10-K

United States
Securities and Exchange Commission

Washington, D.C. 20549

Form 10-K

þ Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the Fiscal Year Ended December 31, 2009

o Transition Report Under Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from                      to                     

Commission file number: 001-32212

Endeavour International Corporation

(Exact name of registrant as specified in its charter)

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

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

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

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class of Stock	Name of Each Exchange on Which Registered
Common Stock - $0.001 par value per share	NYSE-Amex

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer as defined in Rule 405 of the Securities Act. o Yes þ No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. o Yes þ No

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 2 months (or for such shorter period that the registrant was required to submit and post such files). o Yes o No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

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

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

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant was $154.0 million computed by reference to the closing sale price of the registrant’s common stock on the NYSE-Amex on June 30, 2009, the last business day of the registrant’s most recently completed second fiscal quarter. Shares of common stock held by executive officers and directors of the registrant are not included in the computation. However, the registrant has made no determination that such individuals are “affiliates” within the meaning of Rule 405 of the Securities Act of 1933.

As of March 12, 2010, 160,247,205 shares of the registrant’s common stock were outstanding.

Documents Incorporated By Reference:

Portions of the registrant’s definitive proxy statement relating to the 2010 Annual Meeting of Stockholders, which will be filed within 120 days of December 31, 2009, are incorporated by reference into Part III of this Form 10-K.

Table of Contents

Part I	1
Item 1. Business	1
Item 1A. Risk Factors	15
Item 1B. Unresolved Staff Comments	33
Item 2. Properties	33
Item 3. Legal Proceedings	36
Part II	36
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	36
Item 6. Selected Financial Data	37
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	39
Item 7A. Quantitative and Qualitative Disclosures About Market Risk	60
Item 8. Financial Statements and Supplementary Data	62
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	123
Item 9A. Controls and Procedures	123
Item 9B. Other Information	126
Part III
Item 10. Directors, Executive Officers and Corporate Governance of the Registrant	126
Item 11. Executive Compensation	126
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	126
Item 13. Certain Relationships and Related Transactions, and Director Independence	126
Item 14. Principal Accounting Fees and Service	127
Part IV	127
Item 15. Exhibits and Financial Statement Schedules	127
Signatures	128
EX-3.6.C
EX-10.7
EX-10.13.C
EX-10.15.B
EX-10.26.B
EX-12.1
EX-12.2
EX-21.1
EX-23.1
EX-23.2
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-99.1

Quantities of natural gas are expressed in this Annual Report on Form 10-K in terms of thousand cubic feet (Mcf) and million cubic feet (MMcf). Oil is quantified in terms of barrels (Bbls) and thousands of barrels (Mbbls). Natural gas is compared to oil in terms of barrels of oil equivalent (BOE), thousand barrels of oil equivalent (MBOE) or million barrels of oil equivalent (MMBOE). One barrel of oil is the energy equivalent of six Mcf of natural gas. With respect to information relating to our working interest in wells or acreage, “net” oil and gas wells or acreage is determined by multiplying gross wells or acreage by our working interest therein. References to number of potential well locations are gross, unless otherwise indicated.

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

Endeavour International Corporation

Part I

Item 1. Business

Endeavour International Corporation is an independent oil and gas company engaged in the exploration, development and acquisition of energy reserves in the U.S. and U.K. Unless the context otherwise requires, references to “Endeavour”, “we”, “us” or “our” mean Endeavour International Corporation and our consolidated subsidiaries.

General

Since commencing operations in 2004, we have built a strong asset base and achieved steady reserve growth through acquisitions and exploration and development activities. Historically, we have focused our operations in the North Sea, but have recently expanded our focus to target unconventional U.S. onshore resource shale plays with shorter production-cycle times and compelling risk/return profiles. As a result, we have established a strong foundation of producing assets and undeveloped acreage in both established and emerging U.S. onshore resource plays, including approximately 66,000 gross (27,000 net) acres within the Haynesville and Marcellus Shale regions, complemented by our four development assets in the UK North Sea.

Our strategic shift to expand our focus to include U.S. onshore asset development has been achieved through measured and specific steps taken in 2009. In May 2009, we sold our assets and operations in the Norwegian sector of the North Sea for $150 million. Proceeds from this sale enabled us to enter into a joint venture relationship with an established U.S. gas shale operator, providing us with acreage positions and production in the Haynesville and Marcellus gas shales. We also entered into additional joint venture agreements with other selected operators, providing exposure to emerging shale plays in Alabama and Montana.

The primary focus of our U.S. unconventional gas shale development efforts will target reserve and production growth in the Haynesville and Marcellus Shales. We have approximately 7,250 net acres with over 200 potential drilling locations in the Northern Louisiana and East Texas Haynesville Shale, with acreage located in Red River, DeSoto, Bienville and Caddo Parishes in Louisiana and Harrison and Gregg Counties in Texas. Our Marcellus gas shale acreage is comprised of 19,750 net acres and over 300 potential drilling locations, with acreage between two of the most active parts of the play. We also have exploratory plans in emerging shale plays in Alabama and Montana, with 63,000 and 75,000 net acres, respectively. Early well results will determine the pace and scope of subsequent development initiatives in each of these plays.

In addition to our recent expansion into the onshore U.S. shale plays, we intend to continue to actively manage our North Sea assets in a manner that maximizes value and enables us to allocate resources to effectively pursue our strategic objectives. Our North Sea activities and assets remain a key source of value that can be further developed to increase our overall reserves and production. Our major development projects – Bacchus, Columbus, Cygnus and Rochelle – have the potential to significantly expand our total proved reserves and production levels.

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Endeavour International Corporation

Further exploration and development efforts will continue on our current and nearby properties, as appropriate, to best achieve maximum risk-adjusted value for our North Sea assets.

With the recent volatility in commodity prices and concerns over the financial markets, we will continue to pursue our strategy of exploiting a balanced portfolio of exploration and development assets through a disciplined approach. We are attempting to balance the capital intensive, long lead-time nature of our North Sea assets with our recent entry into the onshore U.S. shale plays. We believe the resource-rich shale plays provide us with less expensive, shorter lead time opportunities in some of the most active hydrocarbon producing areas in the U.S. We intend to develop our existing assets in the North Sea, which we expect to enter production beginning in 2011, while simultaneously pursuing the development of our leasehold positions in the Haynesville and Marcellus Shales.

Strategic Alternatives for North Sea Assets

On March 15, 2010, we announced that our board of directors has approved a review of strategic alternatives for its North Sea assets. In an effort to unlock the value of our underlying North Sea assets, we will study a full range of options, including:

• Continuing to execute current operations plan;

• Entering into a joint venture to accelerate activities in the North Sea; and

• Selling specific assets or the North Sea entire business.

We will announce the results of the effort once a course of action is chosen. At the end of this review process, we may elect to make no changes.

Our Areas of Operation

North Sea

The exploitation of North Sea oil reserves has been ongoing for a number of decades and the resulting increase in international oil prices made the large investments needed for extraction attractive. Although production costs are relatively high, the quality of the oil, the political stability of the region, and the proximity of important markets in Western Europe has made the North Sea an important oil producing region.

Our development assets in the Bacchus, Columbus, Cygnus and Rochelle fields comprise the primary component of our UK North Sea portfolio. We currently have development plans under way in each of these primary fields. When these projects are fully producing, they have the potential to exceed our current production levels from all other fields. We also hold interests in producing and non-producing properties in the UK sector of the North Sea. Our producing properties include the Alba, Bittern, Enoch and Goldeneye fields and recently suspended production from certain of our fields. We anticipate re-developing these suspended fields, if commercially advisable and practicable, once additional production commences from the nearby Rochelle field. We believe our assets in the North Sea possess significant value that can continue to be harvested or monetized in a manner that maximizes shareholder value.

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Primary Development Fields

Rochelle

We hold a 55.6% working interest in and operate our Rochelle field assets. Our interests in the Rochelle field account for 6.3 MMBOE of our proved reserves at December 31, 2009. The environmental impact study for the subsea development and pipeline corridor has been completed with no sensitivities identified.

Moreover, recent seismic studies in the area near our Rochelle field in the North Sea indicate that the natural gas formation may be larger than we had previously understood. We believe this larger Rochelle area can be developed using the current infrastructure. We are planning to drill a well to test the westward expansion of the Rochelle play in 2010. The Rochelle development is scheduled to achieve first production in 2011. This first production is dependent on approval of the Field Development Plan from the Department of Energy and Climate Change (“DECC”), which is further dependent on receiving acceptable commercial terms from the infrastructure holders for the off-take solution.

Cygnus

We hold a 12.5% working interest in our Cygnus field assets, which are operated by Gaz de France. Our interests in the Cygnus field account for 5.7 MMBOE of our proved reserves at December 31, 2009. These proved reserves are associated with the eastern portion of the field. Appraisal drilling to test two additional fault blocks in the western portion of the field has begun, with drilling underway of a well in the fourth fault block. A field development plan has been filed, with production from the eastern portion of the field expected to begin in 2011.

Columbus

We hold a 25% working interest in our Columbus field assets, which are operated by Serica Energy plc. Our interests in the Columbus field account for 1.8 MMBOE of our proved reserves at December 31, 2009. The host platform has been identified and commercial agreements are under negotiation with first production expected in 2012.

Bacchus

We hold a 10% working interest in our Bacchus field assets, which are operated by Apache Corporation. The development of the Bacchus field is expected to be sanctioned in 2010 by the DECC with first production expected to commence in 2011. The discovery well was drilled in 2005, followed by a down-dip sidetrack appraisal well that tested the upper part of the reservoir. A three-well subsea development tie-back to the Forties field is planned.

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Producing Fields

We have four producing fields in the U.K. – Alba, Bittern, Enoch and Goldeneye. Combined these fields held 2.5 MMBOE of proved reserves at December 31, 2009. The Goldeneye field represents nearly all of our current gas production in the U.K.

Our Ivanhoe, Rob Roy, Hamish (collectively, “IVRRH”), Renee and Rubie fields all produced to a single floating production facility that has experienced significant increases in operating costs in recent periods. As a result, production was suspended in the first quarter of 2009 and will remain suspended until the development activities at Rochelle are operational, which we currently anticipate to be during 2011. After the start of Rochelle production, we expect to re-develop these fields if commercially advisable and practicable.

United States

We have made significant recent acquisitions to bolster our holdings in unconventional U.S. onshore resource shale plays. As of March 16, 2010, our U.S. acreage consisted of approximately 165,000 net acres. We believe that our U.S. acreage provides us with development projects with shorter timeframes compared to our North Sea assets, and a strong return/risk profile. We anticipate that development of our U.S. acreage will be less expensive than our North Sea assets and reduce our overall finding and development costs. In addition, our U.S. acreage covers a broad spectrum of resource plays, from established and explored areas, such as the Haynesville and Marcellus Shales, to “frontier” areas, in Alabama and Montana.

Haynesville Shale

The Haynesville Shale has become one of the most active natural gas plays in the U.S. This area is defined by a Jurassic shale formation located approximately 1,000 to 1,500 feet below the base of the Cotton Valley formation at depths ranging from approximately 10,500 feet to 13,000 feet. The formation is 125 to 250 feet thick and is composed of organic-rich, black shale. It is located across numerous parishes in Northwest Louisiana, primarily in Caddo, Bossier, Red River, DeSoto, Webster and Bienville parishes and also in East Texas. Numerous shallower secondary objectives exist in the Haynesville Shale play area, including the overlying Jurassic Cotton Valley Sandstone and Bossier Shale intervals.

To facilitate our entrance into the Haynesville Shale, we have entered into a joint venture relationship with Cohort Energy, a subsidiary of J-W Operating Company (“J-W Operaing”). J-W Operating, a privately-held company, is a proven operator that has drilled over 130 horizontal wells in the Barnett, Haynesville, Marcellus and other shale formations since 2004. In separate transactions, we have acquired interests in both producing wells and acreage that is prospective for the Haynesville Shale. We have not acquired any meaningful Haynesville Shale interests outside of our relationship with Cohort Energy. Both the Haynesville and the Marcellus Shale project wells (described below) will be operated by J-W Operating, which has substantial experience in the Haynesville and Marcellus Shales.

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Endeavour International Corporation

In October 2009, we purchased 50% of Cohort’s working interest in 24 wells located in five fields and certain proved undeveloped locations associated with Cohort’s proved developed assets in North Louisiana and East Texas for $15 million in cash. These 24 wells, some of which produce from the Cotton Valley trend and some of which produce from the Haynesville Shale, are associated with net proved reserves of approximately 1.6 MMBOE.

In addition to these wells, through our joint venture with Cohort Energy, we hold interests in approximately 17,700 gross (7,250 net) acres with Haynesville Shale potential. In connection with this acreage, we have identified over 200 potential drilling locations. Of this acreage, approximately 13,500 gross (5,800 net) acres are located in the Haynesville Shale core area in Louisiana with over 150 potential drilling locations.

Our most recent Haynesville well in Red River Parish, Louisiana, the Indigo Minerals 3#1-H, initially flowed approximately 21 MMcf/d and has produced over 2 Bcf (gross) gas in its first 6 months of production. Currently, we are drilling the Bachelor 3#1-H as a direct offset to the Indigo Minerals well. We are also drilling the Longview North 1H in Gregg County, Texas as a horizontal Cotton Valley Sandstone test.

Marcellus Shale

The Marcellus Shale is a Middle Devonian-aged shale that underlies much of Pennsylvania, New York, Ohio, West Virginia and adjacent states. The Marcellus Shale is an organic-rich shale gas target which we believe is analogous to the Mississippian Barnett Shale in Texas. Within the past few years, advances in two technologies, fracture stimulation and horizontal drilling, have produced promising results in the Marcellus Shale. These developments have resulted in significantly increased leasing and drilling activity in the area. As with our Haynesville Shale acreage, we have acquired all of our interests in the Marcellus Shale through a 50/50 joint venture relationship with Cohort Energy/J-W Operating who will operate the project. We acquired interests in approximately 48,300 gross (19,750 net) acres prospective for the Marcellus Shale in several project areas, including portions of Cameron, Elk, Potter, McKean, Jefferson and Clarion counties, Pennsylvania. In connection with this acreage, we have over 300 potential drilling locations. Currently, we are planning to complete the Pardee C-9H horizontal well in Cameron County followed by vertical pilot tests in other selected project areas.

Alabama Gas Shales

Through our joint venture with Hillwood Energy Alabama LP, an affiliate of Hillwood International Energy, we hold a 50% non-operating interest in approximately 160,000 gross (63,000 net) acres with exposure to emerging gas shale plays in western Alabama. Hillwood has an extensive and successful background as a participant and an operator in the Barnett shale play. Our position allows us to target multiple gas shale intervals. If successful, we believe this acreage could yield in excess of 400 potential drilling locations. We intend to participate in the drilling of vertical pilot wells during the first half of 2010, which may be followed by horizontal re-entries. We will monitor the results of these wells before formulating an appropriate development plan.

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Central Montana Oil-prone Shales

Through our joint venture with a private company, we own a 25% non-operating interest in approximately 300,000 gross (75,000 net) acres in central Montana. In this region, historical conventional oil production from Cretaceous through Mississippian reservoirs has totaled over 130 MMBoe. Our acreage contains approximately 900 potential drilling locations and has exposure to both the Mississippian Heath and Devonian Bakken oil-prone source shales. We currently plan to participate in the drilling of pilot wells during 2010. As with our Alabama acreage, we intend to monitor the results of these wells before determining further appraisal or development plans.

Reserves

Our proved oil and gas reserves at December 31, 2009, 2008 and 2007 included the following:

	Oil		Gas		Oil Equivalents
	(MBbls)		(MMcf)		(MBOE)
2009:
United Kingdom		3,348		78,316		16,401
United States		18		10,784		1,815
		3,366		89,100		18,216
2008:
United Kingdom		2,131		27,130		6,653
United States		18		690		133
Discontinued operations — Norway		1,406		4,977		2,236
		3,555		32,797		9,022
2007:
United Kingdom		3,284		11,812		5,252
Discontinued operations — Norway		2,056		8,434		3,461
		5,340		20,246		8,713

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Endeavour International Corporation

Our proved developed and undeveloped oil and gas reserves at December 31, 2009, 2008 and 2007 included the following:

	Proved		Proved
	Developed		Undeveloped		Total Proved
	Reserves		Reserves		Reserves
	(MBOE)		(MBOE)		(MBOE)
2009:
United Kingdom		2,103		14,298		16,401
United States		792		1,023		1,815
		2,895		15,321		18,216
2008:
United Kingdom		2,595		4,058		6,653
United States		46		87		133
Discontinued Operations — Norway		2,122		114		2,236
		4,763		4,259		9,022
2007:
United Kingdom		3,947		1,305		5,252
Discontinued Operations — Norway		2,752		709		3,461
		6,699		2,014		8,713

Preparation of Oil and Gas Reserve Information

We have established internal controls over reserve estimation processes and procedures to support the accurate and timely preparation and disclosure of reserve estimations in accordance with SEC and GAAP requirements. These controls include oversight of the reserves estimation reporting processes by our technical staff, annual external audits of all of our proved reserves by independent reserve engineers and secured access to reservoir databases and systems. Proved reserve estimates are prepared by our technical staff and reviewed and approved by our executive team, including our Executive Vice President of Exploration. Reserves are reviewed internally with senior management quarterly and presented to our Board of Directors in summary form on an annual basis.

For 2009, our oil and gas reserve estimates were prepared by our internal reservoir engineers and audited by independent reserve engineers, Netherland, Sewell & Associates, Inc. (“NSAI”). For 2008 and 2007, our proved oil and gas reserves were estimated by NSAI.

Each year, our internal technical staff use reliable technologies to evaluate all technical data available on each field including production data, wells logs, pressure data, petrophysical analysis, fluid properties, seismic data, seismic interpretations and well control along with offset well data. We estimate the quantity of oil and gas reserves and provide our estimates, analysis and data to our independent reserve engineers.

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Endeavour International Corporation

For 2008 and 2007, we provided our analysis and data to NSAI for their independent estimates using the Securities and Exchange Commission, or SEC, definitions of proved reserves. The independent engineers then performed their own analysis of the same raw data including analysis of all production data, pressure data, well logs, petrophysical analysis, fluid analysis, seismic data and mapping based on that seismic data to determine their own reserves in place and ultimately estimated the quantity of proved oil and gas reserves attributable to a specific property.

Qualification of Reserves Preparers and Auditors

We employ oil and gas technical professionals, including geophysicists, petrophysicists, geologists, petroleum engineers, and production and reservoir engineers, who have an average of 10 to 35 years of experience in their technical fields. In addition, we engage experienced and qualified consultants to perform various comprehensive seismic acquisitions, processing, reprocessing, interpretation, and other related services.

NSAI provides worldwide petroleum property analysis services for energy clients, financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-002699. The technical persons responsible for conducting this audit for NSAI meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. NSAI opined that the overall proved reserves for the reviewed properties as estimated by us are, in the aggregate, reasonable, prepared in accordance with generally accepted petroleum engineering and evaluation principles and conform to the SEC’s definition of proved reserves as set forth in Rule 210.4-10(a) of Regulation S-X. NSAI has informed us that the tests and procedures used during its reserves audit conform to the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Paragraph 2.2(f) of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information defines a reserves audit as the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed, (2) the adequacy and quality of the data relied upon, (3) the depth and thoroughness of the reserves estimation process, (4) the classification of reserves appropriate to the relevant definitions used, and (5) the reasonableness of the estimated reserve quantities. A reserve audit is not the same as a financial audit and is less rigorous in nature than an independent reserve report where the independent reserve engineer determines the reserves on his or her own.

2010 Planned Capital Expenditures

We anticipate spending approximately $90 million during 2010 to fund oil and gas activities in the U.S. and U.K. The majority of this amount is controllable by Endeavour. Our primary focus during 2010 in the U.S. will be in the Haynesville area as we believe this acreage contains near-term production potential. The ongoing U.S. program and expenditures will be tailored based on early drilling results. During 2010, we also expect to begin the evaluation program of our other

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U.S. assets in the Marcellus area and the two frontier plays in Alabama and Montana. Four U.K. wells have been or will be drilled in 2010; two Cygnus appraisal wells in the western portion of the field; the Deacon well that began in 2009 and finished in 2010, and the exploration well west of the Rochelle development. While this drilling is occurring, we expect to continue to further our development programs at our four existing development projects, including ongoing engineering assessments for future production and commercial off-take solutions. We intend to fund these development activities through cash on hand, and cash flow generated from operations, as well as expansion of our credit facilities as needed.

The timing, completion and process of our 2010 capital program is subject to a number of factors, including availability of capital, drilling results, drilling and production costs, availability of drilling services and equipment, partner approvals and technical work. Based on these and other factors, we may increase or decrease our planned capital program or prioritize certain projects over others.

Company History

Endeavour International Corporation (a Nevada corporation formed in 2000) is an independent oil and gas company engaged in the acquisition, exploration and development of energy reserves.

In November 2004, we purchased a 76.66% majority interest in OER oil AS (“OER”), a privately held Norwegian exploration and production company. In January 2005, we purchased the remaining 23.34% interest in OER from the minority interest holders.

In May 2006, we announced our largest acquisition to date – the purchase of producing properties in the U.K. (the “Talisman Acquisition”). On October 31, 2006, we completed this acquisition of all the outstanding shares of Talisman Expro Limited for $366 million, after purchase price adjustments and expenses. As a result of the Talisman Acquisition, we acquired interests in eight fields in the United Kingdom sector of the North Sea and over seven million BOE of proved reserves as of the closing date.

In the second quarter of 2006, we purchased an eight percent interest in the Enoch Field in the North Sea for approximately $11.7 million. The field is one of the first discoveries to be developed along the median line between the United Kingdom and Norway after the ratification of the U.K./Norway Framework Treaty concerning cross-boundary petroleum cooperation.

While working to complete and integrate these acquisitions, we also moved forward in our drilling program. During 2004 and 2005, we gained approval in the U.K. and Norway to act as an operator or licensee in both countries and began participating in the license round process. We continue to participate in the licensing rounds in the U.K. and Norway. We have also pursued various farm-in and license transfer opportunities to build acreage and exploration potential and spread the risk of exploration drilling among multiple prospects. Most notably, we have four significant development projects ongoing in the U.K. – Bacchus, Columbus, Cygnus and Rochelle. In 2008, we initiated operations in the U.S. and announced our first production there in January 2009.

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On May 14, 2009, we completed the divestiture of our Norwegian subsidiary, Endeavour Energy Norge AS, to VerbundnetzGas AG, a German utility company, for cash consideration of $150 million. We used the proceeds from this divestiture primarily to pay down our outstanding debt and streamline our capital structure, acquire new properties in the U.S. and support our ongoing drilling program. This divestiture allows us to focus our efforts on our acquired positions in our U.S. resource plays, as wells as develop our significant North Sea assets.

In the fourth quarter of 2009, we purchased producing properties and exploration acreage in the U.S. We purchased additional exploration acreage in the U.S. in January 2010. This accumulation of acreage in the U.S. reflects our expansion into resource plays in the U.S.

Geographical Data

We operate in one industry segment, that being oil and gas exploration and production, in two geographical areas. See Note 21 to our consolidated financial statements in “Item 8, Financial Statements and Supplementary Data” for geographic operating segment information, including results of operations and segment assets.

Competition

We encounter intense competition from other oil and gas companies in all areas of our operations, including the acquisition of producing properties and undeveloped acreage. Our competitors include major integrated oil and gas companies, numerous independent oil and gas companies and individuals. Many of our competitors are large, well-established companies with substantially larger operating staffs and greater capital resources and have been engaged in the oil and gas business for a much longer time than our company.

Petroleum and natural gas producers also compete with other suppliers of energy and fuel to industrial, commercial and individual customers. Competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the governments and/or agencies thereof and other factors out of our control including, international political conditions, overall levels of supply and demand for oil and gas, and the markets for synthetic fuels and alternative energy sources.

Significant Customers

Our sales in the U.K. are to a limited number of customers, each of which accounts for more than 10% of revenue: Chevron North Sea Ltd; Shell U.K. Limited, and Esso Exploration and Production. Our sales in the U.S. are sold through our arrangements with the operators of the fields, with substantially all of the sales being to Cohort Energy.

Employees

As of March 16, 2010, we have 43 full-time employees. We believe that we maintain good relationships with our employees, none of whom are covered by a collective bargaining agreement.

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Environmental Matters and Regulation

Endeavour was established on a commitment to find and develop energy resources in a manner that protects the health and safety of people and preserves the quality of the environment. Adhering to high performance standards in the areas of health, safety and the environment (“HSE”) is an integral part of our operations in our efforts to end each day “injury and incident free.”

North Sea

Our operations in the U.K. portions of the North Sea are subject to numerous U.K. and European Union laws and regulations relating to environmental matters, health and safety. Environmental matters are addressed before oil and gas production activities commence and during the exploration and production activities. Before a U.K. licensing round begins, the DECC will consult with various public bodies that have responsibility for the environment. Applicants for production licenses are required to submit a summary of its management systems and how those systems will be applied to the proposed work program. Additionally, the Offshore Petroleum Production and Pipelines (Assessment of Environmental Effects) Regulations 1999 require the Secretary of State to exercise his licensing powers under the U.K. Petroleum Act in such a way to ensure that an environmental assessment is undertaken and considered before consent is given to certain projects.

United States

With our entry into the U.S. onshore shale plays, our U.S. operations are subject to stringent federal, state and local laws and regulations relating to environmental protection, as well as controlling the manner in which various substances, including wastes generated in connection with oil and gas industry operations, are released into the environment. Compliance with these laws and regulations require the acquisition of permits authorizing air emissions and wastewater discharge from operations and can affect the location or size of wells and facilities, limit or prohibit the extent to which exploration and development may be allowed, and require proper closure of wells and restoration of properties that are being abandoned. Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties, imposition of remedial obligations, incurrence of capital costs to comply with governmental standards, and even injunctions that limit or prohibit exploration and production operations or the disposal of substances generated in connection with oil and gas industry operation.

We currently lease a number of properties that for many years have been used for the exploration and production of oil and gas. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or wastes may have been disposed of or released on or under the properties operated or leased by us or on or under other locations where such hydrocarbons or wastes have been taken for recycling or disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or wastes was not under our control. These properties and the hydrocarbons and

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wastes disposed thereon may be subject to laws and regulations imposing joint and several, strict liability, without regard to fault or the legality of the original conduct, that could require us to remove or remediate previously disposed wastes or environmental contamination, or to perform remedial plugging or pit closure to prevent future contamination.

In June 2009, the U.S. House of Representatives passed a bill — the “American Clean Energy and Security Act of 2009,” also known as the “Waxman-Markey cap-and-trade legislation” (“ACESA”) — to control and reduce the emission of “greenhouse gases” (“GHGs”), such as carbon dioxide and methane, that may be contributing to warming of the Earth’s atmosphere and other climatic changes. The U.S. Senate is currently considering similar legislation that seeks to reduce emission of GHGs in the U.S. through the granting of emission allowances which would gradually be decreased over time. Moreover, more than one-third of the states, either individually or through multi-state initiatives, already have begun implementing legal measures to reduce emissions of GHGs. Also, on December 15, 2009, the U.S. Environmental Protection Agency (“EPA”) published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. EPA has also proposed regulations that would require a reduction in emissions of GHGs from motor vehicles, and this regulatory action, if finalized, could also lead to the imposition of GHG emission limitations in Clean Air Act permits for certain stationary sources. In addition, on September 22, 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S. beginning in 2011 for emissions occurring in 2010. Although our facilities were not subject to the EPA’s GHG reporting rule adopted in September 2009, EPA has indicated that it is evaluating whether the rule should be applied to oil and gas production activities, perhaps on a field-wide basis. While it is not possible at this time to fully predict how legislation or new regulations that may be adopted in the U.S. to address GHG emissions would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions, and could have an adverse effect on demand for the oil and natural gas that we produce.

The U.S. Congress is currently considering legislation to amend the federal Safe Drinking Water Act (“SDWA”), to subject hydraulic fracturing operations to regulation under the SDWA and to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate oil and gas production. Sponsors of bills currently pending before the U.S. Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. Proposed legislation would require, among other things, the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings against producers. In addition, these bills, if adopted, could establish an additional level of regulation and permitting of hydraulic fracturing operations at the federal level, which could lead to operational delays, increased operating costs and additional regulatory burdens that could make it more difficult for us to perform hydraulic fracturing, which is an important component of well development. Any impairment of our ability to perform hydraulic fracturing could have an adverse effect on our ability to produce oil and gas from new wells.

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We have made, and will continue to make, expenditures in our effort to comply with environmental laws and regulations. We believe that we are in substantial compliance with applicable environmental laws and regulations in effect and that continued compliance with existing requirements will not have a material adverse impact on us. However, we also believe that it is reasonably likely that the trend in environmental legislation and regulation will continue toward stricter standards and, thus, we cannot give any assurance that we will not be adversely affected in the future.

We have established internal guidelines to be followed in order to comply with environmental laws and regulations in the U.S. We employ a safety department whose responsibilities include providing assurance that our operations are carried out in accordance with applicable environmental guidelines and safety precautions. Although we maintain pollution insurance to cover a portion of the costs of cleanup operations, public liability and physical damage, there is no assurance that such insurance will be adequate to cover all such costs or that such insurance will continue to be available in the future. To date, we believe that compliance with existing requirements of such governmental bodies has not had a material effect on our operations.

Other Regulation of the Oil and Gas Industry

The oil and gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

Legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including oil and gas facilities. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.

Production Regulation

Our operations are subject to various types of regulation at federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties and municipalities, in which we operate, also regulate one or more of the following:

• the location of wells;

• the method of drilling and casing wells;

• the surface use and restoration of properties upon which wells are drilled;

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• the plugging and abandoning of wells; and

• notice to surface owners and other third parties.

The various states regulate the drilling for, and the production of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowable from oil and gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, and to limit the number of wells or locations we can drill.

Regulation

The exploration, production and sale of oil and gas are extensively regulated by governmental bodies. Applicable legislation is under constant review for amendment or expansion. Oil and gas mineral rights may be held by individuals, corporations or governments having jurisdiction over the area in which such mineral rights are located. As a general rule, parties holding such mineral rights grant licenses or leases to third parties to facilitate the exploration and development of these mineral rights. The terms of the leases and licenses are generally established to require timely development. Notwithstanding the ownership of mineral rights, the government of the jurisdiction in which mineral rights are located generally retains authority over the manner of development of those rights.

Title to Properties

We believe that our title to the various interests set forth above is satisfactory and consistent with generally accepted industry standards, subject to exceptions that would not materially detract from the value of the interests or materially interfere with their use in our operations. Individual properties may be subject to burdens such as royalty, overriding royalty and other outstanding interests customary in the industry. In addition, interests may be subject to obligations or duties under applicable laws or burdens such as production payments, net profits interest, liens incident to operating agreements and for current taxes, development obligations under crude oil and natural gas leases or capital commitments under production sharing contracts or exploration licenses.

Offices

Our principal executive offices are located at 1001 Fannin Street, Suite 1600, Houston, Texas 77002, and our telephone number is (713) 307-8700. Many of our executive officers are also located in our offices at 114 St. Martin’s Lane, London WC2N 4BE England. We also have offices in Aberdeen, United Kingdom and Denver, Colorado.

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Available Information

We file annual and quarterly financial reports, as well as interim updates of a material nature to investors, with the SEC. The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains a website that contains reports, proxy and information statements and other information regarding issuers, including Endeavour, that file electronically with the SEC. The public can obtain any document we file at the SEC web page; http://www.sec.gov.

Our website is available at http://www.endeavourcorp.com. We make available, free of charge, on our website, the annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. Also, our Governance Guidelines, the charters of the Audit Committee, the Compensation Committee and the Governance and Nominating Committee, and the Code of Conduct and Code of Ethics for Senior Officers are available on our website and in print to any stockholder who provides a written request to the Corporate Secretary at 1001 Fannin Street, Suite 1600, Houston, Texas 77002. Our Code of Conduct applies to all directors, officers and employees, including the chief executive officer and senior financial officer.

Information contained on or connected to our website is not incorporated by reference into this Form 10-K and should not be considered part of this report or any other filing that we make with the SEC.

Financial Information about Segment and Geographical Areas

Our revenues and long-lived assets by geographic area is included in Note 21 to our consolidated financial statements in Item 8 and incorporated herein by reference.

Average Sales Prices and Production Costs by Geographical Area

Information on average sales prices and production costs by geographic area is included in Item 7 and incorporated herein by reference.

Item 1A. Risk Factors

Cautionary Statement Concerning Forward-Looking Statements

Certain matters discussed in this Annual Report on Form 10-K are “forward-looking statements” intended to qualify for the safe harbors from liability established by the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. These forward-looking statements include statements that express a belief,

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expectation, or intention, as well as those that are not statements of historical fact, and may include projections and estimates concerning the timing and success of specific projects and our future production, revenues, income and capital spending. Our forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “plan,” “goal” or other words that convey the uncertainty of future events or outcomes. We caution you not to rely on them unduly. In particular, this Annual Report on Form 10-K contains forward-looking statements pertaining to the following:

• our future financial position;

• our business strategy;

• budgets;

• projected costs, savings and plans;

• objectives of management for future operations;

• legal strategies; and

• legal proceedings.

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

• discovery, estimation, development and replacement of oil and gas reserves;

• decreases in proved reserves due to technical or economic factors;

• drilling of wells and other planned exploitation activities;

• timing and amount of future production of oil and gas;

• the volatility of oil and gas prices;

• availability and terms of capital;

• operating costs such as lease operating expenses, administrative costs and other expenses;

• our future operating or financial results;

• amount, nature and timing of capital expenditures, including future development costs;

• cash flow and anticipated liquidity;

• availability of drilling and production equipment;

• uncertainties related to drilling and production operations in a new region;

• business strategy and the availability of acquisition opportunities; and

• factors not known to us at this time.

Any of these factors, or a combination of these factors, could materially affect our future financial condition or results of operations and the ultimate accuracy of the forward-looking statements. The forward-looking statements are not guarantees of our future performance, and our actual results and future developments may differ materially from those projected in the forward-looking statements. In addition, any or all of our forward-looking statements in this Annual Report on Form 10-K may turn out to be incorrect. They can be affected by inaccurate assumptions we might make or by known or unknown risks and uncertainties, including those mentioned in “Item 1A. Risk Factors” and elsewhere in this Annual Report on Form 10-K.

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Except as required by law, we undertake no obligation to update publicly or release any revisions to these forward-looking statements to reflect events or circumstances after the date of this Annual Report on Form 10-K. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

Risks related to our business

We operate internationally and are subject to political, economic and other uncertainties.

We currently have operations in the U.S., U.K. and the Netherlands. We may expand our operations to other countries or regions. International operations are subject to political, economic and other uncertainties, including:

• the risk of war, acts of terrorism, revolution, border disputes, expropriation, renegotiation or modification of existing contracts, and import, export and transportation regulations and tariffs;

• taxation policies, including royalty and tax increases and retroactive tax claims;

• exchange controls, currency fluctuations and other uncertainties arising out of foreign government sovereignty over our international operations;

• laws and policies of the U.S. affecting foreign trade, taxation and investment; and

• the possibility of being subject to the exclusive jurisdiction of foreign courts in connection with legal disputes and the possible inability to subject foreign persons to the jurisdiction of courts in the U.S.

The exploration, production and sale of oil and gas are extensively regulated by governmental bodies. Applicable legislation is under constant review for amendment or expansion. These efforts frequently result in an increase in the regulatory burden on companies in our industry and consequently an increase in the cost of doing business and decrease in profitability. Numerous governmental departments and agencies are authorized to, and have, issued rules and regulations imposing additional burdens on the oil and gas industry that often are costly to comply with and carry substantial penalties for failure to comply. Production operations are affected by changing tax and other laws relating to the petroleum industry, by constantly changing administrative regulations and possible interruptions or termination by government authorities.

Oil and gas mineral rights may be held by individuals, corporations or governments having jurisdiction over the area in which such mineral rights are located. As a general rule, parties holding such mineral rights grant licenses or leases to third parties to facilitate the exploration and development of these mineral rights. The terms of the leases and licenses are generally established to require timely development. Notwithstanding the ownership of mineral rights, the government of the jurisdiction in which mineral rights are located generally retains authority over the manner of development of those rights.

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Future economic conditions in the U.S. and key international markets may materially adversely impact our operating results, which could hinder or prevent us from meeting our future capital needs.

The U.S. and other world economies are slowly recovering from a recession which began in 2008 and extended into 2009. Growth has resumed, but is modest. There are likely to be significant long-term effects resulting from the recession and credit market crisis, including a future global economic growth rate that is slower than what was experienced in recent years. In addition, more volatility may occur before a sustainable, yet lower, growth rate is achieved. Global economic growth drives demand for energy from all sources, including fossil fuels. A lower future economic growth rate will result in decreased demand growth for our crude oil and natural gas production as well as lower commodity prices, which will reduce our cash flows from operations and our profitability and may adversely affect our ability to obtain funding for our projects.

In addition, we may be unable to obtain adequate funding under our current senior bank facility because (i) our lending counterparties may be unwilling or unable to meet their funding obligations or (ii) our borrowing base under our current senior bank facility is redetermined at least twice per year and was reduced twice in 2009 as a result of lower oil or gas prices, declines in reserves, sales of assets and lending requirements or regulations.

Due to these factors, we cannot be certain that funding will be available if needed, and to the extent required, on acceptable terms or at all. If funding is not available as needed, or is available only on unfavorable terms, we may be unable to meet our obligations as they come due, or we may be unable to implement our capital program, enhance our existing business, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations.

Oil and gas prices are volatile, and a decline in oil and gas prices would reduce our revenues, profitability and cash flow and impede our growth.

Our revenues, profitability and cash flow depend substantially upon the prices and demand for oil and gas. The markets for these commodities are volatile, and even relatively modest drops in prices can significantly affect our financial results and impede our growth. Oil and gas prices increased to, and then declined significantly from, historical highs in 2008 and may fluctuate and decline significantly in the near future. Prices for oil and gas fluctuate in response to relatively minor changes in the supply and demand for oil and gas, market uncertainty and a variety of additional factors beyond our control, such as:

• global supply of oil and gas;

• level of consumer product demand;

• technological advances affecting oil and gas consumption;

• global economic conditions;

• price and availability of alternative fuels;

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• actions of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil price and production controls;

• governmental regulations and taxation;

• political conditions in or affecting other oil-producing and gas-producing countries;

• weather conditions;

• the proximity, capacity, cost and availability of pipeline and other transportation facilities; and

• the impact of energy conservation efforts.

Lower oil and gas prices may not only decrease our revenues on a per unit basis, but significant or extended price declines may also reduce the amount of oil and gas that we can produce economically. A reduction in production could result in a shortfall in expected cash flows and require us to reduce capital spending or borrow funds to cover any such shortfall. Any of these factors could negatively impact our ability to replace our production and our future rate of growth.

In addition, we may, from time to time, enter into long-term contracts based upon our reasoned expectations for commodity price levels. If commodity prices subsequently decrease significantly for a sustained period, we may be unable to perform our obligations or otherwise breach the contract and be liable for damages.

Competition for oil and gas properties and prospects is intense and some of our competitors have larger financial, technical and personnel resources that give them an advantage in evaluating, obtaining and developing properties and prospects.

We operate in a highly competitive environment for reviewing prospects, acquiring properties, marketing oil and gas and securing trained personnel. Many of our competitors are major or independent oil and gas companies that have longer operating histories in our areas of operation and employ superior financial resources which allow them to obtain substantially greater technical and personnel resources and which better enable them to acquire and develop the prospects that they have identified. We also actively compete with other companies when acquiring new licenses or oil and gas properties. Our relatively small size could adversely affect our ability to obtain new prospects and opportunities. Specifically, competitors with greater resources than our own have certain advantages that are particularly important in reviewing prospects and purchasing properties. Competitors may be able to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Competitors may also be able to pay more for producing oil and gas properties and exploratory prospects than we are able or willing to pay. If we are unable to compete successfully in these areas in the future, our future revenues and growth may be diminished or restricted.

These competitors may also be better able to withstand sustained periods of unsuccessful drilling or downturns in the economy, including decreases in the price of commodities as experienced in 2008 and 2009. Larger competitors may also be able to absorb the burden of any changes in laws and regulations more easily than we can, which would also adversely affect our competitive position. In addition, most of our competitors have been operating for a much longer time and have demonstrated the ability to operate through industry cycles.

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We are dependent on our executive officers and need to attract and retain additional qualified personnel.

Our future success depends in large part on the service of our executive officers. The loss of these executives could have a material adverse effect on our business. Although we have employment agreements with certain of our executive officers, there can be no assurance that we will have the ability to retain their services. Further, we do not maintain key-person life insurance on any executive officers.

Our future success also depends upon our ability to attract, assimilate and retain highly qualified technical and other management personnel who are essential for the identification and development of our prospects. There can be no assurance that we will be able to attract, integrate and retain key personnel, and our failure to do so would have a material adverse effect on our business.

Our use of derivative transactions may limit future revenues from price increases and involves the risk that our counterparties may be unable to satisfy their obligations to us.

To manage our exposure to price or interest rate risk with our production, we routinely enter into commodity derivative contracts. The goal of these derivative contracts is to limit volatility and increase the predictability of cash flow. Although the use of derivative contracts limits the downside risk of price declines, their use also may limit future revenues from price increases. In addition, derivative contracts may expose us to the risk of financial loss in certain circumstances, including instances in which our production is less than expected or a sudden, unexpected event materially impacts oil or gas prices.

Derivative contracts also involve the risk that counterparties, which generally are financial institutions, may be unable to satisfy their obligations to us. If any of our counterparties were to default on its obligations to us under the derivative contracts or seek bankruptcy protection it could have a material adverse effect on our ability to fund our planned activities and could result in a larger percentage of our future production being subject to commodity price changes. In addition, in the current economic environment and tight financial markets, the risk of a counterparty default is heightened and it is possible that fewer counterparties will participate in future derivative transactions, which could result in greater concentration of our exposure to any one counterparty or a larger percentage of our future production being subject to commodity price changes.

Risks related to executing our strategy and operations

To maintain and grow our production and cash flow, we must continue to develop and produce existing reserves and discover or acquire new oil and gas reserves to develop and produce.

Our future oil and gas production is highly dependent upon our level of success in finding or acquiring additional reserves. Producing oil and gas reserves are generally characterized by

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declining production rates that vary depending on reservoir characteristics and other factors. Our reserves will decline unless we acquire properties with proved reserves or conduct successful development and exploration drilling activities. We accomplish this through successful drilling programs and the acquisition of properties. However, we may be unable to find, develop or acquire additional reserves or production at an acceptable cost or at all. Acquisition opportunities in the oil and gas industry are very competitive, which can increase the cost of, or cause us to refrain from, completing acquisitions.

If we are unable to find, develop or acquire additional reserves to replace our current and future production, our production rates will decline even if we drill the undeveloped locations that were included in our estimated proved reserves. Our future oil and gas reserves and production, and therefore our cash flow and income, are dependent on our success in economically finding or acquiring new reserves and efficiently developing our existing reserves.

We may be unable to make attractive acquisitions, and any acquisition we complete is subject to substantial risks that could impact our business.

As part of our growth strategy, we intend to pursue strategic acquisitions of new properties or businesses that expand our current asset base and potentially offer unexploited reserve potential. Our growth strategy following the full development of our existing properties could be impeded if we are unable to acquire additional interests in oil and gas prospects on a profitable basis. Acquisition opportunities in the oil and gas industry are very competitive, which can increase the cost of, or cause us to refrain from, completing acquisitions. The success of any acquisition will depend on a number of factors and involves potential risks, including among other things:

• the inability to estimate accurately the costs to develop the interests in oil and gas prospects, the recoverable volumes of reserves, rates of future production and future net cash flows attainable from the reserves;

• the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which the indemnity we receive is inadequate;

• the validity of assumptions about costs, including synergies;

• the impact on our liquidity or financial leverage of using available cash or debt to finance acquisitions;

• the diversion of management’s attention from other business concerns; and

• an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets.

All of these factors affect whether an acquisition will ultimately generate cash flows sufficient to provide a suitable return on investment. Even though we perform a review of the properties we seek to acquire that we believe is consistent with industry practices, such reviews are often limited in scope. As a result, among other risks, our initial estimates of reserves may be subject to revision following an acquisition, which may materially and adversely impact the desired benefits of the acquisition.

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Our expectations for future drilling activities will be realized over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing.

We have identified drilling locations and prospects for future drilling opportunities, including development, exploratory and other drilling and enhanced recovery activities. These drilling locations and prospects represent a significant part of our future drilling plans. Our ability to drill and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, third-party operators, regulatory approvals, negotiation of agreements with third parties, commodity prices, costs and drilling results. Because of these uncertainties, we cannot give any assurance as to the timing of these activities or that they will ultimately result in the realization of proved reserves or meet our expectations for success. As such, our actual drilling and enhanced recovery activities may materially differ from our current expectations, which could have a significant adverse effect on our financial condition and results of operations.

Our drilling projects are based in part on seismic data, which cannot ensure the commercial success of the project.

Our decisions to purchase, explore, develop and exploit prospects or properties depend in part on data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often uncertain. Even when used and properly interpreted, seismic data and visualization techniques only assist geoscientists and geologists in identifying subsurface structures and hydrocarbon indicators. Seismic data do not enable an interpreter to conclusively determine whether hydrocarbons are present or producible economically. In addition, the use of seismic and other advanced technologies may require greater predrilling expenditures than other drilling strategies. Because of these factors, we could incur losses as a result of exploratory drilling expenditures. Poor results from drilling activities could have a material adverse effect on our future cash flows, ability to replace reserves and results of operations.

Reserve estimates depend on many assumptions that may turn out to be inaccurate and any material inaccuracies in the reserve estimates or underlying assumptions of our assets will materially affect the quantities and present value of those reserves.

Estimating oil and gas reserves is complex and inherently imprecise. It requires interpretation of the available technical data and making many assumptions about future conditions, including price and other economic factors. In preparing such estimates, projection of production rates, timing of development expenditures and available geological, geophysical, production and engineering data are analyzed. The extent, quality and reliability of these data can vary. This process also requires economic assumptions about matters such as oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. If our interpretations or assumptions used in arriving at our reserve estimates prove to be inaccurate, the amount of oil and gas that will ultimately be recovered may differ materially from the estimated quantities and net present value of reserves owned by us.

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A significant portion of our total estimated net proved reserves at December 31, 2009 were undeveloped, and those reserves may not ultimately be developed.

At December 31, 2009, approximately 84 percent of our total estimated net proved reserves were undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling. Our reserve data assumes that we can and will make these expenditures and conduct these operations successfully. These assumptions, however, may not prove correct. If we choose not to spend the capital to develop these reserves or if we are not otherwise able to successfully develop these reserves we may be required to write-off these reserves. Any such write-offs of our reserves could reduce our ability to borrow money and could reduce the value of our securities.

Our offshore operations involve special risks that could increase our cost of operations and adversely affect our ability to produce oil and gas.

Offshore operations are subject to a variety of operating risks specific to the marine environment, such as capsizing, collisions and damage or loss from hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production. As a result, we could incur substantial liabilities that could reduce or eliminate the funds available for exploration, development or leasehold acquisitions, or result in loss of equipment and properties. Offshore drilling in the North Sea generally requires more time and more advanced drilling technologies, involving a higher risk of technological failure and usually higher drilling costs. Moreover, offshore projects often lack proximity to the physical and oilfield service infrastructure, necessitating significant capital investment in subsea flow line infrastructure. Subsea tieback production systems require substantial time and the use of advanced and very sophisticated installation equipment supported by remotely operated vehicles. These operations may encounter mechanical difficulties and equipment failures that could result in significant cost overruns. As a result, a significant amount of time and capital must be invested before we can market the associated oil or gas, increasing both the financial and operational risk involved with these operations. Because of the lack and high cost of infrastructure, some offshore reserve discoveries may never be produced economically.

We have recently commenced exploration, production and development operations in the United States, and as a result, our ability to successfully achieve our goals is subject to greater risk and uncertainty.

In 2008, we began to pursue exploration, production and development activities in the U.S. Moreover, we did not have a significant U.S. presence in our assets and operations until late 2009. Because we have limited production history in this geographic region and do not have extensive experience in unconventional resource plays, we are less able to use past operational results to help predict future results. Our lack of operational experience in the U.S. may result in our not being able to fully execute our expected drilling programs in this region, and the return on investment from our United States operations may not be as attractive as expected. We cannot assure you that our efforts in the U.S. will be successful, or if successful will achieve the resource potential levels that we currently anticipate or achieve the anticipated economic returns based on our current financial models.

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We will not be the operator of all of the interests we own or acquire, and therefore we may not be in a position to control the timing of development efforts, the associated costs, or the rate of production of the reserves in respect of such interests.

A significant number of our interests, including all of our producing fields, are currently operated by third parties. As a result, we may have limited ability to exercise influence over the operations of these interests or their associated costs. Dependence on the operator and other working interest owners for these projects, and limited ability to influence operations and associated costs could prevent the realization of expected returns on capital in drilling or acquisition activities. The success and timing of development and exploitation activities on properties operated by others depend upon a number of factors that will be largely outside our control, including:

• the operator’s expertise and financial resources;

• the timing and amount of their capital expenditures;

• the rate of production of the reserves;

• approval of other participants to drill wells and implement other work programs;

• the availability of suitable drilling rigs, drilling equipment, support vessels, production and transportation infrastructure and qualified operating personnel; and

• selection of technology.

Our inability to control the development efforts, costs and timing on the interests where we are not the operator could have a material adverse effect on our financial conditions, results of operations and business prospects.

Actual production could differ significantly from forecasts.

From time to time we provide forecasts of expected quantities of future oil and gas production. These forecasts are based on a number of estimates, including expectations of production decline rates from existing wells and the outcome of future drilling activity. Should these estimates prove inaccurate, actual production could be adversely impacted. Downturns in commodity prices could make certain drilling activities or production uneconomical, which would also adversely impact production. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which are beyond our control.

Our insurance may not protect us against business and operating risks, including an operator of a prospect in which we participate failing to maintain or obtain adequate insurance.

Oil and gas operations are subject to particular hazards incident to the drilling and production of oil and gas, such as blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires and pollution and other environmental risks. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. We maintain insurance for some, but not

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Endeavour International Corporation

all, of the potential risks and liabilities associated with our business. If a significant accident or other event resulting in damage to our operations, including severe weather, terrorist acts, war, civil disturbances, pollution or environmental damage, occurs and is not fully covered by insurance, it could adversely affect our financial condition and results of operations. We do not currently operate all of our oil and gas properties. In the projects in which we own non-operating interests, the operator may maintain insurance of various types to cover our operations with policy limits and retention liability customary in the industry. The occurrence of a significant adverse event that is not fully covered by insurance could result in the loss of our total investment in a particular prospect and additional liability for us, which could have a material adverse effect on our financial condition and results of operations and prospects.

The cost of decommissioning is uncertain.

We expect to incur obligations to abandon and decommission certain structures associated with our producing properties. To date, the industry has little experience of removing oil and gas structures from the North Sea. Few of the structures in the North Sea have been removed. Certain groups have been established to study issues relating to decommissioning and abandonment and how the costs will be borne. Because experience is limited, we cannot precisely predict the costs of any future decommissions for which we might become obligated. If actual decommission or abandonment costs exceed our estimates or reserves to satisfy such obligations, our financial condition, results of operations and prospects could be materially adversely affected.

Risks related to environmental and other regulations

We are subject to environmental regulations that can have a significant impact on our operations.

Our operations are subject to a variety of national, state, local and international laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Failure to comply with these laws and regulations can result in the imposition of substantial fines and penalties as well as potential orders suspending or terminating our rights to operate. Some environmental laws to which we are subject to provide for strict liability for pollution damages, rendering a person liable without regard to negligence or fault on the part of such person. In addition, we may be subject to claims alleging personal injury or property damage as a result of alleged exposure to hazardous substances such as oil and gas related products. Aquatic environments in which we operate are often particularly sensitive to environmental impacts, which may expose us to greater potential liability than that associated with exploration, development and production at many onshore locations.

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly requirements for oil and gas exploration and production activities could require us, as well as others in our industry, to make significant expenditures to attain and maintain compliance which could have a corresponding material adverse effect on our competitive position, financial condition or results of operations. We cannot provide assurance that we will be able to comply with future laws and regulations to the same extent that we

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Endeavour International Corporation

believe we have in the past. Similarly, we cannot always precisely predict the potential impact of environmental laws and regulations which may be adopted in the future, including whether any such laws or regulations would restrict our operations in any area.

Current and future environmental regulations, including restrictions on greenhouse gases due to concerns about climate change, could reduce the demand for our products. Our business, financial condition and results of operations could be materially and adversely affected if this were to occur.

Under certain environmental laws and regulations, we could be subject to liability arising out of the conduct of operations or conditions caused by others, or for activities that were in compliance with all applicable laws at the time they were performed. Such liabilities can be significant, and if imposed could have a material adverse effect on our financial condition or results of operations.

Governmental regulations to which we are subject could expose us to significant fines and/or penalties and our cost of compliance with such regulations could be substantial.

Oil and gas exploration, development and production are subject to various types of regulation by local, state and national agencies. Regulations and laws affecting the oil and gas industry are comprehensive and under constant review for amendment and expansion. These regulations and laws carry substantial penalties for failure to comply. The regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, adversely affects our profitability. In addition, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the governments and/or agencies thereof.

Federal legislation and state legislative regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affect our support services.

The U.S. Congress is currently considering two companions bills for the “Fracturing Responsibility and Awareness of Chemicals Act,” or “FRAC Act.” The bills would repeal an exemption in the federal Safe Drinking Water Act (“SWDA”) for the underground injection of hydraulic fracturing fluids near drinking water sources. Hydraulic fracturing is an important and commonly used process for the completion of natural gas, and to a lesser extent, oil wells in shale formations, and involves the pressurized injection of water, sand and chemicals into rock formations to stimulate natural gas production. Sponsors of the FRAC Act have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. If enacted, the FRAC Act could result in additional regulatory burdens such as permitting, construction, financial assurance, monitoring, recordkeeping, and plugging and abandonment requirements. The FRAC Act also proposes requiring the disclosure of chemical constituents used in the fracturing process to state or federal regulatory authorities, who would then make such information publicly available. The availability of this information could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect

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Endeavour International Corporation

groundwater. In addition, various state and local governments are considering increased regulatory oversight of hydraulic fracturing through additional permit requirements, operational restrictions, and temporary or permanent bans on hydraulic fracturing in certain environmentally sensitive areas such as watersheds. The adoption of the FRAC Act or any other federal or state laws or regulations imposing reporting obligations on, or otherwise limiting, the hydraulic fracturing process could make it more difficult to complete natural gas wells in shale formations, increase our costs of compliance and doing business.

Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the crude oil and natural gas that we produce.

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

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The adoption of derivatives legislation by the U.S. Congress could have an adverse impact on our ability to hedge risks associated with our business.

The U.S. Congress is currently considering legislation to impose restrictions on certain transactions involving derivatives, which could affect the use of derivatives in hedging transactions. ACESA contains provisions that would prohibit private energy commodity derivative and hedging transactions. ACESA would expand the power of the Commodity Futures Trading Commission, or CFTC, to regulate derivative transactions related to energy commodities, including oil and natural gas, and to mandate clearance of such derivative contracts through registered derivative clearing organizations. Under ACESA, the CFTC’s expanded authority over energy derivatives would terminate upon the adoption of general legislation covering derivative regulatory reform. The CFTC is considering whether to set limits on trading and positions in commodities with finite supply, particularly energy commodities, such as crude oil, natural gas and other energy products. The CFTC also is evaluating whether position limits should be applied consistently across all markets and participants. Separately, the House of Representatives adopted financial regulatory reform legislation on December 11, 2009, that among other things would impose comprehensive regulation on the over-the-counter (OTC) derivatives marketplace. This legislation would subject swap dealers and “major swap participants” to substantial supervision and regulation, including capital standards, margin requirements, business conduct standards, recordkeeping and reporting requirements. It also would require central clearing for transactions entered into between swap dealers or major swap participants, and would provide the CFTC with authority to impose position limits in the OTC derivatives markets. A major swap participant generally would be someone other than a dealer who maintains a “substantial” net position in outstanding swaps, excluding swaps used for commercial hedging or for reducing or mitigating commercial risk, or whose positions create substantial net counterparty exposure that could have serious adverse effects on the financial stability of the U.S. banking system or financial markets. Although it is not possible at this time to predict whether or when Congress may act on derivatives legislation or how any climate change bill approved by the Senate would be reconciled with ACESA, any laws or regulations that may be adopted that subject us to additional capital or margin requirements relating to, or to additional restrictions on, our trading and commodity positions could have an adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activity.

Certain federal income tax deductions currently available with respect to oil and natural gas exploration and development may be eliminated as a result of future legislation.

President Obama’s Proposed Fiscal Year 2010 Budget includes proposed legislation that would, if enacted into law, make significant changes to U.S. tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether any such changes will be enacted or how soon any such changes could become effective. The passage of any legislation as a result of these

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Endeavour International Corporation

proposals or any other similar changes in U.S. federal income tax laws could eliminate or otherwise limit certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could negatively impact our financial condition and results of operations.

Risks related to access to capital and financing

Our development and exploration operations, including our recent North Sea discoveries, require substantial capital, and we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our oil and gas reserves.

The oil and gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business and operations for the exploration, development, production and acquisition of oil and gas reserves, including expenditures relating to the development of our discoveries in the North Sea and our acreage position in the Haynesville Shale and other U.S. plays. We intend to finance our future capital expenditures primarily with cash flow from operations and borrowings under our senior bank facility. Our cash flow from operations and access to capital is subject to a number of variables, including:

• our proved reserves;

• the level of natural gas and crude oil we are able to produce from existing wells;

• the prices at which natural gas and crude oil are sold; and

• our ability to acquire, locate and produce new reserves.

If our revenues decrease as a result of lower oil and gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels or to further develop and exploit our current properties, or for exploratory activity. In order to fund our capital expenditures, we may need to seek additional financing. Our credit agreements contain covenants restricting our ability to incur additional indebtedness without the consent of the lenders. Our lenders may withhold this consent in their sole discretion. In addition, if our borrowing base is redetermined resulting in a lower borrowing base under our senior bank facility, we may be unable to obtain financing otherwise available under our senior bank facility.

Furthermore, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. In particular, the cost of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets generally has diminished significantly. Also, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity on terms that are similar to existing debt, and reduced, or in some cases ceased, to provide funding to borrowers. The failure to obtain additional financing could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could lead to

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a possible loss of properties and a decline in our natural gas, crude oil and natural gas liquids reserves.

Our debt level could negatively impact our financial condition, results of operations and business prospects.

As of December 31, 2009, we had $231.2 million in outstanding indebtedness. Our level of indebtedness could have important consequences on our operations, including

• placing restrictions on certain operating activities;

• making it more difficult for us to satisfy our obligations under our indentures or the terms of our other debt instruments and increasing the risk that we may default on our debt obligations;

• requiring us to dedicate a substantial portion of our cash flow from operating activities to required payments on debt, thereby reducing the availability of cash flow for working capital, capital expenditures and other general business activities;

• limiting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and other general business activities;

• decreasing our ability to withstand a downturn in our business or the economy generally; and

• placing us at a competitive disadvantage against other less leveraged competitors.

We may not have sufficient funds to repay our outstanding debt. If we are unable to repay our debt out of cash on hand, we could attempt to refinance such debt, sell assets or repay such debt with the proceeds from an equity offering. In addition, we cannot assure you that we will be able to generate sufficient cash flow from operating activities to pay the interest on our debt or that future borrowings, equity financings or proceeds from the sale of assets will be available to repay or refinance such debt. Factors that will affect our ability to raise cash through an offering of our capital stock, a refinancing of our debt or a sale of assets include financial market conditions, our market value, our reserve levels and our operating performance at the time of such offering or other financing. We cannot assure you that any such offering, refinancing or sale of assets can be successfully completed. The inability to repay or refinance our debt, could have a material adverse effect on our operations and negatively impact our capital program.

A change of control may adversely affect our liquidity and require refinancing of certain debt instruments.

At December 31, 2009, we had $231.2 million outstanding under our debt agreements. Upon specified change of control events, each lender under our debt agreements may cancel the facility and declare outstanding loans, plus accrued and unpaid interest, outstanding letters of credit and other outstanding fees, if any, due and payable. We cannot assure you we would have sufficient financial resources to purchase the notes for cash or repay the lenders under our Debt Agreements upon the occurrence of a change of control. If a change of control occurs, we may be required to refinance our indebtedness. There can be no assurance that we would be able to refinance our indebtedness or, if a refinancing were to occur, that the refinancing would be on terms favorable to us.

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If we are unable to fulfill commitments under any of our oil and gas interests, we will lose our interest, and our entire investment, in such interest.

Our ability to retain oil and gas interests will depend on our ability to fulfill the commitments made with respect to each interest. We cannot assure you that we or the other participants in the projects will have the financial ability to fund these potential commitments. If we are unable to fulfill commitments under any of our interests, we will lose our interest, and our entire investment, in such interest.

Risks relating to our common stock

The trading price of our common stock may be volatile.

Smaller capitalized companies like ours often experience substantial fluctuations in the trading price of their securities. The trading price of our common stock has fluctuated significantly and in the future may be subject to similar fluctuations. The trading price may be affected by a number of factors, including those set forth elsewhere herein, as well as our operating results, financial condition, announcements or drilling activities, general conditions in the oil and gas exploration and development industry, and other events or factors, some of which may be unrelated to our performance or prospects or to conditions in the industry as a whole.

If we, our existing stockholders or holders of our securities that are convertible into shares of our common stock sell additional shares of our common stock, the market price of our common stock could significantly decline.

The market price of our common stock could decline as a result of sales of a large number of shares of common stock in the public market or the perception that such sales could occur. These sales, or the possibility that these sales may occur, might make it more difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate.

As of March 12, 2010, we had approximately 160.2 million shares of common stock outstanding. Of those shares, approximately 5.0 million shares are restricted shares subject to vesting periods of up to three years. The remainder of these shares is freely tradable.

In addition, approximately 2.8 million shares are issuable upon the exercise of presently outstanding stock options under our employee incentive plans and 0.9 million shares are issuable upon the exercise of presently outstanding options and warrants outside our employee incentive plans. Also 16.2 million shares are issuable upon the conversion of our convertible senior notes due 2012 and 48.8 million shares are issuable upon conversion of our Series C Preferred Stock, based upon the conversion price of $1.25, and 21.5 million shares are issuable upon conversion of our 11.5% convertible bonds, based on a conversion price of $2.36.

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Provisions in our articles of incorporation, bylaws and the Nevada Revised Statutes may discourage a change of control.

Certain provisions of our amended and restated articles of incorporation and amended and restated bylaws and the Nevada Revised Statutes (“NRS”) could delay or make more difficult a change of control transaction or other business combination that may be beneficial to stockholders. These provisions include, but are not limited to, the ability of our board of directors to issue a series of preferred stock, classification of our board of directors into three classes and limiting the ability of our stockholders to call a special meeting.

We are subject to the “Combinations With Interested Stockholders Statute” and the “Control Share Acquisition Statute” of the NRS. The Combinations Statute provides that specified persons who, together with affiliates and associates, own, or within three years did own, 10% or more of the outstanding voting stock of a corporation cannot engage in specified business combinations with the corporation for a period of three years after the date on which the person became an interested stockholder, unless the combination or the transaction by which the person first became an interested stockholder is approved by the corporation’s board of directors before the person first became an interested stockholder.

The Control Share Acquisition Statute provides that persons who acquire a “controlling interest” as defined by the statute, in a company may only be given full voting rights in their shares if such rights are conferred by the stockholders of the company at an annual or special meeting. However, any stockholder that does not vote in favor of granting such voting rights is entitled to demand that the company pay fair value for their shares if the acquiring person has acquired at least a majority of all of the voting power of the company. As such, persons acquiring a controlling interest may not be able to vote their shares.

Risks related to potential impairments

Lower oil and gas prices and other factors resulted in a ceiling test write-down and may in the future result in additional ceiling test write-downs or other impairments.

We capitalize the costs to acquire, find and develop our oil and gas properties under the full cost accounting method. The net capitalized costs of our oil and gas properties may not exceed the present value of estimated future net cash flows from proved reserves, using period-end oil and gas prices and a 10% discount factor, plus the lower of cost or fair market value for unproved properties. If net capitalized costs of our oil and gas properties exceed this limit, we must charge the amount of the excess to earnings. This is called a “ceiling test write-down.” Although a ceiling test write-down does not impact cash flow from operating activities, it does reduce net income and our shareholders’ equity. Once recorded, a ceiling test write-down is not reversible at a later date even if oil and gas prices increase.

We review the net capitalized costs of our properties quarterly, based on prices in effect (excluding the effect of our hedging contracts that are not designated for hedge accounting) as of the end of each quarter or as of the time of reporting our results. The net capitalized costs of oil and gas properties are computed on a country-by-country basis. Therefore, while our properties

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in one country may be subject to a write-down, our properties in other countries could be unaffected. We also assess investments in unproved properties periodically to determine whether impairment has occurred.

The risk that we will be required to further write down the carrying value of our oil and gas properties increases when oil and gas prices are low or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves or our unproved property values, or if estimated future development costs increase. We may experience further ceiling test write-downs or other impairments in the future. In addition, any future ceiling test cushion would be subject to fluctuation as a result of acquisition or divestiture activity.

Our financial results could be adversely affected by goodwill impairments.

As a result of mergers, acquisitions and dispositions, at December 31, 2009 we had $211.9 million of goodwill on our balance sheet. Goodwill is not amortized, but instead must be tested at least annually for impairment by applying a fair-value-based test. Goodwill is deemed impaired to the extent that its carrying amount exceeds the fair value of the reporting unit. Although our latest tests indicate that no goodwill impairment is currently required, future deterioration in market conditions could lead to goodwill impairments that could have a substantial negative effect on our profitability.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

Drilling Statistics

A well is considered productive for purposes of the following table if it justifies the installation of permanent equipment for the production of oil or gas. The information contained in the table should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. The following table shows the results of the oil and gas wells in which we participated, drilled and tested during 2009, 2008 and 2007:

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	Productive Wells				Dry Holes				In Progress Wells
	Gross		Net		Gross		Net		Gross		Net
Exploration
2009:
United Kingdom		3.00		0.82		2.00		0.52		1.00		0.10
United States		3.00		1.32		1.00		0.22		3.00		1.04
2008:
United Kingdom		—		—		—		—		2.00		0.68
United States		1.00		0.20		—		—		1.00		0.10
Discontinued Operations — Norway		5.00		0.14		—		—		—		—
2007:
United Kingdom		2.00		0.50		3.00		0.75		—		—
Discontinued Operations — Norway		2.00		0.05		1.00		0.04		—		—
Development
2009:
United Kingdom		2.00		0.05		—		—		1.00		0.02
2008:
United Kingdom		—		—		—		—		1.00		0.02
Discontinued Operations — Norway		3.00		0.08		—		—		—		—
2007:
United Kingdom		1.00		0.02		—		—		—		—
Discontinued Operations — Norway		3.00		0.13		1.00		0.04		—		—

We do not own any drilling rigs, and all of our drilling activities are conducted by independent drilling contractors.

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Productive Well Summary

At December 31, 2009, our productive wells included the following:

	Oil				Gas
	Gross		Net		Gross		Net
United Kingdom		32.00		0.79		2.00		0.14
United States		2.00		1.12		25.00		7.16
Total		34.00		1.91		27.00		7.30

Acreage

The following table sets forth certain information regarding our developed and undeveloped acreage as of December 31, 2009, in the areas indicated.

	Developed				Undeveloped
	Gross		Net		Gross		Net
United Kingdom		31,790		8,108		325,610		86,566
United States		39,360		11,690		427,518		102,342
Ireland		—		—		172,797		34,559
Total		71,150		19,798		925,925		223,467

As of December 31, 2009, we had approximately 34,559, 28,473 and no net acres that are scheduled to expire by December 31, 2010, 2011 and 2012, respectively, if we take no action to continue the term of the underlying license through operational or administrative actions. We currently have plans to continue the terms of various licenses through operational or administrative actions and do not expect a significant portion of our net acreage position to expire before such actions occur.

Sales Volumes and Prices

Information regarding our annual average sales volumes, sales prices and average production costs is contained in Item 7 of this Form 10-K. Additional detail of production costs is contained in Note 24 to our consolidated financial statements under Item 8 of this Form 10-K.

Reserves

Our estimates of proved reserves, proved developed reserves and proved undeveloped reserves at December 31, 2009, 2008 and 2007 and changes in proved reserves during the last three years

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are contained in Note 24 Note to our consolidated financial statements under Item 8 of this Form 10-K.

Item 3. Legal Proceedings

We are a party to various lawsuits, claims, and proceedings from time to time in the ordinary course of business. These proceedings are subject to uncertainties inherent in any litigation, and the outcome of these matters is inherently difficult to predict with any certainty. We believe that the amount of any potential loss associated with these proceedings would not be material to our consolidated financial position; however, in the event of an unfavorable outcome, the potential loss could have an adverse effect on our results of operations and cash flow in the reporting periods in which any such actions are resolved.

Part II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Our common stock currently trades on the NYSE-Amex, formerly the American Stock Exchange, under the symbol “END” and on the London Stock Exchange under the symbol “ENDV.” The following table sets forth the range of high and low prices per share of our common stock for each of the calendar quarters identified below as reported by the NYSE-Amex. These quotations represent inter-dealer prices, without retail mark-up, markdown or commission, and may not represent actual transactions.

	2009				2008
	High		Low		High		Low
First Quarter	$	1.03	$	0.46	$	1.46	$	1.13
Second Quarter		2.21		0.83		2.56		1.20
Third Quarter		1.50		1.02		2.30		1.01
Fourth Quarter		1.30		0.82		1.45		0.33

Holders

As of March 12, 2010, the number of holders of record of our common stock was 222. We believe that there are a number of additional beneficial owners of our common stock who hold such shares in street name.

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Dividends

We have not paid any cash dividends on our common stock to date, and have no intention of declaring or paying any cash dividends on our common stock in the foreseeable future. Our Series B Preferred Stock is subject to a cumulative 8% dividend. Unless the full amount of the foregoing dividends accrued for the Series B Preferred Stock is paid in full, we cannot declare or pay any dividend on our common stock. In addition, our senior bank facility contains restrictions on the payment of dividends to the holders of our common stock. The declaration and payment of dividends is subject to the discretion of our Board of Directors and to certain limitations imposed under Nevada corporate laws. The timing, amount and form of dividends, if any, will depend on, among other things, our results of operations, financial condition, cash requirements and other factors deemed relevant by our Board of Directors.

In 2006, we issued the Series C Preferred Stock. Dividends on the Series C Preferred Stock are:

• cumulative;

• compounded quarterly based on the original issue price;

• payable in cash or common stock; and

• payable to the preferred stock investors prior to payment of any other dividend on any other shares of our capital stock.

In November 2009, we amended the terms of the Series C Preferred Stock in connection with a partial redemption. In connection with this transaction, the Series C Preferred Stock dividend rates were changed from 8.5% or 8.92% when payable in cash or common stock, respectively, to 4.5% or 4.92%, respectively. The Series C Preferred Stock continues to participate in any dividends paid on our common stock. We paid the Series C Preferred Stock dividends in common stock until the fourth quarter of 2007. Thereafter, we have paid the Series C Preferred Stock dividends in cash.

Item 6. Selected Financial Data

The following table sets forth some of our historical consolidated financial data. We completed the divestiture of our Norwegian subsidiary on May 14, 2009. The results of operations and financial position of this subsidiary are classified as discontinued operations for all periods presented.

The following data should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial Statements and Notes thereto included in “Item 8. Financial Statements and Supplementary Data.” The selected consolidated financial data provided below are not necessarily indicative of our future results of operations or financial performance.

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Summary Financial Data(1)
	Year Ended December 31,
(Amounts in thousands, except per share data)	2009			2008		2007			2006			2005
Summary Income Statement Data:
Revenues	$	62,293		$	170,781	$	135,876		$	24,881		$	—
Operating Profit (Loss)		(50,398	)		18,236		23,778			(11,516	)		(43,281	)
Net Income (Loss) to Common Shareholders		(62,206	)		45,681		(60,315	)		(8,829	)		(31,531	)
Net Income (Loss) Per
Common Share — Basic:
Continuing Operations	$	(0.84	)	$	0.12	$	(0.50	)	$	(0.08	)	$	(0.50	)
Discontinued Operations		0.36			0.24		0.01			(0.02	)		0.08
Total	$	(0.48	)	$	0.36	$	(0.49	)	$	(0.10	)	$	(0.42	)
Net Income (Loss) Per Common Share — Diluted:
Continuing Operations	$	(0.84	)	$	0.15	$	(0.50	)	$	(0.08	)	$	(0.50	)
Discontinued Operations		0.36			0.17		0.01			(0.02	)		0.08
Total	$	(0.48	)	$	0.32	$	(0.49	)	$	(0.10	)	$	(0.42	)
Summary Balance Sheet Data:
Working Capital	$	24,885		$	22,902	$	37,198		$	47,431		$	49,638
Total Assets		538,879			737,470		747,623			774,470			186,966
Debt		223,385			227,855		266,250			306,250			81,250
Convertible Preferred Stock		59,058			125,000		125,000			125,000			—
Equity		60,133			117,971		70,149			116,828			40,344

⁽¹⁾ Includes the following:

• acquisition of producing properties and exploration acreage in the U.S. in 2009;

• acquisition of Talisman Expro Limited in November 2006;

• acquisition of working interests in the Enoch and Bacchus prospects in 2006;

• disposition of Thailand assets in 2005;

• acquisition of Norwegian assets in November 2004 and January 2005;

• disposition of non-core assets in 2004;

• acquisition of NSNV, Inc. in 2004; and

• unrealized gains (losses) on derivatives of $(55.6) million, $76.7 million, $(89.1) million and $34.5 million in 2009, 2008, 2007 and 2006, respectively.

Information regarding each of these transactions is included in the notes to the Consolidated Financial Statements included elsewhere in this report.

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

This Management’s Discussion and Analysis of Financial Condition and Results of Operations and other parts of this Annual Report on Form 10-K contain forward-looking statements that involve risks and uncertainties. All forward-looking statements included in this Annual Report on Form 10-K are based on information available to us on the date hereof, and we assume no obligation to update any such forward-looking statements. Our actual results could differ materially from those anticipated in these forward-looking statements as a result of a number of factors, including those set forth in the section captioned “Risk Factors” in Item 1A and elsewhere in this Annual Report on Form 10-K. The following should be read in conjunction with the audited financial statements and the notes thereto included in “Item 8. Financial Statements and Supplementary Data.” The following discussion also includes non-GAAP financial measures, which may not be comparable to similarly titled measures presented by other companies. Accordingly, we strongly encourage investors to review our financial statements in their entirety and not rely on any single financial measure.

Overview

We are an international oil and gas exploration and production company focused on the acquisition, exploration and development of energy reserves. Historically, we have focused our operations in the North Sea, but have recently expanded our focus to target unconventional U.S. onshore resource shale plays with shorter production-cycle times and compelling risk/return profiles.

On May 14, 2009, we completed the sale of our Norwegian subsidiary, Endeavour Energy Norge AS, to Verbundnetz Gas AG for cash consideration of $150 million (the “Norway Sale”). We recognized a gain upon closing the Norway Sale of $47.0 million, after the allocation of $68 million of goodwill to the assets sold. Proceeds from this sale enabled us to enter into a joint venture relationship with an established U.S. shale operator, providing us with acreage positions and production in the Haynesville and Marcellus Shales. We also entered into additional joint venture agreements with other selected operators, providing exposure to emerging shale plays in Alabama and Montana.

Our North Sea activities and assets represented the majority of our activity in 2007 and 2008,. Our major development projects – Bacchus, Columbus, Cygnus and Rochelle – have continued to move toward development with appraisal wells drilled at Cygnus and Rochelle in early 2009. Further appraisal drilling is planned for 2010 at Cygnus.

Our realized price per BOE, before derivatives, decreased from $71.70 per BOE in 2008 to $64.15 per BOE in 2009 largely as a result of lower gas prices in the U.K. Our realized price per BOE, before derivatives, increased 25% from 2007 to 2008 largely as a result of oil prices climbing to record levels in the summer of 2008 and gas prices in our markets improving. This substantial increase in prices in the first half of 2008 helped revenue grow from $135.9 million in

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2007 to $170.8 million in 2008. At December 31, 2009, we held $27.3 million in cash and another $2.9 million in restricted cash.

Even with the substantial growth in revenues, net income can be significantly affected by various non-cash items, such as unrealized gains and losses on our commodity derivatives, currency impact of long-term liabilities and deferred taxes. Cash flow provided by (used in) operations was $55.7 million in 2009 versus $133.2 million in 2008 and $128.5 million in 2007. Discretionary cash flow was $71.4 million in 2009 compared to $120.8 million in 2008 and $113.0 million in 2007.

Net loss to common stockholders was $62.2 million for 2009, representing $(0.48) per diluted share and reflecting significant unrealized losses on the mark-to-market of commodity derivatives and a non-cash preferred stock dividend upon the valuation of the redemption and modification of a portion of our preferred stock. Net income to common stockholders was $45.7 million for 2008, or $0.32 per diluted share. Net loss to common stockholders for 2007 was $60.3 million, or $0.49 per share, reflecting the significant unrealized loss on the mark-to-market of commodity derivatives.

Net income as adjusted for 2009 would have been $41.1 million without the effect of impairments, derivative transactions and currency impacts of deferred taxes. Net income as adjusted for 2008 would have been $16.5 million, as compared to net loss as adjusted of $0.3 million in 2007.

Given the significant impact that non-cash items may have on our net income, we use various measures in addition to net income, including non-financial performance indicators and non-GAAP measures as key metrics to manage our business. These key metrics demonstrate the company’s ability to maintain or grow production levels and reserves, internally fund capital expenditures and service debt as well as provide comparisons to other oil and gas exploration and production companies. These measures include, among others, debt and cash balances, production levels, oil and gas reserves, drilling results, discretionary cash flow, adjusted earnings before interest, taxes, depreciation, depletion and amortization (“Adjusted EBITDA”) and adjusted net income.

For definitions of Adjusted EBITDA and Discretionary Cash Flow, and a reconciliation of Adjusted EBITDA to net income as adjusted, please see “Reconciliation of Non-GAAP Accounting Measures.”

Results of Operations

Our revenues have increased significantly since 2006 primarily due to the following:

• Our Enoch field began first production in mid 2007 and each of 2009 and 2008 reflect a full year’s contribution of this asset.

• U.S. production reflects the results of our successful drilling of the Garwood well at the end of 2008 and the purchase of producing assets in October 2009.

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• In the first quarter of 2009, we suspended production at the IVRRH, Renee and Rubie fields due to high operating costs.

• Natural production declines at certain of our fields have not been offset by infield drilling resulting in production decreases at certain fields, particularly in 2009 at our largest gas field – Goldeneye.

• There was an increase in gas production from our discontinued operations at the end of 2007 with the completion of a gas project at Njord in the fourth quarter of 2007.

The following table shows our annual average sales volumes, sales prices and average production costs.

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

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(1)	We record oil revenues on the sales method, i.e. when delivery has occurred. Actual production may differ based on the timing of tanker liftings. We use the entitlements method to account for sales of gas production.
(2)	The average sales prices reflect both our continuing and discontinued operations and include realized gains and losses for derivative contracts we utilize to manage price risk related to our future cash flows.
(3)	Operating costs reflect both our continuing and discontinued operations and are costs incurred to operate and maintain our wells and related equipment and include cost of labor, well service and repair, location maintenance, power and fuel, transportation, cost of product and production related general and administrative costs.

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

The markets in which we sell our oil and natural gas also materially impact our revenues and cash flows. Oil trades on a worldwide market and consequently, price movements for all types and grades of crude oil generally trend in the same direction and within a relatively narrow price range. However, natural gas prices vary among geographic areas as the prices received are largely impacted by local supply and demand conditions as the global transportation infrastructure for natural gas is still developing. As such, the oil we produce and sell is typically in line with global prices, whereas our natural gas is to a large extent impacted by regional supply and demand issues and to a lesser extent by global fuel prices, including oil and coal. Specifically, we sell a majority of our gas into the U.K. market, which is very sensitive to and impacted by tighter European gas supplies and gas deliveries from Russia. Therefore, the price for natural gas in the U.K. market is typically higher than the price for natural gas in other geographic regions and markets, including the U.S.

We utilize various oil and gas derivative instruments to achieve a more predictable cash flow by reducing our exposure to price fluctuations. Hedge accounting has not been elected for these instruments resulting in the application of mark-to-market accounting — effectively pulling forward into current periods the non-cash gains and losses from commodity price fluctuations relating to all future delivery periods. The derivative instruments cover a portion of our production through 2011. The significant volatility in commodity prices and the multi-year nature of the derivative instruments leads to large fluctuations in the fair market value of the derivative instruments at the end of each year. This non-cash change in the fair market value are recorded in unrealized gains (losses) on derivatives in the income statement. The realized prices above show the effect of the cash settlements for our derivative instruments each year. We expect to continue to have fluctuations in net earnings for the change in the fair market value each period as commodity prices fluctuate based on all remaining unsettled contracts. See Note 18 to the consolidated financial statements for additional information on these derivatives.

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Operating Expenses

For 2009, operating expenses decreased to $17.8 million as compared to $32.3 million for 2008. Operating costs per BOE decreased to $12.97 per BOE for 2009 from $14.40 per BOE for 2008. In general, the changes in operating costs reflect the increase in fuel costs in 2008 at a non-operated facility which gathered the production from the IVRRH, Renee and Rubie and then the absence of those costs when we suspended production from those fields in 2009.

DD&A and Impairment of Oil and Gas Properties

Decreased depreciation, depletion and amortization (“DD&A”) expense from 2008 to 2009 reflects the impact of a decrease in production and the lower DD&A rates as a result of impairments in oil and gas properties in 2008 and earlier 2009. Decreased DD&A expense from 2007 to 2008 reflects the impact of a decrease in production from 2007 to 2008 partially offset by an increase in the DD&A rate.

In 2009, we recorded $43.9 million in impairment of oil and gas properties, pre-tax, through the application of the full cost ceiling test. At December 31, 2009, the prices used to determine the estimates of future cash inflows were $60.40 per Bbl for oil and $4.96 per Mcf for gas.

In 2008, we recorded $37.0 million in impairment of oil and gas properties, pre-tax, through the application of the full cost ceiling test at year-end. The prices used to determine the impairment were $36.55 per barrel for oil and $8.70 per Mcf for gas. While our commodity derivatives had a fair value of $31.0 million at December 31, 2008, these derivatives were not included in the calculation of the full cost ceiling test as the derivatives are not accounted for as cash flow hedges.

General and Administrative (“G&A”) Expenses

Our have only slightly increased since 2007 as we have been able to absorb a significant amount of our expanded operations without a corresponding increase in the number of employees. The increase in G&A expenses to $17.0 million for 2009 is a result of an increase in employee compensation and consulting fees associated with the additional staff to pursue our expanding development projects in the U.K. Much of this increase in staff costs was offset by recoveries from our partner on the development project we operate, Rochelle. Non-cash stock-based compensation decreased as a result of the final vesting of grants given in prior years, current year forfeitures and declining fair values on each year’s grants. Components of G&A expenses for these periods are as follows:

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	Year Ended December 31,
	2009			2008			2007
Compensation	$	14,659		$	11,203		$	10,181
Consulting, legal and accounting fees		5,118			4,679			5,045
Occupancy costs		982			1,130			994
Other expenses		1,364			4,004			2,352
Total gross cash G&A expenses		22,123			21,016			18,572
Non-cash stock-based compensation		2,612			2,928			4,487
Gross G&A expenses		24,735			23,944			23,059
Less: capitalized G & A expenses		(7,769	)		(8,012	)		(7,206	)
Net G&A expenses	$	16,966		$	15,932		$	15,853

Interest Expense and Other

The decrease in interest expense from $23.0 million in 2008 to $16.6 million in 2009 reflects the partial repayment of outstanding balances under our senior bank facility with a portion of the proceeds from the sale of our Norwegian operations. Interest expense increased to $23.0 million in 2008 primarily as a result of $4.3 million in expenses, including $2.1 million in cash, related to the early repayment of the second lien term loan.

Income Taxes

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

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

Our income tax expense during the periods indicated relates primarily to our operations in the U.K. and our discontinued operations in Norway. Income taxes decreased in 2009 to a benefit of $7.2 million reflecting the decrease in revenues and the weakening of the U.S. dollar versus the U.K. pound. Income tax expense in 2008 represents the significant increase in revenues as a result of higher realized prices, the strengthening of the U.S. dollar versus the U.K. pound and the shift in anticipated capital expenditures from late 2008 to early 2009. During 2007, we incurred taxes in all of the jurisdictions in which we do business, except for the U.S.

At December 31, 2009, we had net operating loss carryforwards of $77.6 million in the U.S.

In 2009, 2008 and 2007, we have not recorded any income tax benefits in the U.S. as there was no assurance that we could generate any U.S. taxable earnings, resulting in a full valuation allowance of deferred tax assets generated.

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Capital Program

We spent $88.6 million, $88.5 million and $87.9 million on our oil and gas capital program, excluding acquisitions, in 2009, 2008 and 2007, respectively. We spent $16.5 million in 2009 and $15 million to $20 million in both 2008 and 2007 on development activities at our producing properties. The remaining costs were spent on exploration and appraisal activities, including $11.4 million and $5.5 million in 2009 and 2008, respectively, related to our new operations in the U.S. Expenditures for 2009 also included $32.2 million for our acquisitions, primarily located in the U.S.

2009 Capital Resources

	Year Ended December 31,
(Amounts in thousands)	2009			2008
Cash	$	27,287		$	31,421
Restricted Cash, related to rig commitments	$	2,879		$	20,739
Debt, including current maturities	$	(223,385	)	$	(227,855	)
Debt, net of Cash	$	(193,219	)	$	(175,695	)

	Year Ended December 31,
	2009			2008
Net cash provided by operating activities	$	55,711		$	133,180
Net cash provided by (used in) investing activities	$	31,120		$	(64,851	)
Net cash used in financing activities	$	(97,700	)	$	(46,613	)

Our primary sources of financial resources and liquidity are internally generated cash flows from operations and access to the credit and capital markets, to the extent available. During 2009, we principally relied on cash flow from operations and proceeds from our sale of Norwegian assets to fund our capital needs and repay a portion of outstanding debt and preferred stock. Going forward, we believe the combination of our available cash on hand, cash flow from operations and our ability to control capital expenditures will allow us to manage our business effectively while enabling us to further our strategic objectives.

Operating, Investing and Financing Activities include the net cash flows from our discontinued operations. For the years ended December 31, 2009, 2008, and 2007, our discontinued operations had net cash flows provided by (used in) operating activities of approximately $9.0 million, $38.8 million and $26.3 million, respectively. These net cash flows were substantially offset by net cash used by investing activities of approximately $9.0 million, $34.7 million and $25.5 million during 2009, 2008, and 2007, respectively.

Cash flow from operations decreased to $55.7 million for 2009 from $133.2 million for 2008 primarily due to lower realized commodity prices and lower sales volumes, particularly the reduction in gas sales as a result of production declines at Goldeneye.

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In addition to cash flows from operations, we have utilized issuances of debt and equity securities to enhance our liquidity and support the execution of our strategic objectives. Significant issuances and repayments of debt and equity, as well as the uses of the net proceeds, in 2009, 2008, and 2007 were as follows:

• repaid the outstanding balance of the second lien term loan in the first quarter of 2008;

• issued $40 million of the 11.5% convertible bonds in the first quarter of 2008;

• repaid $63.0 million of net debt in 2009; and

• repaid $75 million of the Series C Convertible Preferred Stock in the fourth quarter of 2009 with $25 million in cash and a $50 million note payable.

On November 17, 2009, we redeemed 60% of the outstanding shares of Series C Preferred Stock, for face value of $75 million, and amended the terms of the remaining shares of Series C Preferred Stock. The redemption price consisted of a $25 million cash payment and the issuance of $50 million Subordinated Notes.

The redemption and modification of the Series C Preferred Stock required the modified Series C Preferred Stock to be recorded at fair market value at the redemption date. As there was not a market observable price for the Series C Preferred Stock, we utilized a valuation approach to estimate the price that would be paid to transfer the Series C Preferred Stock in an orderly transaction between market participants. The fair value of the modified Series C Preferred Stock was greater than the carrying value by $11.5 million. This excess of fair value over carrying value was recorded as a non-cash charge to preferred stock dividends and increased the carrying value of the Series C Preferred Stock. As holders convert the Series C Preferred Stock, the $11.5 million non-cash charge will be transferred to equity on a ratio of shares converted to shares of Series C Preferred Stock outstanding.

In the November 2009 amendment, we amended terms of the Series C Preferred Stock to reduce the annual dividend rate to 4.5% (from 8.5%), adjust the conversion price to $1.25 per share (from $2.50) and remove certain anti-dilution provisions.

See Note 9 to the Consolidated Financial Statements for additional discussion of our debt.

Our future revenues and cash flows from operating activities will continue to be sensitive to changes in prices received for our products. Our production is sold at prevailing market prices which fluctuate in response to many factors that are outside of our control. Given the current tightly balanced supply-demand market, small variations in either supply or demand, or both, can have dramatic effects on prices we receive for our oil and natural gas production. While the market price received for oil and natural gas varies among geographic areas, oil trades in a worldwide market, whereas natural gas, which is still developing a global transportation system, is more subject to local supply and demand conditions. Consequently, price movements for all types and grades of crude oil generally move in the same direction.

Natural gas prices in the North Sea have been influenced by fuel prices around the world, including crude oil and coal. These prices are also impacted by European gas supplies,

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particularly deliveries from Russian gas supplies. In addition, regional supply and demand issues affect gas prices. The majority of our natural gas is sold in the U.K. market. Market prices for both oil and natural gas were at high levels throughout much of 2007 and 2008. North Sea gas prices declined in the first quarter of 2007 but recovered in the second half of the year and remained strong during 2008 and 2009.

Our cash flows will be significantly impacted by the amount of hydrocarbons we produce, the price we obtain for our produced commodities and taxes paid on operations. Oil prices continue to be impacted by supply and demand on a worldwide basis, while natural gas prices are more impacted by regional economic and weather patterns. Although oil and gas prices have remained volatile, the full impact on our cash flows will be partially mitigated by our balance of gas to oil production and our commodity derivative positions. As of December 31, 2009, our outstanding commodity derivatives covered 30% to 45% of expected 2010 production.

Recent Financing Arrangements

In February 2010, we issued 23.5 million shares of common stock in a private placement for aggregate net proceeds of $20.5 million. We also entered $25 million junior lending facility, with a maturity date of February 5, 2011, and interest at LIBOR plus 8%. Upon entering the new junior lending facility, we borrowed $15 million against the facility. The net proceeds from the private placement and the borrowing under the junior facility will be used to partially fund our 2010 capital budget.

Non-GAAP Measures

Net income can be significantly affected by various non-cash items, such as unrealized gains and losses on our commodity derivatives, currency impact of long-term liabilities and deferred taxes. Given the significant impact that non-cash items may have on our net income, we use various measures in addition to net income, including non-financial performance indicators and non-GAAP measures as key metrics to manage our business. These key metrics demonstrate the company’s ability to maintain or grow production levels and reserves, internally fund capital expenditures and service debt as well as provide comparisons to other oil and gas exploration and production companies. These measures include, among others, debt and cash balances, production levels, oil and gas reserves, drilling results, discretionary cash flow, adjusted earnings before interest, taxes, depreciation, depletion and amortization (“Adjusted EBITDA”) and adjusted net income.

Net Income (Loss) as Adjusted, Adjusted EBITDA and Discretionary Cash Flow are internal, supplemental measures of our performance that are not required by, or presented in accordance with, GAAP. We use these non-GAAP measures as internal measures of performance and to aid in our budgeting and forecasting processes. We view these non-GAAP measures, and we believe that others in the oil and gas industry view these, or similar, non-GAAP measures, as commonly used analytic indicators to compare performance among companies. We further believe that these non-GAAP measures are frequently used by securities analysts, investors, and other interested parties in the evaluation of issuers, many of which present these measures when reporting their results. We believe these non-GAAP measures provide useful information to both

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management and investors to gain an overall understanding of our current financial performance and provide investors with financial measures that most closely align to our internal measurement processes. Since the application of mark-to-market accounting has the effect of pulling forward into current periods non-cash gains and losses related to commodity derivatives relating to future delivery periods, analysis of results of operations from one period to another can be difficult. We believe that excluding these unrealized non-cash gains and losses related to commodity derivatives and currency exchange changes provides a more meaningful representation of our economic performance in the reporting period and is therefore useful to us, investors, analysts and others in facilitating the analysis of our results of operations from one period to another. These measures should not be considered as measures of financial performance under GAAP, and the items excluded from these measures are significant components in understanding and assessing financial performance.

These non-GAAP measures should not be considered in isolation or as an alternative to net income, operating income or any other performance measures derived in accordance with GAAP or as alternatives to cash flows generated by operating, investing or financing activities as a measure of our liquidity. Because Net Income (Loss) as Adjusted, Adjusted EBITDA and Discretionary Cash Flow are not measurements determined in accordance with GAAP and thus susceptible to varying calculations, Net Income (Loss) as Adjusted, Adjusted EBITDA and Discretionary Cash Flow as presented may not be comparable to other similarly titled measures of other companies.

Net Income (Loss) as Adjusted, Adjusted EBITDA and Discretionary Cash Flow have limitations as an analytical tool, and you should not consider these measures in isolation, or as a substitute for analysis of our financial statement data presented in the consolidated financial statements as reported under GAAP. For example, Net Income (Loss) as Adjusted, Adjusted EBITDA and Discretionary Cash Flow may not reflect:

• our cash expenditures, or future requirements, for capital expenditures or contractual commitments;

• changes in, or cash requirements for, our working capital needs;

• unrealized gains (losses) on derivatives;

• non-cash foreign currency gains (losses);

• our interest expense, or the cash requirements necessary to service interest and principal payments on our debts;

• our preferred stock dividend requirements; and

• depreciation, depletion and amortization.

Because of these limitations, Net Income (Loss) as Adjusted, Adjusted EBITDA and Discretionary Cash Flow should not be considered as measures of cash available to us to invest in the growth of our business. We compensate for these limitations by relying primarily on our GAAP results and by using Net Income (Loss) as Adjusted, Adjusted EBITDA and Discretionary Cash Flow only supplementally.

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As required under Regulation G of the Securities Exchange Act of 1934, provided below are reconciliations of net income (loss) to the following non-GAAP financial measures: Net Income (Loss) as Adjusted, Adjusted EBITDA and Discretionary Cash Flow.

	Year Ended December 31,
	2009			2008			2007
Net income (loss)	$	(40,995	)	$	56,490		$	(49,077	)
Depreciation, depletion and amortization		38,701			81,734			76,850
Impairment of oil and gas properties		43,929			36,970			—
Deferred tax expense (benefit)		4,599			17,682			(12,925	)
Gain on asset sales		(47,308	)		—			—
Unrealized (gain) loss on derivatives		55,598			(76,666	)		89,132
Other		16,835			4,597			8,994
Discretionary Cash Flow (1)	$	71,359		$	120,807		$	112,974
Net income (loss)	$	(40,995	)	$	56,490		$	(49,077	)
Impairment of oil and gas properties (net of tax) (2)		28,263			18,485			—
Unrealized (gain) loss on derivatives (net of tax) (3)		33,702			(37,743	)		44,566
Currency impact on deferred taxes		20,123			(20,709	)		4,842
Net Income as Adjusted	$	41,093		$	16,523		$	331
Net income (loss)	$	(40,995	)	$	56,490		$	(49,077	)
Unrealized (gain) loss on derivatives		55,598			(76,666	)		89,132
Net interest expense		16,420			21,301			16,430
Depreciation, depletion and amortization		38,701			81,734			76,850
Impairment of oil and gas properties		43,929			36,970			—
Income tax expense (benefit)		(1,729	)		56,729			(9,180	)
Gain on asset sales		(47,308	)		—			—
Adjusted EBITDA	$	64,616		$	176,558		$	124,155

(1)	Discretionary cash flow is equal to cash flow from operating activities before the changes in operating assets and liabilities.
(2)	Net of tax benefits of $ (15,666) and $ (18,485) for 2009 and 2008, respectively.
(3)	Net of tax expense (benefit) of $ (21,896), $38,923 and (44,566), respectively.

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Outlook
2010 Planned Capital Expenditures

We anticipate spending approximately $90 million during 2010 to fund oil and gas activities in the U.S. and U.K. The majority of this amount is controllable by Endeavour. Our primary focus during 2010 in the U.S. will be in the Haynesville area as we believe this acreage contains near-term production potential. The ongoing U.S. program and expenditures will be tailored based on early drilling results. During 2010, we also expect to begin the evaluation program of our other U.S. assets in the Marcellus area and the two frontier plays in Alabama and Montana. Four U.K. wells have been or will be drilled in 2010; two Cygnus appraisal wells in the western portion of the field; the Deacon well that began in 2009 and finished in 2010, and the exploration well west of the Rochelle development. While this drilling is occurring, we expect to continue further our development programs at our four existing development projects, including ongoing engineering assessments for future production and commercial off-take solutions. We intend to fund these development activities through cash on hand, and cash flow generated from operations, as well as expansion of our credit facilities as needed.

The timing, completion and process of our 2010 capital program is subject to a number of factors, including availability of capital, drilling results, drilling and production costs, availability of drilling services and equipment, partner approvals and technical work. Based on these and other factors, we may increase or decrease our planned capital program or prioritize certain projects over others.

Estimated Average Production (A)
Daily Production (BOE per day)		4,500		to		6,000
Differentials (B)
Oil ($/Bbl)	$	(5.00	)	to	$	(6.00	)
Gas ($Mcf)	$	(0.50	)	to	$	(0.60	)
Gas Percentage of Total		55	%	to		60	%
Lease Operating Expense ($  per barrel)	$	8.00		to	$	10.00

(A)	Actual results may differ materially from these estimates.
(B)	For purposes of the estimates, assumptions of price differentials are based on location, quality and other factors, excluding the effects of derivative financial instruments. Gas price differentials are stated as premiums (discounts) from Henry Hub pricing, and oil price differentials are stated as premiums (discounts) from West Texas Intermediate pricing.

Liquidity and Financial Resources

Our primary sources of financial resources and liquidity are internally generated cash flows from operations and access to the credit and capital markets, to the extent available. We believe the

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combination of our available cash on hand, cash flow from operations and our ability to control capital expenditures will allow us to manage our business effectively while enabling us to further our strategic objectives.

Our cash flows will be significantly impacted by the amount of hydrocarbons we produce, the price we obtain for our produced commodities and taxes paid on operations. Oil prices continue to be impacted by supply and demand on a worldwide basis, while natural gas prices are more impacted by regional economic and weather patterns. Although oil and gas prices have remained volatile, the full impact on our cash flows will be partially mitigated by our balance of gas to oil production and our commodity derivative positions. As of December 31, 2009, our outstanding commodity derivatives covered 30% to 45% of expected 2010 production.

Our income tax expense relates primarily to our operations in the UK (statutory income tax rate of 50%). We are currently not able to record income tax benefits on our U.S. loss as there is no assurance that we can generate any U.S. taxable earnings. As operations expand in the U.S., we will be able to record income tax benefits in the U.S., however we do not anticipate paying current federal income taxes in the U.S. for quite some time.

In February 2010, we issued 23.5 million shares of common stock for an aggregate net proceeds of $20.5 million. We also entered into a $25 million junior lending facility, with a maturity date of February 5, 2011, and interest at LIBOR plus 8%. Upon entering the new junior lending facility, we borrowed $15 million against the facility. The net proceeds from these transactions will be used to partially fund our 2010 capital budget.

At December 31, 2009, we had $49.9 million outstanding under our senior bank facility. The senior bank facility has a current borrowing base capacity of $50 million, which is secured by our oil and gas assets. In February 2010, the maturity date of the senior bank facility was changed to January 31, 2011. We also have $50.1 million of Subordinated Notes that amortize over four years commencing in March 2011.

With the Junior Facility and Senior Bank Facility, we will have $65 million in debt due in the first quarter of 2011, based on outstanding balances at February 28, 2010. During 2010, we plan to utilize our existing U.K. oil and gas assets, as well as our growing U.S. reserve base, as a basis for refinancing and expansion of our credit facilities. We are currently in discussions with several parties concerning this process. We strive to synchronize our capital expenditures with our cash flow. However, we believe our existing U.K. reserves, including probable reserves, are of significant value and together with our U.S. assets can be used as support for increased financial resources when necessary to fund our on-going activities or refinance indebtedness. We continually monitor the capital markets to evaluate the most appropriate actions to fund our activities.

On March 15, 2010, we announced that our board of directors has approved a review of strategic alternatives for its North Sea assets. In an effort to unlock the value of our underlying North Sea assets, we will study a full range of options, including:

• Continuing to execute current operations plan;

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• Entering into a joint venture to accelerate activities in the North Sea; and

• Selling specific assets or the North Sea entire business.

We will announce the results of the effort once a course of action is chosen. At the end of this review process, we may elect to make no changes.

Disclosures about Contractual Obligations and Commercial Commitments

The following table sets forth our obligations and commitments to make future payments under its lease agreements and other long-term obligations as of December 31, 2009:

	Payments due by Period
			Less
			than 1		1-3		3-5		After 5
(Amounts in thousands)	Total		Year		Years		Years		Years
Long-term debt
Principal	$	231,152	$	—	$	161,192	$	69,960	$	—
Interest (1)		56,962		11,323		13,728		31,911		—
Asset retirement obligations		47,362		3,249		51		—		44,062
Operating leases for office leases and equipment		1,073		638		393		42		—
Rig commitments (2)		17,055		17,055		—		—		—
Total Contractual Obligations	$	353,604	$	32,265	$	175,364	$	101,913	$	44,062

(1)

Assumes a 1.5% LIBOR rate. In addition, interest on our 11.5% convertible debt and $50 million note is added to the outstanding principal balance each quarter and reflected as due upon maturity.

(2)

As is common in the oil and gas industry, we operate in many instances through joint ventures under joint operating or similar agreements. Typically, the operator under a joint operating agreement enters into contracts, such as rig commitment contracts, for the benefit of all joint venture partners. Through the joint operating agreement, the non-operators reimburse, and in some cases advance, the funds necessary to meet the contractual obligations entered into by the operator. These obligations are typically shared on a “working interest” basis. The joint operating agreement provides remedies to the operator in the event that the non-operator does not satisfy its share of the contractual obligations. Occasionally, the operator is permitted by the joint operating agreement to enter into lease obligations and other contractual commitments that are then passed on to the non-operating joint interest owners as lease operating expenses, frequently without any identification as to the long-term nature of any commitments underlying such expenses. Once the timing for rig delivery and the specific well to be drilled are determined, this obligation will be shared with the other working interest owners.

Off-Balance Sheet Arrangements

At December 31, 2010, we did not have any off-balance sheet arrangements.

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Rig Commitments

Our rig commitments represent one commitment for 46 days of a rig in the U.K. We are currently considering the timing of rig deliverability and completion of the commitment.

Critical Accounting Policies and Estimates

The accompanying financial statements have been prepared on the accrual basis of accounting in accordance with accounting principles generally accepted in the United States of America and have been presented on a going concern basis, which contemplates the realization of assets and satisfaction of liabilities in the normal course of business. These accounting principles require management to use estimates, judgments and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements, and revenues and expenses during the reporting period. Management reviews its estimates, including those related to the determination of proved reserves, estimates of future dismantlement costs, income taxes and litigation. Actual results could differ from those estimates.

Management believes it is reasonably possible that the following material estimates affecting the financial statements could change in the coming year: (1) estimates of proved oil and gas reserves, (2) estimates as to the expected future cash flow from proved oil and gas properties, (3) estimates of future dismantlement and restoration costs, (4) estimates of fair values used in purchase accounting and (5) estimates of the fair value of derivative instruments. In addition, alternatives may exist among various accounting methods. In such cases, the choice of accounting method may also have a significant impact on reported amounts.

Our critical accounting policies are as follows:

Full Cost Accounting

Under the full cost method, all acquisition, exploration and development costs, including certain directly related employee costs and a portion of interest expense, incurred for the purpose of finding oil and gas are capitalized and accumulated in pools on a country-by-country basis. Capitalized costs include the cost of drilling and equipping productive wells, including the estimated costs of dismantling and abandoning these assets, dry hole costs, lease acquisition costs, seismic and other geological and geophysical costs, delay rentals and costs related to such activities. Employee costs associated with production and other operating activities and general corporate activities are expensed in the period incurred.

Capitalized costs are limited on a country-by-country basis (the ceiling test). The ceiling test limitation is calculated as the sum of the present value of future net cash flows related to estimated production of proved reserves, using the average, first-day-of-the-month price during the 12-month period before the end of the year for 2009 and the year-end price for 2008 and 2007, including the effect of derivative instruments that qualify as cash flow hedges, discounted at 10%, plus the lower of cost or estimated fair value of unproved properties, all net of expected

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income tax effects. Under the ceiling test, if the capitalized cost of the full cost pool, net of deferred taxes, exceeds the ceiling limitation, the excess is charged as an impairment expense.

We utilize a single cost center for each country where we have operations for amortization purposes. Any conveyances of properties are treated as adjustments to the cost of oil and gas properties with no gain or loss recognized unless the operations are suspended in the entire cost center or the conveyance is significant in nature.

Unproved property costs include the costs associated with unevaluated properties and properties under development and are not included in the full cost amortization base (where proved reserves exist) until the project is evaluated. These costs include unproved leasehold acreage, seismic data, wells and production facilities in progress and wells pending determination, together with interest costs capitalized for these projects. Seismic data costs are associated with specific unevaluated properties where the seismic data is acquired for the purpose of evaluating acreage or trends covered by a leasehold interest owned by us. Significant unproved properties are assessed periodically for possible impairment or reduction in value. If a reduction in value has occurred, these property costs are considered impaired and are transferred to the related full cost pool. Geological and geophysical costs included in unproved properties are transferred to the full cost amortization base along with the associated leasehold costs on a specific project basis. Costs associated with wells in progress and wells pending determination are transferred to the amortization base once a determination is made whether or not proved reserves can be assigned to the property. Costs of dry holes are transferred to the amortization base immediately upon determination that the well is unsuccessful. Unproved properties whose acquisition costs are not individually significant are aggregated, the portion of such costs estimated to be ultimately nonproductive, based on experience, are amortized to the full cost pool over an average holding period.

In countries where the existence of proved reserves has not yet been determined, unevaluated property costs remain capitalized in unproved property cost centers until proved reserves have been established, exploration activities cease or impairment and reduction in value occurs. If exploration activities result in the establishment of a proved reserve base, amounts in the unproved property cost center are reclassified as proved properties and become subject to amortization and the application of the ceiling test. When it is determined that the value of unproved property costs have been permanently diminished (in part or in whole) based on the impairment evaluation and future exploration plans, the unproved property cost centers related to the area of interest are impaired, and accumulated costs charged against earnings.

We capitalize interest on expenditures for significant exploration and development projects while activities are in progress to bring the assets to their intended use. Capitalized interest is calculated by multiplying our weighted-average interest rate on debt by the amount of qualifying costs and is limited to gross interest expense. As costs are transferred to the full cost pool, the associated capitalized interest is also transferred to the full cost pool.

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Business Combinations

Assets and liabilities acquired through a business combination are recorded at estimated fair value. We use all available information to make these fair value determinations, including information commonly considered by our engineers in valuing individual oil and gas properties and sales prices for similar assets. Estimated deferred taxes are based on available information concerning the tax basis of the acquired company’s assets and liabilities and carryforwards at the merger date.

Any excess of the acquisition cost of the acquired business over the fair value amounts assigned to assets and liabilities is recorded as goodwill. Any excess of the amounts assigned to assets and liabilities over the acquisition of the acquired business is recorded as a gain on acquisition on the income statement. The amount of goodwill recorded in any particular business combination can vary significantly depending upon the fair values attributed to assets acquired and liabilities assumed relative to the total acquisition cost.

Goodwill and Intangible Assets

Goodwill represents the excess of the purchase price over the estimated fair value of the assets acquired and liabilities assumed in an acquisition. Intangible assets represent the purchase price allocation to the assembled workforce as a result of the acquisition of NSNV, Inc. We assess the carrying amount of goodwill and other indefinite-lived intangible assets by testing the asset for impairment annually at year-end, or more frequently if events or changes in circumstances indicate that the asset might be impaired. The impairment test requires allocating goodwill and all other assets and liabilities to reporting units. The fair value of each reporting unit is determined and compared to the book value of the reporting unit. An impairment loss is recognized to the extent that the carrying amount exceeds the asset’s fair value.

At December 31, 2009, we had $211.9 million of goodwill recorded related to past business combinations. This goodwill is not amortized, but is required to be assessed for impairment annually, or more often as facts and circumstances warrant. The first step of that process is to compare the fair value of the reporting unit to which goodwill has been assigned to the carrying amount of the associated net assets and goodwill. The reporting units used to evaluate and measure goodwill for impairment are determined from the manner in which the business is managed. We have determined we have a single reporting unit. Goodwill is tested annually at year end. Although we cannot predict when or if goodwill will be impaired, impairment charges may occur if we are unable to replace the value of our depleting asset base or if other adverse events (for example, lower sustained oil and gas prices) reduce the fair value of the reporting unit.

We completed our 2009 annual goodwill impairment test with no impairment indicated as the estimated fair value of our reporting unit was substantially greater than its book value. We considered our market capitalization based on average stock prices for 20 days before December 31, 2009.

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A lower fair value estimate in the future could result in impairment. Examples of factors that could cause a lower fair value estimate could be sustained declines in prices, increases in costs, and changes in discount rate assumptions due to market conditions.

Dismantlement, Restoration and Environmental Costs

We recognize liabilities for asset retirement obligations associated with tangible long-lived assets, such as producing well sites, offshore production platforms, and natural gas processing plants, with a corresponding increase in the related long-lived asset. The asset retirement cost is depreciated along with the property and equipment in the full cost pool. The asset retirement obligation is recorded at fair value and accretion expense, recognized over the life of the property, increases the liability to its expected settlement value. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded for both the asset retirement obligation and the asset retirement cost.

Revenue Recognition

We use the entitlements method to account for sales of gas production. We may receive more or less than our entitled share of production. Under the entitlements method, if we receive more than our entitled share of production, the imbalance is treated as a liability at the market price at the time the imbalance occurred. If we receive less than our entitled share, the imbalance is recorded as an asset at the lower of the current market price or the market price at the time the imbalance occurred. Oil revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred, title has transferred and collectability of the revenue is probable.

Derivative Instruments and Hedging Activities

From time to time, we may utilize derivative financial instruments to hedge cash flows from operations or to hedge the fair value of financial instruments. We may use derivative financial instruments with respect to a portion of our oil and gas production or a portion of our variable rate debt to achieve a more predictable cash flow by reducing our exposure to price fluctuations. These transactions are likely to be swaps, collars or options and to be entered into with major financial institutions or commodities trading institutions. Derivative financial instruments are intended to reduce our exposure to declines in the market prices of crude oil and natural gas that we produce and sell, to increases in interest rates and to manage cash flows in support of our annual capital expenditure budget. We also have embedded derivatives related to our debt instruments and convertible preferred stock.

We record all derivatives at fair market value in our Consolidated Balance Sheets at the end of each period. The accounting for the fair market value, and the changes from period to period, depends on the intended use of the derivative and the resulting designation. This evaluation is determined at each derivative’s inception and begins with the decision to account for the derivative as a hedge, if applicable. The accounting for changes in the fair value of a derivative

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instrument that is not accounted for as a hedge is included in other (income) expense as an unrealized gain or loss. Where we intend to account for a derivative as a hedge, we document, at its inception, the hedging relationship, the risk management objective and the strategy for undertaking the hedge. The documentation includes the identification of the hedging instrument, the hedged item or transaction, the nature of the risk being hedged, and the method that will be used to assess effectiveness of derivative instruments that receive hedge accounting treatment.

Changes in fair value to hedge instruments, to the extent the hedge is effective, are recognized in other comprehensive income until the forecasted transaction occurs. Hedge effectiveness is assessed at least quarterly based on total changes in the derivative’s fair value. Any ineffective portion of the derivative instrument’s change in fair value is recognized immediately in other (income) expense.

We discontinue hedge accounting prospectively when (1) we determine that the derivative is no longer effective in offsetting changes in the fair value or cash flows of a hedged item (including hedged items such as firm commitments or forecasted transactions); (2) the derivative expires; (3) it is no longer probable that the forecasted transaction will occur; (4) a hedged firm commitment no longer meets the definition of a firm commitment; or (5) management determines that designating the derivative as a hedging instrument is no longer appropriate.

Income Taxes

We use the liability method of accounting for income taxes under which deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities, and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized as part of the provision for income taxes in the period that includes the enactment date. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion of, or all of, the deferred tax assets will not be realized.

Stock-Based Compensation Arrangements

We recognize all share-based payments to employees, including grants of employee stock options, based on their fair values. The share-based compensation cost is measured at the grant date, based on the calculated fair value of the award, and is recognized as general and administrative expense over the employee’s requisite service period (generally the vesting period of the equity award). We apply the fair value method in accounting for stock option grants to non-employees using the Black-Scholes Method.

It is our policy to use authorized but unissued shares of stock when stock options are exercised. At December 31,2009, we had approximately 7.0 million additional shares available for issuance pursuant to our existing stock incentive plan.

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Fair Value

We estimate fair value for the measurement of derivatives, long-lived assets during certain impairment tests, reporting units for goodwill impairment testing, the initial measurement of an asset retirement obligation and the initial measurement of our Series C Preferred Stock upon its redemption and modification. When we are required to measure fair value, and there is not a market observable price for the asset or liability, or a market observable price for a similar asset or liability, we generally utilize an income valuation approach. This approach utilizes management’s best assumptions regarding expectations of projected cash flows, and discounts the expected cash flows using a commensurate risk adjusted discount rate. Such evaluations involve a significant amount of judgment since the results are based on expected future events or conditions, such as sales prices; estimates of future oil and gas production; development and operating costs and the timing thereof; economic and regulatory climates and other factors. Our estimates of future net cash flows are inherently imprecise because they reflect management’s expectation of future conditions that are often outside of management’s control. However, assumptions used reflect a market participant’s view of long-term prices, costs and other factors, and are consistent with assumptions used in our business plans and investment decisions.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Foreign Exchange Risk

The international scope of our business operations exposes us to the risk of fluctuations in foreign currency markets. As a result, we are subject to foreign currency exchange rate risk due to effects that foreign exchange rate movements have on our costs and on the cash flows that we receive from foreign operations. Our oil revenues are received in U.S. dollars while gas revenues in the U.K. are received in pounds sterling. Capital expenditures, payroll and operating expenses may be denominated in U.S. dollars or pounds sterling. We operate a centralized currency management operation to take advantage of potential opportunities to naturally offset exposures against each other. To date, we have addressed our foreign currency exchange rate risks principally by maintaining our liquid assets in interest-bearing accounts, until payments in foreign currency are required. We have not reduced this risk by hedging to date as the timing expenditures in pounds sterling has been predictable and we have been able to match revenues received in pounds sterling and foreign currency purchases to minimize our exposure to foreign currency exchange rate risk.

Commodity Price Risk

We produce and sell crude oil and natural gas. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and regional gas spot market prices which have been volatile and unpredictable for several years. As a result, our financial results can be significantly impacted as these commodity prices fluctuate widely in response to changing market forces. We

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may engage in oil and gas hedging activities to realize commodity prices which we consider favorable.

At December 31, 2009, we had the following commodity derivative instruments outstanding:

	2010		2011		Total
Oil:
Fixed Price Swaps (Mbbl)		533		487		1,020
Weighted Average Price ($/Barrel)	$	68.39	$	66.01	$	67.25
Gas: (1)
Fixed Price Swaps (MMcf)		1,032		627		1,659
Weighted Average Price ($/Mcf)	$	8.68	$	8.32	$	8.54

⁽¹⁾ Gas derivative contracts are designated in therms and have been converted to Mcf at a rate of 10 therm to 1 Mcf. The exchange rate at December 31, 2009 was $1.62 to £1.00.

At December 31, 2009 and 2008, the prices used to determine the estimates of future cash inflows were $60.40 and $36.55 per barrel, respectively, for oil and $4.96 and $8.70 per Mcf, respectively, for gas. The fair value of our commodity derivatives was $12.8 million at December 31, 2009.

Interest Rate Risk

We are exposed to changes in interest rates. Changes in interest rates affect the interest earned on cash and cash equivalents and the interest rate paid on certain borrowings under debt. A 250 point change in basis points on LIBOR would not result in a material change in our annual interest expense, given our floating rate debt at December 31, 2009.

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Item 8. Financial Statements and Supplementary Data

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders
Endeavour International Corporation:

We have audited the accompanying consolidated balance sheets of Endeavour International Corporation and subsidiaries as of December 31, 2009 and 2008, and the related consolidated statements of operations, stockholders’ equity and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2009. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Endeavour International Corporation and subsidiaries as of December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles.

As discussed in note 2 to the consolidated financial statements, effective January 1, 2008, the Company changed its method of accounting and disclosures for fair value measurements and fair value reporting of financial assets and liabilities. Also as discussed in note 2 to the consolidated financial statements, effective December 31, 2009, the Company has changed it reserve estimates and related disclosures as a result of adopting new oil and gas reserve estimation and disclosure requirements.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Endeavour International Corporation’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 16, 2010 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/S/ KPMG LLP
Houston, Texas
March 16, 2010

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Consolidated Balance Sheets
(Amounts in thousands)

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

See accompanying notes to condensed consolidated financial statements.

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Consolidated Balance Sheets
(Amounts in thousands)

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

See accompanying notes to condensed consolidated financial statements.

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Consolidated Statement of Operations
(Amounts in thousands, except per share data)

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

See accompanying notes to condensed consolidated financial statements.

65

Endeavour International Corporation
Consolidated Statement of Cash Flows
(Amounts in thousands)

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

See accompanying notes to condensed consolidated financial statements.

66

Endeavour International Corporation
Consolidated Statement of Stockholders’ Equity
(Amounts in thousands)

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

See accompanying notes to condensed consolidated financial statements.

67

Endeavour International Corporation
Consolidated Statement of Stockholders’ Equity
(Amounts in thousands)

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

See accompanying notes to condensed consolidated financial statements.

68

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

Note 1 — Description of Business

Endeavour International Corporation was incorporated under the laws of the state of Nevada on January 13, 2000. As used in these Notes to Consolidated Financial Statements, the terms “Endeavour”, “we”, “us”, “our” and similar terms refer to Endeavour International Corporation and, unless the context indicates otherwise, its consolidated subsidiaries.

Note 2 — Summary of Significant Accounting Policies

Basis of Presentation and Use of Estimates

The accompanying financial statements have been prepared on the accrual basis of accounting in accordance with accounting principles generally accepted in the United States of America (“US GAAP”) and have been presented on a going concern basis, which contemplates the realization of assets and satisfaction of liabilities in the normal course of business. These accounting principles require management to use estimates, judgments and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements, and revenues and expenses during the reporting period. Management reviews its estimates, including those related to the determination of proved reserves, estimates of future dismantlement costs, income taxes and litigation. Actual results could differ from those estimates. In the opinion of management, all normal recurring adjustments considered necessary for a fair presentation have been included in these financial statements. Certain amounts for prior periods have been reclassified to conform to the current presentation.

Management believes it is reasonably possible that the following material estimates affecting the financial statements could change in the coming year: (1) estimates of proved oil and gas reserves, (2) estimates as to the expected future cash flow from proved oil and gas properties, (3) estimates of future dismantlement and restoration costs, (4) estimates of fair values used in purchase accounting and (5) estimates of the fair value of derivative instruments.

Principles of Consolidation

The accompanying consolidated financial statements include all of the accounts of Endeavour and our consolidated subsidiaries. All significant intercompany accounts and transactions have been eliminated. Investments in entities over which we have significant influence, but not control, are carried at cost adjusted for equity in earnings or (losses) and distributions received.

Cash and Cash Equivalents

We consider all highly liquid instruments with an original maturity of 90 days or less at the time of purchase to be cash equivalents.

69

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

Restricted Cash

Restricted cash includes amounts held in escrow for drilling rig commitments and for purchase price of the acquisition of properties from Hillwood Energy. The escrow for the Hillwood Energy properties was release upon closing of the acquisition in January 2010. The remaining reserved amounts in escrow will be released as payments are made for this drilling activity.

Inventories

Materials and supplies and oil inventories are valued at the lower of cost or market value (net realizable value).

Full Cost Accounting for Oil and Gas Operations

Under the full cost method, all acquisition, exploration and development costs, including certain directly related employee costs and a portion of interest expense, incurred for the purpose of finding oil and gas are capitalized and accumulated in pools on a country-by-country basis. Capitalized costs include the cost of drilling and equipping productive wells, including the estimated costs of dismantling and abandoning these assets, dry hole costs, lease acquisition costs, seismic and other geological and geophysical costs, delay rentals and costs related to such activities. Employee costs associated with production and other operating activities and general corporate activities are expensed in the period incurred.

Capitalized costs are limited on a country-by-country basis (the ceiling test). The ceiling test limitation is calculated as the sum of the present value of future net cash flows related to estimated production of proved reserves, using the average, first-day-of-the-month price during the 12-month period before the end of the year for 2009 and the year-end price for 2008 and 2007, including the effect of derivative instruments that qualify as cash flow hedges, discounted at 10%, plus the lower of cost or estimated fair value of unproved properties, all net of expected income tax effects. Under the ceiling test, if the capitalized cost of the full cost pool, net of deferred taxes, exceeds the ceiling limitation, the excess is charged as an impairment expense.

We utilize a single cost center for each country where we have operations for amortization purposes. Any conveyances of properties are treated as adjustments to the cost of oil and gas properties with no gain or loss recognized unless the operations are suspended in the entire cost center or the conveyance is significant in nature.

Unproved property costs include the costs associated with unevaluated properties and properties under development and are not initially included in the full cost amortization base (where proved reserves exist) until the project is evaluated. These costs include unproved leasehold acreage, seismic data, wells and production facilities in progress and wells pending determination,

70

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

together with interest costs capitalized for these projects. Seismic data costs are associated with specific unevaluated properties where the seismic data is acquired for the purpose of evaluating acreage or trends covered by a leasehold interest owned by us. Significant unproved properties are assessed periodically for possible impairment or reduction in value. If a reduction in value has occurred, these property costs are considered impaired and are transferred to the related full cost pool. Geological and geophysical costs included in unproved properties are transferred to the full cost amortization base along with the associated leasehold costs on a specific project basis. Costs associated with wells in progress and wells pending determination are transferred to the amortization base once a determination is made whether or not proved reserves can be assigned to the property. Costs of dry holes are transferred to the amortization base immediately upon determination that the well is unsuccessful. Unproved properties whose acquisition costs are not individually significant are aggregated, the portion of such costs estimated to be ultimately nonproductive, based on experience, are amortized to the full cost pool over an average holding period.

In countries where the existence of proved reserves has not yet been determined, unevaluated property costs remain capitalized in unproved property cost centers until proved reserves have been established, exploration activities cease or impairment and reduction in value occurs. If exploration activities result in the establishment of a proved reserve base, amounts in the unproved property cost center are reclassified as proved properties and become subject to amortization and the application of the ceiling test. When it is determined that the value of unproved property costs have been permanently diminished (in part or in whole) based on the impairment evaluation and future exploration plans, the unproved property cost centers related to the area of interest are impaired, and accumulated costs charged against earnings.

Other Property and Equipment

Other oil and gas assets, computer equipment and furniture and fixtures are recorded at cost, less accumulated depreciation. The assets are depreciated using the straight-line method over their estimated useful lives of two to five years.

Capitalized Interest

We capitalize interest on expenditures for significant exploration and development projects while activities are in progress to bring the assets to their intended use. Capitalized interest is calculated by multiplying our weighted-average interest rate on debt by the amount of qualifying costs and is limited to gross interest expense. As costs are transferred to the full cost pool, the associated capitalized interest is also transferred to the full cost pool.

71

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

Marketable Securities

The marketable securities reflected in these financial statements are deemed by management to be “available-for-sale” and, accordingly, are reported at fair value, with unrealized gains and losses reported in other comprehensive income and reflected as a separate component within the Statement of Stockholders’ Equity unless we determine that an other-than-temporary impairment has occurred. Realized gains and losses on securities available-for-sale are included in other income/expense and, when applicable, are reported as a reclassification adjustment, net of tax, in other comprehensive income. Gains and losses on the sale of available-for-sale securities are determined using the specific-identification method.

Business Combinations

Assets and liabilities acquired through a business combination are recorded at estimated fair value. We use all available information to make these fair value determinations, including information commonly considered by our engineers in valuing individual oil and gas properties and sales prices for similar assets. Estimated deferred taxes are based on available information concerning the tax basis of the acquired company’s assets and liabilities and carryforwards at the merger date.

Any excess of the acquisition cost of the acquired business over the fair value amounts assigned to assets and liabilities is recorded as goodwill. Any excess of the amounts assigned to assets and liabilities over the acquisition of the acquired business is recorded as a gain on acquisition on the income statement. The amount of goodwill recorded in any particular business combination can vary significantly depending upon the fair values attributed to assets acquired and liabilities assumed relative to the total acquisition cost.

Goodwill and Intangible Assets

We assess the carrying amount of goodwill and other indefinite-lived intangible assets by testing the asset for impairment annually at year-end, or more frequently if events or changes in circumstances indicate that the asset might be impaired. The impairment test requires allocating goodwill and all other assets and liabilities to reporting units. The fair value of each reporting unit is determined and compared to the book value of the reporting unit. An impairment loss is recognized to the extent that the carrying amount exceeds the asset’s fair value.

Dismantlement, Restoration and Environmental Costs

We recognize liabilities for asset retirement obligations associated with tangible long-lived assets, such as producing well sites, offshore production platforms, and natural gas processing plants, with a corresponding increase in the related long-lived asset. The asset retirement cost is depreciated along with the property and equipment in the full cost pool. The asset retirement

72

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

obligation is recorded at fair value and accretion expense, recognized over the life of the property, increases the liability to its expected settlement value. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded for both the asset retirement obligation and the asset retirement cost.

Revenue Recognition

We use the entitlements method to account for sales of gas production. We may receive more or less than our entitled share of production. Under the entitlements method, if we receive more than our entitled share of production, the imbalance is treated as a liability at the market price at the time the imbalance occurred. If we receive less than our entitled share, the imbalance is recorded as an asset at the lower of the current market price or the market price at the time the imbalance occurred. Oil revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred, title has transferred and collectability of the revenue is probable.

Significant Customers

Our sales in the U.K. are to a limited number of customers, each of which accounts for more than 10% of revenue: Chevron North Sea Ltd; Shell U.K. Limited, and Esso Exploration and Production. Our sales in the U.S. are sold through our arrangements with the operators of the fields, with substantially all of the sales being to Cohort Energy.

Derivative Instruments and Hedging Activities

From time to time, we may utilize derivative financial instruments to hedge cash flows from operations or to hedge the fair value of financial instruments. We may use derivative financial instruments with respect to a portion of our oil and gas production or a portion of our variable rate debt to achieve a more predictable cash flow by reducing our exposure to price fluctuations. These transactions are likely to be swaps, collars or options and to be entered into with major financial institutions or commodities trading institutions. Derivative financial instruments are intended to reduce our exposure to declines in the market prices of crude oil and natural gas that we produce and sell, to increases in interest rates and to manage cash flows in support of our annual capital expenditure budget. We also have embedded derivatives related to our debt instruments and convertible preferred stock.

We record all derivatives at fair market value in our Consolidated Balance Sheets at the end of each period. The accounting for the fair market value, and the changes from period to period, depends on the intended use of the derivative and the resulting designation. This evaluation is determined at each derivative’s inception and begins with the decision to account for the derivative as a hedge, if applicable. The accounting for changes in the fair value of a derivative instrument that is not accounted for as a hedge is included in other (income) expense as an

73

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

unrealized gain or loss. At December 31, 2009, we have no outstanding derivatives that are accounted for as a hedge.

Where we intend to account for a derivative as a hedge, we document, at its inception, the hedging relationship, the risk management objective and the strategy for undertaking the hedge. The documentation includes the identification of the hedging instrument, the hedged item or transaction, the nature of the risk being hedged, and the method that will be used to assess effectiveness of derivative instruments that receive hedge accounting treatment.

Changes in fair value to hedge instruments, to the extent the hedge is effective, are recognized in other comprehensive income until the forecasted transaction occurs. Hedge effectiveness is assessed at least quarterly based on total changes in the derivative’s fair value. Any ineffective portion of the derivative instrument’s change in fair value is recognized immediately in other (income) expense.

We discontinue hedge accounting prospectively when (1) we determine that the derivative is no longer effective in offsetting changes in the fair value or cash flows of a hedged item (including hedged items such as firm commitments or forecasted transactions); (2) the derivative expires; (3) it is no longer probable that the forecasted transaction will occur; (4) a hedged firm commitment no longer meets the definition of a firm commitment; or (5) management determines that designating the derivative as a hedging instrument is no longer appropriate.

Concentrations of Credit and Market Risk

Financial instruments that potentially subject us to concentrations of credit risk consist principally of cash deposits at financial institutions. At various times during the year, we may exceed the federally insured limits. To mitigate this risk, we place our cash deposits only with high credit quality institutions. Management believes the risk of loss is minimal.

Derivative financial instruments that hedge the price of oil and gas, interest rates or currency exposure will be generally executed with major financial or commodities trading institutions which expose us to market and credit risks, and may at times be concentrated with certain counterparties or groups of counterparties. Although notional amounts are used to express the volume of these contracts, the amounts potentially subject to credit risk, in the event of non-performance by the counterparties, are substantially smaller. We review the credit ratings of our counterparties to derivative contracts (who are all lenders under our senior bank facility) on a regular basis and to date we have not experienced any non-performance by any of our counterparties, currently BNP Paribas S.A. At December 31, 2009 our derivative instruments do not require either side to maintain collateral or margin accounts.

As an independent oil and gas producer, our revenue, profitability and future rate of growth are substantially dependent upon prevailing prices for oil and gas, which are dependent upon

74

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

numerous factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. The energy markets have historically been very volatile, and there can be no assurance that oil and gas prices will not be subject to wide fluctuations in the future. A substantial or extended decline in oil and gas prices could have a material adverse effect on our financial position, results of operations, cash flows and our access to capital and on the quantities of oil and gas reserves that may be economically produced.

Foreign Currency Translation

The U.S. dollar is the functional currency for all of our existing operations, as a majority of all revenue and financing transactions in these operations are denominated in U.S. dollars. For foreign operations with the U.S. dollar as the functional currency, monetary assets and liabilities are remeasured into U.S. dollars at the exchange rate on the balance sheet date. Nonmonetary assets and liabilities are translated into U.S. dollars at historical exchange rates. Income and expense items are translated at exchange rates prevailing during each period. Adjustments are recognized currently as a component of foreign currency gain or loss and deferred income taxes. To the extent that business transactions are not denominated in U.S. dollars, we are exposed to foreign currency exchange rate risk.

Income Taxes

We use the liability method of accounting for income taxes under which deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities, and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized as part of the provision for income taxes in the period that includes the enactment date. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion of, or all of, the deferred tax assets will not be realized.

Share-Based Payments

We recognize all share-based payments to employees, including grants of employee stock options, based on their fair values. The share-based compensation cost is measured at the grant date, based on the calculated fair value of the award, and is recognized as general and administrative expense over the employee’s requisite service period (generally the vesting period of the equity award). We apply the fair value method in accounting for stock option grants using the Black-Scholes Method.

75

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

It is our policy to use authorized but unissued shares of stock when stock options are exercised. At December 31, 2009, we had approximately 7.0 million additional shares available for issuance pursuant to our existing stock incentive plan.

Adoption of New Accounting Standards

On January 1, 2008, we adopted the following new standards without material effects on our results of operations or financial position:

• Fair value option — Guidance allowing entities to choose to measure many financial instruments and certain other items at fair value. This standard expanded the use of fair value measurement and applied to entities that elect the fair value option.

• Fair value measurement and disclosure — Framework for measuring fair value and expanded disclosures about such measurements. The new standards do not require new fair value measurements, rather, the provisions apply when fair value measurements are performed under other accounting pronouncements.

On January 1, 2009, we adopted the following new standards without material effects on our results of operations or financial position:

• Business combinations — Guidance related to the measurement of identifiable assets acquired, liabilities assumed and disclosure of information related to business combinations and their effect.

• Noncontrolling interests — Guidance for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. Specifically, this standard requires the recognition of a noncontrolling interest (minority interest) as a component of consolidated equity. Similarly, the new standard requires consolidated net income and comprehensive income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interests.

• Expanded disclosures of derivatives — Expanded and detailed financial statement disclosures for derivatives and hedged financial instruments. This standard applies to all derivatives and non-derivative instruments designated and qualifying as hedges, including bifurcated derivative instruments and related hedged items.

• Convertible debt — Guidance for convertible debt that may be settled in part or in whole in cash upon conversion requiring issuers of this form of debt to account for its debt and equity components separately. The new guidance also expands the definition of mandatorily redeemable convertible preferred shares that should be classified as liabilities.

• Share-based payments — Guidance for instruments that are granted in share-based payment transactions to treat unvested share-based payment awards with non-forfeitable rights to dividend or dividend equivalents as a separate class of securities in calculating earnings per share (“EPS”). The impact of the adoption of this standard on our weighted

76

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

average shares outstanding and EPS was not material, therefore, we have not restated prior periods.

• Fair value — Framework for measuring fair value and expanded disclosures about fair value measurements. New fair value measurements are not required; rather, the provisions apply when fair value measurements are performed under other accounting pronouncements.

On June 30, 2009, we adopted the following new standard that did not have a material effect on our results of operations or financial position:

• Subsequent Events — Standards of accounting for and disclosure of events that occur after the balance sheet date but before the financial statements are issued.

On December 31, 2009, we adopted the following new standard:

• Oil and gas modernization — Revised oil and gas reserve estimation and disclosure requirements. The accounting standards update revised the definition of proved oil and gas reserves to require that the average, first-day-of-the-month price during the 12-month period before the end of the year rather than the year-end price, must be used when estimating whether reserve quantities are economical to produce and when calculating the aggregate amount of (and changes in) future cash inflows related to the standardized measure of discounted future net cash flows.

Note 3 — Discontinued Operations

On May 14, 2009, we completed the divestiture of our Norwegian subsidiary, Endeavour Energy Norge AS, to Verbundnetz Gas AG for cash consideration of $150 million (the “Norway Sale”). We recognized a gain upon closing the Norway Sale of $47.0 million, after the allocation of $68 million of goodwill to the assets sold.

As a result of the Norway Sale, we have classified the results of operations and financial position of our Norwegian subsidiary as discontinued operations for all periods presented. The following table details selected financial data for the assets included in the Norway Sale:

77

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

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

78

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

	Year Ended December 31,
	2009			2008			2007
Sales	$	17,550		$	89,660		$	40,188
Income before Taxes	$	4,654		$	63,244		$	14,096
Income Tax Expense		(5,428	)		(32,613	)		(13,028	)
Income (Loss) from Operations		(774	)		30,631			1,068
Gain on sale		47,308			—			—
Net Income from Discontinued Operations	$	46,534		$	30,631		$	1,068

Note 4 — Prepaid Expenses and Other Current Assets

Prepaid expenses and other current assets consisted of the following:

	December 31,
	2009		2008
Fair market value of commodity derivatives — current	$	2,890	$	31,649
Prepaid insurance		1,506		1,322
Inventory		4,450		5,109
Other		1,272		4,114
	$	10,118	$	42,194

79

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

Note 5 — Property and Equipment

Property and equipment included the following:

	December 31,
	2009			2008
Oil and gas properties under the full cost method:
Subject to amortization	$	275,278		$	239,024
Not subject to amortization:
Acquired in 2009		51,797			—
Acquired in 2008		32,970			37,288
Acquired in 2007		10,235			14,746
Acquired prior to 2007		59,551			82,522
		429,831			373,580
Other oil and gas assets		—			4,875
Computers, furniture and fixtures		3,560			3,236
Total property and equipment		433,391			381,691
Accumulated depreciation, depletion and amortization		(166,804	)		(149,345	)
Net property and equipment	$	266,587		$	232,346

The majority of costs not subject to amortization relate to values assigned to unproved reserves acquired. The remainder of costs not subject to amortization relate to exploration costs such as drilling costs for projects awaiting approved development plans or the determination of whether or not proved reserves can be assigned and other seismic and geological and geophysical costs. These costs are transferred to the amortization base when it is determined whether or not proved reserves can be assigned to such properties. This analysis is dependent upon well performance, results of infield drilling, approval of development plans, drilling results and development of identified projects and periodic assessment of reserves. We expect acquisition costs excluded from amortization to be transferred to the amortization base over the next five years due to a combination of well performance and results of infield drilling relating to currently producing assets and the drilling and development of identified projects acquired, such as the Rochelle field. We expect exploration costs not subject to amortization to be transferred to the amortization base over the next three years as development plans are completed and production commences on existing discoveries including the Bacchus, Columbus, Cygnus and Rochelle projects.

The following is a summary of our oil and gas properties not subject to amortization as of December 31, 2009:

80

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

Costs Incurred in the Year Ended December 31,
	2009		2008		2007		Prior to 2007		Total
Acquisition costs	$	10,662	$	807	$	—	$	30,292	$	41,761
Exploration costs		38,158		28,528		9,260		29,261		105,207
Capitalized interest		2,977		3,635		975		—		7,587
Total oil and gas properties not subject to amortization	$	51,797	$	32,970	$	10,235	$	59,553	$	154,555

During 2009, 2008 and 2007, we capitalized $7.8 million, $8.0 million and $7.2 million, respectively, in certain directly related employee costs. During 2009, 2008 and 2007, we capitalized $3.1 million, $4.0 million and $6.4 million, respectively, in interest.

Note 6 — Goodwill

In connection with the several acquisitions, we recorded goodwill for the excess of the purchase price over the value assigned to individual assets acquired and liabilities assumed. With the 2009 settlement of a liability for a metering mis-measurement liability at a purchased field, the goodwill was reduced by $2.1 million. The following is a reconciliation of the changes in goodwill for the year ended December 31, 2009 and 2008:

	December 31,
	2009			2008
Balance at beginning of year	$	281,943		$	283,324
Allocation of goodwill to discontinued operations sold		(67,994	)		—
Adjustments		(2,063	)		(1,381	)
Balance at end of year	$	211,886		$	281,943

81

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

Note 7 — Other Assets

Other long-term assets consisted of the following at December 31:

	2009			2008
Intangible assets — workforce in place:
Gross	$	4,800		$	4,800
Accumulated amortization		(3,919	)		(3,363	)
		881			1,437
Debt issuance costs		3,875			5,714
Fair market value of long-term portion of commodity derivatives		318			1,702
Other		248			312
	$	5,322		$	9,165

Intangible assets represent the purchase price allocated to the assembled workforce as a result of an acquisition and is being amortized over its estimated life using the straight-line method. Estimated amortization expense is $0.6 million and $0.3 million in 2010 and 2011, respectively.

Debt issuance costs are amortized over the life of the related debt obligation.

Note 8 — Accrued Expenses

We had the following accrued expenses outstanding:

	December 31,
	2009		2008
Derivative liability	$	6,817	$	1,193
Foreign taxes payable		1,926		6,655
Deferred foreign taxes payable		—		15,825
Accrued interest		2,432		30
Preferred dividends		1,143		1,011
Accrued compensation		4,311		2,135
Crude oil imbalance		—		8,954
Other		1,169		839
	$	17,798	$	36,642

82

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

Note 9 — Debt Obligations

Our debt consisted of the following at the indicated dates:

	December 31,			December 31,
	2009			2008
Senior notes, 6% fixed rate, due 2012	$	81,250		$	81,250
Senior bank facility, variable rate, due 2011		49,942			113,000
Convertible bonds, 11.5%, due 2014		49,838			44,496
Subordinated notes, 12.5%, due 2014		50,122			—
		231,152			238,746
Less: debt discount		(7,767	)		(10,891	)
Less: current maturities		—			(13,000	)
Long-term debt	$	223,385		$	214,855
Standby letters of credit outstanding for abandonment liabilities	$	33,388		$	30,115

Principal maturities of debt at December 31, 2009 are as follows:

2010	$	—
2011		69,942
2012		91,250
2013		10,000
2014		59,960
Thereafter		—

The fair value of our debt obligations was $219 million and $191 million at December 31, 2009 and 2008, respectively. The fair values of long-term debt were determined based upon quotes obtained from banks for our senior notes, discounted cash flows for our 11.5% convertible debt and book value for other debt. Book value approximates fair value for our senior bank facility as this instrument bears interest at a market rate.

6% Senior notes, due 2012

During 2005, we issued in a private offering $81.25 million aggregate principal amount of convertible senior notes due 2012. The notes bear interest at a rate of 6.00% per annum, payable in January and July. The notes are convertible into shares of our common stock at an initial conversion rate of 199.2032 shares of common stock per $1,000 principal amount of notes,

83

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

subject to adjustment, which represents an initial conversion price of approximately $5.02 per share. In connection with the issuance of these notes, we paid $3.6 million in financing and other costs. Upon specified change of control events, each holder of those notes may require us to purchase all or a portion of the holder’s notes at a price equal to 100% of the principal amount, plus accrued and unpaid interest, if any, up to but excluding the date of purchase.

Senior bank facility

We have a $225 million senior bank facility, which is subject to a borrowing base limitation. The borrowing base is subject to redetermination every six months with an independent reserve report required every 12 months. At December 31, 2009, the borrowing base capacity was $50 million, which was fully drawn at year-end. The senior bank facility also provides for issuances of letters of credit of up to an aggregate $60 million. As of December 31, 2009, we have $33.4 million of outstanding letters of credit related to abandonment liabilities on certain of our oil and gas properties.

Indebtedness under the facility is secured by cross guarantees from all of our subsidiaries, share pledges from all of our subsidiaries and floating charges over the operating assets held in the United Kingdom. Our borrowings under the senior bank facility bear interest at LIBOR plus 1.3% for the first $46.1 million of availability, and LIBOR plus 1.7% for up to an additional $3.9 million of availability.

The senior bank facility contains customary covenants, which limit our ability to incur indebtedness, pledge our assets and dispose of our assets. In addition, the senior bank facility contains various financial and technical covenants, including:

• a maximum consolidated debt to earnings before interest, taxes, depreciation and amortization (“EBITDA”) ratio of 3.0:1;

• a minimum current assets to current liabilities ratio of 1.1:1;

• a minimum debt coverage ratio of 1.2:1 for the initial tranche and 1.15:1 for the second tranche;

• a minimum field life net present value (“NPV”) to loans outstanding coverage ratio of 1.5:1 for the initial tranche, and 1.3:1 for the second tranche; and

• a minimum loan life NPV to loans outstanding coverage ratio of 1.3:1 for the initial tranche, and 1.2:1 for the second tranche.

The final maturity is the earlier of January 31, 2011 or the reserve tail date, being the date when the remaining borrowing base reserves are projected to be 20% or less of the initially approved borrowing base reserves. The senior bank facility is subject to mandatory prepayment in the event of a change of control of any obligor under the senior bank facility agreement. It is prepayable at our option at any time without penalty.

84

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

The borrowing base is subject to redetermination every six months (on April 1 and October 1), and we are required to provide our lenders with an independent reserve report every 12 months. Based on our reserve report at December 31 and June 30 each year, commodity prices set by our lenders and terms set forth in the credit agreement, the maximum capacity of our borrowing base is set, and any amounts outstanding over the redetermined borrowing base must be repaid within 45 days of the redetermination date. The senior bank facility is also subject to maximum commitment levels by the participating lenders that change over time. We are currently undergoing the redetermination process based on our reserve report as of December 31, 2009, which will be effective as of April 1, 2010. We cannot estimate the level of the borrowing base capacity that will be in effect as of April 1, 2010.

Convertible Bonds

In January 2008, we issued 11.5% Convertible Bonds due 2014 (the “Convertible Bonds”) for gross proceeds of $40 million pursuant to a private offering to a sophisticated investor in Norway. The net proceeds from the issuance of the Convertible Bonds were used to repay a portion of our outstanding indebtedness. The Convertible Bonds bear interest at a rate of 11.5% per annum, compounded quarterly. Interest is compounded quarterly and added to the outstanding principal balance each quarter. The bonds are convertible into shares of our common stock at an initial conversion price of $2.36 per $1,000 of principal, which represents a conversion rate of approximately 424 shares of our common stock per $1,000 of principal. The conversion price will be adjusted in accordance with the terms of the bonds upon occurrence of certain events, including payment of common stock dividends, common stock splits or issuance of common stock at a price below the then current market price.

Upon the fourth anniversary of the issuance of the Convertible Bonds, the holders have the right to cause us to redeem the Convertible Bonds if the weighted average closing price of our common stock for the preceding 30 days is less than the conversion price, as adjusted. If the holders do not exercise this right, the right will lapse and the conversion price will be reset to the then current market price of our common stock if such price is lower than the conversion price, as adjusted.

If we undergo a “change of control” as defined, the holders of the bonds have the right, subject to certain conditions, to redeem the bonds and accrued interest. The bonds may become immediately due upon the occurrence of certain events of default, as defined.

Two derivatives are associated with the conversion and change in control features of the Convertible Bonds. At December 31, 2009, the combined fair market value of these derivatives is $26.9 million, reflecting a $12.3 million increase during 2009 that was recorded in unrealized gains (losses) on derivatives.

85

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

Subordinated Notes

On November 17, 2009, we entered into Stock Redemption Agreements with each of the holders of our outstanding shares of Series C convertible preferred stock (“Series C Preferred Stock”) whereby we redeemed 60% of the outstanding shares of Series C Preferred Stock, for face value of $75 million, and amended the terms of the remaining shares of Series C Preferred Stock. The redemption price consisted of a $25 million cash payment and the issuance of $50 million Subordinated Notes.

The Subordinated Notes bear interest at an annual rate of 10%, plus 2% capitalized to the outstanding principal amount. We will pay interest, in cash, on the unpaid principal amount of the Subordinated Notes quarterly on March 31, June 30, September 30 and December 31 of each year commencing on December 31, 2009. The Subordinated Notes are payable over four years commencing in March 2011, but may be prepaid at any time at face value. The Subordinated Notes are unsecured and subordinated to our outstanding obligations under our senior bank facility and rank on parity with our other existing debt obligations.

Note 10 — Other Liabilities

Other liabilities included the following:

	December 31,
	2009		2008
Asset retirement obligations	$	47,362	$	38,776
Long-term derivative liabilities		38,050		17,015
Total Other Liabilities	$	85,412	$	55,791

Our asset retirement obligations relate to obligation of the plugging and abandonment of oil and gas properties. The asset retirement obligation is recorded at fair value and accretion expense, recognized over the life of the property, increases the liability to its expected settlement value. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded for both the asset retirement obligation and the asset retirement cost. The following table provides a rollforward of the asset retirement obligations for the year ended December 31, 2009 and 2008:

86

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

	Year Ended
	December 31,
	2009			2008
Carrying amount of asset retirement obligations as of beginning of period	$	38,776		$	30,790
Increase (decrease) due to revised estimates of asset retirement obligations		7,762			13,840
Accretion expense		4,117			2,795
Impact of foreign currency exchange rate changes		4,280			(8,649	)
Payment of asset retirement obligation		(7,325	)		—
Sale of assets		(248	)		—
Carrying amount of asset retirement obligations as of end of period	$	47,362		$	38,776

Note 11 — Equity

The activity in shares of our common and preferred stock during 2009, 2008 and 2007 included the following:

87

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

	Year Ended December 31,
	2009			2008			2007
Common Stock:
Outstanding at the beginning of the year		128,572			127,006			118,577
Issuance of common stock to pay preferred dividends		—			—			6,403
Exercise of stock options		164			—			—
Issuance of stock based compensation		2,882			1,566			2,026
Outstanding at the end of the year		131,618			128,572			127,006
Series B Preferred Stock:
Outstanding at the end of the year		20			20			20
Convertible Preferred Stock:
Outstanding at the beginning of the year		125			125			—
Redemptions		(75	)
Issuance of preferred stock		—			—			125
Outstanding at the end of the year		50			125			125
Treasury Stock:
Outstanding at the beginning of the year		(327	)		—			—
Purchase of treasury shares for stock vesting		(171	)		(327	)		—
Outstanding at the end of the year		(498	)		(327	)		—

Common Stock

The Common Stock is $0.001 par value common stock, 300,000,000 shares authorized.

In 2008, we issued inducement grants of 300,000 shares of our restricted common stock, and options to purchase 250,000 shares of our common stock at an exercise price of $0.75 per share upon commencement of employment of one executive officer. In 2007, we issued inducement grants of 800,000 shares of our restricted common stock, options to purchase 400,000 shares of our common stock at an exercise price of $2.00 per share and options to purchase 200,000 shares of our common stock at an exercise price of $1.14 per share upon commencement of employment of two executive officers.

88

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

Convertible Preferred Stock

The Series C Preferred Stock ranks senior to any of our other existing or future shares of capital stock. Dividends are cumulative and payable in cash, or common stock if we are unable to pay such dividends in cash, and any dividends will be paid to the preferred stock investors prior to payment of any other dividend on any other shares of our capital stock. The Series C Preferred Stock also participates on an as-converted basis with respect to any dividends paid on the common stock.

We initially agreed to pay a cumulative dividend on the Series C Preferred Stock equal to 8.5% per annum of the original issue price (compounded quarterly) if paid in cash and 8.92% per annum of the original issue price (compounded quarterly) if paid in stock. On November 17, 2009, we redeemed 60% of the outstanding shares of Series C Preferred Stock, for face value of $75 million, and amended the terms of the remaining shares of Series C Preferred Stock. The redemption price consisted of a $25 million cash payment and the issuance of $50 million Subordinated Notes.

The redemption and modification of the Series C Preferred Stock required the modified Series C Preferred Stock to be recorded at fair market value at the redemption date. The fair value of the modified Series C Preferred Stock was greater than the carrying value by $11.5 million. This excess of fair value over carrying value was recorded as a non-cash charge to preferred stock dividends and increased the carrying value of the Series C Preferred Stock. As holders convert the Series C Preferred Stock, the $11.5 million non-cash charge will be transferred to equity on a ratio of shares converted to shares of Series C Preferred Stock outstanding.

In addition, the modification of the Series C Preferred Stock, we also recorded an embedded derivative are associated with the change in control features of the Series C Preferred Stock of $2.4 million. This embedded derivative was recorded in other liabilities and reduced the premium on the Series C Preferred Stock at the date of issuance. At December 31, 2009, the fair market value of this derivative was $1.9 million, reflecting a $0.5 million gain during 2009 that was recorded in unrealized gains (losses) on derivatives.

Prior to the November 2009 amendment, the Series C Preferred Stock was convertible into common stock at any time at the option of the preferred stock investors, at (i) a conversion price of $2.50 (the “Conversion Price”) and (ii) in an amount of common stock equal to the quotient of the liquidation preference of $1,000 per share plus accrued but unpaid dividends (the “Liquidation Preference”) divided by the Conversion Price.

In the November 2009 amendment, we amended terms of the Series C Preferred Stock to reduce the annual dividend rate to 4.5% (from 8.5%), adjust the conversion price to $1.25 per share (from $2.50) and remove certain anti-dilution provisions.

89

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

Issuance of dividends in the form of common stock are subject to the following equity conditions (the “Equity Conditions”), which are waivable by two-thirds of the holders of the Series C Preferred Stock: (i) such common stock is listed on the NYSE AMEX, the New York Stock Exchange or the Nasdaq Stock Market, and not subject to any trading suspension; (ii) we are not then subject to any bankruptcy event; and (iii) such common stock will be immediately re-saleable by the holders pursuant to an effective registration statement and otherwise in compliance with all applicable laws. If we have not maintained the effectiveness of the registration statement pursuant to the registration rights section below, then the dividend rate on the Series C Preferred Stock will be increased by the product of 2.5% (if the dividend is paid in cash) or 2.63% (if the dividend is paid in stock) times the number of quarters (or portions thereof) in which the failure occurs or we fail to cure such failure.

After the fourth anniversary of the initial issuance of the Series C Preferred Stock, we may redeem all of the Series C Preferred Stock in exchange for a cash payment to the preferred stock investors of an amount equal to 102% of the sum of the Liquidation Preference. If we call the Series C Preferred Stock for redemption, the holders thereof will have the right to convert their shares into a newly issued preferred stock identical in all respects to the Convertible Preferred Stock except that such newly issued preferred stock will not bear a dividend (the “Alternate Preferred Stock”). We may not redeem the Convertible Preferred Stock if the Equity Conditions are not then satisfied with respect to the common stock into which the Alternate Preferred Stock is convertible.

Upon the tenth anniversary of the initial issuance of the Convertible Preferred Stock, we must redeem all of the Convertible Preferred Stock for an amount equal to the Liquidation Preference plus accrued and unpaid dividends payable by us in cash or common stock at our election. Issuance by us of common stock for such redemption is subject to the Equity Conditions and to the market value of the outstanding shares of common stock immediately prior to such redemption equaling at least $500 million.

In the event of a change of control of Endeavour, we will be required to offer to redeem all of the Convertible Preferred Stock for the greater of: (i) the amount equal to which such holder would be entitled to receive had the holder converted such Convertible Preferred Stock into common stock; (ii) 115% of the sum of the Liquidation Preference plus accrued and unpaid dividends; and (iii) the amount resulting in an internal rate of return to such holder of 15% from the date of issuance of such Convertible Preferred Stock through the date that Endeavour pays the redemption price for such shares.

Series B Preferred Stock

In September 2002, we authorized and designated 500,000 shares of Preferred Stock, as Series B Preferred Stock par value $.001 per share.

90

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

The Series B Preferred Stock is to pay dividends of 8% of the original issuing price per share per annum, which are cumulative prior to any dividends on the common stock and on parity with the payment of any dividend or other distribution on any other series of preferred stock that has similar characteristics. The holders of each share of Series B Preferred Stock are entitled to be paid out of available funds prior to any distributions to holders of common stock in the amount of $100.00 per outstanding share plus all accrued dividends. We may, upon approval of our Board, redeem all or a portion of the outstanding shares of Series B preferred stock at a cost of the liquidation preference and all accrued and unpaid dividends.

Note 12 — Income Taxes

The loss before income taxes and the components of the income tax expense recognized on the Consolidated Statement of Income are as follows:

91

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

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

The following table presents the principal reasons for the difference between our effective tax rates and the United States federal statutory income tax rate of 35%.

92

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

	Year Ended December 31,
	2009			2008			2007
Federal income tax expense (benefit) at statutory rate	$	(33,141	)	$	17,491		$	(25,323	)
Taxation of foreign operations		1,572			12,464			(1,790	)
Change in valuation allowance — US		10,464			4,150			3,515
Foreign tax benefit from foreign currency tax law change		(5,400	)		—			—
Foreign currency (gain)/loss on deferred taxes		18,882			(10,028	)		1,327
Other		465			39			63
Income Tax Expense, continuing operations		(7,158	)		24,116			(22,208	)
Discontinued operations — Norway		5,429			32,613			13,207
Total Income Tax Expense	$	(1,729	)	$	56,729		$	(9,001	)
Effective Income Tax Rate		8	%		45	%		(32	)%

During 2009, 2008 and 2007, we incurred taxes in all of the jurisdictions that we do business in except for the U.S. In 2009, 2008 and 2007, we had a loss before taxes of $31.2 million, $8.3 million and $6.9 million, respectively, in the U.S. and we did not record any income tax benefits as there was no assurance that we could generate any U.S. taxable earnings, and therefore recorded a valuation allowance of the full amount of deferred tax asset generated.

Deferred income taxes result from the net tax effects of temporary timing differences between the carrying amounts of assets and liabilities reflected on the financial statements and the amounts recognized for income tax purposes. The tax effects of temporary differences that give rise to significant portions of deferred tax assets and liabilities are as follows at December 31:

93

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

	2009			2008
Deferred tax asset:
Deferred compensation	$	6,236		$	5,771
Unrealized loss on derivative instruments		16,560			4,506
Asset retirement obligation		7,026			5,244
Net operating loss and capital loss carryforward		34,635			21,633
Other		621			621
Total deferred tax assets		65,078			37,775
Less valuation allowance		(38,771	)		(23,701	)
Total deferred tax assets after valuation allowance		26,307			14,074
Deferred tax liability:
Property, plant and equipment		(97,111	)		(67,810	)
Unrealized gain on derivative instruments		—			(23,628	)
Petroleum revenue tax, net of tax benefit		(1,264	)		(1,642	)
Debt discount		(2,330	)		(3,267	)
Other		(6,294	)		(850	)
Total deferred tax liabilities		(106,999	)		(97,197	)
Net deferred tax liability	$	(80,692	)	$	(83,123	)

At December 31, 2009, we had the following carryforwards available to reduce future income taxes:

	Years of		Carryforward
Types of Carryforward	Expiration		Amounts
U.S. — Net operating loss		2022 – 2029	$	77,630
U.K. — Corporate tax net operating loss	Indefinite			24,570

With the exception of $77.6 million of net operating loss carryforward attributable to our U.S. operations for which a valuation allowance has been established, the remaining carryforward amounts shown above have been recognized for financial statement reporting purposes to reduce deferred tax liability.

Recognition of the benefits of the deferred tax assets will require that we generate future taxable income. There can be no assurance that we will generate any earnings or any specific level of earnings in future years. Therefore, we have established a valuation allowance for deferred tax assets of approximately $38.8 million, $23.7 million and $19.7 million as of December 31, 2009, 2008 and 2007, respectively. During 2009, the valuation allowance in the U.S. increased $10.5 million due to net operating losses and increased $4.6 million in other jurisdictions. During 2008, the valuation allowance in the U.S. increased $2.9 million due to net operating losses and

94

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

increased $1.1 million for net operating losses in other jurisdictions. During 2007, the valuation allowance in the U.S. increased $2.4 million due to net operating losses and adjustments.

For U.S. federal income tax purposes, certain limitations are imposed on an entity’s ability to utilize its NOLs in future periods if a change of control, as defined for federal income tax purposes, has taken place. In general terms, the limitation on utilization of NOLs and other tax attributes during any one year is determined by the value of an acquired entity at the date of the change of control multiplied by the then-existing long-term, tax-exempt interest rate. The manner of determining an acquired entity’s value has not yet been addressed by the Internal Revenue Service. We have determined that, for federal income tax purposes, a change of control occurred during 2004 and 2007, however, we do not believe such limitations will significantly impact our ability to utilize the NOL. The timing of NOL utilization will be determined by our future net income.

At December 2007, we provided for a liability of $1.7 million for unrecognized tax benefits relating to various U.K. matters. The statute of limitations for assessing tax for these benefits expired during 2008, thus allowing the full recognition of these benefits. The benefit was recorded as a reduction to goodwill.

As of December 31, 2009, we believe that no current tax positions that have resulted in unrecognized tax benefits will significantly increase or decrease within the next year.

As of December 31, 2009, we had unremitted earnings in our foreign subsidiaries. If these unremitted earnings had been dividend to the U.S., the U.S. NOL’s not subject to the limitations mentioned above would be fully available to offset any incremental U.S. federal income tax. Further, the foreign tax credits associated with the unremitted earnings would be sufficient to offset any incremental U.S. tax liabilities associated with the dividend.

Note 13 — Stock-Based Compensation Arrangements

We grant restricted stock and stock options to employees and directors as incentive compensation. The restricted stock and options generally vest over three years. The vesting of these shares and options is dependent upon the continued service of the grantees with Endeavour. Upon the occurrence of a change in control, each outstanding share of restricted stock and stock option will immediately vest.

Non-cash stock-based compensation is recorded in general and administrative (“G&A”) expenses or capitalized G&A as follows:

95

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

	Fourth Quarter				Year Ended
	December 31,				December 31,
	2009		2008		2009		2008
G & A Expenses	$	705	$	723	$	2,786	$	2,641
Capitalized G & A		227		299		573		901
Total non-cash stock-based compensation	$	932	$	1,022	$	3,359	$	3,542

Stock-Based Compensation Arrangements

We grant restricted stock and stock options, including notional restricted stock and options, to employees and directors as incentive compensation. The notional restricted stock and options may be settled in cash or stock upon vesting, at our option, however it has been our practice to settle in stock. The restricted stock and options generally vest over three years and the options have a five to ten year expiration. The vesting of these shares and options is dependent upon the continued service of the grantees to Endeavour. Upon the occurrence of a change in control, each share of restricted stock and stock option outstanding on the date on which the change in control occurs will immediately become vested.

The fair value of each option award is estimated on the date of grant using the Black-Scholes option-pricing model. For 2007, expected volatility is based on an average of our peer companies where there is a lack of relevant Endeavour volatility information for the length of the expected term and the expected term is the average of the vesting date and the expiration of the option. After 2007, expected volatility is based on historical Endeavour volatility for the length of the expected term, which was determined by historical data. We use historical data to estimate option exercises and employee terminations within the valuation model. The risk-free rate for periods within the contractual life of the option is based on the U.S. treasury yield curve in effect at the time of grant. We do not include an estimated dividend yield since we have not paid dividends on our common stock historically.

The following summarizes the weighted average of the assumptions used in the method:

	For the Year Ended December 31,
	2009			2008			2007
Risk-free rate		1.5	%		3.1	%		4.4	%
Expected years until exercise		4.25			4.00			4.00
Expected stock volatility		56	%		46	%		45	%
Dividend yield		—			—			—

96

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

At December 31, 2009, total compensation cost related to nonvested awards not yet recognized was approximately $2.3 million and is expected to be recognized over a weighted average period of less than two years. For the year ended December 31, 2009, we included approximately $0.6 million of stock-based compensation in capitalized G&A in property and equipment.

Stock Options

Information relating to stock options, including notional stock options, is summarized as follows:

				Weighted		Weighted
	Number of			Average		Average
	Shares			Exercise		Contractual		Aggregate
	Underlying			Price per		Life in		Intrinsic
	Options			Share		Years		Value
Balance outstanding January 1, 2009		4,807		$	2.35
Granted		1,181			0.54
Exercised		(164	)		0.81
Forfeited		(680	)		3.39
Expired		(932	)		2.09
Balance outstanding — December 31, 2009		4,212		$	1.87		6.2	$	665
Currently exercisable — December 31, 2009		2,124		$	2.79		4.1	$	42

The weighted average grant-date fair value of options granted during 2009, 2008 and 2007 was $0.25, $0.50 and $0.40, respectively.

Of options granted during 2009, 2008 and 2007, 1.2 million, 1.2 million and 0.1 million options, respectively, were granted pursuant to incentive plans which have been approved by our stockholders. All other stock options have been granted pursuant to stock option plans that were not subject to stockholder approval.

Information relating to stock options outstanding at December 31, 2009 is summarized as follows:

97

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

	Options Outstanding						Options Exercisable
			Weighted		Weighted				Weighted
			Average		Average				Average
	Number of		Remaining		Exercise				Exercise
Range of Exercise	Options		Contractual		Price Per		Number		Price Per
Prices	Outstanding		Life		Share		Exercisable		Share
Less than $1.00		1,329		9.00	$	0.58		123	$	0.74
$1.00 – $2.00		1,597		7.84		1.48		741		1.54
$2.00 – $3.00		265		3.88		2.44		238		2.48
$3.00 – $4.00		386		0.86		3.57		386		3.57
Greater than $4.00		635		0.79		4.28		635		4.28
Total		4,212		6.25	$	1.87		2,123	$	2.79

The weighted average grant-date fair value of options granted for the year ended December 31, 2009 was $0.25 per option.

Restricted Stock

At December 31, 2009, our employees and directors held 3,420,703 million restricted shares of our common stock that vest over the service period of up to three years. The restricted stock awards were valued based on the closing price of our common stock on the measurement date, typically the date of grant, and compensation expense is recorded on a straight-line basis over the restricted share vesting period.

Status of the restricted shares as of December 31, 2009 and the changes during the year ended December 31, 2009 are presented below:

98

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

				Weighted
				Average Grant
				Date Fair
	Number of			Value per
	Shares			Share
Balance outstanding — January 1, 2009		3,966		$	1.88
Granted		2,545			0.72
Vested		(2,917	)		1.92
Forfeited		(174	)		1.46
Balance outstanding — December 31, 2009		3,420		$	1.00
Total grant date fair value of shares vesting during the period	$	5,594

Note 14 — Earnings per Share

Basic income (loss) per common share is computed by dividing net income (loss) to common stockholders by the weighted average number of common shares outstanding for the period. Diluted income (loss) per share includes the effect of our outstanding stock options, warrants and shares issuable pursuant to convertible debt, convertible preferred stock and certain stock incentive plans under the treasury stock method, if including such instruments is dilutive.

	Year Ended December 31,
	2009			2008		2007
Net income (loss) to common shareholders
Basic	$	(62,206	)	$	45,681	$	(60,315	)
Add Effect of:
Preferred dividends		—			10,625		—
Diluted	$	(62,206	)	$	56,306	$	(60,315	)
Weighted Average Number of Common Shares Outstanding:
Basic		130,291			128,312		123,118
Add Effect of:
Preferred stock		—			50,000		—
Diluted		130,291			178,312		123,118

For each of the periods presented, shares associated with stock options, warrants, convertible debt, convertible preferred stock and certain stock incentive plans are not included because their inclusion would be antidilutive (i.e., reduce the net loss per share). The common shares potentially issuable arising from these instruments, which were outstanding during the periods presented in the financial statements, consisted of:

99

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

	December 31,
	2009		2008		2007
Options and stock-based compensation		1,910		2		—
Convertible debt		37,303		32,725		16,185
Convertible preferred stock		40,000		—		50,000
Common shares potentially issuable		79,213		32,727		66,185

Note 15 — Comprehensive Income (Loss)

The following summarizes the components of comprehensive loss:

	Year Ended December 31,
	2009			2008			2007
Net income (loss)	$	(40,995	)	$	56,490		$	(49,077	)
Related to derivative instruments:
Unrealized gain (loss)		—			428			(852	)
Reclassification adjustment for gain (loss) realized in net income (loss) above		1,194			(770	)		—
Related to marketable securities:
Unrealized loss		—			(1	)		(71	)
Reclassification adjustment for loss realized in net income (loss) above		72			—			—
Net impact on comprehensive income (loss)		1,266			(343	)		(923	)
Comprehensive income (loss)	$	(39,729	)	$	56,147		$	(50,000	)

The components of accumulated other comprehensive income (loss) are:

100

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

	Year Ended December 31,
	2009			2008			2007
Related to derivative instruments:
Balance at beginning of year	$	(1,194	)	$	(852	)	$	—
Change during the year		1,194			(342	)		(852	)
Balance at end of year		—			(1,194	)		(852	)
Related to marketable securities:
Balance at beginning of year		(72	)		(71	)		—
Change during the year		72			(1	)		(71	)
Balance at end of year		—			(72	)		(71	)
Accumulated other comprehensive loss	$	—		$	(1,266	)	$	(923	)

Note 16 — Financial Instruments

	December 31, 2009						December 31, 2008
	Fair			Carrying						Carrying
	Value			Value			Fair Value			Value
Assets:
Derivative instruments	$	3,208		$	3,208		$	33,351		$	33,351
Liabilities:
Long-term debt		219,959			223,385			190,681			214,855
Derivative instruments		(44,866	)		(44,866	)		(18,208	)		(18,208	)

The carrying amounts reflected in the consolidated balance sheets for cash and equivalents, short-term receivables and short-term payables approximate their fair value due to the short maturity of the instruments. The fair values of commodity derivative instruments interest rate swaps and were determined based upon quotes obtained from brokers. The fair values of long-term debt were determined based upon quotes obtained from brokers for our senior notes, discounted cash flows for our 11.5% convertible debt and book value for other debt. Book value approximates fair value for our senior bank facility and second lien term loan as these instruments bear interest at a market rate.

101

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

Note 17 — Fair Value Measurements

Effective January 1, 2008, we adopted the new guidance for fair value measurements of financial assets and liabilities measured on a recurring basis. This new standard defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. It also clarifies that fair value should be based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. This includes not only the credit standing of counterparties involved and the impact of credit enhancements but also the impact of our own nonperformance risk on our liabilities. According to this new standard, fair value measurements are classified and disclosed in one of the following categories:

Level 1:	Fair value is based on actively-quoted market prices, if available.
Level 2:	In the absence of actively-quoted market prices, we seek price information from external sources, including broker quotes and industry publications. Substantially all of these inputs are observable in the marketplace during the entire term of the instrument, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace.
Level 3:	If valuations require inputs that are both significant to the fair value measurement and less observable from objective sources, we must estimate prices based on available historical and near-term future price information and certain statistical methods that reflect our market assumptions.

We apply fair value measurements to certain assets and liabilities including commodity and interest rate derivative instruments, marketable securities and embedded derivatives relating to conversion and change in control features in certain of our debt instruments. We seek to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The following table summarizes the valuation of our investments and financial instruments by pricing levels as of December 31, 2009:

102

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

	Quoted Market Prices		Significant Other			Significant
	in Active Markets -		Observable Inputs -			Unobservable Inputs -			Total
	Level 1		Level 2			Level 3			Fair Value
Oil and gas derivative contracts:
Oil and gas swaps	$	—	$	(12,816	)	$	—		$	(12,816	)
Embedded derivatives		—		—			(28,843	)		(28,843	)
Total derivative liabilities	$	—	$	(12,816	)	$	(28,843	)	$	(41,659	)

Our commodity and interest rate derivative contracts were measured based on quotes from our counterparties, which are major financial institutions or commodities trading institutions. Such quotes have been derived using models that consider various inputs including current market and contractual prices for the underlying instruments, quoted forward prices for natural gas and crude oil, volatility factors and interest rates, such as a LIBOR curve for a similar length of time as the derivative contract term. The inputs for the fair value models for our swaps and Brent oil collars were all observable market data and these instruments have been classified as Level 2. Although we utilized the same option pricing models to assess the reasonableness of the fair values of our gas collars, an active futures market does not exist for our U.K. gas options. We based the inputs to the option models for our U.K. gas collars on observable market data in other markets to verify the reasonableness of the counterparty quotes. These U.K. gas collars are classified as Level 3. There are no outstanding oil or gas collars at December 31, 2009.

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

	Year Ended
	December 31,
	2009
Balance at beginning of period	$	(12,057	)
Total gains or losses (realized/unrealized)
Included in earnings		(14,390	)
Purchases, issuance and settlements		(2,396	)
Balance at end of period	$	(28,843	)
Changes in unrealized gains (losses) relating to derivatives assets and liabilities still held at December 31, 2009	$	(9,713	)

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are reported at fair value on a nonrecurring basis in our consolidated balance sheets. The following methods and assumptions were used to estimate the fair values:

103

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

Goodwill — Goodwill is tested annually at year end for impairment. The first step of that process is to compare the fair value of the reporting unit to which goodwill has been assigned to the carrying amount of the associated net assets and goodwill. Significant Level 3 inputs may be used in the determination of the fair value of the reporting unit, including present values of expected cash flows from operations.

When we are required to measure fair value, and there is not a market observable price for the asset or liability, or a market observable price for a similar asset or liability, we generally utilize an income valuation approach. This approach utilizes management’s best assumptions regarding expectations of projected cash flows, and discounts the expected cash flows using a commensurate risk adjusted discount rate. Such evaluations involve a significant amount of judgment since the results are based on expected future events or conditions, such as sales prices; estimates of future oil and gas production; development and operating costs and the timing thereof; economic and regulatory climates and other factors. Our estimates of future net cash flows are inherently imprecise because they reflect management’s expectation of future conditions that are often outside of management’s control. However, assumptions used reflect a market participant’s view of long-term prices, costs and other factors, and are consistent with assumptions used in our business plans and investment decisions.

Note 18 — Derivative Instruments

As discussed in Note 2 — Accounting Policies, we have oil and gas commodity derivatives, interest rate derivatives and embedded derivatives related to debt instruments. The fair market value of these derivative instruments is included in our balance sheet as follows:

104

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

	December 31,			December 31,
	2009			2008
Derivatives not designated as hedges:
Oil and gas commodity derivatives:
Assets:
Prepaid expenses and other current assets	$	2,890		$	31,649
Other assets — long term		318			1,702
Liabilities:
Accrued expenses and other		(6,817	)		—
Other liabilities — long-term		(9,207	)		(2,375	)
	$	(12,816	)	$	30,976
Embedded derivatives related to debt instrument:
Liabilities:
Other liabilities — long-term		(28,843	)		(14,640	)
Derivatives designated as cash flow hedge:
Interest rate swap
Liabilities:
Accrued expenses and other		—			(1,334	)

If all counterparties failed to perform, our maximum loss would be $3.2 million as of December 31, 2009.

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

	Year Ended December 31,
	2009			2008			2007
Derivatives not designated as hedges:
Oil and gas commodity derivatives
Realized gains (losses)	$	35,422		$	(28,578	)	$	12,048
Unrealized gains (losses)		(43,791	)		77,846			(89,132	)
		(8,369	)		49,268			(77,084	)
Embedded derivatives related to debt instrument
Unrealized gains (losses)	$	(11,807	)	$	(1,180	)	$	—

The effect of derivatives designated as cash flow hedges on our results of operations and other comprehensive income was as follows:

105

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

		Year Ended December 31,
	Location of
	Reclassification
	into Income	2009		2008			2007
Interest rate swap
(Gain) loss recognized in other comprehensive income, net of tax		$	—	$	428		$	(852	)
(Gain) loss reclassified from accumulated other comprehensive income into income	Interest expense		1,194		(770	)		—

We did not exclude any component of the hedging instruments’ gain or loss when assessing effectiveness. The ineffective portion of the hedges is not material for the periods presented and is included in other income (expense).

As of December 31, 2009, our outstanding commodity derivatives covered approximately 1,020 Mbbl of oil and 1,659 MMcf of gas cumulative through 2011 and consist of fixed price swaps with BNP Paribas.

During 2007, we entered into an interest rate swap with BNP Paribas for a notional amount of $37.5 million whereby we paid a fixed rate of 5.05% and received three-month LIBOR through November 2009.

Note 19 — Supplementary Cash Flow Disclosures

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

	Year Ended December 31,
	2009		2008		2007
Interest paid	$	7,074	$	15,966	$	22,164
Income taxes paid	$	4,738	$	20,088	$	7,662

Non-Cash Investing and Financing Transactions

As discussed in Note 9, we redeemed 60% of the outstanding shares of Series C Preferred Stock, for face value of $75 million with a $25 million cash payment and the issuance of $50 million Subordinated Notes.

106

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

We recorded $11.4 million in preferred stock dividends in 2009 for a non-cash valuation under fair value accounting relating to the redemption and modification of our Series C Preferred Stock. Prior to the fourth quarter of 2007, we paid outstanding dividends on the Series C Preferred Stock through the issuance of common stock.

In 2009 and 2008, we recorded $5.3 million and $4.5 million, respectively, in non-cash interest expense that was added to the principal balance of the 11.5% convertible notes.

Note 20 — Commitments and Contingencies

General

The oil and gas industry is subject to regulation by federal, state and local authorities. In particular, oil and gas production operations and economics are affected by environmental protection statutes, tax statutes and other laws and regulations relating to the petroleum industry. We believe we are in compliance with all federal, state and local laws, regulations applicable to Endeavour and its properties and operations, the violation of which would have a material adverse effect on us or our financial condition.

Operating Leases

We have leases for office space and equipment with lease payments of $0.6 million, $0.2 million and $0.2 million for the years ended December 31, 2010, 2011 and 2012, respectively.

Rig Commitments

Our rig commitments represent one commitment for 46 days of a rig in the U.K. We are currently considering the timing of rig deliverability and completion of the commitment.

Participation Agreement

In April 2009, we executed an agreement with Caza Petroleum Inc., a subsidiary of Caza Oil and Gas, Inc., (“Caza”) to participate in a jointly established exploration and development program covering Caza’s onshore acreage position and opportunity portfolio in the United States. We have the option but not the obligation to participate in the acquisition, exploration and appraisal activities of selected assets. Caza provides economic and engineering analysis on projects submitted for our selection. We receive 75% of Caza’s interest in exchange for $250,000 per

107

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

month and payment of our share of all external costs on any projects we select. We have elected to terminate the agreement effective April 2010.

Contingencies

Hess Limited, the operator of the facility supporting production from the Ivanhoe, Rob Roy, and Hamish fields (collectively, “IVRRH”), had advised us that there had been a mis-measurement of the volumes of oil produced from the IVRRH fields. As of December 31, 2009, the estimated liability from this mis-measurement was extinguished. As the settlement of the mis-measurement liability is covered under the purchase agreement for these assets, the decrease in our net liability was recorded as a decrease to goodwill during the third quarter of 2009.

Note 21 — Segment and Geographic Information

We have determined we have one reportable operating segment being the acquisition, exploration and development of oil and gas properties. Our operations are conducted in geographic areas as follows:

	2009				2008				2007
			Long-				Long				Long
			lived				lived				lived
	Revenue		Assets		Revenue		Assets		Revenue		Assets
United States	$	1,627	$	46,172	$	—	$	12,125	$	—	$	6,920
United Kingdom		60,666		436,016		170,782		441,195		135,876		488,377
Other		—		1,607		—		2,140		—		4,386
Continuing Operations		62,293		483,795		170,782		455,460		135,876		499,683
Discontinued operations — Norway		17,550		—		89,660		148,605		40,188		129,693
Total	$	79,843	$	483,795	$	260,442	$	604,065	$	176,064	$	629,376
Total International	$	78,216	$	437,623	$	260,442	$	583,943	$	176,064	$	622,456

108

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

Note 22 — Quarterly Financial Data (Unaudited)

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

109

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

Note 23 — Subsequent Events

Asset Acquisitions

On January 6, 2010, we acquired significant positions in several U.S. resource plays. We funded the initial cash contributions for these new joint ventures from existing cash reserves.

We entered into a participation agreement with Cohort Energy Company (a subsidiary of J-W Operating Company) and acquired 50 percent of Cohort’s interests in certain acreage in North Louisiana/East Texas and Western Pennsylvania, primarily in the Haynesville and Marcellus gas shale plays. Our initial investment is $15 million cash and we will pay a share of Cohort’s drilling and completion expenditures as wells are drilled over the next few years.

We also acquired 50 percent of Hillwood Energy Alabama LP’s position in Hillwood’s unproven, but highly prospective new multi-target gas shale play in Alabama with an initial net investment of approximately $8.0 million.

Series C Convertible Preferred Stock

On January 29, 2010, we and the holders of our outstanding Series C Convertible Preferred Stock corrected a technical oversight in the Subscription and Registration Rights Agreement of our Series C Convertible Preferred Stock. The amendment aligns the number of common shares reserved for the potential conversion of the Series C Convertible Preferred Stock to the terms of the Series C Convertible Preferred Stock after our partial redemption in November 2009. On March 10, 2010, we also amended in the Certificate of Designation for the Series C Convertible Preferred Stock and the $50 million Note issued to the holders of the Series C Convertible Preferred Stock for technical changes. These technical changes align certain definitions and provisions relating to potential repurchases of securities by Endeavour.

In February and March 2010, a combined 2,100 shares of our Series C Convertible Preferred Stock were converted into 1.8 million shares of our common stock.

Common Stock Issuance

On February 4, 2010, we entered into and closed a private placement of common stock pursuant to a Common Stock Purchase Agreement primarily with existing stockholders and certain directors and with certain other third-party investors to sell 23.5 million shares of our common stock, par value $0.001 per share, for aggregate net cash consideration of approximately $20.5 million. The purchase price per Share was $0.90, the closing price of our shares on the NYSE Amex on February 3, 2010. We intend to use the net proceeds from the Private Placement to partially fund our 2010 capital budget.

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

The Private Placement was made in reliance upon an exemption from the registration requirements of the Securities Act of 1933, pursuant to Section 4(2) thereof.

Junior Facility

On February 5, 2010, we announced the closing of a $25 million lending facility between us, our subsidiaries and Bank of Scotland PLC (the “Junior Facility”), with a maturity date of February 5, 2011, and interest at LIBOR plus 8%. Upon entering the Junior Facility, we borrowed $15 million against the facility. Our indebtedness under the Junior Facility remains secured by cross guarantees from our subsidiaries and a second ranking interest in the security package provided under our senior bank facility. Outstanding amounts under the Junior Facility may be prepaid.

The Junior Facility contains customary covenants, similar to those in our senior bank facility, which limit our ability to incur indebtedness, create certain liens; dispose of our assets and, make dividend payments or other distributions with respect to equity securities. The Junior Facility also includes mandatory prepayment terms for the amount of net proceeds received upon a capital raise of more than $50 million or the sale of an asset. The Junior Facility also contains a covenant to maintain a minimum fair market value of proved plus probable reserves to consolidated secured debt ratio of 2:1.

Senior Bank Facility

On February 5, 2010, we also amended our senior bank facility. Previously, the final maturity date of the Senior Bank Facility was the earlier of October 31, 2011 or the reserve tail date, being the date when the remaining borrowing base reserves are projected to be 20% or less of the initially approved borrowing base reserves. The amendment brings the maturity date of the senior bank facility into alignment with the originally expected reserve tail date and maturity of the Junior Facility by changing the final maturity date to the earlier of January 31, 2011 or the reserve tail date.

2011 Debt Maturities

With the Junior Facility and Senior Bank Facility, we will have $65 million in debt due in the first quarter of 2011, based on outstanding balances at February 28, 2010. We plan to utilize our existing U.K. oil and gas assets, as well as our growing U.S. reserve base, as a basis for refinancing and expansion of our credit facilities. We are currently in discussions with several parties concerning this process. We strive to synchronize our capital expenditures with our cash flow. However, we believe our existing U.K. reserves, including probable reserves, are of significant value and together with our U.S. assets can be used as support for increased financial resources when necessary to fund our on-going activities. We continually monitor the capital markets to evaluate the most appropriate actions in our capital market activities.

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Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)

Strategic Alternatives for North Sea Assets

On March 15, 2010, we announced that our board of directors has approved a review of strategic alternatives for its North Sea assets. In an effort to unlock the value of our underlying North Sea assets, we will study a full range of options, including:

• Continuing to execute current operations plan;

• Entering into a joint venture to accelerate activities in the North Sea; and

• Selling specific assets or the North Sea entire business.

We will announce the results of the effort once a course of action is chosen. At the end of this review process, we may elect to make no changes.

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Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)

Note 24 — Supplemental Oil and Gas Disclosures (Unaudited)

Capitalized Costs Relating to Oil and Gas Producing Activities

									Total			Discontinued
	United			United					Continuing			Operations
	Kingdom			States			Other		Operations			Norway (1)			Total
December 31, 2009:
Proved	$	266,893		$	8,385		$	—	$	275,278		$	—		$	275,278
Unproved		125,996			26,817			1,740		154,553			—			154,553
Total capitalized costs		392,889			35,202			1,740		429,831			—			429,831
Accumulated depreciation, depletion and amortization		(164,703	)		(810	)		—		(165,513	)		—			(165,513	)
Net capitalized costs	$	228,186		$	34,392		$	1,740	$	264,318		$	—		$	264,318
December 31, 2008:
Proved	$	232,730		$	629		$	9	$	233,368		$	65,522		$	298,890
Unproved		131,688			5,876			2,132		139,696			48,714			188,410
Total capitalized costs		364,418			6,505			2,141		373,064			114,236			487,300
Accumulated depreciation, depletion and amortization		(142,686	)		—			—		(142,686	)		(33,914	)		(176,600	)
Net capitalized costs	$	221,732		$	6,505		$	2,141	$	230,378		$	80,322		$	310,700

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Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities

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

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

Results of Operations for Oil and Gas Producing Activities

							Total			Discontinued
	United			United			Continuing			Operations -
	Kingdom			States			Operations			Norway (1)		Total
Year Ended December 31, 2009:
Revenues	$	60,666		$	1,627		$	62,293		$	17,550	$	79,843
Production expenses		16,911			865			17,776			5,536		23,312
DD&A		31,915			817			32,732			4,595		37,327
Impairment of oil and gas properties		31,332			12,597			43,929			—		43,929
Income tax expense		(9,746	)		(4,428	)		(14,174	)		5,787		(8,387	)
Results of activities	$	(9,746	)	$	(8,224	)	$	(17,970	)	$	1,632	$	(16,338	)
Year Ended December 31, 2008:
Revenues	$	170,781		$	—		$	170,781		$	89,660	$	260,441
Production expenses		31,489			828			32,317			14,259		46,576
DD&A		65,764			—			65,764			14,078		79,842
Impairment of oil and gas properties		36,970			—			36,970			—		36,970
Income tax expense		18,279			(290	)		17,989			47,832		65,821
Results of activities	$	18,279		$	(538	)	$	17,741		$	13,491	$	31,232
Year Ended December 31, 2007:
Revenues	$	135,876		$	—		$	135,876		$	40,188	$	176,064
Production expenses		27,263			—			27,263			13,781		41,044
DD&A		67,338			—			67,338			7,722		75,060
Income tax expense		20,638			—			20,638			14,574		35,212
Results of activities	$	20,637			—		$	20,637		$	4,111	$	24,748

⁽¹⁾ We completed the divestiture of our Norwegian subsidiary on May 14, 2009. The results of operations and financial position of this subsidiary are classified as discontinued operations for all periods presented.

Oil and Gas Reserves

Proved reserves are estimated quantities of oil, gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from

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

known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can reasonably be expected to be recovered through existing wells with existing equipment and operating methods. The reserve volumes presented are estimates only and should not be construed as being exact quantities. These reserves may or may not be recovered and may increase or decrease as a result of our future operations and changes in economic conditions. During 2009, our oil and gas reserves were audited by independent reserve engineers. Our oil and gas reserves were prepared by independent reserve engineers at December 31, 2008 and 2007.

In the fourth quarter of 2009, we adopted revised oil and gas reserve estimation and disclosure requirements. The primary impact of the new disclosures is to conform the definition of proved reserves to the SEC Modernization of Oil and Gas Reporting rules, which were issued by the SEC at the end of 2008. The accounting standards update revised the definition of proved oil and gas reserves to require that the average, first-day-of-the-month price during the 12-month period before the end of the year rather than the year-end price, must be used when estimating whether reserve quantities are economical to produce. This same 12-month average price is also used in calculating the aggregate amount of (and changes in) future cash inflows related to the standardized measure of discounted future net cash flows. The rules also allow for the use of reliable technology to estimate proved oil and gas reserves if those technologies have been demonstrated to result in reliable conclusions about reserve volumes. The unaudited supplemental information on oil and gas exploration and production activities for 2009 has been presented in accordance with the new reserve estimation and disclosure rules, which may not be applied retrospectively. The 2008, 2007 and 2006 data are presented in accordance with FASB oil and gas disclosure requirements effective during those periods.

116

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

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

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

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

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Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)

							Total			Discontinued
	United			United			Continuing			Operations -
	Kingdom			States			Operations			Norway			Total
Proved Reserves (MBOE):
Proved reserves at January 1, 2007		7,428			—			7,428			2,465			9,893
Extensions and discoveries		—			—			—			643			643
Production		(2,700	)		—			(2,700	)		(574	)		(3,274	)
Revisions of previous estimates		524			—			524			927			1,451
Proved reserves at December 31, 2007		5,252			—			5,252			3,461			8,713
Production		(2,121	)		—			(2,121	)		(1,113	)		(3,234	)
Extensions and discoveries		3,917			133			4,050			130			4,180
Revisions of previous estimates		(395	)		—			(395	)		(242	)		(637	)
Proved reserves at December 31, 2008		6,653			133			6,786			2,236			9,022
Production		(1,314	)		(57	)		(1,371	)		(424	)		(1,795	)
Extensions and discoveries		10,025			4			10,029			—			10,029
Purchae of Reserves		—			1,675			1,675			—			1,675
Sales of Reserves		—			—			—			(1,815	)		(1,815	)
Revisions of previous estimates		1,037			60			1,097			3			1,100
Proved reserves at December 31, 2009		16,401			1,815			18,216			—			18,216
Proved Developed Reserves (MBOE):
At December 31, 2007		3,947			—			3,947			2,752			6,699
At December 31, 2008		2,595			46			2,641			2,122			4,763
At December 31, 2009		2,103			792			2,895			—			2,895

Standardized Measure of Discounted Future Net Cash Flows

Future cash inflows and future production and development costs are determined by applying year-end prices and costs to the estimated quantities of oil and gas to be produced. Estimated future income taxes are computed using current statutory income tax rates for where production occurs. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor.

Estimates of future cash inflows are based on prices at year-end. Oil, gas and condensate prices are escalated only for fixed and determinable amounts under provisions in some contracts. At December 31, 2009 and 2008, the prices used to determine the estimates of future cash inflows were $60.40 and $36.55 per barrel, respectively, for oil and $4.96 and $8.70 per Mcf, respectively, for gas. Estimated future cash inflows are reduced by estimated future

119

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

development, production, abandonment and dismantlement costs based on year-end cost levels, assuming continuation of existing economic conditions, and by estimated future income tax expense. Income tax expense, both U.S. and foreign, is calculated by applying the existing statutory tax rates, including any known future changes, to the pretax net cash flows giving effect to any permanent differences and reduced by the applicable tax basis. The effect of tax credits is considered in determining the income tax expense.

The standardized measure of discounted future net cash flows is not intended to present the fair market value of our oil and gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves in excess of proved reserves, anticipated future changes in prices and costs, an allowance for return on investment and the risks inherent in reserve estimates.

Under the full cost method of accounting, a noncash charge to earnings related to the carrying value of our oil and gas properties on a country-by-country basis may be required when prices are low. Whether we will be required to take such a charge depends on the prices for crude oil and natural gas at the end of any quarter, as well as the effect of both capital expenditures and changes to proved reserves during that quarter. Given the volatility of natural gas and oil prices, it is reasonably possible that our estimate of discounted future net cash flows from proved oil and gas reserves will change in the near term. If a noncash charge were required, it would reduce earnings for the period and result in lower DD&A expense in future periods.

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

Standardized Measure of Discounted Future Net Cash Flows

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

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

Principal Sources of Change in the Standardized Measure
of Discounted Future Net Cash Flows

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

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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

None.

Item 9A. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our chief executive officer, chief financial officer and chief accounting officer, we evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this Annual Report on Form 10-K, December 31, 2009. Based on that evaluation, our chief executive officer, chief financial officer and chief accounting officer concluded that our disclosure controls and procedures are effective to ensure that information we are required to disclose in our reports filed or submitted under the Securities Exchange Act of 1934, as amended, is accumulated and communicated to management as appropriate to allow timely decisions regarding required disclosures.

Management’s Report on Internal Control Over Financial Reporting

Management of the Company is responsible for establishing and maintaining adequate internal controls over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended. Our internal controls were designed to provide reasonable assurance as to the reliability of our financial reporting and the preparation and presentation of the consolidated financial statements for external purposes in accordance with accounting principles generally accepted in the United States.

Because of its inherent limitations, internal control over financial reporting may not detect or prevent misstatements. Projections of any evaluation of the effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2009. In making this assessment, our management used the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our assessment, our internal control over financial reporting was effective as of December 31, 2009.

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KPMG LLP, an independent registered public accounting firm, audited management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2009 and issued their attestation report set forth in this Item 9A.

Changes in Internal Control over Financial Reporting

There were no changes in our internal controls over financial reporting during the quarterly period ended December 31, 2009 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders
Endeavour International Corporation:

We have audited Endeavour International Corporation’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Endeavour International Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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Endeavour International Corporation

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Endeavour International Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Endeavour International Corporation and subsidiaries as of December 31, 2009 and 2008, and the related consolidated statements of operations, stockholders’ equity and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2009, and our report dated March 16, 2010 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Houston, Texas
March 16, 2010

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Endeavour International Corporation

Item 9B. Other Information

On March 10, 2010, we amended the Certificate of Designation for the Series C Convertible Preferred Stock and the $50 million Note issued to the holders of the Series C Convertible Preferred Stock to correct technical oversights. The technical changes align certain definitions and provisions relating to potential repurchases of securities by Endeavour.

Item 10. Directors, Executive Officers and Corporate Governance of the Registrant

Our Definitive Proxy Statement for our 2010 Annual Meeting of Stockholders, when filed pursuant to Regulation 14A under the Securities Exchange Act of 1934, will be incorporated by reference into this annual report on Form 10-K pursuant to General Instruction G(3) of Form 10-K and will provide the information required under Part III, Item 10.

Our Code of Business Conduct and the Code of Ethics for Senior Officers can be found on our internet located at www.endeavourcorp.com. Any stockholder may request a printed copy of these codes by submitting a written request to our Corporate Secretary.

Item 11. Executive Compensation

Our Definitive Proxy Statement for our 2010 Annual Meeting of Stockholders, when filed pursuant to Regulation 14A under the Securities Exchange Act of 1934, will be incorporated by reference into this annual report on Form 10-K pursuant to General Instruction G(3) of Form 10-K and will provide the information required under Part III, Item 11.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholders Matters

Our Definitive Proxy Statement for our 2010 Annual Meeting of Stockholders, when filed pursuant to Regulation 14A under the Securities Exchange Act of 1934, will be incorporated by reference into this annual report on Form 10-K pursuant to General Instruction G(3) of Form 10-K and will provide the information required under Part III, Item 12.

Item 13. Certain Relationships and Related Transactions, and Director Independence

Our Definitive Proxy Statement for our 2010 Annual Meeting of Stockholders, when filed pursuant to Regulation 14A under the Securities Exchange Act of 1934, will be incorporated by

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Endeavour International Corporation

reference into this annual report on Form 10-K pursuant to General Instruction G(3) of Form 10-K and will provide the information required under Part III, Item 13.

Item 14. Principal Accounting Fees and Services

Our Definitive Proxy Statement for our 2010 Annual Meeting of Stockholders, when filed pursuant to Regulation 14A under the 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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Endeavour International Corporation

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 16, 2010

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 16, 2010
/s/ J. Michael Kirksey J. Michael Kirksey	Chief Financial Officer (Principal Financial Officer)	March 16, 2010
/s/ Robert L. Thompson Robert L. Thompson	Chief Accounting Officer (Principal Accounting Officer)	March 16, 2010
/s/ Thomas D. Clark Thomas D. Clark	Director	March 16, 2010
/s/ John B. Connally III John B. Connally III	Director	March 16, 2010
/s/ Sheldon R. Erikson Sheldon Erikson	Director	March 16, 2010
/s/ Charles Hue Williams Charles Hue Williams	Director	March 16, 2010
/s/ Leiv R. Nergaard Leiv L. Nergaard	Director	March 16, 2010
/s/ Nancy K. Quinn Nancy K. Quinn	Director	March 16, 2010
/s/ John N. Seitz John N. Seitz	Director	March 16, 2010

128

Endeavour International Corporation

Exhibit Index

Exhibit	Description
** 2.1	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).
** 2.2	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).
3.2(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).
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 (Incorporated by reference to Exhibit 3.7 of our Quarterly Report on Form 10-Q (Commission File No. 001-32212) for the quarter ended June 30, 2004).
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).

129

Endeavour International Corporation

Exhibit Index

Exhibit	Description
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.
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	Warrant to Purchase 25,000 Shares of Common Stock issued to Trident Growth Fund, L.P. (Incorporated by reference to Exhibit 10.11 of our Annual Report on Form 10-KSB (Commission File No. 000-33439) for the Year Ended December 31, 2002).
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).

130

Endeavour International Corporation

Exhibit Index

Exhibit	Description
4.6	Common Stock Purchase Warrant dated February 26, 2004 issued to Sanders Morris Harris Inc. in connection with the private placement of 25,000,000 shares of Endeavour’s common stock. (Incorporated by reference to Exhibit 10.24 of our Annual Report on Form 10-KSB (Commission File No. 000-33439) for the year ended December 31, 2003).
†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	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).
†10.4	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).
†10.5	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).
†10.6	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).
*†10.7	Change in Control and Termination Benefits Agreement dated January 11, 2010, by and between Endeavour International Corporation and James Joseph Emme.
†10.8	Form of Restricted Stock Award Agreement. (Incorporated by reference to Exhibit 10.39 of our Annual Report on Form 10-KSB (Commission File No. 000-33439) for the year ended December 31, 2003).
†10.9	Form of Nonstatutory Stock Option Agreement between Endeavour International Corporation and William L. Transier, John N. Seitz, Michael D. Cochran, Bruce H. Stover, H. Don Teague and Robert L. Thompson, individually (Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on January 5, 2005.)

131

Endeavour International Corporation

Exhibit Index

Exhibit	Description
†10.10	Form of Stock Grant Agreement between Endeavour International Corporation and William L. Transier, John N. Seitz, Bruce H. Stover and Robert L. Thompson, individually (Incorporated by reference to Exhibit 10.4 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on January 5, 2005).
10.11(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).
10.11(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).
**10.12	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).
10.13(a)	$225,000,000 Secured Revolving Loan and Letter of Credit Facility Agreement (Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on November 6, 2006).
10.13(b)	Waiver and consent to $225,000,000 Secured Revolving Loan and Letter of Credit Facility Agreement (Incorporated by reference to Exhibit 4.8(b) to our Annual Report on Form 10-K (Commission File No. 001-32212) for the year ended December 31, 2006).
*10.13(c)	Waiver and consent to $225,000,000 Secured Revolving Loan and Letter of Credit Facility Agreement, dated as of February 5, 2010.
10.14(a)	Second Lien Credit and Guarantee Agreement (Incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K/A (Commission File No. 001-32212) filed on November 7, 2006).
10.14(b)	Amendment to Second Lien Credit and Guarantee Agreement (Incorporated by reference to Exhibit 4.9(b) to our Annual Report on Form 10-K (Commission File No. 001-32212) for the year ended December 31, 2006).
10.15(a)	Junior Facility Agreement dated January 22, 2008 by and among Endeavour International Holding B.V., as borrower, Endeavour International Corporation and certain of its affiliates party thereto, as guarantors, BNP Paribas and Bank of Scotland Plc, as the mandated lead arrangers and original lenders, and BNP Paribas, as agent and security trustee (Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on January 28, 2008).

132

Endeavour International Corporation

Exhibit Index

Exhibit	Description
*10.15(b)	Amendment to Junior Facility Agreement dated February 5, 2010 by and among Endeavour International Holding B.V., as borrower, Endeavour International Corporation and certain of its affiliates party thereto, as guarantors, BNP Paribas and Bank of Scotland Plc, as the mandated lead arrangers and original lenders, and BNP Paribas, as agent and security trustee.
†10.16	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).
†10.17	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).
†10.18	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).
†10.19	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).
†10.20	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).
†10.21	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).
†10.22	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).
†10.23	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).

133

Endeavour International Corporation

Exhibit Index

Exhibit	Description
†10.24	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).
†10.25	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).
10.26(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).
*10.26(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.
10.27	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).
10.28	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).
*12.1	Computation of Ratios of Earnings to Fixed Charges.
*12.2	Computation of Ratios of Earnings to Fixed Charges and Preference Securities Dividends.
*21.1	List of Subsidiaries.
*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.

134

Endeavour International Corporation

Exhibit Index

Exhibit	Description
‡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.

135

EX-3.6.C

     EXHIBIT 3.6(c)

AMENDMENT TO
CERTIFICATE OF DESIGNATION
OF
SERIES C PREFERRED STOCK
OF
ENDEAVOUR INTERNATIONAL CORPORATION

     Endeavour International Corporation, a Nevada corporation (the “Corporation”), does hereby certify that this Amendment dated as of March ___, 2010 (this “Amendment”) to the Corporation’s Certificate of Designation of Series C Preferred Stock (as amended, the “Certificate”), originally filed with the Nevada Secretary of State on October 30, 2006 and amended on December 21, 2006 and November 17, 2009, is made and entered into by the Corporation and has been duly authorized and approved by the Board of Directors of the Corporation and stockholders of the Corporation in accordance with the provisions of Nevada Revised Statutes 78.1955. All capitalized terms used but not otherwise defined herein shall have the meanings given to such terms in the Certificate.

     The Corporation hereby certifies:

     FIRST, that the Board of Directors of the Corporation duly adopted resolutions proposing and declaring advisable the following amendments to the Certificate in accordance with the provisions of Section 78.1955 of the Nevada Revised Statutes:

     RESOLVED, that Section 8(e) of Article First of the Certificate is hereby amended and restated in its entirety as follows:

     “The Corporation shall neither (A) purchase, redeem or otherwise acquire any shares of Common Stock at a price per share greater than the average Closing Sale Price per share of the Common Stock on the American Stock Exchange (or such other national quotation system or national securities exchange as the Common Stock is primarily traded) for the ten (10) Trading Days ending on the day immediately preceding the purchase, redemption or acquisition (the “Current Market Price”) nor (B) purchase, redeem or otherwise acquire Options or Convertible Securities for a consideration per share of Common Stock into which such security is convertible or exchangeable greater than the Current Market Price on the date of such event. The foregoing shall not prohibit the Company from (a) purchasing, redeeming or otherwise acquiring Permitted Convertible Securities where the consideration for such purchase, redemption or other acquisition is 75% or less than the principal or liquidation preference plus accrued interest or dividends, as applicable, of such Permitted Convertible Securities on the date of purchase, redemption or other acquisition, or (b) refinancing in full any issue, class or series of Permitted Convertible Securities (the “Refinanced Convertible Securities”) solely with the proceeds from newly issued debt securities or equity securities of the Company, but only if the earliest date upon which any portion of such debt or equity securities is required to be repaid,

repurchased or redeemed by the Company or any of its Subsidiaries (absent an event of default, in the case of debt securities, or a change of control, in the case of equity securities) is later than the latest date upon which the Company or one of its Subsidiaries would have been required to repay, redeem or repurchase in full all of the Refinanced Convertible Securities in accordance with the terms thereof. “Permitted Convertible Securities” means shares of Series C Preferred Stock, the Company’s 6% Convertible Senior Notes due 2012 issued pursuant to the Indenture dated as of January 20, 2005 between the Company and Wells Fargo Bank, N.A., as trustee, and the Company’s 11.5% Guaranteed Convertible Bonds due 2014 subject to a Trust Deed, dated as of January 24, 2008, among the Company, Endeavour Energy Luxembourg S.a.r.l. and BNY Corporate Trustee Services Limited, as trustee.”

     SECOND, that the previously stated amendment to the Certificate was duly approved by the requisite consent of the holders of Series C Preferred Stock in accordance with the provisions of Section 78.1955 of the Nevada Revised Statutes.

[SIGNATURE PAGE FOLLOWS]

     IN WITNESS WHEREOF, the Corporation has caused this Amendment to be signed and acknowledged by the undersigned as of the 10 day of March, 2010 as the act and deed of the Corporation.

ENDEAVOUR INTERNATIONAL
CORPORATION

Signature’s

/s/ J. Michael Kirksey	/s/Gaurav Bhandari
J. Michael Kirksey	Gaurav Bhandari
Chief Financial Officer	Goldman, Sachs Investment Partners Master Fund, L.P.
/s/ Terence Aquino	/s/ Mark J. Vanacore
Terence Aquino	Mark J. Vanacore
Chief Financial Officer	Trading Manager
Eton Park Capital Management, LP	High Bridge International, LLC.
/s/ Terence Aquino	/s/ Martin Kobinger
Terence Aquino	Martin Kobinger
Chief Financial Officer	Investment Manager
Eton Park Master Fund, LTD.	Capital Ventures International
/s/ Mary Lee	/s/ R. Jeffrey Bruce
Mary Lee	R. Jeffrey Bruce
Chief Legal Officer	Vice President
TPG-Axon Partners, L.P.	Professional Life and Casualty
/s/ Mary Lee	/s/ J. Baker Gentry, Jr.
Mary Lee	J. Baker Gentry, Jr.
Chief Legal Officer	Investment Advisor
TPG-Axon Partners(Offshore), LTD.	HBK Master Fund, L.P.
/s/ Paul Smith Paul Smith
General Counsel
Magnetar Capital Master Fund, LTD.

EX-10.7

Exhibit 10.7

CHANGE IN CONTROL

TERMINATION BENEFITS AGREEMENT

     THIS CHANGE IN CONTROL TERMINATION BENEFITS AGREEMENT (the “Agreement”), dated as of the 11^th day of January 2010 is between Endeavour International Corporation, a Nevada corporation (the “Company”), and James Joseph Emme (the “Executive”).

W I T N E S S E T H:

     WHEREAS, the Company considers it essential to the best interests of the Company and its stockholders that its executive management be encouraged to remain with the Company and to continue to devote full attention to the Company’s business in the event of a transaction or series of transactions that could or do result in a change in control of the Company;

     WHEREAS, the Company recognizes that the possibility of a change in control and the uncertainty which it may raise among management may result in the departure or distraction of management personnel to the detriment of the Company and its stockholders;

     WHEREAS, the Executive is a key executive-level employee of the Company;

     WHEREAS, the Company believes that the Executive has made (and will continue to make) valuable contributions to the Company;

     WHEREAS, should the Company receive a proposal for, or otherwise consider, any such transaction, in addition to the Executive’s regular duties, the Executive may be called upon to assist in the assessment of proposals, advise management and the Board of Directors of the Company (the “Board”) as to whether a proposed transaction would be in the best interests of the Company and its stockholders, and take such other actions as the Board might determine to be appropriate; and

     WHEREAS, the Board has determined that it is in the best interests of the Company and its stockholders to assure that the Company will have the continued services of the Executive, notwithstanding the possibility, threat or occurrence of a change in control of the Company and believes that it is imperative to diminish the potential distraction of the Executive by virtue of the personal uncertainties and risks created by a pending or threatened change in control, to assure the Executive’s full attention and dedication to the Company in the event of any threatened or pending change in control, and to provide the Executive with appropriate severance arrangements following a change in control.

     NOW, THEREFORE, to assure the Company that it will have the continued undivided attention and services of the Executive and the availability of the Executive’s advice and counsel notwithstanding the possibility, threat or occurrence of a change in control of the Company, and to induce the Executive to remain in the employ of the Company, and for other good and valuable consideration, the Company and the Executive agree as follows:

     1. Change in Control. For purposes of the Agreement, a “Change in Control” shall be deemed to have taken place if any of the following occurs:

          (a) the Company (i) shall not be the surviving entity in any merger, consolidation or other reorganization (or survives only as a subsidiary of an entity other than a previously wholly-owned subsidiary of the Company), or (ii) is to be dissolved and liquidated, and as a result of or in connection with such transaction, the persons who were directors of the Company before such transaction shall cease to constitute a majority of the Board;

          (b) any person or entity, including a “group” as contemplated by Section 13(d)(3) of the Exchange Act, acquires or gains ownership or control (including, without limitation, power to vote) of 30% or more of the outstanding shares of the Company’s voting stock (based upon voting power), and as a result of or in connection with such transaction, the persons who were directors of the Company before such transaction shall cease to constitute a majority of the Board;

          (c) the Company sells all or substantially all of the assets of the Company to any other person or entity (other than a wholly-owned subsidiary of the Company) in a transaction that requires shareholder approval pursuant to applicable corporate law; or

          (d) during a period of two consecutive calendar years, individuals who at the beginning of such period constitute the Board, and any new director(s) whose election by the Board or nomination for election by the Company’s stockholders was approved by a vote of at least a majority of the directors then still in office, who either were directors at the beginning of the two (2) year period or whose election or nomination for election was previously so approved, cease for any reason to constitute a majority of the Board.

     2. Circumstances Triggering Receipt of Termination Benefits.

          (a) Subject to Section 2(c), the Company will provide the Executive with the benefits set forth in Section 4 upon any termination of the Executive’s employment:

          (i) by the Company at any time within the first 24 months after a Change in Control;

          (ii) by the Executive for “Good Reason” (as defined in Section 2(b) below) at any time within the first 24 months after a Change in Control; or

          (iii) by the Company or the Executive pursuant to Section 2(d).

          (b) In the event of a Change in Control, the Executive may terminate employment with the Company and/or any subsidiary for “Good Reason,” following notice and opportunity for remedy as set forth herein and in Section 3. For purposes hereof, “Good Reason” shall mean (subject to such notice and opportunity to remedy) any of the occurrence of any of the following events without the Executive’s prior written consent:

          (i) A material reduction of the Executive’s authorities, duties, or responsibilities as an executive and/or officer of the Company from those in effect as of ninety (90) calendar days prior to the Change in Control, other than an insubstantial and inadvertent reduction that is remedied by the Company promptly after receipt of notice thereof given by the Executive.

          (ii) The Company’s requiring the Executive to be based at a location in excess of fifty (50) miles from the location of the Executive’s principal job location or office immediately prior to the Change in Control; except for required travel on the Company’s business to an extent substantially consistent with the Executive’s then present business travel obligations;

          (iii) A reduction by the Company of the Executive’s Base Salary and/or target annual bonus opportunity in effect on the Effective Date hereof, or as the same shall be increased from time to time;

          (iv) The failure of the Company to obtain a satisfactory agreement from any successor to the Company to assume and agree to perform the Company’s obligations under this Agreement, as contemplated in Section 8 (where it requires successors to accept this Agreement) herein; or

          (v) A material breach of this Agreement by the Company which is not remedied by the Company within ten (10) business days of receipt of written notice of such breach delivered by the Executive to the Company.

          (c) Notwithstanding Sections 2(a) and (b) above, no benefits shall be payable by reason of this Agreement in the event of:

          (i) Termination of the Executive’s employment with the Company and/or its subsidiaries by reason of the Executive’s death or Disability, provided that the Executive has not previously given a valid “Notice of Termination” pursuant to Section 3. For purposes hereof, “Disability” shall mean the Executive’s inability, due to physical or mental infirmity, to perform the Executive’s material duties and responsibilities to the Company and its subsidiaries for any period of six consecutive months or for any period of eight months out of any 12-month period, as determined by a physician selected by the Company or its insurers and acceptable to the Executive or the Executive’s legal representative (such agreement as to acceptability not to be withheld unreasonably);

          (ii) Termination of the Executive’s employment with the Company and/or its subsidiaries on account of the Executive’s retirement without Good Reason; provided, however, that, if at the time of such retirement the Executive has Good Reason to terminate the Executive’s employment hereunder, then such retirement shall be treated hereunder as a termination of the Executive’s employment for Good Reason and the Executive shall be entitled to the benefits provided in Section 4 hereof;

          (iii) Termination of the Executive’s employment with the Company and its subsidiaries for Cause. For the purposes hereof, “Cause” shall mean:

               (A) The Executive’s willful failure to substantially perform his or her duties with the Company (other than any such failure resulting from the Executive’s

Disability), after a written demand for substantial performance is delivered to the Executive that specifically identifies the manner in which the Committee believes that the Executive has not substantially performed his or her duties, and the Executive has failed to remedy the situation within fifteen (15) business days of such written notice from the Company;

               (B) Gross negligence in the performance of the Executive’s duties which results in material financial harm to the Company;

               (C) The Executive’s conviction of, or plea of guilty or nolo contendere, to any felony or any other crime involving the personal enrichment of the Executive at the expense of the Company;

               (D) The Executive’s willful engagement in conduct that is demonstrably and materially injurious to the Company, monetarily or otherwise; or

               (E) The Executive’s willful violation of any of the covenants contained in Section 7.

     Notwithstanding the foregoing, “Cause” shall not exist unless and until the Company has delivered to the Executive, along with the Notice of Termination for Cause, a copy of a resolution duly adopted by three-quarters (3/4) of the entire Board (excluding the Executive if the Executive is a Board member) at a meeting of the Board called and held for such purpose (after reasonable notice to the Executive and an opportunity for the Executive, together with counsel, to be heard before the Board), finding that in the good faith opinion of the Board an event (or events) set forth in clauses (A)-(E) above has occurred and specifying the particulars thereof in detail.

     This Section 2(c) shall not preclude the payment of any amounts otherwise payable to the Executive under any of the Company’s employee benefit plans, stock plans, programs and arrangements, which payment shall be governed exclusively by the terms thereof.

          (d) A termination of the Executive’s employment by the Company without Cause or by the Executive for an event that would constitute Good Reason following a Change in Control that occurs, in either event, prior to a Change in Control, but occurs (i) not more than 200 days prior to the date on which a Change in Control occurs and (ii) (x) at the request of a third party who has indicated an intention or taken steps reasonably calculated to effect a Change in Control or (y) otherwise arose in connection with, or in anticipation of, a Change in Control, shall be deemed to be a termination or removal of the Executive without Cause within the first 24 months after a Change in Control for purposes of this Agreement and the date of such Change in Control shall be deemed to be the date immediately preceding the date the Executive’s employment terminates.

     3. Notice of Termination; Termination Date. Any termination of the Executive’s employment with the Company and its subsidiaries as contemplated by Section 2 shall be communicated by written “Notice of Termination” to the other party hereto. Any “Notice of Termination” shall indicate the effective date of termination, which, shall be more than 60 days after the date the Notice of Termination is delivered (the “Termination Date”), the specific provision in this Agreement relied upon,

and, except for a termination pursuant to Section 2(d), will set forth in reasonable detail the facts and circumstances claimed to provide a basis for such termination including, if applicable, the failure by the Company, after provision of written notice by the Executive, to effect a remedy pursuant to the final clause of Section 2(b)(i) or 2(b)(vi). Executive must provide the Notice of Termination to the Company within 90 days of the events constituting “Good Reason” for termination and the Company shall have a period of 30 days after the Notice of Termination during which the Company may remedy the condition before such termination shall be effective. In the event the Company effects a remedy within such 30-day period and the Executive does not rescind the Notice of Termination upon being notified of such remedy, the termination benefits described in Section 4 hereof shall not be payable with respect to such termination.

     4. Termination Benefits. Subject to the conditions set forth in Section 2(a) and contingent upon the Executive’s executing (and not revoking) the “Release” (as defined below), the following post-termination payments or benefits shall be paid or provided to the Executive following the Executive’s termination of employment:

          (a) Severance Payment. The Company shall pay to the Executive, as a severance payment, an amount equal to the sum of (i) two times (A)the Executive’s “Base Pay”, which shall be an amount equal to the greater of (x) the Executive’s rate of annual base salary (prior to any deferrals) at the Termination Date or (y) the Executive’s rate of annual base salary (prior to any deferrals) immediately prior to the Change in Control, and (B) the Executive’s “Incentive Pay”, which shall be an amount equal to the average annual bonus earned by the Executive under the Company’s incentive compensation plan or any other annual bonus plan (whether paid currently or on a deferred basis) during the three fiscal years of the Company immediately preceding the fiscal year of the Company in which the Change in Control occurred plus (ii) a pro rata portion of the Executive’s target bonus for the fiscal year in which the Termination Date occurs, which payment shall be made in a single lump sum on the first business day following the expiration of the revocation period for the Release. Notwithstanding the foregoing, if all or any portion of the severance payment is determined to be “nonqualified deferred compensation” subject to Section 409A of the Internal Revenue Code of 1986, as amended (the “Code”), and the Company determines that the Executive is a “specified employee” as defined in Section 409A(a)(2)(B)(i) of the Code and Final Treasury Regulations promulgated thereunder (the “Treasury Regulations”) and other guidance published thereunder, then such payment (or portion thereof) shall be paid on the first day of the seventh month following the Executive’s “separation from service” (as such term is defined in the Treasury Regulations, giving effect to the default presumptions of Section 1.409A-1(h) thereof).

          (b) Health Benefits. To the extent the Executive timely elects to continue healthcare coverage through COBRA, the Company shall pay that portion of the COBRA premium equal to the difference between the COBRA premium and Executive’s monthly contribution towards health benefits that is in effect as of the date of Executive’s termination of employment for a period equal to 18 months following the Termination Date; provided, that, the Company’s obligation to provide such health benefits shall cease at the time Executive becomes eligible for such health benefits from another employer.

          (c) Release. The Company’s obligation to make the payment and provide the benefits described in this Section 4 are conditioned expressly on the Executive’s executing (and not revoking) a general release of claims against the Company (as “Company” is defined in Section 8) and its subsidiaries

in a form reasonably satisfactory to the Company (the “Release”) within 45 days following the Termination Date. The Company will provide the Release to the Executive within seven days following the Termination Date.

     5. Certain Additional Payments by the Company.

          (a) Anything in this Agreement to the contrary notwithstanding, in the event that it shall be determined (as hereafter provided) that any payment (other than the Gross-Up payments provided for in this Section 5) or benefit provided by the Company or any of its subsidiaries to or for the benefit of the Executive, whether paid or payable or provided pursuant to the terms of this Agreement or otherwise pursuant to or by reason of any other agreement, policy, plan, program or arrangement, including without limitation any stock option, stock appreciation right or similar right, restricted stock, deferred stock or the lapse or termination of any restriction on, deferral period for, or the vesting or exercisability of any of the foregoing (a “Payment”), would be subject to the excise tax imposed by Section 4999 of the Code (or any successor provision thereto) by reason of being considered “contingent on a change in ownership or control” of the Company, within the meaning of Section 280G of the Code (or any successor provision thereto) or to any similar tax imposed by state or local law, or any interest or penalties with respect to any such tax (such tax or taxes, together with any such interest and penalties, being hereafter collectively referred to as the “Excise Tax”), then the Executive shall be entitled to receive an additional payment or payments (collectively, a “Gross-Up Payment”). The Gross-Up Payment shall be in an amount such that, after payment by the Executive of all taxes (including any interest or penalties imposed with respect to such taxes), including any Excise Tax and any income tax imposed upon the Gross-Up Payment, the Executive retains an amount of Gross-Up Payment equal to the Excise Tax imposed upon the Payment.

          (b) Subject to the provisions of Section 5(f), all determinations required to be made under this Section 5, including whether an Excise Tax is payable by the Executive and the amount of such Excise Tax and whether a Gross-Up Payment is required to be paid by the Company to the Executive and the amount of such Gross-Up Payment, if any, shall be made by the Company’s outside auditors immediately prior to the Change in Control (the “Accounting Firm”). The Executive shall direct the Accounting Firm to submit its determination and detailed supporting calculations to both the Company and the Executive within 30 days after the Change in Control Date, the Termination Date, if applicable, and any such other time or times as may be requested by the Company or the Executive. If the Accounting Firm determines that any Excise Tax is payable by the Executive, the Company shall pay the required Gross-Up Payment to the Executive as soon as reasonably practicable thereafter but in any event no later than the end of the Executive’s taxable year next following the taxable year in which the Executive remits such Excise Tax to the Internal Revenue Service. If the Accounting Firm determines that no Excise Tax is payable by the Executive, it shall, at the same time as it makes such determination, furnish the Company and the Executive an opinion that the Executive has substantial authority not to report any Excise Tax on the Executive’s federal, state or local income or other tax return. As a result of the uncertainty in the application of Section 4999 of the Code (or any successor provision thereto) and the possibility of similar uncertainty regarding applicable state of local tax law at the time of any determination by the Accounting Firm hereunder, it is possible that a Gross-Up Payment which will not have been made by the Company should have been made (an “Underpayment”), consistent with the calculations required to be made hereunder. In the event that the Company exhausts or fails to pursue its remedies pursuant to Section 5(f) and the Executive thereafter is required to make a payment of any

Excise Tax, the Executive shall direct the Accounting Firm to determine the amount of the Underpayment that has occurred and to submit its determination and detailed supporting calculations to both the Company and the Executive as promptly as possible. Any such Underpayment shall be promptly paid by the Company to, or for the benefit of, the Executive within five business days after receipt of such determination and calculations but in any event no later than the end of the Executive’s taxable year next following the taxable year in which the Executive remits such Underpayment to the Internal Revenue Service.

          (c) The Company and the Executive shall each provide the Accounting Firm access to and copies of any books, records and documents in the possession of the Company or the Executive, as the case may be, reasonably requested by the Accounting Firm, and otherwise cooperate with the Accounting Firm in connection with the preparation and issuance of the determinations and calculations contemplated by Section 5(b). Any determination by the Accounting Firm as to the amount of the Gross-Up Payment shall be binding upon the Company and the Executive.

          (d) The federal, state and local income or other tax returns filed by the Executive shall be prepared and filed on a consistent basis with the determination of the Accounting Firm with respect to the Excise Tax payable by the Executive. The Executive shall make proper payment of the amount of any Excise Tax, and at the request of the Company, provide to the Company true and correct copies (with any amendments) of the Executive’s federal income tax return as filed with the Internal Revenue Service and corresponding state and local tax returns, if relevant, as filed with the applicable taxing authority, and such other documents reasonably requested by the Company, evidencing such payment. If prior to the filing of the Executive’s federal income tax return, or corresponding state or local tax return, if relevant, the Accounting Firm determines that the amount of the Gross-Up Payment should be reduced, the Executive shall, within five business days, pay to the Company the amount of such reduction.

          (e) The fees and expenses of the Accounting Firm for its services in connection with the determinations and calculations contemplated by Section 5(b) shall be borne by the Company. If such fees and expenses are initially paid by the Executive, the Company shall reimburse the Executive the full amount of such fees and expenses paid by Executive within five business days after receipt from the Executive of a statement therefor and reasonable evidence of payment thereof.

          (f) The Executive shall notify the Company in writing of any claim, by the Internal Revenue Service or any other taxing authority that, if successful, would require the payment by the Company of a Gross-Up Payment or any additional Gross-Up Payment. Such notification shall be given as promptly as practicable but no later than l0 business days after the Executive actually receives notice of such claim, and the Executive shall further apprise the Company of the nature of such claim and the date on which such claim is requested to be paid (in each case, to the extent known by the Executive). The Executive shall not pay such claim prior to the earlier of (x) the expiration of the 30-day period following the date on which the Executive gives such notice to the Company and (y) the date that any payment with respect to such claim is due. If the Company notifies the Executive in writing prior to the expiration of such period that it desires to contest such claim, the Executive shall:

          (i) provide the Company with any written records or documents in the Executive’s possession relating to such claim reasonably requested by the Company;

          (ii) take such action in connection with contesting such claim as the Company shall reasonably request in writing from time to time, including without limitation accepting legal representation with respect to such claim by an attorney competent in respect of the subject matter and reasonably selected by the Company;

          (iii) cooperate with the Company in good faith in order effectively to contest such claim; and

          (iv) permit the Company to participate in any proceedings relating to such claim;

provided, however, that the Company shall bear and pay directly all costs and expenses (including interest and penalties) incurred in connection with such contest and shall indemnify and hold harmless the Executive, on an after-tax basis, for and against any Excise Tax or income tax including interest and penalties with respect thereto, imposed as a result of such contest and payment of costs and expenses. Without limiting the foregoing provisions of this Section 5(f), the Company shall control all proceedings taken in connection with the contest of any claim contemplated by this Section 5(f) and, at its sole option, may pursue or forego any and all administrative appeals, proceedings, hearings and conferences with the taxing authority in respect of such claim (provided, however, that the Executive may participate therein at the Executive’s own cost and expense) and may, at its option, either direct the Executive to pay the tax claimed and sue for a refund or contest the claim in any permissible manner, and the Executive agrees to prosecute such contest to a determination before any administrative tribunal, in a court of initial jurisdiction and in one or more appellate courts, as the Company shall determine; provided, however, that if the Company directs the Executive to pay the tax claimed and sue for a refund, the Company shall advance the amount of such payment to the Executive on an interest-free basis and shall indemnify and hold the Executive harmless, on an after-tax basis, from any Excise Tax or income or other tax, including interest or penalties with respect thereto, imposed with respect to such advance; and provided further, that any extension of the statute of limitations relating to payment of taxes for the taxable year of the Executive with respect to which the contested amount is claimed to be due is limited solely to such contested amount. Furthermore, the Company’s control of any such contested claim shall be limited to issues with respect to which a Gross-Up Payment would be payable hereunder and the Executive shall be entitled to settle or contest, as the case may be, any other issue raised by the Internal Revenue Service or any other taxing authority.

          (g) If, after the receipt by the Executive of an amount advanced by the Company pursuant to Section 5(f), the Executive receives any refund with respect to such claim, the Executive shall (subject to the Company’s complying with the requirements of Section 5(f)) promptly pay to the Company the amount of such refund (together with any interest paid or credited thereon after any taxes applicable thereto). If, after the receipt by the Executive of an amount advanced by the Company pursuant to Section 5(f), a determination is made that the Executive shall not be entitled to any refund with respect to such claim and the Company does not notify the Executive in writing of its intent to contest such denial or refund prior to the expiration of 30 days after such determination, then such advance shall be forgiven and shall not be required to be repaid and the amount of any such advance shall offset, to the extent thereof, the amount of any Gross-Up Payment required to be paid by the Company to the Executive pursuant to this Section 5.

     6. No Mitigation Obligation; Obligations Absolute. The payment of the severance compensation by the Company to the Executive in accordance with the terms of this Agreement is hereby acknowledged by the Company to be reasonable, and the Executive will not be required to mitigate the amount of any payment or other benefit provided in this Agreement by seeking other employment or otherwise, nor will any profits, income, earnings or other benefits from any source whatsoever create any mitigation, offset, reduction or any other obligation on the part of the Executive hereunder or otherwise, except as expressly provided in Section 12 hereof. The obligations of the Company to make the payments and provide the benefits provided herein to the Executive are absolute and unconditional (except as provided herein) and may not be reduced under any circumstances, including without limitation any set-off, counterclaim, recoupment, defense or other right which the Company may have against the Executive or any third party at any time.

     7. Continuing Obligations.

          (a) Confidentiality. The Executive shall hold in a fiduciary capacity for the benefit of the Company all secret or confidential information, knowledge or data relating to the Company or any of its affiliated companies, and their respective businesses, which shall have been obtained by the Executive during the Executive’s employment by the Company and which shall not be or become public knowledge (information that has become public knowledge shall not include any information that has entered the public domain as a result of acts or omissions by the Executive or representatives of the Executive in violation of this Agreement). After termination of the Executive’s employment with the Company and its subsidiaries for any reason, the Executive shall not, without the prior written consent of the Company or as may otherwise be required by law or legal process, communicate or divulge any such information, knowledge or data to anyone other than the Company and those designated by it.

          (b) Non-Solicitation. During the term of this Agreement and for a period of twelve (12) months after the Termination Date, the Executive shall not, directly or indirectly, employ or retain or solicit for employment or arrange to have any other person, firm, or other entity employ or retain or solicit for employment or otherwise participate in the employment or retention of any person who is an employee of the Company.

          (c) Cooperation. Executive agrees to cooperate with the Company and its attorneys in connection with any and all lawsuits, claims, investigations, or similar proceedings that have been or could be asserted at any time arising out of or related in any way to Executive’s employment by the Company or any of its subsidiaries.

          (d) Non-Disparagement. At all times following the Termination Date, the Executive agrees not to disparage the Company or any of its directors or executive officers, or otherwise make comments harmful to the Company’s business or reputation

          (e) Blue Penciling. It is expressly understood and agreed that although the Executive and the Company consider the restrictions contained in Sections 7(a) through (d) to be reasonable, if a judicial determination is made by a court of competent jurisdiction that the time or territory or any other restriction contained in this Agreement is an unenforceable restriction against the Executive, the provisions of this Agreement shall not be rendered void but shall be

deemed amended to apply as to such maximum time and territory and to such maximum extent as such court may judicially determine or indicate to be enforceable. Alternatively, if any court of competent jurisdiction finds that any restriction contained in this Agreement is unenforceable, and such restriction cannot be amended so as to make it enforceable, such finding shall not affect the enforceability of any of the other restrictions contained herein.

     8. Successors.

          (a) The Company shall require any successor (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business and/or assets of the Company, by agreement in form and substance reasonably satisfactory to the Executive to expressly assume and agree to perform this Agreement in the same manner and to the same extent that the Company would be required to perform it if no such succession had taken place. Failure of such successor entity to enter into such agreement prior to the effective date of any such succession (or, if later, within three business days after first receiving a written request for such agreement) shall constitute a breach of this Agreement and shall entitle the Executive to terminate employment pursuant to Section 2(a)(ii) and to receive the payments and benefits provided under Section 4. As used in this Agreement, “Company” shall mean the Company as herein before defined and any successor to its business and/or assets as aforesaid which executes and delivers the Agreement provided for in this Section 7 or which otherwise becomes bound by all the terms and provisions of this Agreement by operation of law.

          (b) This Agreement shall inure to the benefit of and be enforceable by the Executive’s personal or legal representatives, executors, administrators, successors, heirs, distributees, devisees and legatees. If the Executive dies while any amounts are payable to him hereunder, all such amounts, unless otherwise provided herein, shall be paid in accordance with the terms of this Agreement to the Executive’s designee or, if there is no such designee, to the Executive’s estate.

     9. Notices. For all purposes of this Agreement, all communications, including without limitation notices, consents, requests or approvals, required or permitted to be given hereunder will be in writing and will be deemed to have been duly given when hand delivered or dispatched by electronic facsimile transmission (with receipt thereof orally confirmed), or five business days after having been mailed by United States registered or certified mail, return receipt requested, postage prepaid, or three business days after having been sent by a nationally recognized overnight courier service such as FedEx, UPS, or DHL, addressed to the Company (to the attention of the Secretary of the Company, with a copy to the General Counsel of the Company) at its principal executive office and to the Executive at the Executive’s principal residence, or to such other address as any party may have furnished to the other in writing and in accordance herewith, except that notices of changes of address shall be effective only upon receipt.

     10. Governing Law. The validity, interpretation, construction and performance of this agreement shall be governed by the laws of the State of Texas, without regard to conflicts of law principles.

     11. Miscellaneous. No provisions of this Agreement may be modified, waived or discharged unless such waiver, modification or discharge is agreed to in a writing signed by the Executive and the

Company. No waiver by either party hereto at any time of any breach by the other party hereto of, or compliance with, any condition or provision of this Agreement to be performed by such other party shall be deemed a waiver of similar or dissimilar provisions or conditions at the same or any prior or subsequent time. No agreements or representations, oral or otherwise, express or implied, with respect to the subject matter hereof have been made by either party which are not set forth expressly in this Agreement (or in any employment or other written agreement relating to the Executive). Nothing expressed or implied in this Agreement will create any right or duty on the part of the Company or the Executive to have the Executive remain in the employment of the Company or any subsidiary prior to or following any Change in Control. The Company may withhold from any amounts payable under this Agreement all federal, state, city or other taxes as the Company is required to withhold pursuant to any law or government regulation or ruling. In the event that the Company refuses or otherwise fails to make a payment when due and it is ultimately decided that the Executive is entitled to such payment, such payment shall be increased to reflect an interest factor, compounded annually, equal to the prime rate in effect as of the date the payment was first due plus two points. For this purpose, the prime rate shall be based on the rate identified by Chase Manhattan Bank as its prime rate.

     All headings and section references used herein are for convenience only and do not constitute a part of this Agreement. Where specific language is used to clarify by example a general statement contained herein, such specified language shall not be deemed to modify, limit or restrict in any manner the construction of the general statement to which it relies. The language used in this Agreement is deemed to be the language chosen by the parties hereto to express their mutual intent, and no rule of strict construction shall be applied against any such party.

     12. Reduction for Other Severance. Any payments or other benefits provided to the Executive under this Agreement shall be offset or reduced by any payments or other benefits provided under any severance plan or employment agreement which the Executive is eligible to receive (or has received) as a result of the termination of the Executive’s employment.

     13. Separability. The invalidity or unenforceability of any provisions of this Agreement shall not affect the validity or enforceability of any other provision of this Agreement, which shall remain in full force and effect.

     14. Non-assignability. This Agreement is personal in nature and neither of the parties hereto shall, without the consent of the other, assign or transfer this Agreement or any rights or obligations hereunder, except as provided in Section 8. Without limiting the foregoing, the Executive’s right to receive payments hereunder shall not be assignable or transferable, whether by pledge, creation of a security interest or otherwise, other than a transfer by will or by the laws of descent or distribution, and in the event of any attempted assignment or transfer by the Executive contrary to this Section 14 the Company shall have no liability to pay any amount so attempted to be assigned or transferred to any person other than the Executive or, in the event of death, the Executive’s designated beneficiary or, in the absence of an effective beneficiary designation, the Executive’s estate.

     15. Effectiveness; Term. This Agreement will be effective and binding as of the date first above written immediately upon its execution and shall continue in effect through the second anniversary of such date; provided, however, that the term of this Agreement shall automatically be extended for an

additional day for each day that passes so that there shall at any time be two years remaining in the term unless the Company provides written notice to the Executive that it does not wish the term of this Agreement to continue to be so extended, in which case the Agreement shall terminate on the second anniversary of such notice if there has not been a Change in Control prior to such second anniversary. In the event that a Change in Control has occurred during the term of this Agreement, then this Agreement shall continue to be effective until the second anniversary of such Change in Control. Notwithstanding any other provision of this Agreement, if, prior to a Change in Control, the Executive ceases for any reason to be an employee of the Company and any subsidiary (other than a termination of employment pursuant to Section 2(d) hereof), thereupon without further action the term of this Agreement shall be deemed to have expired and this Agreement will immediately terminate and be of no further effect. For purposes of this Section 15, the Executive shall not be deemed to have ceased to be an employee of the Company and any subsidiary by reason of the transfer of the Executive’s employment between the Company and any subsidiary, or among any subsidiaries. Notwithstanding any provision of this Agreement to the contrary, the parties’ respective rights and obligations under Sections 4 through 8 will survive any termination or expiration of this Agreement or the termination of the Executive’s employment following a Change in Control for any reason whatsoever.

     16. Counterparts. This Agreement may be executed in one or more counterparts, each of which shall be deemed to be an original but all of which together will constitute one and the same agreement.

     17. Code Section 409A. Notwithstanding any other provision of this Agreement to the contrary, the Company shall modify the time and/or form of any payment or benefit provided hereunder any if and to the extent that the Company or the Executive determines such modification to be necessary or advisable to avoid the imposition upon the Executive of earlier or additional taxes pursuant to Code Section 409A (including, without limitation, to the extent necessary if the Executive has received payments or benefits that would be aggregated with such payment or benefit under any other plan or agreement of the Company). In making any such modification, the determination by the Company or the Executive must be made in good faith, be based on advice of counsel and be designed, in the Company’s sole judgment, to fulfill as closely as possible the Company’s original commitment to the Executive with respect to the payment or benefit being modified to comply with Section 409A without increasing the Company’s costs in providing such payment or benefit No modification shall be made by the Company without the Executive’s prior written consent.

[SIGNATURE PAGE FOLLOWS]

     IN WITNESS WHEREOF, the parties have caused this Agreement to be executed and delivered as of the day and year first above set forth.

Endeavour International Corporation

Signatures

/s/ William L. Transier               
William L. Transier
Chairman, CEO and President

/s/ James Joseph Emme               
James Joseph Emme
Executive VP of North America

EX-10.13.C

Exhibit 10.13(c)

To:	Endeavour International Corporation and each of the other Obligors
From:	BNP Paribas (as Agent and Security Trustee)
Date:	5 February 2010

Dear Sirs

$225,000,000 revolving loan and letter of credit facility agreement dated 30 October 2006 between, among others, Endeavour International Corporation and BNP Paribas (as amended from time to time) (the “Facility Agreement”)

1.	INTRODUCTION
1.1	General
	We refer to the Facility Agreement. We also refer to Company’s recent request for relevant consents to be provided under the Facility Agreement and/or the Intercreditor Agreement in order for the Junior Facility and the New Security to be effected.
1.2	Definitions and construction

1.2.1	Unless otherwise defined in this letter, terms defined in the Facility Agreement (whether expressly or by incorporation) shall have the same meaning when used in this letter.
1.2.2	Unless otherwise specified, references in this letter to clauses are references to clauses of the Facility Agreement.
1.2.3	In this letter:
	“Existing Second Lien Credit Agreement” means the Second Lien Credit Agreement (as defined under the Intercreditor Agreement before the same is amended pursuant to paragraph 2.3.2 (Conditions) below).
	“Intercreditor Amendment” means each amendment to the Intercreditor Agreement which is highlighted in the blacklined version of the Intercreditor Agreement set out in Appendix 2 hereto.
	“Junior Facility” means a junior credit facility for an aggregate principal amount of $25,000,000 provided by the lenders thereto (being, as at the date of this letter, Bank of Scotland plc) to the Company and certain of its Affiliates on the terms summarised in the Termsheet.
	“New Security” means Security granted in favour of the Security Trustee over the same assets that are the subject of the Security which has (i) been constituted by the existing Security Documents and (ii) not been released before the date of this letter by the Security Trustee pursuant to the Finance Documents.
	“Termsheet” means the termsheet set out in Appendix 1 hereto.

2.	CONSENTS
2.1	Facility Agreement
	We confirm in our capacity as Agent, subject to paragraph 2.3 (Conditions) below, that:

2.1.1 the Majority Lenders have consented, under clause 23.4.2(G) (Negative pledge), to the grant of the New Security;

2.1.2	the Majority Lenders have consented, under clause 23.6.2(H) (Financial Indebtedness) to the Junior Facility being effected;
2.1.3	the Majority Creditors have agreed, notwithstanding clause 23.7 (Credits and guarantees), that each guarantor under the Junior Facility may give the lenders and the other finance parties under the Junior Facility a guarantee in respect of the Financial Indebtedness and other liabilities arising under the Junior Facility; and
2.1.4	the Majority Lenders have agreed, notwithstanding Clause 23.21.2 (Distributions), that the Junior Facility may restrict the ability of the Obligors and members of the Group to declare, make or pay any dividend, distribution or other payment referred to in Clause 23.21.1 (Distributions).

2.2 Intercreditor Agreement

2.2.1	We understand that the Junior Facility will be effected by the entry of the parties thereto of an amendment and restatement agreement (the “ARA”) pursuant to which the terms of the Existing Second Lien Credit Agreement are, or will be, amended and restated.
2.2.2	We confirm in our capacity as Agent and Security Trustee, subject to paragraph 2.3 (Conditions), that:

(A)	the Majority First Lien Lenders have consented under clause 8.2 (Second Lien Documents) of the Intercreditor Agreement to the amendments to the Existing Second Lien Credit Agreement that are, or to be, effected under the ARA in so far as such amendments result in the Junior Facility being effected on terms summarised in the Termsheet;
(B)	the relevant quorum of Secured Creditors (other than the Second Lien Lenders) has consented to the Intercreditor Amendments.

2.3 Conditions

2.3.1 On the date of this letter, the definition of “Final Maturity Date” set out in clause 1.1 (Definitions) shall be deleted in its entirety and replaced with the following:

“Final Maturity Date” means the earlier of 31 January 2011 and the Reserve Tail Date.

2.3.2	The Intercreditor Amendments shall be made to the Intercreditor Agreement on the date of the ARA and, accordingly, the Intercreditor Agreement (as amended) shall govern (i) the relationship between the Creditors under the Junior Facility and the other Secured Creditors and (ii) the ability of the Creditors under the Junior Facility to take any action with respect to the New Security.
2.3.3	The Obligors shall pay, on or before the three Business Day after the date of this letter, to the Agent (for the account of each Lender) a fee equal to 0.20% of that Lender’s Commitment as at the date of this letter.

3.	GENERAL
3.1	Governing law
	This letter and any non-contractual obligations arising out of or in connection with it are governed by English law.
3.2	Miscellaneous

3.2.1 This letter is a Finance Document.

3.2.2	This letter may be executed in any number of counterparts, and this has the same effect as if signatures in the counterparts were on a single copy of this letter.
3.2.3	Please confirm your agreement to the terms of this letter by counter-signing this letter or a copy of it.

Yours faithfully

/s/ Remi Collonges-Duflouleur For and on behalf of	/s/ Aurelie Guth
BNP PARIBAS (AS AGENT AND SECURITY TRUSTEE)
WE AGREE TO THE TERMS OF THIS LETTER.
/s/ J. Michael Kirksey For and on behalf of
ENDEAVOUR INTERNATIONAL CORPORATION
/s/ J. Michael Kirksey For and on behalf of
ENDEAVOUR OPERATING CORPORATION
/s/ J. Michael Kirksey For and on behalf of
ENDEAVOUR ENERGY NEW VENTURES INC. COMPANY
/s/ J. Michael Kirksey For and on behalf of
END MANAGEMENT COMPANY

/s/ J. Michael Kirksey For and on behalf of

ENDEAVOUR ENERGY NORTH SEA, L.P.

/s/ J. Michael Kirksey For and on behalf of

ENDEAVOUR ENERGY NORTH SEA LLC

/s/ J. Michael Kirksey For and on behalf of

ENDEAVOUR INTERNATIONAL HOLDING B.V.

/s/ J. Michael Kirksey For and on behalf of

ENDEAVOUR ENERGY NETHERLANDS B.V.

/s/ J. Michael Kirksey For and on behalf of

ENDEAVOUR ENERGY UK LIMITED

/s/ J. Michael Kirksey For and on behalf of

ENDEAVOUR NORTH SEA LIMITED

EX-10.15.B

Exhibit 10.15(b)

EXECUTION VERSION

                                        2010

ENDEAVOUR INTERNATIONAL CORPORATION
(and certain of its Affiliates)

BNP PARIBAS
BANK OF SCOTLAND PLC

AMENDMENT AND RESTATEMENT
relating to a junior credit agreement dated 22
January 2008

Herbert Smith LLP

THIS AGREEMENT is dated            February 2010 and made between:

(1)	ENDEAVOUR INTERNATIONAL CORPORATION (the “Company”);
(2)	THE AFFILIATES OF THE COMPANY listed in Part I (Obligors) of Schedule 1 (Parties);
(3)	BNP PARIBAS; and
(5)	BANK OF SCOTLAND PLC.

IT IS AGREED as follows:

1.	GENERAL
1.1	Definitions
	Terms defined in the Restated Intercreditor Agreement (whether expressly or by incorporation) shall, unless otherwise defined in this Agreement or unless a contrary intention appears, have the same meaning when used in this Agreement. In addition, in this Agreement:
	“Intercreditor Agreement” means the intercreditor agreement dated 31 October 2006 between, among others, the Company and BNP Paribas (in various capacities) (as amended and restated from time to time).
	“New Obligor” means each of Endeavour North Sea Limited. Endeavour North Sea, L.P. and Endeavour North Sea LLC.
	“Restated Intercreditor Agreement” means the Intercreditor Agreement as amended and restated in the form set out in Schedule 3 (Form of Intercreditor Agreement) to this Agreement.
	“Restated Second Lien Credit Agreement” means the Second Lien Credit Agreement as amended and restated in the form set out in Schedule 2 (Form of Second Lien Agreement) to this Agreement.
	“Second Lien Credit Agreement” means the credit agreement dated 22 January 2008 between, among others, the Company, Bank of Scotland plc (in various capacities) and BNP Paribas (in various capacities) (as amended and restated from time to time).
1.2	Designation
	Each of the Company and the Second Lien Agent hereby designates this Agreement as a “Finance Document” for the purposes of (and as defined in) the Restated Second Lien Credit Agreement.
1.3	Counterparts
	This Agreement may be executed in any number of counterparts, and this has the same effect as if the signatures on the counterparts were on a single copy of this Agreement.
2.	AMENDMENT AND RESTATEMENT OF SECOND LIEN CREDIT AGREEMENT
2.1	Amendment
	On and from the date of this Agreement:

2.1.1 the Second Lien Credit Agreement shall be amended and restated so that it shall be read and construed for all purposes as set out in Schedule 2 (Form of Restated Second Lien Credit Agreement) to this Agreement; and

2.1.2 the Finance Documents shall be read and construed as if all references therein to the Second Lien Credit Agreement are references to the Restated Second Lien Credit Agreement as modified from time to time.

	Each of the New Obligors hereby agrees to be a party to, and to be bound by the terms of, the Restated Second Lien Credit Agreement in the relevant capacity(ies) in which it is expressed to be a party thereto.
2.2	Continuing effect
	The provisions of the Second Lien Credit Agreement shall, save as amended hereby, continue in full force and effect.
3.	INTERCREDITOR AGREEMENT
3.1	Amendment
	The Security Trustee confirms, pursuant to clause 8.3 of the Intercreditor Agreement that the Intercreditor Agreement shall be amended on the date of this Agreement such that it shall be read and construed for all purposes as set out in Schedule 3 (Form of Restated Intercreditor Agreement).
3.2	Consent

3.2.1	The Security Trustee confirms that the relevant quorum of the Secured Creditors has consented to the amendments to the Intercreditor Agreement that are effected pursuant to Clause 3.1 (Amendment).
3.2.2	To the extent that such consent is required under the Intercreditor Agreement, each of the parties to this Agreement confirms to the Security Trustee that it consents to the amendments to the Intercreditor Agreement that are effected pursuant to Clause 3.1 (Amendment).

4.	GOVERNING LAW
	This Agreement and any non-contractual obligations arising out of or in connection with it are governed by English law.

This Agreement has been entered into on the date stated at the beginning of this Agreement.

SIGNATORIES

SIGNED by	)	/s/ J. Michael Kirksey
	)
for and on behalf of	)
ENDEAVOUR INTERNATIONAL	)
CORPORATION	)

SIGNED by	)	/s/ J. Michael Kirksey
	)
for and on behalf of	)
ENDEAVOUR OPERATING	)
CORPORATION	)
SIGNED by	)	/s/ J. Michael Kirksey
	)
for and on behalf of	)
ENDEAVOUR ENERGY	)
NEW VENTURES INC.	)
COMPANY	)
SIGNED by	)	/s/ J. Michael Kirksey
	)
for and on behalf of	)
END MANAGEMENT COMPANY	)
SIGNED by	)	/s/ J. Michael Kirksey
	)
for and on behalf of	)
ENDEAVOUR ENERGY NORTH SEA, L.P.	)

SIGNED by	)	/s/ J. Michael Kirksey
	)
for and on behalf of	)
ENDEAVOUR ENERGY NORTH SEA LLC	)
SIGNED by	)	/s/ J. Michael Kirksey
	)
for and on behalf of	)
ENDEAVOUR INTERNATIONAL	)
HOLDING B.V.	)
SIGNED by	)	/s/ J. Michael Kirksey
	)
for and on behalf of	)
ENDEAVOUR ENERGY	)
NETHERLANDS B.V.	)
SIGNED by	)	/s/ J. Michael Kirksey
	)
for and on behalf of	)
by ENDEAVOUR ENERGY UK LIMITED	)
	)

SIGNED by	)	/s/ J. Michael Kirksey
	)
for and on behalf of	)
ENDEAVOUR NORTH SEA LIMITED	)
	)
SIGNED by	)	/s/ Aurelie Guth
	)
for and on behalf of	)
BANK OF SCOTLAND PLC	)
SIGNED by	)
	)	/s/ Remi Collonges-Duflouleur
for and on behalf of	)
BNP PARIBAS	)

SCHEDULE 1

PARTIES

Obligors

	Registration number (or
Name of Obligor	equivalent, if any)	Jurisdiction of incorporation
Endeavour International Corporation	C897-2000	Nevada, U.S.A.
Endeavour Operating Corporation	3737839	Delaware, U.S.A.
Endeavour Energy New Ventures Inc. (formerly, END Operating Management Company)	3900636	Delaware, U.S.A.
END Management Company	3900274	Delaware, U.S.A.
Endeavour Energy North Sea, L.P.	4591023	Delaware, U.S.A.
Endeavour Energy North Sea LLC	4621624	Delaware, U.S.A
Endeavour International Holding B.V.	34229293	Netherlands
Endeavour Energy Netherlands B.V.	34229296	Netherlands
Endeavour Energy UK Limited	5030838	England and Wales
Endeavour North Sea Limited	3518803	England and Wales

SCHEDULE 2

FORM OF RESTATED SECOND LIEN CREDIT AGREEMENT

SCHEDULE 2

FORM OF RESTATED SECOND LIEN CREDIT AGREEMENT

22 JANUARY 2008

ENDEAVOUR INTERNATIONAL CORPORATION

arranged by

BANK OF SCOTLAND PLC

$25,000,000
JUNIOR FACILITY AGREEMENT
as amended and restated on 5 February 2010

Herbert Smith LLP

TABLE OF CONTENTS

Clause	Headings	Page
1.	DEFINITIONS AND INTERPRETATION		1
2.	THE FACILITY		13
3.	PURPOSE		14
4.	CONDITIONS OF UTILISATION		14
5.	UTILISATION		14
6.	OPTIONAL CURRENCY		15
7.	REPAYMENT		17
8.	PREPAYMENT AND CANCELLATION		18
9.	INTEREST		21
10.	INTEREST PERIODS		22
11.	CHANGES TO THE CALCULATION OF INTEREST		23
12.	FEES		24
13.	TAX GROSS UP AND INDEMNITIES		25
14.	INCREASED COSTS		30
15.	OTHER INDEMNITIES		31
16.	MITIGATION BY THE LENDERS		33
17.	COSTS AND EXPENSES		33
18.	GUARANTEE AND INDEMNITY		34
19.	REPRESENTATIONS		37
20.	INFORMATION UNDERTAKINGS		43
21.	GENERAL UNDERTAKINGS		48
22.	FINANCIAL COVENANTS		60
23.	EVENTS OF DEFAULT		64
24.	CHANGES TO THE LENDERS		68
25.	CHANGES TO THE OBLIGORS		72
26.	ROLE OF THE ADMINISTRATIVE FINANCE PARTIES		75
27.	CONDUCT OF BUSINESS BY THE FINANCE PARTIES		80
28.	SHARING AMONG THE FINANCE PARTIES		81
29.	PAYMENT MECHANICS		82
30.	SET-OFF		84
31.	NOTICES		84
32.	CALCULATIONS AND CERTIFICATES		86
33.	PARTIAL INVALIDITY		86
34.	REMEDIES AND WAIVERS		86
35.	AMENDMENTS AND WAIVERS		87
36.	CONFIDENTIALITY		88

Clause	Headings	Page
37.	COUNTERPARTS		91
38.	GOVERNING LAW		92
39.	ENFORCEMENT		92
SCHEDULE 1 THE ORIGINAL OBLIGORS			93
SCHEDULE 2 THE ORIGINAL LENDERS			95
SCHEDULE 3 CONDITIONS PRECEDENT			96
SCHEDULE 4 REQUESTS			101
SCHEDULE 5 MANDATORY COST FORMULAE			112
SCHEDULE 6 FORM OF TRANSFER CERTIFICATE			115
SCHEDULE 7 FORM OF ASSIGNMENT AGREEMENT			118
SCHEDULE 8 FORM OF ACCESSION LETTER			121
SCHEDULE 9 CORPORATE ORGANISATION CHART			123

THIS AGREEMENT is dated 22 January 2008

BETWEEN:

(1)	ENDEAVOUR INTERNATIONAL CORPORATION (a corporation incorporated under the laws of the State of Nevada whose principal place of business is 1000 Main Street, Suite 3300, Houston, Texas, 77002, USA) (the “Company”);
(2)	THE AFFILIATES of the Company listed in Part I (The Original Borrowers) of Schedule 1 (The Original Obligors) as original borrowers (the “Original Borrowers”);
(3)	THE AFFILIATES of the Company listed in Part II (The Original Guarantors) of Schedule 1 (The Original Obligors) as original guarantors (together with the Company, the “Original Guarantors”);
(4)	BANK OF SCOTLAND PLC as Mandated Lead Arranger, Technical Bank, Original Lender and Agent; and
(5)	BNP PARIBAS as Security Trustee.

IT IS AGREED as follows:

5.	DEFINITIONS AND INTERPRETATION
5.1	Definitions
	In this Agreement:
	“Abandonment Date” means, in relation to each Borrowing Base Asset, the date on which it is assumed that production of Petroleum from that Borrowing Base Asset will no longer be commercially viable and the operation of such Borrowing Base Asset will cease for economic reasons.
	“Accession Letter” means a document substantially in the form set out in Schedule 7 (Form of Accession Letter).
	“Acquisition Agreement” means the Agreement dated 26th May 2006 between Paladin Resources Limited (1) Endeavour Energy UK Limited (2) and Endeavour International

Corporation (3) granting put and call options over the entire issued share capital of Endeavour North Sea (formerly, Talisman Expro Limited).

“Additional Borrower” means a company which becomes an Additional Borrower in accordance with Clause 29 (Changes to the Obligors).

“Additional Cost Rate” has the meaning given to it in Schedule 5 (Mandatory Cost formulae).

“Additional Financing” has the meaning given to it in Clause 12.3 (Mandatory prepayment).

“Additional Guarantor” means a company which becomes an Additional Guarantor in accordance with Clause 29 (Changes to the Obligors).

“Additional Obligor” means an Additional Borrower or an Additional Guarantor.

“Administrative Finance Parties” means each of the Mandated Lead Arranger, the Technical Bank, the Agent and the Security Trustee.

“Affiliate” means, in relation to any person, a Subsidiary of that person or a Holding Company of that person or any other Subsidiary of that Holding Company.

“Agent” means Bank of Scotland plc in its capacity as agent for the other Finance Parties or any other person that replaces it in such capacity in accordance with this Agreement.

“Agent’s Spot Rate of Exchange” means, in relation to any date, the Agent’s spot rate of exchange for the purchase of the relevant currency with dollars in the London foreign exchange market at or about 11.00 a.m. on the second Business Day prior to that date.

“Aggregate Commitments” means the sum of the Lenders’ Commitments.

“Amendment Effective Date” means the date on which the amendment and restatement of this Agreement takes effect pursuant to an amendment and restatement agreement dated 5 February 2010.

“Assignment Agreement” means an agreement substantially in the form set out in Schedule 7 (Form of Assignment Agreement) or any other form agreed between the relevant assignor and assignee.

“Authorisation” means an authorisation, consent, approval, resolution, licence, exemption, filing, notarisation or registration.

“Availability Period” means the period from and including the Amendment Effective Date to and including the date falling 30 days prior to the Final Maturity Date.

“Available Commitment” means a Lender’s Commitment minus:

(A)	the Dollar Amount of its participation in any outstanding Loans; and
(B)	in relation to any proposed Loan, the Dollar Amount of its participation in any Loans that are due to be made on or before the proposed Utilisation Date.

“Borrower” means an Original Borrower or an Additional Borrower.

“Borrower Group” means (i) Endeavour International Holding and its Subsidiaries for the time being other than any Non-Recourse Subsidiary and (ii) Endeavour Operating Corporation.

“Borrowing Base Asset” has the meaning given in the First Lien Credit Agreement.

“Break Costs” means the amount (if any) by which:

(A) the interest which a Lender should have received for the period from the date of receipt of all or any part of its participation in a Loan or Unpaid Sum to the last day of the

current Interest Period in respect of that Loan or Unpaid Sum, had the principal amount or Unpaid Sum received been paid on the last day of that Interest Period;

exceeds:

(B) the amount which that Lender would be able to obtain by placing an amount equal to the principal amount or Unpaid Sum received by it on deposit with a leading bank in the London interbank market for a period starting on the Business Day following receipt or recovery and ending on the last day of the current Interest Period.

“Business Day” means a day (other than a Saturday or Sunday or bank holiday) on which banks are open for general business in London and, in relation to any date for the payment or purchase of dollars, New York City.

“Commitment” means:

(A)	in relation to the Original Lender the amount (in dollars) set opposite its name under the heading “Commitment” in the table set out in Schedule 2 (The Original Lender); and
(B)	in relation to any other Lender, the amount of any Commitment transferred to it under this Agreement,

in each case, to the extent not cancelled, reduced or transferred by it under this Agreement.

“Confidential Information” means all information relating to the Company, any Obligor, the Group, the Finance Documents or the Facility of which a Finance Party becomes aware in its capacity as, or for the purpose of becoming, a Finance Party or which is received by a Finance Party in relation to, or for the purpose of becoming a Finance Party under, the Finance Documents or the Facility from either:

(A)	any member of the Group or any of its advisers; or
(B)	another Finance Party, if the information was obtained by that Finance Party directly or indirectly from any member of the Group or any of its advisers,

in whatever form, and includes information given orally and any document, electronic file or any other way of representing or recording information which contains or is derived or copied from such information but excludes information that:

(i)	is or becomes public information other than as a direct or indirect result of any breach by that Finance Party of Clause 30.13 (Confidentiality); or
(ii)	is identified in writing at the time of delivery as non-confidential by any member of the Group or any of its advisers; or
(iii)	is known by that Finance Party before the date the information is disclosed to it in accordance with paragraphs (A) or (B) above or is lawfully obtained by that Finance Party after that date, from a source which is, as far as that Finance Party is aware, unconnected with the Group and which, in either case, as far as that Finance Party is aware, has not been obtained in breach of, and is not otherwise subject to, any obligation of confidentiality.

“Confidentiality Undertaking” means a confidentiality undertaking substantially in a form from time to time recommended by the LMA or in any other form agreed between the Company and the Agent.

“Coverage Ratio” has the meaning given in Clause 26.7 (Reserves Value).

“CTA” means the Corporation Tax Act 2009.

“Default” means Event of Default or Potential Event of Default.

“Disruption Event” means either or both of:

(A)	a material disruption to those payment or communications systems or to those financial markets which are, in each case, required to operate in order for payments to be made in connection with the Facility (or otherwise in order for the transactions contemplated by the Finance Documents to be carried out) which disruption is not caused by, and is beyond the control of, any of the Parties; or
(B)	the occurrence of any other event which results in a disruption (of a technical or systems-related nature) to the treasury or payments operations of a Party preventing that, or any other Party;

(i)	from performing its payment obligations under the Finance Documents; or
(ii)	from communicating with other Parties in accordance with the terms of the Finance Documents,

(and which (in either such case)) is not caused by, and is beyond the control of, the Party whose operations are disrupted.

“Dollar Amount” means:

(A)

in relation to a proposed Loan or Loan denominated in dollars, the amount of that proposed Loan or (as the case may be) Loan;

(B)

in relation to a proposed Loan or Loan denominated in sterling, the amount of that proposed Loan, or (as the case may be) Loan, converted into dollars at the Agent’s Spot Rate of Exchange on the most recent valuation date (where “valuation date” means (i) the date which is three Business Days before the Utilisation Date for that Loan or, if later, the date the Agent receives the Utilisation Request for that Loan and (ii) any other date nominated by the Agent (acting reasonably)).

“Due Diligence Report” means the due diligence report from Ashurst referred to in, and delivered to the finance parties under the First Lien Credit Agreement pursuant to, the First Lien Credit Agreement.

“Dutch Borrower” means any Borrower which is incorporated in The Netherlands.

“Dutch Obligor” means any Obligor which is incorporated in The Netherlands.

“Effective Date” means the date on which the Agent issues a notice to the Company and the Lenders under Clause 8.1 (Initial conditions precedent).

“Endeavour International Holding” means Endeavour International Holding B.V., a private company with limited liability (besloten vennootschap met beperkte aansprakelijkheid) incorporated in The Netherlands having its corporate seat at Amsterdam, The Netherlands and its registered address at Teleportboulevard 140, 1043 EJ, Amsterdam, The Netherlands.

“Endeavour North Sea” means Endeavour North Sea Limited (formerly, Talisman Expro Limited), a company incorporated in England and Wales (Registered No. 03518803).

“Endeavour Operating Corporation” means Endeavour Operating Corporation, a Delaware corporation with corporate registration number 3737839 and whose registered office is at 1000 West Street, 17^th Floor, Wilmington, Delaware.

“Environmental Claims” means any claim by any person in connection with (i) a breach, or alleged breach, of an Environmental Law; (ii) any accident, fire, explosion or other event of any

type involving an emission or substance which is capable of causing harm to any living organism or the environment; or (iii) any other environmental contamination.

“Environmental Laws” means any law or regulation concerning (i) the protection of health and safety; (ii) the environment; or (iii) any emission or substance which is capable of causing harm to any living organism or the environment.

“Environmental Licence” means all Authorisations required by any Environmental Law for the ownership of an interest in, or the operation or development of, any Petroleum Asset.

“Equivalent Field Document” means, to the extent that any member of the Group is permitted to enter into the same under the Finance Documents, in relation to any Petroleum Asset that is not a Borrowing Base Asset:

(A)	each joint operating agreement and/or unitisation and unit operating agreement relating thereto, each agreement relating to the transportation, processing and/or storage of production therefrom and each agreement for the sale or marketing of production therefrom and each other major agreement relating to that Petroleum Asset and/or Petroleum produced therefrom;
(B)	any Authorisation required for the lawful exploitation, development or operation of that Petroleum Asset or the production, transportation or sale of Petroleum therefrom (and including, without limitation, any Petroleum production licence);
(C)	any development plan approved by any relevant operating committee and/or any appropriate governmental or other regulatory authority relating to that Petroleum Asset;
(D)	any documents relating to the acquisition by any member of the Group of any interests in that Petroleum Asset or of any entity holding the interest in that Petroleum Asset; and
(E)	any other document designated as such by the Company and the Agent.

“Event of Default” means any event or circumstance specified as such in Clause 27 (Events of Default).

“Facility” means the term loan credit facility described in Clause 6.1 (Facility).

“Facility Office” means the office or offices notified by a Lender to the Agent in writing on or before the date it becomes a Lender (or, following that date, by not less than five Business Days’ written notice) as the office or offices through which it will perform its obligations under this Agreement.

“Fee Letter” means each of:

(A)	any letter dated on or about the Amendment Effective Date between (i) all or any of the Obligors and (ii) all or any of the Administrative Finance Parties relating to the payment of fees by the Obligors (or any of them) to any such Administrative Finance Party(ies); and
(B)	any other letter designated as such by the Agent and the Company.

“Final Maturity Date” means the date falling 365 days after the Effective Date.

“Finance Document” means:

(A)	this Agreement;
(B)	any Security Document;
(C)	any Fee Letter;
(D)	any Transfer Certificate;

(E)	any Accession Letter;
(F)	any other Accession Instrument;
(G)	the Intercreditor Agreement; and
(H)	any other document designated as such by the Company and the Agent.

“Finance Party” means each of the Lenders, the Mandated Lead Arranger, the Technical Bank, the Security Trustee and the Agent.

“Financial Indebtedness” means, at the relevant date, any indebtedness for or in respect of:

(A)	moneys borrowed;
(B)	any acceptance credit;
(C)	any bond, note, debenture, loan stock, or other similar instrument;
(D)	any redeemable preference share;
(E)	any finance or capital lease;
(F)	receivables sold or discounted (otherwise than on a non-recourse basis);
(G)	the acquisition cost of any asset to the extent payable after its acquisition or possession by the party liable where the deferred payment is arranged primarily as a method of raising finance or financing the acquisition of that asset;
(H)	any derivative transaction protecting against or benefiting from fluctuations in any rate or price (and, except for non-payment of an amount, the then mark to market value of the derivative transaction will be used to calculate its amount);
(I)	any other transaction (including any forward sale or purchase agreement) which has the commercial effect of a borrowing;
(J)	any counter-indemnity obligation in respect of any guarantee, indemnity, bond, letter of credit or any other instrument issued by a bank or financial institution; or
(K)	any guarantee, indemnity or similar assurance against financial loss of any person in respect of any item referred to in paragraphs (A) to (J) above,

but excluding, for the avoidance of doubt, any indebtedness arising from the purchase of goods or services on normal credit terms in the ordinary course of business.

“GAAP/IFRS” means:

(A)	in relation to any member of the Group incorporated in the UK, generally accepted accounting principles in the UK; or
(B)	in relation to any member of the Group that is not incorporated in the UK, generally accepted accounting principles in that person’s jurisdiction of incorporation,

or, in each case, if IFRS has been implemented by the Group or the relevant member thereof, IFRS.

“Group” means Endeavour International Corporation and its Subsidiaries for the time being other than any Non-Recourse Subsidiary.

“Guarantor” means an Original Guarantor or an Additional Guarantor.

“Holding Company” means, in relation to a company or corporation, any other company or corporation in respect of which it is a Subsidiary.

“IFRS” means the International Financial Reporting Standards, International Accounting Standards and interpretations of those standards issued by the International Accounting Standards Board and the International Financial Reporting Interpretations Committee and their predecessor bodies.

“Information Package” means the written information and documents delivered to the Mandated Lead Arranger by any Obligor in connection with the negotiation of this Agreement on or before the Amendment Effective Date.

“Insolvency Officer” means any liquidator, trustee in bankruptcy, judicial custodian or manager, compulsory manager, receiver, administrative receiver, administrator, curator, bewindvoerder, vereffenaar or similar officer, in each case, appointed in any relevant jurisdiction.

“Insurances” means any insurances that are required to be maintained by, or on behalf of, any Obligor or any member of the Group in respect of the Borrowing Base Assets and/or any activities related thereto pursuant to this Agreement.

“Intercreditor Agreement” means the agreement dated 31 October 2006 between, among others, the Company, the Obligors as defined therein and the Finance Parties (as amended from time to time including pursuant to an amendment and restatement agreement dated on 5 February 2010).

“Interest Period” means, in relation to a Loan, each period determined in accordance with Clause 14 (Interest Periods) and, in relation to an Unpaid Sum, each period determined in accordance with Clause 13.3 (Default interest).

“ITA” means the Income Tax Act 2007.

“Key Asset” means each of:

(A)	the interest held by Endeavour Energy UK Limited in UK Petroleum Licence P226 relating to Block 15/27 (which block includes the discovery known as “Rochelle”);
(B)	the interest held by Endeavour Energy UK Limited in UK Petroleum Licence P1055 relating to Blocks 44/11a and 44/12a (which block includes the discovery known as “Cygnus”);
(C)	the interest held by Endeavour Energy UK Limited in UK Petroleum Licence P1314 relating to Block 23/16f (which block includes the discovery known as “Columbus”); and
(D)	any other Petroleum Asset which has been designated as such by the Agent, the Technical Bank and the Company.

“Lender” means:

(A)	the Original Lender; and
(B)	any bank, financial institution, trust, fund or other entity which has become a Party in accordance with Clause 28 (Changes to the Lenders),

which in each case has not ceased to be a Party in accordance with the terms of this Agreement.

“LIBOR” means, in relation to any Loan:

(A)	the applicable Screen Rate; or
(B)	(if no Screen Rate is available for the currency or the Interest Period of that Loan) the arithmetic mean of the rates (rounded upwards to four decimal places) as supplied to the

Agent at its request quoted by the Reference Banks to leading banks in the London interbank market,

as of 11.00 a.m. (London time) on the Quotation Day for the offering of deposits in the currency of that Loan and for a period comparable to the Interest Period for that Loan.

“LMA” means the Loan Market Association.

“Loan” means a loan made or to be made under the Facility or the principal amount outstanding for the time being of that loan.

“Majority Lenders” means:

(A)	if there are no Loans then outstanding, a Lender or Lenders whose Commitments aggregate 66 2/3% or more of the Aggregate Commitments (or, if the Aggregate Commitments have been reduced to zero, aggregated 66 2/3% or more of the Aggregate Commitments immediately prior to the reduction); or
(B)	at any other time, a Lender or Lenders whose participations in the Loans then outstanding aggregate 66 2/3% or more of all the Loans then outstanding.

“Mandatory Cost” means the percentage rate per annum calculated by the Agent in accordance with Schedule 5 (Mandatory Cost Formulae).

“Margin” means 8.00 per cent. per annum.

“Material Adverse Change” means any event, development or circumstance that has a material adverse effect on:

(A)	the ability of any Obligor to perform any of its payment obligations under any Finance Document as and when they fall due to be performed;
(B)	the business, property, operations or financial condition of the Obligors (taken as a whole);
(C)	the validity or enforceability of any provision of any Finance Document;
(D)	the rights and remedies of any Finance Party under any Finance Document; or
(E)	the validity, enforceability, effectiveness or priority of any Security created or purported to be created under the Finance Documents.

“Material Subsidiary” means each member of the Group whose:

(A)

profits (calculated before making allowances for Taxes) represent more than 10% of the aggregate profits of the Group (calculated before making allowances for Taxes) as shown by the latest audited consolidated accounts for the time being of the Company as adjusted in such manner as the Agent and the Company may agree (each acting reasonably) to be appropriate from time to time to take account of any matters occurring after the relevant balance sheet date; or

(B)

fixed assets (other than intangible assets) have a book value which represents more than 10% of the book value of the consolidated fixed assets (other than intangible assets) of the Group as shown by the latest audited consolidated accounts for the time being of the Company as adjusted in such manner as the Agent and the Company may agree (each acting reasonably) to be appropriate from time to time to take account of any matters occurring after the relevant balance sheet date.

“Month” means a period starting on one day in a calendar month and ending on the numerically corresponding day in the next calendar month, except that:

(A)	(subject to paragraph (C) below) if the numerically corresponding day is not a Business Day, that period shall end on the next Business Day in that calendar month in which that period is to end if there is one, or if there is not, on the immediately preceding Business Day;
(B)	if there is no numerically corresponding day in the calendar month in which that period is to end, that period shall end on the last Business Day in that calendar month; and
(C)	if an Interest Period begins on the last Business Day of a calendar month, that Interest Period shall end on the last Business Day in the calendar month in which that Interest Period is to end.

The above rules will only apply to the last Month of any period.

“Non Recourse Subsidiary” means any Subsidiary of the Company which:

(A) does not own directly or indirectly (by shareholding or otherwise) an interest in any Borrowing Base Asset; and

(B) which has been nominated as a “Non-Recourse Subsidiary” by the Company by written notice to the Agent.

“Obligor” means a Borrower or a Guarantor.

“Original Financial Statements” means:

(A)	in relation to the Company, the audited consolidated financial statements of the Company for the financial year ended 31 December 2008; and
(B)	in relation to each of the other Original Obligors, its financial statements or, if the same have been audited, audited financial statements for its financial year ended 31 December 2008.

“Original Lender” means Bank of Scotland plc.

“Original Obligor” means the Original Borrower or an Original Guarantor.

“Participating Member State” means any member state of the European Communities that adopts or has adopted the euro as its lawful currency in accordance with legislation of the European Community relating to Economic and Monetary Union.

“Party” means a party to this Agreement.

“Permitted Transaction” means:

(A)

an intra-group re-organisation on a solvent basis which does not involve any transfer of any of the Key Assets or Borrowing Base Assets, or any transfer of any shares that are the subject of any Security Document or any transfer of any shares in any member of the Group to a person that is not a member of the Group;

(B)

the transfer of any Borrowing Base Asset owned by Endeavour North Sea to Endeavour Energy UK Limited, on terms (i) whereby such asset remains a Borrowing Base Asset and (ii) that ensure that the Security Trustee continues to have Security over such Borrowing Base Asset upon the same, or more beneficial, terms as the Security granted in favour of the Security Trustee over such Borrowing Base Asset before such transfer and that the Security that the Security Trustee has over such Borrowing Base Asset is not prejudiced or adversely affected in any way;

(C)	the winding-up of Endeavour North Sea on a solvent basis at a time when it has no assets whatsoever and is not a Borrower or Guarantor; or
(B)	any other transaction agreed by the Majority Lenders.

“Petroleum” means any mineral, oil or relative hydrocarbon (including condensate and natural gas liquids) and natural gas existing in its natural condition in strata (but not including coal or bituminous shale or other stratified deposits from which oil can be extracted by destructive distillation).

“Petroleum Asset” means (i) any Petroleum field, pipeline transmission system or other Petroleum project, (ii) the facilities relating to such field, system or project and/or (iii) the interests in such field, system, project or facilities.

“Potential Event of Default” means any event or circumstances specified in Clause 27 (Events of Default) which would (with the expiry of a grace period, the giving of notice, the fulfilment of any condition, the making of any determination under the Finance Documents or any combination of the foregoing) be an Event of Default.

“Probable Reserves” means, in relation to any Petroleum Asset, those quantities of Petroleum which are deemed to be recoverable from the relevant petroleum field comprised in those Petroleum Assets as “Proved plus Probable Reserves” in accordance with the Society of Petroleum Engineers (provided that if such guidelines are modified after the date of such Agreement and as a result of such modification, the Technical Bank (acting reasonably in consultation with the Company) is of the opinion that such definition of the term “Probable Reserves” will need to be modified to take account of the relevant modification to such guidelines, then such definition shall be modified as required by the Technical Bank (acting reasonably in consultation with the Company and the Lenders).

“Project Documents” means:

(A) in relation to each Borrowing Base Asset:

(1)	each joint operating agreement and/or unitisation and unit operating agreement relating thereto, each agreement relating to the development thereof or the transportation, processing and/or storage of production therefrom and each agreement for the sale or marketing of production therefrom and each other major agreement relating to that Borrowing Base Asset and/or Petroleum produced therefrom;
(2)	any Authorisation required for the lawful exploitation, development or operation of that Borrowing Base Asset or the production, transportation or sale of Petroleum therefrom (and including, without limitation, any Petroleum production licence);
(3)	any development plan approved by any relevant operating committee and/or any appropriate governmental or other regulatory authority relating to that Borrowing Base Asset;

(B)	any documents relating to the acquisition by any member of the Borrower Group of any interests in any Borrowing Base Asset or of any entity holding the interest in such Borrowing Base Asset; and
(C)	any other document designated as such by the Company and the Agent.

“Projection” has the meaning given in the First Lien Credit Agreement.

“Qualifying Lender” has the meaning given to it in Clause 17 (Tax gross up and indemnities).

“Quotation Day” means, in relation to any period for which an interest rate is to be determined:

(A)	(if the currency is sterling) the first day of that period;
(B)	(if the currency is dollars) two Business Days before the first day of that period,

unless market practice differs in the London interbank market for that currency in which case the Quotation Day for that currency will be determined by the Agent in accordance with market practice in the London interbank market and if quotations would normally be given by leading banks in the London interbank market on more than one day, the Quotation Day will be the last of those days.

“Reference Banks” means the principal London offices of Bank of Scotland plc or such other banks as may be appointed by the Agent in consultation with the Company.

“Related Fund” in relation to a fund (the “first fund"), means a fund which is managed or advised by the same investment manager or investment adviser as the first fund or, if it is managed by a different investment manager or investment adviser, a fund whose investment manager or investment adviser is an Affiliate of the investment manager or investment adviser of the first fund.

“Relevant Affiliate” means, to the extent that it is not already an Obligor, any wholly-owned Subsidiary of the Company.

“Relevant Disposal” has the meaning given to it in Clause 12.3 (Mandatory prepayment).

“Relevant Net Proceeds” has the meaning given to it in Clause 12.3 (Mandatory prepayment).

“Relevant Repayment Proceeds” has the meaning given to it in Clause 12.3 (Mandatory prepayment).

“Repeating Representations” means each of the representations set out in Clause 23 (Representations) other than those in Clauses 23.6 (Pari passu ranking), 23.7 (Insolvency), 23.9 (Authorisations), 23.10 (Financial statements), 23.11 (No Material Adverse Change), 23.12 (Litigation), 23.13 (Information Package), 23.15 (Environmental matters), 23.18 (Laws and regulations), 23.19 (Insurances), 23.22 (Deduction of Tax), 23.23 (Ownership structure) and 23.25 (Share Security).

“Representative” means any delegate, agent, manager, administrator, nominee, attorney, trustee or custodian.

“Reserves Report” has the meaning given in the First Lien Credit Agreement.

“Screen Rate” means the British Bankers’ Association Interest Settlement Rate for the relevant currency and period, displayed on the appropriate page of the Telerate screen. If the agreed page is replaced or service ceases to be available, the Agent may specify another page or service displaying the appropriate rate after consultation with the Company and the Lenders.

“Security” means a mortgage, charge, pledge, lien or other security interest securing any obligation of any person or any other agreement or arrangement having a similar effect.

“Selection Notice” means a notice substantially in the form set out in Part II (Selection Notice) of Schedule 4 (Requests) given in accordance with Clause 14 (Interest Periods).

“Senior Finance Documents” means the Finance Documents (as defined in the First Lien Credit Agreement).

“Subsidiary” means a subsidiary undertaking within the meaning of section 1162 of the Companies Act 2006.

“Tax” means any tax, levy, impost, duty or other charge or withholding of a similar nature (including any penalty or interest payable in connection with any failure to pay or any delay in paying any of the same).

“Taxes Act” means the Income and Corporation Taxes Act 1988.

“Technical Bank” means Bank of Scotland plc in its capacity as technical bank for the other Finance Parties or any other person that replaces it in such capacity in accordance with this Agreement.

“Total Available Commitments” means the aggregate for the time being of all the Lenders’ Available Commitment.

“Transaction Documents” means the Project Documents and the Finance Documents.

“Transaction Party” means each Obligor and each other party (not being a Finance Party) who is party to any Finance Document.

“Transfer Certificate” means a certificate substantially in the form set out in Schedule 6 (Form of Transfer Certificate) or any other form agreed between the Agent and the Company.

“Transfer Date” means, in relation to an assignment or transfer, the later of:

(A)	the proposed Transfer Date specified in the relevant Assignment Agreement or Transfer Certificate; and
(B)	the date on which the Agent executes the relevant Assignment Agreement or Transfer Certificate.

	“Unpaid Sum” means any sum due and payable but unpaid by an Obligor under the Finance Documents.
	“Utilisation Date” means, in relation to any Loan, the date on which the Loan is made.
	“Utilisation Request” means a notice substantially in the form set out in Part I (Utilisation Requests) of Schedule 4 (Requests).
	“VAT” means value added tax as provided for in the Value Added Tax Act 1994 and any other tax of a similar nature.
5.2	Construction

5.2.1 Unless a contrary indication appears, any reference in this Agreement to:

(A)	any Finance Party or any Obligor or Transaction Party shall be construed so as to include its successors in title, permitted assigns and permitted transferees;
(B)	“assets” includes present and future properties, revenues and rights of every description;
(C)	any form of asset (including any Borrowing Base Asset or Key Asset) shall include a reference to (i) all or any part of that asset and (ii) (in the case of any Borrowing Base Asset or any Key Asset), the Petroleum field or other Petroleum Assets comprised therein;
(D)	a “Finance Document” or any other agreement or instrument is a reference to that Finance Document or other agreement or instrument as modified (however fundamentally and whether or not more onerously) and includes any change in the purpose of, any extension of or increase in any facility or addition of any new facility under that Finance Document or other agreement or instrument;

(E)	“indebtedness” includes any obligation (whether incurred as principal or as surety) for the payment or repayment of money, whether present or future, actual or contingent;
(F)	a “person” includes any individual, firm, company, corporation, government, state or agency of a state or any association, trust, joint venture, consortium or partnership (whether or not having separate legal personality) or two or more of the foregoing;
(G)	a “regulation” includes any regulation, rule, official directive, request or guideline (whether or not having the force of law but, if not having the force of law, being of a kind that is normally complied with by those to whom it is addressed) of any governmental, intergovernmental or supranational body, agency, department or regulatory, self-regulatory or other authority or organisation;
(H)	“disposal” means a sale, transfer, grant, lease or other disposal, whether voluntary or involuntary (and shall include any unitisation), and “dispose” will be construed accordingly;
(I)	a “guarantee” includes any form of indemnity or other assurance against financial loss (including any obligation to pay, purchase or provide funds for the purchase of any liability), and the verb “to guarantee” shall be construed accordingly;
(J)	a provision of law is a reference to that provision as amended or re-enacted;
(K)	a time of day is a reference to London time;
(L)	any matter “including” specific instances or examples of such matter shall be construed without limitation to the generality of that matter (and references to “include” shall be construed accordingly);
(M)	a “modification” includes an amendment, supplement, novation, re-enactment, restatement, variation, extension, replacement, modification or waiver or the giving of any waiver, release, consent having the same commercial effect of any of the foregoing (and “modify” shall be construed accordingly);
(N)	an amount in one currency that is “equivalent” to an amount in another currency shall be construed as meaning the amount of the second currency that can be obtained by converting the amount in the first currency into the second currency at the Agent’s spot rate of exchange for conversions between those two currencies at the relevant time;
(O)	the “winding-up”, “dissolution” or “administration” of a person shall be construed so as to include any equivalent or analogous proceedings under the law of the jurisdiction in which such person is incorporated or established, or any jurisdiction in which such person carries on business including the seeking of liquidation, winding-up, reorganisation, dissolution, administration, arrangement, adjustment, protection or relief of debtors;
(P)	“£” or “sterling” is the lawful currency for the time being of the United Kingdom of Great Britain and Northern Ireland; and
(Q)	“$” or “dollars” is to the lawful currency for the time being of the United States of America.

5.2.2	Clause and Schedule headings are for ease of reference only.
5.2.3	The words “other", “or otherwise” and “whatsoever” shall not be construed ejusdem generis or be construed as any limitation upon the generality of any preceding words or matters specifically referred to.
5.2.4	Unless a contrary indication appears, a term used in any other Finance Document or in any notice given under or in connection with any Finance Document has the same meaning in that Finance Document or notice as in this Agreement. Unless otherwise defined in this Agreement or unless the contrary is expressly specified in this Agreement, terms defined in the Intercreditor Agreement shall have the same meaning when used in this Agreement.
5.2.5	A Potential Event of Default is “continuing” if it has not been remedied or waived. An Event of Default is “continuing” if it has not been waived.
5.2.6	Unless a contrary intention appears, the obligation(s) of each Obligor and Transaction Party under this Agreement and/or the other Finance Documents shall remain in force for as long as any amount is or may be outstanding under the Finance Documents or any Commitment is in force.
5.2.7	If a moratorium (or other similar event in any jurisdiction) occurs in respect of an Obligor, the ending of that moratorium (or other such similar event) will not remedy any Event of Default caused by the moratorium (or other such similar event) and, notwithstanding any other term of the Finance Documents, that Event of Default will continue to be outstanding unless and until it is expressly waived by the Agent (acting on the instructions of the Majority Lenders).

5.3 Third party rights

5.3.1	Unless expressly provided to the contrary in a Finance Document, a person who is not a Party has no right under the Contracts (Rights of Third Parties) Act 1999 (the “Third Parties Act") to enforce or to enjoy the benefit of any term of this Agreement.
5.3.2	Notwithstanding any term of any Finance Document, the consent of any person who is not a Party is not required to rescind or vary this Agreement at any time.

6.	THE FACILITY
6.1	Facility
	Subject to the terms of this Agreement, the Lenders make available to the Borrowers a multicurrency term credit facility in an aggregate amount equal to the Aggregate Commitments.
6.2	Finance Parties’ rights and obligations

6.2.1	The obligations of each Finance Party under the Finance Documents are several. Failure by a Finance Party to perform its obligations under the Finance Documents does not affect the obligations of any other Party under the Finance Documents. No Finance Party is responsible for the obligations of any other Finance Party under the Finance Documents.
6.2.2	The rights of each Finance Party under or in connection with the Finance Documents are separate and independent rights and any debt arising under the Finance Documents to a Finance Party from an Obligor shall be a separate and independent debt.
6.2.3	A Finance Party may, except as otherwise stated in the Finance Documents, separately enforce its rights under the Finance Documents.

7.	PURPOSE
7.1	Purpose
	Each Borrower shall apply the proceeds of the Loans borrowed by it under the Facility in or towards:

7.1.1 the payment of the transaction costs relating to this Facility and its implementation; and

7.1.2 its lawful general corporate purposes.

7.2	Monitoring
	No Finance Party is bound to monitor or verify the application of any amount borrowed pursuant to this Agreement.
8.	CONDITIONS OF UTILISATION
8.1	Initial conditions precedent
	The Lenders will only be obliged to comply with Clause 9.4 (Lenders’ participation) if the Agent has received all of the documents and other evidence listed in Part I (CPs to first Loan) of Schedule 3 (Conditions precedent) in form and substance satisfactory to the Agent (acting on the instructions of all the Lenders). The Agent shall notify the Company and the Lenders promptly upon being so satisfied.
8.2	Further conditions precedent

8.2.1 The Lenders will only be obliged to comply with Clause 9.4 (Lenders’ participation) if on the date of the Utilisation Request and on the proposed Utilisation Date:

(A)	no Default is continuing or would result from the proposed Loan; and
(B)	the Repeating Representations to be made by each Obligor are true in all material respects.

8.2.2 The Lenders will only be obliged to comply with Clause 6.2 (Change of currency) if, on the first day of an Interest Period, no Default is continuing or would result from the change of currency and the Repeating Representations to be made by each Obligor are true in all material respects.

8.3 Maximum number of Loans

8.3.1	The Borrowers may not deliver more than three Utilisation Requests.
8.3.2	A Borrower may not request that a Loan be divided if, as a result of the proposed division, three or more Loans would be outstanding.

9.	UTILISATION
9.1	Delivery of a Utilisation Request
	A Borrower may request a Loan to be made by delivery to the Agent of a duly completed Utilisation Request not later than (in the case of the first Loan made under this Agreement) 1 p.m on the proposed Utilisation Date and (in the case of any other Loan) 10:00 a.m. on the third Business Day prior to the proposed Utilisation Date (or such later date as the Lenders may agree).
9.2	Completion of a Utilisation Request

9.2.1 Each Utilisation Request is irrevocable and will not be regarded as having been duly completed unless:

(A) the proposed Utilisation Date is a Business Day within the Availability Period;

(B)	the currency and amount of the Loan comply with Clause 9.3 (Currency and amount);
(C)	the proposed Interest Period complies with Clause 14 (Interest Periods);
(D)	it sets out the purposes of the Loan in such level of detail as may be satisfactory to the Agent (acting reasonably);
(E)	(unless all the Lenders otherwise approve) it includes a confirmation that the proceeds of the Loan will only be utilised for expenditure in relation to the Obligors’ operations in the United States of America or the United Kingdom; and
(F)	it has been duly signed by an authorised signatory of the relevant Borrower.

9.2.2 Only one Loan may be requested in each Utilisation Request.

9.3 Currency and amount

9.3.1	The currency specified in a Utilisation Request must be dollars or sterling.
9.3.2	The amount of the proposed Loan must be:

(A)	if the currency selected is dollars, a minimum of $5,000,000 or, if less, the Total Available Commitments; or
(B)	if the currency selected is sterling, a minimum of £3,000,000 or, if less, an amount (in sterling) the Dollar Amount of which is equal to the Total Available Commitments.

9.4 Lenders’ participation

9.4.1	If the conditions set out in this Agreement have been met, each Lender shall make its participation in each Loan available by the Utilisation Date through its Facility Office.
9.4.2	The amount of each Lender’s participation in each Loan will be equal to the proportion borne by its Available Commitment to the Total Available Commitments immediately prior to making the Loan.
9.4.3	The Agent shall determine the Dollar Amount of each Loan which is to be made in a currency other than dollars and shall notify each Lender of the amount, currency and Dollar Amount of each Loan and the amount of its participation in that Loan, in each case, not later than 5.00 p.m. on the (in the case of the first Loan made under the Facility) second and (in the case of any other Loan) third Business Day prior to the Utilisation Date for such Loan.

9.5	Cancellation of Commitment
	The Aggregate Commitments shall be immediately cancelled at the end of the Availability Period.
10.	OPTIONAL CURRENCY
10.1	Selection of currency

10.1.1 A Borrower (or the Company on behalf of a Borrower) shall select the currency of a Loan:

(A)	in the Utilisation Request for that Loan; and
(B)	(after that Loan has been made to it) in a Selection Notice.

10.1.2 If a Borrower (or the Company on behalf of a Borrower) fails to issue a Selection Notice in relation to a Loan, the Loan will remain denominated for its next Interest Period in the same currency in which it is then outstanding.

10.1.3 If a Borrower (or the Company on behalf of a Borrower) issues a Selection Notice requesting a change of currency and the first day of the requested Interest Period is not a Business Day for the new currency, the Agent shall promptly notify the Borrower and the Lenders and the Loan will remain in the existing currency (with Interest Periods running from one Business Day until the next Business Day) until the next day which is a Business Day for both currencies, on which day the requested Interest Period will begin.

10.2 Change of currency

10.2.1 If a Loan is to be denominated in different currencies during two successive Interest Periods:

(A)	if the currency for the second Interest Period is sterling, the amount of the Loan in sterling will be calculated by the Agent as the amount of sterling equal to the Dollar Amount of the Loan at the Agent’s Spot Rate of Exchange on the date which is three Business Days before the first day of the second Interest Period or, if later, on the date the Agent receives the Selection Notice;
(B)	if the currency for the second Interest Period is dollars, the amount of the Loan will be equal to the Dollar Amount;
(C)	(unless the Agent and the Borrower agree otherwise in accordance with Clause 10.2.2) the Borrower that has borrowed the Loan shall repay it on the last day of the first Interest Period in the currency in which it was denominated for that Interest Period; and
(D)	(subject to Clause 4.2 (Further conditions precedent)) the Lenders shall re-advance the Loan in the new currency in accordance with Clause 10.4 (Agent’s calculations).

10.2.2 If the Agent and the Borrower that has borrowed the Loan agree, the Agent shall:

(A) apply the amount paid to it by the Lenders pursuant to Clause 10.2.1(D) (or so much of that amount as is necessary) in or towards purchase of an amount in the currency in which the Loan is outstanding for the first Interest Period; and

(B) use the amount it purchases in or towards satisfaction of the relevant Borrower’s obligations under Clause 10.2.1(C).

10.2.3 If the amount purchased by the Agent pursuant to Clause 10.2.2(A) is less than the amount required to be repaid by the relevant Borrower, the Agent shall promptly notify that Borrower and that Borrower shall, on the last day of the first Interest Period, pay an amount to the Agent (in the currency of the outstanding Loan for the first Interest Period) equal to the difference.

10.2.4 If any part of the amount paid to the Agent by the Lenders pursuant to Clause 10.2.1(D) is not needed to purchase the amount required to be repaid by the relevant Borrower, the Agent shall promptly notify that Borrower and pay that Borrower, on the last day of the first Interest Period that part of that amount (in the new currency).

10.3 Same currency during successive Interest Periods

10.3.1 If a Loan is to be denominated in sterling during two successive Interest Periods, the Agent shall calculate the amount of the Loan in sterling for the second of those Interest Periods (by calculating the amount of sterling equal to the Dollar Amount of that Loan at the Agent’s Spot Rate of Exchange on the date which is three Business Days before the first day of the second Interest Period or, if later, on the date the Agent receives the Selection Notice) and (subject to Clause 10.3.2):

(A)	if the amount calculated is less than the existing amount of that Loan in sterling during the first Interest Period, promptly notify the Borrower that has borrowed that Loan and that Borrower shall pay, on the last day of the first Interest Period, an amount equal to the difference; or
(B)	if the amount calculated is more than the existing amount of that Loan in sterling during the first Interest Period, promptly notify each Lender and, if no Default is continuing, each Lender shall, on the last day of the first Interest Period, pay its participation in an amount equal to the difference.

10.3.2 If the calculation made by the Agent pursuant to Clause 10.3.1 shows that the amount of the Loan in sterling for the second of those Interest Periods converted into dollars at the Agent’s Spot Rate of Exchange on the date which is three Business Days before the first day of the second Interest Period or, if later, on the date the Agent receives the Selection Notice has increased or decreased by less than five per cent. compared to its Dollar Amount (taking into account any payments made pursuant to Clause 10.3.1), no notification shall be made by the Agent and no payment shall be required under Clause 10.3.1.

10.4 Agent’s calculations

10.4.1 All calculations made by the Agent pursuant to this Clause 10 (Optional currency) will take into account any repayment, prepayment, consolidation or division of Loans to be made on the last day of the first Interest Period.

10.4.2 Each Lender’s participation in a Loan will, subject to Clause 10.3.1, be determined in accordance with Clause 5.4 (Lenders’ participation).

11. REPAYMENT

11.1	Reduction of Facility The Aggregate Commitments shall reduce to zero on the Final Maturity Date.
11.2	Repayment of Loans

11.2.1	The Borrowers shall repay such amount of the Loans as is required to ensure that at all times the aggregate Dollar Amount of the Loans does not exceed the Aggregate Commitments at that time.
11.2.2	Without prejudice to Clause 11.2.1, the Borrowers shall repay the Loans on the Final Maturity Date.

11.3	Reborrowing
	No Borrower may reborrow any part of the Facility which is prepaid or repaid.

12.	PREPAYMENT AND CANCELLATION
12.1	Illegality
	If it becomes unlawful in any applicable jurisdiction for a Lender to perform any of its obligations as contemplated by this Agreement or to fund or maintain its participation in any Loan:

12.1.1 that Lender shall promptly notify the Agent upon becoming aware of that event;

12.1.2 upon the Agent notifying the Company, the Commitment of that Lender will be immediately cancelled; and

12.1.3 each Borrower shall repay that Lender’s participation in the Loans made to that Borrower on the last day of the Interest Period for each Loan occurring after the Agent has notified the Company or, if earlier, the date specified by the Lender in the notice delivered to the Agent (being no earlier than the last day of any applicable grace period permitted by law).

12.2 Change of control

12.2.1 If any person or group of persons acting in concert gains control of an Obligor:

(A)

the Company shall promptly notify the Agent upon becoming aware of that event;

(B)

if the Majority Lenders so require, the Agent shall, by not less than fifteen Business Days notice to the Company, cancel the Facility and declare all outstanding Loans, together with accrued interest, and all other amounts accrued under the Finance Documents immediately due and payable whereupon the Facility will be cancelled and all such outstanding amounts will become immediately due and payable.

12.2.2 For the purposes of Clause 12.2.1, “control” has the meaning given to such term in Section 416 of the Income and Corporation Taxes Act 1988 (whether or not that Act applies to any Obligor).

12.2.3 For the purposes of Clause 12.2.1, “acting in concert” has the meaning given to such term in the City Code on Takeovers and Mergers and the presumptions specified therein in relation to the term “acting in concert” shall apply to such term as used in this Agreement (whether or not that code applies to any Obligor).

12.3 Mandatory prepayment

12.3.1 For the purposes of this Clause 12.3 (Mandatory prepayment):

(A)

“Additional Financing” means the raising of funds or capital by the Company or any of its Subsidiaries which is carried out after the date of this Agreement (whether through the issue of shares, securities or other equity instruments, the issue of any bonds or other debt instruments, the borrowing from banks or other financial institutions, the incurrence of Financial Indebtedness or otherwise) other than pursuant to any loan agreement entered into between (i) the Company or any such Subsidiary and (ii) one or more banks or financial institutions in accordance with the terms of this Agreement solely for the purposes of financing the development of any Petroleum Asset in the United Kingdom in which a member of the Group has an interest;

(B)

“Relevant Disposal” means any disposal (other than any disposal under Clauses 25.5.2(A) to 25.5.2(E) and Clauses 25.5.2(G) to 25.5.2(I)) by any member of the Group of any of its interests in any Petroleum Assets (including

	any Borrowing Base Assets) or its shares in any member of the Group that holds any interest in any such Petroleum Assets;
(C)	“Relevant Net Proceeds” means, in relation to any Relevant Disposal, the proceeds of such Relevant Disposal that are due to the relevant member(s) of the Group carrying out such Relevant Disposal less the aggregate amount of all reasonable costs and expenses relating to such Relevant Disposal;
(D)	“Relevant Repayment Proceeds” means, in relation to any Relevant Disposal, the Relevant Net Proceeds of such Relevant Disposal less the Senior Outstanding Amount; and
(E)	"Senior Outstanding Amount” means, in relation to any Relevant Disposal, the sum of (i) the aggregate amount of the outstanding utilisations under the First Lien Credit Agreement that the Obligors are required to repay under the First Lien Credit Agreement as a result of that Relevant Disposal being effected; (ii) the aggregate amount of the accrued interest or commission that is due in respect of such outstanding utilisations and payable by the Obligor(s) as a result of that Relevant Disposal and (iii) the aggregate amount of the break costs payable by the Obligor(s) as a result of such repayment of the utilisations.

12.3.2 If:

(A)	any Relevant Disposal is carried out after the Amendment Effective Date; and
(B)	either:

(1)	the Relevant Net Proceeds of such Relevant Disposal exceeds $2,000,000 (or its equivalent in one or more other currencies); or
(2)	the sum of (a) the Relevant Net Proceeds of such Relevant Disposal and (b) the aggregate amount of the Relevant Net Proceeds of the other Relevant Disposals (if any) that have been carried out after the Amendment Effective Date exceed $10,000,000 (or its equivalent in one or more other currencies),

then on the first date on which any member of the Group receives any of the Relevant Net Proceeds for such Relevant Disposal:

(i) the Aggregate Commitments shall be cancelled by an amount equal to the Relevant Repayment Proceeds for that Relevant Disposal; and

(ii) the Borrowers shall repay such amount of the Loans as is required to ensure that the aggregate Dollar Amount of the Loans does not exceed the Aggregate Commitments (after the cancellation provided for under Clause 8.3.2(i)).

12.3.3	Any repayment made under Clause 8.3.2(ii) shall be applied against such Loans as may be determined by the Agent (acting reasonably in consultation with the Company).
12.3.4	On the date of the cancellation of any Aggregate Commitments pursuant to Clause 8.3.2(i), the Commitment of each Lender shall be reduced rateably.
12.3.5	If:

(A)	any Additional Financing is carried out; and
(B)	either:

(1) the aggregate amount received or receivable by the Company and/or the relevant Subsidiary(ies) of the Company pursuant to such Additional Financing exceeds $50,000,000 (or its equivalent in one or more other currencies); or

(2) the sum of (i) the aggregate amount received or receivable by the Company and/or the relevant Subsidiary(ies) of the Company pursuant to such Additional Financing and (ii) the aggregate amount received or receivable by the Company and/or the relevant Subsidiary(ies) of the Company pursuant to any prior Additional Financings (if any) exceeds $50,000,000 (or its equivalent in one or more other currencies),

then on the first date on which the Company and/or the relevant Subsidiary(ies) of the Company receive(s) any proceeds of such Additional Financing, the Facility shall be cancelled and the Borrowers shall repay all outstanding Loans (together with accrued interest and all other accrued amounts under the Finance Documents).

12.4 Voluntary cancellation

12.4.1 The Company may, if it gives the Agent not less than three Business Days’ (or such shorter period as the Majority Lenders may agree) prior notice, cancel the whole or any part (being a minimum amount of $5,000,000 of the Total Available Commitments).

12.4.2 On the date of the cancellation of any Total Available Commitments pursuant to Clause 12.4.1, the Commitment of each Lender shall be reduced rateably.

12.5	Voluntary prepayment of Loans
	A Borrower to which a Loan has been made may, if it gives the Agent not less than three Business Days’ (or such shorter period as the Majority Lenders may agree) prior notice, prepay the whole or any part of any Loan.
12.6	Right of repayment and cancellation in relation to a single Lender

12.6.1 If:

(A)	any sum payable to any Lender by an Obligor is required to be increased under Clause 17.2.3 (Tax gross-up); or
(B)	any Lender claims indemnification from the Company under Clause 17.3 (Tax indemnity) or Clause 18.1 (Increased costs),

the Company may, whilst the circumstance giving rise to the requirement for indemnification continues, give the Agent notice of cancellation of the Commitment of that Lender and its intention to procure the repayment of that Lender’s participation in the Loans.

12.6.2 On receipt of a notice referred to in Clause 12.6.1, the Commitment of that Lender shall immediately be reduced to zero.

12.6.3 On the last day of each Interest Period which ends after the Company has given notice under Clause 12.6.1 (or, if earlier, the date specified by the Company in that notice), each Borrower to which a Loan is outstanding shall repay that Lender’s participation in that Loan.

12.7 Restrictions

12.7.1 Any notice of cancellation or prepayment given by any Party under this Clause 12 (Prepayment and cancellation) shall be irrevocable and, unless a contrary indication appears in this Agreement, shall specify the date or dates upon which the relevant cancellation or prepayment is to be made and the amount of that cancellation or prepayment.

12.7.2 Any prepayment under this Agreement shall be made together with accrued interest on the amount prepaid and, subject to any Break Costs, without premium or penalty.

12.7.3 The Borrowers shall not repay or prepay all or any part of the Loans or cancel all or any part of the Commitments except at the times and in the manner expressly provided for in this Agreement.

12.7.4 No amount of the Commitments cancelled under this Agreement may be subsequently reinstated.

12.7.5 If the Agent receives a notice under this Clause 12 (Prepayment and cancellation) it shall promptly forward a copy of that notice to either the Company or the affected Lender, as appropriate.

12.7.6 If all or part of a Loan is repaid or prepaid and is not available for redrawing (other than by operation of Clause 8.2 (Further conditions precedent), an amount of the Commitments (equal to the Dollar Amount of the amount of the Loan which is repaid or prepaid) will be deemed to be cancelled on the date of repayment or prepayment. Any cancellation under this Clause 12.7.6 shall reduce the Commitments of the Lenders rateably.

13.	INTEREST
13.1	Calculation of interest
	The rate of interest on each Loan for each Interest Period is the percentage rate per annum which is the aggregate of the applicable:

13.1.1	Margin;
13.1.2	LIBOR; and
13.1.3	Mandatory Cost, if any.

13.2	Payment of interest
	The Borrower to which a Loan has been made shall pay accrued interest on that Loan on the last day of each Interest Period.
13.3	Default interest

13.3.1 If an Obligor fails to pay any amount payable by it under a Finance Document on its due date, interest shall accrue on the overdue amount from the due date up to the date of actual payment (both before and after judgment) at a rate which, subject to Clause 13.3.2, is two per cent. per annum higher than the rate which would have been payable if the overdue amount had, during the period of non-payment, constituted a Loan in the currency of the overdue amount for successive Interest Periods, each of a duration selected by the Agent (acting reasonably). Any interest accruing under this Clause 13.3 (Default interest) shall be immediately payable by the Obligor on demand by the Agent.

13.3.2 If any overdue amount consists of all or part of a Loan which became due on a day which was not the last day of an Interest Period relating to that Loan:

(A)	the first Interest Period for that overdue amount shall have a duration equal to the unexpired portion of the current Interest Period relating to that Loan; and
(B)	the rate of interest applying to the overdue amount during that first Interest Period shall be two per cent. higher than the rate which would have applied if the overdue amount had not become due.

13.3.3 Default interest (if unpaid) arising on an overdue amount will be compounded with the overdue amount at the end of each Interest Period applicable to that overdue amount but will remain immediately due and payable.

13.4	Notification of rates of interest
	The Agent shall promptly notify the Lenders and the relevant Borrower of the determination of a rate of interest under this Agreement.
14.	INTEREST PERIODS
14.1	Selection of Interest Periods

14.1.1 A Borrower (or the Company on behalf of a Borrower) may select an Interest Period for a Loan in the Utilisation Request for that Loan or (if the Loan has already been borrowed) in a Selection Notice.

14.1.2 Each Selection Notice for a Loan is irrevocable and must be delivered to the Agent by the Borrower (or the Company on behalf of a Borrower) to which that Loan was made no later than 10.00am on the third Business Day prior to the last day of the existing Interest Period for that Loan.

14.1.3 If a Borrower (or the Company) fails to deliver a Selection Notice to the Agent in accordance with Clause 14.1.2, the relevant Interest Period will be one Month.

14.1.4 Subject to this Clause 14 (Interest Periods), a Borrower (or the Company on its behalf) must select an Interest Period of one Month or any other period agreed between the Company and the Agent (acting on the instructions of all the Lenders).

14.1.5 An Interest Period for a Loan shall not extend beyond the Final Maturity Date.

14.1.6 Each Interest Period for a Loan shall start on the Utilisation Date or (if already made) on the last day of its preceding Interest Period.

14.2	Non-Business Days
	If an Interest Period would otherwise end on a day which is not a Business Day, that Interest Period will instead end on the next Business Day in that calendar month (if there is one) or the preceding Business Day (if there is not).
14.3	Consolidation and division of Loans

14.3.1 Subject to Clause 14.3.2, if two or more Interest Periods:

(A)	relate to Loans in the same currency;
(B)	end on the same date; and
(C)	are made to the same Borrower,

those Loans will, unless that Borrower (or the Company on its behalf) specifies to the contrary in the Selection Notice for the next Interest Period, be consolidated into, and treated as, a single Loan on the last day of the Interest Period.

14.3.2

Subject to Clause 8.3 (Maximum number of Loans) and Clause 9.3 (Currency and amount), if a Borrower (or the Company on its behalf) requests in a Selection Notice that a Loan be divided into two or more Loans, that Loan will, on the last day of its Interest Period, be so divided with Dollar Amounts specified in that Selection Notice, being an aggregate Dollar Amount equal to the Dollar Amount of the Loan immediately before its division.

15.	CHANGES TO THE CALCULATION OF INTEREST
15.1	Absence of quotations
	Subject to Clause 15.2 (Market disruption), if LIBOR is to be determined by reference to the Reference Banks but a Reference Bank does not supply a quotation by 11.00 a.m. (London time) on the Quotation Day, LIBOR shall be determined on the basis of the quotations of the remaining Reference Banks.
15.2	Market disruption

15.2.1 If a Market Disruption Event occurs in relation to a Loan for any Interest Period, then the rate of interest on each Lender’s share of that Loan for the Interest Period shall be the rate per annum which is the sum of:

(A)	the Margin;
(B)	the rate notified to the Agent by that Lender as soon as practicable and in any event before interest is due to be paid in respect of that Interest Period, to be that which expresses as a percentage rate per annum the cost to that Lender of funding its participation in that Loan from whatever source it may reasonably select; and
(C)	the Mandatory Cost, if any, applicable to that Lender’s participation in the Loan.

15.2.2 In this Agreement “Market Disruption Event” means:

(A)	at or about noon on the Quotation Day for the relevant Interest Period the Screen Rate is not available and none or only one of the Reference Banks supplies a rate to the Agent to determine LIBOR for the relevant currency and Interest Period; or
(B)	before close of business in London on the Quotation Day for the relevant Interest Period, the Agent receives notifications from a Lender or Lenders (whose participations in a Loan exceed 25 per cent. of that Loan) that the cost to it or them of obtaining matching deposits in the London interbank market would be in excess of LIBOR.

15.3 Alternative basis of interest or funding

15.3.1	If a Market Disruption Event occurs and the Agent or the Company so requires, the Agent and the Company shall enter into negotiations (for a period of not more than thirty days) with a view to agreeing a substitute basis for determining the rate of interest.
15.3.2	Any alternative basis agreed pursuant to Clause 15.3.1 shall, with the prior consent of all the Lenders and the Company, be binding on all Parties.

15.4 Break Costs

15.4.1 Each Borrower shall, within three Business Days of demand by a Finance Party, pay to that Finance Party its Break Costs attributable to all or any part of a Loan or Unpaid Sum being paid by that Borrower on a day other than the last day of an Interest Period for that Loan or Unpaid Sum.

15.4.2 Each Lender shall, as soon as reasonably practicable after a demand by the Agent, provide a certificate confirming the amount of its Break Costs for any Interest Period in which they accrue and showing how that amount was calculated.

16.	FEES
16.1	Commitment fee
	The Borrowers shall pay to the Agent (for the account of each Lender) in respect of each Fee Period a fee computed at the Commitment Rate on the daily amount (if any) by which the Aggregate Commitments exceed the aggregate Dollar Amount of the Loans.
16.2	Computation and payment

16.2.1	Any commitment fee payable under this Clause 16 (Fees) must be paid by the relevant Borrower(s) within two Business Days after receipt by the Company of the calculation of such commitment fee or, as the case may be, such letter of credit commission from the Agent under Clause 16.2.3.
16.2.2	Any such commitment fee must be paid in dollars.
16.2.3	The Agent shall calculate the commitment fee payable for each Fee Period and shall notify the Company of the same within five Business Days after the end of the relevant Fee Period. Each such calculation shall, in the absence of manifest error, be conclusive evidence of the amount thereof.

16.3	Definitions
	For the purposes of this Agreement:

16.3.1	“Commitment Rate” means 4.00 per cent. per annum; and
16.3.2	“Fee Period” means:

(A)	the period commencing on the Amendment Effective Date and ending on the first quarter date to occur thereafter; and thereafter,
(B)	each successive period of three months (or, in the case of the last such period, less) commencing on the day after a quarter date and ending on the first quarter date to occur thereafter (or, in the case of the last such period, on the Final Maturity Date),

where for these purposes, “quarter date” means each 31 March, 30 June, 30 September and 31 December of each year.

16.4	Other fees and costs
	The Borrowers will pay to the relevant Finance Parties the relevant fees and other costs and expenses in the amounts and at the times set out in the Fee Letters.

16.5 Representatives

16.5.1 Subject to Clause 16.5.2 below, the Company shall, (or shall procure that an Obligor will) within five Business Days of demand by the Agent or the Security Trustee pay, or

reimburse the relevant Administrative Finance Party for any payments that it has made in relation to, any reasonable fees, costs and expenses that the relevant Administrative Finance Party has properly incurred in connection with the appointment by such Administrative Finance Party of any legal adviser, insurance adviser, environmental consultant, engineering consultant, model auditor or tax model auditor, in each case, in connection with the exercise of its rights and discretions or the performance of its duties and obligations, under the Finance Documents.

16.5.2

Save to the extent that such fees, costs and expenses have been incurred in circumstances where a Default has occurred, the Company shall only be obliged to pay or reimburse (or shall procure that an Obligor will pay or reimburse) the relevant Administrative Finance Party for any fees, costs and expenses incurred by it if the Company has approved the appointment of the relevant adviser, consultant or auditor and the terms (including fees) of the appointment (such approval not to be unreasonably withheld or delayed).

17. TAX GROSS UP AND INDEMNITIES

17.1 Definitions

17.1.1	In this Agreement:
	“Protected Party” means a Finance Party which is or will be subject to any liability, or required to make any payment, for or on account of Tax in relation to a sum received or receivable (or any sum deemed for the purposes of Tax to be received or receivable) under a Finance Document.
	“Qualifying Lender” means:

(A) a Lender (other than a Lender within paragraph (B) below) which is beneficially entitled to interest payable to that Lender in respect of an advance under a Finance Document and is:

(1) a Lender:

(a)	which is a bank (as defined for the purpose of section 879 of the ITA) making an advance under a Finance Document; or
(b)	in respect of an advance made under a Finance Document by a person that was a bank (as defined for the purpose of section 879 of the ITA) at the time that that advance was made,

	and which is within the charge to United Kingdom corporation tax as respects any payments of interest made in respect of that advance; or
(2)	a Lender which is:

(a) a company resident in the United Kingdom for United Kingdom tax purposes;

(b) a partnership each member of which is

(i) a company so resident in the United Kingdom; or

(ii) a company not so resident in the United Kingdom which carries on a trade in the United Kingdom through a permanent establishment and which brings into account in computing its chargeable profits (within the meaning of section 19 of the CTA) the whole of any

share of interest payable in respect of that advance that falls to it by reason of Part 17 of the CTA;

(c) a company not so resident in the United Kingdom which carries on a trade in the United Kingdom through a permanent establishment and which brings into account interest payable in respect of that advance in computing its chargeable profits (within the meaning of section 19 of the CTA) of that company; or

(3) a Treaty Lender; or

(B) a building society (as defined for the purposes of section 880 of the ITA) making an advance under a Finance Document.

“Tax Confirmation” means a confirmation by a Lender that the person beneficially entitled to interest payable to that Lender in respect of an advance under a Finance Document is:

(C)	a company resident in the United Kingdom, for United Kingdom tax purposes;
(D)	a partnership each member of which is:

(1)	a company so resident in the United Kingdom; or
(2)	a company not so resident in the United Kingdom which carries on a trade in the United Kingdom through a permanent establishment and which brings into account in computing its chargeable profits (within the meaning of section 19 of the CTA) the whole of any share of interest payable in respect of that advance that falls to it by reason of Part 17 of the CTA; or

(E) a company not so resident in the United Kingdom which carries on a trade in the United Kingdom through a permanent establishment and which brings into account interest payable in respect of that advance in computing its chargeable profits (within the meaning of section 19 of the CTA) of that company.

“Tax Credit” means a credit against, relief or remission for, or repayment of any Tax.

“Tax Deduction” means a deduction or withholding for or on account of Tax from a payment under a Finance Document.

“Tax Payment” means either the increase in a payment made by an Obligor to a Finance Party under Clause 17.2 (Tax gross-up) or a payment under Clause 17.3 (Tax indemnity).

“Treaty Lender” means a Lender which:

(F)

in the case of an Obligor which is resident in the United Kingdom, is treated as a resident of a Treaty State for the purposes of the Treaty and does not carry on a business in the United Kingdom through a permanent establishment with which that Lender’s participation in the Loan is effectively connected; or

(G)

in the case of an Obligor which is not resident in the United Kingdom, is treated as resident in a jurisdiction which has a double taxation agreement with the jurisdiction in which the Obligor is resident or treated as resident, which double tax treaty makes provision (subject to satisfaction of any conditions provided therein) for full exemption from Tax Deductions imposed by the jurisdiction in which the Obligor is resident or treated as resident.

“Treaty State” means a jurisdiction having a double taxation agreement (a “Treaty”) with the United Kingdom which makes provision for full exemption from tax imposed by the United Kingdom on interest.

“UK Non-Bank Lender” means:

(H)	where a Lender becomes a Party to this Agreement on the Amendment Effective Date, a Lender listed in Schedule 2 (The Original Lenders) and identified as a “UK Non-Bank Lender” in that Schedule; and
(I)	where a Lender becomes a Party after the Amendment Effective Date, a Lender which gives a Tax Confirmation in the Assignment Agreement or Transfer Certificate which it executes on becoming a Party.

17.1.2 Unless a contrary indication appears, in this Clause 17 (Tax gross-up and indemnities) a reference to “determines” or “determined” means a determination made in the absolute discretion of the person making the determination.

17.2 Tax gross-up

17.2.1 Each Obligor shall make all payments to be made by it without any Tax Deduction, unless a Tax Deduction is required by law.

17.2.2 The Company shall promptly upon becoming aware that an Obligor must make a Tax Deduction (or that there is any change in the rate or the basis of a Tax Deduction) notify the Agent accordingly. Similarly, a Lender shall notify the Agent on becoming so aware in respect of a payment payable to that Lender. If the Agent receives such notification from a Lender it shall notify the Company and that Obligor.

17.2.3 If a Tax Deduction is required by law to be made by an Obligor, the amount of the payment due from that Obligor shall be increased to an amount which (after making any Tax Deduction) leaves an amount equal to the payment which would have been due if no Tax Deduction had been required.

17.2.4 A payment shall not be increased under Clause 17.2.3 above by reason of a Tax Deduction on account of Tax imposed by the United Kingdom, if on the date on which the payment falls due:

(A)

the payment could have been made to the relevant Lender without a Tax Deduction if the Lender had been a Qualifying Lender, but on that date that Lender is not or has ceased to be a Qualifying Lender other than as a result of any change after the date it became a Lender under this Agreement in (or in the interpretation, administration, or application of) any law or Treaty, or any published practice or published concession of any relevant taxing authority; or

(B)

(1)	the relevant Lender is a Qualifying Lender solely by virtue of paragraph (A)(2) of the definition of “Qualifying Lender” set out in Clause 17.1.1 (Definitions); and
(2)	an officer of H.M. Revenue & Customs has given (and not revoked) a direction (a “Direction”) under section 931 of the ITA which relates to the payment and that Lender has received from the Obligor making the payment or from the Company a certified copy of that Direction; and
(3)	the payment could have been made to the Lender without any Tax Deduction if that Direction had not been made; or

(C) the relevant Lender is a Qualifying Lender solely by virtue of paragraph (A)(2) of the definition of “Qualifying Lender” set out in Clause 17.1.1 (Definitions) and:

(1)	the relevant Lender has not given a Tax Confirmation to the Company; and
(2)	the payment could have been made to the Lender without any Tax Deduction if the Lender had given a Tax Confirmation to the Company, on the basis that the Tax Confirmation would have enabled the Company to have formed a reasonable belief that the payment was an “excepted payment” for the purpose of section 930 of the ITA; or

(D) the relevant Lender is a Treaty Lender and the Obligor making the payment is able to demonstrate that the payment could have been made to the Lender without the Tax Deduction had that Lender complied with its obligations under Clause 17.2.7 below.

17.2.5 If an Obligor is required to make a Tax Deduction, that Obligor shall make that Tax Deduction and any payment required in connection with that Tax Deduction within the time allowed and in the minimum amount required by law.

17.2.6 Within thirty days of making either a Tax Deduction or any payment required in connection with that Tax Deduction, the Obligor making that Tax Deduction shall deliver to the Agent for the Finance Party entitled to the payment a statement under section 975 of the ITA or other evidence reasonably satisfactory to that Finance Party that the Tax Deduction has been made or (as applicable) any appropriate payment paid to the relevant taxing authority.

17.2.7 A Treaty Lender and each Obligor which makes a payment to which that Treaty Lender is entitled shall co-operate in completing any procedural formalities necessary for that Obligor to obtain authorisation to make that payment without a Tax Deduction.

17.2.8 A UK Non-Bank Lender which becomes a Party on the Amendment Effective Date gives a Tax Confirmation to the Company by entering into this Agreement.

17.2.9 A UK Non-Bank Lender shall promptly notify the Company and the Agent if there is any change in the position from that set out in the Tax Confirmation.

17.3 Tax indemnity

17.3.1 The Company shall (or shall procure that an Obligor will) (within three Business Days of demand by the Agent, such demand to be accompanied by a written calculation of the amount claimed by the Protected Party) pay to a Protected Party an amount equal to the loss, liability or cost which that Protected Party determines will be or has been (directly or indirectly) suffered for or on account of Tax by that Protected Party in respect of a Finance Document.

17.3.2 Clause 17.3.1 above shall not apply:

(A) with respect to any Tax assessed on a Finance Party:

(1) under the law of the jurisdiction in which that Finance Party is incorporated or, if different, the jurisdiction (or jurisdictions) in which that Finance Party is treated as resident for tax purposes; or

(2) under the law of the jurisdiction in which that Finance Party’s Facility Office is located in respect of amounts received or receivable in that jurisdiction,

	if that Tax is imposed on or calculated by reference to the net income received or receivable (but not any sum deemed to be received or receivable) by that Finance Party; or
(B)	to the extent a loss, liability or cost:

(1) is compensated for by an increased payment under Clause 17.2 (Tax gross-up); or

(2) would have been compensated for by an increased payment under Clause 17.2 (Tax gross-up) but was not so compensated solely because one of the exclusions in Clause 17.2.4 (Tax gross up) applied.

17.3.3 A Protected Party making, or intending to make a claim under Clause 17.3.1 above shall promptly notify the Agent of the event which will give, or has given, rise to the claim, following which the Agent shall notify the Company.

17.3.4 A Protected Party shall, on receiving a payment from an Obligor under this Clause 17.3 (Tax indemnity), notify the Agent.

17.4	Tax Credit
	If an Obligor makes a Tax Payment and the relevant Finance Party determines that:

17.4.1 a Tax Credit is attributable either to an increased payment of which that Tax Payment forms part, or to that Tax Payment; and

17.4.2 that Finance Party has obtained, utilised and retained that Tax Credit,

the Finance Party shall pay an amount to the Obligor which that Finance Party determines will leave it (after that payment) in the same after-Tax position as it would have been in had the Tax Payment not been required to be made by the Obligor.

17.5 Lender status confirmation

17.5.1 Each Lender which becomes a Party to this Agreement after the Amendment Effective Date shall indicate, in the Transfer Certificate or Assignment Agreement which it executes on becoming a Party, and for the benefit of the Agent and without liability to any Obligor, which of the following categories it falls in:

(A)	not a Qualifying Lender;
(B)	a Qualifying Lender (other than a Treaty Lender); or
(C)	a Treaty Lender.

17.5.2 If a New Lender fails to indicate its status in accordance with this Clause 17.5 (Lender status confirmation) then such New Lender shall be treated for the purposes of this Agreement (including by each Obligor) as if it is not a Qualifying Lender until such time as it notifies the Agent which category applies (and the Agent, upon receipt of such notification, shall inform the Company). For the avoidance of doubt, a Transfer Certificate or Assignment Agreement shall not be invalidated by any failure of a Lender to comply with this Clause 17.5 (Lender status confirmation).

17.6	Stamp taxes
	The Company shall (or shall procure that an Obligor will) pay and, within three Business Days of demand, indemnify each Finance Party against any cost, loss or liability that Finance Party incurs in relation to all stamp duty, registration and other similar Taxes payable in respect of any Finance Document (other than a Transfer Certificate).
17.7	Value added tax

17.7.1 All amounts set out, or expressed in a Finance Document to be payable by any Party to a Finance Party which (in whole or in part) constitute the consideration for a supply or supplies for VAT purposes shall be deemed to be exclusive of any VAT which is chargeable on such supply, and accordingly, subject to Clause 17.7.3 (Value added tax), if VAT is or becomes chargeable on any supply made by any Finance Party to any Party under a Finance Document, that Party shall pay to the Finance Party (in addition to and at the same time as paying any other the consideration for such supply) an amount equal to the amount of such VAT (and such Finance Party shall promptly provide an appropriate VAT invoice to such Party).

17.7.2 If VAT is or becomes chargeable on any supply made by any Finance Party (the “Supplier") to any other Finance Party (the “Recipient") under a Finance Document, and any Party other than the Recipient (the “Subject Party") is required by the terms of any Finance Document to pay an amount equal to the consideration for such supply to the Supplier (rather than being required to reimburse the Recipient in respect of that consideration), such Party shall also pay to the Supplier (in addition to and at the same time as paying such amount) an amount equal to the amount of such VAT. The Recipient will promptly pay to the Subject Party an amount equal to any credit or repayment obtained by the Recipient Party from the relevant tax authority which the Recipient Party reasonably determines in respect of such VAT.

17.7.3 Where a Finance Document requires any Party to reimburse or indemnify a Finance Party for any cost or expense, that Party shall reimburse or indemnify (as the case may be) such Finance Party for the full amount of such cost or expense, including such part thereof that represents VAT, save to the extent that such Finance Party reasonably determines that it is entitled to credit or repayment in respect of such VAT from the relevant tax authority.

17.7.4 Any reference in this Clause 17.7 (Value added tax) to any Party shall, at any time when such Party is treated as a member of a group for VAT purposes, included (where appropriate and unless the context otherwise requires) a reference to the representative member of such group at such time (the term “representative member” to have the same meaning in the Value Added Tax Act 1994).

18.	INCREASED COSTS
18.1	Increased costs

18.1.1 Subject to Clause 18.3 (Exceptions), the Company shall (or shall procure that an Obligor will), within three Business Days of a demand by the Agent, pay for the account of a Finance Party the amount of any Increased Costs incurred by that Finance Party or any of its Affiliates as a result of (i) the introduction of or any change in (or in the interpretation, administration or application of) any law or regulation or (ii) compliance with any law or regulation made after the Amendment Effective Date.

18.1.2 In this Agreement “Increased Costs” means:

(A)	a reduction in the rate of return from the Facility or on a Finance Party’s (or its Affiliate’s) overall capital;
(B)	an additional or increased cost; or
(C)	a reduction of any amount due and payable under any Finance Document,

which is incurred or suffered by a Finance Party or any of its Affiliates to the extent that it is attributable to that Finance Party having entered into its Commitment or funding or performing its obligations under any Finance Document.

18.2 Increased cost claims

18.2.1 A Finance Party intending to make a claim pursuant to Clause 18.1 (Increased costs) shall notify the Agent of the event giving rise to the claim, following which the Agent shall promptly notify the Company.

18.2.2 Each Finance Party shall, as soon as practicable after a demand by the Agent or the Company, provide a certificate confirming the amount of its Increased Costs and setting out the calculation of such amount in reasonable detail.

18.3 Exceptions

18.3.1 Clause 18.1 (Increased costs) does not apply to the extent any Increased Cost is:

(A)	attributable to a Tax Deduction required by law to be made by an Obligor;
(B)	compensated for by Clause 17.3 (Tax indemnity) (or would have been compensated for under Clause 17.3 (Tax indemnity) but was not so compensated solely because any of the exclusions in Clause 17.3.2 (Tax indemnity) applied);
(C)	compensated for by the payment of the Mandatory Cost;
(D)	attributable to the wilful breach by the relevant Finance Party or its Affiliates of any law or regulation or any Finance Document to which it is a party; or
(E)	attributable to the implementation or application of or compliance with the Basle II Accord or any law or regulation which implements the Basle II Accord.

18.3.2 In this Clause 18.3 (Exceptions):

(A)	a reference to a “Tax Deduction” has the same meaning given to the term in Clause 17.1 (Definitions); and
(B)	“Basle II Accord” means the paper titled “International Convergence of Capital Measurement and Capital Standards, a Revised Framework” published by the Basle Committee on Banking Supervision in June 2004 in the form existing as at the Amendment Effective Date.

19.	OTHER INDEMNITIES
19.1	Currency indemnity

19.1.1 If any sum due from an Obligor under the Finance Documents (a “Sum"), or any order, judgment or award given or made in relation to a Sum, has to be converted from the currency (the “First Currency") in which that Sum is payable into another currency (the “Second Currency") for the purpose of:

(A)	making or filing a claim or proof against that Obligor; or
(B)	obtaining or enforcing an order, judgment or award in relation to any litigation or arbitration proceedings,

	that Obligor shall as an independent obligation, within three Business Days of demand, indemnify each Finance Party to whom that Sum is due against any cost, loss or liability arising out of or as a result of the conversion including any discrepancy between (i) the rate of exchange used to convert that Sum from the First Currency into the Second Currency and (ii) the rate or rates of exchange available to that person at the time of its receipt of that Sum.
19.1.2	Without prejudice to Clause 19.1.1, each Obligor shall as an independent obligation, within three Business Days of demand, indemnify each Finance Party against any cost, loss or liability which that Finance Party incurs as a result of that Finance Party receiving an amount in respect of that Obligor’s liability under any Finance Document in a currency other than the currency in which that liability is expressed to be payable under that Finance Document.
19.1.3	Each Obligor waives any right it may have in any jurisdiction to pay any amount under the Finance Documents in a currency or currency unit other than that in which it is expressed to be payable.

19.2	Other indemnities
	The Company shall (or shall procure that an Obligor will), within three Business Days of demand, indemnify each Finance Party against any cost, loss or liability incurred by that Finance Party as a result of:

19.2.1 the occurrence of any Event of Default;

19.2.2 a failure by an Obligor to pay any amount due under a Finance Document on its due date, including, any cost, loss or liability arising as a result of Clause 32 (Sharing among the Finance Parties);

19.2.3 funding, or making arrangements to fund, its participation in a Loan requested by a Borrower in a Utilisation Request but not made by reason of the operation of any one or more of the provisions of this Agreement (other than by reason of default or negligence by that Finance Party alone);

19.2.4 a Loan (or part of a Loan) not being prepaid in accordance with a notice of prepayment given hereunder; or

19.2.5 the release of any Security constituted by any Finance Document or any release of any Obligor which is permitted under the Finance Documents.

19.3	Indemnity to the Agent
	The Company shall (or shall procure that an Obligor will) promptly indemnify the Agent against any cost, loss or liability incurred by the Agent (acting reasonably) as a result of:

19.3.1 investigating any event which it reasonably believes is a Default;

19.3.2 entering into or performing any foreign exchange contract for the purposes of Clause 10.2.2 (Change of currency); or

19.3.3 acting or relying on any notice, request or instruction which it reasonably believes to be genuine, correct and appropriately authorised.

20.	MITIGATION BY THE LENDERS
20.1	Mitigation

20.1.1 Each Finance Party shall, in consultation with the Company, take all reasonable steps to mitigate any circumstances which arise and which would result in any amount becoming payable under or pursuant to, or cancelled pursuant to, any of Clause 12.1 (Illegality), Clause 17 (Tax gross-up and indemnities), Clause 18 (Increased costs) or paragraph 3 of Schedule 5 (Mandatory Cost Formulae) including transferring its rights and obligations under the Finance Documents to another Affiliate or Facility Office.

20.1.2 Clause 20.1.1 does not in any way limit the obligations of any Obligor under the Finance Documents.

20.2 Limitation of liability

20.2.1 The Company shall (or shall procure that an Obligor will) indemnify each Finance Party for all costs and expenses reasonably incurred by that Finance Party as a result of steps taken by it under Clause 20.1 (Mitigation).

20.2.2 A Finance Party is not obliged to take any steps under Clause 20.1 (Mitigation) if, in the opinion of that Finance Party (acting reasonably), to do so might be prejudicial to it.

21.	COSTS AND EXPENSES
21.1	Transaction expenses
	The Company shall (or shall procure that an Obligor will) promptly on demand pay the Administrative Finance Parties the amount of all costs and expenses (including legal fees) reasonably incurred by any of them in connection with:

21.1.1 the negotiation, preparation, printing, execution and syndication of:

(A)	this Agreement and any other documents referred to in this Agreement; and
(B)	any other Finance Documents (other than a Transfer Certificate or Assignment Agreement) executed after the Amendment Effective Date; and

21.1.2 the completion of the transactions and perfection of the Security intended to be created pursuant to the Security Documents,

	subject to any applicable cap agreed between the Company and the Agent.
21.2	Amendment costs
	If (a) a relevant party requests an amendment, waiver or consent to any Finance Document or (b) an amendment is required pursuant to Clause 33.9 (Change of currency), the Obligors shall, within three Business Days of demand, reimburse the Finance Parties for the amount of all costs and expenses (including legal fees) reasonably incurred by the Finance Parties in responding to, evaluating, negotiating or complying with that request or requirement. For the purposes of this Clause, “relevant party” means any Obligor or any other party (other than a Finance Party) to a Finance Document.
21.3	Enforcement costs
	The Company shall (or shall procure that an Obligor will), within three Business Days of demand, pay to each Finance Party the amount of all costs and expenses (including legal fees) incurred by that Finance Party in connection with the enforcement of, or the preservation of any rights under, any Finance Document.

22.	GUARANTEE AND INDEMNITY
22.1	Guarantee and indemnity
	Each Guarantor irrevocably and unconditionally jointly and severally:

22.1.1 guarantees to each Finance Party punctual performance by each other Obligor of all that other Obligor’s obligations under the Finance Documents;

22.1.2 undertakes with each Finance Party that whenever an Obligor does not pay any amount when due under or in connection with any Finance Document, that Guarantor shall immediately on demand pay that amount as if it was the principal obligor; and

22.1.3 agrees with each Finance Party that if any obligation guaranteed by it is or becomes unenforceable, invalid or illegal, it will, as an independent and primary obligation, indemnify that Finance Party immediately on demand against any cost, loss or liability it incurs as a result of a Borrower not paying any amount which would, but for such unenforceability, invalidity or illegality, have been payable by it under any Finance Document on the date when it would have been due. The amount payable by a Guarantor under this indemnity will not exceed the amount it would have had to pay under this Clause 22 (Guarantee and indemnity) if the amount claimed had been recoverable on the basis of a guarantee.

22.2	Continuing guarantee
	This guarantee is a continuing guarantee and will extend to the ultimate balance of sums payable by any Obligor under the Finance Documents, regardless of any intermediate payment or discharge in whole or in part.

22.3

Reinstatement

If any discharge, release or arrangement (whether in respect of the obligations of any Obligor or any security for those obligations or otherwise) is made by a Finance Party in whole or in part on the basis of any payment, security or other disposition which is avoided or must be restored in insolvency, liquidation, administration or otherwise, then the liability of each Guarantor under this Clause 22 (Guarantee and indemnity) will continue or be reinstated as if the discharge, release or arrangement had not occurred.

22.4

Waiver of defences

The obligations of each Guarantor under this Clause 22 (Guarantee and indemnity) will not be affected by (and the intention of each Guarantor is that its obligations shall continue in full force and effect notwithstanding) any act, omission, matter or thing which, but for this Clause 22.4 (Waiver of defences), would reduce, release or prejudice any of its obligations under this Clause 22 (Guarantee and indemnity) (without limitation and whether or not known to it or any Finance Party) including:

22.4.1 any time, waiver or consent granted to, or composition with, any Obligor or other person;

22.4.2 the release of any other Obligor or any other person under the terms of any composition or arrangement with any creditor of any Obligor or other person;

22.4.3 the taking, variation, compromise, exchange, renewal or release of, or refusal or neglect to perfect, take up or enforce, any rights against, or security over assets of, any Obligor or other person or any non-presentation or non-observance of any formality or other requirement in respect of any instrument or any failure to realise the full value of any security;

22.4.4 any incapacity or lack of power, authority or legal personality of or dissolution or change in the members or status of an Obligor or any other person;

22.4.5 any amendment, novation, supplement, extension, restatement (however fundamental and whether or not more onerous) or replacement of any Finance Document or any other document or security including any change in the purpose of, any extension of or any increase in any facility or the addition of any new facility under any Finance Document or other document or security;

22.4.6 any unenforceability, illegality or invalidity of any obligation of any person under any Finance Document or any other document or security; or

22.4.7 any insolvency or similar proceedings.

22.5	Immediate recourse
	Each Guarantor waives any right it may have of first requiring any Finance Party (or any trustee or agent on its behalf) to proceed against or enforce any other rights or security or claim payment from any person before claiming from that Guarantor under this Clause 22 (Guarantee and indemnity). This waiver applies irrespective of any law or any provision of a Finance Document to the contrary.
22.6	Appropriations
	Until all amounts which may be or become payable by the Obligors under or in connection with the Finance Documents have been irrevocably paid in full, each Finance Party (or any trustee or agent on its behalf) may:

22.6.1 refrain from applying or enforcing any other moneys, security or rights held or received by that Finance Party (or any trustee or agent on its behalf) in respect of those amounts, or apply and enforce the same in such manner and order as it sees fit (whether against those amounts or otherwise) and no Guarantor shall be entitled to the benefit of the same; and

22.6.2 hold in an interest-bearing suspense account any moneys received from any Guarantor or on account of any Guarantor’s liability under this Clause 22 (Guarantee and indemnity).

22.7 Deferral of Guarantors’ rights

22.7.1 Until all amounts which may be or become payable by the Obligors under or in connection with the Finance Documents have been irrevocably paid in full and unless the Agent or the Security Trustee otherwise directs, no Guarantor will exercise any rights which it may have by reason of performance by it of its obligations under the Finance Documents:

(A)	to be indemnified by an Obligor;
(B)	to claim any contribution from any other guarantor of any Obligor’s obligations under the Finance Documents;
(C)	to take the benefit (in whole or in part and whether by way of subrogation or otherwise) of any rights of the Finance Parties under the Finance Documents or of any other guarantee or security taken pursuant to, or in connection with, the Finance Documents by any Finance Party; and/or
(D)	to claim any set off or counterclaim against any other Obligor or any other person liable or claim or prove in competition with the Finance Parties in the bankruptcy or liquidation of any other Obligor or any other person liable or

have the benefit of, or share in, any payment from or composition with, any other Obligor or any other person liable or any other security now or hereafter held by the Finance Parties in respect of the obligations of any Obligor under the Finance Documents or for the obligations or liabilities of any other person liable but so that, if so directed by the Agent or the Security Trustee, it will prove for the whole or any part of its claim in the liquidation or bankruptcy of any other Obligor on terms that the benefit of such proof and of all of the money received by it in respect thereof shall be held on trust for the Finance Parties and applied in or towards discharge of the obligations of the Obligors under the Finance Documents in such manner as the Agent or the Security Trustee shall deem appropriate.

22.7.2 Without prejudice to Clause 22.7.1(D) or Clause 22.8 (Agent’s authority), if a Guarantor receives any benefit, payment or distribution in relation to such rights described in Clause 22.7.1, it shall hold that benefit, payment or distribution to the extent necessary to enable all amounts which may be or become payable to the Finance Parties by the Obligors under or in connection with the Finance Documents to be repaid in full on trust for the Finance Parties and shall promptly pay or transfer the same to the Agent or as the Agent may direct for application in accordance with Clause 33 (Payment mechanics).

22.8	Agent’s authority
	If any Guarantor fails to claim or prove in the liquidation or bankruptcy of any other Obligor promptly upon being directed to do so by the Agent or the Security Trustee as contemplated by Clause 22.7.1(D) (Deferral of Guarantors’ rights):

22.8.1

the Agent or the Security Trustee (as the case may be) may, and is irrevocably authorised on behalf of such Obligor to, file any claims or proofs in such liquidation or bankruptcy on its behalf; and

22.8.2

the Agent or the Security Trustee (as the case may be) may direct the trustee in bankruptcy, liquidator, assignee or other person distributing the assets of any Obligor or their proceeds to pay distributions on the obligations or liabilities of such Obligor direct to the Agent or the Security Trustee on behalf of the Finance Parties until all amounts which may be or become payable by the Obligors under or in connection with the Finance Documents have been irrevocably paid in full.

22.9	Release of Guarantors’ right of contribution
	If any Guarantor (a “Retiring Guarantor") ceases to be a Guarantor in accordance with the terms of the Finance Documents for the purpose of any sale or other disposal of that Retiring Guarantor that is permitted under the terms of the Finance Documents, then on the date such Retiring Guarantor ceases to be a Guarantor:

22.9.1 that Retiring Guarantor is released by each other Guarantor from any liability (whether past, present or future and whether actual or contingent) to make a contribution to any other Guarantor arising by reason of the performance by any other Guarantor of its obligations under the Finance Documents; and

22.9.2 each other Guarantor waives any rights it may have by reason of the performance of its obligations under the Finance Documents to take the benefit (in whole or in part and whether by way of subrogation or otherwise) of any rights of the Finance Parties under any Finance Document or of any other security taken pursuant to, or in connection with,

any Finance Document where such rights or security are granted by or in relation to the assets of the Retiring Guarantor.

22.10	Additional security
	This guarantee is in addition to and is not in any way prejudiced by any other guarantee or security now or subsequently held by any Finance Party.
22.11	Limitation of guarantee
	Notwithstanding any other provision of any Finance Document, the amount guaranteed by each Guarantor hereunder shall be limited to the extent, if any, required so that its obligations under this Clause 22 (Guarantee and indemnity) shall not be subject to avoidance under Section 548 of Title 11 of the United States Code, or to being set aside or annulled under any applicable law or regulation relating to fraud on creditors. In determining the limitations, if any, on the amount of any Guarantor’s obligations hereunder pursuant to the preceding sentence, it is the intention of the parties hereto that any rights of subrogation or contribution which such Guarantor may have under this Clause 22 (Guarantee and indemnity), any other agreement or applicable law or regulation shall be taken into account.
23.	REPRESENTATIONS
23.1	Timing of representations

23.1.1	Each Obligor makes the representations and warranties set out in this Clause 23 (Representations) to each Finance Party on the Amendment Effective Date.
23.1.2	In addition, the Repeating Representations are deemed to be made by each Obligor by reference to the facts and circumstances then existing on:

(A)	the date of each Utilisation Request and the first day of each Interest Period; and
(B)	in the case of an Additional Obligor, the day on which the company becomes (or it is proposed that the company becomes) an Additional Obligor.

23.2 Status

23.2.1 With the exception of Endeavour Energy North Sea, L.P., it, and each member of the Group party to a Transaction Document is a limited liability company, duly incorporated or in the case of Endeavour Energy North Sea LLC, duly formed and validly existing under the laws of its jurisdiction of incorporation.

23.2.2 Endeavour Energy North Sea, L.P. is a limited partnership duly formed and validly existing under the laws of the state of Delaware.

23.2.3 It, and each member of the Group party to a Transaction Document has the power to own its assets and carry on its business as it is being conducted.

23.3	Powers and authority
	It, and each member of the Group party to a Finance Document or material Project Document, has the power to enter into and perform, and has taken all necessary action to authorise the entry into, and performance of, the Finance Documents or material Project Documents to which it is a party and the transactions contemplated by those Finance Documents or material Project Documents.
23.4	Legal validity
	Subject to any general principles of law limiting its obligations or the obligations of any member of the Group and specifically referred to in any legal opinion required, and delivered to the Agent,

under this Agreement, each Finance Document and, to the best of its knowledge (after due enquiry), each material Project Document to which it, or any member of the Group, is a party:

23.4.1 is in full force and effect; and

23.4.2 is its legally binding, valid and enforceable obligation or, as the case may be, the legally binding, valid and enforceable obligation of that member of the Group,

	and no person is in default under any Finance Document or material Project Document.
23.5	Non-conflict
	The entry into and performance by it of, or any Transaction Party of, and the transactions contemplated by, the Finance Documents, do not conflict with:

23.5.1 any law or regulation applicable to it or any member of the Group party to such documents;

23.5.2 its constitutional documents or the constitutional documents of any member of the Group party to such documents; or

23.5.3 any document which is binding upon (i) it or any of its assets or (ii) any member of the Group or any assets of any member of the Group.

23.6	Pari passu ranking
	Its payment obligations, and the payment obligations of each Transaction Party, under the Finance Documents rank at least pari passu with all its other present unsecured obligations, except for obligations mandatorily preferred by law applying to companies generally.
23.7	Insolvency
	As at the Amendment Effective Date and, in the case of any member of the Borrower Group which does not have an interest in any Borrowing Base Asset at the Amendment Effective Date, the date on which any Petroleum Asset owned by such member of the Borrower Group becomes a Borrowing Base Asset, neither it nor any member of the Group has taken any steps, and (after due enquiry) it is not aware of any steps having been taken for:

23.7.1	the winding-up, administration, or dissolution of it or any member of the Group (or any of their respective assets); or
23.7.2	the appointment of any Insolvency Officer in relation to it or any member of the Group or their respective assets,
or any analogous step in any jurisdiction.

23.8 No default

23.8.1	No Event of Default and, on the Amendment Effective Date, no Default has occurred and is continuing or will result from the execution of, or the performance of any transaction contemplated by, any Finance Document and so far as it is aware no circumstances exist which threaten the foregoing.
23.8.2	No other event is outstanding which constitutes a default under any document which is binding on it, or any member of the Group or any of its assets or any assets of any member of the Group, in each case, to an extent or in a manner which is reasonably likely to result in a Material Adverse Change.

23.9 Authorisations

23.9.1 As at the date of a Finance Document and the date on which any Petroleum Asset becomes a Borrowing Base Asset, except for registration of any relevant Security

Document, all Authorisations required by it, or any Transaction Party in connection with the entry into, performance, validity and enforceability of, and the transactions contemplated by, that Finance Document have been obtained or effected (as appropriate) and are in full force and effect, and to the best of its knowledge (after due enquiry), no steps have been or are being taken for the revocation, variation or refusal of any such Authorisation.

23.9.2

As at the Amendment Effective Date and the date on which any Petroleum Asset becomes a Borrowing Base Asset, all material Authorisations required by it or any member of the Group in connection with:

(A)	the entry into, performance, validity and enforceability of; and
(B)	the transactions (including the exploitation of the Borrowing Base Assets) contemplated by,

each of the material Project Documents to which it or any member of the Group is a party have been obtained or effected (as appropriate) (or, in relation to the matters referred to at paragraph (B) above, if not yet required, there is no reason to believe that they will not be obtained in satisfactory terms at the time they are required) and are in full force and effect and, to the best of its knowledge (after due enquiry), no steps have been taken to revoke or amend such Authorisations.

23.9.3 As at the Amendment Effective Date and the date on which any Petroleum Asset becomes a Borrowing Base Asset, all material Authorisations required by it, or any member of the Group in connection with the exploitation of the Borrowing Base Assets as contemplated by the Finance Documents and each Projection, have been obtained or effected (as appropriate) and are in full force and effect and, to the best of its knowledge (after due enquiry), no steps have been taken to revoke or amend such Authorisations.

23.10	Financial statements
	Its audited financial statements or, in the case of the Company, its audited consolidated financial statements most recently delivered to the Agent:

23.10.1 have been prepared in accordance with GAAP/IFRS, consistently applied; and

23.10.2 give a true and fair view of its financial condition as at the date to which they were drawn up,

	except, in each case, as disclosed to the contrary in those financial statements.
23.11	No Material Adverse Change
	As at the Amendment Effective Date, there has been no Material Adverse Change.
23.12	Litigation
	No litigation, arbitration or administrative proceedings are current or, to its knowledge, pending or threatened which, if adversely determined, would be reasonably likely to result in a Material Adverse Change.
23.13	Information Package

23.13.1 The factual information contained in the Information Package was true and accurate in all material respects as at its date or (if appropriate) as at the date (if any) at which it is stated to be given.

23.13.2 The Information Package contains all information regarding each Obligor and the Borrowing Base Assets which is material as at its date or (if appropriate) as at the date (if any) at which it is stated to be given.

23.13.3 The estimates, forecasts and financial projections contained in the Information Package have been prepared, in good faith and with due care on the basis of recent historical information and assumptions believed by the Obligors to be reasonable as at the date it is stated to be given.

23.13.4 Each estimate, forecast and expression of opinion or intention contained in the Information Package was made in good faith, with due care and after careful consideration and enquiry and is believed by the Obligors to be reasonable as at the date at which it is stated to be given.

23.13.5 The Information Package did not, when provided, omit any information which, if disclosed, would make the Information Package untrue or misleading in any material respect.

23.13.6 As at the Amendment Effective Date, nothing has occurred which, if disclosed, would make the Information Package untrue or misleading in any material respect.

23.14	Security
	Subject to:

23.14.1 any qualifications as to matters of law set out in any legal opinion required, and delivered to the Agent, under this Agreement;

23.14.2 any required registration of any Security Document;

23.14.3 the delivery of any notices required to be delivered pursuant to the Security Documents which has not been delivered on the date that this representation and warranty is, or is deemed to be, given; and

23.14.4 any rights of forfeiture (or similar rights) of the counterparties to the Project Documents,

each Security Document to which it or any Transaction Party is a party:

(A)	confers the Security of the type it purports to create over the assets over which a Security is purported to be given by that Security Document;
(B)	is valid and enforceable against (i) it or, as the case may be, the relevant Transaction Party which is party thereto, and (ii) its or, as the case may be, such Transaction Party’s Insolvency Officers and creditors; and
(C)	is not capable of being avoided or set aside, whether in the winding up, administration, or dissolution or otherwise of it (or any of its assets) or, as the case may be, such Transaction Party (or any such Transaction Party’s assets).

23.15 Environmental matters

23.15.1 To the best of its knowledge (after due enquiry) it has obtained all material Environmental Licences required by it in connection with each of the Borrowing Base Assets in which it has an interest and their exploitation and has at all times complied in all material respects with all those Environmental Licences and it and each other member of the Group has complied in all material respects with all applicable Environmental Laws.

23.15.2 To the best of its knowledge (after due enquiry) there is no material environmental contamination on any site connected with any Borrowing Base Asset or in which it or any member of the Group has an interest.

23.15.3 To the best of its knowledge (after due enquiry) there are no material Environmental Claims current, or to its knowledge, pending or threatened, connected with it, any member of the Group or any of the Borrowing Base Assets.

23.16 Borrowing Base Assets

23.16.1 The Obligors own, or have sufficient access to and the right to use all assets necessary for the exploitation of each Borrowing Base Asset as contemplated by the Transaction Documents and the then current Projection.

23.16.2 Save as disclosed in Section C of the Due Diligence Report, to the best of its knowledge (after due enquiry), an Obligor is the absolute legal and beneficial owner of each Borrowing Base Asset and each Key Asset, in each case, free from any Security or other interest of any kind (other than (i) the interests of co-venturers under the Project Documents relating to that Borrowing Base Asset, (ii) the Security under the Security Documents or (iii) the Security permitted under Clause 25.4 (Negative pledge)) and no member of the Group is under any obligation to create any Security over any Borrowing Base Asset or Key Asset (except by virtue of any Security Document or as permitted under Clause 25.4 (Negative pledge)).

23.16.3 So far as it is aware, no event or circumstance exists which entitles any person to terminate or suspend any Authorisation of a kind referred to in Clause 23.9.2 (Authorisations).

23.17	Copies of Project Documents
	Save as disclosed in Section A of the Due Diligence Report, each copy of a Project Document delivered to the Agent by it is, at the time it is delivered, a correct and complete copy of the relevant document as in force at that time.

23.18	Laws and regulations
	It and each member of the Group, is in compliance in all material respects with all applicable laws and regulations including any applicable tax laws and regulations. This implies that Dutch Financial Supervision Act (Wet op het financieel toezicht) is also applicable.
23.19	Insurances

23.19.1 All Insurances which are at any time required to be maintained or effected by it, or any member of the Group, pursuant to the Finance Documents are in full force and effect at that time, and to the best of its knowledge (after due enquiry), no event or circumstance has occurred, nor has there been any omission to disclose a fact, which would in either case entitle any insurer under those Insurances to avoid its liability or otherwise reduce its liability.

23.19.2 The Security Trustee (as security trustee for the Secured Creditors) will, on and from the first Utilisation Date, be named as co-insured in relation to all such Insurances.

23.20 No immunity

23.20.1 It, and each member of the Group party to a Transaction Document is subject to civil commercial law in respect of its obligations under the Transaction Documents.

23.20.2 None of it, any other member of the Group party to a Transaction Document, any of its assets, or any assets of any other member of the Group party to a Transaction

Document, is entitled to any right of immunity, and the entry into and performance by it, and each member of the Group party to a Transaction Document, of the Transaction Documents to which it or, as the case may be, that member of the Group, is a party constitute private and commercial acts.

23.21	Governing law and enforcement
	Subject to any qualifications as to matters of law set out in any legal opinion required, and delivered to the Agent, under this Agreement:

23.21.1 the relevant law chosen as the governing law of each of the Finance Documents to which it, or any member of the Group, is a party will be recognised and enforced in its jurisdiction of incorporation or, as the case may be, the jurisdiction of incorporation of such member of the Group;

23.21.2 the submission by it, or any member of the Group, to the jurisdiction of the courts of England under any relevant Finance Document to which it or, as the case may be, such member of the Group, is a party and any undertaking given in any Finance Document by it, or any member of the Group, not to claim any immunity, in each case, is legal, valid and binding under the law of its jurisdiction of incorporation or, as the case may be, the jurisdiction of incorporation of such member of the Group; and

23.21.3 any judgment obtained in England in relation to a Finance Document to which it, or any member of the Group, is a party will be recognised and enforced in its jurisdiction of incorporation or, as the case may be, the jurisdiction of incorporation of such member of the Group.

23.22	Deduction of Tax
	As at the Amendment Effective Date it is not required under the law of its jurisdiction of incorporation to make any deduction for or on account of Tax from any payment that it may make under any Finance Document.

23.23 Ownership structure

23.23.1 As at the Amendment Effective Date, each of the Company’s Subsidiaries, apart from Endeavour Energy Luxembourg S.a.r.l and Endeavour Energy New Ventures I Ltd, are Original Guarantors.

23.23.2 As at the Amendment Effective Date, the ownership structure of the Group is as set out in Schedule 9 (Corporate Organisation Chart).

23.24	No Security
	No Security (or agreement to create the same) exists over any of its assets or any assets of any member of the Group save, in each case, as permitted under Clause 25.4 (Negative pledge).

23.25

Share Security

Each member of the Group that has entered into any Security Document for the purposes of granting Security over its shares in another member of the Group is the legal and beneficial owner of all of such shares and other assets (the “charged assets") secured, or purported to be secured, under such Security Document free from any Security (other than the relevant Security created pursuant to that Security Document); and the charged assets are free from any restrictions as to transfer or registration and are not subject to any calls or other liability to pay money.

23.26	Dutch Work’s Council Act
	None of the Obligors incorporated in The Netherlands is required to obtain advice from any works council within the meaning of the Dutch Works Council Act (Wet op de Ondernemingsraden).

23.27	Final Salary Pension Schemes
	No member of the Group has at any time operated a final salary pension scheme.
23.28	Overseas Company
	None of the Obligors (other than Endeavour Energy UK Limited and Endeavour North Sea) have registered an establishment in the United Kingdom at Companies House whether under its name of incorporation or under any other name.
24.	INFORMATION UNDERTAKINGS
24.1	Financial statements

24.1.1 The Company must supply to the Agent (in sufficient copies for all the Lenders if the Agent so requests):

(A)	its audited consolidated financial statements for each of its financial years; and
(B)	its unaudited consolidated financial statements for each six month period in each of its financial years.

24.1.2 In addition, if the Agent so requests, each Obligor (other than the Company) must supply to the Agent (in sufficient copies for all the Lenders if the Agent so requests):

(A)	its financial statements (or, if the same have been audited, audited financial statements) for each of its financial years; and
(B)	its unaudited financial statements for each six month period in each of its financial years.

24.1.3 All financial statements must be supplied as soon as they are available and:

(A)	in the case of audited financial statements or audited consolidated financial statements of the Company, within 120 days;
(B)	in the case of audited financial statements or audited consolidated financial statements of each Obligor (other than the Company), within 180 days or, in the case only of Endeavour Energy UK Limited or any other Obligor incorporated in England and Wales, 304 days;
(C)	in the case of unaudited financial statements or unaudited consolidated financial statements of the Company, within 90 days; and
(D)	in the case of unaudited financial statements or unaudited consolidated financial statements of each Obligor (other than the Company), within 120 days,

	of the end of the relevant financial period.
24.1.4	The Company must supply to the Agent, with each set of financial statements it supplies in accordance with Clause 24.1.2 and Clause 24.1.3, a certificate signed by a director of the Company (in form satisfactory to the Agent) demonstrating the compliance of the Group with Clause 26 (Financial Covenants) or, if it is not in compliance, stating this fact together with a brief explanation therefor.

24.2 Form of financial statements

24.2.1 Each Obligor must ensure that each set of financial statements supplied under this Agreement is prepared using GAAP/IFRS and gives (if audited) a true and fair view of, or (if unaudited) fairly represents, the financial condition (consolidated or otherwise) of the relevant person as at the date and for the period in respect of which those financial statements were drawn up.

24.2.2 Each Obligor must notify the Agent of any change to GAAP/IFRS, accounting practices or reference periods which affect the basis on which its audited consolidated financial statements or audited financial statements are prepared.

24.2.3 If requested by the Agent, the relevant Obligor must supply to the Agent:

(A)	a full description of any change notified under Clause 24.2.2; and
(B)	sufficient information to enable the Finance Parties to make a proper comparison between the financial position shown by the set of financial statements prepared on the changed basis and its most recent audited consolidated financial statements or, as the case may be, audited financial statements delivered to the Agent under this Agreement.

24.2.4 If requested by the Agent, the Company must enter into discussions for a period of not more than 30 days with a view to agreeing any amendments required to be made to this Agreement to place the relevant Obligor and the Finance Parties in the same position as they would have been in if the change notified under Clause 24.2.2 had not happened. Any agreement between the Company and the Agent will, with the prior consent of the Majority Lenders, be binding on all the Parties.

24.2.5 If no agreement is reached under Clause 24.2.4 on the required amendments to this Agreement, the Company must ensure that its auditors certify those amendments required to be made to this agreement to place the relevant Obligor and the Finance Parties in the same position as they would have been in if the change notified under Clause 24.2.2 had not happened. The certificate of the auditors will, in the absence of manifest error, be binding on all the Parties.

24.3	Information: miscellaneous
	Each Obligor must supply, and the Company must procure that each member of the Group supplies, to the Agent (in sufficient copies for all the Lenders if the Agent so requests):

24.3.1 copies of all documents dispatched by it to its creditors generally or any class of them or required by its constitutional documents or law to be dispatched to its shareholders (or any class of them) in their capacity as such, in each case, at the same time as they are dispatched;

24.3.2 promptly upon becoming aware of them, details of any litigation, arbitration or administrative proceedings relating to it which are current, threatened or pending which, if adversely determined, is reasonably likely to result in a Material Adverse Change;

24.3.3 promptly upon becoming aware of them, details of any potential or actual material warranty claim or any other material claim or dispute relating to it under any Transaction Document;

24.3.4 promptly upon becoming aware of it, any incident involving any material physical damage to a Borrowing Base Asset in which it has an interest and its proposal for reinstatement;

24.3.5 promptly upon changing its financial year end, details of the same;

24.3.6 as soon as reasonably practicable before the same is carried out:

(A)	details of each proposed Relevant Disposal (together with confirmation, and details, of the amount of the anticipated Relevant Net Proceeds and the anticipated Relevant Repayment Proceeds relating to that Relevant Disposal); and
(B)	details of each proposed Additional Financing (together with confirmation, and details, of the anticipated proceeds of that Additional Financing);

24.3.7 promptly upon the same being completed:

(A)	details of each Relevant Disposal that has been carried out (together with confirmation, and details, of the amount of the Relevant Net Proceeds and the Relevant Repayment Proceeds relating to that Relevant Disposal); and
(B)	details of each Additional Financing that has been carried out (together with confirmation, and details, of the proceeds of that Additional Financing); and

24.3.8 promptly on request, such further information regarding its financial condition and operations or any Key Asset as any Finance Party through the Agent may reasonably request.

24.4	Information: Borrowing Base Assets and Key Assets
	The Company shall supply to the Agent (in sufficient copies for all of the Lenders if the Agent so requests):

24.4.1 promptly upon receipt by it or any member of the Group, a copy of:

(A)	any production reports, budgets prepared by any operator, any minutes of operating committee meetings or any other document as the Agent or Technical Bank may reasonably request from time to time, in each case, relating to any Borrowing Base Asset; and
(B)	any other information relating to a Borrowing Base Asset or a member of the Group that could change any Assumption in the then current Projection (in a material respect) or impose any additional material liability on any member of the Group;

24.4.2 promptly upon request by the Agent:

(A)	a copy of any Project Document; and
(B)	such information as the Lenders may reasonably require in respect of a Borrowing Base Asset or any member of the Group;

24.4.3 not less than 14 days before any member of the Group enters into any new material Project Document or any material amendment to any existing Project Document, details of that Project Document or material amendment;

24.4.4 promptly upon the same being provided under the First Lien Credit Agreement, a copy of each Reserves Report provided to the agent, technical bank or any other lender or finance party under the First Lien Credit Agreement;

24.4.5 promptly upon receipt by an Obligor, or any member of the Group, a certified copy of any material Authorisation required under any law or regulation (including Environmental Laws and Environmental Licences) to enable that Obligor or member of

the Group to perform its obligations under, or for the validity or enforceability of, any Finance Document; and

24.4.6 no later than ten Business Days after the end of each quarter, an update (in such form and containing such information as the Technical Bank may reasonably require) with respect to the Key Assets and the other Petroleum Assets (other than any Borrowing Base Asset) in which the member(s) of the Group has or have an interest.

24.5 Notification of Default

24.5.1 Unless the Agent has already been so notified, an Obligor shall, as soon as it becomes aware, promptly notify the Agent of any Default (and the steps, if any, being taken to remedy it).

24.5.2 Promptly on request by the Agent and together with the financial statements specified in Clause 24.1.2(A) (Financial statements), each Obligor must supply to the Agent a certificate, signed by two of its authorised signatories on its behalf, certifying that no Default is outstanding or, if a Default is outstanding, specifying the Default and the steps, if any, being taken to remedy it.

24.6 Reserves Report

24.6.1 The Obligors shall procure, without prejudice to Clause 24.4.4, that a Reserve Report is delivered to the Agent and the Technical Bank on each date on which the same is due (as at the Amendment Effective Date) to be delivered to the agent, technical bank, lenders and/or other finance parties under the First Lien Credit Agreement whether or not the same is actually delivered to such parties under the First Lien Credit Agreement.

24.6.2 If:

(A)

the date as of which the Reserves Report most recently delivered to the Agent and/or the Technical Bank under Clause 24.4.4 or Clause 24.6.1 (as the case may be) falls 12 months or more before the next test date and no new Reserves Report is scheduled to be delivered under Clause 24.4.4 or Clause 24.6.1 (as the case may be) before that test date; and

(B)

the Technical Bank (by notice given to the Company) so requires, the Company shall (at the expense of the Obligors) commission a new Reserves Report and ensure that the same is delivered to the Agent and the Technical Bank within 40 days of the date on which the Technical Bank issues the relevant notice to the Company (provided that the Technical Bank shall not issue any notice under this Clause 24.6.2 before 15 February 2010),

where, for these purposes, “test date” means each 30 June or 31 December of each year.

24.7 Use of websites

24.7.1 Except as provided below, an Obligor may deliver any information under the Finance Documents to a Lender by posting it on to an electronic website if:

(A)	the Agent and the relevant Obligor agree;
(B)	the relevant Obligor and the Agent designate an electronic website for this purpose;
(C)	both the relevant Obligor and the Agent are aware of the address of and any relevant password specifications for the website; and

(D) the information posted is in a format agreed between the relevant Obligor and the Agent.

The Agent must supply each relevant Lender with the address of and any relevant password specifications for the website.

24.7.2 Notwithstanding the above, each relevant Obligor must supply to the Agent in paper form a copy of any information posted on the website together with sufficient copies for each Lender:

(A)	if requested to do so by the Agent; or
(B)	if so required by a governmental requirement,

in each case within 10 Business Days of receipt of the request.

24.7.3 The Agent must promptly upon becoming aware of its occurrence, notify the relevant Obligor and the Lenders if:

(A)	the website cannot be accessed;
(B)	the website or any information on the website is infected by any electronic virus or similar software;
(C)	the relevant password specification for the website is changed; or
(D)	any information to be supplied under this Agreement is posted on the website or amended after being posted.

In the circumstances in paragraphs (A) or (B) above occur, the relevant Obligor must supply any information required under this Agreement in paper form.

24.8 “Know your customer” checks

24.8.1 If:

(A)	the introduction of or any change in (or in the interpretation, administration or application of) any law or regulation made after the Amendment Effective Date;
(B)	any change in the status, or the composition of the shareholders, of an Obligor after the Amendment Effective Date; or
(C)	a proposed assignment or transfer by a Lender of any of its rights and obligations under this Agreement to a party that is not a Lender prior to such assignment or transfer,

obliges the Agent or any other Finance Party (or, in the case of Clause 24.8.1(C) above, any prospective new Lender) to comply with “know your customer” or similar identification procedures in circumstances where the necessary information is not already available to it, each Obligor shall promptly upon the request of the Agent or any Finance Party supply, or procure the supply of, such documentation and other evidence as is reasonably requested by the Agent (for itself or on behalf of any Finance Party) or any Finance Party (for itself or, in the case of the event described in Clause 24.8.1(C) above, on behalf of any prospective new Lender) in order for the Agent, such Finance Party or, in the case of the event described in Clause 24.8.1(C) above, any prospective new Lender to carry out and be satisfied it has complied with all necessary “know your customer” or other similar checks under all applicable laws and regulations pursuant to the transactions contemplated in the Finance Documents.

24.8.2 Each Finance Party shall promptly upon the request of the Agent supply, or procure the supply of, such documentation and other evidence as is reasonably requested by the Agent (for itself) in order for the Agent to carry out and be satisfied it has complied with all necessary “know your customer” or other similar checks under all applicable laws and regulations pursuant to the transactions contemplated in the Finance Documents.

24.8.3 The Company shall, by not less than 10 Business Days’ prior written notice to the Agent, notify the Agent (which shall promptly notify the Finance Parties) of its intention to request that any Relevant Affiliate becomes an Additional Obligor pursuant to Clause 29 (Changes to the Obligors).

24.8.4 If the accession of any person to this Agreement as an Additional Obligor pursuant to Clause 29 (Changes to the Obligors) obliges the Agent or any other Finance Party to comply with “know your customer” or similar identification procedures in circumstances where the necessary information is not already available to it, the Company shall promptly upon the request of the Agent or any other Finance Party supply, or procure the supply of, such documentation and other evidence as is reasonably requested by the Agent (for itself or on behalf of any Finance Party) or any other Finance Party (for itself or on behalf of any prospective new Finance Party) in order for the Agent or such Finance Party or any prospective new Finance Party to carry out and be satisfied it has complied with the results of all necessary “know your customer” or other similar checks under all applicable laws and regulations pursuant to the accession of such person to this Agreement as an Additional Obligor.

24.9	Permitted Transactions
	Each Obligor shall consult with the Agent prior to completing any Permitted Transaction described in paragraph (B) or (C) of the definition of “Permitted Transaction” set out in Clause 5.1 (Definitions) and promptly notify the Agent upon the completion of the same. The Obligors shall provide such evidence as the Agent (acting reasonably) may request for the purposes of ensuring that each such Permitted Transaction has been or, as the case may be, will be, completed upon the terms described in the relevant paragraph of the definition of “Permitted Transaction” and that the interests of the Secured Creditors have not been adversely affected.
25.	GENERAL UNDERTAKINGS
25.1	Authorisations
	Each Obligor shall, and shall procure that each member of the Group shall, promptly obtain, maintain and comply with the terms of any material Authorisation required under any law or regulation (including Environmental Laws and Environmental Licences):

25.1.1	to enable it to perform its obligations (or exercise its rights) under, or for the validity or enforceability of, any Finance Document; or
25.1.2	to enable it to perform its obligations (or exercise its rights) under, or for the validity or enforceability of, any other Finance Document or material Project Document to which it is party or for the exploitation and/or operation of any Borrowing Base Asset in which it has an interest as contemplated by the Finance Document or material Project Document and the then current Projection.

25.2	Compliance with laws
	Each Obligor shall, and shall procure that each member of the Group shall, comply in all material respects with all laws and regulations applicable to it or its assets or activities for the time being.

25.3	Pari passu ranking
	Each Obligor shall, and shall procure that each member of the Group party to a Finance Document, shall ensure that its obligations under the Finance Documents rank at least pari passu with all its other present and future unsecured obligations, except for obligations mandatorily preferred by law applying to companies generally.
25.4	Negative pledge

25.4.1 Except as provided in Clause 25.4.2:

(A)	no Obligor may create or allow to exist any Security on, over, or affecting, any of its assets; and
(B)	each Obligor shall procure that no member of the Group creates or allows to exist any Security on, over, or affecting, any of its assets.

25.4.2 Clause 25.4.1 does not apply to:

(A)	any Security constituted by the Security Documents or arising under any other Finance Document (including any such Security that has been granted by the obligors under the First Lien Credit Agreement);
(B)	any Security comprising a netting or set-off arrangement entered into by an Obligor or any other member of the Group:

(1)	in the ordinary course of its banking and trading arrangements for the purpose of netting debit and credit balances;
(2)	under any Permitted Hedging Agreement; or
(3)	under any other Hedging Agreement to which any member of the Group that is not an Obligor is a party;

(C)	any lien arising by operation of law and in the ordinary course of trading and does not secure any amount more than 30 days overdue;
(D)	any Security that arises under or pursuant to a Project Document which does not secure any Financial Indebtedness;
(E)	any Security that are retention of title or set off arrangements constituted under industry standard conditions for the supply of goods acquired by any Obligor or any other member of the Group in the ordinary course of its trading;
(F)	any Security arising pursuant to the specific terms of any Equivalent Field Document which does not secure any Financial Indebtedness;
(G)	any Security which the Majority Lenders have consented to in writing;
(H)	any Security securing Financial Indebtedness, the outstanding principal amount of which (when aggregated with the outstanding principal amount of any other Financial Indebtedness which has the benefit of any Security given by any member of the Group other than permitted under paragraphs 25.4.2(A) to 25.4.2(G) above) does not exceed $250,000 (or its equivalent in other currencies).

25.4.3 No Obligor may, and each Obligor shall procure that no member of the Group shall:

(A) sell, transfer or otherwise dispose of any of its assets on terms where it is or may be leased to or re-acquired or acquired by that company or any member of the Group or Non Recourse Subsidiary; or

(B) sell, transfer or otherwise dispose of any of its receivables on recourse terms,

	in circumstances where the transaction is entered into primarily as a method of raising Financial Indebtedness or of financing the acquisition of an asset.
25.4.4	No Obligor may, and each Obligor shall ensure that no member of the Group shall, agree to an amendment of any document or enter into a document which may restrict its ability to create a Security envisaged by a Security Document.

25.5 Disposals

25.5.1

Except as provided in Clause 25.5.2, no Obligor may, and each Obligor shall procure that no member of the Group shall, either in a single transaction or in a series of transactions and whether related or not, dispose of all or any part of any Borrowing Base Asset or Key Asset or any interests therein or any of its shareholding in any person holding any interest in any Borrowing Base Asset or Key Asset.

25.5.2

Clause 25.5.1 does not apply to:

(A)	sales of Petroleum under any Project Document or otherwise on arms’ length terms for cash-only consideration;
(B)	disposals arising solely by virtue of a unitisation or redetermination of a Borrowing Base Asset or Key Asset;
(C)	disposals of surplus materials or of materials that are forthwith replaced with materials of equivalent utility;
(D)	disposals of obsolete or surplus assets;
(E)	disposals of materials used in the course of its operations where such disposals are made in the ordinary course of business and on arms’ length terms;
(F)	disposals of (i) a Petroleum Asset which has ceased to be designated as a Borrowing Base Asset pursuant to the First Lien Credit Agreement, (ii) any Key Asset or (iii) the shares of any member of the Group that ceases to hold any Borrowing Base Asset by reason of the same ceasing to be designated as a Borrowing Base Asset pursuant to the First Lien Credit Agreement (provided, in each case, that (a) such disposal is made to a person other than a member of the Group or an Affiliate thereof on an arms length basis and on reasonable commercial terms for cash and (b) the proceeds of such disposal are applied in accordance with Clause 12.3.2 (Mandatory prepayment));
(G)	any step which is part of a Permitted Transaction;
(H)	disposals with prior consent of the Majority Lenders;
(I)	any step which is part of a Permitted Hedging Agreement.

25.6 Financial Indebtedness

25.6.1	Except as provided in Clause 25.6.2, no Obligor may, and each Obligor shall procure that no member of the Group shall, at any time incur or have outstanding any Financial Indebtedness.
25.6.2	Clause 25.6.1 does not apply to:

(A)	any Financial Indebtedness incurred under the Finance Documents or;
(B)	any Financial Indebtedness accruing under the $81,250,000 convertible senior notes due 2012 of Endeavour International Corporation and any Financial

	Indebtedness incurred under any arrangement (“refinancing arrangements”) entered into for the purposes of refinancing and repaying the Financial Indebtedness incurred under such convertible senior notes (provided that (i) the aggregate principal amount of the Financial Indebtedness under such refinancing arrangements and (to the extent that the Financial Indebtedness incurred under such convertible senior notes is only refinanced in part) any outstanding Financial Indebtedness under such convertible senior notes, does not exceed $81,250,000 and (ii) no payments of principal are payable under the refinancing arrangements before the Final Maturity Date);
(C)	Financial Indebtedness incurred under any Permitted Hedging Agreement or any guarantee given by a member of the Group in respect of a Permitted Hedging Agreement;
(D)	any Financial Indebtedness owed by an Obligor to another Obligor;
(E)	any Financial Indebtedness which is subordinated to amounts due to the Finance Parties under the Finance Documents pursuant to a subordination agreement approved by the Majority Lenders;
(F)	any Financial Indebtedness incurred under the $40,000,000 11.5% unsecured convertible loan notes due 2014 issued by Endeavour Energy Luxembourg S.a.r.l (provided that no payments of interest or principal under such notes are payable before the Final Maturity Date);
(G)	any Financial Indebtedness incurred under the First Lien Credit Agreement provided that the aggregate principal amount of the Financial Indebtedness under the First Lien Credit Agreement does not exceed $225,000,000;
(H)	any Financial Indebtedness incurred under the subordinated loan note issued by the Company referred to in the waiver letter dated 16 November 2009 between BNP Paribas and the Obligors entered into pursuant to the First Lien Credit Agreement provided that such Financial Indebtedness is incurred and repaid in accordance with the terms of such waiver letter;
(I)	any Financial Indebtedness incurred other than under Clauses 25.6.2(A) to 25.6.2(H) which does not at any time exceed (in aggregate) $10,000,000 (or its equivalent in one or more other currencies); and
(J)	any other Financial Indebtedness incurred with the prior consent of the Majority Lenders.

25.7 Credits and guarantees

25.7.1	Except as provided in Clause 25.7.2, no Obligor may, and each Obligor shall procure that no member of the Group shall, make any loan or extend any other form of credit or financial accommodation, or give any guarantee of any person’s Financial Indebtedness, to any person, or otherwise be a creditor in respect of any Financial Indebtedness of any person.
25.7.2	Clause 25.7.1 does not apply to:

(A) any loan, credit or financial accommodation to the extent required by or pursuant to any Project Document or any Equivalent Field Document;

(B)	trade credit and guarantees on usual commercial terms including guarantees by a member of the Group of oil and gas trading obligations of any other member of the Group;
(C)	the guarantee given by the Company to Paladin Resources Limited under the terms of the Acquisition Agreement;
(D)	any Financial Indebtedness permitted under Clause 25.6.2;
(E)	any extension of credit given pursuant to a Permitted Hedging Agreement in relation to hedge receipts.

25.8 Change of business

25.8.1	Each Obligor shall procure that no substantial change is made to the general nature of its business or the business of the Group from that carried on at the Amendment Effective Date.
25.8.2	No Obligor shall:

(A)	carry on any business other than the ownership and exploitation of interests in Petroleum Assets and the exploration for, and production and disposal of Petroleum from, the areas covered by the petroleum production licences for such Petroleum Assets and activities associated with those activities; or
(B)	own any assets or incur any liabilities except for the purposes of carrying on that business.

25.9 Corporate existence

25.9.1	Each Obligor shall maintain, and shall ensure that each member of the Group maintains, its corporate existence under the laws of its jurisdiction of incorporation and each Obligor shall not, and shall ensure that no member of the Group will, change its corporate domicile, or attempt to resolve to do so.
25.9.2	No Obligor may, and each Obligor shall procure that no member of the Group shall, enter into any amalgamation, demerger, merger or reconstruction except a solvent amalgamation, demerger, merger or reconstruction within the Group with the consent of the Majority Lenders (such consent not to be unreasonably withheld).
25.9.3	The restrictions in Clauses 25.9.1 and 25.9.2 shall not apply to any step or procedure which is part of a Permitted Transaction.

25.10 Environmental matters

25.10.1	Each Obligor shall ensure that it, and the Company shall procure that each member of the Group is, and has been, in compliance in all material respects with all Environmental Laws and Environmental Licences applicable to it.
25.10.2	Each Obligor shall, and the Company shall procure that each member of the Group, shall promptly upon becoming aware of the same notify the Agent of:

(A)	any material Environmental Claim current, or to its knowledge, pending or threatened; or
(B)	any circumstances reasonably likely to result in an Environmental Claim.

25.11 Insurance

25.11.1 Each Obligor shall, and the Company shall procure that each member of the Group shall:

(A) take out and maintain, or caused to be taken out and maintained, with respect to all of its assets and activities, insurance policies:

(1)	in such amounts and on such terms and against such risks as are normally insured against by prudent owners of comparable assets in the region in which the relevant assets are located or activities are taking place; and
(2)	against any other risks which the Agent may reasonably require as a result of any material change(s) in circumstances, risks or the Majority Lenders’ reasonable perception of risk.

(B) ensure that each Insurance is maintained:

(1)	with an insurance company or underwriters acceptable to the Agent (acting reasonably); and
(2)	otherwise on terms consistent with the good practice of prudent owners of comparable assets;

(C)	ensure that moneys received by it under any Insurances relating to third party liability are applied directly to the person to whom the liability to which the sum relates was incurred, or to the relevant insured party in reimbursement of moneys expended in satisfaction of such liability;
(D)	procure that the Security Trustee (as security trustee for the Secured Creditors) is, on and from the first Utilisation Date, named as a co-insured party upon the policy, certificate or cover note relating to each Insurance;
(E)	not do, or knowingly permit anything to be done, which may make any Insurance void, voidable, unavailable or unenforceable or render any sum which may be paid out under such insurance repayable in whole or in part;
(F)	promptly pay all premiums, calls and contributions and do all other things necessary to keep each Insurance maintained in full force and effect;
(G)	produce to the Agent (i) the policy, certificate or cover note relating to any Insurance, (ii) the receipt for payment of any premium for any Insurance or (iii) such other details of any Insurance as the Agent may reasonably request; and
(H)	if the Security Trustee or the Agent so requires:

(1)	enter into a Security Document (in form and substance satisfactory to the Security Trustee) for the purposes of granting Security over such Insurances which relate to the Borrowing Base Assets and the proceeds thereof in favour of the Security Trustee unless such Security has been granted under an existing Security Document; and
(2)	deliver to the Security Trustee, or procure the delivery to the Security Trustee of, any legal opinion or other document that the Security Trustee or the Agent may reasonably require in connection with the entry into such Security Document.

25.11.2	No Finance Party shall have any liability for the payment of premiums or any other amount owing in respect of any insurance.
25.11.3	If any Obligor or member of the Group fails to pay any premium relating to any Insurances, the Agent may, at its sole discretion, pay any premium due and the Obligors shall immediately pay to the Agent the amount of such premium.

25.12	Project Documents
	Each Obligor shall:

25.12.1	ensure that none of its rights under or in respect of any Project Document are at any time cancelled, terminated, suspended or limited if the same would be reasonably likely to result in a Material Adverse Change;
25.12.2	not agree to any waiver, amendment, termination or cancellation of any Project Document if the same would be reasonably likely to result in a Material Adverse Change;
25.12.3	duly and properly perform, in all material respects, its obligations under the Project Documents (except to the extent, if any, they are inconsistent with its obligations under the Finance Documents);
25.12.4	exercise its rights, and (so far as within its power) ensure that others exercise their respective rights, under and in respect of the Project Documents consistently with its obligations under the Finance Documents; and
25.12.5	not enter into any Project Document the entry into, performance, termination or breach of which would be reasonably likely to result in a Material Adverse Change.

25.13 Borrowing Base Assets

25.13.1 Each Obligor shall:

(A)	exercise such votes and other rights as it may have under the Project Documents with a view to ensuring (so far as it is able) that each Borrowing Base Asset is at all times exploited and operated in a reasonable and prudent manner and in accordance with good industry practice, all applicable laws and regulations and the provisions of the Project Documents;
(B)	prior to the Abandonment Date forecast in the then current Projection, not concur in, and shall vote against, any proposal or decision to abandon all or any material part of any of its Borrowing Base Assets unless each of the Agent and the Technical Bank has received a copy of any confirmation provided by the technical bank under the First Lien Credit Agreement to the Company confirming that if a new Projection (reflecting such an abandonment) were to be adopted, the same would not result in the Borrowers having to reduce the utilisations under the First Lien Credit Agreement in accordance with the First Lien Credit Agreement following the adoption of that Projection;
(C)	not exercise its rights on any operating or similar committee in a manner that would be materially prejudicial to the interests of any Finance Party under the Finance Documents; and
(D)	maintain full and proper technical and financial records in relation to each of its Borrowing Base Assets, and ensure (so far as it is able) that the Agent (and/or any person nominated by it) is afforded reasonable access to each of its Borrowing Base Assets and all such records during normal business hours on reasonable notice.

25.13.2 The Obligors shall ensure that no request is made under the First Lien Credit Agreement for any Petroleum Asset to be designated a new Borrowing Base Asset under the First Lien Credit Agreement without the prior consent of the Lenders.

25.14	Taxes
	Each Obligor shall, and the Company shall procure that each member of the Group shall:

25.14.1	maintain its tax residence in the relevant country of incorporation;
25.14.2	procure that all Taxes payable by, or assessed upon, it are paid when due save to the extent that such payment is being contested in good faith and being lawfully withheld;
25.14.3	to the fullest extent it is able to do so, apply any and all tax credits, losses, reliefs or allowances taken into account in any Projection at any time in the manner, at the time and to the extent that they were so taken into account;
25.14.4	not surrender or dispose of any tax credit, loss, relief or allowance to any person other than an Obligor; and
25.14.5	file all tax returns required to be filed by it in any jurisdiction within the period required by law.

25.15	Securitisation
	Each Obligor shall:

25.15.1	give the Lenders such assistance as they may reasonably request, and provide such information as such Lender may reasonably request, in connection with any steps that Lender may wish to take to achieve a successful securitisation of all or part of its rights under this Agreement whether alone or in conjunction with any other loan or loans;
25.15.2	make such amendments of an administrative or a technical nature to the Finance Documents as may be reasonably requested by the Lenders in connection with any such securitisation; and
25.15.3	use all reasonable endeavours to take such steps as a Lender may require to ensure full compliance with the listing rules of any applicable stock exchange that may become applicable as a result of any such securitisation.

25.16 Security Documents

25.16.1 Save as disclosed in Section D of the Due Diligence Report and save, for any registration of the Security Documents which is to be undertaken by the Lenders’ legal counsel, each Obligor shall, and shall ensure that each member of the Group party to any Security Document shall, take all such steps (including the obtaining and/or carrying out of all relevant approvals, filings, registrations or recordings) as are available to it and as are reasonably necessary for the purposes of ensuring that each Security Document:

(A)	confers the Security of the type it purports to create over the assets over which a Security is purported to be given by that Security Document;
(B)	is valid and enforceable against the relevant member of the Group which is party thereto and such Group member’s Insolvency Officers and creditors; and
(C)	is not capable of being avoided or set aside, whether in the winding up, administration or dissolution or otherwise of such member of the Group.

25.16.2 Without prejudice to Clause 25.16.1 each Obligor shall, and shall ensure that each member of the Group party to any Security Document shall, promptly pay all stamp, registration and similar taxes and fees that are payable in connection with each Security Document to which it is a party.

25.17	Petroleum won and saved
	Each Obligor shall use all reasonable endeavours to procure that all Petroleum won and saved from any Borrowing Base Asset and which it is entitled to lift is dealt with in accordance with good commercial practice and is sold (whether pursuant to a spot or term contract) on the best terms (as to price and otherwise) as are reasonably available to companies of comparable standing to the relevant Obligor at the date the relevant contract is entered into.
25.18	Ownership
	The Company must (subject only to any Security constituted under any Security Document) at all times beneficially and legally own (whether directly or indirectly) the whole of the issued share capital of each Obligor (other than itself).
25.19	Distributions

25.19.1	Subject to Clause 25.19.3 and Clause 25.19.4, at any time while a Default has occurred and is continuing, no Obligor shall, and the Company shall ensure that no member of the Group shall, make or pay, or permit to be made or paid, any dividend or distribution (whether in cash or in kind) in relation to its share capital, any redemption or reduction of any share capital, any payments in respect of any loans made available to it by any Affiliate or any other distribution to any of its shareholders save for any of the foregoing in and among or to the Obligors and any dividend or distribution that has been declared prior to the occurrence of any such Default.
25.19.2	No Obligor may, and each Obligor shall ensure that no member of the Group will, agree to any arrangement (other than the Finance Documents or the First Lien Credit Agreement) which may restrict its ability to declare, make or pay any dividend, distribution or any payments referred to in Clause 25.19.1.
25.19.3	Subject to Clause 25.19.4, no Obligor may, and each Obligor shall ensure that no member of the Group will, make or pay any dividend or distribution in relation to its share capital in cash save (i) to the extent the same has been approved by the Agent, at its sole discretion and (ii) in respect of the $125,000,000 preferred series C stock holders.
25.19.4	The aggregate amount of any dividend, distribution or any other payments referred to in Clause 25.19.1 made to person(s) other than the Obligors in accordance with this Clause 25.19 at any time on or after the Amendment Effective Date must not exceed $3,000,000 (or its equivalent in one or more other currencies).

25.20 Hedging

25.20.1	Each Obligor shall comply with the requirements of the First Lien Credit Agreement with respect to the entry into any Hedging Agreements.
25.20.2	Promptly upon request, the Company shall provide to the Agent a report (in a form satisfactory to the Agent, acting reasonably) which confirms whether the Obligors are in compliance with such requirements of the First Lien Credit Agreement.
25.20.3	No Obligor may enter into any Hedging Agreement unless:

(A)	such Hedging Agreement has been entered into pursuant to Clause 25.20.1 in connection with the Borrowing Base Assets;
(B)	such Hedging Agreement has been entered into with a Hedging Bank or such other hedging counterparty that has a credit rating of at least A3 with Moody’s

	Investors Service Inc. or A- with Standard and Poor’s Rating Group or such other lower credit rating as may be acceptable to the Majority Lenders; and
(C)	in the case of any such Hedging Agreement with a Hedging Bank, that Hedging Agreement has been entered into in compliance with the Intercreditor Agreement.

25.20.4 Each Obligor that enters into a Hedging Agreement on or after Amendment Effective Date shall:

(A)	enter into a Security Document in form and substance satisfactory to the Security Trustee for the purposes of granting Security over that Hedging Agreement in favour of the Security Trustee unless Security over such Hedging Agreement has been granted to the Security Trustee under any existing Security Document;
(B)	without prejudice to Clause 25.16 (Security Documents), promptly obtain all such Authorisations as may be necessary in order for such Security to be granted; and
(C)	deliver to the Security Trustee, or procure the delivery to the Security Trustee of, any legal opinion or other document that the Security Trustee or the Agent may reasonably require in connection with the entry into such Security Document.

25.20.5 Save for:

(A)	any Security that is permitted to be granted pursuant to Clause 25.4 (Negative pledge) in respect of any such Hedging Agreement; and
(B)	any guarantee that is permitted pursuant to Clause 25.6 (Financial Indebtedness) and Clause 25.7 (Credits and guarantees) in respect of any such Hedging Agreement,

	no Obligor may, and each Obligor shall ensure that no member of the Group shall, enter into any margin call arrangement, post any collateral or credit support, grant any Security or otherwise give any guarantee or other financial accommodation in respect of any Hedging Agreement that such Obligor or, as the case may be, such member of the Group enters into.
25.20.6	The Obligors shall ensure that no member of the Group (other than an Obligor) enters into any Hedging Agreement.
25.20.7	No Obligor shall after the Amendment Effective Date enter into any Hedging Agreement under any Master Agreement, Schedule or other agreement in effect prior to the date of the First Lien Credit Agreement, except a Master Agreement in respect of the existing commodity hedges which the Group has in place with J. Aron and Company (a Goldman Sachs subsidiary).

25.21	Non-Recourse Subsidiaries
	Unless the Agent (acting reasonably) shall otherwise agree in writing, the Company:

25.21.1 will procure that (i) no investment in any Non-Recourse Subsidiary is made by any member of the Group (whether represented by amounts subscribed for shares, debentures or otherwise howsoever) and (ii) no Non-Recourse Subsidiary will incur or permit to remain outstanding any indebtedness (whether present, future, actual or contingent) or other liability to any member of the Group, unless (x) (in every such

	case) at the time such investment is made or indebtedness or other liability is incurred, no Default is continuing and immediately prior to the making of such investment or such indebtedness or other liability being incurred a director of the Company has certified on behalf of the Company that no Default is continuing and (y) the Company would, under the terms of this Agreement, otherwise be free to pay an amount equal to the amount of such investment, indebtedness or liability to its shareholders by way of dividend;
25.21.2	without prejudice to the generality of the foregoing, it will procure that no member of the Group gives any guarantee, undertaking or indemnity or undertakes to permit to subsist any other liability whatsoever contingent or otherwise in favour of or in respect of an obligation of any Non-Recourse Subsidiary (whether in respect of indebtedness or the performance of any obligation or otherwise howsoever);
25.21.3	without prejudice to the foregoing, it will ensure that all transactions entered into between any member of the Group and any Non-Recourse Subsidiary (other than the declaration or payment of any dividend or other distribution by a Non-Recourse Subsidiary to a member of the Group) shall be on an arms length basis and on normal commercial terms;
25.21.4	will ensure that no Non-Recourse Subsidiary acquires any interest in or entitlement to (or to the revenues from) any asset the revenues from which were included in a Projection;
25.21.5	will ensure that no Non-Recourse Subsidiary itself has any Subsidiary other than a Subsidiary which is also a Non-Recourse Subsidiary;
25.21.6	will procure that, insofar as there is a significant risk that it might materially affect the ability of any Obligor to perform any of their obligations under the Transaction Documents or might otherwise result in a liability being imposed on any Finance Party, each Non-Recourse Subsidiary:

(A)	exercises all its powers to obtain and maintain in full force and effect all material Authorisations applicable to it and will comply in all material respects with all conditions and obligations to which such material Authorisations may be subject;
(B)	carries on its business as a whole in a prudent manner and uses all reasonable endeavours to procure that each Petroleum interest of it is operated in accordance with good oilfield practice;
(C)	promptly pays as and when due, unless and to the extent only that such royalties, Taxes and duties are being contested by it in good faith, all royalties, Taxes and duties of whatsoever kind and whether payable in the United Kingdom or elsewhere; and
(D)	complies with all laws and regulations, applicable to it (including all Environmental Laws and Licences) in all material respects;

25.21.7 will procure that each Non-Recourse Subsidiary, (i) promptly upon becoming aware of the same, gives written notice to the Agent of every notice of default or adverse claim or demand made by any person against such Non-Recourse Subsidiary affecting any of its assets of whatsoever nature (disregarding for this purpose any of the aforesaid of a spurious nature) if such default (if proved) or claim or demand (if successful) is reasonably likely to result in a liability being imposed on any member of the Group and (ii) diligently takes all reasonable steps open to such Non-Recourse Subsidiary to

	remedy any such default and protect and defend its interest in the relevant asset against any such adverse claim or demand; and
25.21.8	will procure that each Non-Recourse Subsidiary, as soon as reasonably practicable following request by the Agent, provides to the Agent such information as the Agent may reasonably request for the purpose of monitoring compliance with the representations, covenants and other obligations hereunder which have application to Non-Recourse Subsidiaries.

25.22 Key Assets

25.22.1	Each Obligor shall, and shall procure that each member of the Group shall, exercise such votes and other rights as it may have with respect to the Key Assets for the purposes ensuring (so far as it is able) that each Key Asset is at all times exploited and operated in a reasonable and prudent manner and in accordance with good industry practice and all applicable laws and regulations.
25.22.2	Each Obligor shall not, and each Obligor shall ensure that no member of the Group will:

(A)	do or cause or (in so far as it is able) permit to be done anything which may reasonably be expected to depreciate, jeopardise or otherwise prejudice the value of any Key Asset in a material manner; and
(B)	enter into any arrangements (other than the Finance Documents, or in the case of Clause 25.22.2(B)(2), the existing arrangements under clause 23.5 (Disposals) of the First Lien Credit Agreement as at the Amendment Effective Date) which restricts its ability to dispose of:

(1)	any Key Asset; or
(2)	any of its shareholding in any person holding any interest in any Key Asset.

25.23	Senior facility
	No Obligor shall, and each Obligor shall procure that no member of the Group will agree to or permit to be made, any modification of any First Lien Documents without the consent of the Majority Lenders if:

25.23.1

such modification has the effect of increasing the amount that the borrower(s) under the First Lien Credit Agreement are entitled to draw under the First Lien Credit Agreement other than as a result of any increase to the Tranche A Borrowing Base Amount or the Tranche B Borrowing Base Amount (as the case may be) which takes effect in accordance with the terms of the First Lien Credit Agreement as at the Amendment Effective Date; or

25.23.2

as a result of such modification, the Obligors or any member of the Group would be obliged to repay the outstanding utilisations, or to make any other payments, under the First Lien Credit Agreement in connection with any Key Asset Disposal in circumstances or in amounts that are not provided for under the terms of the First Lien Documents as at the Amendment Effective Date (where, for these purposes, “Key Asset Disposal” means any disposal by any member of the Group of any of its interest in any Key Asset or its shares in any member of the Group that holds any interest in any Key Asset).

25.24	Condition subsequent
	The Obligors shall ensure that within 10 Business Days of the Amendment Effective Date:

25.24.1	Endeavour Energy UK Limited shall deliver to the Security Trustee or procure the delivery to the Security Trustee of a blocked control account control agreement (in form and substance satisfactory to the Agent (acting reasonably)), in respect of its bank accounts held with JPMorgan Chase or any of its Affiliates; and
25.24.2	Endeavour Operating Corporation shall deliver or procure the delivery to the Security Trustee of a blocked control account agreement (in form and substance satisfactory to the Security Trustee (acting reasonably)), in respect of its bank accounts held with JPMorgan Chase or any of its Affiliates.

25.25	No detrimental amendments
	Subject always to the Intercreditor Agreement, no Obligor may, and each Obligor shall ensure that no member of the Group will, to the extent that this Agreement incorporates the terms (including definitions) of the First Lien Credit Agreement, agree to modify any such incorporated or related term without the consent of the Majority Lenders if as a result of such modification, the rights or interests of the Finance Parties hereunder would be prejudiced in any material way.
26.	FINANCIAL COVENANTS
26.1	Definitions
	In this Clause 26 (Financial covenants):

26.1.1 “Consolidated Cash and Cash Equivalents” means, at any time:

(A)	cash in hand or on deposit with any acceptable bank (including cash collateral balances for decommissioning costs and debt service cash balances);
(B)	certificates of deposit, maturing within one year after the relevant date of calculation, issued by an acceptable bank;
(C)	any investment in marketable obligations issued or guaranteed by the government of the United States of America or the U.K. or by an instrumentality or agency of the government of the United States of America or the U.K. having an equivalent credit rating;
(D)	open market commercial paper:

(1)	for which a recognised trading market exists;
(2)	issued in the United States of America or the U.K.;
(3)	which matures within one year after the relevant date of calculation; and
(4)	which has a credit rating of either A 1 by Standard & Poor’s or Fitch or P 1 by Moody’s, or, if no rating is available in respect of the commercial paper, the issuer of which has, in respect of its long term debt obligations, an equivalent rating;

(E)	Sterling bills of exchange eligible for rediscount at the Bank of England and accepted by an acceptable bank; or
(F)	any other instrument, security or investment approved by the Majority Lenders,

in each case, to which any member of the Group is beneficially entitled at that time and which is capable of being applied against Consolidated Total Borrowings. An “acceptable bank” for this purpose is a commercial bank or trust company which has a rating of A- or higher by Standard & Poor’s Rating Group or Fitch or A3 or higher by Moody’s Investors Service Inc. or a comparable rating from an internationally recognised credit rating agency for its long term debt obligations or has been approved by the Majority Lenders.

26.1.2 “Consolidated EBITDA” means the consolidated gross pre taxation profits of the Group for a Measurement Period:

(A)	excluding the gross pre taxation profits of a member of the Group for that part of that Measurement Period when it was not a member of the Group and the gross pre taxation profits relating to business or assets acquired by a member of the Group during that Measurement Period for that part of that Measurement Period when the business or assets were not owned by a member of the Group; and
(B)	excluding the gross pre taxation profits attributable to any member of the Group or to any business or assets sold during that Measurement Period,

and all as adjusted by:

(1)	adding back Consolidated Net Interest Payable;
(2)	taking no account of any exceptional or extraordinary item;
(3)	excluding any amount attributable to minority interests;
(4)	adding back depreciation, depletion, amortisation and all exploration and appraisal write-offs;
(5)	taking no account of any revaluation of an asset or any loss or gain over book value arising on the disposal of an asset (otherwise than in the ordinary course of trading) by a member of the Group during that Measurement Period;
(6)	adding back any non-cash decommissioning charges;
(7)	adding back any non-cash impairment charges; and
(8)	taking no account of any other non-cash charges or credits (including any non-cash charges or credits arising by reason of the operation of IAS 17 or IAS 39).

26.1.3	“Consolidated Interest Payable” means all interest and other financing charges (whether, in each case, paid, payable or capitalised) incurred by the Group during a Measurement Period (excluding any amortisation of any financing fees which have been paid and any amortisation of any interest related to decommissioning liabilities).
26.1.4	“Consolidated Interest Receivable” means all interest and other financing charges received or receivable by the Group during a Measurement Period.
26.1.5	“Consolidated Net Interest Payable” means Consolidated Interest Payable less Consolidated Interest Receivable during the relevant Measurement Period.
26.1.6	“Consolidated Total Borrowings” means, in respect of the Group, at any time the aggregate of the following:

(A) the outstanding principal amount of any moneys borrowed;

(B)	the outstanding principal amount of any acceptance under any acceptance credit;
(C)	the outstanding principal amount of any bond, note, debenture, loan stock or other similar instrument;
(D)	the capital element of indebtedness under a finance or capital lease;
(E)	the outstanding principal amount of all moneys owing in connection with the sale or discounting of receivables (otherwise than on a non recourse basis);
(F)	the outstanding principal amount of any indebtedness arising from any deferred payment agreements arranged primarily as a method of raising finance or financing the acquisition of an asset;
(G)	any fixed or minimum premium payable on the repayment or redemption of any instrument referred to in paragraph (C) above;
(H)	the outstanding principal amount of any indebtedness arising in connection with any other transaction (including any forward sale or purchase agreement) which has the commercial effect of a borrowing;
(I)	the outstanding amount of any guarantee, indemnity, bond, letter of credit or any other instrument issued by a bank or financial institution in respect of which any member of the Group has provided a counter-indemnity; and
(J)	the outstanding principal amount of any indebtedness of any person of a type referred to in paragraphs (A) – (I) above which is the subject of a guarantee, indemnity or similar assurance against financial loss given by a member of the Group.

26.1.7	“Consolidated Total Net Borrowings” means at any time Consolidated Total Borrowings less Consolidated Cash and Cash Equivalents.
26.1.8	“Current Assets” means, in relation to the Group, the aggregate value of the current assets which are reasonably expected to be realised, consumed or sold in the ordinary course of the trading activities of the Group within one year of the date from which any calculation falls to be made together with cash at bank.
26.1.9	“Current Liabilities” means, in relation to the Group, the aggregate value of the current liabilities which are reasonably expected to be repayable or payable within one year from the date on which any calculation falls to be made but disregarding any amounts repayable under the First Lien Credit Agreement which it is anticipated are to be funded by way of a rollover loan thereunder.
26.1.10	“Current Ratio” means the ratio of Current Assets to Current Liabilities.
26.1.11	“IAS 17” means standard 17 (relating to leases) under IFRS.
26.1.12	“IAS 39” means standard 39 (relating to financial instruments) under IFRS.
26.1.13	“Measurement Period” means each of the two consecutive six month periods in a financial year of the Company.

26.2 Interpretation

26.2.1 Except as provided to the contrary in this Agreement, an accounting term used in this Clause is to be construed in accordance with the principles applied in the preparation of the financial statements delivered in accordance with Clause 24.1 (Financial statements).

26.2.2 Any amount in a currency other than dollars is to be taken into account at its dollar equivalent calculated on the basis of:

(A)	the Agent’s spot rate of exchange for the purchase of the relevant currency in the London foreign exchange market for dollars at or about 11.00 a.m. on the day the relevant amount falls to be calculated; or
(B)	if the amount is to be calculated on the last day of a financial period of the Company, the relevant rates of exchange used by the Company in, or in connection with, its financial statements for that period.

26.2.3 No item must be credited or deducted more than once in any calculation under this Clause 26 (Financial Covenant).

26.3	Current Ratio
	The Company must ensure that the Current Ratio on the last day of each Measurement Period is greater than 1.1:1
26.4	Gearing
	The Company must ensure that the ratio of (1) Consolidated Total Net Borrowings to (2) Consolidated EBITDA on the last day of each Measurement Period is less than or equal to 3.0:1.
26.5	Compliance
	The financial covenants set out in Clauses 26.3 (Current Ratio) and 26.4 (Gearing) shall be tested by reference to each of the financial statements most recently delivered pursuant to Clause 24.1 (Financial statements).
26.6	Verification
	The Agent may, at any time, at the Company’s expense, require the auditors of the Company to verify any figure or calculation made in any certificate delivered pursuant to Clause 24.1.4 (Financial Statements) if it reasonably believes that any such figure or calculation is incorrect. If the Agent is not satisfied (acting reasonably) with the verification provided by the auditors, it may, at the Company’s expense, appoint an independent firm of accountants to investigate and verify the relevant figures. Such verification shall be conclusive evidence of whether the Company is in compliance with Clause 26 (Financial Covenant).
26.7	Reserves Value

26.7.1	The Company must ensure that the Coverage Ratio on each 30 June and 31 December of each year exceeds 2:1.
26.7.2	For the purposes of this Agreement, “Coverage Ratio” means, on any date, the ratio of N:D where:

(A)	“N” is an amount (expressed in dollars) which is the fair market value (as determined by the Technical Bank acting reasonably and in consultation with the Company) of the aggregate amount of the Group’s share of the Probable Reserves that are projected, in the Reserves Report most recently delivered to the Technical Bank under this Agreement, to be recoverable from the Petroleum Assets referred to in such Reserves Report;
(B)	“D” is the sum of the aggregate commitments under the First Lien Credit Agreement on that date and the Aggregate Commitments on that date;
(C)	in determining “N”, the Technical Bank shall attribute an approved value (expressed in dollars per boe) to the Probable Reserves recoverable from each

	Petroleum Asset referred to in the relevant Reserves Report most recently delivered to the Technical Bank; and
(D)	the “approved value” means, in relation to the Probable Reserves recoverable from any Petroleum Asset, $20 per boe as reduced by the Technical Bank (acting reasonably) to take account of:

(1)	the capital expenditure anticipated to be incurred in connection with such Petroleum Asset;
(2)	the extent to which that Petroleum Asset is required to be developed in order for the same to be producing Petroleum in commercial quantities; and
(3)	the commerciality or commercial position of that Petroleum Asset.

27.	EVENTS OF DEFAULT
27.1	General
	Each of the events or circumstances set out in Clause 27.2 (Non-payment and failure to reduce) to Clause 27.22 (Senior defaults) (inclusive) is an Event of Default.
27.2	Non-payment and failure to reduce
	An Obligor or any Transaction Party does not pay on the due date any amount payable by it under the Finance Documents in the manner required under the Finance Documents, unless the non-payment:

27.2.1	is caused by technical or administrative error or a Disruption Event; and
27.2.2	is remedied within two Business Days of the due date.

27.3 Breach of other obligations

27.3.1	The Company does not comply with any term of Clause 26 (Financial Covenants).
27.3.2	An Obligor or any Transaction Party does not comply with any other term of the Finance Documents to which it is a party not already referred to in Clause 27.3.1, unless the non-compliance:

(A)	in the reasonable opinion of the Majority Lenders, is capable of remedy; and
(B)	is remedied within 10 Business Days of the earlier of the Agent giving notice and the relevant Obligor or Transaction Party (as the case may be) becoming aware of the non-compliance.

27.4	Misrepresentation
	A representation made or repeated by any Obligor or Transaction Party in any Finance Document to which it is a party or in any document delivered by or on behalf of any Obligor or Transaction Party under any Finance Document to which it is a party is incorrect in any material respect when made or deemed to be repeated, unless the circumstances giving rise to the misrepresentation:

27.4.1	are capable of remedy; and
27.4.2	are remedied within 10 Business Days of the earlier of the Agent giving notice and the relevant Obligor or Transaction Party (as the case may be) becoming aware of the misrepresentation.

27.5	Cross-default
	Any of the following occurs in respect of an Obligor or any other member of the Group:

27.5.1	any of its Financial Indebtedness is not paid when due and payable (after the expiry of any originally applicable grace period);
27.5.2	any of its Financial Indebtedness:

(A)	becomes prematurely due and payable;
(B)	is placed on demand; or
(C)	is capable of being declared by a creditor to be prematurely due and payable or being placed on demand,

	in each case, as a result of an event of default (howsoever described); or
27.5.3	any commitment for its Financial Indebtedness is cancelled or suspended as a result of an event of default (howsoever described),
	unless the aggregate amount of Financial Indebtedness falling within Clause 27.5.1, Clause 27.5.2 or Clause 27.5.2(C) (as the case may be) is less than $10,000,000 (or its equivalent in one or more other currencies).

27.6	Insolvency
	Any of the following occurs in respect of an Obligor or any other member of the Group:

27.6.1	it is, or is deemed for the purposes of any law to be, unable to pay its debts as they fall due or insolvent;
27.6.2	it admits its inability to pay its debts as they fall due;
27.6.3	it suspends making payments on any of its debts or announces an intention to do so;
27.6.4	by reason of actual or anticipated financial difficulties, it begins negotiations with any creditor for the rescheduling of any of its indebtedness; or
27.6.5	a moratorium is declared in respect of any of its indebtedness.

27.7 Insolvency proceedings

27.7.1 Except as provided in Clause 27.7.2, any of the following occurs in respect of an Obligor or any other member of the Group:

(A)	any step is taken with a view to a faillissement, surséance van betaling, composition, assignment or similar arrangement with any of its creditors;
(B)	a meeting of it is convened for the purpose of considering any resolution for (or to petition for) its winding-up, administration, or dissolution or any such resolution is passed;
(C)	any person presents a petition, files an application or takes any other analogous steps for its winding-up, administration, or dissolution;
(D)	an order for its winding-up, administration, or dissolution is made;
(E)	any Insolvency Officer is appointed in respect of it or any of its assets;
(F)	its directors or other officers request the appointment of an Insolvency Officer;
(G)	a notice under section 36 of the Tax Collection Act of the Netherlands (Invorderingswet 1990) or section 60 of the Social Insurance Financing Act of the Netherlands (Wet Financiering Sociale Verzekeringen) in conjunction with section 36 of the Tax Collection Act of the Netherlands (Invorderingswet 1990) is filed upon a member of the Group that is incorporated or established in the Netherlands; or

(H) any other analogous step or procedure is taken in any jurisdiction.

27.7.2 Clause 27.7.1 does not apply to:

(A)	any step or procedure which is part of a Permitted Transaction; or
(B)	a petition for winding-up presented by a creditor which is being contested in good faith and with due diligence and is discharged or struck out within 14 days; or
(C)	any petition, action, proceeding or step which is demonstrated by the Company to the reasonable satisfaction of the Agent to be frivolous, vexatious or otherwise an abuse of process of court.

27.8	Enforcement of security
	Any steps are taken to enforce any Security securing Financial Indebtedness in excess of $5,000,000 (or its equivalent in one or more other currencies), in aggregate, over any part of the assets of an Obligor or any other member of the Group.
27.9	Creditors’ process
	Any prejudgment attachment (conservatoir Beslag), expropriation attachment, sequestration, distress, execution, diligence or analogous event affects any asset(s) of any Obligor or any other member of the Group having an aggregate value in excess of $5,000,000 (or its equivalent in one or more other currencies) and is not discharged within 14 days unless it is any petition, action, proceeding or step which is demonstrated by the Company to the reasonable satisfaction of the Agent to be frivolous, vexatious or otherwise an abuse of process of court.
27.10	Analogous proceedings
	There occurs, in relation to any Obligor or any other member of the Group, any event anywhere which, in the reasonable opinion of the Majority Lenders, corresponds with any of those mentioned in Clauses 27.6 (Insolvency) to 27.9 (Creditors’ process) (inclusive).
27.11	Cessation of business
	Any Obligor threatens to cease to carry on business except as part of a Permitted Transaction.
27.12	Unlawfulness
	It is or becomes unlawful for any Obligor to perform any of its material obligations under any Project Document.
27.13	Effectiveness of Finance Documents

27.13.1	It is or becomes unlawful for any Obligor or Transaction Party to perform any of its payment obligations or other material obligations under the Finance Documents.
27.13.2	Any Finance Document, the guarantee of any Guarantor or any Security purported to be created or evidenced by any Security Document is not effective or is unenforceable or is alleged by any Obligor or any Transaction Party to be ineffective or unenforceable for any reason.
27.13.3	An Obligor or Transaction Party repudiates a Finance Document or evidences an intention to repudiate a Finance Document.

27.14	Ownership
	Any member of the Group that holds any interests in any Borrowing Base Assets or Obligor is not or ceases to be a wholly-owned (directly or indirectly) by the Company.

27.15 Project Documents

27.15.1	All or any part of any Project Document is not, or ceases to be, a legal, valid and binding obligation of any person expressed to be party to it in circumstances which are reasonably likely to result in a Material Adverse Change.
27.15.2	Any party to any Project Document defaults under that Project Document in circumstances which are reasonably likely to result in a Material Adverse Change.
27.15.3	All or any part of any Project Document is suspended, terminated or revoked in circumstances which are reasonably likely to result in a Material Adverse Change.

27.16 Borrowing Base Assets

27.16.1

A decision is taken to abandon a Borrowing Base Asset unless such a decision was taken in compliance with Clause 25.13.2 (Borrowing Base Assets).

27.16.2

All or any part of the interest of any member of the Group in any Borrowing Base Asset or Key Asset (or, in each case, any Petroleum or revenues or other moneys arising in respect of it) is nationalised, expropriated, compulsorily acquired or seized by any government or any governmental or public sector agency, or any such government or agency takes, or officially announces that it will take, any step with a view to any of the foregoing and the same is reasonably likely to result in a Material Adverse Change.

27.17	Litigation
	Any judgment is made or award is issued against any Obligor in relation to any litigation, arbitration or administrative proceedings in an amount equal to or exceeding $10,000,000 (or its equivalent in one or more other currencies) or any litigation, arbitration or administrative proceeding is instituted or current in respect of any Obligor or any member of the Group which would be reasonably likely, if adversely determined, to result in a Material Adverse Change.
27.18	Authorisations
	Any Authorisation necessary for the ownership of any interest in, the development or the operation of, any Borrowing Base Asset is revoked, cancelled, surrendered, terminated or varied and the same would be reasonably likely to result in a Material Adverse Change.
27.19	Material Adverse Change
	An event occurs which is reasonably likely to result in a Material Adverse Change as compared to the position as at Amendment Effective Date.
27.20	Qualification of accounts
	Any audited financial statements delivered to the Agent under this Agreement is qualified in any material way.
27.21	Evidential inadmissibility
	At any time any act, condition or thing required to be done, fulfilled or performed (other than by the Finance Parties) in order to make each Finance Document to which any Obligor or Transaction Party is a party admissible in evidence in the country in which such party is incorporated is not done, fulfilled or performed to the extent or in a respect such that the effect thereof is materially to impair the legality, validity or enforceability of the obligations of any Obligor or any Transaction Party under the Finance Documents.

27.22	Senior defaults
	An Event of Default (as defined in the First Lien Credit Agreement) has occurred and is continuing.
27.23	Acceleration
	On and at any time after the occurrence of an Event of Default which is continuing the Agent may, and shall if so directed by the Majority Lenders, by notice to the Company:

27.23.1	cancel the Aggregate Commitments whereupon they shall immediately be cancelled; and/or
27.23.2	declare that all or part of the Loans, together with accrued interest, and all other amounts accrued or outstanding under the Finance Documents be immediately due and payable, whereupon they shall become immediately due and payable; and/or
27.23.3	declare that all or part of the Loans payable on demand, whereupon they shall immediately become payable on demand by the Agent on the instructions of the Majority Lenders.

CHANGES TO PARTIES

28.	CHANGES TO THE LENDERS
28.1	Assignments and transfers by the Lenders
	Subject to this Clause 28 (Changes to the Lenders), a Lender (the “Existing Lender”) may:

28.1.1	assign any of its rights; or
28.1.2	transfer by novation any of its rights and obligations,

	to another bank or financial institution or to a trust, fund or other entity which is regularly engaged in or established for the purpose of making, purchasing or investing in loans, securities or other financial assets (the “New Lender”).
28.2	Conditions of assignment or transfer

28.2.1	The consent of the Company is required for an assignment or transfer by an Existing Lender, unless subject to Clause 28.2.4(B) (a) the assignment or transfer is to another Lender or an Affiliate of a Lender or (b) an Event of Default has occurred and is continuing.
28.2.2	The consent of the Company to an assignment or transfer must not be unreasonably withheld or delayed. The Company will be deemed to have given its consent five Business Days after the Existing Lender has requested it unless consent is expressly refused by the Company within that time.
28.2.3	The consent of the Company to an assignment or transfer must not be withheld solely because the assignment or transfer may result in an increase to the Mandatory Cost.
28.2.4	An assignment will only be effective on:

(A)	receipt by the Agent (whether in the Assignment Agreement or otherwise) of written confirmation from the New Lender (in form and substance satisfactory to the Agent) that the New Lender will assume the same obligations to the other Finance Parties as it would have been under if it was an Original Lender; and
(B)	performance by the Agent of all necessary “know your customer” or other similar checks under all applicable laws and regulations in relation to such

assignment to a New Lender, the completion of which the Agent shall promptly notify to the Existing Lender and the New Lender.

28.2.5	In order to comply with the Dutch Financial Supervision Act (Wet op het financieel toezicht), any assignment or transfer by an Existing Lender pursuant to this Clause 24 shall in any event be in an amount of at least €50,000 (or its equivalent in any other currency) or such other amount as may be required form time to time by the Dutch Financial Supervision Act or, if less, the New Lender shall confirm in writing to the Company that it is a professional market party (professionele marktpartij) within the meaning of the Dutch Financial supervision Act (Wet op het financieel toezicht).
28.2.6	A transfer will only be effective if the procedure set out in Clause 28.5 (Procedure for transfer) is complied with.
28.2.7	If:

(A)	a Lender assigns or transfers any of its rights or obligations under the Finance Documents or changes its Facility Office; and
(B)	as a result of circumstances existing at the date the assignment, transfer or change occurs, an Obligor would be obliged to make a payment to the New Lender or Lender acting through its new Facility Office under Clause 17 (Tax gross-up and indemnities) or Clause 18 (Increased Costs),

then the New Lender or Lender acting through its new Facility Office is only entitled to receive payment under those Clauses to the same extent as the Existing Lender or Lender acting through its previous Facility Office would have been if the assignment, transfer or change had not occurred.

28.2.8

Each New Lender, by executing the relevant Transfer Certificate or Assignment Agreement, confirms, for the avoidance of doubt, that the Agent has authority to execute on its behalf any amendment or waiver that has been approved by or on behalf of the requisite Lender or Lenders in accordance with this Agreement on or prior to the date on which the transfer or assignment becomes effective in accordance with this Agreement and that it is bound by that decision to the same extent as the Existing Lender would have been had it remained a Lender

28.3	Assignment or transfer fee
	The New Lender shall, on the date upon which an assignment or transfer takes effect pay to the Agent (for its own account) a fee of $2,000.
28.4	Limitation of responsibility of Existing Lenders

28.4.1 Unless expressly agreed to the contrary, an Existing Lender and each existing Finance Party makes no representation or warranty and assumes no responsibility to a New Lender for:

(A)	the legality, validity, effectiveness, adequacy or enforceability of the Finance Documents or any other documents;
(B)	the financial condition of any Obligor or any other member of the Group;
(C)	the performance and observance by any Obligor or any other member of the Group of its obligations under the Finance Documents or any other documents; or
(D)	the accuracy of any statements (whether written or oral) made in or in connection with any Finance Document or any other document,

	and any representations or warranties implied by law are excluded.
28.4.2	Each New Lender confirms to the Existing Lender and the other Finance Parties that it:

(A)	has made (and shall continue to make) its own independent investigation and assessment of the financial condition and affairs of each Obligor and its related entities in connection with its participation in this Agreement and has not relied exclusively on any information provided to it by the Existing Lender or any existing Finance Party in connection with any Finance Document; and
(B)	will continue to make its own independent appraisal of the creditworthiness of each Obligor and its related entities whilst any amount is or may be outstanding under the Finance Documents or any Commitment is in force.

28.4.3 Nothing in any Finance Document obliges an Existing Lender or any existing Finance Party to:

(A)	accept a re-transfer or re-assignment from a New Lender of any of the rights and obligations assigned or transferred under this Clause 28 (Changes to the Lenders); or
(B)	support any losses directly or indirectly incurred by the New Lender by reason of the non-performance by any Obligor or Transaction Party of its obligations under the Finance Documents or otherwise.

28.5 Procedure for transfer

28.5.1	Subject to the conditions set out in Clause 28.2 (Conditions of assignment or transfer) a transfer is effected in accordance with Clause 28.5.3 when the Agent executes an otherwise duly completed Transfer Certificate delivered to it by the Existing Lender and the New Lender. The Agent shall, subject to Clause 28.5.2 below, as soon as reasonably practicable after receipt by it of a duly completed Transfer Certificate appearing on its face to comply with the terms of this Agreement and delivered in accordance with the terms of this Agreement, execute that Transfer Certificate.
28.5.2	The Agent shall only be obliged to execute a Transfer Certificate delivered to it by the Existing Lender and the New Lender once it is satisfied it has complied with all necessary “know your customer” or other similar checks under all applicable laws and regulations in relation to the transfer to such New Lender.
28.5.3	Subject to Clause 28.9 (Pro-rata interest settlement), on the Transfer Date:

(A)	to the extent that in the Transfer Certificate the Existing Lender seeks to transfer by novation its rights and obligations under the Finance Documents each of the Obligors and the Existing Lender shall be released from further obligations towards one another under the Finance Documents and their respective rights against one another under the Finance Documents shall be cancelled (being the “Discharged Rights and Obligations”);
(B)	each of the Obligors and the New Lender shall assume obligations towards one another and/or acquire rights against one another which differ from the Discharged Rights and Obligations only insofar as that Obligor and the New Lender have assumed and/or acquired the same in place of that Obligor and the Existing Lender;
(C)	the existing Finance Parties and the New Lender shall acquire the same rights and assume the same obligations between themselves as they would have

	acquired and assumed had the New Lender been an Original Lender with the rights and/or obligations acquired or assumed by it as a result of the transfer and to that extent the existing Finance Parties and the Existing Lender shall each be released from further obligations to each other under the Finance Documents; and
(D)	the New Lender shall become a Party as a “Lender”.

28.6 Procedure for assignment

28.6.1	Subject to the conditions set out in Clause 28.2 (Conditions of assignment or transfer) an assignment may be effected in accordance with Clause 28.6.3 below when the Agent executes an otherwise duly completed Assignment Agreement delivered to it by the Existing Lender and the New Lender. The Agent shall, subject to Clause 28.6.2 below, as soon as reasonably practicable after receipt by it of a duly completed Assignment Agreement appearing on its face to comply with the terms of this Agreement and delivered in accordance with the terms of this Agreement, execute that Assignment Agreement.
28.6.2	The Agent shall only be obliged to execute an Assignment Agreement delivered to it by the Existing Lender and the New Lender once it is satisfied it has complied with all necessary “know your customer” or other similar checks under all applicable laws and regulations in relation to the assignment to such New Lender.
28.6.3	Subject to Clause 28.9 (Pro rata interest settlement), on the Transfer Date:

(A)	the Existing Lender will assign absolutely to the New Lender the rights under the Finance Documents expressed to be the subject of the assignment in the Assignment Agreement;
(B)	the Existing Lender will be released by each Obligor and the other Finance Parties from the obligations owed by it (the “Relevant Obligations”) and expressed to be the subject of the release in the Assignment Agreement; and
(C)	the New Lender shall become a Party as a “Lender” and will be bound by obligations equivalent to the Relevant Obligations.

28.6.4 Lenders may utilise procedures other than those set out in this Clause 28.6 (Procedure for assignment) to assign their rights under the Finance Documents (but not, without the consent of the relevant Obligor or unless in accordance with Clause 28.5 (Procedure for transfer), to obtain a release by that Obligor from the obligations owed to that Obligor by the Lenders nor the assumption of equivalent obligations by a New Lender) provided that they comply with the conditions set out in Clause 28.2 (Conditions of assignment or transfer).

28.7	Copy of Transfer Certificate or Assignment Agreement to Company
	The Agent shall, as soon as reasonably practicable after it has executed a Transfer Certificate or an Assignment Agreement, send to the Company a copy of that Transfer Certificate or Assignment Agreement.
28.8	Security over Lenders’ rights
	In addition to the other rights provided to Lenders under this Clause 28.8, each Lender may without consulting with or obtaining consent from any Obligor, at any time charge, assign or otherwise create Security in or over (whether by way of collateral or otherwise) all or any of its

rights under any Finance Document to secure obligations of that Lender including, without limitation:

28.8.1	any charge, assignment or other Security to secure obligations to a federal reserve or central bank; and
28.8.2	in the case of any Lender which is a fund, any charge, assignment or other Security granted to any holders (or trustee or representatives of holders) of obligations owed, or securities issued, by that Lender as security for those obligations or securities,

except that no such charge, assignment or Security shall:

(A)	release a Lender from any of its obligations under the Finance Documents or substitute the beneficiary of the relevant charge, assignment or Security for the Lender as a party to any of the Finance Documents; or
(B)	require any payments to be made by an Obligor other than or in excess of, or grant to any person any more extensive rights than, those required to be made or granted to the relevant Lender under the Finance Documents.

28.9

Pro rata interest settlement

If the Agent has notified the Lenders that it is able to distribute interest payments on a “pro rata basis” to Existing Lenders and New Lenders then (in respect of any transfer pursuant to Clause 28.5 (Procedure for transfer) or any assignment pursuant to Clause 28.6 (Procedure for assignment) the Transfer Date of which, in each case, is after the date of such notification and is not on the last day of an Interest Period):

28.9.1

any interest or fees in respect of the relevant participation which are expressed to accrue by reference to the lapse of time shall continue to accrue in favour of the Existing Lender up to but excluding the Transfer Date (“Accrued Amounts”) and shall become due and payable to the Existing Lender (without further interest accruing on them) on the last day of the current Interest Period (or, if the Interest Period is longer than six Months, on the next of the dates which falls at six Monthly intervals after the first day of that Interest Period); and

28.9.2

the rights assigned or transferred by the Existing Lender will not include the right to the Accrued Amounts, so that, for the avoidance of doubt:

(A)	when the Accrued Amounts become payable, those Accrued Amounts will be payable to the Existing Lender; and
(B)	the amount payable to the New Lender on that date will be the amount which would, but for the application of this Clause 28.9, have been payable to it on that date, but after deduction of the Accrued Amounts.

29.	CHANGES TO THE OBLIGORS
29.1	Assignments and transfer by Obligors
	No Obligor may assign any of its rights or transfer any of its rights or obligations under the Finance Documents.
29.2	Additional Borrowers

29.2.1 Subject to compliance with Clauses 24.8.3 and 24.8.4 (“Know your customer” checks) the Company may request that any Relevant Affiliate becomes an Additional Borrower. That Relevant Affiliate shall become an Additional Borrower if:

(A)	all Lenders approve the addition of that Relevant Affiliate,
(B)	that Relevant Affiliate (a) delivers to the Agent a duly completed and executed Accession Letter and (b) executes and enters into all other documents and takes all such other steps as the Agent may reasonably require for the purposes of ensuring that it accedes and becomes a party to, all relevant Finance Documents as an Additional Borrower;
(C)	the Company confirms that no Default is continuing or would occur as a result of that Relevant Affiliate becoming an Additional Borrower; and
(D)	the Agent has received all of the documents and other evidence listed in Part II (Conditions precedent required to be delivered by an Additional Obligor) of Schedule 3 (Conditions precedent) in relation to that Additional Borrower, each in form and substance satisfactory to the Agent.

29.2.2 The Agent shall, in relation to each proposed Additional Borrower, notify the Company and the Lenders promptly upon being satisfied that it has received (in form and substance satisfactory to it) all the documents and other evidence listed in Part II (Conditions precedent required to be delivered by an Additional Obligor) of Schedule 3 (Conditions precedent).

29.3 Additional Guarantors

29.3.1 Subject to compliance with Clauses 24.8.3 and 24.8.4 (“Know your customer” checks) the Company may request that any Relevant Affiliate becomes an Additional Guarantor. That Relevant Affiliate shall become an Additional Guarantor if:

(A)	that Relevant Affiliate (a) delivers to the Agent a duly completed and executed Accession Letter and (b) executes and enters into all other documents and takes all such other steps as the Agent may reasonably require for the purposes of ensuring that it accedes and becomes a party to, all relevant Finance Documents as an Additional Guarantor; and
(B)	the Agent has received all of the documents and other evidence listed in Part II (Conditions precedent required to be delivered by an Additional Obligor) of Schedule 3 (Conditions precedent) in relation to that Additional Guarantor, each in form and substance satisfactory to the Agent.

29.3.2 The Company shall procure that (i) promptly upon any member of the Group becoming a Material Subsidiary and (ii) prior to any member of the Borrower Group acquiring a Borrowing Base Asset (if it is not already an Obligor) it shall become an Additional Guarantor (unless prohibited under the laws of their jurisdiction of incorporation, despite the Company and such member of the Group or Borrower Group having used all reasonable endeavours to overcome such prohibition) and shall ensure that:

(A)	such member of the group (a) delivers to the Agent a duly completed and executed Accession Letter and (b) executes and enters into all other documents and takes all such other steps as the Agent may reasonably require for the purposes of ensuring that it accedes and becomes a party to, all relevant Finance Documents as an Additional Guarantor; and
(B)	the Agent receives all of the documents and other evidence listed in Part II (Conditions precedent required to be delivered by an Additional Obligor) of Schedule 3 (Conditions precedent) in relation to that Additional Guarantor, each in form and substance satisfactory to the Agent.

29.3.3 The Agent shall, in relation to each proposed Additional Guarantor, notify the Company and the Lenders promptly upon being satisfied that it has received (in form and substance satisfactory to it) all the documents and other evidence listed in Part II (Conditions precedent required to be delivered by an Additional Obligor) of Schedule 3 (Conditions precedent).

29.4	Repetition of Representations
	Delivery of an Accession Letter constitutes confirmation by the relevant intended Obligor that the Repeating Representations are true and correct in relation to it as at the date of delivery as if made by reference to the facts and circumstances then existing.
29.5	Release of non-asset holding Obligors

29.5.1	For the purposes of this Clause 29.5 (Release of non-asset holding Obligors), a “Relevant Obligor” means any Obligor (other than the Company) that (a) does not have an interest in any Borrowing Base Asset or any shares or other interest in any person holding an interest in any Borrowing Base Asset (whether by reason of any Borrowing Base Asset ceasing to be so designated in accordance with this Agreement or otherwise) and (b) is not a Material Subsidiary.
29.5.2	The Company may submit a request to the Agent at any time for any Relevant Obligor to cease to be an Obligor.
29.5.3	Subject to Clause 29.5.4, as soon as reasonably practicable after the submission of any such request, the Finance Parties shall (at the cost and expense of the Obligors) take all such steps as the Company may reasonably require for the purposes of ensuring:

(A)	that the Relevant Obligor ceases to be an Obligor for the purposes of the Finance Documents; and
(B)	the release of any Security under the Finance Documents granted to the Finance Parties (a) by the Relevant Obligor over its assets or (b) by any other person over the shares in the Relevant Obligor.

29.5.4 A Relevant Obligor may only cease to be an Obligor pursuant to this Clause 29.5 (Release of non-asset holding Obligors) if:

(A)	no Default is continuing or would result from it ceasing to be an Obligor (and the Company confirms that this is the case); and
(B)	(other than in the case of Endeavour North Sea) the Majority Lenders consent to such Relevant Obligor ceasing to be an Obligor; and
(C)	in the case only of Endeavour North Sea:

(1)	the Permitted Transaction described in paragraph (B) of the definition of “Permitted Transaction” has been completed upon the terms described therein;
(2)	Endeavour North Sea is under no actual or contingent obligation as a Borrower; and
(3)	Endeavour North Sea has no assets whatsoever,

and, in each case, the Company confirms the same to the Agent.

THE FINANCE PARTIES

30.	ROLE OF THE ADMINISTRATIVE FINANCE PARTIES
30.1	General
	For the purposes only of this Clause 30 (Role of the Administrative Finance Parties), references to the Administrative Finance Parties shall be construed as excluding the Security Trustee.
30.2	Appointment of the Agent

30.2.1	Each other Finance Party appoints the Agent to act as its agent under and in connection with the Finance Documents.
30.2.2	Each other Finance Party authorises the Agent to exercise the rights, powers, authorities and discretions specifically given to the Agent under or in connection with the Finance Documents together with any other incidental rights, powers, authorities and discretions.

30.3 Duties of the Agent

30.3.1	Subject to Clause 30.3.3, the Agent shall promptly forward to a Party the original or a copy of any document which is delivered to the Agent for that Party by any other Party.
30.3.2	Without prejudice to Clause 28.7 (Copy of Transfer Certificate or Assignment Agreement to Company), Clause 30.3.1 above shall not apply to any Transfer Certificate or to any Assignment Agreement.
30.3.3	Except where a Finance Document specifically provides otherwise, the Agent is not obliged to review or check the adequacy, accuracy or completeness of any document it forwards to another Party.
30.3.4	If the Agent receives notice from a Party referring to this Agreement, describing a Default and stating that the circumstance described is a Default, it shall promptly notify the other Finance Parties.
30.3.5	If the Agent is aware of the non-payment of any principal, interest, commitment fee or other fee payable to a Finance Party (other than an Administrative Finance Party or the Security Trustee) under this Agreement it shall promptly notify the other Finance Parties.
30.3.6	The Agent’s duties under the Finance Documents are solely mechanical and administrative in nature.

30.4	Role of the Mandated Lead Arranger
	Except as specifically provided in the Finance Documents, the Mandated Lead Arranger have no obligations of any kind to any other Party under or in connection with any Finance Document.
30.5	No fiduciary duties

30.5.1	Nothing in this Agreement constitutes any Administrative Finance Party as a trustee or fiduciary of any other person.
30.5.2	No Administrative Finance Party shall be bound to account to any Finance Party for any sum or the profit element of any sum received by it for its own account.

30.6	Business with the Group
	Each Administrative Finance Party may accept deposits from, lend money to and generally engage in any kind of banking or other business with any Obligor or any other member of the Group.
30.7	Rights and discretions of the Administrative Finance Parties

30.7.1 Each Administrative Finance Party may rely on:

(A)	any representation, notice or document believed by it to be genuine, correct and appropriately authorised; and
(B)	any statement made by a director, authorised signatory or employee of any person regarding any matters which may reasonably be assumed to be within his knowledge or within his power to verify.

30.7.2 Each Administrative Finance Party may assume (unless it has received notice to the contrary in its capacity as an Administrative Finance Party) that:

(A)	no Default has occurred (unless it has actual knowledge of a Default arising under Clause 27.2 (Non-payment and failure to reduce));
(B)	any right, power, authority or discretion vested in any Party or the Majority Lenders has not been exercised; and
(C)	any notice or request made by the Company (other than a Utilisation Request or Selection Notice) is made on behalf of and with the consent and knowledge of all the Obligors.

30.7.3	Each Administrative Finance Party may engage, pay for and rely on the advice or services of any lawyers, accountants, surveyors or other experts.
30.7.4	Each Administrative Finance Party may act in relation to the Finance Documents through its personnel and agents.
30.7.5	Each Administrative Finance Party may disclose to any other Party any information it reasonably believes it has received in its capacity as such under this Agreement.
30.7.6	Notwithstanding any other provision of any Finance Document to the contrary, no Administrative Finance Party is obliged to do or omit to do anything if it would or might in its reasonable opinion constitute a breach of any law or regulation or a breach of a fiduciary duty or duty of confidentiality.

30.8 Majority Lenders’ instructions

30.8.1	Unless a contrary indication appears in a Finance Document, the Agent shall (a) exercise any right, power, authority or discretion vested in it in such capacity in accordance with any instructions given to it by the Majority Lenders (or, if so instructed by the Majority Lenders), refrain from exercising any right, power, authority or discretion vested in it and (b) not be liable for any act (or omission) if it acts (or refrains from taking any action) in accordance with an instruction of the Majority Lenders.
30.8.2	Unless a contrary indication appears in a Finance Document, any instructions given by the Majority Lenders will be binding on all the Finance Parties.
30.8.3	The Agent may refrain from acting in accordance with the instructions of the Majority Lenders (or, if appropriate, the Lenders) until it has received such security as it may require for any cost, loss or liability (together with any associated VAT) which it may incur in complying with the instructions.

30.8.4	In the absence of instructions from the Majority Lenders, (or, if appropriate, the Lenders) the Agent may act (or refrain from taking action) as it considers to be in the best interest of the Finance Parties.
30.8.5	The Agent is not authorised to act on behalf of a Finance Party (without first obtaining that Finance Party’s consent) in any legal or arbitration proceedings relating to any Finance Document.

30.9	Responsibility for documentation
	No Administrative Finance Party is liable or responsible for:

30.9.1	the adequacy, accuracy and/or completeness of any information (whether oral or written) supplied by it, an Obligor or any other person given in or in connection with any Finance Document; or
30.9.2	the legality, validity, effectiveness, adequacy or enforceability of any Finance Document or any other agreement, arrangement or document entered into, made or executed in anticipation of or in connection with any Finance Document.

30.10 Exclusion of liability

30.10.1	Without limiting Clause 30.10.2, and without prejudice to the provisions of paragraph (e) of Clause 33.10 (Disruption to Payment Systems etc.) no Administrative Finance Party will be liable (including, for negligence or any other category of liability whatsoever) for any action taken by it under or in connection with any Finance Document, unless directly caused by its gross negligence or wilful misconduct.
30.10.2	No Party (other than an Administrative Finance Party) may take any proceedings against any officer, employee or agent of that Administrative Finance Party in respect of any claim it might have against that Administrative Finance Party or in respect of any act or omission of any kind by that officer, employee or agent in relation to any Finance Document and any officer, employee or agent of that Administrative Finance Party may rely on this Clause 30.10.2 subject to Clause 5.3 (Third party rights) and the provisions of the Third Parties Act.
30.10.3	No Administrative Finance Party will be liable for any delay (or any related consequences) in crediting an account with an amount required under the Finance Documents to be paid by that Administrative Finance Party if it has taken all necessary steps as soon as reasonably practicable to comply with the regulations or operating procedures of any recognised clearing or settlement system used by it for that purpose.
30.10.4	Nothing in this Agreement shall oblige any Administrative Finance Party to carry out any “know your customer” or other checks in relation to any person on behalf of any Finance Party and each Finance Party confirms to the Administrative Finance Parties that it is solely responsible for any such checks it is required to carry out and that it may not rely on any statement in relation to such checks made by any Administrative Finance Party.

30.11 Lenders’ indemnity

30.11.1 Each Lender shall (in proportion to its share of the Aggregate Commitments or, if the Aggregate Commitments are then zero, to its share of the Aggregate Commitments immediately prior to their reduction to zero) within three Business Days of demand, indemnify:

(A)	each Administrative Finance Party, against any cost, loss or liability (including, for negligence or any other category of liability whatsoever) incurred by that Administrative Finance Party (otherwise than by reason of its gross negligence or wilful misconduct) in acting in its capacity as such an Administrative Finance Party under or in connection with the Finance Documents; and
(B)	the Agent against any cost, loss or liability, in the case of any cost, loss or liability (notwithstanding the Agent’s negligence, gross negligence or any other category of liability whatsoever) pursuant to Clause 33.10 (Disruption to Payment Systems etc.) (but excluding any claim based on the fraud of the Agent in acting in such capacity),

	unless, in the case of Clause 30.11.1(A) and 30.11.1(B), that Administrative Finance Party has been reimbursed for the same by an Obligor pursuant to a Finance Document.
30.11.2	The Obligors shall forthwith on demand reimburse each Finance Party for any payments made by it under this Clause 30.11 (Lenders’ indemnity).

30.12 Resignation

30.12.1	Each Administrative Finance Party (other than the Mandated Lead Arranger) may resign at any time and appoint one of its Affiliates acting through an office in the United Kingdom as successor by giving notice to the other Finance Parties and the Company.
30.12.2	Alternatively such Administrative Finance Party may resign by giving notice to the other Finance Parties and the Company, in which case the Majority Lenders (after consultation with the Company) may appoint a successor Administrative Finance Party.
30.12.3	If the Majority Lenders have not appointed a successor Administrative Finance Party in accordance with Clause 30.12.2 within 30 days after notice of resignation was given, the incumbent Administrative Finance Party (after consultation with the Company and the Majority Lenders) may appoint a successor Administrative Finance Party (acting through an office in the United Kingdom or Paris).
30.12.4	The retiring Administrative Finance Party shall, at its own cost, make available to the successor Administrative Finance Party such documents and records and provide such assistance as the successor Administrative Finance Party may reasonably request for the purposes of performing its functions as Administrative Finance Party under the Finance Documents.
30.12.5	The Administrative Finance Party’s resignation notice shall only take effect upon the successor Administrative Finance Party (a) notifying all the Parties that it accepts its appointment and (b) completing all such steps as may reasonably be required by the Majority Lenders in order to (1) ensure that it accedes, and becomes a party, to all relevant Finance Documents in its capacity as Administrative Finance Party and (2) facilitate the change in identity of the Administrative Finance Party.
30.12.6	Upon the appointment of a successor, the retiring Administrative Finance Party shall be discharged from any further obligation in respect of the Finance Documents but shall remain entitled to the benefit of this Clause 30 (Role of the Administrative Finance Parties). Its successor and each of the other Parties shall have the same rights and obligations amongst themselves as they would have had if such successor had been an original Party.
30.12.7	After consultation with the Company, the Majority Lenders may, by notice to any Administrative Finance Party (other than the Mandated Lead Arranger), require it to

resign in accordance with Clause 30.12.2. In this event, the relevant Administrative Finance Party shall resign in accordance with Clause 30.12.2.

30.13 Confidentiality

30.13.1	In acting under the Finance Documents, the relevant division through which each Administrative Finance Party acts shall be treated as a separate entity from any other of its divisions or departments.
30.13.2	If information is received by another division or department of an Administrative Finance Party, it may be treated as confidential to that relevant division or department and that Administrative Finance Party shall not be deemed to have notice of it.

30.14 Relationship with the Lenders

30.14.1 Subject to Clause 28.9 (Pro rata Interest Settlement), the Agent may treat the person shown in its records as Lender at the opening of business (in the place of the Agent’s principal office as notified to the Finance Parties from time to time) as the Lender acting through its Facility Office:

(A)	entitled to or liable for any payment due under any Finance Document on that day; and
(B)	entitled to receive and act upon any notice, request, document or communication or make any decision or determination under any Finance Document made or delivered on that day,

	unless it has received not less than five Business Days prior notice from that Lender to the contrary in accordance with the terms of this Agreement.
30.14.2	Each Lender shall supply the Agent with any information required by the Agent in order to calculate the Mandatory Cost in accordance with Schedule 5 (Mandatory Cost formulae).
30.14.3	Any Finance Party may by notice to the Agent appoint a person to receive on its behalf all notices, communications, information and documents to be made or despatched to that Finance Party under the Finance Documents. Such notice shall contain the address, fax number and (where communication by electronic mail or other electronic means is permitted under Clause 35.5 (Electronic communication)) electronic mail address and/or any other information required to enable the sending and receipt of information by that means (and, in each case, the department or officer, if any, for whose attention communication is to be made) and be treated as a notification of a substitute address, fax number, electronic mail address, department and officer by that Finance Party for the purposes of Clause 35.2 (Contact details) and Clause 35.5 (Electronic communication) and the Agent shall be entitled to treat such person as the person entitled to receive all such notices, communications, information and documents as though that person were that Finance Party.

30.15

Credit appraisal by the Finance Parties

Without affecting the responsibility of any Obligor for information supplied by it or on its behalf in connection with any Finance Document, each Finance Party confirms to each Administrative Finance Party that it has been, and will continue to be, solely responsible for making its own independent appraisal and investigation of all risks arising under or in connection with any Finance Document including:

30.15.1	the financial condition, status and nature of each Obligor and each other member of the Group;
30.15.2	the legality, validity, effectiveness, adequacy or enforceability of any Finance Document and any other agreement, arrangement or document entered into, made or executed in anticipation of, under or in connection with any Finance Document;
30.15.3	whether that Finance Party has recourse, and the nature and extent of that recourse, against any Party or any of its respective assets under or in connection with any Finance Document, the transactions contemplated by the Finance Documents or any other agreement, arrangement or document entered into, made or executed in anticipation of, under or in connection with any Finance Document; and
30.15.4	the adequacy, accuracy and/or completeness of any information provided by that Administrative Finance Party, any other Party or by any other person under or in connection with any Finance Document, the transactions contemplated by the Finance Documents or any other agreement, arrangement or document entered into, made or executed in anticipation of, under or in connection with any Finance Document.

30.16	Reference Banks
	If a Reference Bank (or, if a Reference Bank is not a Lender, the Lender of which it is an Affiliate) ceases to be a Lender, the Agent shall (in consultation with the Company) appoint another Lender or an Affiliate of a Lender to replace that Reference Bank.
30.17	Management time
	Any amount payable to an Administrative Finance Party under Clause 19.3 (Indemnity to the Agent), Clause 21 (Costs and expenses) and Clause 30.11 (Lenders’ indemnity) shall include the reasonable cost of utilising that Administrative Finance Party’s management time or other resources and will be calculated on the basis of such reasonable daily or hourly rates as that Administrative Finance Party may notify to the Company and the Lenders, and is in addition to any fee paid or payable to that Administrative Finance Party pursuant to Clause 16 (Fees).
30.18	Deduction
	If any Party owes an amount to the Agent under the Finance Documents the Agent may, after giving notice to that Party, deduct an amount not exceeding that amount from any payment to that Party which the Agent would otherwise be obliged to make under the Finance Documents and apply the amount deducted in or towards satisfaction of the amount owed. For the purposes of the Finance Documents, that Party shall be regarded as having received any amount so deducted.
30.19	Parallel Debt (Covenant to pay the Security Trustee)

30.19.1 Notwithstanding any other provisions of this Agreement, each Obligor hereby irrevocably and unconditionally undertakes (such undertaking and the obligations and liabilities which are a result thereof, hereinafter being referred to as its “Parallel Debt”) to pay to the Security Trustee an amount equal to and in the currency of the aggregate amount payable by it to any Secured Creditor under any Finance Document (the “Principal Obligations”) in accordance with the terms and conditions of such Principal Obligations. The Parallel Debt of each Obligor shall become due and payable as and when its Principal Obligations become due and payable.

30.19.2 The Parties acknowledge that:

(A) the Parallel Debt of each Obligor:

(1)	constitutes an undertaking, obligation and liability of such Obligor to the Security Trustee (in its personal capacity and not in its capacity as agent) which is separate and independent from, and without prejudice to, its Principal Obligations; and
(2)	represents the Security Trustee’s own claim to receive payment of such Parallel Debt from such Obligor; and

(B) the Security created under the Finance Documents to secure the Parallel Debt is granted to the Security Trustee in its capacity as sole creditor of the Parallel Debt.

30.19.3 The Parties agree that:

(A)	the Parallel Debt of each Obligor shall be decreased if and to the extent that its Principal Obligations have been paid or in the case of guarantee obligations discharged;
(B)	the Principal Obligations of each Obligor shall be decreased if and to the extent that its Parallel Debt has been paid or in the case of guarantee obligations discharged; and
(C)	the amount payable under the Parallel Debt of each Obligor shall at no time exceed the amount payable under its Principal Obligations.

30.19.4	Any amount received or recovered by the Security Trustee in respect of a Parallel Debt (including, but not limited to, enforcement proceeds) shall be applied in accordance with the terms of this Agreement subject to limitations (if any) expressly provided for in any Security Document.
30.19.5	The rights of the Secured Creditors (other than the Security Trustee) to receive payment of the Principal Obligations of each Obligor are several and separate and independent from, and without prejudice to, the rights of the Security Trustee to receive payment under the Parallel Debt.
30.19.6	The Parties agrees that the claim of the Security Trustee in respect of the Parallel Debt of each Obligor and the claims of any one or more of the Secured Creditors under the Principal Obligations do not constitute common property (gemeenschap) within the meaning of section 3:166 of the Netherlands Civil Code and that the provisions relating to common property shall not apply. Should a court determine that the claim of the Security Trustee and the claims of any one or more of the Secured Creditors under the Principal Obligations do constitute common property and the provisions of common property do apply, the Secured Creditors agree that this Agreement together with the Intercreditor Agreement shall constitute the administration agreement (beheersregeling) within the meaning of section 3:168 of the Netherlands Civil Code.
30.19.7	For the purposes of this Clause 30.19 (Parallel Debt (Covenant to pay the Security Trustee), “Finance Documents” has the meaning given to that term in the Intercreditor Agreement.

31.	CONDUCT OF BUSINESS BY THE FINANCE PARTIES
	No provision of this Agreement will:

31.1.1	interfere with the right of any Finance Party to arrange its affairs (tax or otherwise) in whatever manner it thinks fit;
31.1.2	oblige any Finance Party to investigate or claim any credit, relief, remission or repayment available to it or the extent, order and manner of any claim; or
31.1.3	oblige any Finance Party to disclose any information relating to its affairs (tax or otherwise) or any computations in respect of Tax.

32.	SHARING AMONG THE FINANCE PARTIES
32.1	Payments to Finance Parties
	If a Finance Party (a “Recovering Finance Party”) receives or recovers any amount from an Obligor other than in accordance with Clause 33 (Payment mechanics) (a “Recovered Amount”) and applies that amount to a payment due under the Finance Documents then:

32.1.1	the Recovering Finance Party shall, within three Business Days, notify details of the receipt or recovery, to the Agent;
32.1.2	the Agent shall determine whether the receipt or recovery is in excess of the amount the Recovering Finance Party would have been paid had the receipt or recovery been received or made by the Agent and distributed in accordance with Clause 33 (Payment mechanics), without taking account of any Tax which would be imposed on the Agent in relation to the receipt, recovery or distribution; and
32.1.3	the Recovering Finance Party shall, within three Business Days of demand by the Agent, pay to the Agent an amount (the “Sharing Payment”) equal to such receipt or recovery less any amount which the Agent determines may be retained by the Recovering Finance Party as its share of any payment to be made, in accordance with Clause 33.5 (Partial payments).

32.2	Redistribution of payments
	The Agent shall treat the Sharing Payment as if it had been paid by the relevant Obligor and distribute it between the Finance Parties (other than the Recovering Finance Party) (the “Sharing Finance Parties”) in accordance with Clause 33.5 (Partial payments) towards the obligations of that Obligor to the Sharing Finance Parties.
32.3	Recovering Finance Party’s rights
	On a distribution by the Agent under Clause 32.2 (Redistribution of payments), of a payment received by a Recovering Finance Party from an Obligor, as between the relevant Obligor and the Recovering Finance party, an amount of the Recovered Amount equal to the Sharing Payment to be treated as not having been paid by that Obligor.
32.4	Reversal of redistribution
	If any part of the Sharing Payment received or recovered by a Recovering Finance Party becomes repayable and is repaid by that Recovering Finance Party, then:

32.4.1 each Sharing Finance Party shall, upon request of the Agent, pay to the Agent for the account of that Recovering Finance Party an amount equal to the appropriate part of its share of the Sharing Payment (together with an amount as is necessary to reimburse that Recovering Finance Party for its proportion of any interest on the Sharing Payment which that Recovering Finance Party is required to pay) (the “Redistributed Amount”); and

32.4.2 as between the relevant Obligor and each relevant Sharing Finance Party, an amount equal to the relevant Redistributed Amount will be treated as not having been paid by that Obligor.

32.5 Exceptions

32.5.1	This Clause 32 (Sharing among the Finance Parties) shall not apply to the extent that the Recovering Finance Party would not, after making any payment pursuant to this Clause, have a valid and enforceable claim against the relevant Obligor.
32.5.2	A Recovering Finance Party is not obliged to share with any other Finance Party any amount which the Recovering Finance Party has received or recovered as a result of taking legal or arbitration proceedings, if:

(A)	it notified that other Finance Party of the legal or arbitration proceedings; and
(B)	that other Finance Party had an opportunity to participate in those legal or arbitration proceedings but did not do so as soon as reasonably practicable having received notice and did not take separate legal or arbitration proceedings.

ADMINISTRATION

33.	PAYMENT MECHANICS
33.1	Payments to the Agent

33.1.1

On each date on which an Obligor or a Finance Party is required to make a payment under a Finance Document, that Obligor or Finance Party shall make the same available to the Agent (unless a contrary indication appears in a Finance Document) for value on the due date at the time and in such funds specified by the Agent as being customary at the time for settlement of transactions in the relevant currency in the place of payment.

33.1.2

Payment shall be made to such account in the principal financial centre of the country of that currency with such bank as the Agent specifies.

33.2	Distributions by the Agent
	Each payment received by the Agent under the Finance Documents for another Party shall, subject to Clause 33.3 (Distributions to an Obligor) and Clause 33.4 (Clawback) be made available by the Agent as soon as practicable after receipt to the Party entitled to receive payment in accordance with this Agreement (in the case of a Lender, for the account of its Facility Office), to such account as that Party may notify to the Agent by not less than five Business Days’ notice with a bank in the principal financial centre of the country of that currency).
33.3	Distributions to an Obligor
	The Agent may (with the consent of the Obligor or in accordance with Clause 34 (Set-off)) apply any amount received by it for that Obligor in or towards payment (on the date and in the currency and funds of receipt) of any amount due from that Obligor under the Finance Documents or in or towards purchase of any amount of any currency to be so applied.
33.4	Clawback

33.4.1

Where a sum is to be paid to the Agent under the Finance Documents for another Party, the Agent is not obliged to pay that sum to that other Party (or to enter into or perform any related exchange contract) until it has been able to establish to its satisfaction that it has actually received that sum.

33.4.2

If the Agent pays an amount to another Party and it proves to be the case that the Agent had not actually received that amount, then the Party to whom that amount (or the proceeds of any related exchange contract) was paid by the Agent shall on demand refund the same to the Agent together with interest on that amount from the date of payment to the date of receipt by the Agent, calculated by the Agent to reflect its cost of funds.

33.5 Partial payments

33.5.1 If the Agent receives a payment that is insufficient to discharge all the amounts then due and payable by an Obligor under the Finance Documents, the Agent shall apply that payment towards the obligations of that Obligor under the Finance Documents in the following order:

(A)	first, in or towards payment pro rata of any unpaid fees, costs and expenses of the Administrative Finance Parties under the Finance Documents;
(B)	secondly, in or towards payment pro rata of any accrued interest, commitment fees or commission due but unpaid under the Finance Documents;

(C)	thirdly, in or towards payment pro rata of any principal due but unpaid under the Finance Documents; and
(D)	fourthly, in or towards payment pro rata of any other sum due but unpaid under the Finance Documents.

33.5.2	The Agent shall, if so directed by the Majority Lenders, vary the order set out in Clauses 33.5.1(B) to 33.5.1(D) above.
33.5.3	Clauses 33.5.1 and 33.5.2 above will override any appropriation made by an Obligor.

33.6	No set-off by Obligors
	All payments to be made by an Obligor under the Finance Documents shall be calculated and be made without (and free and clear of any deduction for) set-off or counterclaim.
33.7	Business Days

33.7.1	Any payment which is due to be made on a day that is not a Business Day shall be made on the next Business Day in the same calendar month (if there is one) or the preceding Business Day (if there is not).
33.7.2	During any extension of the due date for payment of any principal or Unpaid Sum under this Agreement interest is payable on the principal or Unpaid Sum at the rate payable on the original due date.

33.8 Currency of account

33.8.1	Subject to Clauses 33.8.2 and to 33.8.5, dollars is the currency of account and payment for any sum due from an Obligor under any Finance Document.
33.8.2	A repayment of a Loan or Unpaid Sum or a part of a Loan or Unpaid Sum shall be made in the currency in which that Loan or Unpaid Sum is denominated on its due date.
33.8.3	Each payment of interest shall be made in the currency in which the sum in respect of which that interest is payable was denominated when that interest accrued.
33.8.4	Each payment in respect of costs, expenses or Taxes shall be made in the currency in which the costs, expenses or Taxes are incurred.
33.8.5	Any amount expressed to be payable in a currency other than dollars shall be paid in that other currency.

33.9 Change of currency

33.9.1 Unless otherwise prohibited by law, if more than one currency or currency unit are at the same time recognised by the central bank of any country as the lawful currency of that country, then:

(A)	any reference in the Finance Documents to, and any obligations arising under the Finance Documents in, the currency of that country shall be translated into, or paid in, the currency or currency unit of that country designated by the Agent (after consultation with the Company); and
(B)	any translation from one currency or currency unit to another shall be at the official rate of exchange recognised by the central bank for the conversion of that currency or currency unit into the other, rounded up or down by the Agent (acting reasonably).

33.9.2 If a change in any currency of a country occurs, this Agreement will, to the extent the Agent (acting reasonably and after consultation with the Company) specifies to be

necessary, be amended to comply with any generally accepted conventions and market practice in the London interbank market and otherwise to reflect the change in currency.

33.10	Disruption to Payment Systems etc.
	If either the Agent determines (in its discretion) that a Disruption Event has occurred or the Agent is notified by the Company that a Disruption Event has occurred:

33.10.1	the Agent may, and shall if requested to do so by the Company, consult with the Company with a view to agreeing with the Company such changes to the operation or administration of the Facility as the Agent may deem necessary in the circumstances;
33.10.2	the Agent shall not be obliged to consult with the Company in relation to any changes mentioned in Clause 33.10.1 if, in its opinion, it is not practicable to do so in the circumstances and, in any event, shall have no obligation to agree to such changes;
33.10.3	the Agent may consult with the Finance Parties in relation to any changes mentioned in Clause 33.10.1 but shall not be obliged to do so if, in its opinion, it is not practicable to do so in the circumstances;
33.10.4	any such changes agreed upon by the Agent and the Company shall (whether or not it is finally determined that a Disruption Event has occurred) be binding upon the Parties as an amendment to (or, as the case may be, waiver of) the terms of the Finance Documents notwithstanding the provisions of Clause 39 (Amendments and waivers);
33.10.5	the Agent shall not be liable for any damages, costs or losses whatsoever (including, for negligence, gross negligence or any other category of liability whatsoever but not including any claim based on the fraud of the Agent) arising as a result of its taking, or failing to take, any actions pursuant to or in connection with this Clause 33.10 (Disruption to Payment Systems etc.); and
33.10.6	the Agent shall notify the Finance Parties of all changes agreed pursuant to Clause 33.10.4 above.

34.	SET-OFF
	A Finance Party may set off any matured obligation due from an Obligor under the Finance Documents (to the extent beneficially owned by that Finance Party) against any matured obligation owed by that Finance Party to that Obligor, regardless of the place of payment, booking branch or currency of either obligation. If the obligations are in different currencies, the Finance Party may convert either obligation at a market rate of exchange in its usual course of business for the purpose of the set-off.
35.	NOTICES
35.1	Communication in writing
	Any communication in connection with a Finance Document must be in writing and, unless otherwise stated, may be given in person, by fax or letter.
35.2	Contact details

35.2.1 Except as provided in this Clause 35.2 (Contact details), the contact details of each Party for all communications in connection with the Finance Documents are those notified by that Party for this purpose to the Agent on or before the date it becomes a Party.

35.2.2	Any Party may change its contact details by giving five Business Days’ notice to the Facility Agent or (in the case of the Facility Agent) to the other Parties.
35.2.3	Where a Party nominates a particular department or officer to receive a communication, a communication will not be effective if it fails to specify that department or officer.

35.3 Effectiveness

35.3.1 Except as provided in Clause 35.3.2 and Clause 35.3.3, any communication in connection with a Finance Document will be deemed to be given as follows:

(A)	if delivered in person, at the time of delivery; and
(B)	if by fax , when received in legible form.

35.3.2	A communication given under Clause 35.4.1 but received on a non-working day or after business hours in the place of receipt will only be deemed to be given on the next working day in that place.
35.3.3	A communication to any Administrative Finance Party will only be effective on actual receipt by it.

35.4 Obligors

35.4.1 All communications under the Finance Documents:

(A)	to or from any other Administrative Finance Party (in its capacity as such) may be made directly to, or as the case may be, come directly from, that Administrative Finance Party (provided that the relevant communication is also copied to the Agent); and
(B)	to or from any other Finance Party must be sent through the Agent.

35.4.2	All communications under the Finance Documents to or from an Obligor may be sent through the Company.
35.4.3	Each Obligor (other than the Company) irrevocably appoints the Company to act as its agent:

(A)	to give and receive all communications under the Finance Documents;
(B)	to supply all information concerning itself to any Finance Party; and
(C)	to sign all documents under or in connection with the Finance Documents.

35.4.4	Any communication given to the Company in connection with a Finance Document will be deemed to have been given also to the other Obligors.
35.4.5	The Finance Parties may assume that any communication made by the Company is made with the consent of each other Obligor.

35.5 Electronic Communication

35.5.1 Any communication to be made between the Agent and a Lender under or in connection with the Finance Documents may be made by electronic mail or other electronic means, if the Agent and the relevant Lender:

(A)	agree that, unless and until notified to the contrary, this is to be an accepted form of communication;
(B)	notify each other in writing of their electronic mail address and/or any other information required to enable the sending and receipt of information by that means; and

(C) notify each other of any change to their address or any other such information supplied by them.

35.5.2 Any electronic communication made between the Agent and a Lender will be effective only when actually received in readable form and in the case of any electronic communication made by a Lender to the Agent only if it is addressed in such a manner as the Agent shall specify for this purpose.

35.6 English language

35.6.1	Any notice given in connection with a Finance Document must be in English.
35.6.2	Any other document provided in connection with a Finance Document must be:

(A)	in English; or
(B)	(unless the Agent otherwise agrees) accompanied by a certified English translation. In this case, the English translation prevails unless the document is a statutory or other official document.

36.	CALCULATIONS AND CERTIFICATES
36.1	Accounts
	In any litigation or arbitration proceedings arising out of or in connection with a Finance Document, the entries made in the accounts maintained by a Finance Party are prima facie evidence of the matters to which they relate.
36.2	Certificates and Determinations
	Any certification or determination by a Finance Party of a rate or amount under any Finance Document is, in the absence of manifest error, conclusive evidence of the matters to which it relates.
36.3	Day count convention
	Any interest, commission or fee accruing under a Finance Document will accrue from day to day and is calculated on the basis of the actual number of days elapsed and a year of (in the case of dollars) 360 days, (in the case of sterling) 365 days or, in any case where the practice in the London interbank market differs, in accordance with that market practice.
37.	PARTIAL INVALIDITY
	If, at any time, any provision of the Finance Documents is or becomes illegal, invalid or unenforceable in any respect under any law of any jurisdiction, neither the legality, validity or enforceability of the remaining provisions nor the legality, validity or enforceability of such provision under the law of any other jurisdiction will in any way be affected or impaired.
38.	REMEDIES AND WAIVERS
	No failure to exercise, nor any delay in exercising, on the part of any Finance Party, any right or remedy under the Finance Documents shall operate as a waiver, nor shall any single or partial exercise of any right or remedy prevent any further or other exercise or the exercise of any other right or remedy. The rights and remedies provided in this Agreement are cumulative and not exclusive of any rights or remedies provided by law.

39.	AMENDMENTS AND WAIVERS
39.1	Required consents

39.1.1	Subject to Clause 39.2 (Exceptions) any term of the Finance Documents (other than the Intercreditor Agreement) may be amended or waived only with the consent of the Majority Lenders and the Obligors and any such amendment or waiver will be binding on all Parties.
39.1.2	Any term of the Intercreditor Agreement may be amended or waived in accordance with its terms.
39.1.3	The Agent may effect, on behalf of any Finance Party, any amendment or waiver permitted by this Clause.
39.1.4	In addition, each Obligor hereby authorises the Company to effect, on its behalf, any amendment or waiver permitted by this Clause 39 (Amendments and waivers). In any event, each Party shall take such action as the Agent and/or the Security Trustee may reasonably request in order to ensure that such amendment or waiver that is permitted by this Clause 39 (Amendments and waivers) is promptly effected.

39.2 Exceptions

39.2.1 Any amendment or waiver that has the effect of changing or which relates to:

(A)	the definition of “Majority Lenders” in Clause 5.1 (Definitions);
(B)	an extension to the date of payment of any amount under the Finance Documents;
(C)	a reduction in the Margin or a reduction in the amount of any payment of principal, interest, fees or commission payable;
(D)	an increase in or an extension of any Commitment;
(E)	a change to the Borrowers or Guarantors other than in accordance with Clause 29 (Changes to the Obligors);
(F)	any provision which expressly requires the consent of all the Lenders;
(G)	Clause 6.2 (Finance Parties’ rights and obligations), Clause 28 (Changes to the Lenders) or this Clause 39 (Amendments and waivers); or
(H)	the release of any Security granted under any Security Document save where such release is required pursuant to the terms of any Finance Document or the release of any Borrower, Guarantor or Transaction Party (in its capacity as such) that holds any assets that are the subject of any Security granted under any Security Document;

shall not be made without the prior consent of all the Lenders.

39.2.2	Any amendment or waiver which relates to the rights or obligations of any Administrative Finance Party may not be effected without the consent of that Finance Party.
39.2.3	Any term of any Fee Letter relating to the payment of fees to any Administrative Finance Party for its own account may be amended or waived by the relevant Administrative Finance Party without the prior consent of the Majority Lenders.

40.	CONFIDENTIALITY
40.1	Confidential Information
	Each Finance Party agrees to keep all Confidential Information confidential and not to disclose it to anyone, save to the extent permitted by Clause 40.2 (Disclosure of Confidential Information) and Clause 40.3 (Disclosure to numbering service providers), and to ensure that all Confidential Information is protected with security measures and a degree of care that would apply to its own confidential information.
40.2	Disclosure of Confidential Information
	Any Finance Party may disclose:

40.2.1

to any of its Affiliates and Related Funds and any of its or their officers, directors, employees, professional advisers, auditors, partners and Representatives such Confidential Information as that Finance Party shall consider appropriate if any person to whom the Confidential Information is to be given pursuant to this Clause 40.2.1 is informed in writing of its confidential nature and that some or all of such Confidential Information may be price-sensitive information except that there shall be no such requirement to so inform if the recipient is subject to professional obligations to maintain the confidentiality of the information or is otherwise bound by requirements of confidentiality in relation to the Confidential Information;

40.2.2

to any person:

(A)	to (or through) whom it assigns or transfers (or may potentially assign or transfer) all or any of its rights and/or obligations under one or more Finance Documents and to any of that person’s Affiliates, Related Funds, Representatives and professional advisers;
(B)	with (or through) whom it enters into (or may potentially enter into), whether directly or indirectly, any sub-participation in relation to, or any other transaction under which payments are to be made or may be made by reference to, one or more Finance Documents and/or one or more Obligors and to any of that person’s Affiliates, Related Funds, Representatives and professional advisers;
(C)	appointed by any Finance Party or by a person to whom paragraph (A) or paragraph (B) above applies to receive communications, notices, information or documents delivered pursuant to the Finance Documents on its behalf (including, without limitation, any person appointed under Clause 30.14 (Relationship with the Lenders));
(D)	who invests in or otherwise finances (or may potentially invest in or otherwise finance), directly or indirectly, any transaction referred to in paragraph (A) or paragraph (B) above;
(E)	to whom information is required or requested to be disclosed by any court of competent jurisdiction or any governmental, banking, taxation or other regulatory authority or similar body, the rules of any relevant stock exchange or pursuant to any applicable law or regulation;
(F)	to whom or for whose benefit that Finance Party charges, assigns or otherwise creates Security (or may do so) pursuant to Clause 28.8 (Security over Lenders’ rights);

(G)	to whom information is required to be disclosed in connection with, and for the purposes of, any litigation, arbitration, administrative or other investigations, proceedings or disputes;
(H)	who is a Party; or
(I)	with the consent of the Company;

in each case, such Confidential Information as that Finance Party shall consider appropriate if:

(1)	in relation to paragraphs (A), (B) and (C) above, the person to whom the Confidential Information is to be given has entered into a Confidentiality Undertaking except that there shall be no requirement for a Confidentiality Undertaking if the recipient is a professional adviser and is subject to professional obligations to maintain the confidentiality of the Confidential Information;
(2)	in relation to paragraph (D) above, the person to whom the Confidential Information is to be given has entered into a Confidentiality Undertaking or is otherwise bound by requirements of confidentiality in relation to the Confidential Information they receive and is informed that some or all of such Confidential Information may be price-sensitive information;
(3)	in relation to paragraphs (E), (F) and (G) above, the person to whom the Confidential Information is to be given is informed of its confidential nature and that some or all of such Confidential Information may be price-sensitive information except that there shall be no requirement to so inform if, in the opinion of that Finance Party, it is not practicable so to do in the circumstances;

40.2.3

to any person appointed by that Finance Party or by a person to whom Clauses 40.2.2(A) or 40.2.2(B) above applies to provide administration or settlement services in respect of one or more of the Finance Documents including without limitation, in relation to the trading of participations in respect of the Finance Documents, such Confidential Information as may be required to be disclosed to enable such service provider to provide any of the services referred to in this Clause 40.2.3 if the service provider to whom the Confidential Information is to be given has entered into a confidentiality agreement substantially in the form of the “LMA Master Confidentiality Undertaking for Use With Administration/Settlement Service Providers” or such other form of confidentiality undertaking agreed between the Company and the relevant Finance Party;

40.2.4

to any rating agency (including its professional advisers) such Confidential Information as may be required to be disclosed to enable such rating agency to carry out its normal rating activities in relation to the Finance Documents and/or the Obligors if the rating agency to whom the Confidential Information is to be given is informed of its confidential nature and that some or all of such Confidential Information may be price-sensitive information.

40.3 Disclosure to numbering service providers

40.3.1 Any Finance Party may disclose to any national or international numbering service provider appointed by that Finance Party to provide identification numbering services in

respect of this Agreement, the Facility and/or one or more Obligors the following information:

(A)	names of Obligors;
(B)	country of domicile of Obligors;
(C)	place of incorporation of Obligors;
(D)	date of this Agreement;
(E)	the names of the Agent and the Mandated Lead Arranger;
(F)	date of each amendment and restatement of this Agreement;
(G)	amount of Aggregate Commitments;
(H)	currencies of the Facility;
(I)	type of Facility;
(J)	ranking of Facility;
(K)	Termination Date for Facility;
(L)	changes to any of the information previously supplied pursuant to paragraphs (A) to (K) above; and
(M)	such other information agreed between such Finance Party and the Company,

	to enable such numbering service provider to provide its usual syndicated loan numbering identification services.
40.3.2	The Parties acknowledge and agree that each identification number assigned to this Agreement, the Facility and/or one or more Obligors by a numbering service provider and the information associated with each such number may be disclosed to users of its services in accordance with the standard terms and conditions of that numbering service provider.
40.3.3	Each Obligor represents that none of the information set out in Clauses 40.3.1(A) to 40.3.1(M) above is, nor will at any time be, unpublished price-sensitive information.
40.3.4	The Agent shall notify the Company and the other Finance Parties of:

(A)	the name of any numbering service provider appointed by the Agent in respect of this Agreement, the Facility and/or one or more Obligors; and
(B)	the number or, as the case may be, numbers assigned to this Agreement, the Facility and/or one or more Obligors by such numbering service provider.

40.4	Entire agreement
	This Clause 40 (Confidentiality) constitutes the entire agreement between the Parties in relation to the obligations of the Finance Parties under the Finance Documents regarding Confidential Information and supersedes any previous agreement, whether express or implied, regarding Confidential Information.
40.5	Inside information
	Each of the Finance Parties acknowledges that some or all of the Confidential Information is or may be price-sensitive information and that the use of such information may be regulated or prohibited by applicable legislation including securities law relating to insider dealing and market abuse and each of the Finance Parties undertakes not to use any Confidential Information for any unlawful purpose.

40.6	Notification of disclosure
	Each of the Finance Parties agrees (to the extent permitted by law and regulation) to inform the Company:

40.6.1	of the circumstances of any disclosure of Confidential Information made pursuant to Clause 40.2.2(E) (Disclosure of Confidential Information) except where such disclosure is made to any of the persons referred to in that paragraph during the ordinary course of its supervisory or regulatory function; and
40.6.2	upon becoming aware that Confidential Information has been disclosed in breach of this Clause 40 (Confidentiality).

40.7	Continuing obligations
	The obligations in this Clause 40 (Confidentiality) are continuing and, in particular, shall survive and remain binding on each Finance Party for a period of twelve months from the earlier of:

40.7.1	the date on which all amounts payable by the Obligors under or in connection with this Agreement have been paid in full and all Commitments have been cancelled or otherwise cease to be available; and
40.7.2	the date on which such Finance Party otherwise ceases to be a Finance Party.

41.	COUNTERPARTS
	Each Finance Document may be executed (if such execution shall be valid under the laws of the jurisdiction by which such Finance Document is expressed to be governed) in any number of counterparts, and this has the same effect as if the signatures on the counterparts were on a single copy of the Finance Document.

GOVERNING LAW AND ENFORCEMENT

42.	GOVERNING LAW
	This Agreement and any non-contractual obligations arising out of or in connection with it) are governed by English law.
43.	ENFORCEMENT
43.1	Jurisdiction

43.1.1	The courts of England have exclusive jurisdiction to settle any dispute arising out of or in connection with this Agreement (including a dispute regarding the existence, validity or termination of this Agreement or any non-contractual obligation arising out of or in connection with this Agreement) (a “Dispute").
43.1.2	The Parties agree that the courts of England are the most appropriate and convenient courts to settle Disputes and accordingly no Party will argue to the contrary.
43.1.3	This Clause 43.1 (Jurisdiction) is for the benefit of the Finance Parties only. As a result, no Finance Party shall be prevented from taking proceedings relating to a Dispute in any other courts with jurisdiction. To the extent allowed by law, the Finance Parties may take concurrent proceedings in any number of jurisdictions.

43.2 Service of process

43.2.1 Without prejudice to any other mode of service allowed under any relevant law, each Obligor (other than an Obligor incorporated in England and Wales):

(A)	irrevocably appoints Endeavour Energy UK Limited as its agent for service of process in relation to any proceedings before the English courts in connection with any Finance Document; and
(B)	agrees that failure by a process agent to notify the relevant Obligor of the process will not invalidate the proceedings concerned.

43.2.2 Each of the Obligors expressly agrees and consents to the provisions of this Clause 43 (Enforcement) and Endeavour Energy UK Limited hereby confirm its acceptance of such appointment.

43.3	Waiver of immunity
	Each Obligor irrevocably and unconditionally:

43.3.1	agrees not to claim any immunity from proceedings brought by a Finance Party against that Obligor in relation to a Finance Document and to ensure that no such claim is made on its behalf;
43.3.2	consents generally to the giving of any relief or the issue of any process in connection with those proceedings; and
43.3.3	waives all rights of immunity in respect of it or its assets.

This Agreement has been entered into on the date stated at the beginning of this Agreement.

SCHEDULE 1

THE ORIGINAL OBLIGORS

Part I

THE ORIGINAL BORROWERS

(A) Name of Original Borrowers		(B)	Registration number	(C)	Jurisdiction of
			(or equivalent, if any)		incorporation
(D)	Endeavour International Holding B.V.	(E)	34229293	(F)	Netherlands
(G)	Endeavour Operating Corporation	(H)	3737839	(I)	Delaware, U.S.A
(J)	Endeavour Energy UK Limited	(K)	5030838	(L)	England and Wales
(M)	Endeavour North Sea Limited	(N)	03518803	(O)	England and Wales

Part II

THE ORIGINAL GUARANTORS

(P)	Name of Original Guarantors	(Q)	Registration number	(R)	Jurisdiction of
			(or equivalent, if any)		incorporation
(S)	Endeavour International Corporation	(T)	C897-2000	(U)	Nevada, U.S.A
(V)	Endeavour Operating Corporation	(W)	3737839	(X)	Delaware, U.S.A
(Y)	Endeavour Energy New Ventures Inc. (formerly, END Operating Management Company)	(Z)	3900636	(AA)	Delaware, U.S.A
(BB)	END Management Company	(CC)	3900274	(DD)	Delaware, U.S.A
(EE)	Endeavour International Holding B.V.	(FF)	34229293	(GG)	Netherlands
(HH)	Endeavour Energy UK Limited	(II)	5030838	(JJ)	England and Wales
(KK)	Endeavour North Sea Limited	(LL)	03518803	(MM)	England and Wales

(P)	Name of Original Guarantors	(Q)	Registration number	(R)	Jurisdiction of
			(or equivalent, if any)		incorporation
(NN)	Endeavour Energy North Sea, L.P.	(OO)	4591023	(PP)	Delaware, U.S.A
(QQ)	Endeavour Energy North Sea LLC	(RR)	4621624	(SS)	Delaware, U.S.A
(TT)	Endeavour Energy Netherlands B.V.	(UU)	34229296	(VV)	Netherlands

SCHEDULE 2

THE ORIGINAL LENDER

(WW)	Original Lender	(XX)	Commitment
(YY)	Bank of Scotland Plc	(ZZ)	$25,000,000

SCHEDULE 3

CONDITIONS PRECEDENT

Part I

CPs to first Loan

1.	OBLIGORS AND TRANSACTION PARTIES
1.1	A copy of the constitutional documents of each Obligor.
1.2	A copy of a resolution of the respective board of directors of each Obligor (or a committee of its board of directors) and of the respective general meeting of shareholders of each Dutch Obligor:

1.2.1	approving the terms of, and the transactions contemplated by, such of the Finance Documents that it is or will become party to;
1.2.2	authorising a specified person or persons to execute each such document on its behalf; and
1.2.3	authorising a specified person or persons, on its behalf, to sign and/or dispatch all other documents and notices to be signed and/or dispatched by it under or in connection with any such document.

1.3	If applicable, a copy of a resolution of the board of directors of each relevant Obligor establishing the committee referred to in paragraph 1.2 above.
1.4	For each Obligor, a specimen of the signature of each person authorised by the resolutions referred to in paragraph 1.2 above.
2.	CERTIFICATES
2.1	A certificate of an authorised signatory of each Obligor certifying on behalf of that Obligor that:

2.1.1	the borrowing or, as the case may be, the guaranteeing of the Aggregate Commitments in full would not cause any borrowing, guaranteeing or similar limit binding on it to be exceeded; and
2.1.2	each copy document specified in Paragraph 1 of Part I of Schedule 3 relating to it is correct, complete and in full force and effect as at a date no earlier than the Amendment Effective Date.

2.2	A certificate of a person who is both a director and an authorised signatory of each Obligor confirming that no Default has occurred and is continuing.
3.	FINANCE AND OTHER DOCUMENTS
3.1	Originals of the following documents duly executed by all parties to them and in full force and effect:

3.1.1	the Fee Letters;
3.1.2	an amendment and restatement agreement relating to the Intercreditor Agreement;
3.1.3	any other side letter or ancillary document the form of which has been agreed between the Company and the Mandated Lead Arranger on or before the date of this Agreement.

3.2	Originals of the following Security Documents duly executed by all parties to them and in full force and effect:
	English law

3.2.1	a debenture between Endeavour Energy UK Limited and the Security Trustee;
3.2.2	a debenture between Endeavour North Sea Limited and the Security Trustee;
3.2.3	a debenture (creating security over accounts and Hedging Agreements) between Endeavour International Holding B.V. and the Security Trustee;
3.2.4	a charge over shares between Endeavour Energy North Sea, L.P. and the Security Trustee over the shares held in Endeavour Energy UK Limited;
3.2.5	a charge over shares between Endeavour Energy UK Limited and the Security Trustee over the shares held in Endeavour North Sea Limited;

Dutch law

3.2.6	an agreement and deed of pledge of shares between Endeavour Operating Company and the Security Trustee over the shares held in Endeavour International Holding B.V.;
3.2.7	an agreement and deed of pledge of shares between Endeavour International Holding B.V. and the Security Trustee over the shares held in Endeavour Energy Netherlands B.V.;

New York law

3.2.8 a security agreement between the Original Guarantors and the Security Trustee;

Texas law

3.2.9 a mortgage, deed of trust, assignment of products, security agreement, fixture filing and financing statement between Endeavour Operating Corporation and the Security Trustee.

4.	OTHER EVIDENCE AND DOCUMENTS
4.1	The Original Financial Statements for the Company and each other Obligor.
4.2	Evidence that all fees (including legal fees and fees due and payable under the Fee Letters) due and payable have been or will be paid on the first Utilisation Date.
4.3	Confirmation from the Finance Parties that they have completed all “know your customer” requirements to their satisfaction.
4.4	Evidence that all consents required under the First Lien Credit Agreement (and any related finance documents) in order for this Agreement to be entered into, and for the transactions contemplated hereunder to be completed, have been so obtained.
4.5	Confirmation from the Technical Bank that the Coverage Ratio on the Amendment Effective Date exceeds 2:1.
5.	LEGAL OPINIONS
5.1	A legal opinion of Herbert Smith LLP.
5.2	A legal opinion of Stibbe N.V.
5.3	A legal opinion of Bracewell & Giuliani LLP.
5.4	A legal opinion of Rice, Silbey, Reuther & Sullivan.

6.	AUTHORISATIONS
6.1	Confirmation from the Obligors that all relevant authorisations necessary in connection with the Transaction Documents have been obtained and are in full force and effect or will be in full force and effect when required.

SCHEDULE 3

CONDITIONS PRECEDENT

Part II

Conditions precedent required to be delivered by an Additional Obligor

1.	An Accession Letter, duly executed by the Additional Obligor and the Company and duly executed originals of any other documents (in form and substance satisfactory to the Agent) as may be necessary to ensure that the Additional Obligors accedes, and becomes a party, to each relevant Finance Document (“accession documents”).
2.	A copy of the constitutional documents of the Additional Obligor and any other person (an “Additional Transaction Party”) entering into any Security Documents referred to in paragraph 12 below.
3.	A copy of a resolution of the respective board of directors (or equivalent) of (a) the Additional Obligor and (b) any Additional Transaction Party, in each case:

3.1	approving the terms of, and the transactions contemplated by, each of the documents it is or will become party to (the “Relevant Documents”);
3.2	authorising a specified person or persons to execute each such Relevant Document on its behalf; and
3.3	authorising a specified person or persons, on its behalf, to sign and/or despatch all other documents and notices (including, in relation to an Additional Borrower, any Utilisation Request or a Selection Notice) to be signed and/or despatched by it under or in connection with any such Relevant Document.

4.	A specimen of the signature of each person authorised by the resolution referred to in paragraph 3 above.
5.	In the case of an Additional Guarantor, a copy of a resolution signed by all the holders of the issued shares of the Additional Guarantor, approving the terms of, and the transactions contemplated by, the Finance Documents to which the Additional Guarantor is, or will become, a party.
6.	A certificate of the Additional Obligor (signed by a director or, if appropriate, an officer) confirming that borrowing or guaranteeing, as appropriate, the Aggregate Commitments would not cause any borrowing, guaranteeing or similar limit binding on it to be exceeded.
7.	A certificate of an authorised signatory of:

7.1	the Additional Obligor; and
7.2	each Additional Transaction Party (if any)

	(in each case) certifying that each copy document listed in this Part II of Schedule 3 relating to it is correct, complete and in full force and effect as at a date no earlier than the date of the Relevant Document(s) to which it is a party.
8.	A copy of any other Authorisation or other document, opinion or assurance which the Agent considers to be necessary or desirable in connection with the entry into and performance of the transactions contemplated by each Relevant Document or for the validity and enforceability of any Relevant Document.
9.	If available, the latest audited financial statements of the Additional Obligor.

10.	Such legal opinions in relation to the Additional Obligor, any Additional Transaction Party and/or the Relevant Documents as the Agent may reasonably require (together with any documents that may be required for the delivery of such legal opinions).
11.	If the proposed Additional Obligor is incorporated in a jurisdiction other than England and Wales, evidence that the process agent specified in Clause 43.2 (Service of process), if not an Obligor, has accepted its appointment in relation to the proposed Additional Obligor.
12.	Security Document(s) creating Security over (a) the entire issued share capital of the Additional Obligor, (b) if required by the Majority Lenders, all of the assets of the Additional Obligor, in the case of (a) and (b) duly executed by the relevant parties in form and substance satisfactory to the Security Trustee together with:

12.1	(to the extent applicable) evidence that all approvals, filings, registrations, recordings and other things necessary or desirable (including the carrying out of the procedures specified in ss.155-8 of the Companies Act 1985 (if appropriate)) to ensure the validity, effectiveness, priority and enforceability of each such Security Document have been carried out;
12.2	copies of each of the notices required to be given under each such Security Document together with other copies of acknowledgements from each person to whom notice was given, in the form required by such document; and
12.3	(if required by the Agent) evidence that the Security Trustee or its nominee has been entered in the register of members (or equivalent) of such proposed Additional Obligor as sole shareholder of all its issued share capital.

14. Evidence that all “know your customer” or similar identification procedures relating to the proposed Additional Obligor or any Additional Transaction Party have been carried out and completed.

SCHEDULE 4

REQUESTS

Part I

Utilisation Request

From: [Borrower]

To: [Agent]

Dated:

Dear Sirs

Junior Facility Agreement dated 22 January 2008 between, among others, Endeavour International
Corporation and Bank of Scotland plc (as amended and restated from time to time) (the
“Agreement”)

1.	We refer to the Agreement. This is a Utilisation Request. Terms defined in the Agreement have the same meaning in this Utilisation Request unless given a different meaning in this Utilisation Request.
2.	We wish to borrow a Loan on the following terms:

Proposed Utilisation Date:	[     ] (or, if that is not a Business Day, the next Business Day)
Amount:	[     ]
Currency:	[dollars/sterling]
Interest Period:	[     ]

3.	The purpose of the Loan is [     ].
4.	We confirm that each condition specified in Clause 8 (Conditions of Utilisation) of the Agreement are or will be satisfied on the first Utilisation Date.
5.	[We confirm that the proceeds of the Loan will only be utilised for expenditure in relation to the operations of the Obligors in the United States of America or in the United Kingdom, a jurisdiction in which we operate.]1
6.	The proceeds of this Loan should be credited to [      ].
7.	This Utilisation Request is irrevocable.

Yours faithfully

authorised signatory for

[name of relevant Borrower]

SCHEDULE 4

REQUESTS

(i)¹ Consent of all Lenders needed if this confirmation is omitted.

Part II

Selection Notice

From: [Borrower]

To: [Agent]

Dated:

Dear Sirs

Junior Facility Agreement dated 22 January 2008 between, among others, Endeavour International
Corporation and Bank of Scotland plc (as amended and restated from time to time) (the
“Agreement”)

1.	We refer to the Agreement. This is a Selection Notice. Terms defined in the Agreement have the same meaning in this Selection Notice unless given a different meaning in this Selection Notice.
2.	We refer to the following Loan[s] in [identify currency] with an Interest Period ending on [          ]*.
3.	[We request that the above Loan[s] be divided into [          ] Loans with the following Amounts and Interest Periods:]**
	or
	[We request that the next Interest Period for the above Loan[s] is [          ]].***
4.	We request that the above Loan[s] [is]/[are] [denominated in the same currency for the next Interest Period]/[denominated in the following currency: [dollar][sterling]. As this results in a change of currency, we confirm that each condition specified in Clause 4.2 (Further conditions precedent) is satisfied on the date of this Selection Notice. The proceeds of any change in currency shall be credited to [account].]
5.	This Selection Notice is irrevocable.

Yours faithfully

authorised signatory for

[name of relevant Borrower]

SCHEDULE 5

MANDATORY COST FORMULAE

1.	The Mandatory Cost is an addition to the interest rate to compensate lenders for the cost of compliance with (a) the requirements of the Bank of England and/or the Financial Services Authority (or, in either case, any other authority which replaces all or any of its functions) or (b) the requirements of the European Central Bank.
2.	On the first day of each Interest Period (or as soon as possible thereafter) the Agent shall calculate, as a percentage rate, a rate (the “Additional Cost Rate”) for each Lender, in accordance with the paragraphs set out below. The Mandatory Cost will be calculated by the Agent as a weighted average of the Lenders’ Additional Cost Rates (weighted in proportion to the percentage participation of each Lender in the relevant Loan) and will be expressed as a percentage rate per annum.
3.	The Additional Cost Rate for any Lender lending from a Facility Office in a Participating Member State will be the percentage notified by that Lender to the Agent. This percentage will be certified by that Lender in its notice to the Agent to be its reasonable determination of the cost (expressed as a percentage of that Lender’s participation in all Loans made from that Facility Office) of complying with the minimum reserve requirements of the European Central Bank in respect of loans made from that Facility Office.
4.	The Additional Cost Rate for any Lender lending from a Facility Office in the United Kingdom will be calculated by the Agent as follows:
4.1	in relation to a sterling Loan:

AB + C (B-D) + E x 0.01	per cent. per annum
100-(A+C)

4.2 in relation to a Loan in any currency other than sterling:

E x 0.01	per cent. per annum
300

Where:

A	is the percentage of Eligible Liabilities (assuming these to be in excess of any stated minimum) which that Lender is from time to time required to maintain as an interest free cash ratio deposit with the Bank of England to comply with cash ratio requirements.
B	is the percentage rate of interest (excluding the Margin and the Mandatory Cost and, if the Loan is an Unpaid Sum, the additional rate of interest specified in Clause 13.3.1 (Default interest)) payable for the relevant Interest Period on the Loan.
C	is the percentage (if any) of Eligible Liabilities which that Lender is required from time to time to maintain as interest bearing Special Deposits with the Bank of England.
D	is the percentage rate per annum payable by the Bank of England to the Agent on interest bearing Special Deposits.
E	is designed to compensate Lenders for amounts payable under the Fees Rules and is calculated by the Agent as being the average of the most recent rates of charge supplied by the Reference Banks to the Agent pursuant to paragraph 7 below and expressed in pounds per £1,000,000.

5. For the purposes of this Schedule:

5.1	“Eligible Liabilities” and “Special Deposits” have the meanings given to them from time to time under or pursuant to the Bank of England Act 1998 or (as may be appropriate) by the Bank of England;
5.2	“Fees Rules” means the rules on periodic fees contained in the Financial Services Authority Fees Manual or such other law or regulation as may be in force from time to time in respect of the payment of fees for the acceptance of deposits;
5.3	“Fee Tariffs” means the fee tariffs specified in the Fees Rules under the activity group A.1 Deposit acceptors (ignoring any minimum fee or zero rated fee required pursuant to the Fees Rules but taking into account any applicable discount rate); and
5.4	“Tariff Base” has the meaning given to it in, and will be calculated in accordance with, the Fees Rules.
6.	In application of the above formulae, A, B, C and D will be included in the formulae as percentages (i.e. 5 per cent. will be included in the formula as 5 and not as 0.05). A negative result obtained by subtracting D from B shall be taken as zero. The resulting figures shall be rounded to four decimal places.
7.	If requested by the Agent, each Reference Bank shall, as soon as practicable after publication by the Financial Services Authority, supply to the Agent, the rate of charge payable by that Reference Bank to the Financial Services Authority pursuant to the Fees Rules in respect of the relevant financial year of the Financial Services Authority (calculated for this purpose by that Reference Bank as being the average of the Fee Tariffs applicable to that Reference Bank for that financial year) and expressed in pounds per £1,000,000 of the Tariff Base of that Reference Bank.
8.	Each Lender shall supply any information required by the Agent for the purpose of calculating its Additional Cost Rate. In particular, but without limitation, each Lender shall supply the following information on or prior to the date on which it becomes a Lender:
8.1	the jurisdiction of its Facility Office; and
8.2	any other information that the Agent may reasonably require for such purpose.
9.	Each Lender shall promptly notify the Agent of any change to the information provided by it pursuant to this paragraph.
10.	The percentages of each Lender for the purpose of A and C above and the rates of charge of each Reference Bank for the purpose of E above shall be determined by the Agent based upon the information supplied to it pursuant to paragraphs 7 and 8 above and on the assumption that, unless a Lender notifies the Agent to the contrary, each Lender’s obligations in relation to cash ratio deposits and Special Deposits are the same as those of a typical bank from its jurisdiction of incorporation with a Facility Office in the same jurisdiction as its Facility Office.
11.	The Agent shall have no liability to any person if such determination results in an Additional Cost Rate which over or under compensates any Lender and shall be entitled to assume that the information provided by any Lender or Reference Bank pursuant to paragraphs 3, 7 and 8 above is true and correct in all respects.
12.	The Agent shall distribute the additional amounts received as a result of the Mandatory Cost to the Lenders on the basis of the Additional Cost Rate for each Lender based on the information provided by each Lender and each Reference Bank pursuant to paragraphs 3, 7 and 8 above.
13.	Any determination by the Agent pursuant to this Schedule in relation to a formula, the Mandatory Cost, an Additional Cost Rate or any amount payable to a Lender shall, in the absence of manifest error, be conclusive and binding on all Parties.

14. The Agent may from time to time, after consultation with the Company and the Lenders, determine and notify to all Parties any amendments which are required to be made to this Schedule in order to comply with any change in law, regulation or any requirements from time to time imposed by the Bank of England, the Financial Services Authority or the European Central Bank (or, in any case, any other authority which replaces all or any of its functions) and any such determination shall, in the absence of manifest error, be conclusive and binding on all Parties.

SCHEDULE 6

FORM OF TRANSFER CERTIFICATE²

To: [     ] as Agent

From: [The Existing Lender] (the “Existing Lender”) and [The New Lender] (the “New Lender”)

Dated:

Junior Facility Agreement dated 22 January 2009 between, among others, Endeavour International Corporation and Bank of Scotland (as amended and restated from time to time) (the “Agreement”)

1.	We refer to the Agreement. This is a Transfer Certificate. Terms defined in the Agreement have the same meaning in this Transfer Certificate unless given a different meaning in this Transfer Certificate.
2.	We refer to Clause 28.5 (Procedure for transfer):

2.1	The Existing Lender and the New Lender agree to the Existing Lender transferring to the New Lender by novation all or part of the Existing Lender’s Commitment, rights and obligations referred to in the Schedule in accordance with Clause 28.5 (Procedure for transfer).
2.2	The proposed Transfer Date is [     ].
2.3	The Facility Office and address, fax number and attention details for notices of the New Lender for the purposes of Clause 31.2 (Contact details) are set out in the Schedule.

3.	The New Lender expressly acknowledges the limitations on the Existing Lender’s obligations set out in Clause 28.4 (Limitation of responsibility of Existing Lenders).
4.	The New Lender confirms, for the benefit of the Agent and without liability to any Obligor, that it is:

4.1	[a Qualifying Lender falling within paragraph (A)(1) [or paragraph (B)] of the definition of Qualifying Lender;]
4.2	[a Treaty Lender;]
4.3	[not a Qualifying Lender].3

5. [The New Lender confirms that the person beneficially entitled to interest payable to that Lender in respect of an advance under a Finance Document is either:

5.1	a company resident in the United Kingdom for United Kingdom tax purposes;
5.2	a partnership each member of which is:

(A)	a company so resident in the United Kingdom; or
(B)	a company not so resident in the United Kingdom which carries on a trade in the United Kingdom through a permanent establishment and which brings into account in computing its chargeable profits (within the meaning of section 19 of the CTA) the whole of any share of interest payable in respect of that advance that falls to it by reason of Part 17 of the CTA; or

(ii)2	Please seek advice from Dutch counsel for transfer below Euro €50,000.
(iii)3	Delete as applicable — each New Lender is required to confirm which of these three categories it falls within.

4.3 a company not so resident in the United Kingdom which carries on a trade in the United Kingdom through a permanent establishment and which brings into account interest payable in respect of that advance in computing the chargeable profits (within the meaning of section 19 of the CTA) of that company.]⁴

[4/5].	This Transfer Certificate may be executed in any number of counterparts and this has the same effect as if the signatures on the counterparts were on a single copy of this Transfer Certificate.
[5/6].	This Transfer Certificate [and any non-contractual obligations arising out of or in connection with it] [is/are] governed by English law.
[6/7].	This Transfer Certificate has been entered into on the date stated at the beginning of this Transfer Certificate.

(iv)⁴ Include if New Lender comes within Clause 5.1 (Definitions) of the definition of Qualifying Lender.

THE SCHEDULE

Commitment/rights and obligations to be transferred

[insert relevant details]
[Facility Office address, fax number and attention details for notices and account details for payments,]

(A) [Existing Lender]	(B) [New Lender]
(C) By:	(D) By:

This Transfer Certificate is accepted by the Agent and the Transfer Date is confirmed as [     ].

[Agent]

By:

SCHEDULE 7

FORM OF ASSIGNMENT AGREEMENT

To: [     ] as Agent and [     ] as Company, for and on behalf of each Obligor

From: [the Existing Lender] (the “Existing Lender") and [the New Lender] (the “New Lender")

Dated:

Junior Facility Agreement dated 22 January 2008 between, among others, Endeavour International Corporation and Bank of Scotland (as amended and restated from time to time) (the “Agreement”)

1.	We refer to the Agreement. This is an Assignment Agreement. Terms defined in the Agreement have the same meaning in this Assignment Agreement unless given a different meaning in this Assignment Agreement.
2.	We refer to Clause 28.6 (Procedure for assignment):

2.1	The Existing Lender assigns absolutely to the New Lender all the rights of the Existing Lender under the Agreement and the other Finance Documents which relate to that portion of the Existing Lender’s Commitments and participations in Loans under the Agreement as specified in the Schedule.
2.2	The Existing Lender is released from all the obligations of the Existing Lender which correspond to that portion of the Existing Lender’s Commitments and participations in Loans under the Agreement specified in the Schedule.
2.3	The New Lender becomes a Party as a Lender and is bound by obligations equivalent to those from which the Existing Lender is released under paragraph 2.2 above.5

3.	The proposed Transfer Date is [     ].
4.	On the Transfer Date the New Lender becomes Party to the Finance Documents as a Lender.
5.	The Facility Office and address, fax number and attention details for notices of the New Lender for the purposes of Clause 31.2 (Contact details) are set out in the Schedule.
6.	The New Lender expressly acknowledges the limitations on the Existing Lender’s obligations set out in Clause 28.4 (Limitation of responsibility of Existing Lenders).
7.	The New Lender confirms, for the benefit of the Agent and without liability to any Obligor, that it is:

7.1	[a Qualifying Lender falling within paragraph (A)(1) [or paragraph (B)] of the definition of Qualifying Lender;]
7.2	[a Treaty Lender;]
7.3	[not a Qualifying Lender].6

8. [The New Lender confirms that the person beneficially entitled to interest payable to that Lender in respect of an advance under a Finance Document is either:

(v)	5 If the Assignment Agreement is used in place of a Transfer Certificate in order to avoid a novation of rights/obligations for reasons relevant to a civil jurisdiction, local law advice should be sought to check the suitability of the Assignment Agreement due to the assumption of obligations contained in paragraph 2.3. This issue should be addressed at primary documentation stage.
(vi)	6 Delete as applicable — each New Lender is required to confirm which of these three categories it falls within.

8.1	a company resident in the United Kingdom for United Kingdom tax purposes; or
8.2	a partnership each member of which is:

8.2.1	a company so resident in the United Kingdom; or
8.2.2	a company not so resident in the United Kingdom which carries on a trade in the United Kingdom through a permanent establishment and which brings into account in computing its chargeable profits (within the meaning of section 19 of the CTA) the whole of any share of interest payable in respect of that advance that falls to it by reason of Part 17 of the CTA; or

8.3 a company not so resident in the United Kingdom which carries on a trade in the United Kingdom through a permanent establishment and which brings into account interest payable in respect of that advance in computing the chargeable profits (within the meaning of section 19 of the CTA) of that company.]⁷

[8/9].	This Assignment Agreement acts as notice to the Agent (on behalf of each Finance Party) and, upon delivery in accordance with Clause 28.7 (Copy of Transfer Certificate or Assignment Agreement to Company), to the Company (on behalf of each Obligor) of the assignment referred to in this Assignment Agreement.
[9/10].	This Assignment Agreement may be executed in any number of counterparts and this has the same effect as if the signatures on the counterparts were on a single copy of this Assignment Agreement.
[10/11].	This Assignment Agreement [and any non-contractual obligations arising out of or in connection with it] [is/are] governed by English law.
[11/12].	This Assignment Agreement has been entered into on the date stated at the beginning of this Assignment Agreement.

(vii) ⁷ Include only if New Lender is a UK Non-Bank Lender — i.e. falls within Clause 17.1.1(A)(2) (Definitions) of the definition of Qualifying Lender.

THE SCHEDULE

Rights to be assigned and obligations to be released and undertaken

[insert relevant details]

[Facility office address, fax number and attention details for notices and account details for payments]

(E) [Existing Lender]	(F) [New Lender]
(G) By:	(H) By:

This Assignment Agreement is accepted by the Agent and the Transfer Date is confirmed as [   ].

Signature of this Assignment Agreement by the Agent constitutes confirmation by the Agent of receipt of notice of the assignment referred to herein, which notice the Agent receives on behalf of each Finance Party.

[Agent]

By:

SCHEDULE 8

FORM OF ACCESSION LETTER

To: [Agent] and [Security Trustee]

From: [Subsidiary] and [Company]

Dated:

Dear Sirs

Junior Facility Agreement dated 22 January 2008 between, among others, Endeavour International Corporation and Bank of Scotland plc (as amended and restated from time to time) (the “Agreement”)

1.	We refer to the Agreement. This is an Accession Letter. Terms defined in the Agreement have the same meaning in this Accession Letter unless given a different meaning in this Accession Letter.
2.	[Subsidiary] agrees to become an Additional [Borrower]/[Guarantor] and to be bound by (i) the terms of the Agreement and the Intercreditor Agreement as an Obligor and (ii) the terms of the other Finance Documents as an Additional [Borrower]/[Guarantor] pursuant to [Clause 29.2 (Additional Borrowers)] [Clause 29.3 (Additional Guarantors)] of the Agreement. [Subsidiary] is a company duly incorporated under the laws of [name of relevant jurisdiction].
4.	[Subsidiary’s] administrative details are as follows:
	Address:
	Fax No:
	Attention:
5.	This Accession Letter and any non-contractual obligation arising out of or in connection with it are governed by English law.

[This Accession Letter has been executed and delivered as a deed on the date stated at the beginning of this Accession Letter.]⁸

	Yours faithfully,
authorised signatory for	authorised signatory for
[name of relevant Subsidiary]	[Company]

This Accession Letter is accepted by the Agent and the Security Trustee.

[Agent]

By:

[Security Trustee]

By:

(viii)⁸ If to be entered by way of deed, execution blocks must be amended appropriately.

SCHEDULE 9

CORPORATE ORGANISATION CHART

0.1% GP 99.9% LP Endeavour International Corporation (Nevada Corporation) Endeavour Operating Corporation (Delaware Corporation) END Management Company (Delaware Corporation) Endeavour International Holding B.V. (Netherlands Corporation) Endeavour Energy New Ventures I, Ltd. (Bermuda Corporation) Endeavour Energy New Ventures Inc. (Delaware Corporation) Endeavour Energy Netherlands B.V. (Netherlands Corporation) Endeavour Energy Luxembourg S.a.r.l. (Luxembourg Corporation) Endeavour Energy North Sea LLC (Delaware LLC) Endeavour Energy UK Limited (England and Wales Corporation) Endeavour North Sea Limited (England and Wales Corporation) Endeavour Energy North Sea L.P. (DE)

SCHEDULE 3

FORM OF RESTATED INTERCREDITOR AGREEMENT

SCHEDULE 3
FORM OF RESTATED INTERCREDITOR AGREEMENT

31 OCTOBER 2006

ENDEAVOUR INTERNATIONAL CORPORATION
(as the Company)

THE OBLIGORS
(as defined herein)

THE FIRST LIEN LENDERS

(as defined herein)

THE SECOND LIEN LENDERS

(as defined herein)

THE HEDGING BANKS

(as defined herein)

BANK OF SCOTLAND PLC

(as Second Lien Agent)

and

BNP PARIBAS

(as First Lien Agent and Security Trustee)

INTERCREDITOR AGREEMENT

Herbert Smith LLP

TABLE OF CONTENTS

1. DEFINITIONS, CONSTRUCTION AND THIRD PARTY RIGHTS	1
2. RANKING	8
3. UNDERTAKINGS	8
4. PERMITTED PAYMENTS	9
5. EQUALISATION	10
6. ENFORCEMENT	12
7. CASCADE	14
8. MODIFICATIONS	16
9. HEDGING UNDERTAKINGS	18
10. INFORMATION SHARING	19
11. SUBROGATION	20
12. PROTECTION OF SUBORDINATION	21
13. CHANGES TO THE PARTIES	22
14. GENERAL	24
15. SECOND LIEN BUY-OUT	24
16. SECOND LIEN BUY-OUT OF HEDGES	26
17. FIRST LIEN BUY-OUT	27
18. THE SECURITY TRUSTEE	28
19. NOTICES	37
20. GOVERNING LAW	39
21. ENFORCEMENT	39
SCHEDULE 1 — PARTIES	40
SCHEDULE 2 — FORM OF ACCESSION INSTRUMENT	42

THIS AGREEMENT is made as a deed, dated 31 October 2006 and made between:

(4)	ENDEAVOUR INTERNATIONAL CORPORATION (the “Company”);
(5)	THE AFFILIATES OF THE COMPANY listed in Part I (Obligors) of Schedule 1 (Parties) (as initial Obligors);
(6)	THE BANKS AND FINANCIAL INSTITUTIONS listed in Part II (First Lien Lenders) of Schedule 1 (Parties) (as initial First Lien Lenders);
(7)	THE BANKS AND FINANCIAL INSTITUTIONS listed in Part III (Second Lien Lenders) of Schedule 1 (Parties) (as initial Second Lien Lenders);
(8)	THE BANKS AND FINANCIAL INSTITUTIONS listed in Part IV (Hedging Banks) of Schedule 1 (Parties) (as initial Hedging Banks);
(6)	BANK OF SCOTLAND PLC (as Second Lien Agent); and

(7) BNP PARIBAS (as First Lien Agent and Security Trustee)

IT IS AGREED as follows:

44.	DEFINITIONS, CONSTRUCTION AND THIRD PARTY RIGHTS
44.1	Definitions
	In this Agreement:
	“Accession Instrument” means:

(a) in relation to any person acceding, and becoming a party, to this Agreement as an “Obligor”:

(i)	at any time before the First Lien Discharge Date, an Accession Letter (as defined in the First Lien Credit Agreement); and
(ii)	at any time before the Second Lien Discharge Date, an Accession Letter (as defined in the Second Lien Credit Agreement);

(b)	in relation to any person acceding, and becoming a party, to this Agreement as a “First Lien Lender”, a Transfer Certificate (as defined in the First Lien Credit Agreement);
(c)	in relation to any person acceding, and becoming a party, to this Agreement as a “Second Lien Lender”, a Transfer Certificate (as defined in the Second Lien Credit Agreement); and
(d)	in relation to any other person, a deed of accession in the form set out in Schedule 2 (Form of Accession Instrument) (as the same may be amended with the approval of the Security Trustee).

“Amendment Agreement” means the amendment and restatement agreement dated February 2010 between, among others, the Company, Bank of Scotland plc and the BNP Paribas pursuant to which the Second Lien Credit Agreement has been amended and restated.

“Debt” means any present or future sum, liability and obligation whatsoever (actual or contingent) payable, owing due or incurred by any Obligor to any Secured Creditor, together with:

(a)	any refinancing, novation, refunding, deferral or extension of that sum, liability or obligation;
(b)	any further advance which may be made under any agreement supplemental to the relevant documents relating to that sum, liability or obligation (together with all related interest, fees and costs);
(c)	any claim for damages or restitution in the event of rescission of that sum, liability or obligation or otherwise;
(d)	any claim flowing from any recovery by a payment or discharge in respect of that sum, liability or obligation on the grounds of preference or otherwise; and

(e) any sum, liability or obligation (such as post-insolvency interest) which would be included in any of the above but for any discharge, non-provability, unenforceability or non-allowability of the same in any insolvency or other proceedings.

“Enforcement Trigger Date” means the earlier of the First Lien Enforcement Date and the Second Lien Enforcement Date.

“Finance Documents” means:

(a)	the First Lien Documents;
(b)	the Secured Hedging Agreements;
(c)	the Second Lien Documents;
(d)	this Agreement;
(e)	any Accession Instrument; and
(f)	any other document that is designated as such by the Security Trustee and the Company.

“First Lien Agent” means the Agent (as defined in the First Lien Credit Agreement) and any other person that replaces it in such capacity in accordance with the First Lien Credit Agreement and this Agreement.

“First Lien Credit Agreement” means the $225,000,000 secured revolving loan and letter of credit facility agreement dated 30 October 2006 between, among others, the Company and BNP Paribas and the Bank of Scotland plc (formerly, Governor and Company of the Bank of Scotland) (as amended from time to time).

“First Lien Debt” means all Debt payable, owing due or incurred by any Obligor to a First Lien Lender under or in connection with the First Lien Documents.

“First Lien Discharge Date” means the date, as determined by the First Lien Agent, on which all First Lien Debt and all Hedging Debt has been unconditionally and irrevocably paid and discharged in full (as a result of enforcement or otherwise) and no amount is capable of being outstanding under the First Lien Documents.

“First Lien Documents” means the First Lien Credit Agreement and the other Finance Documents (as defined in the First Lien Credit Agreement) other than (a) any Secured Hedging Agreement and (b) to the extent that the same relates to the accession by any party to the Finance Documents as a Hedging Bank, any Accession Instrument.

“First Lien Enforcement Date” means the date on which the First Lien Agent has issued a notice under clause 25.23 (Acceleration) of the First Lien Credit Agreement and provided a copy of the same to the Second Lien Agent.

“First Lien Lender” means each of the Finance Parties (as defined in the First Lien Credit Agreement but excluding, for these purposes, the Security Trustee and the Hedging Banks) being:

(a)	(as at the date of the Amendment Agreement) the banks and financial institutions named in Part II (First Lien Lenders) of Schedule 1 (Parties); and
(b)	each other person that accedes, and becomes a party, to this Agreement as a “First Lien Lender” in accordance with this Agreement,

which, in each case, has not ceased to be a party to the First Lien Credit Agreement in accordance with the terms of that agreement (where a person shall not cease to be a party to the First Lien Credit Agreement solely by reason of the prepayment or repayment of the Facility (as defined in the First Lien Credit Agreement)).

“Fronting Bank” has the meaning given to it in the First Lien Credit Agreement.

“Hedging Agreement” means any interest, currency or commodity swap, option, cap, collar, floor or similar arrangement or other hedging arrangement.

“Hedging Bank” means:

(a)

any First Lien Lender; and

(b)

any Affiliate of any First Lien Lender that executes or accedes to , and becomes a party to, this Agreement as a “Hedging Bank” in accordance with Clause 56.5 (Accession of Hedging Banks) (provided that such Affiliate shall cease to be a “Hedging Bank” when that First Lien Lender ceases to be a First Lien Lender or, if earlier, when the relevant Affiliate ceases to be an Affiliate of the relevant First Lien Lender).

“Hedging Costs” means any amount falling due from an Obligor under a Permitted Hedging Agreement except for any Hedging Termination Payment.

“Hedging Debt” means all Debt payable, owing due or incurred by any Obligor to a Hedging Bank under or in connection with the Secured Hedging Agreements.

“Hedging Receipts” means any amount falling due to an Obligor under a Permitted Hedging Agreement except for any Hedging Termination Payment.

“Hedging Termination Payment” means any amount falling due from or, as the case may be, to any Obligor under a Permitted Hedging Agreement as a direct or indirect result of the termination of that Permitted Hedging Agreement, other than interest accruing on any amount not paid when due.

“Instructing Group” means:

(a)	the Majority First Lien Lenders; or
(b)	on and from the First Lien Discharge Date, the Majority Second Lien Lenders; or
(c)	if the Second Lien Enforcement Date has occurred before the First Lien Discharge Date and either:

(i) the Majority First Lien Lenders have specifically instructed the Security Trustee not to (1) enforce the Security constituted by the Security Documents or (2) take

any action (including any such action described in Clause 49.1 (No independent action)) in connection with the recovery of the Debt; or

(ii) (1) the Second Lien Lenders are entitled under Clause 49.4 (Action by Second Lien Lenders) to take any of the actions that are otherwise prohibited by Clause 49.3 (Further restrictions — Second Lien Debt), (2) the Second Lien Agent has issued a Junior Pre-enforcement Notice to the First Lien Agent no earlier than ten Business Days before the expiry of the Relevant Standstill Period and (3) the Majority First Lien Lenders have not given any instructions to the Security Trustee on or before the tenth Business Days after the date of issue of that Junior Pre-enforcement Notice,

the Majority Second Lien Lenders.

“ISDA (1992)” means the 1992 ISDA Master Agreement (Multicurrency — Cross Border) (as published by the International Swaps and Derivatives Association).

“Junior Pre-enforcement Notice” means a notice issued by the Second Lien Agent which specifies that it is a “Junior Pre-enforcement Notice” and confirms that it is being issued under this Agreement for the purposes of the definition of “Instructing Group” set out above.

“Letter of Credit” has the meaning given to it in the First Lien Credit Agreement.

“Majority Second Lien Lenders” means the Majority Lenders as defined in the Second Lien Credit Agreement.

“Majority First Lien Lenders” means:

(a) at any time when there are no Hedging Termination Payments outstanding, the Majority Lenders as defined in the First Lien Credit Agreement; and

(b) at any time when there are Hedging Termination Payments outstanding:

(i)

until the Aggregate Commitments have been reduced to zero, a Lender or Lenders whose Commitments and the Hedge Termination Payments due to it or them or their Affiliates aggregate more than 66.67% of the sum of the Aggregate Commitments and such outstanding Hedge Termination Payments (or, if the Aggregate Commitments have been reduced to zero and there are no Utilisations then outstanding, aggregated more than 66.67% of the Aggregate Commitments immediately prior to the reduction); or

(ii)

at any other time, a Lender or Lenders the sum of whose participations in the Utilisations then outstanding and whose Hedge Termination Payments (or those of their Affiliates) receivable aggregate more than 66.67% of all the Utilisations and such Hedge Termination Payments then outstanding,

where, for the purpose of this paragraph (b) each of the terms “Lender”, “Commitments”, “Aggregate Commitments” and “Utilisations” has the meaning given in the First Lien Credit Agreement.

“Master Agreement” means:

(a)	the ISDA (1992) and related schedule and confirmations; or
(b)	any other agreement which is in form and substance satisfactory to the First Lien Agent.

“Obligor” means (a) the Company; (b) each person that is listed in Part I (Obligors) of Schedule 1 (Parties) and (c) each other person that accedes, and becomes a party, to this Agreement as an “Obligor” in accordance with this Agreement.

“Party” means a party to this Agreement.

“Prepayment” means any prepayment of any loan under the Second Lien Credit Agreement (other than as a result of an Event of Default (as defined in the Second Lien Credit Agreement)) before the earlier of (a) the First Lien Discharge Date and (b) the Final Maturity Date (as defined in the Second Lien Credit Agreement).

“Relevant Group” means:

(a)	at all times before the First Lien Discharge Date and the Second Lien Discharge Date, the Majority First Lien Lenders and the Majority Second Lien Lenders (acting together);
(b)	if the First Lien Discharge Date has occurred, the Majority Second Lien Lenders; or
(c)	if the Second Lien Discharge Date has occurred, the Majority First Lien Lenders.

“Relevant Standstill Period” has the meaning given to it in Clause 49.4.2 (Action by Second Lien Lenders).

“Report” means any report or opinion which has been prepared by an independent expert or adviser for the benefit of the Secured Creditors and which has been delivered to any of the Secured Creditors pursuant to the Finance Documents (including any legal opinions or reserves reports prepared by the Independent Engineer).

“Secured Creditor” means each of:

(a)	the Security Trustee;
(b)	the First Lien Lenders;
(c)	the Hedging Banks; and
(d)	the Second Lien Lenders.

“Secured Hedging Agreement” means any Hedging Agreement entered into between any Obligor and any Hedging Bank in compliance with the Finance Documents on or after the date on which that Hedging Bank becomes a Party hereto in its capacity as Hedging Bank.

“Security Document” means:

(a)	each document entered into pursuant to which Security over the share capital of any Obligor is granted to the Secured Creditors or, as the case may be, the Security Trustee (in its capacity as such);
(b)	each document entered into pursuant to which Security is granted by any Obligor over that Obligor’s assets to the Secured Creditors or, as the case may be, the Security Trustee (in its capacity as such);

(c)	each other document evidencing or creating any Security in favour of the Secured Creditors (or, as the case may be, the Security Trustee (in its capacity as such)) for, or in respect of, the liabilities and obligations of any Debt; and
(d)	each other document designated as such by the Security Trustee and the Company.

“Security Trustee” means BNP Paribas in its capacity as security trustee or any other person that replaces it in such capacity in accordance with this Agreement.

“Second Lien Agent” means the Agent (as defined in the Second Lien Credit Agreement) and any other person that replaces it in such capacity in accordance with the Second Lien Credit Agreement and this Agreement.

“Second Lien Credit Agreement” means the $25,000,000 junior facility agreement dated January 2008 between, among others, the Company, BNP Paribas and Bank of Scotland plc.

“Second Lien Debt” means all Debt payable, owing due or incurred by any Obligor to a Second Lien Lender under or in connection with the Second Lien Documents.

“Second Lien Discharge Date” means the date, as determined by the Second Lien Agent, on which all Second Lien Debt has been unconditionally and irrevocably paid and discharged in full (as a result of enforcement or otherwise).

“Second Lien Documents” means the Second Lien Credit Agreement and the other Finance Documents (as defined in the Second Lien Credit Agreement).

“Second Lien Enforcement Date” means the date on which the Second Lien Agent issues a notice under clause 23.23 (Acceleration) of the Second Lien Credit Agreement and provides a copy of the same to the First Lien Agent.

“Second Lien Lender” means each of the Finance Parties (as defined in the Second Lien Credit Agreement but excluding, for these purposes, the Security Trustee) being:

(a)	(as at the date of the Amendment Agreement) each of the banks and financial institutions named in Part III (Second Lien Lenders) of Schedule 1 (Parties); and
(b)	each other person that accedes, and becomes a party, to this Agreement as a “Second Lien Lender” in accordance with this Agreement,

which, in each case, has not ceased to be a party to the Second Lien Credit Agreement in accordance with the terms of that agreement (where a person shall not cease to be a party to the Second Lien Credit Agreement solely by reason of the prepayment or repayment of the Facility (as defined in the Second Lien Credit Agreement)).

44.2 Construction

44.2.1 Unless otherwise defined herein or unless the contrary is expressly specified herein:

(A) before the First Lien Discharge Date, terms defined in the First Lien Credit Agreement have the same meaning when used in this Agreement; and

(B) on or after the First Lien Discharge Date, terms defined in the Second Lien Credit Agreement have the same meaning when used in this Agreement.

44.2.2 Unless a contrary indication appears, any reference in this Agreement to:

(A)	any Secured Creditor or any Obligor shall be construed so as to include its successors in title, permitted assigns and permitted transferees;
(B)	“assets” includes present and future properties, revenues and rights of every description;
(C)	a “Finance Document” or any other agreement or instrument is a reference to that Finance Document or other agreement or instrument as modified (however fundamental and whether or not more onerously) and includes any change in the purpose of, any extension of or increase in any facility or addition of any new facility under that Finance Document or other agreement or instrument and only if the modification has not been made in contravention of this Agreement;
(D)	“indebtedness” includes any obligation (whether incurred as principal or as surety) for the payment or repayment of money, whether present or future, actual or contingent;
(E)	a “person” includes any individual, firm, company, corporation, government, state or agency of a state or any association, trust, joint venture, consortium or partnership (whether or not having separate legal personality) or two or more of the foregoing;
(F)	a “regulation” includes any regulation, rule, official directive, request or guideline (whether or not having the force of law but, if not having the force of law, being of a kind that is normally complied with by those to whom it is addressed) of any governmental, intergovernmental or supranational body, agency, department or regulatory, self-regulatory or other authority or organisation;
(G)	a “modification” includes an amendment, supplement, novation, re-enactment, restatement, variation, modification or waiver or the giving of any waiver, release or consent having the same commercial effect of any of the forgoing (and “modify” shall be construed accordingly);
(H)	a provision of law is a reference to that provision as amended or re-enacted;
(I)	a time of day is a reference to London time;
(J)	any matter “including” specific instances or examples of such matter shall be construed without limitation to the generality of that matter (and references to “include” shall be construed accordingly);
(K)	the “winding-up", “dissolutions” or “administration” of a person shall be construed so as to include any equivalent or analogous proceedings under the law of the jurisdiction in which such person is incorporated or established, or any jurisdiction in which such person carries on business including the seeking of liquidation, winding-up, reorganisation, dissolution, administration, arrangement, adjustment, protection or relief of debtors.

44.2.3 Clause and Schedule headings are for ease of reference only.

44.3 Third party rights

44.3.1	Unless expressly provided to the contrary in a Finance Document, a person who is not a Party has no right under the Contracts (Rights of Third Parties) Act 1999 to enforce or to enjoy the benefit of any term of this Agreement.
44.3.2	Notwithstanding any term of any Finance Document, the consent of any person who is not a Party is not required to rescind or vary this Agreement at any time.

44.4	Incorporation
	Without prejudice to the application of any other provisions of the First Lien Credit Agreement to this Agreement (by reason of this Agreement being a Finance Document for the purposes of the First Lien Credit Agreement), clauses 16.1 (Currency indemnity), 18 (Costs and expenses), 33 (Calculations and certificates), 34 (Partial invalidity), 35 (Remedies and waivers), and 37 (Counterparts) of the First Lien Credit Agreement shall apply to this Agreement, mutatis mutandis, as if the same had been set out in full herein with references in each clauses to any “Finance Party” being construed as references to any “Secured Creditor” for the purposes of this Agreement.
45.	RANKING
45.1	Priority of Security
	Subject to the terms of this Agreement, the Security granted pursuant to the Security Documents shall secure:

45.1.1	all the First Lien Debt and Hedging Debt in priority to the Second Lien Debt; and
45.1.2	all the Second Lien Debt.

45.2	Application of ranking
	The ranking in Clause 45.1 (Priority of Security) shall apply regardless of:

45.2.1	the order of registration, delivery of, notice or execution of any document (including any Security Document);
45.2.2	the date upon which a Debt arises;
45.2.3	whether a Secured Creditor is obliged to advance moneys included in any Debt; or
45.2.4	any fluctuations in the outstanding amount of, or any intermediate discharge of, any Debt in whole or in part.

46.	UNDERTAKINGS
46.1	Obligors
	Each of the Obligors undertakes to the Secured Creditors that it will not without the prior consent of the Instructing Group:

46.1.1	pay, repay, reduce, redeem, purchase, acquire or otherwise discharge, any of the Debt in cash or kind except as permitted by Clause 47 (Permitted payments);
46.1.2	discharge any of the Debt by set-off, any right of combination of accounts or otherwise except as permitted by Clause 47 (Permitted payments);
46.1.3	create, or permit to subsist, any Security over any of its assets for any of the Debt except under the Security Documents;

46.1.4	give, or permit any person to give, any guarantee, indemnity or other assurance against financial loss in respect of any of the Debt save for any Security or guarantee constituted by any Security Document and the guarantees given under the First Lien Credit Agreement and the Second Lien Credit Agreement;
46.1.5	permit any Debt to be evidenced by any negotiable instrument unless a memorandum of this Agreement is endorsed on such instrument; or
46.1.6	take or omit to take any action whereby the priority contemplated by this Agreement may be impaired.

46.2	Secured Creditors
	Each Secured Creditor undertakes to the other Secured Creditors that it will not without the prior consent of the Instructing Group:

46.2.1 demand or receive any payment, repayment, reduction or redemption of, or otherwise permit the discharge of, any of the Debt in cash or in kind from an Obligor or any other source except in each case:

(A)	to the extent permitted or required under this Agreement; and
(B)	for any proceeds received and applied in the order permitted by Clause 7 (Cascade);

46.2.2	discharge any Debt by set-off, any right of combination of accounts or otherwise except as permitted by Clause 47 (Permitted payments);
46.2.3	permit to subsist, or receive the benefit of, any Security for any of the Debt except under the Security Documents;
46.2.4	permit to subsist, or receive the benefit of, any guarantee, indemnity or other assurance against financial loss in respect of any of the Debt save for any Security or guarantee constituted by any Security Document and the guarantees given under the First Lien Credit Agreement and the Second Lien Credit Agreement;
46.2.5	permit any Debt to be evidenced by any negotiable instrument unless a memorandum of this Agreement is endorsed on such instrument; or
46.2.6	take or omit to take any action whereby the priority contemplated by this Agreement may be impaired.

46.3	Prepayment under the Second Lien Credit Agreement
	Without prejudice to the rights of all or any of the Second Lien Lenders to accelerate, in accordance with this Agreement, the facility provided for under the Second Lien Credit Agreement following the occurrence of any Event of Default (as defined in the Second Lien Credit Agreement), each of the Obligors and each of the Second Lien Lenders agree that unless the First Lien Agent otherwise consents, no Prepayments may be made under the Second Lien Credit Agreement other than under clause 8.1 (Illegality) or clause 8.3 (Mandatory prepayment) of the Second Lien Credit Agreement.
47.	PERMITTED PAYMENTS
47.1	First Lien Debt
	Prior to the Enforcement Trigger Date:

47.1.1	each Obligor may make, and each First Lien Lender may receive and retain, any payments or prepayments of any First Lien Debt (including any payments of cash cover with respect to any Letter of Credit) in accordance with the First Lien Documents; and
47.1.2	each First Lien Lender may only discharge any First Lien Debt by set-off in accordance with the First Lien Documents and only to the extent that such First Lien Debt is permitted to be paid under Clause 47.1.1.

47.2	Hedging Debt
	Prior to the Enforcement Trigger Date:

47.2.1	each Obligor may make, and each Hedging Bank may receive and retain, any scheduled payments arising under the terms of the relevant Secured Hedging Agreement in accordance with the terms of the relevant Secured Hedging Agreement;
47.2.2	each Hedging Bank may only discharge any Hedging Debt under any netting arrangements in accordance with the terms of the relevant Secured Hedging Agreement to the extent that such Hedging Debt is permitted to be paid under Clause 47.2.1; and
47.2.3	each Hedging Bank may only discharge any Hedging Debt by set-off in accordance with the First Lien Credit Agreement and only to the extent that such Hedging Debt is permitted to be paid under Clause 47.2.1.

47.3	Second Lien Debt
	Prior to the Enforcement Trigger Date:

47.3.1	each Obligor may make, and each Second Lien Lender may receive and retain, any payments or prepayments of any Second Lien Debt in accordance with the Second Lien Documents; and
47.3.2	each Second Lien Lender may only discharge any Second Lien Debt by set-off in accordance with the Second Lien Documents and only to the extent that such Second Lien Debt is permitted to be paid under Clause 47.3.1.

47.4	Suspension of permitted payments
	Unless the Instructing Group otherwise consents, on and from the Enforcement Trigger Date:

47.4.1	no Obligor may make, and none of the Secured Creditors may receive and retain, any payments or prepayments of any Debt; or
47.4.2	no Secured Creditor may discharge any Debt by set-off,

	which, in each case, would otherwise be permitted pursuant to the preceding provisions of this Clause 47 (Permitted payments); and on and from such Enforcement Trigger Date, the repayment of all Debt must be made pursuant to Clause 50 (Cascade).
48.	EQUALISATION
48.1	Recoveries

48.1.1 If:

(A) a Secured Creditor receives or recovers a payment or distribution in cash or in kind (including by way of set-off or combination of accounts) in respect of any Debt, in each case, other than as permitted under Clause 4 (Permitted payments) or other than pursuant to Clause 7 (Cascade); or

(B) before the First Lien Discharge Date, any Second Lien Lender receives or recovers a payment or distribution in cash or in kind (including by way of set-off or combination of accounts) from or on behalf of any member of the Group on the account of the purchase or acquisition of any Second Lien Debt,

	then that Secured Creditor (a “Recovering Secured Creditor”) shall, within three Business Days, notify details of the receipt or recovery, to the Security Trustee.
48.1.2	The Security Trustee shall determine whether the receipt or recovery is in excess of the amount the Recovering Secured Creditor would have been paid had the receipt or recovery been received or made by the Security Trustee and distributed in accordance with Clause 7 (Cascade) without taking account of any Tax which would be imposed on the Security Trustee in relation to the receipt, recovery or distribution.
48.1.3	The Recovering Secured Creditor shall, within three Business Days of demand by the Security Trustee, pay to the Security Trustee an amount (the “Sharing Payment”) equal to such receipt or recovery less any amount which the Security Trustee determines may be retained by the Recovering Secured Creditor as its share of any payment to be made in accordance with Clause 7 (Cascade).

48.2	Redistribution of payments
	The Security Trustee shall treat the Sharing Payment as if it had been paid by the relevant Obligor and distribute it between the Secured Creditors (other than the Recovering Secured Creditor) in accordance with Clause 7 (Cascade).
48.3	Recovering Secured Creditor’s rights

48.3.1	On a distribution by the Security Trustee under Clause 48.2 (Redistribution of payments), the Recovering Secured Creditor will be subrogated to the rights of the Secured Creditors which have shared in the redistribution.
48.3.2	If and to the extent that the Recovering Secured Creditor is not able to rely on its rights under Clause 48.3.1, the Obligors shall be liable to the Recovering Secured Creditor for a debt equal to the Sharing Payment which is immediately due and payable.

48.4	Reversal of redistribution
	If any part of the Sharing Payment received or recovered by a Recovering Secured Creditor becomes repayable and is repaid by that Recovering Secured Creditor, then:

48.4.1

each Secured Creditor which has received a share of the relevant Sharing Payment pursuant to Clause 48.2 (Redistribution of payments) shall, upon request of the Security Trustee, pay to the Security Trustee for account of that Recovering Secured Creditor an amount equal to the appropriate part of its share of the Sharing Payment (together with an amount as is necessary to reimburse that Recovering Secured Creditor for its proportion of any interest on the Sharing Payment which that Recovering Secured Creditor is required to pay); and

48.4.2

that Recovering Secured Creditor’s rights of subrogation, or the debt due pursuant to Clause 48.3.2 (as the case may be), in respect of any reimbursement shall be cancelled and the Obligors will be liable to the reimbursing Secured Creditor for the amount so reimbursed.

48.5 Exceptions

48.5.1 This Clause 48 (Equalisation) shall not apply to the extent that the Recovering Secured Creditor would not, after making any payment pursuant to this Clause, have a valid and

	enforceable claim against the relevant Obligor from whom the relevant receipt or recovery is made.
48.5.2	Without prejudice to Clause 49 (Enforcement), a Recovering Secured Creditor is not obliged to share with any other Secured Creditor any amount which the Recovering Secured Creditor has received or recovered as a result of taking legal or arbitration proceedings, if:

(A)	it notified that other Secured Creditor of the legal or arbitration proceedings; and
(B)	that other Secured Creditor had an opportunity to participate in those legal or arbitration proceedings but did not do so as soon as reasonably practicable having received notice and did not take separate legal or arbitration proceedings.

49.	ENFORCEMENT
49.1	No independent action

49.1.1 Without prejudice to the rights of the Secured Creditors to instruct the Security Trustee pursuant to Clause 61.7 (Instructions) to take any such action, none of the Secured Creditors (other than the Security Trustee) may (without the consent of the Security Trustee):

(A)	enforce or exercise any other equivalent right with respect to any Security constituted by any Security Document;
(B)	in respect of any asset or right subject to any Security Document, sue for or institute any creditor’s process (including a Mareva injunction, garnishment, execution or levy, whether before or after judgment) in respect of any obligation (whether or not for the payment of money) owing to it under or in respect of any Finance Document or otherwise enforce any Debt by attachment, execution or otherwise;
(C)	take any step (including petition, application, notice of meeting or proposal to creditors) for the liquidation, winding-up, administration, dissolution or bankruptcy (or analogous proceeding in any jurisdiction) of an Obligor, or take any step for a voluntary arrangement or scheme of arrangement or analogous proceeding in relation to any Obligor.

49.1.2 Subject thereto, each Secured Creditor may exercise any rights it may have as an unsecured creditor of the Company or of any Obligor as it thinks fit, provided that it shall not exercise such rights in a manner inconsistent with the provisions of this Agreement or which may affect recovery under the Security Documents.

49.2	Further restrictions — Hedging Debt
	Subject to Clause 49.1 (No independent action), a Hedging Bank may exercise its rights under any Secured Hedging Agreement to terminate, or close out of, any hedging transaction and to demand the repayment of sums outstanding thereunder provided that (unless the Security Trustee otherwise consents) it shall only exercise such rights if:

49.2.1	an Illegality (as defined in the ISDA (1992)) has occurred;
49.2.2	a Tax Event (as defined in the ISDA (1992)) has occurred;

49.2.3	the relevant Obligor that is party to such Secured Hedging Agreement has not paid an amount due under that Secured Hedging Agreement on its stated due date and such payment has not been made within 21 days of the date on which the relevant Hedging Bank notifies the Security Trustee of such failure to pay (and of such Hedging Bank’s intention to terminate or close out);
49.2.4	the relevant Obligor that is party to any such Secured Hedging Agreement, in respect of which the confirmations were entered into on or before 15 October 2006 has failed to comply with any other covenant or undertaking thereunder, or any event of default under or incorporated into such Secured Hedging Agreement has occurred, and such failure or default has not been cured within 21 days of the date on which the relevant Hedging Bank notifies the Security Trustee of such failure or default (and of such Hedging Bank’s intention to terminate or close out);
49.2.5	any formal proceedings have been commenced for the liquidation, winding-up, administration, dissolution or bankruptcy (or analogous proceeding in any jurisdiction) of the relevant Obligor that is party to such Secured Hedging Agreement and such proceedings have not been discharged within one month from the date of commencement;
49.2.6	the Enforcement Trigger Date has occurred and all or any amounts accrued or outstanding under the First Lien Documents or the Second Lien Documents have become immediately due and payable;
49.2.7	the Security Trustee has confirmed to that Hedging Bank that no amount under the First Lien Documents is outstanding or is capable of being outstanding; or
49.2.8	so required pursuant to Clause 52.1.3 (Two way payments).

49.3	Further restrictions — Second Lien Debt
	Save as permitted under Clause 49.4 (Action by Second Lien Lenders), the Second Lien Lenders shall not give the Security Trustee any instructions to take any of the actions referred to in Clause 49.1 (No independent action), unless (a) the First Lien Enforcement Date has occurred and all or any amounts accrued or outstanding under the First Lien Documents have become immediately due and payable, (b) the First Lien Discharge Date has occurred, (c) the Majority First Lien Lenders otherwise consent or (d) the Majority Second Lien Lenders constitute the Instructing Group in accordance with the definition of “Instructing Group” set out in Clause 1.1 (Definitions).
49.4	Action by Second Lien Lenders

49.4.1 The Second Lien Lenders may take any of the actions prohibited by Clause 49.3 (Further restrictions — Second Lien Debt) if each of the circumstances in (A), (B) and (C) below has occurred:

(A)	an Event of Default (as defined in the Second Lien Credit Agreement) has occurred and is continuing;
(B)	the Second Lien Agent has given notice to the First Lien Agent and the Security Trustee of such Event of Default; and
(C)	the Relevant Standstill Period or more days have elapsed since the date of issue of such notice; such Event of Default is still continuing; and:

(1) the First Lien Lenders have not exercised their rights under Clause 60 (First Lien buy-out);

(2)	the First Lien Agent and the Second Lien Agent have not otherwise reached agreement on any alternative arrangements satisfactory to the Majority Second Lien Lenders for the purposes of curing or addressing such Event of Default; and
(3)	the Second Lien Agent has issued a Junior Pre-Enforcement Notice no earlier than 10 Business Days before the expiry of the Relevant Standstill Period.

49.4.2 In this Agreement, “Relevant Standstill Period” means 180 days.

49.5 Manner of enforcement

49.5.1 The Instructing Group may give or refrain from giving any instructions to the Security Trustee to:

(A)	enforce (or refrain from enforcing) any Security constituted by the Security Documents; or
(B)	take (or refrain from taking) any other action in connection with the recovery of the Debt,

	in each case, as it sees fit without prior consultation with the other Secured Creditors.
49.5.2	In:

(A)	enforcing (or refrain from enforcing) any Security constituted by the Security Documents or giving any instructions to the Security Trustee relating thereto; or
(B)	taking (or refrain from taking) any other action (including any such action described in Clause 49.1 (No independent action)) in connection with the recovery of the Debt or giving any instructions to the Security Trustee relating thereto,

no Secured Creditor shall be responsible to any other Secured Creditor or any Obligor for maximizing the proceeds of such enforcement or such other action.

49.6	Permitted action — general
	If the operation of any provision of this Agreement prevents a Secured Creditor from exercising its rights to sue or bring or support proceedings against any member of the Group or any provider of any Report in a manner that would result in such Secured Creditor being prevented permanently from suing or bringing or supporting those proceedings by reason of the expiry of any statutory limitation period, that Secured Creditor may exercise its rights to sue or bring or support those proceedings against that member of the Group or that provider of that Report but only to the extent necessary to prevent the loss of the right to sue or bring or support those proceedings.
50.	CASCADE
50.1	Order of application

50.1.1 Subject to the rights of any creditor with prior Security or any preferential claim, all amounts paid to, or otherwise recovered by, the Security Trustee pursuant to the Finance Documents, shall be applied in the following order:

(A) first, in or towards payment pro rata of any unpaid fees, costs and expenses incurred by or on behalf of the Security Trustee and any receiver, attorney, agent or similar officer appointed under the Security Documents and any other

	sum due to the Security Trustee (in its capacity as such) but unpaid under the Finance Documents;
(B)	second, in or towards payment pro rata (a) to the First Lien Agent for application by the First Lien Agent under the First Lien Credit Agreement towards the balance of the First Lien Debt comprised by any unpaid fees, costs and expenses of the Administrative Finance Parties under the First Lien Documents and (b) of any unpaid fees, costs and expenses of the Account Bank;
(C)	third, in or towards payment pro rata (a) of Hedging Costs due but unpaid under the Secured Hedging Agreements and (b) to the First Lien Agent for application by the First Lien Agent under the First Lien Credit Agreement towards the balance of the First Lien Debt comprised by any accrued interest, commitment fees, commission due but unpaid under the First Lien Documents;
(D)	fourth, in or towards payment pro rata (a) of Hedging Termination Payments due to the Hedging Banks but unpaid under the Secured Hedging Agreements and (b) to the First Lien Agent for application by the First Lien Agent under the First Lien Credit Agreement towards the balance of the First Lien Debt comprised by any principal (including amounts payable under clause 6.8 (Claims under a Letter of Credit) or clause 6.10 (Indemnities) of the First Lien Credit Agreement) or any cash cover due but unpaid under the First Lien Documents;
(E)	fifth, in or towards payment pro rata (a) of any other sum due to the Hedging Banks but unpaid under the Secured Hedging Agreements and (b) to the First Lien Agent for application by the First Lien Agent under the First Lien Credit Agreement towards the balance of the First Lien Debt comprised by any other sum due but unpaid under the First Lien Documents;
(F)	sixth, in or towards payment to the Second Lien Agent for application by the Second Lien Agent under the Second Lien Credit Agreement towards the balance of the Second Lien Debt; and
(G)	seventh, in or towards payment of the surplus (if any) to the relevant Obligor or other person entitled to it.

50.1.2	Subject to Clause 51.3.4, the Security Trustee shall, if so directed by the Relevant Group, vary the order set out in Clauses 50.1.1(A) to 50.1.1(G).
50.1.3	Clauses 50.1.1 and 50.1.2 above will override any appropriation made by an Obligor.

50.2 Redistribution of cash cover

50.2.1 If any cash cover has been provided in respect of any Letter(s) of Credit (other than pursuant to clause 6.11 (Ratings criteria) of the First Lien Credit Agreement), then:

(A)

subject to Clause 50.2.1(B), any such cash cover shall not be applied pursuant to Clause 50.1 (Order of Application) but shall instead be retained by the relevant First Lien Lender(s) entitled to hold the same and be applied by such First Lien Lender(s) in the discharge of the Contingent Indebtedness in respect of which such cash cover has been provided as such Contingent Indebtedness matures; and

(B)

each of the First Lien Lenders that holds any such cash cover on the First Lien Discharge Date shall (provided that the First Lien Agent is satisfied that no First Lien Lender or Obligor is capable of incurring any further liability (actual or

contingent) with respect to the Letter(s) of Credit in respect of which such cash cover has been provided) pay the balance of such cash cover to the Security Trustee for application in accordance Clause 50.1 (Order of application).

50.2.2

The Obligors shall take all such steps as the Security Trustee may require in order to ensure that the First Lien Lenders are able to comply with Clause 50.2.1.

50.2.3

For the purposes of this Clause 50.2, “Contingent Indebtedness” means the liabilities of the Fronting Bank, the Lenders (as defined in the First Lien Credit Agreement) or, as the case may be, the Obligors (as defined in the First Lien Credit Agreement), with respect to any outstanding Letter(s) of Credit which have not matured and remain contingent by reason of such Letter(s) of Credit being outstanding.

50.3	Good discharge
	An acknowledgement of receipt signed by the relevant person to whom payments are to be made under this Clause 50 (Cascade) shall discharge the Security Trustee.
51.	MODIFICATIONS
51.1	First Lien Documents

51.1.1	Prior to the Second Lien Discharge Date, no Obligor or First Lien Lender will modify, or permit any modification to be made to, any provision of any of the First Lien Documents unless (a) Clause 51.1.2 has been complied with and (b) such modification is made in accordance with the First Lien Credit Agreement and the relevant First Lien Document to be modified.
51.1.2	Where any amendment, supplement or modification to the First Lien Document would have any of the following effects:

(A) to increase the aggregate principal amount of the Advances under the First Lien Credit Agreement plus the face amount of any Letter of Credit issued under the First Lien Credit Facility Agreement plus any Available Commitments thereunder to an amount in excess of T (where:

T (in US$) = A + F + C + $25 million;

A =	the Advances under the First Lien Facility Agreement;
F =	the face amount of all Letters of Credit issued under the First Lien Credit Agreement; and
C =	the Available Commitments under the First Lien Credit Agreement);

(B)	to increase the Margin or the utilisation fees applicable under the First Lien Credit Agreement by an amount of more than 3.0 per cent. per annum; or
(C)	extend the Final Maturity Date under the First Lien Credit Agreement to a date falling on or after 20 October 2011,

then such amendment, supplement or modification shall not be made without the prior consent of the Majority Second Lien Lenders.

51.2 Second Lien Documents

51.2.1 Subject to Clause 51.2.2, prior to the First Lien Discharge Date, no Obligor or Second Lien Lender will modify, or permit any modification to be made to, any provision of any of the Second Lien Documents unless:

(A)	such modification is made in accordance with the Second Lien Credit Agreement and the relevant Second Lien Document to be modified; and
(B)	where Clause 51.2.2 applies, the Majority First Lien Lenders have consented to such modification.

51.2.2 Where any amendment, supplement or modification to the Second Lien Documents applicable under the Second Lien Credit Agreement would have any of the following effects:

(A)	to advance any date for repayment of principal or payment of interest or the making of any mandatory prepayment under the Second Lien Credit Agreement;
(B)	to increase the Margin or the utilisation fees applicable under the Second Lien Credit Agreement;
(C)	to change any Event of Default under the Second Lien Credit Agreement in a manner which the First Lien Facility Agent reasonably determines is adverse to the interest of any Obligor;
(D)	to grant any additional Security to the Second Lien Agent; or
(E)	to modify clause 8.1 (Illegality) or clause 8.3 (Mandatory prepayment) in a manner which permits or requires Prepayments to be made in circumstances that are not provided for under such clause as at the date of the Amendment Agreement;
(F)	to otherwise make any amendment to the Second Lien Credit Agreement which, in the reasonable opinion of the First Lien Facility Agent would have an adverse affect upon the rights of the First Lien Lenders against the Obligors under this Agreement or otherwise in connection with the transactions contemplated by this Agreement and the First Lien Finance Documents,

then such amendment, supplement or modification shall not be made without the prior consent of the Majority First Lien Lenders.

51.3 Intercreditor Agreement

51.3.1	Subject to Clauses 51.3.2 to 51.3.5, any term of this Agreement may be modified only with the consent of the Relevant Group and any such modification will be binding on all Parties. The Security Trustee may effect, on behalf of any Secured Creditor, any modification permitted by this Clause 51.3 (Intercreditor Agreement).
51.3.2	Any modification that has the effect of changing or which relates to:

(A)	the definition of “Majority First Lien Lenders” or “Majority Second Lien Lenders” in Clause 44.1 (Definitions);
(B)	this Clause 51.3 (Intercreditor Agreement); or
(C)	the release of any Security granted under any Security Document save where such release is required pursuant to the terms of any Finance Document,

	shall not be made without the prior consent of the All Lender Group.
51.3.3	A modification that has the effect of changing or which relates to any provision which expressly requires the consent of any Secured Creditor or group of Secured Creditors (such as the Instructing Group or the Relevant Group) may not be effected without the consent of that Secured Creditor or group of Secured Creditors. If the modification in

	question is the giving of the relevant consent expressly provided for, then such modification may be effected by that Secured Creditor or group of Secured Creditors giving the requisite consent.
51.3.4	A modification that has the effect of changing or which relates to the rights or obligations of any of the Account Bank, the First Lien Agent, the Second Lien Agent, the Security Trustee, any other Administrative Finance Party (whether under the First Lien Credit Agreement or the Second Lien Credit Agreement) or any Hedging Bank may not be effected without the consent of that Secured Creditor.
51.3.5	A modification that has the effect of changing or which relates to the rights or obligations of the Obligors (or any of them) may not be effected without the consent of the Obligors.
51.3.6	For the purposes of this Clause 51.3 (Intercreditor Agreement), “All Lender Group” means:

(A)	at all times before the First Lien Discharge Date and the Second Lien Discharge Date, all the First Lien Lenders and all the Second Lien Lenders (acting together);
(B)	if the First Lien Discharge Date has occurred, all the Second Lien Lenders; or
(C)	if the Second Lien Discharge Date has occurred, all the First Lien Lenders.

51.4	Binding nature
	If any modification of any term of any Finance Document has been granted or made in accordance with the preceding provisions of this Clause 51 (Modifications), such or an equivalent modification shall also be deemed to have been made in relation to the other Finance Documents if any absence of such or equivalent modification would give rise to the contravention of, or a default under, such other Finance Documents.
52.	HEDGING UNDERTAKINGS
52.1	Two way payments
	Each Obligor and each Hedging Bank agrees that unless the First Lien Agent otherwise consents:

52.1.1	each Secured Hedging Agreement which it enters into after the date of this Agreement will provide for “full two way payments” or payments under the “Second Method” and “Market Quotation” in the event of a termination of a hedging transaction whether upon a Termination Event or an Event of Default (as defined in the ISDA (1992));
52.1.2	at any time on or after the Enforcement Trigger Date, if an amount falls due from a Hedging Bank to any Obligor under any Secured Hedging Agreement, that amount shall be paid by that Hedging Bank to the Security Trustee (in full discharge of its obligations to make such payments to such Obligor) for application in accordance with Clause 50 (Cascade); and
52.1.3	promptly on the occurrence of the Enforcement Trigger Date, each Hedging Bank will, if so instructed by the Security Trustee, exercise any rights it may have to terminate or close out all the hedging transactions under the Secured Hedging Agreements which the Security Trustee instructs it to terminate or close out and shall notify the Security Trustee when requested of any amounts due under such Secured Hedging Agreement.

52.2	Copies of documents
	Promptly upon request, each Obligor and each Hedging Bank will provide to the Security Trustee and the First Lien Agent copies of all Secured Hedging Agreements to which it is a party.
52.3	ISDA

52.3.1	Unless the First Lien Agent otherwise agrees, all Secured Hedging Agreements must be entered into under the terms of the Master Agreement.
52.3.2	Each Hedging Bank and each Obligor agrees that each Secured Hedging Agreement to which it is a party shall operate subject to the terms of this Agreement and the other First Lien Documents and, accordingly, in the event of any inconsistency between the terms of such Secured Hedging Agreement and any First Lien Document, the terms of that First Lien Document shall prevail.
52.3.3	Without prejudice to Clause 52.3.2, each Hedging Bank waives any rights or remedies that it may have against any other Secured Creditors by reason of (a) the entry into any Finance Document between any Obligor and any Secured Creditor, (b) the compliance by any Obligor of its obligations, or the exercise by any Obligor of its rights, under any Finance Document, (c) any modification of any Finance Document effected in accordance with this Agreement, or (d) any requirement or condition imposed by any Secured Creditor under any Finance Document in accordance with the terms thereof, in the case of (a), (b), (c) or (d) which:

(A)	breaches or contravenes any term of any Secured Hedging Agreement to which that Hedging Bank is a party; or
(B)	results in a potential event of default, event of default or termination event (in each case, however described) under any such Secured Hedging Agreement.

52.4	Consent to Security
	Subject to the terms of any specific consent agreed by it with the Security Trustee, each Hedging Bank that is a party to any Hedging Agreement with any Obligor:

52.4.1	consents to the grant by such Obligor of Security over all that Obligor’s rights and interests in such Hedging Agreement in favour of the Secured Creditors or, as the case may be, the Security Trustee (in its capacity as such); and
52.4.2	to the extent that such Security has been granted pursuant to a Security Document, acknowledges that it has received notice that each such Hedging Agreement to which it is a party is the subject of such Security.

53.	INFORMATION SHARING
53.1	Defaults

53.1.1	The First Lien Agent will promptly upon receiving written notice of any Event of Default under the First Lien Credit Agreement provide a copy of the same to the Second Lien Agent and the Security Trustee.
53.1.2	The Second Lien Agent will promptly upon receiving written notice of any Event of Default under the Second Lien Credit Agreement provide a copy of the same to the First Lien Agent and the Security Trustee.

53.2	Amounts of debt
	Each of the First Lien Agent, the Hedging Banks and the Second Lien Agent (each a, “Relevant Party”) will on request by any other Relevant Party from time to time notify such other Relevant Party of the details of the amount of the outstanding First Lien Debt, Hedging Debt or Second Lien Debt (as the case may be).
53.3	Other information
	Each Obligor authorises the Secured Creditors to disclose to each other all information (relating to that Obligor, its subsidiaries or related entities or any member of the Group) coming into the possession of any of them in connection with the Finance Documents.
54.	SUBROGATION
54.1	Subrogation

54.1.1	If any Prior Debt is wholly or partially paid out of any proceeds received on or account of the Subordinated Debt owing to one or more Subordinated Lenders, then the Subordinated Lenders will (pro rata to their respective interests in such Subordinated Debt) to that extent be subrogated to the Prior Debt so paid (and all securities and guarantees for that Prior Debt).
54.1.2	Any rights of subrogation so arising in favour of any Second Lien Lender must not be exercised by that Second Lien Lender before the First Lien Discharge Date without the consent of the First Lien Agent.
54.1.3	For the purposes of this Clause 54.1 (Subrogation):

(A)	“Prior Debt” means (in relation to the Second Lien Debt) the First Lien Debt and the Hedging Debt.
(B)	“Subordinated Debt” means (in relation to the First Lien Debt and the Hedging Debt) the Second Lien Debt.
(C)	“Subordinated Lender” means any Secured Creditor to whom any Subordinated Debt is owed.

54.2

First Lien Discharge Date

Following the First Lien Discharge Date, each First Lien Lender and Hedging Bank shall (subject to being indemnified to its reasonable satisfaction against any resulting costs, expenses and liabilities) take all such steps and provide all such assistance as the Second Lien Agent and/or the Security Trustee may reasonably request for the purposes of (i) ensuring that the Second Lien Lenders are entitled to exercise any rights of subrogation to which they may be entitled or (ii) otherwise ensuring that all the rights of the First Lien Lenders and the Hedging Banks under First Lien Documents and the Secured Hedging Agreements are assigned to and assumed by the Second Lien Lenders.

54.3	Non-subrogation
	Until both the Second Lien Discharge Date and the First Lien Discharge Date have occurred no Obligor may exercise any rights which it may have by reason of performance by it of its obligations under the Finance Documents:

54.3.1	to be indemnified by any other Obligor;
54.3.2	to claim any contribution from any guarantor of any Obligor’s obligations under the Finance Documents;
54.3.3	to take the benefit (in whole or in part and whether by way of subrogation or otherwise) of any rights of any Secured Creditor under the Finance Documents or of any other guarantee or security taken pursuant to, or in connection with, the Finance Documents by any Secured Creditor;
54.3.4	to claim, rank, prove or vote as a creditor of any other Obligor in competition with any Secured Creditor; and/or
54.3.5	to receive, claim or have the benefit of any payment, distribution or security from or on account of any other Obligor, or exercise any right of set-off against any other Obligor.

55.	PROTECTION OF SUBORDINATION
55.1	Continuing subordination
	The subordination of any Debt to any other Debt (a “prior ranking Debt”) provided for in this Agreement constitutes a continuing subordination and will extend to the ultimate balance of the prior ranking Debt regardless of any intermediate payment or discharge of such prior ranking Debt in whole or in part.
55.2	Waiver of defences
	The subordination of any Debt provided for in this Agreement and the obligations of each Party under this Agreement relating thereto will not be affected by an act, omission, matter or thing which but for this Clause 55.2, would operate to reduce, release or prejudice the subordination or any of those obligations (without limitation and whether known to any Party) including:

55.2.1	any time, waiver or consent granted to, or composition with, any Obligor or other person;
55.2.2	the release of any other Obligor or any other person under the terms of any composition or arrangement with any creditor of any Obligor or other person;
55.2.3	the taking, variation, compromise, exchange, renewal or release of, or refusal or neglect to perfect, take up or enforce, any rights against, or security over assets of, any Obligor or other person or any non-presentation or non-observance of any formality or other requirement in respect of any instrument or any failure to realise the full value of any security;
55.2.4	any incapacity or lack of power, authority or legal personality of or dissolution or change in the members or status of an Obligor or any other person;
55.2.5	any amendment, novation, supplement, extension, restatement (however fundamental or whether or not more onerous) or replacement of any Finance Document or any other

	document or security including any change in the purpose of any extension of, or any increase in any facility or the addition of any new facility under any Finance Document or other document or security;
55.2.6	any unenforceability, illegality or invalidity of any obligation of any person under any Finance Document or any other document or security; or
55.2.7	any insolvency or similar proceedings.

56.	CHANGES TO THE PARTIES
56.1	Successors and assigns
	This Agreement is binding on the successors and assigns of the Parties.
56.2	Obligors
	No Obligor may assign or transfer any of its rights (if any) or obligations under this Agreement.
56.3	New Obligors

56.3.1	The Company shall ensure that each relevant member of the Group accedes, and becomes a Party, to this Agreement as an “Obligor” by executing the Accession Instrument(s) and delivering the same (together with such other documents as the Security Trustee may reasonably request) to the Security Trustee.
56.3.2	For these purposes, a “relevant member of the Group” means each member of the Group which is not already an Obligor which (a) becomes a guarantor, borrower or an obligor under or in relation to a Finance Document (other than this Agreement) or (b) guarantees or otherwise becomes liable for any Debt or grants Security for any Debt.
56.3.3	Each of the Obligors shall ensure that:

(A)	unless the Majority Second Lien Lenders otherwise agree, each Transaction Party (as defined in the First Lien Credit Agreement) is also a Transaction Party (as defined in the Second Lien Credit Agreement); and
(B)	each Transaction Party (as defined in the Second Lien Credit Agreement) is also a Transaction Party (as defined in the First Lien Credit Agreement).

56.4 Secured Creditors

56.4.1 No First Lien Lender or Second Lien Lender will assign, transfer, novate or dispose of, or create or permit to subsist any Security over:

(A)	any of the Debt owing to it, any proceeds of such Debt or any of its interests in such Debt or proceeds; or
(B)	its rights or obligations under any of the Finance Documents,

(in each case) to or in favour of any person unless and until that person accedes, and becomes a Party, to this Agreement as a “First Lien Lender” or “Second Lien Lender” (as the case may be) by executing an Accession Instrument and delivering the same (together with all such other documents as the Security Trustee may reasonably request) to the Security Trustee and then only in accordance with the terms of those Finance Documents.

56.4.2

Subject to Clause 56.4.3, no Hedging Bank will assign, transfer, novate or dispose of, or create or permit to subsist any Security over:

(A)	any of the Hedging Debt owing to it, any proceeds of such Hedging Debt or any of its interests in such Hedging Debt or proceeds; or
(B)	its rights or obligations under any of the Finance Documents,

	(in each case) to or in favour of any person other than another Hedging Bank and then only in accordance with the terms of those Finance Documents.
56.4.3	A Hedging Bank may transfer its interests in any Secured Hedging Agreement to another person that is not a Hedging Bank (a “transferee”) in accordance with the terms of the Finance Documents provided that:

(A)	such transfer is effected upon terms which ensure that following the relevant transfer, neither the transferee nor the Hedging Bank shall have the benefit of any Security, guarantee or other financial accommodation constituted by any Finance Document with respect to the interests so transferred; and
(B)	such Hedging Bank and such transferee provide such releases and confirmations and other evidence as the Security Trustee may require (acting reasonably) to satisfy itself that the transfer has been effected on such terms.

56.5	Accession of Hedging Banks
	A Lender (as defined in the First Lien Credit Agreement) may, at any time, request that any of its Affiliates that has entered, or is to enter, into a Hedging Agreement with an Obligor in accordance with the Finance Documents be given the benefit of the Security constituted by the Security Documents by becoming a Hedging Bank. Following any such request (which shall be submitted to the First Lien Agent and the Security Trustee), the relevant Affiliate shall accede, and become a party, to the Finance Documents as a Hedging Bank by executing an Accession Instrument and delivering the same (together with all such other documents as the Security Trustee may reasonably request) to the Security Trustee.
56.6	Agents and other administrative parties

56.6.1	Neither the First Lien Agent nor the Second Lien Agent may resign or be removed except as provided for in the First Lien Credit Agreement or the Second Lien Credit Agreement (as the case may be) and only if the replacement First Lien Agent or Second Lien Agent accedes, and becomes a Party, to this Agreement as a “First Lien Agent” or, as the case may be, a “Second Lien Agent” by executing an Accession Instrument and delivering the same (together with such other documents as the Security Trustee may reasonably request) to the Security Trustee.
56.6.2	No Administrative Finance Party (as defined in the First Lien Credit Agreement but excluding, for these purposes, the First Lien Agent and the Security Trustee) may resign or be removed except as provided for in the First Lien Credit Agreement and (in the case of any such replacement Administrative Finance Party that is not already a First Lien Lender or not becoming a First Lien Lender pursuant to Clause 56.4 (Secured Creditors)) only if the replacement Administrative Finance Party accedes, and becomes a Party, to this Agreement as a “First Lien Lender” by executing an Accession Instrument and delivering the same (together with such other documents as the Security Trustee may reasonably request) to the Security Trustee.
56.6.3	No Administrative Finance Party (as defined in the Second Lien Credit Agreement but excluding, for these purposes, the Second Lien Agent and the Security Trustee) may resign or be removed except as provided for in the Second Lien Credit Agreement and (in the case of any such replacement Administrative Finance Party that is not already a

Second Lien Lender or not becoming a Second Lien Lender pursuant to Clause 56.4 (Secured Creditors)) only if the replacement Administrative Finance Party accedes, and becomes a Party, to this Agreement as a “Second Lien Lender” by executing an Accession Instrument and delivering the same (together with such other documents as the Security Trustee may reasonably request) to the Security Trustee.

56.7	Authorisations
	Each existing Party authorises the Security Trustee to execute each Accession Instrument delivered to the Security Trustee under this Clause 56 (Changes to the Parties) on such Party’s behalf in order that such Accession Instrument may be supplemental to this Agreement and be binding on, and enure to the benefit of, all the Parties.
57.	GENERAL
57.1	Preservation of debt

57.1.1	Notwithstanding any term of this Agreement postponing, subordinating or preventing the payment of any Debt, as between the Obligors and the Secured Creditor to whom such Debt is owed, that Debt shall remain owing and payable (and interest and/or default interest shall continue to accrue) in accordance with the terms of the relevant Finance Documents relating to such Debt.
57.1.2	No failure to exercise, nor any delay in exercising, on the part of any Secured Creditor, any right or remedy under the Finance Documents by reason of the operation of this Agreement shall operate as a waiver of such right or remedy.

57.2 Status of the Obligors

57.2.1

Each of the Obligors joins in this Agreement for the purpose of acknowledging the priorities, rights and obligations set out in this Agreement and undertakes with each of the other Parties to observe the provisions of this Agreement at all times and not in any way to prejudice or affect the enforcement of such provisions or do or suffer anything within its reasonable control which would be inconsistent with the terms of this Agreement.

57.2.2

None of the Obligors shall have any rights under this Agreement (other than under Clause 51.3.5 (Intercreditor Agreement) and any related provisions necessary to give effect to such rights) and none of the undertakings given by the Secured Creditors in this Agreement are given (or shall be deemed to have been given) to, or for the benefit of, the Obligors.

58.	SECOND LIEN BUY-OUT
58.1	Option to purchase

58.1.1	At any time on or after the First Lien Enforcement Date and subject to Clause 58.1.2, the Second Lien Lenders may issue a notice (a “Buy-out Notice”) specifying their intention to purchase all (and not part only) of the outstanding First Lien Debt and the date (the “Purchase Date”) on which such purchase is to be effected.
58.1.2	The Second Lien Lenders shall not issue a Buy-out Notice unless they issue a Buy-out Notice under Clause 59.1 at the same time.

58.1.3 The Purchase Date specified in any Buy-out Notice must be a Business Day falling no less than 10 Business Days and no more 15 Business Days after the date of issue of such Buy-out Notice.

58.2	Purchase Date
	On the Purchase Date:

58.2.1	the Second Lien Lenders shall pay to the First Lien Agent in cash and in the currency in which the First Lien Debt is denominated, an amount (the “Purchase Amount”) determined by the First Lien Agent (acting reasonably) to be equal to the outstanding First Lien Debt (including all accrued interest, fees, expenses and any Break Costs) on such Purchase Date;
58.2.2	the Second Lien Lenders shall take all such other steps as the First Lien Agent (acting reasonably) may require for the purposes of ensuring that on and from the Purchase Date none of the First Lien Lenders will have any liability (actual or contingent) in relation to any outstanding Letters of Credit or under any First Lien Document;
58.2.3	the First Lien Lenders shall, subject to payment to them of the Purchase Amount, the completion of all relevant steps in accordance with Clause 58.2.2, and the provision of an indemnity in accordance with Clause 58.4 (Indemnity against claw back) transfer the First Lien Debt (and all their rights and obligations relating thereto) in accordance with the procedure for transfer provided for in clause 26.5 (Procedure for transfer) of the First Lien Credit Agreement or by such other means as the First Lien Agent and the Second Lien Agent may otherwise agree;
58.2.4	the Obligors shall take all such steps as the First Lien Agent and the Second Lien Agent (each, acting reasonably) may require for the purposes of effecting such transfer;
58.2.5	each First Lien Lender shall be deemed to have represented and warranted to the Second Lien Lenders that (i) it is the owner of the beneficial interest in all the rights and interests under the First Lien Documents purported to be assigned or transferred by it by such transfer; and (ii) it has taken all necessary corporate action to authorise such transfer.

58.3	Protection of First Lien Lenders
	Save as provided for in Clause 58.2.5 (Purchase Date), any transfer of the First Lien Debt pursuant to this Clause 58 (Second Lien buy-out) shall be without recourse to, or representation or warranty from, the First Lien Lenders and the terms of clause 26 (Changes to the Lenders) of the First Lien Credit Agreement relating to the protection of the First Lien Lenders with respect to any assignment or transfer of their rights or rights and obligations which is effected thereunder shall apply to any such transfer of the First Lien Debt pursuant to this Clause 58 (Second Lien buy-out).
58.4	Indemnity against claw back

58.4.1 Subject to Clause 58.4.2, the Second Lien Lenders must provide, or procure the provision of, an indemnity (on terms, and from a person, satisfactory to the Majority First Lien Lenders) to each of the First Lien Lenders against any and all costs, losses, liabilities, expenses and payments which may be incurred or made by such First Lien Lender as a result of all or any of the Purchase Amount being required, or being alleged to be required, to be paid back by, or clawed back from, such First Lien Lender for any reason.

58.4.2 Any indemnity provided pursuant to Clause 58.4.1 shall not extend to any costs, losses, liabilities, expenses and payments which could not have been recovered by the relevant First Lien Lender had the First Lien Debt not been transferred pursuant to this Clause 58 (Second Lien buy-out).

58.5	Protection of Hedging Banks
	Notwithstanding any other provision in this Agreement, each Hedging Bank shall continue to be a “Hedging Bank” for the purposes of the Finance Documents and to be bound by, and benefit from, the terms of the Finance Documents in its capacity as Hedging Bank notwithstanding any transfer of the First Lien Debt pursuant to this Clause 58 (Second Lien Buy-out) and notwithstanding that such Hedging Bank may not be a First Lien Lender following the transfer of such First Lien Debt.
59.	SECOND LIEN BUY-OUT OF HEDGES
59.1	Option to purchase

59.1.1	At any time on or after the First Lien Enforcement Date, the Second Lien Lenders may issue a notice (a “Buy-out Notice”) to each of the Hedging Banks specifying their intention to purchase all (and not part only) of the outstanding Hedging Termination Payments and the date (the “Purchase Date”) on which such purchase is to be effected.
59.1.2	The Purchase Date specified in any Buy-out Notice must be a Business Day falling no less than 10 Business Days and no more 15 Business Days after the date of issue of such Buy-out Notice.

59.2 Purchase Date

On the Purchase Date:

59.2.1	the Second Lien Lenders shall pay to each Hedging Bank in cash and in the currency in which the Hedging Termination Payment is denominated, an amount (the “Purchase Amount”) equal to the outstanding Hedging Termination Payment due to that Hedging Bank (including all accrued interest) on such Purchase Date;
59.2.2	the Hedging Banks shall, subject to payment to them of the Purchase Amount and the provision of an indemnity in accordance with Clause 59.4 (Indemnity against claw back) transfer all their rights and obligations relating the Hedging Termination Payments by such means as the the Second Lien Agent may reasonably require;
59.2.3	the Obligors shall take all such steps as the Hedging Banks and the Second Lien Agent (each, acting reasonably) may require for the purposes of effecting such transfer;
59.2.4	each Hedging Bank shall be deemed to have represented and warranted to the Second Lien Lenders that (i) it is the owner of the beneficial interest in all the rights and interests under the Hedging Termination Payment purported to be assigned or transferred by it; and (ii) it has taken all necessary corporate action to authorise such transfer.

59.3

Protection of Hedging Banks

Save as provided for in Clause 59.2.4 (Purchase Date), any transfer of rights and obligations relating to a Hedging Termination Payment pursuant to this Clause 16 (Second Lien buy-out of Hedges) shall be without recourse to, or representation or warranty from, the Hedging Banks and the terms of clause 26 (Changes to the Lenders) of the First Lien Credit Agreement relating to the protection of the First Lien Lenders with respect to any assignment or transfer of their rights or

	rights and obligations which is effected thereunder shall apply to any such transfer pursuant to this Clause 59 (Second Lien buy-out of Hedges).
59.4	Indemnity against claw back

59.4.1

Subject to Clause 59.4.2, the Second Lien Lenders must provide, or procure the provision of, an indemnity (on terms, and from a person, satisfactory to the Hedging Banks, acting reasonably) to each of the Hedging Banks against any and all costs, losses, liabilities, expenses and payments which may be incurred or made by such Hedging Bank as a result of all or any of the Purchase Amount being required, or being alleged to be required, to be paid back by, or clawed back from, such Hedging Bank for any reason.

59.4.2

Any indemnity provided pursuant to Clause 59.4.1 shall not extend to any costs, losses, liabilities, expenses and payments which could not have been recovered by the relevant Hedging Bank had the rights and obligations relating to the Hedging Termination Payment not been transferred pursuant to this Clause 59 (Second Lien buy-out of Hedges).

60.	FIRST LIEN BUY-OUT
60.1	Option to purchase

60.1.1	At any time after the issue of any notice by the Second Lien Agent under Clause 49.4.1(B) (Action by Second Lien Lenders), the First Lien Lenders may issue a notice (a “Buy-out Notice”) specifying their intention to purchase all (and not part only) of the outstanding Second Lien Debt and the date (the “Purchase Date”) on which such purchase is to be effected.
60.1.2	The Purchase Date specified in any Buy-out Notice must be a Business Day falling no less than 10 Business Days and no more 15 Business Days after the date of issue of such Buy-out Notice.

60.2	Purchase Date
	On the Purchase Date:

60.2.1	the First Lien Lenders shall pay to the Second Lien Agent in cash and in the currency in which the Second Lien Debt is denominated, an amount (the “Purchase Amount”) determined by the Second Lien Agent (acting reasonably) to be equal to the outstanding Second Lien Debt (including all accrued interest, fees, expenses and any Break Costs) on such Purchase Date;
60.2.2	the First Lien Lenders shall take all such other steps as the Second Lien Agent (acting reasonably) may require for the purposes of ensuring that on and from the Purchase Date none of the Second Lien Lenders will have any liability (actual or contingent) under any Second Lien Document;
60.2.3	the Second Lien Lenders shall, subject to payment to them of the Purchase Amount, the completion of all relevant steps in accordance with Clause 60.2.2, and the provision of an indemnity in accordance with Clause 60.4 (Indemnity against claw back) transfer the Second Lien Debt (and all their rights and obligations relating thereto) in accordance with the procedure for transfer provided for in clause 24.5 (Procedure for transfer) of the Second Lien Credit Agreement or by such other means as the First Lien Agent and the Second Lien Agent may otherwise agree;

60.2.4	the Obligors shall take all such steps as the First Lien Agent and the Second Lien Agent (each, acting reasonably) may require for the purposes of effecting such transfer;
60.2.5	each Second Lien Lender shall be deemed to have represented and warranted to the First Lien Lenders that (i) it is the owner of the beneficial interest in all the rights and interests under the Second Lien Documents purported to be assigned or transferred by it by such transfer; and (ii) it has taken all necessary corporate action to authorise such transfer.

60.3	Protection of Second Lien Lenders
	Save as provided for in Clause 60.2.5 (Purchase Date), any transfer of the Second Lien Debt pursuant to this Clause 60 (First Lien buy-out) shall be without recourse to, or representation or warranty from, the Second Lien Lenders and the terms of clause 24 (Changes to the Lenders) of the Second Lien Credit Agreement relating to the protection of the Second Lien Lenders with respect to any assignment or transfer of their rights or rights and obligations which is effected thereunder shall apply to any such transfer of the Second Lien Debt pursuant to this Clause 60 (First Lien buy-out).
60.4	Indemnity against claw back

60.4.1

Subject to Clause 60.4.2, the First Lien Lenders must provide, or procure the provision of, an indemnity (on terms, and from a person, satisfactory to the Majority Second Lien Lenders) to each of the Second Lien Lenders against any and all costs, losses, liabilities, expenses and payments which may be incurred or made by such Second Lien Lender as a result of all or any of the Purchase Amount being required, or being alleged to be required, to be paid back by, or clawed back from, such Second Lien Lender for any reason.

60.4.2

Any indemnity provided pursuant to Clause 60.4.1 shall not extend to any costs, losses, liabilities, expenses and payments which could not have been recovered by the relevant Second Lien Lender had the Second Lien Debt not been transferred pursuant to this Clause 60 (First Lien buy-out).

61.	THE SECURITY TRUSTEE
61.1	Appointment of the Security Trustee

61.1.1 Each other Secured Creditor:

(A)	appoints the Security Trustee to act as its agent and trustee in connection with the Finance Documents;
(B)	irrevocably authorises the Security Trustee (by itself or by such persons as it may nominate) on its behalf to:

(1)	enter into each Finance Document to which it is a party;
(2)	exercise the rights, powers, authorities and discretions specifically given to the Security Trustee under or in connection with the Finance Documents together with any other incidental rights, powers, authorities and discretions or any other incidental rights, powers, authorities and discretions necessary to give effect to the trusts hereby created; and
(3)	enforce any Security granted by the Security Documents as trustee (or as otherwise provided) on its behalf, subject always to the terms of the Finance Documents.

61.1.2	The powers conferred upon the Security Trustee by the Finance Documents shall be in addition to any powers which may from time to time be vested in trustees by the general law.
61.1.3	If there is any conflict between the provisions of this Agreement and any Security Documents with regard to instructions to or the matters affecting the Security Trustee, this Agreement will prevail.
61.1.4	Each other Secured Creditor acknowledges that the concept of trust as known in common law jurisdictions is not known as such in France.

61.2 Trust

61.2.1 The Security Trustee shall hold the benefits of the Finance Documents in its capacity as Security Trustee on trust for (to the extent such benefits are capable of being secured in their favour) the Secured Creditors. Save as expressly specified in any Finance Document, the Security Trustee:

(A)	shall not be liable to any Party for any breach by any other Party of any Finance Document;
(B)	shall have only those duties which are expressly specified in the Finance Documents;
(C)	will apply all payments and other benefits received by it under the Finance Documents in accordance with Clause 50 (Cascade); and
(D)	shall exercise its rights, powers and duties under the Security Documents and/or this Agreement for the benefit of the Secured Creditors.

61.2.2	Section 1 of the Trustee Act 2000 shall not apply to any function of the Security Trustee under or in connection with the Finance Documents provided that nothing in this Agreement shall exempt the Security Trustee from any liability for gross negligence or wilful misconduct.
61.2.3	Save as set out in Clause 61.2.1, the Security Trustee’s duties under the Finance Documents are of a mechanical and administrative nature. Nothing in the Finance Documents shall constitute a partnership between any Party and the Security Trustee.
61.2.4	The perpetuity period for the security trust established in relation to the Finance Documents shall be eighty years from the date of this Agreement.

61.3 Resignation of Security Trustee

61.3.1	The Security Trustee may resign at any time and appoint an Affiliate acting through an office in the United Kingdom or Paris in its place by giving notice to the other Secured Creditors and the Company.
61.3.2	Alternatively the Security Trustee may resign by giving notice to the other Secured Creditors and the Company, in which case the Relevant Group (after consultation with the Company) may appoint a successor Security Trustee.
61.3.3	If the Relevant Group has not appointed a successor Security Trustee in accordance with Clause 61.3.2 within 30 days after notice of resignation was given, the Security Trustee (after consultation with the Company) may appoint a successor Security Trustee (acting through an office in the United Kingdom or Paris).
61.3.4	The resignation of the retiring Security Trustee and the appointment of any successor Security Trustee shall both become effective upon:

(A)

the successor Security Trustee (i) notifying all the Parties that it accepts such appointment (ii) executing and delivering to the First Lien Agent and Second Lien Agent duly completed deed(s) or instrument(s) of accession in such form as the Relevant Group may require and taking all such other steps as may be necessary to ensure that it accedes, and becomes a party, to the relevant Finance Documents, as Security Trustee; and

(B)

each of the First Lien Agent and the Second Lien Agent (each, acting reasonably) confirms it has received acceptable advice to the effect that all of the Security Documents provide for enforceable Security in favour of the successor Security Trustee and the Secured Creditors,

	whereupon the retiring Security Trustee shall be discharged from any further obligation in respect of the Finance Documents but shall remain entitled to the benefit of this Clause 61 (Security Trustee). Its successor and each of the other Parties shall have the same rights and obligations amongst themselves as they would have had if such successor had been an original Party.
61.3.5	The Parties shall take such action as the retiring Security Trustee and the Relevant Group may consider necessary in order that the Security Documents shall provide for perfected and enforceable Security in favour of any successor Security Trustee and the Secured Creditors.
61.3.6	The retiring Security Trustee shall, at its own cost (unless required to retire pursuant to Clause 61.3.7, in which case the costs shall be borne by the Company), make available to the successor Security Trustee such documents and records and provide such assistance as the successor may reasonably request for the purposes of performing its functions as Security Trustee under the Finance Documents.
61.3.7	After consultation with the Company, the Relevant Group may, by notice to the Security Trustee, require it to resign in accordance with Clause 61.3.2 above. In this event, the Security Trustee shall resign in accordance with Clause 61.3.2 above.

61.4 Additional trustees

61.4.1

The Security Trustee may, upon giving prior notice to the other Secured Creditors, appoint any person established or resident in any jurisdiction (whether a trust corporation or not) to act either as a separate trustee or as a co-trustee jointly with the Security Trustee if the Security Trustee considers such appointment to be in the interests of the Secured Creditors.

61.4.2

Any such additional trustee shall have such trusts, powers, obligations, authorities and discretions (not exceeding those conferred on the Security Trustee by the Finance Documents) and remuneration as shall be conferred or imposed by the instrument of appointment. The Security Trustee shall have power in like manner to remove any such person. The Company shall indemnify such additional trustee as though it were the Security Trustee in accordance with Clause 61.5 (Remuneration and indemnity). The Security Trustee shall not be under any obligation to supervise the proceedings or acts of any such delegate or sub-delegate or be in any way responsible for any liability incurred by reason of any misconduct or default on the part of any such delegate or sub-delegate.

61.5 Remuneration and indemnity

61.5.1 For the benefit of the Security Trustee, nothing in this Clause 61 (Security Trustee) shall prejudice any right of indemnity by law given to trustees.

61.5.2 The Company agrees to indemnify, on demand, the Security Trustee and any receiver, attorney, agent or other person appointed by the Security Trustee in accordance with the Finance Documents for any and all claims, liabilities, costs, fees, charges, losses and expenses which may be incurred by or asserted against the Security Trustee or any such person in any way relating to or arising out of:

(A)	its execution or purported execution of any of its trusts, powers, authorities and discretions under the Finance Documents; or
(B)	performing its duties and functions in such capacity; or
(C)	any action taken or omitted by the Security Trustee or any such person under the Finance Documents,

	except to the extent arising directly from the Security Trustee’s or any such person’s gross negligence or wilful misconduct.
61.5.3	The Security Trustee may indemnify itself and each other person referred to in Clause 61.5.2 out of the assets over which Security is granted pursuant to the Security Documents against all such claims, liabilities, costs, fees, charges, losses and expenses referred to in Clause 61.5.2.
61.5.4	The Security Trustee shall be entitled to such remuneration as it may agree from time to time with the Company.
61.5.5	Without prejudice to Clause 61.5.2, each Secured Creditor shall (in proportion to its share of the Debt) indemnify the Security Trustee, within three Business Days of demand, against any cost, loss or liability incurred by the Security Trustee (otherwise than by reason of the Security Trustee’s gross negligence or wilful misconduct) in acting as Security Trustee under or in connection with the Finance Documents (unless the Security Trustee has been reimbursed for the same by any Obligor). The Obligors shall forthwith on demand reimburse each Secured Creditor for any payments made by it under this Clause 61.5.5.

61.6 Exclusion of liability

61.6.1	Without limiting Clause 61.6.2, the Security Trustee will not be liable for any action taken by it under or in connection with any Finance Document, unless directly caused by its gross negligence or wilful misconduct.
61.6.2	No Party (other than the Security Trustee) may take any proceedings against any officer, employee or agent of the Security Trustee in respect of any claim it might have against the Security Trustee or in respect of any act or omission of any kind by that officer, employee or agent in relation to any Finance Document and any officer, employee or agent of the Security Trustee may rely on this Clause.
61.6.3	The Security Trustee will not be liable for any delay (or any related consequences) in crediting an account with an amount required under the Finance Documents to be paid by the Security Trustee if the Security Trustee has taken all necessary steps as soon as reasonably practicable to comply with the regulations or operating procedures of any recognised clearing or settlement system used by the Security Trustee for that purpose.
61.6.4	Nothing in this Agreement shall oblige the Security Trustee to carry out any “know your customer” or other checks in relation to any person on behalf of any Secured Creditor and each Secured Creditor confirms to the Security Trustee that it is solely responsible for any such checks that it is required to carry out and that it may not rely on any statement in relation to such checks made by the Security Trustee.

61.7 Instructions

61.7.1	Unless a contrary indication appears in the Finance Documents, the Security Trustee shall (A) exercise any right, power, authority or discretion vested in it as Security Trustee in accordance with any instructions given to it by the Instructing Group (or, if so instructed by the Instructing Group, refrain from exercising any right, power, authority or discretion vested in it as Security Trustee) and (B) not be liable for any act (or omission) if it acts (or refrains from taking any action) in accordance with an instruction of the Instructing Group. This Clause 61.7.1 shall not require the Security Trustee to act in accordance with the instructions of the Instructing Group or any person in respect of those powers, authorities and discretions granted to the Security Trustee pursuant to Clauses 61.4 (Additional trustees), 61.5 (Remuneration and indemnity), 61.15.1, 61.15.3, 61.15.4 (Security Trustee’s functions) and 61.16 (Legal restrictions and confidentiality).
61.7.2	Unless a contrary indication appears in the Finance Documents, any instructions given by the Instructing Group, shall be binding on all the Secured Creditors.
61.7.3	The Security Trustee may refrain from acting in accordance with the instructions of the Instructing Group until it has received such security as it may require for any cost, loss or liability (together with any associated VAT) which it may incur in complying with the instructions.
61.7.4	In the absence of instructions from the Instructing Group, the Security Trustee may act (or refrain from taking action) as it considers to be in the best interests of the Secured Creditors.
61.7.5	The Security Trustee is not authorised to act on behalf of a Secured Creditor (without first obtaining that Secured Creditor’s consent) in any legal or arbitration proceedings relating to any Finance Document.

61.8 Rights and discretions of the Security Trustee

61.8.1 The Security Trustee may rely on:

(A)	any representation, notice or document believed by it to be genuine, correct and appropriately authorised; and
(B)	any statement made by a director, authorised signatory or employee of any person regarding any matters which may reasonably be assumed to be within his knowledge or within his power to verify.

61.8.2 The Security Trustee may assume (unless it has received notice to the contrary in its capacity as Security Trustee) that:

(A)	no Default (whether under the First Lien Credit Agreement or the Second Lien Credit Agreement) has occurred (unless it has actual knowledge of such Default);
(B)	any right, power, authority or discretion vested in any Party, the Majority First Lien Lenders or the Majority Second Lien Lenders has not been exercised; and
(C)	any notice or request made by the Company is made on behalf of and with the consent and knowledge of all the Obligors.

61.8.3 The Security Trustee may engage, pay for and rely on the advice or services of any lawyers, accountants, surveyors or other experts.

61.8.4 The Security Trustee may act in relation to the Finance Documents through its personnel and agents.

61.9 Information

61.9.1	The Security Trustee has no duty (in the absence of a specific provision in any Finance Document) to provide any Party with any credit or other information relating to the business, assets or financial condition of any Obligor or any other person whenever coming into its possession.
61.9.2	Except where a Finance Document specifically provides otherwise, the Security Trustee is not obliged to check the adequacy, accuracy or completeness of any document it forwards to another Party.
61.9.3	The Security Trustee shall not be liable or responsible to any other Secured Creditor for the adequacy, accuracy and/or completeness of any information (whether oral or written) supplied by the Security Trustee, an Obligor or any other person given in or in connection with any Finance Document or the Information Memorandum.

61.10	Responsibility for documentation
	The Security Trustee shall not be liable or responsible:

61.10.1	for the legality, validity, effectiveness, adequacy or enforceability of any Finance Document or any other agreement, arrangement or document entered into, made or executed in anticipation of or in connection with any Finance Document;
61.10.2	for any failure to give notice to any third party or to register, file or record (or any defect in such registration, filing or recording) any Security created pursuant to any Security Document, or effect, procure the registration of or otherwise protect the floating charge or any other such Security created by or pursuant to the Security Documents under the Land Registration Act 1925 or any other registration laws in England or any other jurisdiction;
61.10.3	to obtain any licence, consent or other authority for the creation of any such Security;
61.10.4	for any failure, omission, or defect in perfecting or protecting the Security constituted by the Security Documents, either in England and Wales or in any other jurisdiction; or
61.10.5	for the financial condition of any Obligor.

61.11	Title
	The Security Trustee may accept without enquiry such title as any Obligor may have to the property over which Security is intended to be created by any Security Document.
61.12	Investments
	All moneys which are received by the Security Trustee in its capacity as trustee or otherwise may be invested in the name of or under the control of the Security Trustee in any investment for the time being authorised by English law for the investment by trustees of trust money or in any other investments which may be selected by the Security Trustee. Additionally, the same may be placed on deposit in the name of or under the control of the Security Trustee at such bank or institution (including the Security Trustee) and upon such terms as the Security Trustee may think fit.

61.13	Tax
	The Security Trustee shall have no responsibility whatsoever to any Secured Creditor as regards any deficiency which might arise because the Security Trustee is subject to any Tax or withholding from any payment made by it under the Finance Documents.
61.14	Receivers’ indemnity
	In no circumstances shall the Security Trustee itself be obliged to give an indemnity to any receiver who requires an indemnity as a condition of appointment.
61.15	Security Trustee’s functions

61.15.1 The Security Trustee shall:

(A)	not be under any obligation to hold any title deeds, Finance Documents or any other documents in connection with the assets charged by any Security Document in its own possession or to take any steps to protect or preserve the same (and the Security Trustee may permit the Obligors to retain any title deeds and other documents if it considers such course of action to be appropriate);
(B)	without prejudice to Clause 61.15.1(A), be at liberty to hold the Finance Documents and any other documents relating thereto or to deposit them in any part of the world with any bank or company whose business includes undertaking the safe custody of documents or firm of lawyers considered by the Security Trustee to be of good repute and the Security Trustee shall not be responsible for or be required to insure against any liability incurred in connection with any such holding or deposit and may pay all sums required to be paid on account of or in respect of any such deposit;
(C)	not be bound to give notice to any person of the execution of any documents comprised or referred to in the Finance Documents or of any other matter in any way relating to the Finance Documents or to take any steps to ascertain whether any default under any Finance Document has happened or whether any Party has breached any of its obligations under any Finance Document or whether any right, power, discretion or remedy has or may become exercisable by the Security Trustee and the Security Trustee shall be entitled to assume that no such default has happened and that each Party is observing and performing all its obligations under any Finance Document and that no such right, power, discretion or remedy has or may become exercisable;
(D)	as soon as reasonably practicable following receipt of the same, notify the First Lien Agent and the Second Lien Agent of any request received by it to exercise any power, authority or discretion under this Agreement or any Finance Document or to form any opinion;
(E)	promptly provide the First Lien Agent and the Second Lien Agent of copies of any notice received by it from any Party (i) describing the occurrence of any Default (as defined in the First Lien Credit Agreement or the Second Lien Credit Agreement) and (ii) stating that the circumstance described is a Default (so defined); and
(F)	be entitled to treat each Secured Creditor as a Secured Creditor entitled to payments under this Agreement unless it has received not less than five Business Days’ prior notice from that Secured Creditor to the contrary in accordance with the terms of this Agreement.

61.15.2	Any consent or approval given by the Security Trustee for the purposes of the Finance Documents may be given on such terms and subject to such conditions (if any) as the Security Trustee thinks fit.
61.15.3	Any trustee of any Security Document being a lawyer, accountant, broker or other person engaged in any profession or business shall be entitled to charge and be paid all usual professional and other charges for business transacted and acts done by him or his firm in connection with the trusts of the Security Documents and also his reasonable charges in addition to disbursements for all other work and business done and all time spent by him or his firm in connection with matters arising in connection with his trusteeship.
61.15.4	The Security Trustee may in the conduct of the trusts instead of acting personally employ and pay an agent (whether being a lawyer or other professional person) to transact or conduct, or concur in transacting or conducting, any business and to do, or concur in doing, all acts required to be done in connection with the Finance Documents. The Security Trustee shall not be in any way responsible for any liability incurred by reason of any misconduct or default on the part of any such agent or be bound to supervise the proceedings or acts of any such agent.

61.16 Legal restrictions and confidentiality

61.16.1	Notwithstanding any other provision of any Finance Document to the contrary, the Security Trustee is not obliged to do or omit to do anything if it would or might in its reasonable opinion constitute a breach of any law or regulation or a breach of a fiduciary duty or duty of confidentiality.
61.16.2	The relevant division or department through which the Security Trustee acts shall be treated as a separate entity from any other of the Security Trustee’s divisions or departments.
61.16.3	If information is received by another division or department of the Security Trustee, it may be treated as confidential to that relevant division or department and the Security Trustee shall not be deemed to have notice of it.

61.17

Credit appraisal by the Secured Creditors

Without affecting the responsibility of any Obligor for information supplied by it or on its behalf in connection with any Finance Document, each Secured Creditor confirms to the Security Trustee that it has been, and will continue to be, solely responsible for making its own independent appraisal and investigation of all risks arising under or in connection with any Finance Document including but not limited to:

61.17.1	the financial condition, status and nature of each Obligor and each other member of the Group;
61.17.2	the legality, validity, effectiveness, adequacy or enforceability of any Finance Document and any other agreement, arrangement or document entered into, made or executed in anticipation of, under or in connection with any Finance Document;
61.17.3	whether that Secured Creditor has recourse, and the nature and extent of that recourse, against any Party or any of its respective assets under or in connection with any Finance Document, the transactions contemplated by the Finance Documents or any other agreement, arrangement or document entered into, made or executed in anticipation of, under or in connection with any Finance Document; and

61.17.4 the adequacy, accuracy and/or completeness of the Information Memorandum and any other information provided by the Security Trustee, any other Party or by any other person under or in connection with any Finance Document, the transactions contemplated by the Finance Documents or any other agreement, arrangement or document entered into, made or executed in anticipation of, under or in connection with any Finance Document.

61.18	Business with the Group
	The Security Trustee may accept deposits from, lend money to and generally engage in any kind of banking or other business with any Obligor or any member of the Group or any Non-Recourse Subsidiary.
61.19	Enforcement
	The Secured Creditors shall not have any independent power to enforce any of the Security Documents or to exercise any rights, discretions or powers to grant any consents or releases under or pursuant to the Security Documents or otherwise have direct recourse to the Security constituted by any of the Security Documents except through the Security Trustee.
61.20	Release of Security
	The Security Trustee may release any Security over any asset the subject of the Security Documents in accordance with the terms of any such Security Document or if:

61.20.1	the asset is disposed of in compliance with the First Lien Documents; or
61.20.2	the asset is disposed of by any receiver or other person in accordance with the powers granted under the Security Documents.

61.21 Insolvency Events

61.21.1	For the purposes of this Agreement, “Insolvency Event” means any the circumstances or events described in clause 25.7 (Insolvency proceedings), clause 25.8 (Enforcement of security) or clause 25.9 (Creditor’s process) of the First Lien Credit Agreement or any other circumstance or event analogous to any of the foregoing.
61.21.2	If any Insolvency Event occurs in relation to any Obligor, the Security Trustee may, and is irrevocably authorised on behalf of the Secured Creditors, subject to the terms of the Finance Documents, to:

(A)	claim, enforce and prove for the Debt owed by, or any other claims against, that Obligor;
(B)	(subject to Clause 61.21.5) exercise all powers of convening meetings, voting and representation in respect of the Debt owed by that Obligor and each Secured Creditor shall provide all forms of proxy and of representation which may be required for such purposes;
(C)	file claims and proofs, give receipts and take all such proceedings and do all such things as the Security Trustee sees fit to recover the Debt owed by, or any other claims against, that Obligor; and
(D)	receive all distributions on or account of the Debt owed by, or any other claims against, that Obligor for application in accordance with Clause 7 (Cascade).

61.21.3 If and to the extent that the Security Trustee is not entitled to claim, enforce, prove, file claims or proofs, or take proceedings for the recovery of any Debt owed by the relevant

	Obligor, the relevant Secured Creditor(s) to whom such Debt is owed shall do so in good time as reasonably requested by the Security Trustee.
61.21.4	Save to the extent that it has been requested by the Security Trustee under Clause 61.21.3 to take such action, no Secured Creditor may take any of the actions referred to in Clause 61.21.2 without the Security Trustee’s prior consent.
61.21.5	Nothing in this Clause 61.21 (Insolvency events) shall:

(A)	limit the rights of the First Lien Lenders to convene meetings, to exercise their voting rights and to issue instructions to the Security Trustee, under the First Lien Credit Agreement and/or this Agreement; and
(B)	limit the rights of the Second Lien Lenders to convene meetings, to exercise their voting rights and to issue instructions to the Security Trustee, under the Second Lien Credit Agreement and/or this Agreement.

61.21.6 If any Insolvency Event occurs in relation to any Obligor, the trustee in bankruptcy, liquidator, assignee or other person distributing the assets of that Obligor or their proceeds shall be directed to pay distributions on the Debt direct to the Security Trustee for application in accordance with Clause 50 (Cascade).

62.	NOTICES
62.1	In writing

62.1.1	Any communication in connection with this Agreement must be in writing and, unless otherwise stated, may be given in person, by fax or email.
62.1.2	Unless it is agreed to the contrary, any consent or agreement required under this Agreement must be given in writing.

62.2 Contact details

62.2.1	Except as provided in this Clause 62.2, the contact details of each Party for all communications in connection with this Agreement are those notified by that Party for this purpose to the Security Trustee on or before the date it becomes a Party.
	The Company
	The contact details of the Company for this purpose are:
	Address: Endeavour International Corporation, 1000 Main Street, Suite 3300, Houston, Texas 77002

Fax number:	(001) 713 307-8793
Email:	Mike.Kirksey@endeavourcorp.com
Attention:	Mike Kirksey
Copy:	Cathy Stubbs (fax (44) 20 7451 2352)
Email:	Cathy.Stubbs@endeavourcorp.com
BNP PARIBAS as First Lien Agent and Security Trustee
The contact details of BNP Paribas for this purpose are:
Address:	16 Rue de Hanovre, 75002 Paris, France
Attention:	Remi Collonges-Dufouleur/Aurélie Guth
Fax number:	+33 1 43 16 99 43

Copy:	Sophie Pic
Fax number:	+33 1 42 98 49 25
Second Lien Agent
The contact details of Bank of Scotland plc for this purpose are:
Address:	New Uberior House, 11 Earl Grey Street, Edinburgh, EH3 9BN
Attention:	Helen Coates
Fax number:	+ $$131 659 0871

62.2.2	Any Party may change its contact details by giving five Business Days’ notice to the Security Trustee or (in the case of the Security Trustee) to the other Parties.
62.2.3	Where a Party nominates a particular department or officer to receive a communication, a communication will not be effective if it fails to specify that department or officer.

62.3 Effectiveness

62.3.1 Except as provided in Clause 62.3.2 and Clause 62.3.3, any communication in connection with this Agreement will be deemed to be given as follows:

(A)	if delivered in person, at the time of delivery; and
(B)	if by fax or e-mail, when received in legible form.

62.3.2	A communication given under Clause 62.4.1 but received on a non-working day or after business hours in the place of receipt will only be deemed to be given on the next working day in that place.
62.3.3	A communication to the Security Trustee, the First Lien Agent, the Second Lien Agent or the Account Bank will only be effective on actual receipt by it.

62.4 Obligors

62.4.1	All communications under this Agreement to or from the other Secured Creditors must be sent through the Security Trustee.
62.4.2	All communications under this Agreement to or from an Obligor must be sent through the Company.
62.4.3	Each Obligor (other than the Company) irrevocably appoints the Company to act as its agent:

(A)	to give and receive all communications under this Agreement;
(B)	to supply all information concerning itself to any Secured Creditor; and
(C)	to sign all documents under or in connection with this Agreement.

62.4.4	Any communication given to the Company in connection with this Agreement will be deemed to have been given also to the other Obligors.
62.4.5	The Secured Creditors may assume that any communication made by the Company is made with the consent of each other Obligor.

62.5 Language

62.5.1	Any notice given in connection with this Agreement must be in English.
62.5.2	Any other document provided in connection with this Agreement must be:

(A) in English; or

(B) (unless the Security Trustee otherwise agrees) accompanied by a certified English translation. In this case, the English translation prevails unless the document is a statutory or other official document.

63.	GOVERNING LAW
	This Agreement and any non-contractual obligations arising out of or in connection with it are governed by English law.
64.	ENFORCEMENT
64.1	Jurisdiction

64.1.1	The courts of England have exclusive jurisdiction to settle any dispute arising out of or in connection with this Agreement (including a dispute regarding the existence, validity or termination of this Agreement) (a “Dispute”).
64.1.2	The Parties agree that the courts of England are the most appropriate and convenient courts to settle Disputes and accordingly no Party will argue to the contrary.
64.1.3	This Clause 64.1 (Jurisdiction) is for the benefit of the Secured Creditors only. As a result, no Secured Creditor shall be prevented from taking proceedings relating to a Dispute in any other courts with jurisdiction. To the extent allowed by law, the Secured Creditors may take concurrent proceedings in any number of jurisdictions.

64.2 Service of process

64.2.1 Without prejudice to any other mode of service allowed under any relevant law, each Obligor (other than an Obligor incorporated in England and Wales):

(A)	irrevocably appoints Endeavour Energy UK Limited as its agent for service of process in relation to any proceedings before the English courts in connection with this Agreement; and
(B)	agrees that failure by a process agent to notify the relevant Obligor of the process will not invalidate the proceedings concerned.

64.2.2 Each of the Obligors expressly agrees and consents to the provisions of this Clause 64 (Enforcement) and Endeavour Energy UK Limited hereby confirms its acceptance of such appointment.

64.3	Waiver of immunity
	Each Obligor irrevocably and unconditionally:

64.3.1	agrees not to claim any immunity from proceedings brought by a Secured Creditor against that Obligor in relation to a Finance Document and to ensure that no such claim is made on its behalf;
64.3.2	consents generally to the giving of any relief or the issue of any process in connection with those proceedings; and
64.3.3	waives all rights of immunity in respect of it or its assets.

This Agreement has been executed and delivered as a deed on the date stated at the beginning of this Agreement.

SCHEDULE 1

PARTIES

Part I

Obligors

	Registration number (or
Name of Obligor	equivalent, if any)	Jurisdiction of incorporation
Endeavour International Corporation	C897-2000	Nevada, U.S.A.
Endeavour Operating Corporation	3737839	Delaware,U.S.A.
Endeavour Energy New Ventures Inc. (formerly known as END Operating Management Company)	3900636	Delaware, U.S.A.
END Management Company	3737839	Delaware, U.S.A.
Endeavour International Holding B.V.	34229293	Netherlands
Endeavour Energy Netherlands B.V.	34229296	Netherlands
Endeavour Energy UK Limited	5030838	England and Wales
Endeavour North Sea Limited	3518803	England and Wales
Endeavour Energy North Sea LLC	4621624	Delaware, U.S.A.
Endeavour Energy North Sea L.P.	4591023	Delaware, U.S.A.

Part II

First Lien Lenders

BNP Paribas

Bank of Scotland plc (formerly, The Governor and Company of the Bank of Scotland)

Sumitomo Mistsui Finance Dublin Ltd

DnB NOR Bank ASA

Fortis Bank, UK Branch

KBC Bank NV London Branch

DZ Bank AG London Branch

Goldman Sachs Lending Partners LLC.

Part III

Second Lien Lenders

Bank of Scotland plc

Part IV

Hedging Banks

Bank of Scotland plc (formerly, HBOS Treasury Services plc)

J.Aron & Company

SMBC Capital Markets Limited

BNP Paribas

SCHEDULE 2

FORM OF ACCESSION INSTRUMENT

To:	[Security Trustee]
From:	[Name of new party]

Dated:

Dear Sirs

Intercreditor Agreement dated 31 October 2006 between, among others, Endeavour International
Corporation and BNP Paribas (as amended from time to time) (the “Agreement”)

1. We refer to the Agreement. This is an Accession Instrument. Terms defined in the Agreement have the same meaning in this Accession Instrument unless given a different meaning in this Accession Instrument.

2. [Name of new party] agrees to become Party to, and be bound by the terms of, the Agreement [and the First Lien Credit Agreement] [and the Second Lien Credit Agreement] as a[n] {[Obligor]/[Second Lien Lender]/[First Lien Lender]/[Hedging Bank]/[Second Lien Agent]/[First Lien Agent]}. [Name of new party] is a company duly incorporated under the laws of [name of relevant jurisdiction].

3.	[New party’s] administrative details are as follows:
	Address:
	Fax No:
	Attention:
4.	This Accession Instrument and any non-contractual obligations arising out of or in connection with it are governed by English law.

[This Accession Instrument has been executed and delivered as a deed on the date stated at the beginning of this Accession Instrument.]

Yours faithfully,

Authorised signatory for

[Name of new party]

This Accession Instrument is accepted by:

Authorised signatory for

[Security Trustee]

EX-10.26.B

Exhibit 10.26(b)

AMENDMENT TO NOTE AGREEMENT

     This Amendment (this “Amendment”), dated as of March 10, 2010, to the Note Agreement, dated as of November 17, 2009 (the “Note Agreement”), is made and entered into by and between Endeavour International Corporation, a Nevada Corporation (the “Company”), the Initial Noteholders listed on the signature pages hereto and the Guarantors listed on the signature pages hereto.

RECITALS

     WHEREAS, the parties hereto have entered into the Note Agreement; and

     WHEREAS, the parties to this Amendment desire to make certain amendments to the Note Agreement in order to clarify the meaning of Section 10.2 of the Note Agreement, all as specifically set forth herein.

     NOW, THEREFORE, the parties hereto agree as follows:

Section 1. Defined Terms; References. Unless otherwise specifically defined herein, each term used herein which is defined in the Note Agreement has the meaning assigned to such term in the Note Agreement. Each reference to “hereof”, “hereunder”, “herein” and “hereby” and each other similar reference and each reference to “this Agreement” and each other similar reference contained in the Note Agreement shall, after this Amendment becomes effective, refer to the Note Agreement as amended hereby.

Section 2. Amendment. Section 10.2 of the Note Agreement is amended and restated in its entirety as follows:

10.2 Common Stock Repurchase. The Company shall neither (A) purchase, redeem or otherwise acquire any shares of the common stock, par value $0.001 per share, of the Company at a price per share greater than the Current Market Price (as defined in the Certificate of Designations of Series C Preferred Stock of the Company filed October 20, 2006, as amended) nor (B) except as expressly permitted by Sections 10.5 and 10.8 hereof, purchase, redeem or otherwise acquire Options or Convertible Securities (as defined in the Certificate of Designations of Series C Preferred Stock of the Company filed October 20, 2006, as amended) for a consideration per share of common stock into which such security is convertible or exchangeable greater than the Current Market Price as of the date of such purchase, redemption or acquisition, as applicable.

Section 3. Governing Law. THIS AMENDMENT SHALL IN ALL RESPECTS BE GOVERNED BY, AND CONSTRUED AND ENFORCED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK, WITHOUT GIVING EFFECT TO ANY CONFLICT OF LAWS RULES THEREOF TO THE EXTENT THEY ARE NOT

MANDATORILY APPLICABLE BY STATUTE AND WOULD REQUIRE OR PERMIT THE APPLICATION OF THE LAW OF ANOTHER JURISDICTION.

Section 4. Counterpart; Facsimile. This Amendment may be executed in any number of counterparts, all of which taken together shall constitute one and the same instrument, and each of the parties hereto may execute this Amendment by signing any such counterpart. Any facsimile copies hereof or signature hereon shall, for all purposes, be deemed originals.

Section 5. Effect of Amendment. This Amendment shall be effective as of November 17, 2009 upon its execution and delivery by a number of Noteholders holding at least two-thirds of the principal amount of all Notes. Except as amended hereby, the Note Agreement shall remain unchanged and effective. The Note Agreement as amended hereby shall continue in full force and effect.

[Signature Pages Follow]

     IN WITNESS WHEREOF, the parties hereto have executed this Amendment as of the date first above written.

ENDEAVOUR INTERNATIONAL CORPORATION
 

/s/ J. Michael Kirksey  

J. Michael Kirksey 

Chief Financial Officer 

Signatures

/s/Gaurav Bhandari Gaurav Bhandari

Goldman, Sachs Investment Partners Master Fund, L.P.

/s/ Terence Aquino Terence Aquino	/s/ Mark J. Vanacore Mark J. Vanacore
Chief Financial Officer	Trading Manager
Eton Park Capital Management, LP	High Bridge International, LLC.
/s/ Terence Aquino Terence Aquino	/s/ Martin Kobinger Martin Kobinger
Chief Financial Officer	Investment Manager
Eton Park Master Fund, LTD.	Capital Ventures International
/s/ Mary Lee Mary Lee	/s/ R. Jeffrey Bruce R. Jeffrey Bruce
Chief Legal Officer	Vice President
TPG-Axon Partners, L.P.	Professional Life and Casualty
/s/ Mary Lee Mary Lee	/s/ J. Baker Gentry, Jr. J. Baker Gentry, Jr.
Chief Legal Officer	Investment Advisor
TPG-Axon Partners(Offshore), LTD.	HBK Master Fund, L.P.

/s/ Paul Smith Paul Smith

General Counsel

Magnetar Capital Master Fund, LTD.

EX-12.1

Exhibit 12.1

Endeavour International Corporation
Computation of Ratios of Earnings to Fixed Charges
(Amounts in thousands)

	Year Ended December 31,
	2009			2008			2007
Earnings:
Income (Loss) before Taxes	$	(94,687	)	$	49,975		$	(72,353	)
Add: Fixed charges		19,697			26,972			25,640
Less: Capitalized interest		(3,067	)		(3,998	)		(6,358	)
Earnings	$	(71,923	)	$	80,945		$	(40,355	)
Fixed Charges:
Interest expense	$	16,630		$	22,974		$	19,282
Capitalized interest		3,067			3,998			6,358
Total fixed charges	$	19,697		$	26,972		$	25,640
Ratio of earnings to fixed charges		—			3.0			—

For purposes of this computation, earnings are defined as pretax earnings from continuing operations before adjustment for minority interest and equity losses in entities with oil and gas properties, plus interest expense, and amortization of debt discount and expense related to indebtedness. Fixed charges are interest expense, including amortization of debt discount and expenses on indebtedness.

Earnings were insufficient to cover fixed charges by $91.6 million and $66.0 million for the years ended December 31, 2009 and 2007, respectively.

EX-12.2

Exhibit 12.2

Endeavour International Corporation
Computation of Ratios of Earnings to Fixed Charges
and Preference Securities Dividends
(Amounts in thousands)

	Year Ended December 31,
	2009			2008			2007
Earnings:
Income (Loss) before Taxes	$	(94,687	)	$	49,975		$	(72,353	)
Add: Fixed charges		40,908			37,781			36,878
Less: Capitalized interest		(3,067	)		(3,998	)		(6,358	)
Earnings	$	(50,712	)	$	91,754		$	(29,117	)
Fixed Charges:
Interest expense	$	16,630		$	22,974		$	19,282
Preferred dividends		21,211			10,809			11,238
Capitalized interest		3,067			3,998			6,358
Total fixed charges	$	40,908		$	37,781		$	36,878
Ratio of earnings to fixed charges		—			2.4			—

For purposes of this computation, earnings are defined as pretax earnings from continuing operations before adjustment for minority interest and equity losses in entities with oil and gas properties, plus interest expense, and amortization of debt discount and expense related to indebtedness. Fixed charges are interest expense, including amortization of debt discount and expenses on indebtedness.

Earnings were insufficient to cover fixed charges by $91.6 million and $66.0 million for the years ended December 31, 2009 and 2007, respectively.

EX-21.1

Exhibit 21.1

SUBSIDIARIES

Name:			Jurisdiction of Organization
	1.	Endeavour Operating Corporation	Delaware
	2.	Endeavour Energy UK Limited	England and Wales
	3.	Endeavour Energy Netherlands B.V.	The Netherlands
	4.	Endeavour International Holding B.V.	The Netherlands
	5.	Endeavour Energy New Ventures, Inc.	Delaware
	6.	END Management Company	Delaware
	7.	Endeavour North Sea Limited	England and Wales
	8.	Endeavour Energy Luxembourg S.a.r.l.	Luxembourg

EX-23.1

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

The Board of Directors
Endeavour International Corporation:

We consent to the incorporation by reference in the registration statements (Nos. 333-118503, 333-124145, 333-130515, 333-132684, 333-139304, 333-149744, 333-163781) on Forms S-3 and (Nos. 333-119577, 333-128692, 333-143794, 333-149743, 333-157967) Form S-8 of Endeavour International Corporation of our reports dated March 16, 2010, with respect to the consolidated balance sheets of Endeavour International Corporation and subsidiaries as of December 31, 2009 and 2008, and the related consolidated statements of operations, stockholders’ equity and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2009, and the effectiveness of internal control over financial reporting as of December 31, 2009, which reports appear in the December 31, 2009 annual report on Form 10-K of Endeavour International Corporation.

Our report with respect to the consolidated financial statements refers to changes in the Company’s method of accounting and disclosures for fair value measurements and fair value reporting of financial assets and liabilities, and its method of estimating oil and gas reserves.

/s/ KPMG LLP Houston, Texas

March 16, 2010

EX-23.2

EXHIBIT 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

We hereby consent to the inclusion in the Endeavour International Corporation Form 10-K for the year ended December 31, 2009, and the incorporation by reference in the Company’s Registration Statement Nos. 333-118503, 333-124145, 333-130515, 333-132684, 333-139304, 333-149744, 333-163781 on Forms S-3 and Nos. 333-119577, 333-128692, 333-143794, 333-149743, 333-157967 Form S-8 as amended, of the reference to Netherland, Sewell & Associates, Inc.

NETHERLAND, SEWELL & ASSOCIATES, INC.
By:	/s/ Danny D. Simmons
	Danny D. Simmons, P.E.
	President and Chief Operating Officer

Houston, Texas

March 16, 2010

EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, William L. Transier, certify that:

1. I have reviewed this Annual Report on Form 10-K of Endeavour International Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 16, 2010

/s/ William L. Transier William L. Transier, Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, J. Michael Kirksey, certify that:

1. I have reviewed this Annual Report on Form 10-K of Endeavour International Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 16, 2010

/s/ J. Michael Kirksey J. Michael Kirksey, Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO SECTION 906
OF THE SARBANES-OXLEY ACT OF 2002

          In connection with the Annual Report of Endeavour International Corporation (the “Company”) on Form 10-K for the period ended December 31, 2009 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, William L. Transier, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

     1. The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

     2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ William L. Transier William L. Transier

Chief Executive Officer

Date: March 16, 2010

     A signed original of this written statement required by Section 906 has been provided to Endeavour International Corporation and will be retained by Endeavour International Corporation and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO SECTION 906
OF THE SARBANES-OXLEY ACT OF 2002

          In connection with the Quarterly Report of Endeavour International Corporation (the “Company”) on Form 10-Q for the period ended December 31, 2009 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, J. Michael Kirksey, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

     1. The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

     2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ J. Michael Kirksey J. Michael Kirksey

Chief Financial Officer

Date: March 16, 2010

     A signed original of this written statement required by Section 906 has been provided to Endeavour International Corporation and will be retained by Endeavour International Corporation and furnished to the Securities and Exchange Commission or its staff upon request.

EX-99.1

Exhibit 99.1

February 17, 2010

Mr. John Williams

Endeavour International Corporation

114 St. Martin’s Lane

London WC2N 4BE

United Kingdom

Dear Mr. Williams:

In accordance with your request, we have audited the estimates prepared by Endeavour International Corporation (Endeavour), as of December 31, 2009, of the proved reserves and future revenue to the Endeavour interest in certain oil and gas properties located in the United Kingdom and the United States. It is our understanding that the proved reserves estimates shown herein constitute all of the proved reserves owned by Endeavour. Endeavour’s estimates of future revenue for the audited properties exclude the company’s abandonment liability for developed fields for which there are no associated proved reserves. We have examined the estimates with respect to reserves quantities, reserves categorization, future producing rates, future net revenue, and the present value of such future net revenue, using the definitions set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Rule 4-10(a). The estimates of reserves and future revenue have been prepared in accordance with the definitions and guidelines of the SEC and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. This report has been prepared for Endeavour’s use in filing with the SEC.

The following table sets forth Endeavour’s estimates of the net reserves and future net revenue, as of December 31, 2009, for the audited properties:

	Net Reserves						Future Net Revenue ($)
	Oil		NGL		Gas				Present Worth
Category	(Barrels)		(Barrels)		(MCF)		Total		at 10%
Proved Developed Producing		1,211,755		26,347		4,457,678		37,279,400		37,529,700
Proved Developed Non-Producing		150,351		0		4,578,226		25,571,300		23,712,300
Proved Undeveloped		1,973,070		4,923		80,063,968		85,655,100		13,079,600
Total Proved		3,335,175		31,271		89,099,888		148,505,800		74,321,600

Totals may not add because of rounding.

The oil reserves shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in barrels that are equivalent to 42 United States gallons. Gas volumes are expressed in thousands of cubic feet (MCF) at standard temperature and pressure bases.

When compared on a field-by-field basis, some of the estimates of Endeavour are greater and some are less than the estimates of Netherland, Sewell & Associates, Inc. However, in our opinion the estimates of Endeavour’s proved reserves and future revenue shown herein are, in the aggregate, reasonable and have been prepared in accordance with generally accepted petroleum engineering and evaluation principles. These principles are set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. We are satisfied with the methods and procedures used by Endeavour in preparing the December 31, 2009, estimates of reserves and future revenue, and we saw nothing of an unusual nature that would cause us to take exception with the estimates, in the aggregate, as prepared by Endeavour.

The estimates shown herein are for proved reserves. As requested, Endeavour’s estimates of probable and possible reserves that exist for these properties have not been included. Endeavour’s estimates do not include any value for undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Endeavour has included estimates of proved undeveloped reserves for certain locations that would generate positive future net revenue but would have negative present worth discounted at 10 percent based on the constant prices and costs discussed in subsequent paragraphs of this letter. These locations have been included based on the operators’ declared intent to drill these wells, as evidenced by Endeavour’s internal budget and reserves estimates. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.

Oil and NGL prices used by Endeavour are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period January through December 2009. For United Kingdom properties, the average Dated Brent price of $60.40 per barrel is adjusted by field for quality, transportation fees, and regional price differentials. For United States properties, the average West Texas Intermediate price of $61.08 per barrel is adjusted by field for quality, transportation fees, and regional price differentials. All oil and NGL prices are held constant throughout the lives of the properties.

Gas prices used by Endeavour are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period January through December 2009. For United Kingdom properties, the average National Balancing Point spot price of 31.81 pence per therm (equivalent to $4.96 per MMBTU) is adjusted by field for energy content, transportation fees, and regional price differentials. For United States properties, the average Henry Hub spot price of $3.86 per MMBTU is adjusted by lease for energy content, transportation fees, and regional price differentials. All gas prices are held constant throughout the lives of the properties.

Lease and well operating costs used by Endeavour are based on historical operating expense records. These costs include the overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Headquarters general and administrative overhead expenses of Endeavour are included to the extent that they are covered under joint operating agreements for the operated properties. Lease and well operating costs are held constant throughout the lives of the properties. Endeavour’s estimates of capital costs are included as required for workovers, new development wells, production equipment, and abandonment. The future capital costs are held constant to the date of expenditure.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing these estimates. Estimates of reserves may increase or decrease as a result of future operations, market conditions, or changes in regulations.

It should be understood that our audit does not constitute a complete reserves study of the audited oil and gas properties. Our audit consisted primarily of substantive testing, wherein we conducted a detailed review of all properties. In the conduct of our audit, we have not independently verified the accuracy and completeness of information and data furnished by Endeavour with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the properties and sales of production. However, if in the course of our examination something came to our attention that brought into question the validity or sufficiency of any such information or data, we did not rely on such information or data until we had

satisfactorily resolved our questions relating thereto or had independently verified such information or data. We used standard engineering and geoscience methods, or a combination of methods, such as performance analysis, volumetric analysis, analogy, and reservoir modeling, that we considered to be appropriate and necessary to establish the conclusions set forth herein. Our audit did not include a review of Endeavour’s overall reserves management processes and practices.

In evaluating the information at our disposal concerning this audit, we have excluded from our consideration all matters as to which the controlling interpretation may be legal or accounting, rather than engineering and geoscience. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

Supporting data documenting this audit, along with data provided by Endeavour, are on file in our office. The technical persons responsible for conducting this audit 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. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties and are not employed on a contingent basis.

Sincerely, NETHERLAND, SEWELL & ASSOCIATES, INC. Texas Registered Engineering Firm F-002699
By:	/s/ C.H. Rees III
	C.H. (Scott) Rees III, P.E.
	Chairman and Chief Executive Officer

By:	/s/ Derek F. Newton Derek F. Newton, P.E. 97689	By:	/s/ David E. Nice David E. Nice, P.G. 346
	Vice President		Vice President
Date Signed: February 17, 2010		Date Signed: February 17, 2010

DFN: JLM