million in 2008.
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 net income as adjusted, Adjusted EBITDA and Discretionary Cash Flow, and a reconciliation of these non-GAAP measures to the appropriate GAAP measure, please see “Reconciliation of Non-GAAP Accounting Measures.”
Results of Operations
Our revenues and sales volumes have fluctuated significantly during the last three years primarily due to the following:
    As a result of substantially increased oil prices and increased sales from our U.S. operations, partially offset by decreases in natural gas prices, our revenues have increased from $62.3 million for the period ended December 31, 2009 to $71.7 million as of December 31, 2010.
 
    U.S. production reflects the results of our purchase of producing assets in October 2009 and ongoing drilling in 2010, primarily in the Haynesville area.

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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.
 
    In the U.K., natural production declines at certain of our fields have not been offset by infield drilling resulting in production decreases at certain fields, particularly in 2010 and 2009 at our largest producing gas field — Goldeneye.
 
    Sale of our discontinued operations in Norway in May 2009.
The following table shows our annual average sales volumes, sales prices and average production costs. None of our current producing fields represent more than 15% of our total proved reserves during 2009 or 2008. At December 31, 2010, the Woodardville field, in the Haynesville area, represented more than 15% of our proved reserves. Woodardville, which was part of our U.S. acquisitions in 2009, is a gas field and represented 1,865 MMcf and 204 MMcf of our gas sales in 2010 and 2009, respectively.
At December 31, 2009, the Goldeneye field, in the UK, represented more than 15% of our proved reserves. The Goldeneye field in the U.K. had gas sales volumes of 2,990 MMcf, 3,670 MMcf and 6,400 MMcf of in 2010, 2009 and 2008, respectively. The Goldeneye field also had oil sales volumes of 85 Mbbls, 108 Mbbls and 205 Mbbls in 2010, 2009 and 2008, respectively.
Certain of our non-producing North Sea development assets each represent more than 15% of our proved reserves during the last three years, specifically the East Rochelle field in 2010 and 2009 and the Columbus field in 2009. As these fields do not have any current sales or production, they have not been separately identified.

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Endeavour International Corporation
                         
    Year Ended December 31,
    2010   2009   2008
 
 
                       
Sales volume (1)
                       
Oil and condensate sales (Mbbls):
                       
United Kingdom
    545       690       1,032  
United States
    6       4        
 
Continuing operations
    551       694       1,032  
Discontinued operations — Norway
          310       726  
 
Total
    551       1,004       1,758  
 
 
                       
Gas sales (MMcf):
                       
United Kingdom
    3,071       3,743       6,532  
United States
    2,636       320        
 
Continuing operations
    5,707       4,063       6,532  
Discontinued operations — Norway
          686       2,322  
 
Total
    5,707       4,749       8,854  
 
 
                       
Oil equivalent sales (MBOE)
                       
United Kingdom
    1,057       1,314       2,121  
United States
    445       58        
 
Continuing operations
    1,502       1,372       2,121  
Discontinued operations — Norway
          425       1,113  
 
Total
    1,502       1,797       3,234  
 
 
                       
Total BOE per day
    4,115       4,923       8,835  
 
 
                       
Physical production volume (BOE per day) (2):
                       
United Kingdom
    2,904       3,669       5,804  
United States
    1,221       162        
 
Continuing operations
    4,125       3,831       5,804  
Discontinued operations — Norway
          1,156       3,033  
 
Total
    4,125       4,987       8,837  
 
 
                       
Realized Prices (3)
                       
Oil and condensate price ($ per Bbl):
                       
Before commodity derivatives
  $ 76.39     $ 52.15     $ 90.53  
Effect of commodity derivatives
    (5.61 )     22.51       (14.50 )
 
Realized prices including commodity derivatives
  $ 70.78     $ 74.66     $ 76.03  
 
 
                       
Gas price ($ per Mcf):
                       
Before commodity derivatives
  $ 5.18     $ 5.77     $ 11.44  
Effect of commodity derivatives
    0.27       2.69       (0.35 )
 
Realized prices including commodity derivatives
  $ 5.45     $ 8.46     $ 11.09  
 
 
                       
Equivalent oil price ($ per BOE):
                       
Before commodity derivatives
  $ 47.72     $ 44.44     $ 80.54  
Effect of commodity derivatives
    (1.03 )     19.71       (8.84 )
 
                       
 
Realized prices including commodity derivatives
  $ 46.69     $ 64.15     $ 71.70  
 
 
                       
Operating Costs ($ per BOE)(4)
  $ 10.22     $ 12.97     $ 14.40  
 
 
                       

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Endeavour International Corporation
(1)   We record oil revenues on the sales method, i.e. when delivery has occurred. We use the entitlements method to account for sales of gas production.
 
(2)   Physical production may differ from sales volumes based on the timing of tanker liftings for our international sales.
 
(3)   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.
 
(4)   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 sold a majority of our gas in 2009 and 2008 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 2012. 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 is 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 our consolidated financial statements in this Annual Report on Form 10-K for additional information on these derivatives.

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Endeavour International Corporation
Operating Expenses
For 2010, operating expenses decreased to $15.3 million as compared to $17.8 million for 2009. Operating costs per BOE decreased to $10.22 per BOE for 2010 from $12.97 per BOE for 2009. Beginning with the fourth quarter of 2009, our U.S. operations began to be an increasing portion of our total expenses. On average, our U.S. operations have lower operating costs per BOE than our U.K. operations, thereby lowering our overall operating costs and operating costs per BOE.
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 from 2008 to 2009 reflect the higher fuel costs in 2008 at a non-operated facility which gathered production from our IVRRH, Renee and Rubie fields 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 2009 to 2010 reflects lower DD&A rates that result from impairments in oil and gas properties in early 2009 and during 2010 and the increasing proportion of U.S. sales volumes to total sales volumes. Our U.S. assets have a lower DD&A rate due to their lower cost structure. As a consequence, as U.S. sales become a larger portion of our total sales, the lower DD&A rate related to our U.S. properties drives our average DD&A rate lower.
In 2010, we recorded $7.7 million in impairment of oil and gas properties in the U.S., pre-tax, through the application of the full cost ceiling test due to lower U.S. gas prices in the first quarter. At December 31, 2010, the prices used to determine the estimates of future cash inflows were $79.37 per Bbl for oil and $6.58 per Mcf for gas.
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.
General and Administrative (“G&A”) Expenses
Our G&A expenses increased from $17.0 million in 2009 to $18.4 million for 2010 as a result of an increase in employee compensation expense due to expanding U.S. operations and increased consulting costs and related employee costs, that pertain to our expanding U.S. operations. The increase in G&A expense from $15.9 million in 2008 to $17.0 million in 2009 was 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.
Components of G&A expenses for these periods are as follows:

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Endeavour International Corporation
                         
    Year Ended December 31,
(Amounts in thousands)   2010   2009   2008
 
Compensation
  $ 18,110     $ 14,659     $ 11,203  
Consulting, legal and accounting fees
    5,843       5,118       4,679  
Occupancy costs
    1,158       982       1,130  
Other expenses
    2,730       1,364       4,005  
 
Total gross cash G&A expenses
    27,841       22,123       21,017  
 
                       
Non-cash stock-based compensation
    3,692       2,612       2,928  
 
Gross G&A expenses
    31,533       24,735       23,945  
Less: capitalized G&A expenses
    (13,118 )     (7,769 )     (8,013 )
 
Net G&A expenses
  $ 18,415     $ 16,966     $ 15,932  
 
Interest Expense and Other
The increase in interest expense from $16.6 million in 2009 to $34.6 million in 2010 reflects the increases in interest expense that occurred as a result of several changes in our outstanding debt obligations, beginning in the fourth quarter of 2009 and continuing through 2010.
In the fourth quarter of 2009, we issued $50 million of Subordinated Notes in connection with the redemption and modification of our Series C Preferred Stock. During the first quarter of 2010, we borrowed $25 million under the Junior Facility. In August 2010, we borrowed $150 million under the Senior Term Loan and repaid all outstanding balances under the Senior Bank Facility and the Junior Facility. In connection with the repayment of the Senior Bank and Junior Facilities, we expensed the remaining deferred financing costs of $1.2 million related to these instruments. In October 2010 we borrowed an additional $10 million under the Senior Term Loan. At December 31, 2010, we recorded $28.2 million in interest expense related to our debt and $10.3 million in deferred financing expense; offset by $3.9 million in capitalized interest.
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 and lower interest rates.
Income Taxes
The following summarizes the components of tax expense (benefit):

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Endeavour International Corporation
                                                 
                            Total   Discontinued    
                            Continuing   Operations —    
(Amounts in thousands)   U.K.   U.S.   Other   Operations   Norway   Total
 
Year Ended December 31, 2010:
                                               
Net income (loss) before taxes
  $ 90,160     $ (30,978 )   $ (3,439 )   $ 55,743     $     $ 55,743  
 
                                               
Current tax (benefit) expense
    2,734             (154 )     2,580             2,580  
Deferred tax (benefit) expense
    (2,388 )           (929 )     (3,317 )           (3,317 )
Foreign currency losses on deferred tax liabilities
                (51 )     (51 )           (51 )
 
Total tax (benefit) expense
    346             (1,134 )     (788 )           (788 )
 
Net income (loss) after taxes
  $ 89,814     $ (30,978 )   $ (2,305 )   $ 56,531     $     $ 56,531  
 
 
                                               
Year Ended December 31, 2009:
                                               
Net income (loss) before taxes
  $ (52,041 )   $ (31,167 )   $ (11,479 )   $ (94,687 )   $ 51,963     $ (42,724 )
 
                                               
Current tax expense
    (5,739 )     40       (26 )     (5,725 )     (603 )     (6,328 )
Deferred tax expense
    (20,260 )     (20 )     (35 )     (20,315 )     4,791       (15,524 )
Foreign currency gains on deferred tax liabilities
    18,882                   18,882       1,241       20,123  
 
Total tax 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 (benefit) expense
    11,158             10       11,168       27,879       39,047  
Deferred tax (benefit) expense
    22,673             303       22,976       15,415       38,391  
Foreign currency losses on deferred tax liabilities
    (10,028 )                 (10,028 )     (10,681 )     (20,709 )
 
Total tax (benefit) 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  
 
We currently do not record tax benefits due to losses 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 all deferred tax assets generated. Therefore, our income tax expense relates primarily to our operations in the U.K. and our discontinued operations in Norway. Income tax benefit decreased in 2010 as a result of the decrease in U.K. revenues due primarily to lower sales volumes, partially offset by the increase in production revenue taxes (“PRT”) in the U.K. as our allowances for oil production at PRT eligible fields expired. In addition, the gain on the Cygnus sales was non-taxable.
Income taxes decreased in 2009 from 2008 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.

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Endeavour International Corporation
Liquidity and Capital Resources
Capital Expenditures
We spent $106.3 million, $88.6 million and $88.5 million on our oil and gas capital program, excluding acquisitions, in 2010, 2009 and 2008, respectively. We spent $23.9 million in 2010, $16.5 million in 2009 and $25.6 million in 2008 on development activities in both the U.S. and UK. We also spent $82.4 million, $72.1 million and $62.9 million in 2010, 2009 and 2008, respectively, on exploration and appraisal activities, primarily related to our new operations in the U.S. In addition, we incurred $43.7 million, $32.2 million and $2.2 million during 2010, 2009 and 2008, respectively, related to our acquisitions, primarily located in the U.S.
Capital Resources
                 
    Year Ended December 31,
(Amounts in thousands)   2010   2009
 
Cash
  $ 99,267     $ 27,287  
Restricted Cash
  $ 31,776     $ 2,879  
Debt, including current maturities
  $ (345,306 )   $ (223,385 )
 
 
               
Debt, net of Cash
  $ (214,263 )   $ (193,219 )
 
                 
    Year Ended December 31,
    2010   2009
 
Net cash provided by operating activities
  $ 17,019     $ 55,711  
 
Net cash provided by (used in) investing activities
  $ (56,314 )   $ 31,120  
 
Net cash provided by (used in) financing activities
  $ 111,275     $ (97,700 )
 
Our primary sources of financial resources and liquidity are cash on hand, internally generated cash flows from operations and access to the credit and capital markets, to the extent available. Significant issuances and repayments of debt and equity, as well as the uses of the net proceeds, in 2010, 2009, and 2008 were as follows:
    completed the Cygnus Sale for $110 million in cash in October 2010;
 
    entered into a $160 million Senior Term Loan during 2010 Loan in August 2010;
 
    repaid and terminated the Senior Bank Facility and the $25 million Junior Facility;
 
    completed a registered direct offering of common stock, in connection with the Senior Term Loan, to sell 1.3 million shares of our common stock for aggregate cash consideration of approximately $10.1 million, after expenses;
 
    completed a private placement of our common stock, pursuant to a Common Stock Purchase Agreement, selling 3.4 million shares for aggregate net cash consideration of approximately $20.5 million in February 2010;

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Endeavour International Corporation
    repaid $63.1 million of net debt in 2009;
 
    redeemed $75 million of the Series C Convertible Preferred Stock in the fourth quarter of 2009 with $25 million in cash and $50 million subordinated notes;
 
    repaid the $75 million second lien term loan in the first quarter of 2008; and
 
    issued $40 million of 11.5% Convertible Bonds in the first quarter of 2008.
Cash flow from operations decreased to $17.0 million for 2010 from $55.7 million for 2009 primarily due to a $10.2 million loss related to the early termination of commodity derivatives, lower gas prices in the U.S., lower realizations from our commodity derivatives as higher priced oil collars expired at the end of 2009 and increased interest expense following our issuance of the Senior Term Loan in third quarter of 2010 and our issuance of the Subordinated Notes in fourth quarter of 2009. 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.
In 2010, we utilized our cash flow from operations, equity issuances and debt issuances to fund our capital needs and repay a portion of outstanding debt. The proceeds from the Cygnus Sale in the fourth quarter of 2010 are intended to partially fund our capital needs in 2011. 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.
In August 2010, we entered into the Senior Term Loan in the aggregate amount of $150 million, which was subsequently increased to $160 million. We used $66 million of the proceeds from this loan to repay in full the outstanding borrowings under the Senior Bank Facility and the Junior Facility. Following these repayments, both the Senior Bank Facility and the Junior Facility terminated in accordance with their terms.
In February 2010, we issued 3.4 shares of common stock in a private placement for aggregate net proceeds of $20.5 million. We also entered into a $25 million Junior Lending Facility, which had a maturity date of February 5, 2011, and interest at LIBOR plus 8%. The net proceeds from the private placement and the borrowing under the Junior Facility were used to partially fund our 2010 capital budget. We terminated the Junior Facility and repaid the outstanding indebtedness in its entirety on August 16, 2010, in connection with our entry into the Senior Term Loan, discussed above.
In connection with the repayment of the Senior Bank Facility in August 2010, we also terminated all of our outstanding commodity derivative positions for a realized loss of $10.2 million. Under the Senior Term Loan, we are required to re-establish our commodity derivatives to manage our cash flows from operations. In November 2010, we executed six natural gas and ten oil option contracts with three major counterparties. For additional information regarding our derivative contracts, see Note 18 to our consolidated financial statements in this Annual Report.
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.

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Endeavour International Corporation
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 redemption and modification of the Series C Preferred Stock, we also reduced the annual dividend rate to 4.5% (from 8.5%), adjust the conversion price to $8.75 per share (from $17.50) and remove certain anti-dilution provisions.
See Note 9 and Note 12 to the Consolidated Financial Statements herein for additional discussion of our recent issuance of debt and equity. As more fully described in Note 9 to our audited consolidated financial statements herein, our outstanding bank facilities contain certain financial ratio covenants. We were in compliance with all financial and restrictive covenants of our debt obligations as of December 31, 2010 and 2009.
Operating, Investing and Financing Activities include the net cash flows from our discontinued operations which were sold in May 2009. For the years ended December 31, 2009 and 2008, our discontinued operations had net cash flows provided by (used in) operating activities of approximately $9.0 million and $38.8 million, respectively. These net cash flows were substantially offset by net cash used by investing activities of approximately $9.0 million and $34.7 million during 2009 and 2008, respectively.
Outlook
2011 Planned Capital Expenditures
We anticipate spending approximately $150 million during 2011 to fund our oil and gas activities in the U.S. and U.K., with approximately 60% of those expenditures anticipated to be focused on our U.K. assets. In the U.K., our activity during 2011 will be primarily concentrated on the Bacchus and Greater Rochelle development projects. At the Bacchus project, we plan to drill three production wells and install the infrastructure to allow first production in the second half of 2011. At the Greater Rochelle project, our focus will be completing engineering and procuring long lead-time equipment to prepare Greater Rochelle for a 2012 first production date from the East Rochelle area. We also intend to begin actual construction of the subsea infrastructure and modifications to the Scott platform to prepare it for production from the Greater Rochelle area. Additionally, we expect to continue to further our development program at our Columbus project, including ongoing engineering assessments for future production and commercial off-take solutions.
Our primary focus during 2011 in the U.S. will be in the Haynesville and Marcellus areas as we believe this acreage contains near-term production potential. The ongoing U.S. program and expenditures will be tailored based on early drilling results and U.S. gas prices in 2011. During 2011, we expect to further evaluate our two existing frontier plays in Alabama and Montana through the drilling of additional test wells.
We intend to fund our capital expenditures through cash on hand and cash flow generated from operations. The majority of our cash on hand was acquired through our capital raising activities in 2010, including our Senior Term Loan and the sale of our Cygnus asset. The timing, completion and progress of our 2011 capital program is subject to a number of factors, including availability of capital, drilling results, drilling and production costs, availability of drilling services and equipment, partner approvals and technical work. Based on these and other factors, we may increase or decrease our planned capital program or prioritize certain projects over others.

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Endeavour International Corporation
2011 Liquidity and Capital Resources
Our primary sources of financial resources and liquidity are cash on hand, internally generated cash flows from operations and access to the credit and capital markets, to the extent available. We strive to synchronize our capital expenditures with our cash flow and cash on hand. We believe the combination of our available cash on hand and cash flow from operations will fund our capital expenditure program for 2011. In turn, our capital program should allow additional cash flows to be generated as Bacchus and additional U.S. wells begin production.
Our cash flows will be significantly impacted by the amount of oil and gas we produce and the price we obtain for our produced commodities. While we expect our 2011 production to increase over our 2010 production, that increase will not occur evenly throughout the year. Instead, the anticipated production increase will be deferred to the latter half of the year. We expect our production in 2011 will be significantly similar to the fourth quarter of 2010 until Bacchus reaches production and our U.S. drilling program begins produce from new wells. Each of these operational activities will have an impact on our 2011 production as follows:
    Initial production date of the Bacchus field — We expect first production of the Bacchus field to commence in mid 2011. The precise initial production date and how long it may take for Bacchus to reach full production are key variables to our overall 2011 production.
 
    U.S. drilling program results — We are continuing our drilling operations in the U.S. and expect to have additional production as new successful wells are completed. Currently, we have seven wells in the US that are either being completed or awaiting completion.
 
    Flow testing at the Goldeneye field — In early December 2010, the Goldeneye field was shut-in due to flow assurance issues resulting from increased water production. As discussed earlier, the Goldeneye field is a mature gas field, nearing the end of its production life. In February 2011, production was re-started to commence flow trials which, when concluded, should help us determine how much more production may be expected from the Goldeneye field.
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.

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Endeavour International Corporation
Natural gas prices in the North Sea have been influenced by fuel prices around the world, including crude oil and coal. These prices are also impacted by European gas supplies, particularly deliveries from Russian gas supplies. In addition, regional supply and demand issues affect gas prices. U.S. gas prices have been impacted by increases in gas production from shale and other resources play drilling activities, thereby depressing U.S. gas prices in 2010.
Oil prices continue to be impacted by supply and demand on a worldwide basis. Although oil and gas prices have remained volatile, the full impact on our cash flows will be partially mitigated by our balance of gas to oil production and our commodity derivative positions. As of December 31, 2010, our outstanding commodity derivates covered 50% of our estimated 2011 production from our proved developed reserves.
2011 and 2012 Debt Maturities
Our 6% Convertible Notes mature in January 2012 and have an outstanding balance of $81.3 million as of December 31, 2010. In addition, our 11.5% Convertible Bonds have a conditional redemption right in 2012 and have an outstanding balance of $55.8 million as of December 31, 2010. Under the Senior Term Loan, the 6% Convertible Notes must be refinanced, extinguished or extended and the holder’s conditional redemption right on Endeavour’s 11.5% Convertible Bonds due 2014 must be terminated or extended prior to October 14, 2011. If these conditions are not met, the $160 million Senior Term Loan is payable in full on October 14, 2011. We are currently in discussions with several parties concerning this process and expect to extend, refinance or terminate the 6% Convertible Notes and the holder’s conditional redemption right on Endeavour’s 11.5% Convertible Bonds by mid-2011. However, there can be no assurance that efforts to refinance, terminate or extend will be successful, and covenants in our senior Term Loan place restrictions on our ability to use cash on hand to repay other debt, including the 6% Convertible Notes.
Non-GAAP Measures
Net income can be significantly affected by various non-cash items, such as unrealized gains and losses on our commodity derivatives, currency impact of long-term liabilities and deferred taxes. Given the significant impact that non-cash items may have on our net income, we use various measures in addition to net income and net cash provided by operating activities, including non-financial performance indicators and non-GAAP measures as key metrics to manage our business. These metrics demonstrate our ability to maintain or grow production levels and reserves, internally fund capital expenditures and service debt as well as provide comparisons to other oil and gas exploration and production companies. Net Income (Loss) as Adjusted, earnings before interest, taxes, depreciation, depletion and amortization adjusted for the early termination of commodity derivatives and income (loss) from discontinued operations (“Adjusted EBITDA”) and Discretionary Cash Flow are internal, supplemental measures of our performance that are not required by, or presented in accordance with GAAP. The calculations of these non-GAAP measures and the reconciliation of net income (loss) to these non-GAAP measures are provided below.

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

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Endeavour International Corporation
                         
    Year Ended December 31,
(Amounts in thousands)   2010   2009   2008
 
Net income (loss)
  $ 56,531     $ (40,995 )   $ 56,490  
 
                       
Depreciation, depletion and amortization
    28,894       38,701       81,734  
Impairment of oil and gas properties
    7,692       43,929       36,970  
Deferred tax expense (benefit)
    (3,367 )     4,599       17,682  
Gain on sales
    (87,171 )     (47,308 )     (258 )
Unrealized (gain) loss on derivatives
    (12,291 )     55,598       (76,666 )
Early termination of commodity derivatives
    10,201              
Other
    20,632       16,835       5,114  
 
 
                       
Discretionary Cash Flow (1)
  $ 21,121     $ 71,359     $ 121,066  
 
 
                       
Net income (loss)
  $ 56,531     $ (40,995 )   $ 56,490  
Impairment of oil and gas properties (net of tax) (2)
    7,692       28,263       18,485  
Unrealized (gain) loss on derivatives (net of tax) (3)
    (6,820 )     33,702       (37,743 )
Currency impact on deferred taxes
    (51 )     20,123       (20,709 )
 
 
                       
Net Income as Adjusted
  $ 57,352     $ 41,093     $ 16,523  
 
 
                       
Net income (loss)
  $ 56,531     $ (40,995 )   $ 56,490  
 
                       
Unrealized (gain) loss on derivatives
    (12,291 )     55,598       (76,666 )
Net interest expense
    34,517       16,420       21,301  
Depreciation, depletion and amortization
    28,894       38,701       81,734  
Impairment of oil and gas properties
    7,692       43,929       36,970  
Income tax expense (benefit)
    (788 )     (1,729 )     56,729  
Early termination of commodity derivatives
    10,201              
Gain on sale of discontinued operations
          (47,308 )      
 
 
                       
Adjusted EBITDA
  $ 124,756     $ 64,616     $ 176,558  
 
 
(1)   Discretionary Cash Flow is equal to cash flow from operating activities before the changes in operating assets and liabilities, excluding the early termination of commodity derivatives.
 
(2)   Net of tax benefits of none, $(15,666) and $(18,485) in 2010, 2009 and 2008, respectively.
 
(3)   Net of tax expense (benefit) of $5,471, $(21,896) and $38,923 in 2010, 2009 and 2008, respectively.

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Disclosures about Contractual Obligations and Commercial Commitments
The following table sets forth our obligations and commitments to make future payments under our lease agreements and other long-term obligations as of December 31, 2010:
                                         
    Payments due by Period
            Less                
            than 1   1-3           After 5
(Amounts in thousands)   Total   Year   Years   3-5 Years   Years
 
Long-term debt
                                       
Principal
  $ 349,575     $ 21,600     $ 261,021     $ 66,954     $  
Interest (1)
    106,598       34,817       47,531       24,250        
Asset retirement obligations
    42,996       5,987       18,428       1,467       17,114  
Operating leases for office leases and equipment
    1,085       767       318              
 
 
Total Contractual Obligations
  $ 500,254     $ 63,171     $ 327,298     $ 92,671     $ 17,114  
 
Off-Balance Sheet Arrangements
At December 31, 2010, we did not have any off-balance sheet arrangements.
Rig Commitments
We have previously disclosed a potential commitment on a drilling rig in our North Sea operations. We are in dispute with the rig operator in relation to this potential commitment and have also raised potential counterclaims. We will defend our position vigorously, but there can be no certainty that we will resolve this matter favorably.
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.

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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 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; such as the estimated costs of dismantling and abandoning these assets, dry hole costs, lease acquisition costs, seismic and other geological and geophysical costs, delay rentals, costs related to such activities, certain directly-related employee costs and a portion of interest expense. 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). 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. The ceiling test limitation is calculated as the present value, discounted 10%, of:
    the future net cash flows related to estimated production of proved reserves;
 
    the effect of derivative instruments that qualify as cash flow hedges;
 
    the lower of cost or estimated fair value of unproved properties; and
 
    the expected income tax effects of the above items.
Future net cash flows use the average, first-day-of-the-month price for commodities during 2010 and 2009 and the year-end price for 2008.
We utilize a single cost center for each country where we have operations for amortization purposes. Any sales or other conveyances of properties are treated as adjustments to the cost of oil and gas properties with no gain or loss recognized unless the operations are suspended in the entire cost center or the conveyance is significant in nature.
Unproved property costs include the costs associated with unevaluated properties and properties under development and are not initially included in the full cost amortization base (where proved reserves exist) until the project is evaluated. These costs include unproved leasehold acreage, seismic data, wells and production facilities in progress and wells pending determination, together with interest costs capitalized for these projects. Seismic data costs are associated with specific unevaluated properties where the seismic data is acquired for the purpose of evaluating acreage or trends covered by a leasehold interest owned by us.

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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 and 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.
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.

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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, 2010, 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 2010 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, 2010.
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.

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Estimating future asset retirement obligations requires us to make estimates and judgments regarding timing, amount and existence of a liability, as well as what constitutes adequate restoration. We use the present value of estimated cash flows related to our asset retirement obligations to determine fair value. Our liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, inflation factors, the productive lives of wells and our risk-adjusted interest rate. In addition, there are other external factors which could significantly affect the ultimate settlement costs for these obligations including changes in environmental regulations and other statutory requirements, fluctuations in industry costs and advances in technology.
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 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.

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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, 2010, we had approximately 1.4 million additional shares available for issuance pursuant to our existing stock incentive plan.
Fair Value
We estimate fair value for the measurement of derivatives, long-lived assets during certain impairment tests, reporting units for goodwill impairment testing, 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

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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.

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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 may engage in oil and gas hedging activities to realize commodity prices which we consider favorable.
At December 31, 2010, we had the following commodity derivative instruments outstanding:
                         
    2011   2012   Total
 
Oil:
                       
Fixed Price Puts (Mbbl)
    144       40       184  
Weighted Average Price ($/Barrel)
  $ 90.18     $ 91.85       90.55  
 
                       
Gas: (1)
                       
Fixed Price Puts (MMcf)
    118       55       173  
Weighted Average Price ($/Mcf)
  $ 7.48     $ 8.20       7.71  
 
(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, 2010 was $1.54 to £1.00.
The fair value of our commodity derivatives was $2.0 million at December 31, 2010.
Interest Rate Risk
Our exposure to changes in interest rates is not significant as all of our borrowings are subject to fixed interest rates. Changes in interest rates only affect the interest earned on cash and cash equivalents.

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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, 2010 and 2009, 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, 2010. 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, 2010 and 2009, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles.
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, 2010, 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 10, 2011, expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
/S/ KPMG LLP
Houston, Texas
March 10, 2011

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Consolidated Balance Sheets

(Amounts in thousands)
                 
    December 31,  
    2010     2009  
 
 
               
Assets
Current Assets:
               
Cash and cash equivalents
  $ 99,267     $ 27,287  
Restricted cash
    31,776       2,879  
Accounts receivable
    8,068       14,800  
Prepaid expenses and other current assets
    8,718       10,118  
 
Total Current Assets
    147,829       55,084  
 
               
Property and Equipment, Net ($161,430 and $154,553 not subject to amortization at 2010 and 2009, respectively)
    364,677       266,587  
Goodwill
    211,886       211,886  
Other Assets
    25,895       5,322  
 
 
               
Total Assets
  $ 750,287     $ 538,879  
 
See accompanying notes to condensed consolidated financial statements.

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Consolidated Balance Sheets

(Amounts in thousands)
                 
    December 31,
    2010   2009
 
 
               
Liabilities and Stockholders’ Equity
Current Liabilities:
               
Accounts payable
  $ 32,442     $ 12,401  
Current maturities of debt
    21,600        
Accrued expenses and other
    22,642       17,798  
 
Total Current Liabilities
    76,684       30,199  
 
               
Long-Term Debt
    323,706       223,385  
Deferred Taxes
    77,200       80,692  
Other Liabilities
    64,927       85,412  
 
Total Liabilities
    542,517       419,688  
 
               
Commitments and Contingencies
               
 
               
Series C Convertible Preferred Stock:
               
Face value (liquidation preference)
    45,000       50,000  
Net non-cash premiums under fair value accounting on redemption
    8,152       9,058  
 
Total Series C Convertible Preferred Stock
    53,152       59,058  
 
               
Stockholders’ Equity:
               
Series B preferred stock (Liquidation preference: $3,273 and $3,115 at 2010 and 2009, respectively)
           
Common stock; shares issued and outstanding (24,784 and 18,803 shares at 2010 and 2009, respectively)
    25       19  
Additional paid-in capital
    287,995       247,820  
Treasury stock, at cost (72 and 72 shares at 2010 and 2009, respectively)
    (587 )     (587 )
Accumulated deficit
    (132,815 )     (187,119 )
 
Total Stockholders’ Equity
    154,618       60,133  
 
 
               
Total Liabilities and Stockholders’ Equity
  $ 750,287     $ 538,879  
 
See accompanying notes to condensed consolidated financial statements.

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Consolidated Statement of Operations

(Amounts in thousands, except per share data)
                         
    Year Ended December 31,  
    2010     2009     2008  
 
Revenues
  $ 71,675     $ 62,293     $ 170,781  
 
                       
Cost of Operations:
                       
Operating expenses
    15,347       17,776       32,317  
Depreciation, depletion and amortization
    28,894       34,020       67,326  
Impairment of oil and gas properties
    7,692       43,929       36,970  
General and administrative
    18,415       16,966       15,932  
 
Total Expenses
    70,348       112,691       152,545  
 
Income (Loss) From Operations
    1,327       (50,398 )     18,236  
 
 
                       
Other Income (Expense):
                       
Derivatives:
                       
Realized gains (losses)
    (11,753 )     35,422       (28,578 )
Unrealized gains (losses)
    12,291       (55,598 )     76,666  
Interest expense
    (34,592 )     (16,630 )     (22,975 )
Gain on sale of reserves in place
    87,171              
Interest income and other
    1,299       (7,483 )     6,626  
 
Total Other Income (Expense)
    54,416       (44,289 )     31,739  
 
 
                       
Income (Loss) Before Income Taxes
    55,743       (94,687 )     49,975  
Income Tax Expense (Benefit)
    (788 )     (7,158 )     24,116  
 
Income (Loss) from Continuing Operations
    56,531       (87,529 )     25,859  
 
                       
Discontinued Operations, net of tax:
                       
Income (loss) from operations
          (774 )     30,631  
Gain on sale
          47,308        
 
Income (Loss) from Discontinued Operations
          46,534       30,631  
 
 
                       
Net Income (Loss)
    56,531       (40,995 )     56,490  
 
                       
Preferred Stock Dividends:
                       
Dividends declared
    2,227       9,757       10,809  
Non-cash charge under fair value accounting upon redemption
          11,454        
 
Total Preferred Stock Dividends
    2,227       21,211       10,809  
 
 
                       
Net Income (Loss) to Common Stockholders
  $ 54,304     $ (62,206 )   $ 45,681  
 
 
                       
Basic Net Income (Loss) per Common Share:
                       
Continuing operations
  $ 2.34     $ (5.84 )   $ 0.82  
Discontinued operations
          2.50       1.67  
 
Total
  $ 2.34     $ (3.34 )   $ 2.49  
 
 
                       
Diluted Net Income (Loss) per Common Share:
                       
Continuing operations
  $ 1.95     $ (4.70 )   $ 0.59  
Discontinued operations
          2.50       1.20  
 
Total
  $ 1.95     $ (2.20 )   $ 1.79  
 
 
                       
Weighted Average Number of Common Shares Outstanding:
                       
Basic
    23,252       18,613       18,330  
 
Diluted
    28,886       18,613       25,473  
 
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,
    2010   2009   2008
Cash Flows from Operating Activities:
                       
Net income (loss)
  $ 56,531     $ (40,995 )   $ 56,490  
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
                       
Depreciation, depletion and amortization
    28,894       38,701       81,734  
Impairment of oil and gas properties
    7,692       43,929       36,970  
Deferred tax expense (benefit)
    (3,367 )     4,599       17,682  
Unrealized (gains) losses on derivatives
    (12,291 )     55,598       (76,666 )
Gain on sales
    (87,171 )     (47,308 )     (258 )
Non-cash interest expense
    8,764       5,464       4,496  
Amortization of deferred financing costs
    10,262       4,963       7,279  
Other
    1,606       6,408       (6,920 )
Changes in operating assets and liabilities:
                       
Decrease in receivables
    6,732       3,978       9,795  
(Increase) decrease in other current assets
    (4,668 )     7,489       (3,745 )
Increase (decrease) in liabilities
    4,035       (27,115 )     6,323  
 
Net Cash Provided by Operating Activities
    17,019       55,711       133,180  
 
                       
Cash Flows From Investing Activities:
                       
Capital expenditures
    (92,007 )     (99,241 )     (64,194 )
Acquisitions
    (43,726 )     (32,152 )     (2,176 )
Proceeds from sales, net of cash
    108,316       144,653       259  
(Increase) decrease in restricted cash
    (28,897 )     17,860       1,260  
 
Net Cash Provided by (Used in) Investing Activities
    (56,314 )     31,120       (64,851 )
 
                       
Cash Flows From Financing Activities:
                       
 
                       
Repayments of borrowings
    (75,342 )     (64,458 )     (120,000 )
Borrowings under debt agreements
    185,000       1,400       88,000  
Redemption of preferred stock
          (25,000 )      
Proceeds from issuance of common stock
    30,181              
Dividends paid
    (2,070 )     (9,625 )     (10,625 )
Financing costs paid
    (26,590 )           (3,538 )
Other financing
    96       (17 )     (450 )
 
Net Cash Provided by (Used in) Financing Activities
    111,275       (97,700 )     (46,613 )
 
                       
Net Increase (Decrease) in Cash and Cash Equivalents
    71,980       (10,869 )     21,716  
Cash and Cash Equivalents, Beginning of Period
    27,287       38,156       16,440  
 
 
                       
Cash and Cash Equivalents, End of Period
  $ 99,267     $ 27,287     $ 38,156  
 
 
                       
Cash and Cash Equivalents, End of Period:
                       
Continuing operations
  $ 99,267     $ 27,287     $ 31,421  
Discontinued operations
                6,735  
 
Total
  $ 99,267     $ 27,287     $ 38,156  
 
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, January 1, 2008
  $ 19     $     $ 241,647     $ (923 )   $ (170,594 )   $ 70,149          
Preferred stock dividend
                            (10,809 )     (10,809 )        
Amortization of deferred compensation
                3,226                   3,226          
Treasury stock repurchase
          (450 )                       (450 )        
Other
                (293 )                 (293 )        
Comprehensive Income:
                                                       
Net Income
                            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
  $ 19     $ (450 )   $ 244,580     $ (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
                77                   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
  $ 19     $ (587 )   $ 247,820     $     $ (187,119 )   $ 60,133     $ (39,729 )
 
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, 2009
  $ 19     $ (587 )   $ 247,820         $ (187,119 )   $ 60,133          
 
 
                                                       
Preferred stock dividend
                            (2,227 )     (2,227 )        
Common stock issuance
    5             30,176                   30,181          
Series C preferred stock conversion
    1             5,906                   5,907          
Amortization of deferred compensation
                3,660                   3,660          
Other
                433                   433          
Comprehensive Loss:
                                                       
Net Income (Loss)
                            56,531       56,531     $ 56,531  
 
 
Balance, December 31, 2010
  $ 25     $ (587 )   $ 287,995         $ (132,815 )   $ 154,618     $ 56,531  
 
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 is an independent oil and gas company engaged in the exploration, development, production and acquisition of energy reserves in the U.S. and U.K. Endeavour 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. 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.
These accounting principles require management to use estimates, judgments and assumptions that affect the amounts of assets, liabilities, revenues and expenses reported herein. While management reviews its estimates, 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:
    estimates of proved oil and gas reserves,
 
    estimates as to the expected future cash flow from proved oil and gas properties,
 
    estimates of future dismantlement and restoration costs,
 
    estimates of fair values used in purchase accounting and
 
    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.

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
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.
Restricted Cash
Restricted cash has included amounts held in escrow for drilling rig commitments, as collateral for lines of credit, and for acquisitions. At December 31, 2009, restricted cash primarily represented the escrow for our acquisition of properties from Hillwood Energy and was released upon closing of the acquisition in January 2010. At December 31, 2010, restricted cash represented amounts held in escrow as collateral for lines of credit associated abandonment liabilities related to our U.K. properties. On February 6, 2011, we amended our Senior Term Loan to increase the security reserved for potential letters of credit from $25 million to $35 million. Upon receipt of sufficient third party financing, this increase in the security amount should allow us to release the $32 million of restricted cash that currently serves as collateral for existing letters of credit with an alternative letter of credit provider.
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 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; such as the estimated costs of dismantling and abandoning these assets, dry hole costs, lease acquisition costs, seismic and other geological and geophysical costs, delay rentals, costs related to such activities, certain directly-related employee costs and a portion of interest expense. 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). 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. The ceiling test limitation is calculated as the present value, discounted 10%, of:
    the future net cash flows related to estimated production of proved reserves;
 
    the effect of derivative instruments that qualify as cash flow hedges;
 
    the lower of cost or estimated fair value of unproved properties; and
 
    the expected income tax effects of the above items.

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
Future net cash flows use the average, first-day-of-the-month price for commodities during 2010 and 2009 and the year-end price for 2008.
We utilize a single cost center for each country where we have operations for amortization purposes. Any sales or other conveyances of properties are treated as adjustments to the cost of oil and gas properties with no gain or loss recognized unless the operations are suspended in the entire cost center or the conveyance is significant in nature.
Unproved property costs include the costs associated with unevaluated properties and properties under development and are not initially included in the full cost amortization base (where proved reserves exist) until the project is evaluated. These costs include unproved leasehold acreage, seismic data, wells and production facilities in progress and wells pending determination, together with interest costs capitalized for these projects. Seismic data costs are associated with specific unevaluated properties where the seismic data is acquired for the purpose of evaluating acreage or trends covered by a leasehold interest owned by us.
Significant unproved properties are assessed periodically for possible impairment or reduction in value. If a reduction in value has occurred, these property costs are considered impaired and are transferred to the related full cost pool. Geological and geophysical costs included in unproved properties are transferred to the full cost amortization base along with the associated leasehold costs on a specific project basis. Costs associated with wells in progress and wells pending determination are transferred to the amortization base once a determination is made whether or not proved reserves can be assigned to the property. Costs of dry holes are transferred to the amortization base immediately upon determination that the well is unsuccessful. Unproved properties whose acquisition costs are not individually significant are aggregated and 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.

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

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
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.
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. These customers are 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 also have embedded derivatives related to our debt instruments and convertible preferred stock.
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,

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
    reduce our exposure to increases in interest rates, and
 
    manage cash flows in support of our annual capital expenditure budget.
We record all derivatives at fair market value in our Consolidated Balance Sheets at the end of each period. The accounting for the fair market value, and the changes from period to period, depends on the intended use of the derivative and the resulting designation. This evaluation is determined at each derivative’s inception and begins with the decision to account for the derivative as a hedge, if applicable. The accounting for changes in the fair value of a derivative instrument that is not accounted for as a hedge is included in other (income) expense as an unrealized gain or loss. At December 31, 2010 and 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-

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
performance by the counterparties, are substantially smaller. We review the credit ratings of our counterparties to derivative contracts on a regular basis and to date we have not experienced any non-performance by any of our various counterparties, currently BNP Paribas S.A., Bank of America Merrill Lynch and Commonwealth Bank of Australia. At December 31, 2010, our derivative instruments do not require either side to maintain collateral or margin accounts.
As an independent oil and gas producer, our revenue, profitability and future rate of growth are substantially dependent upon prevailing prices for oil and gas, which are dependent upon numerous factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. The energy markets have historically been very volatile, and there can be no assurance that oil and gas prices will not be subject to wide fluctuations in the future. A substantial or extended decline in oil and gas prices could have a material adverse effect on our financial position, results of operations, cash flows and our access to capital and on the quantities of oil and gas reserves that may be economically produced.
Foreign Currency Translation
The U.S. dollar is the functional currency for all of our existing operations, as a majority of all revenue and financing transactions in these operations are denominated in U.S. dollars. For foreign operations with the U.S. dollar as the functional currency, monetary assets and liabilities are remeasured into U.S. dollars at the exchange rate on the balance sheet date. Nonmonetary assets and liabilities are translated into U.S. dollars at historical exchange rates. Income and expense items are translated at exchange rates prevailing during each period. Adjustments are recognized currently as a component of foreign currency gain or loss and deferred income taxes. To the extent that business transactions are not denominated in U.S. dollars, we are exposed to foreign currency exchange rate risk.
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

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
date, based on the calculated fair value of the award, and is recognized as general and administrative expense over the employee’s requisite service period (generally the vesting period of the equity award). We apply the fair value method in accounting for stock option grants using the Black-Scholes Method.
It is our policy to use authorized but unissued shares of stock when stock options are exercised. At December 31, 2010, we had approximately 1.4 million additional shares available for issuance pursuant to our existing stock incentive plan.
Adoption of New Accounting Standards
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 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.

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
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 that did not have a material effect on our results of operations or financial position:
    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.
On January 1, 2010, we adopted the following new standards without material effects on our results of operations or financial position:
    Subsequent events — Amended standards of accounting for and disclosure of events that occur after the balance sheet date but before the financial statements are issued.
 
    Fair value — New, expanded disclosures are required for recurring or nonrecurring fair-value measurements and the reconciliation of specific fair value measurements.
Note 3 — Discontinued Operations
On May 14, 2009, we completed the Norway Sale for cash consideration of $150 million. We recognized a gain upon closing the Norway Sale of $87.0 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)
                         
    Year Ended December 31,
    2010   2009   2008
 
Sales
  $     $ 17,550     $ 89,660  
 
 
                       
Income before Taxes
  $     $ 4,654     $ 63,244  
Income Tax Expense
          (5,428 )     (32,613 )
 
Income (Loss) from Operations
          (774 )     30,631  
 
                       
Gain on sale
          47,308        
 
Net Income from Discontinued Operations
  $     $ 46,534     $ 30,631  
 
Note 4 Prepaid Expenses and Other Current Assets
Prepaid expenses and other current assets consisted of the following:
                 
    December 31,
    2010   2009
 
Fair market value of commodity derivatives — current
  $ 709     $ 2,890  
Prepaid insurance
    1,039       1,506  
Inventory
    4,617       4,450  
Other
    2,353       1,272  
 
 
               
 
  $ 8,718     $ 10,118  
 

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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,
    2010   2009
 
Oil and gas properties under the full cost method:
               
Subject to amortization
  $ 389,575     $ 275,278  
Not subject to amortization:
               
Acquired in 2010
    67,612        
Acquired in 2009
    31,134       51,797  
Acquired in 2008
    23,109       32,970  
Acquired prior to 2008
    39,575       69,786  
 
 
    551,005       429,831  
 
               
Computers, furniture and fixtures
    4,222       3,560  
 
Total property and equipment
    555,227       433,391  
 
               
Accumulated depreciation, depletion and amortization
    (190,550 )     (166,804 )
 
 
               
Net property and equipment
  $ 364,677     $ 266,587  
 
The costs not subject to amortization include
    values assigned to unproved reserves acquired,
    exploration costs such as drilling costs for projects awaiting approved development plans or the determination of whether or not proved reserves can be assigned, and
    other seismic and geological and geophysical costs.
These costs are transferred to the amortization base when it is determined whether or not proved reserves can be assigned to such properties. This analysis is dependent upon well performance, results of infield drilling, approval of development plans, drilling results and development of identified projects and periodic assessment of reserves. We expect acquisition costs excluded from amortization to be transferred to the amortization base over the next five years due to a combination of well performance and results of infield drilling relating to currently producing assets and the drilling and development of identified projects acquired, such as the Rochelle field. We expect exploration costs not subject to amortization to be transferred to the amortization base over the next three years as development plans are completed and production commences on existing discoveries including the Rochelle, Bacchus and Columbus projects.
The following is a summary of our oil and gas properties not subject to amortization as of December 31, 2010:

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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,
    2010   2009   2008   Prior to 2008   Total
 
 
                                       
Acquisition costs
  $ 32,476     $ 10,385     $ 650     $ 10,345     $ 53,856  
Exploration costs
    32,770       20,593       22,459       29,230       105,052  
Capitalized interest
    2,366       156                   2,522  
 
 
                                       
Total oil and gas properties not subject to amortization
  $ 67,612     $ 31,134     $ 23,109     $ 39,575     $ 161,430  
 
During 2010, 2009 and 2008, we capitalized $13.1 million, $7.8 million and $8.0 million, respectively, in certain directly related employee costs. During 2010, 2009 and 2008, we capitalized $3.9 million, $3.1 million and $4.0 million, respectively, in interest.
During 2010, 2009 and 2008, we recorded $7.7 million, $43.9 million and $37.0 million, respectively, of impairment through the application of the full cost ceiling test. The impairment during 2010 related to our U.S. oil and gas properties, pre-tax, and was primarily due to the declaration of two wells as dry holes during the first quarter of 2010; the Alligator Bayou well which was spud in 2008 and a well under a participation agreement. During 2009, our impairment related to both our U.S. and UK properties. During 2008, our impairment related to our UK properties. The impairments in both years resulted from steep declines in commodity prices.
Assets Acquisitions
On January 6, 2010, we acquired positions in several U.S. resource plays as discussed below. We funded the initial cash contributions for these new focus areas from existing cash reserves.
During 2010, we entered into a participation agreement with a private oil and gas operator, and acquired interests in certain acreage in North Louisiana/East Texas and Western Pennsylvania, primarily in the Haynesville and Marcellus areas. Our initial investment was $15 million in cash, and we will pay a share of that operator’s drilling and completion expenditures as wells are drilled over the next few years. Under this agreement, we also acquired additional acreage in the Marcellus area for approximately $7.5 million during the second quarter of 2010.
During 2010, we also acquired interests in an exploratory gas shale play in Alabama with an initial net investment of approximately $8.0 million.

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
Asset Disposition
On October 19, 2010, we completed the Cygnus Sale for $110 million in cash, and recorded a gain of $87 million. The cash proceeds were not burdened by any current taxes payable and are being primarily used to accelerate our development projects.
Note 6 — Goodwill
In connection with the several business 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, 2010 and 2009:
                 
    December 31,
    2010   2009
 
Balance at beginning of year
  $ 211,886     $ 281,943  
Allocation of goodwill to discontinued operations sold
          (67,994 )
Adjustments
          (2,063 )
 
 
               
Balance at end of year
  $ 211,886     $ 211,886  
 

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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:
                 
    2010   2009
 
Intangible assets — workforce in place:
               
Gross
  $ 4,800     $ 4,800  
Accumulated amortization
    (4,475 )     (3,919 )
 
Net intangible assets
    325       881  
 
               
Debt issuance costs
    23,702       3,875  
Fair market value of long-term portion of derivatives
    1,611       318  
Other
    257       248  
 
 
               
 
  $ 25,895     $ 5,322  
 
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. The intangible assets will be fully amortized during 2011.
Debt issuance costs are amortized over the life of the related debt obligation. During 2010, we incurred $26.6 million in debt issuance costs related to the issuance of our Junior Credit Facility and Senior Term Loan. See Note 9 for additional discussion.
Note 8 Accrued Expenses
We had the following accrued expenses outstanding:
                 
    December 31,
    2010   2009
 
Derivative liability
  $     $ 6,817  
Foreign taxes payable
    4,333       1,926  
Accrued interest
    2,234       2,432  
Preferred dividends
    1,301       1,143  
Accrued compensation
    6,681       4,311  
Current portion of asset retirement obligations
    6,405        
Other
    1,688       1,169  
 
 
               
 
  $ 22,642     $ 17,798  
 

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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 December 31:
                 
    2010   2009
 
 
               
Senior notes, 6% fixed rate, due 2012
  $ 81,250     $ 81,250  
Senior bank facility, variable rate, due 2011
          49,942  
Convertible bonds, 11.5%, due 2014
    55,821       49,838  
Subordinated notes, 12.0%, due 2014
    51,132       50,122  
Senior term loan, 15%, due 2013
    161,371        
 
 
    349,574       231,152  
Less: debt discount
    (4,268 )     (7,767 )
Less: current maturities
    (21,600 )      
 
 
               
Long-term debt
  $ 323,706     $ 223,385  
 
 
               
Standby letters of credit outstanding for abandonment liabilities
  $ 31,726     $ 33,388  
 
Principal maturities of debt at December 31, 2010 are as follows:
         
2011
  $ 21,600  
2012
    92,850  
2013
    168,171  
2014
    66,953  
2015
     
Thereafter
     
 
The fair value of our debt obligations was $361 million and $219 million at December 31, 2010 and 2009, respectively. The fair values of long-term debt were determined based upon external market quotes for our Senior Notes, book value for our Senior Bank Facility and discounted cash flows for other debt. Book value approximates fair value for our Senior Bank Facility as this instrument bore interest at a market rate.
Junior Facility
In the first quarter of 2010, we entered into the $25 million Junior Facility, which had a maturity date of February 5, 2011, and bore interest at LIBOR plus 8%. We terminated the Junior Facility and repaid the outstanding indebtedness in its entirety on August 16, 2010.

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
6% Senior Notes
During 2005, we issued in a private offering $81.25 million aggregate principal amount of convertible senior notes due in January 2012. The notes bear interest at a rate of 6.00% per annum, payable in January and July at a conversion price of approximately $35.14 per share, subject to adjustment. 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 had a $225 million Senior Bank Facility, which was subject to a borrowing base limitation with interest of LIBOR plus 1.3%. We terminated the Senior Bank Facility and repaid the outstanding indebtedness in its entirety on August 16, 2010.
11.5% Convertible Bonds
In January 2008, we issued 11.5% Convertible Bonds due 2014 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 11.5% Convertible Bonds were used to repay a portion of our outstanding indebtedness. The 11.5% 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 a conversion price of $16.52 per $1,000 of principal, which represents a conversion rate of approximately 61 shares of our common stock per $1,000 of principal. 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.
In January 2012, the holders have the right to cause us to redeem the 11.5% 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 11.5% Convertible Bonds. At December 31, 2010, the combined fair market value of these derivatives

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
is $27.8 million, reflecting a $0.9 million increase during 2010 that was recorded in unrealized gains (losses) on derivatives.
Subordinated Notes
On November 17, 2009, we entered into Stock Redemption Agreements with each of the holders of our outstanding shares of 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 Term Loan and rank on parity with our other existing debt obligations.
Senior Term Loan
On August 16, 2010, we entered into a credit agreement with Cyan Partners, LP (“Cyan”), as administrative agent, and various lenders for the Senior Term Loan, in the aggregate amount of $150 million, which was subsequently increased to $160 million. We paid $25.4 million in financing costs related to the issuance of the Senior Term Loan.
The Senior Term Loan is a senior obligation of our U.K. subsidiary and guaranteed by Endeavour and all of our material subsidiaries. In addition, substantially all of our assets are pledged as collateral to secure the obligations under the Senior Term Loan. Such collateral may also secure certain hedging obligations and reimbursement obligations in respect of letters of credit that may be issued for our account.
As discussed above, we used $66 million of the proceeds from the loans to repay in full the outstanding borrowings under the Senior Bank Facility and the Junior Facility. Following these repayments, both the Senior Bank Facility and the Junior Facility terminated in accordance with their terms. We expect to use the remaining net proceeds from the Senior Term Loan to fund our development program and for general corporate purposes.
The Senior Term Loan obligates us to pay annual cash interest of 12%. In addition, we are obligated to pay an additional 3% in annual interest “in-kind” (“PIK Interest”) through an increase in the outstanding principal amount of the Senior Term Loan. We have the ability to pay the PIK Interest in cash at our option. We paid Cyan certain fees in the aggregate amount of $18 million. Concurrent with the closing of the Senior Term Loan, Cyan purchased nine million

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
shares of our common stock from us. See Note 12 for additional discussion on this purchase of our common stock.
The Senior Term Loan has a three-year term and matures on August 16, 2013, provided that:
    our 6% Convertible Notes have been refinanced or extended and
 
    the holder’s conditional redemption right on our 11.5% Convertible Bonds has been terminated or extended. Such conditional redemption right exists if our average common stock price, as defined, is below $16.52 per share on January 18, 2012.
If these conditions are not met by October 14, 2011, the Senior Term Loan shall mature and will be due in full on this date. We are currently in discussions with several parties concerning this process and expect to extend, refinance or terminate the 6% Convertible Notes and the holder’s conditional redemption right on Endeavour’s 11.5% Convertible Bonds by mid 2011.
The Senior Term Loan has quarterly principal prepayments of $400,000 beginning on December 31, 2010. At maturity, the remaining principal balance (including any PIK Interest) is due in full.
The Senior Term Loan is callable by us after one year. Between August 16, 2011 and August 15, 2012, we may voluntarily prepay any portion of or all amounts outstanding under the Senior Term Loan at 103% of principal. For prepayments on or after August 16, 2012, the additional prepayment fee will be 1% of the principal amount of the amount outstanding under the Senior Term Loan.
The Senior Term Loan permits certain asset sales and the incurrence of additional indebtedness, subject to certain conditions and within specified limits. We are obligated to comply with certain financial covenants, including:
    a specified maximum total leverage ratio (consolidated net indebtedness to consolidated EBITDAX), ranging from 7.85:1.00 at September 30, 2010 to 3.00:1.00 at December 31, 2012 and thereafter;
 
    a specified minimum EBITDAX for each four-quarter period, ranging from $45,000,000 for the four-quarter period ending September 30, 2010 to $200,000,000 for the four-quarter period ending June 30, 2013;
 
    a minimum Reserve Coverage Ratio, as defined, of not less than 3.00:1.00; and
 
    a PDP Coverage Ratio, as defined, of not less than 0.25:1.00 on or prior to September 30, 2011 and not less than 0.50:1.00 after September 30, 2011.

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
The Senior Term Loan contains various covenants that limit our ability, among other things, to: grant liens; pay dividends; and make investments or loans. We are also obligated to maintain our traditional hedging policies and program. See Note 18 for additional discussion.
The Senior Term Loan also contains customary events of default. If an event of default exists under the Senior Term Loan, the administrative agent has the ability to accelerate the maturity of the loan and exercise other rights and remedies.

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
Note 10 Income Taxes
The income (loss) before income taxes and the components of the income tax expense (benefit) recognized on the Consolidated Statement of Income are as follows:
                                                 
                            Total   Discontinued    
                            Continuing   Operations —    
(Amounts in thousands)   U.K.   U.S.   Other   Operations   Norway   Total
 
Year Ended December 31, 2010:
                                               
Net income (loss) before taxes
  $ 90,160     $ (30,978 )   $ (3,439 )   $ 55,743     $     $ 55,743  
 
                                               
Current tax (benefit) expense
    2,734             (154 )     2,580             2,580  
Deferred tax (benefit) expense
    (2,388 )           (929 )     (3,317 )           (3,317 )
Foreign currency losses on deferred tax liabilities
                (51 )     (51 )           (51 )
 
Total tax (benefit) expense
    346             (1,134 )     (788 )           (788 )
 
Net income (loss) after taxes
  $ 89,814     $ (30,978 )   $ (2,305 )   $ 56,531     $     $ 56,531  
 
 
                                               
Year Ended December 31, 2009:
                                               
Net income (loss) before taxes
  $ (52,041 )   $ (31,167 )   $ (11,479 )   $ (94,687 )   $ 51,963     $ (42,724 )
 
                                               
Current tax expense
    (5,739 )     40       (26 )     (5,725 )     (603 )     (6,328 )
Deferred tax expense
    (20,260 )     (20 )     (35 )     (20,315 )     4,791       (15,524 )
Foreign currency gains on deferred tax liabilities
    18,882                   18,882       1,241       20,123  
 
Total tax 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 (benefit) expense
    11,158             10       11,168       27,879       39,047  
Deferred tax (benefit) expense
    22,673             303       22,976       15,415       38,391  
Foreign currency losses on deferred tax liabilities
    (10,028 )                 (10,028 )     (10,681 )     (20,709 )
 
Total tax (benefit) 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  
 
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,
    2010   2009   2008
 
Federal income tax expense (benefit) at statutory rate
  $ 19,500     $ (33,141 )   $ 17,491  
Taxation of foreign operations
    (579 )     1,572       12,464  
Tax-free gain on sale of reserves in place
    (30,510 )                
Change in valuation allowance — U.S.
    (2,252 )     10,464       4,150  
Foreign tax benefit from foreign currency tax law change
          (5,400 )      
Foreign currency (gain) loss on deferred taxes
    (50 )     18,882       (10,028 )
Deemed foreign dividend of wholly owned subsidiaries
    11,466              
Disallowed executive compensation
    765              
Other
    872       465       39  
 
 
                       
Income Tax Expense, continuing operations
    (788 )     (7,158 )     24,116  
Discontinued operations — Norway
          5,429       32,613  
 
Total Income Tax Expense
  $ (788 )   $ (1,729 )   $ 56,729  
 
Effective Income Tax Rate
    -1 %     8 %     45 %
 
During 2010, 2009 and 2008, we incurred taxes primarily related to our operations in the U.K. and our discontinued operations in Norway. In 2010, 2009 and 2008 we had a loss before taxes of $31.0 million, $31.2 million and $12.0 million, respectively, in the U.S. and we did not record any income tax benefits on these losses as there was no assurance that we could generate any future U.S. taxable earnings. As a result, we recorded a valuation allowance on the full amount of all deferred tax assets generated in the U.S.
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)
                 
    2010   2009
 
Deferred tax asset:
               
Deferred compensation
  $ 6,129     $ 6,236  
Unrealized loss on commodity derivative instruments
    936       16,560  
Asset retirement obligation
    1,324       7,026  
Net operating loss and capital loss carryforward
    57,548       34,635  
Unrealized loss on embedded derivative instruments
    8,343       621  
 
 
               
Total deferred tax assets
    74,280       65,078  
Less valuation allowance
    (37,807 )     (38,771 )
 
Total deferred tax assets after valuation allowance
    36,473       26,307  
 
               
Deferred tax liability:
               
 
               
Property, plant and equipment
    (104,672 )     (97,111 )
Unrealized gain on derivative instruments
    (825 )      
Petroleum revenue tax, net of tax benefit
    (488 )     (1,264 )
Debt discount
    (1,281 )     (2,330 )
Other
    (6,407 )     (6,294 )
 
 
               
Total deferred tax liabilities
    (113,673 )     (106,999 )
 
 
               
Net deferred tax liability
  $ (77,200 )   $ (80,692 )
 
At December 31, 2010, we had the following carryforwards available to reduce future income taxes:
                 
    Years of   Carryforward
Types of Carryforward   Expiration   Amounts
 
U.S. — Net operating loss
    2023 - 2030     $ 69,392  
U.S. — Capital loss
    2015       1,848  
U.K. — Corporate tax net operating loss
  Indefinite     81,767  
U.K. — Supplemental Corporate tax net operating loss
  Indefinite     40,305  
With the exception of $69.4 million of net operating loss carryforward and a $1.8 million capital 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.

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
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 $37.8 million, $38.8 million and $23.7 million as of December 31, 2010, 2009 and 2008, respectively. During 2010, the valuation allowance in the U.S. decreased $2.2 million due to net revisions of the net operating loss and increased $1.3 million for net operating losses in other juridictions. 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 increased $1.1 million for net operating losses in other jurisdictions.
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. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
                         
    Year Ended
    December 31,
    2010   2009   2008
 
Balance at the beginning of the year
  $     $     $ 1,727  
 
                       
Decrease in unrecognized tax benefits from current period tax position
                (1,727 )
 
Balance at the end of the year
  $     $     $  
 
As of December 31, 2010, 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, 2010, 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

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
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 11 Other Liabilities
Other liabilities included the following:
                 
    December 31,
    2010   2009
 
Asset retirement obligations
  $ 36,592     $ 47,362  
Long-term derivative liabilities
    27,810       38,050  
Other
    525        
 
 
               
Total Other Liabilities
  $ 64,927     $ 85,412  
 
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, 2010 and 2009:
                 
    Year Ended
    December 31,
    2010   2009
 
Asset retirement obligations, beginning of year
  $ 47,362     $ 38,776  
Increase due to revised estimates
    2,949       7,762  
Accretion expense
    4,591       4,117  
Impact of foreign currency exchange rate changes
    (2,397 )     4,280  
Payments
    (9,508 )     (7,325 )
Sale of assets
          (248 )
 
Asset retirement obligations, end of year
    42,997       47,362  
 
               
Less: current portion of asset retirement obligations
    (6,405 )      
 
Long-term asset retirement obligations
  $ 36,592     $ 47,362  
 

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
Note 12 Equity
The activity in shares of our common and preferred stock during 2010, 2009 and 2008 included the following:
                         
    Year Ended December 31,
    2010   2009   2008
 
Common Stock:
                       
Outstanding at the beginning of the year
    18,803       18,368       18,144  
Issuance of common stock
    4,638              
Exercise of stock options
    23       24        
Conversion of preferred stock
    572                
Issuance of stock based compensation
    748       411       224  
 
Outstanding at the end of the year
    24,784       18,803       18,368  
 
 
                       
Series B Preferred Stock:
                       
Outstanding at the end of the year
    20       20       20  
 
 
                       
Convertible Preferred Stock:
                       
Outstanding at the beginning of the year
    50       125        
Conversion to common stock
    (5 )            
Redemptions
          (75 )      
Issuance of preferred stock
                125  
 
 
                       
Outstanding at the end of the year
    45       50       125  
 
 
                       
Treasury Stock:
                       
Outstanding at the beginning of the year
    (72 )     (47 )      
Purchase of treasury shares for stock vesting
          (25 )     (47 )
 
 
                       
Outstanding at the end of the year
    (72 )     (72 )     (47 )
 
Common Stock
The Common Stock is $0.001 par value common stock, 64,285,714 shares authorized.
In October 2010, our Board of Directors authorized a one-for-seven share consolidation of our common stock, in the form of a reverse stock split. This consolidation was effective at the opening of trading on November 18, 2010. As a result of the share consolidation, every seven

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Endeavour International Corporation
Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)
shares of our common stock outstanding were automatically combined into one share of our common stock. Each shareholder continues to hold the same percentage of our outstanding common shares. The shares were rounded up to the next whole share for those holders who would have otherwise received fractional shares. The share consolidation was intended to make our common stock available to a broader range of investors and reposition the company’s trading metrics.
On August 16, 2010, in connection with the issuance of the Senior Term Loan, we completed a registered direct offering of common stock pursuant to a Common Stock Purchase Agreement with Cyan to sell 1.3 million shares of our common stock, par value $0.001 per share, for aggregate net cash consideration of approximately $10.1 million, after deducting expenses. The purchase price per share was $7.91, the closing price of our common stock on the NYSE Amex on August 13, 2010. We intend to use the net proceeds from this offering for general corporate purposes.
On February 4, 2010, we completed a private placement of our common stock pursuant to a Common Stock Purchase Agreement with existing stockholders, certain directors and other third-party investors, thereby selling 3.4 million shares of our common stock, for aggregate net cash consideration of approximately $20.5 million. The purchase price per share was $6.30, the closing price of our common stock on the NYSE Amex on February 3, 2010. The net proceeds from this private placement were used to partially fund our 2010 capital budget.
In 2010, we issued inducement grants of 85,715 shares of our restricted common stock, upon commencement of employment of one executive officer. In 2008, we issued inducement grants of 42,858 shares of our restricted common stock, and options to purchase 35,715 shares of our common stock at an exercise price of $5.25 per share upon commencement of employment of one executive officer.
Series C Convertible Preferred Stock
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, at 4.5% or 4.92%, respectively, since November 2009 and at 8.5% or 8.92%, respectively, in prior periods; and
 
    payable 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 ranks senior to any of our other existing or future shares of capital stock. 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.

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Endeavour International Corporation
Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)
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 of 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 to the modification of the Series C Preferred Stock, we also recorded an embedded derivative 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, 2010 the fair market value of this derivative was an asset of $0.3 million, reflecting a $2.3 million gain during 2010 that was recorded in unrealized gains (losses) on derivatives.
The Series C Preferred Stock is convertible into common stock at any time at the option of the preferred stock investors, at (i) a conversion price of $8.75 (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 $8.75 per share (from $17.50) and remove certain anti-dilution provisions.
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.

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Endeavour International Corporation
Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)
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 Series C 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 Series C Preferred Stock, we must redeem all of the Series C 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 Series C Preferred Stock for the greater of: (i) the amount equal to which such holder would be entitled to receive had the holder converted such Series C 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 Series C Preferred Stock through the date that Endeavour pays the redemption price for such shares.
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 for our Series C Preferred Stock. The amendment aligns the number of common shares reserved for the potential conversion of the Series C 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 the Certificate of Designation for the Series C Preferred Stock and the $50 million subordinated notes issued to the holders of the Series C Preferred Stock to make certain technical changes that align certain definitions and provisions relating to potential repurchases of securities by us.
In 2010, a combined 5,000 shares of our Series C Preferred Stock were converted into 0.6 million shares of our common stock.
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 entitled to dividends of 8% of the original issuing price per share per annum, which are cumulative prior to any dividends on the common stock and on parity with the payment of any dividend or other distribution on any other series of preferred stock that has similar characteristics. The holders of each share of Series B Preferred Stock are entitled to be paid out of available funds prior to any distributions to holders of common stock in the amount of $100.00 per outstanding share plus all accrued dividends. We may, upon approval of our Board, redeem all or a portion of the outstanding shares of Series B preferred stock at a cost of the liquidation preference and all accrued and unpaid dividends.
Note 13 Comprehensive Income (Loss)
The following summarizes the components of comprehensive loss:
                         
    Year Ended December 31,
    2010   2009   2008
 
Net income (loss)
  $ 56,531     $ (40,995 )   $ 56,490  
 
                       
Related to derivative instruments:
                       
Unrealized gain
                428  
Reclassification adjustment for gain realized in net income (loss) above
          1,194       (770 )
 
                       
Related to marketable securities:
                       
Unrealized loss
                (1 )
Reclassification adjustment for loss realized in net income (loss) above
          72        
 
 
                       
Net impact on comprehensive income (loss)
          1,266       (343 )
 
 
                       
Comprehensive income (loss)
  $ 56,531     $ (39,729 )   $ 56,147  
 
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,
    2010   2009   2008
 
Related to derivative instruments:
                       
Balance at beginning of year
  $  —     $ (1,194 )   $ (852 )
Change during the year
          1,194       (342 )
 
Balance at end of year
                (1,194 )
 
                       
Related to marketable securities:
                       
Balance at beginning of year
          (72 )     (71 )
Change during the year
          72       (1 )
 
Balance at end of year
                (72 )
 
 
                       
Accumulated other comprehensive loss
  $  —     $     $ (1,266 )
 
Note 14 — 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.
The fair value of each option award is estimated on the date of grant using the Black-Scholes option-pricing model. The following summarizes the weighted average of the assumptions used in the option-pricing model and the method for determining the assumptions:

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Endeavour International Corporation
Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)
                             
    For the Year Ended December 31,    
    2010   2009   2008   Method of Determining Assumptions
 
Risk-free rate
          1.5 %     3.1 %   U.S. treasury yield curve in effect at the time of grant for the duration of estimated term
Expected years until exercise
          4.25       4.00     Historical data regarding option exercises and employee terminations
Expected stock volatility
          56 %     46 %   Historical Endeavour volatility for the length of the expected term
 
Dividend yield
                    Historical
 
At December 31, 2010, total compensation cost related to nonvested awards not yet recognized was approximately $4.0 million and is expected to be recognized over a weighted average period of less than two years. For the year ended December 31, 2010, we included approximately $0.9 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, 2010
    601     $ 13.10                  
Exercised
    (23 )     4.22                  
Forfeited
    (10 )     11.37                  
Expired
    (104 )     29.01                  
 
 
                               
Balance outstanding — December 31, 2010
    464     $ 10.04       5.5     $ 2,366  
 
 
Currently exercisable — December 31, 2010
    338     $ 11.79       5.0     $ 1,301  
 
We did not grant any options during 2010. The weighted average grant-date fair value of options granted during 2009 and 2008 was $0.25 and $0.50, respectively.

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Endeavour International Corporation
Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)
Of options granted during 2009 and 2008, 0.2 million and 0.2 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, 2010 is summarized as follows:
                                         
            Options Outstanding           Options Exercisable
            Weighted   Weighted           Weighted
            Average   Average           Average
    Number of   Remaining   Exercise           Exercise
Range of Exercise   Options   Contractual   Price Per   Number   Price Per
Prices   Outstanding   Life   Share   Exercisable   Share
 
Less than $10.00
    327       6.3     $ 6.55       201     $ 7.30  
$10.00 - $20.00
    91       5.5       15.10       91       15.10  
Greater than $20.00
    46       0.1       24.66       46       24.66  
 
 
                                       
Total
    464       5.5     $ 10.04       338     $ 11.79  
 
Restricted Stock
At December 31, 2010, our employees and directors held 0.8 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, 2010 and the changes during the year ended December 31, 2010 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, 2010
    489     $ 6.99  
Granted
    784       7.90  
Vested
    (422 )     7.95  
Forfeited
    (35 )     7.28  
 
 
               
Balance outstanding — December 31, 2010
    816     $ 7.36  
 
 
               
Total grant date fair value of shares vesting during the period
  $ 3,353          
 
Non-Cash stock-based compensation is recorded in G&A expenses or capitalized G&A as follows:
                         
    Year Ended
    December 31,
    2010   2009   2008
 
G&A Expenses
  $ 3,191     $ 2,464     $ 2,467  
Capitalized G&A
    988       573       759  
 
 
                       
Total non-cash stock-based compensation
  $ 4,179     $ 3,037     $ 3,226  
 
Note 15 — 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.

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Endeavour International Corporation
Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)
                         
    Year Ended December 31,
    2010   2009   2008
 
Net income (loss) to common shareholders
                       
Basic
  $ 54,304     $ (62,206 )   $ 45,681  
Add Effect of:
                       
Preferred dividends
    2,070             10,625  
 
Diluted
  $ 56,374     $ (62,206 )   $ 56,306  
 
 
                       
Weighted Average Number of Common Shares Outstanding:
                       
Basic
    23,252       18,613       18,330  
Add Effect of:
                       
Stock compensation grants and warrants
    380              
Preferred stock
    5,254             7,143  
 
Diluted
    28,886       18,613       25,473  
 
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 when their inclusion would be antidilutive (i.e., reduce the net loss per share). The common shares potentially issuable arising from these instruments excluded from weighted average diluted shares outstanding consisted of:
                         
    For the Year Ended December 31,
    2010   2009   2008
 
Options, warrants and stock-based compensation
          273        
Convertible debt
    5,691       5,329       4,675  
Convertible preferred stock
          5,714        
 
 
                       
Common shares potentially issuable
    5,691       11,316       4,675  
 

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
Note 16 — Financial Instruments
                                 
    December 31,   December 31,
    2010   2009
            Carrying           Carrying
    Fair Value   Value   Fair Value   Value
 
Assets:
                               
Derivative instruments
  $ 2,320     $ 2,320     $ 3,208     $ 3,208  
 
                               
Liabilities:
                               
Debt
    360,844       323,706       219,959       223,385  
Derivative instruments
    (27,810 )     (27,810 )     (44,866 )     (44,866 )
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 and interest rate swaps 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 other debt. Book value approximates fair value for our Senior Bank Facility and as this instrument bears interest at a market rate.
Note 17 — Fair Value Measurements
We measure the fair value of financial assets and liabilities on a recurring basis, defining fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value is based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. This includes not only the credit standing of counterparties involved and the impact of credit enhancements but also the impact of our own nonperformance risk on our liabilities. Fair value measurements are classified and disclosed in one of the following categories:
     
Level 1:
  Fair value is based on actively-quoted market prices, if available.
 
   
Level 2:
  In the absence of actively-quoted market prices, we seek price information from external sources, including broker quotes and industry publications. Substantially all of these inputs are observable in the marketplace during the entire term of the instrument, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace.

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
     
Level 3:
  If valuations require inputs that are both significant to the fair value measurement and less observable from objective sources, we must estimate prices based on available historical and near-term future price information and certain statistical methods that reflect our market assumptions.
We apply fair value measurements to certain assets and liabilities including commodity 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, 2010:
                                 
    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 puts
      $ 1,213     $ 792     $ 2,005  
Embedded derivatives
                (27,495 )     (27,495 )
 
 
                               
Total derivative liabilities
      $ 1,213     $ (26,703 )   $ (25,490 )
 
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 and puts 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 and puts, an active futures market does not exist for our U.K. gas derivatives. We based the inputs to the option models for our U.K. gas derivatives on observable market data in other markets to verify the reasonableness of the counterparty quotes. These U.K. gas derivatives are classified as Level 3.
The following is a reconciliation of changes in fair value of net derivative assets and liabilities classified as Level 3:

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
                 
    Year Ended
    December 31,
    2010   2009
 
Balance at beginning of period
  $ (28,843 )   $ (12,057 )
Total gains or losses (realized/unrealized)
               
Included in earnings
    1,348       (14,390 )
Purchases, issuance and settlements
    792       (2,396 )
 
Balance at end of period
  $ (26,703 )   $ (28,843 )
 
 
               
Changes in unrealized gains (losses) relating to derivatives assets and liabilities still held at December 31, 2010
  $ 1,348     $ (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:
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 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,
    2010   2009
 
Derivatives not designated as hedges:
               
Oil and gas commodity derivatives:
               
Assets:
               
Prepaid expenses and other current assets
  $ 709     $ 2,890  
Other assets — long term
    1,296       318  
Liabilities:
               
Accrued expenses and other
          (6,817 )
Other liabilities — long-term
          (9,207 )
 
 
  $ 2,005     $ (12,816 )
 
               
Embedded derivatives related to debt instrument:
               
Assets:
               
Other assets — long term
  $ 315     $  
Liabilities:
               
Other liabilities — long-term
    (27,810 )     (28,843 )
 
If all counterparties failed to perform, our maximum loss would be $2.0 million as of December 31, 2010.
The effect of the derivatives not designated as hedges on our results of operations was as follows:
                         
    Year Ended December 31,
    2010   2009   2008
 
Derivatives not designated as hedges:
                       
Oil and gas commodity derivatives
                       
Realized gains (losses)
  $ (11,753 )   $ 35,422     $ (28,578 )
Unrealized gains (losses)
    10,943       (43,791 )     77,846  
 
 
    (810 )     (8,369 )     49,268  
 
                       
Embedded derivatives related to debt instrument
                       
Unrealized gains (losses)
  $ 1,348     $ (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   2010   2009   2008
 
Interest rate swap
                               
(Gain) loss recognized in other comprehensive income, net of tax
              $     $ 428  
(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, 2010, our outstanding commodity derivatives covered approximately 184 Mbbl of oil and 173 MMcf of gas cumulative through 2012 and consist of fixed price puts.
During 2007, we entered into an interest rate swap with 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,
    2010   2009   2008
 
 
                       
Interest paid
  $ 18,668     $ 7,074     $ 15,966  
 
 
                       
Income taxes paid (refunded)
  $ (172 )   $ 4,738     $ 20,088  
 
Non-Cash Investing and Financing Transactions
As discussed in Note 12, in 2010, a combined 5,000 shares of our Series C Preferred Stock were converted into 0.6 million shares of our common stock. In addition, during 2009, 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.
In 2010, 2009 and 2008, we recorded $8.8 million, $5.5 million and $4.5 million, respectively, in non-cash interest expense that was added to the principal balance of the 11.5% Convertible Bonds, the $50 million Subordinated Notes and the Senior Term Loan.
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 $0.8 million, $0.2 million and $0.1 million for the years ended December 31, 2011, 2012 and 2013, respectively.
Rig Commitments
We have previously disclosed a potential commitment on a drilling rig in our North Sea operations. We are in dispute with the rig operator in relation to this potential commitment and have also raised potential counterclaims. We will defend our position vigorously, but there can be no certainty that we will resolve this matter favorably.
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 had the option, but not the obligation, to participate in the acquisition, exploration and appraisal activities of selected assets. Caza provided economic and engineering analysis on projects

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
submitted for our selection. We received 75% of Caza’s interest in exchange for $250,000 per month and payment of our share of all external costs on any projects we selected. We elected to terminate the agreement effective April 2010.
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:
                                                 
    2010   2009   2008
            Long-           Long-           Long-
            lived           lived           lived
    Revenue   Assets   Revenue   Assets   Revenue   Assets
 
United States
  $ 11,174     $ 115,114     $ 1,627     $ 46,172     $     $ 12,125  
 
                                               
United Kingdom
    60,501       486,467       60,666       436,016       170,781       441,195  
Other
          877             1,607             2,140  
 
Continuing Operations
    71,675       602,458       62,293       483,795       170,781       455,460  
 
                                               
Discontinued operations — Norway
                17,550             89,660       148,605  
 
 
                                               
Total
  $ 71,675     $ 602,458     $ 79,843     $ 483,795     $ 260,441     $ 604,065  
 
 
                                               
Total International
  $ 60,501     $ 487,344     $ 78,216     $ 437,623     $ 260,441     $ 591,940  
 

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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
 
    2010
Revenues from continuing operations
  $ 13,721     $ 21,532     $ 19,849     $ 16,573  
Operating expenses from continuing operations
    20,625       15,582       16,529       17,613  
Operating profit (loss) from continuing operations
    (6,904 )     5,950       3,320       (1,040 )
Net income (loss) to common stockholders
    (15,779 )     58       (12,238 )     82,263  
Net income (loss) per common share:
                               
Basic
    (0.11 )           (0.07 )     3.34  
Diluted
    (0.11 )           (0.07 )     2.37  
 
                               
    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 income (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              
Note 23 — Subsequent Events
On February 6, 2011, we amended our Senior Term Loan to increase the security reserved for potential letters of credit from $25 million to $35 million. Upon receipt of sufficient third party financing, this increase in the security amount should allow us to release the $32 million of restricted cash that currently serves as collateral for existing letters of credit with an alternative letter of credit provider.
On February 23, 2011, we closed on our previously announced acquisition of an additional 20% working interest in the Bacchus development for approximately $9.2 million at closing and $6.2 million three months after first oil. In addition, we paid capital costs previously incurred by the seller of $9.4 million.

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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
    United   United    
    Kingdom   States   Total
 
December 31, 2010:
                       
Proved
  $ 346,915     $ 42,659     $ 389,574  
Unproved
    85,019       76,412       161,431  
 
Total capitalized costs
    431,934       119,071       551,005  
 
                       
Accumulated depreciation, depletion and amortization
    (182,158 )     (6,058 )     (188,216 )
 
 
                       
Net capitalized costs
  $ 249,776     $ 113,013     $ 362,789  
 
 
                       
December 31, 2009:
                       
Proved
  $ 266,893     $ 8,385     $ 275,278  
Unproved
    127,736       26,817       154,553  
 
Total capitalized costs
    394,629       35,202       429,831  
 
                       
Accumulated depreciation, depletion and amortization
    (164,703 )     (810 )     (165,513 )
 
 
                       
Net capitalized costs
  $ 229,926     $ 34,392     $ 264,318  
 

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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, 2010:
                                               
Acquisition costs:
                                               
Proved
  $     $ 2,386     $     $ 2,386     $     $ 2,386  
Unproved
    1,184       40,155             41,339             41,339  
Exploration costs
    50,328       32,027             82,355             82,355  
Development costs
    22,047       1,884             23,931             23,931  
 
 
Total costs incurred
  $ 73,559     $ 76,452     $     $ 150,011     $     $ 150,011  
 
 
                                               
Year Ended December 31, 2009:
                                               
Acquisition costs:
                                               
Proved
  $ 7,589     $ 8,999     $     $ 16,588     $     $ 16,588  
Unproved
    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  
 

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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, 2010:
                                       
Revenues
  $ 60,501     $ 11,174     $ 71,675     $     $ 71,675  
Production expenses
    11,086       4,261       15,347             15,347  
DD&A
    22,020       5,273       27,293             27,293  
Impairment of oil and gas properties
          7,692       7,692             7,692  
Income tax expense (benefit)
    13,698       (2,118 )     11,580             11,580  
 
 
Results of activities
  $ 13,697     $ (3,934 )   $ 9,763     $     $ 9,763  
 
 
                                       
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 (benefit)
    (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 (benefit)
    18,279       (290 )     17,989       47,832       65,821  
 
 
Results of activities
  $ 18,279     $ (538 )   $ 17,741     $ 13,491     $ 31,232  
 
(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.

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Endeavour International Corporation
Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
Oil and Gas Reserves
Proved reserves are estimated quantities of oil, gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can reasonably be expected to be recovered through existing wells with existing equipment and operating methods. The reserve volumes presented are estimates only and should not be construed as being exact quantities. These reserves may or may not be recovered and may increase or decrease as a result of our future operations and changes in economic conditions. During 2010 and 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.
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 2010 and 2009 have been presented in accordance with the new reserve estimation and disclosure rules, which may not be applied retrospectively. The 2008 data is 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, 2008
    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  
Production
    (545 )     (6 )     (551 )           (551 )
Extensions and discoveries
    457       34       491             491  
Revisions of previous estimates
    404       13       417             417  
 
Proved reserves at December 31, 2010
    3,664       59       3,723             3,723  
 
 
                                       
Proved Developed Oil Reserves (MBbls):
                                       
At December 31, 2008
    1,468       7       1,475       1,302       2,777  
 
At December 31, 2009
    1,381       8       1,389             1,389  
 
At December 31, 2010
    1,240       14       1,254             1,254  
 

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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, 2008
    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  
Production
    (3,071 )     (2,636 )     (5,707 )           (5,707 )
Purchases of reserves
          2,657       2,657             2,657  
Sales of reserves in place
    (51,522 )           (51,522 )           (51,522 )
Extensions and discoveries
    26,692       24,181       50,873             50,873  
Revisions of previous estimates
    5,762       (3,209 )     2,553             2,553  
 
Proved reserves at December 31, 2010
    56,177       31,777       87,954             87,954  
 
 
                                       
Proved Developed Gas Reserves (MMcf):
                                       
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  
 
At December 31, 2010
    555       13,281       13,836             13,836  
 

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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 December 31, 2007
    5,252             5,252       3,461       8,713  
Extensions and discoveries
    3,917       133       4,050       130       4,180  
Production
    (2,121 )           (2,121 )     (1,113 )     (3,234 )
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  
Purchase of proved reserves, in place
          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  
Production
    (1,057 )     (445 )     (1,502 )           (1,502 )
Extensions and discoveries
    4,906       4,064       8,970             8,970  
Purchase of proved reserves, in place
          443       443             443  
Sales of reserves
    (8,587 )           (8,587 )           (8,587 )
Revisions of previous estimates
    1,364       (522 )     842             842  
 
Proved reserves at December 31, 2010
    13,027       5,355       18,382             18,382  
 
 
                                       
Proved Developed Reserves (MBOE):
                                       
At December 31, 2008
    2,595       46       2,641       2,122       4,763  
 
At December 31, 2009
    2,103       792       2,895             2,895  
 
At December 31, 2010
    1,333       2,227       3,560             3,560  
 
Standardized Measure of Discounted Future Net Cash Flows
Future cash inflows and future production and development costs are determined by applying average 12-month pricing for 2010 and 2009 and year-end prices for 2008 and year-end costs to the estimated quantities of oil and gas to be produced. Oil, gas and condensate prices are escalated only for fixed and determinable amounts under provisions in some contracts. Estimated future income taxes are computed using current statutory income tax rates where production occurs. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor.
At December 31, 2010 and 2009, the prices used to determine the estimates of future cash inflows were as follows:

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Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
Estimated future cash inflows are reduced by estimated future development, production, abandonment and dismantlement costs based on year-end cost levels, assuming continuation of existing economic conditions, and by estimated future income tax expense. Income tax expense, both U.S. and foreign, is calculated by applying the existing statutory tax rates, including any known future changes, to the pretax net cash flows giving effect to any permanent differences and reduced by the applicable tax basis. The effect of tax credits is considered in determining the income tax expense.
The standardized measure of discounted future net cash flows is not intended to present the fair market value of our oil and gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves in excess of proved reserves, anticipated future changes in prices and costs, an allowance for return on investment and the risks inherent in reserve estimates.
                                 
    December 31,  
    2010     2009  
    Oil     Gas     Oil     Gas  
 
 
United Kingdom ($/Barrel)
    79.37       6.58       60.40       4.96  
United States ($/Mcf)
    79.81       4.40       61.08       3.86  
 

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Notes to Consolidated Financial Statements
(
Amounts in thousands, except per unit data)
                         
Standardized Measure of Discounted Future Net Cash Flows
    United   United    
    Kingdom   States   Total
 
December 31, 2010:
                       
Future cash inflows
  $ 704,073     $ 129,007     $ 833,080  
Future production costs
    (101,660 )     (26,110 )     (127,770 )
Future development costs
    (374,380 )     (33,433 )     (407,813 )
Future income tax expense
    (72,870 )           (72,870 )
 
 
                       
Future net cash flows (undiscounted)
    155,163       69,464       224,627  
Annual discount of 10% for estimated timing
    81,613       31,717       113,330  
 
 
                       
Standardized measure of future net cash flows
  $ 73,550     $ 37,747     $ 111,297  
 
 
                       
December 31, 2009:
                       
Future cash inflows
  $ 424,007     $ 36,799     $ 460,806  
Future production costs
    (89,696 )     (9,893 )     (99,589 )
Future development costs
    (274,456 )     (12,602 )     (287,058 )
Future income tax expense
    (17,433 )           (17,433 )
 
 
                       
Future net cash flows (undiscounted)
    42,422       14,304       56,726  
Annual discount of 10% for estimated timing
    (6,770 )     7,798       1,028  
 
 
                       
Standardized measure of future net cash flows
  $ 49,192     $ 6,506     $ 55,698  
 
                         
Principal Sources of Change in the Standardized Measure of Discounted Future Net Cash Flows
    2010   2009   2008
 
Standardized measure, beginning of period
  $ 55,698     $ 49,662     $ 191,920  
Net changes in prices and production costs
    86,915       (30,155 )     (144,547 )
Future development costs incurred
    21,112       16,511       8,912  
Net changes in estimated future development costs
    (48,356 )     (81,864 )     (105,784 )
Revisions of previous quantity estimates
    16,375       22,318       (19,381 )
Extensions and discoveries
    110,059       128,090       127,182  
Acretion of discount
    2,630       8,139       39,734  
Changes in income taxes, net
    (35,306 )     (1,054 )     163,445  
Sale of oil and gas produced, net of production costs
    (56,327 )     (56,531 )     (213,865 )
Purchased reserves
    2,386       8,827        
Sales of reserves in place
    (48,310 )     (11,514 )      
Change in production, timing and other
    4,421       3,269       2,046  
 
 
                       
Standardized measure, end of period
  $ 111,297     $ 55,698     $ 49,662  
 

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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, 2010. 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, 2010. 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, 2010.

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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, 2010 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, 2010 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, 2010, 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

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detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
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, 2010, 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, 2010 and 2009, 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, 2010, and our report dated March 10, 2011 expressed an unqualified opinion on those consolidated financial statements.
         
/s/ KPMG LLP      
Houston, Texas
March 10, 2011

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Item 9B. Other Information
None.
Item 10. Directors, Executive Officers and Corporate Governance of the Registrant
Our Definitive Proxy Statement for our 2011 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 2011 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 2011 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 2011 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 13.

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Item 14. Principal Accounting Fees and Services
Our Definitive Proxy Statement for our 2011 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 14.
Part IV
Item 15. Exhibits and Financial Statement Schedules
(a) (1) and (2) Financial Statements and Financial Statement Schedules. See our consolidated financial statements included in Item 8 herein.
(a) (3) Exhibits.
See “Index of Exhibits” herein which lists the documents filed as exhibits with this Annual Report on Form 10-K.
(b) Exhibits.
See “Index of Exhibits” herein which lists the documents filed as exhibits with this Annual Report on Form 10-K.

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Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Annual Report on Form 10-K to be signed on its behalf by the undersigned, thereunto duly authorized.
         
Endeavour International Corporation
 
   
By:   /s/ J. Michael Kirksey      
  J. Michael Kirksey     
  Executive Vice President and Chief Financial Officer     
Date: March 10, 2011
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
         
Signature   Title   Date
 
       
/s/ William L. Transier
 
William L. Transier
  Chief Executive Officer, President and Director (Principal Executive Officer)   March 10, 2011
 
       
/s/ J. Michael Kirksey
 
J. Michael Kirksey
  Chief Financial Officer
(Principal Financial Officer)
  March 10, 2011
 
       
/s/ Robert L. Thompson
 
Robert L. Thompson
  Chief Accounting Officer
(Principal Accounting Officer)
  March 10, 2011
 
       
/s/ John B. Connally III
 
  Director    March 10, 2011
John B. Connally III
       
 
       
/s/ Sheldon R. Erikson
 
  Director    March 10, 2011
Sheldon Erikson
       
 
       
/s/ Charles Hue Williams
 
  Director    March 10, 2011
Charles Hue Williams
       
 
       
/s/ Leiv R. Nergaard
 
  Director    March 10, 2011
Leiv L. Nergaard
       
 
       
/s/ Nancy K. Quinn
 
  Director    March 10, 2011
Nancy K. Quinn
       
 
       
/s/ John N. Seitz
 
  Director    March 10, 2011
John N. Seitz
       

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Exhibit Index
     
Exhibit   Description
*2.1
  Sale and Purchase Agreement relating to Licence P.255, Block 22/6a North, between Endeavour, Shell U.K. Limited and Shell EP Offshore Ventures Limited dated November 23, 2010.
 
   
* 2.2
  Sale and Purchase Agreement relating to Licence P.057, Block 21/9,between Endeavour and Shell EP Offshore Ventures Limited dated November 23, 2010.
 
   
2.3
  Agreement for the Sale and Purchase of the Cygnus Asset dated August 27, 2010. (Incorporated by reference to Exhibit 2.1 of our Quarterly Report on Form 10-Q (Commission File No. 001-32212) for the quarter ended September 30, 2010).
 
   
**2.4
  Purchase and Sale and Participation Agreement by and between Endeavour and Hillwood Energy Alabama LP. Schedules and Exhibits are omitted pursuant to Section 601(b)(2) of Regulation S-K. Endeavour agrees to furnish supplementally a copy of any omitted Schedule to the SEC upon request. (Incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K (Commission File No. 001-32212) filed on January 19, 2010).
 
   
**2.5
  Purchase and Sale Agreement between Endeavour and Cohort Energy Company. Schedules and Exhibits are omitted pursuant to Section 601(b)(2) of Regulation S-K. Endeavour agrees to furnish supplementally a copy of any omitted Schedule to the SEC upon request. (Incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K (Commission File No. 001-32212) filed on January 19, 2010).
 
   
3.1(a)
  Amended and Restated Articles of Incorporation (Incorporated by reference to Exhibit 3.2 of our Quarterly Report on Form 10-Q (Commission File No. 001-32212) for the quarter ended June 30, 2004).
 
   
3.1(b)
  Certificate of Amendment dated June 1, 2006 (Incorporated by reference to Exhibit 4.2 of our Registration Statement on Form S-3 (Commission File No. 333-139304) filed on December 13, 2006).
 
   
3.1(c)
  Certificate of Amendment dated June 1, 2010 (Incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on June 3, 2010).
 
   
*3.1(d)
  Amendment to Articles of Incorporation, dated November 17, 2010.
 
   
3.2(a)
  Amended and Restated Bylaws (Incorporated by reference to Exhibit 3.4 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on November 6, 2006).
 
   
3.2(b)
  Amendment to Amended and Restated By-laws dated December 12, 2007 by Endeavour International Corporation (Incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on December 13, 2007).

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Exhibit Index
     
Exhibit   Description
3.3
  Amended and Restated Certificate of Designation of Series B Preferred Stock filed February 26, 2004 (Incorporated by reference to Exhibit 3.3 of our Quarterly Report on Form 10-Q (Commission File No. 001-32212) for the quarter ended June 30, 2004).
 
   
*3.4
  Specimen of Common Stock Certificate.
 
   
3.5
  Certificate of Designation of Series A Preferred Stock of Endeavour International Corporation (Incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on November 6, 2006).
 
   
3.6(a)
  Certificate of Designation of Series C Preferred Stock of Endeavour International Corporation, (Incorporated by reference to Exhibit 3.2 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on November 6, 2006).
 
   
3.6(b)
  Amendment to Certificate of Designation of Series C Preferred Stock of Endeavour International Corporation, dated November 17, 2009 (Incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on November 23, 2009).
 
   
3.6(c)
  Amendment to Certificate of Designation of Series C Preferred Stock of Endeavour International Corporation, dated March 10, 2010 (Incorporated by reference to Exhibit 3.6(c) of our Annual Report on Form 10-K for the year ended December 31, 2009).
 
   
3.7
  Certificate of Designation of Series D Preferred Stock of Endeavour International Corporation (Incorporated by reference to Exhibit 3.3 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on November 6, 2006).
 
   
4.1(a)
  Warrants to Purchase Common Stock issued to Trident Growth Fund, LP dated July 29, 2003 (warrant # 2003-3) (Incorporated by reference to Exhibit 4.7 of our Annual Report on Form 10-KSB (Commission File No. 000-33439) for the year ended December 31, 2003).
 
   
4.1(b)
  First Amendment to Warrants to Purchase Common Stock dated February 26, 2004 (warrant # 2003-3) (Incorporated by reference to Exhibit 4.7 of our Annual Report on Form 10-KSB (Commission File No. 000-33439) for the year ended December 31, 2003).
 
   
4.2(a)
  Warrants to Purchase Common Stock issued to Gemini Capital, L.P. (Warrant #2002-1) (Incorporated by reference to Exhibit 4.6 of our Quarterly Report on Form 10-QSB (Commission File No. 000-33439) for the Quarter Ended June 30, 2002).

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Exhibit Index
     
Exhibit   Description
4.2(b)
  First Amendment to Warrants to Purchase Common Stock dated July 29, 2003 (Warrant # 2002-1) (Incorporated by reference to Exhibit 4.5 of our Annual Report on Form 10-KSB (Commission File No. 000-33439) for the year ended December 31, 2003).
 
   
4.2(c)
  Second Amendment to Warrants to Purchase Common Stock dated February 26, 2004 (Warrant # 2002-1) (Incorporated by reference to Exhibit 4.5 of our Annual Report on Form 10-KSB (Commission File No. 000-33439) for the year ended December 31, 2003).
 
   
4.3
  Indenture, dated as of January 20, 2005, between Endeavour International Corporation and Wells Fargo Bank, National Association, as Trustee, relating to the 6.00% Convertible Senior Notes due 2012 (Incorporated by reference to our Exhibit 4.1 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on January 24, 2005).
 
   
4.4
  Registration Rights Agreement dated January 24, 2008 by and between Endeavour International Corporation and Smedvig QIF Plc (Incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on January 24, 2008).
 
   
4.5
  Trust Deed dated January 24, 2008 by and among Endeavour International Corporation, Endeavour Energy Luxembourg S.a.r.l. and BNY Corporate Trustee Services Limited, as trustee (Incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on January 24, 2008).
 
   
†10.1
  2004 Incentive Plan, effective February 26, 2004 (Incorporated by reference to Exhibit 10.36 of our Annual Report on Form 10-KSB (Commission File No. 000-33439) for the year ended December 31, 2003).
 
   
†10.2
  2007 Incentive Plan (Incorporated by reference to Exhibit 10.1 to our Quarterly Report (Commission file No. 001-32212) for the quarter ended June 30, 2007).
 
   
†10.3
  2010 Incentive Plan (Incorporated by reference to Exhibit A to our definitive proxy statement on Schedule 14A filed on April 20, 2010).
 
   
†10.4
  Second Amended and Restated Employment Agreement by and between William L. Transier and the Company (Incorporated by reference to Exhibit 10.4 to our Annual Report on Form 10-K (Commission File No. 001-32212) for the year ended December 31, 2008).
 
   
†10.5
  Employment Offer Letter to Carl Grenz, dated August 15, 2008 (Incorporated by reference to Exhibit 10.1 of our Quarterly Report on Form 10-Q (Commission File No. 001-32212) for the quarter ended September 30, 2008).
 
   
†10.6
  Form of Change in Control on Termination of Benefits Agreement (Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K (Commission File No. 000-32212) filed on February 15, 2008).

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Exhibit Index
     
Exhibit   Description
†10.7
  Form of Amended Change in Control Termination Benefits Agreement between the Company and Kirksey, Grenz, Williams and Stover, individually (Incorporated by reference to Exhibit 10.8 of our Annual Report on Form 10-K for the year ended December 31, 2008).
 
   
†10.8
  Change in Control and Termination Benefits Agreement dated January 11, 2010, by and between Endeavour International Corporation and James Joseph Emme (Incorporated by reference to Exhibit 10.7 of our Annual Report on Form 10-K for the year ended December 31, 2009).
 
   
†10.9
  Form of Restricted Stock Agreement under the 2010 Incentive Plan (Incorporated by reference to Exhibit 10.2 of our Quarterly Report on Form 10-Q (Commission File No. 001-32212) for the quarter ended September 31, 2010).
 
   
†10.10
  Form of Stock Option Agreement under the 2010 Incentive Plan (Incorporated by reference to Exhibit 10.3 to our Quarterly Report on Form 10-Q (Commission File No. 001-32212) for the quarter ended September 31, 2010).
 
   
10.11(a)
  Form of Stock Option Agreement under the 2010 Incentive Plan (Incorporated by reference to Exhibit 10.3 to our Quarterly Report on Form 10-Q (Commission File No. 001-32212) for the quarter ended September 31, 2010).
 
   
10.11(b)
  Incremental Term Loan Commitment and Amendment Agreement among Endeavour International Corporation, Endeavour Energy UK Limited, various lenders and Cyan Partners, LP dated October 21, 2010 (Incorporated by reference to Exhibit 10.4(b) to our Quarterly Report on Form 10-Q (Commission File No. 001-32212) for the quarter ended September 31, 2010).
 
   
10.11(c)
  Incremental Fee Letter among Endeavour International Corporation, Endeavour Energy UK Limited, various lenders and Cyan Partners, LP, as supplement to the Incremental Term Loan Commitment and Amendment Agreement, dated October 21, 2010 (Incorporated by reference to Exhibit 10.4(b) to our Quarterly Report on Form 10-Q (Commission File No. 001-32212) for the quarter ended September 31, 2010).
 
   
10.11(d)
  First Amendment to Credit Agreement, U.S. Security Agreement and Subsidiaries Guaranty, dated as of February 3, 2011, by and among Endeavour International Corporation, Endeavour Energy UK Limited, Cyan Partners, LP, as administrative agent, and the lenders party thereto (Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on February 9, 2011).
 
   
10.12(a)
  Subscription and Registration Rights Agreement, dated October 19, 2006, by and among Endeavour International Corporation and the Investors party thereto (Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on October 25, 2006).

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Exhibit Index
     
Exhibit   Description
10.12(b)
  Amendment No. 1 to Subscription and Registration Rights Agreement, January 29, 2010, by and among Endeavour International Corporation and the Investors party thereto (Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on February 1, 2010).
 
   
**10.13
  Final Participation Agreement between Endeavour and Cohort Energy Company (Incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on January 19, 2010).
 
   
†10.14
  Restricted Stock Award Agreement between Endeavour International Corporation and J. Michael Kirksey dated September 26, 2007 (Incorporated by reference to Exhibit 10.31 to our Annual Report on Form 10-K (Commission File No. 001-32212) for the year ended December 31, 2007).
 
   
†10.15
  Restricted Stock Award Agreement between Endeavour International Corporation and John G. Williams dated October 1, 2007 (Incorporated by reference to Exhibit 10.32 to our Annual Report on Form 10-K (Commission File No. 001-32212) for the year ended December 31, 2007).
 
   
†10.16
  Stock Option Agreement between Endeavour International Corporation and J. Michael Kirksey dated September 26, 2007 (Incorporated by reference to Exhibit 10.33 to our Annual Report on Form 10-K (Commission File No. 001-32212) for the year ended December 31, 2007).
 
   
†10.17
  Stock Option Agreement between Endeavour International Corporation and John G. Williams dated October 1, 2007 (Incorporated by reference to Exhibit 10.34 to our Annual Report on Form 10-K (Commission File No. 001-32212) for the year ended December 31, 2007).
 
   
†10.18
  Stock Option Agreement between Endeavour International Corporation and Carl D. Grenz dated November 3, 2008 (Incorporated by reference to Exhibit 10.22 to our Annual Report on Form 10-K (Commission File No. 001-32212) for the year ended December 31, 2008).
 
   
†10.19
  Stock Option Agreement between Endeavour International Corporation and Carl D. Grenz dated November 3, 2008 (Incorporated by reference to Exhibit 10.23 to our Annual Report on Form 10-K (Commission File No. 001-32212) for the year ended December 31, 2008).
 
   
†10.20
  Restricted Stock Award Agreement between Endeavour International Corporation and Carl D. Grenz dated November 3, 2008 (Incorporated by reference to Exhibit 10.24 to our Annual Report on Form 10-K (Commission File No. 001-32212) for the year ended December 31, 2008).
 
   
†10.21
  Restricted Stock Award Agreement between Endeavour International Corporation and Carl D. Grenz dated November 3, 2008 (Incorporated by reference to Exhibit 10.25 to our Annual Report on Form 10-K (Commission File No. 001-32212) for the year ended December 31, 2008).

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Endeavour International Corporation
Exhibit Index
     
Exhibit   Description
*†10.22
  Restricted Stock Award Agreement between Endeavour International Corporation and James J. Emme dated January 10, 2010.
 
   
10.23
  Agreement for the Sale and Purchase of the Endeavour Energy Norge AS dated April 2, 2009 (Incorporated by reference to Exhibit 4.1 of our Quarterly Report on Form 10-Q (Commission File No. 001-32212) for the quarter ended March 31, 2009).
 
   
†10.24
  Form of Stock Redemption Agreement dated November 17, 2009 by and among Endeavour International Corporation and the holders of its Series C Preferred Stock (Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on November 23, 2009).
 
   
10.25(a)
  Form of Note Agreement dated November 17, 2009 by and among Endeavour International Corporation and the holders of its Series C Preferred Stock (Incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on November 23, 2009).
 
   
10.25(b)
  Amendment to Note Agreement dated November 17, 2009 by and among Endeavour International Corporation and the holders of its Series C Preferred Stock, dated March 10, 2010 (Incorporated by reference to Exhibit 10.26(b) of our Annual Report on Form 10-K for the year ended December 31, 2009).
 
   
10.26
  Common Stock Purchase Agreement, dated as of February 4, 2010, by and between Endeavour International Corporation and the purchasers named therein ((Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on February 5, 2010).
 
   
10.27
  Registration Rights Agreement, dated as of February 4, 2010, by and between Endeavour International Corporation and the purchasers named therein (Incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on February 5, 2010).
 
   
10.28
  Common Stock Purchase Agreement, dated August 16, 2010, by and between Endeavour International Corporation and the purchasers named therein (Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on August 20, 2010.
 
   
*12.1
  Computation of Ratios of Earnings to Fixed Charges.
 
   
*12.2
  Computation of Ratios of Earnings to Fixed Charges and Preference Securities Dividends.
 
   
*14.1
  Code of Business Conduct of Endeavour International Corporation.
 
   
*21.1
  List of Subsidiaries.

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Exhibit Index
     
Exhibit   Description
*23.1
  Consent of Independent Registered Public Accounting Firm — KPMG LLP.
 
   
*23.2
  Consent of Independent Reserve Engineers — Netherland, Sewell & Associates, Inc.
 
   
*31.1
  Certification of William L. Transier, Chief Executive Officer, pursuant to Rule 13a-14(a) of the Securities and Exchange Act of 1934, as amended.
 
   
*31.2
  Certification of J. Michael Kirksey, Chief Financial Officer, pursuant to Rule 13a-14(a) of the Securities and Exchange Act of 1934, as amended.
 
   
‡32.1
  Certification of William L. Transier, Chief Executive Officer, pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
   
‡32.2
  Certification of J. Michael Kirksey, Chief Financial Officer, pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
   
‡99.1
  Report of Netherland, Sewell & Associates, Inc., Independent Petroleum Engineers and Geologists.
 
*   Filed herewith.
 
  Furnished herewith.
 
  Identifies management contracts and compensatory plans or arrangements.
 
**   Portions of this exhibit have been omitted pursuant to a request for confidential treatment under Rule 24b-2 of the Securities Exchange Act of 1934, and the omitted material has been separately filed with the Securities and Exchange Commission.

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