20141231 10K FY


United States Securities and Exchange Commission
Washington, D.C. 20549

Form 10-K

☒ Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the Fiscal Year Ended December 31, 2014
☐ 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		(I.R.S. Employer
incorporation or organization)		Identification No.)

811 Main Street, Suite 2100, Houston, Texas 77002 (Address of principal executive offices) (Zip Code)

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

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

Securities registered pursuant to Section 12(g) of the Act:
Title of Each Class of Stock Common Stock - $0.001 par value per share
Indicate by check mark if the registrant is a well-known seasoned issuer as defined in Rule 405 of the Securities Act. ☐ Yes ☒ 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. ☐ Yes ☒ 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. ☒ Yes ☐ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 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). ☒ Yes ☐ No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) 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. ☐

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

Large accelerated filer	☐		Non-accelerated filer	☐
Accelerated filer	☒		Smaller reporting company	☐

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant was $64.3 million computed by reference to the closing sale price of the registrant’s common stock on the New York Stock Exchange on June 30, 2014, the last business day of the registrant’s most recently completed second fiscal quarter. Shares of common stock held by executive officers and directors of the registrant are not included in the computation.

As of March 27, 2015, 52.9 million shares of the registrant’s common stock were outstanding.

Documents Incorporated By Reference:

None

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Endeavour International Corporation

Table of Contents



		Page
Part I			2
Item 1.	Business		2
Item 1A.	Risk Factors		17
Item 1B.	Unresolved Staff Comments		39
Item 2.	Properties		39
Item 3.	Legal Proceedings		47
Item 4.	Mine Safety Disclosures		49
Part II			49
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		49
Item 6.	Selected Financial Data		50
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		52
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		84
Item 8.	Financial Statements and Supplementary Data		85
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		165
Item 9A.	Controls and Procedures		165
Item 9B.	Other Information		167
Part III			167
Item 10.	Directors, Executive Officers and Corporate Governance of the Registrant		167
Item 11.	Executive Compensation		182
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		195
Item 13.	Certain Relationships and Related Transactions, and Director Independence		197
Item 14.	Principal Accounting Fees and Services		198
Part IV			198
Item 15.	Exhibits and Financial Statement Schedules		198
Signatures			199

Quantities of natural gas are expressed in this Annual Report on Form 10-K in terms of thousand cubic feet (“mcf”), million cubic feet (“mmcf”) or million British thermal units (“mmbtu”). We have assumed one mmbtu is assumed to equal one mmcf. Oil, which includes natural gas liquids, is quantified in terms of barrels (“bbls”) and thousands of barrels (“mbbls”). Natural gas and oil are compared in terms of barrels of oil equivalent (“boe”) thousand barrels of oil equivalent (“mboe”) and million barrels of oil equivalent (“mmboe”) or thousand cubic feet equivalent (“mcfe”) and million cubic feet equivalent (“mmcfe”). Daily volumes are expressed as barrels of oil equivalent per day (“boed”), millions of barrels of oil equivalent per day (“mmboed”) or million cubic feet per day (“mmcfd”). One barrel of oil is the approximate energy equivalent of six mcf of natural gas. This is a physical correlation and does not reflect a value or price relationship between the commodities. With respect to information relating to our working interest in wells or acreage, “net” oil and gas wells or acreage is determined by multiplying gross wells or acreage by our working interest therein. References to number of potential well locations are gross, unless otherwise indicated.

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

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Part I

Item 1. Business

Unless the context otherwise requires, references to “Endeavour,” the “Company,” “we,” “us” or “our” mean Endeavour International Corporation and its consolidated subsidiaries.

Our Company

Endeavour International Corporation (a Nevada corporation formed in 2000) is an independent oil and gas company engaged in the acquisition, exploration and development of energy reserves and resources in the United Kingdom (“U.K.”) North Sea and United States (“U.S.”) onshore.

Voluntary Reorganization under Chapter 11 of the U.S. Bankruptcy Code (Bankruptcy Cases)

Overview

Unanticipated events outside of our control forced us over the last three years to borrow funds at a high cost of capital and divert cash from our businesses to satisfy ongoing obligations. During 2012 to 2014, the Company was heavily involved in the development of the oil and gas fields Bacchus and Rochelle which required significant capital expenditures, and also experienced less-than-expected operating performance at the Alba field. These events, combined with unfavorable changes in the economic and political climate for the oil and gas industry, natural disasters, volatile commodity prices and unexpected delays in new oil and gas production due to operating difficulties in the U.K. North Sea all contributed to our thin liquidity and the swift increase of our debt.

Our management spent over a year exploring restructuring alternatives. We conducted a strategic review, implemented cost-cutting initiatives, restructured our business operations, explored the potential sale of some or all of our assets to a third-party and attempted to negotiate an out-of-court restructuring with our creditors. None of these options materialized as a remedy capable of addressing the breadth of our financial difficulties.

In late June 2014, we and our advisors began to engage with our major creditors in an attempt to arrive at a restructuring transaction that would significantly deleverage the Company and reduce its debt obligations. Discussions continued for months, but the parties failed to reach agreement on several key issues that would serve as a foundation of a restructuring transaction.

On September 2, 2014, we announced that we had decided not to pay approximately $33.5 million in interest due on September 2, 2014 on our 12% First Priority Notes due March 2018, our 12% Second Priority Notes due June 2018 and our 6.5% Convertible Senior Notes due November 2017 (collectively, the “Notes”). We engaged in discussions with representatives of certain holders of our various classes of indebtedness regarding the potential terms under which the Notes could be restructured in order to deleverage our balance sheet.

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On October 10, 2014 (the “Petition Date”), Endeavour and certain of our wholly owned subsidiaries (collectively, the “Debtors”) filed voluntary petitions under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”). The Chapter 11 cases are being jointly administered by the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”) as Case No. 14-12308 (the “Bankruptcy Cases”). Our wholly owned subsidiaries included in the Bankruptcy Cases are:

Endeavour Operating Corporation;

Endeavour Colorado Corporation;

Endeavour Energy New Ventures Inc.;

END Management Company; and

Endeavour Energy Luxembourg S.à.r.l.

None of our subsidiaries incorporated in the U.K. has filed under Chapter 11. Such non-filing subsidiaries are called “non-Debtors.”

Since the Petition Date, the Debtors have operated their business as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court, which allows us to continue operations and carry on our business in the ordinary course during the reorganization proceedings. Each Debtor remains in possession of its assets and properties, and its business and affairs continue to be managed by its directors and officers, subject in each case to the supervision of the Bankruptcy Court. We intend to conduct our business operations in the normal course.

Restructuring Support Agreement and RSA Plan

On the Petition Date, we executed a consensual Restructuring Support Agreement (“RSA”) with holders of more than two-thirds of our First Priority Notes, Second Priority Notes, 7.5% Convertible Bonds, 6.5% Convertible Senior Notes and 5.5% Convertible Senior Notes (collectively, the “Consenting Debt Holders”). On November 17, 2014, we filed with the Bankruptcy Court a plan of reorganization (the “RSA Plan”) and related disclosure statement (the “Disclosure Statement”) to implement the terms of the RSA. The RSA Plan, if implemented as proposed, would significantly reduce our outstanding debt and recapitalize Endeavour.

The RSA provides for milestones for consummation and implementation of the consensual restructuring including:

confirmation of the restructuring plan no later than 170 days after the Petition Date (or Friday, March 27, 2015 as calculated under the Federal Rules of Bankruptcy Procedure or the “Bankruptcy Rules”); and

consummation of the confirmed plan no later than 200 days after the Petition Date (or Tuesday, April 28, 2015, as calculated under the Bankruptcy Rules).

The RSA Plan provides that our existing debt and accrued interest will be reduced by approximately $568 million, including the cancellation of all of our First Priority Notes, Second Priority Notes, 7.5% Convertible Bonds, 5.5% Convertible Senior Notes and 6.5% Convertible Senior Notes.

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As consideration for such cancellation, the reorganized Endeavour would issue:

$262.5 million of new notes to the holders of our First Priority Notes;

an aggregate of approximately $237.5 million of new convertible preferred shares to holders of our First Priority Notes and Second Priority Notes; and

new common shares to holders of our Second Priority Notes, 6.5% Convertible Senior Notes, 7.5% Convertible Bonds and 5.5% Convertible Senior Notes.

All of our existing equity securities, including our shares of common stock and preferred stock and warrants, would be cancelled without receiving any distribution. Reference is made to the RSA Plan filed herewith as an exhibit for more information concerning the RSA Plan.

Notice of Adjournment

As a result of the recent decline in oil and gas prices and the implications on our liquidity and results of operations, we have had discussions with certain of our creditors and/or their advisors. Following these discussions, on February 3, 2015, we filed a Notice of Adjournment of Confirmation Hearing with the Bankruptcy Court. That notice discloses the delay of the Bankruptcy Court’s review and confirmation hearing regarding the RSA Plan. A new date for the confirmation hearing has not yet been determined. Subsequent to filing the notice, we continued to have discussions with certain of our creditors and their advisors and the advisors to the Official Committee of Unsecured Creditors appointed by the Bankruptcy Court concerning the impact of such price declines on the RSA Plan and potential amendments thereto and to the RSA.

We have determined that as a result of this decline in commodity prices, the RSA Plan is not feasible and, accordingly, we will not continue to seek its confirmation. If oil and gas prices remain at their depressed levels, we currently anticipate a breach of our leverage covenant under our Amended Term Loan Facility applicable to our U.K. subsidiary in or about the third quarter of 2015, which will result in a default under the terms of the Amended Term Loan Facility and a liquidity shortfall at the end of the fourth quarter of 2015.

We have and continue to engage in discussions with certain of our U.S. and U.K. creditors regarding the possibility of raising new capital to reduce the principal amount of outstanding indebtedness under the Amended Term Loan Facility in an amount adequate to avoid a potential default of the leverage covenant, refinancing all or a portion of the Amended Term Loan Facility or obtaining a waiver or amendment from the lenders under the Amended Term Loan Facility prior to any default thereunder, or to sustain a restructuring and avoid default.

There can be no assurance that a reduction, refinancing, waiver or amendment of the Amended Term Loan Facility could be accomplished. If we are not able to reach a satisfactory agreement with certain of our U.S. and U.K. creditors and are unable to refinance the Amended Term Loan Facility, which is not possible without financial support from certain of our U.S. or U.K. creditors, we may be compelled, either voluntarily or involuntarily, into liquidation of our U.K. operations through a proceeding in the U.K., in addition to any Chapter 11 or Chapter 7 liquidation proceeding in the U.S.

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Solely as a result of the uncertainties regarding our ability to obtain available financing in the future, we reclassified substantially all of our proved undeveloped reserves as probable undeveloped reserves as of December 31, 2014.

The discussion above provides general background information regarding the Bankruptcy Cases, and is not intended to be an exhaustive description. Further information pertaining to our bankruptcy filings may be obtained through our website at www.endeavourcorp.com. The content of the foregoing website is not a part of this report.

Our Areas of Operation

Our operations are organized into two main geographic regions: the U.K. North Sea and U.S. onshore. Since 2010, our focus has been on the acquisition of additional interests and advancement of our primary development projects in our U.K. fields – Bacchus in 2011, Alba in 2012, and Rochelle in 2013. As of December 31, 2014, our estimated proved reserves were 12.2 mmboe, compared to 23.5 mmboe as of December 31, 2013 of which approximately 82% were located in the U.K. and approximately 18% were located in the U.S.



	As of December 31, 2014				Year Ended December 31, 2014

	Proved Reserves			Probable	Average Daily
	Total		% Proved	Reserves	Physical Production
	(mmboe)	% Oil	Developed	(mmboe)	(boed)
U.K. North Sea
Alba	2.9	95%	92%	11.7	3,897
Bacchus	1.7	95%	100%	1.2	2,187
Rochelle	5.0	26%	100%	5.7	4,069
Other fields	0.4	79%	100%	0.6	101
Total North Sea	10.0	60%	98%	19.2	10,254
U.S. Onshore	2.2	3%	88%	6.5	770
Total	12.2	49%	96%	25.7	11,024

U.K. North Sea

The North Sea is a proven resource area where we have producing properties and exploration licenses. Although capital and production costs are higher than conventional developments in the U.S., the quality of the oil, the political stability of the region, and the proximity of important markets with strong demand in Western Europe has made the North Sea an important oil and natural gas producing region over the last 40 years. Our focus in the North Sea has been on our three largest fields – Alba, Bacchus and Rochelle. While these three fields represented 79% of our proved reserves at December 31, 2014, the fields are in very different stages. Alba is a mature oil field, and our 2013 and 2014 activity involved infill drilling and operational activities. Rochelle is a gas condensate field that started production in October 2013. The Bacchus field is an oil field that began production in May 2012, reached payout after 15 months and completed its development operations during 2013.

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Alba

In May 2012, we acquired an additional 23.43% interest in the Alba field, which increased our total working interest in the field to 25.68%. Alba has a one to two well per year drilling program. In 2014 we completed one development well which spud during the second quarter of 2014, with first production beginning in August 2014. The Alba 2014 exit rate was approximately 17,300 barrels per day gross. An additional development well is scheduled to be drilled during 2015.

During 2013, the water injection pipeline supplying pressure to the southern area of the field ruptured, causing a portion of the wells in the southern region to be shut-in. Partial subsea water injection was restored in May 2014 allowing some wells to be returned to production. The permanent replacement of the pipeline began in March 2015. The permanent replacement will resume production from all subsea wells, which is expected in May 2015. We have made an insurance claim to recover certain loss of production and replacement costs, and received $13 million in December 2014 as an interim settlement. The claims remain in progress for potential additional recoveries, which is estimated to be in the range of $10 million to $15 million.

Bacchus

At December 31, 2014, we held a 30% working interest in our Bacchus field asset, an oil field. In 2012, we achieved production from the first two development wells and the third well was completed in July 2013. During the third quarter of 2013, a 3D seismic survey was shot over the Bacchus field to identify additional Bacchus development opportunities. The field has experienced a slower decline curve than originally forecasted. Currently there are two gas-lifted wells producing, and the Bacchus 2014 exit rate was approximately 6,300 boed gross.

Rochelle

Our working interest in the Rochelle field, a gas-condensate field, is 44%. During the development of the field in February 2013, following a severe storm lasting several days, we performed a routine inspection of the conductor, wellhead and blow out preventer systems which revealed that a non-uniform hole had formed around the conductor. As a result of this finding, the E1 well was plugged and abandoned. We have recovered certain abandonment and redrill costs through insurance, receiving $12.6 million in 2014.

First production from Rochelle was achieved in October 2013, and by January 2014, both the E2 and W1 development wells at Rochelle were fully completed and tied-in to the production manifolds. Since completion, Rochelle has experienced significant downtime, both planned and unplanned. As part of the final installation and start-up of the E2 well, the W1 well was shut-in. During the restart of production, a valve was discovered stuck in the ‘shut’ position on the outlet side of the Rochelle production manifold. An attempt to open the valve manually was unsuccessful and the operator secured an intervention vessel to open the valve. The valve was successfully opened in February 2014. The E2 well commenced production on February 28, 2014 and the W1 well restarted production in March 2014.

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In late March 2014, Rochelle production was shut-in due to an unplanned shutdown of the Scott Platform caused by corrosion of bolts on the platform. The E2 and W1 wells were returned to production during May 2014.

Following a planned Scott Platform shutdown which commenced on July 27, 2014, production resumed on August 26, 2014. On September 9, 2014, Rochelle was shut-in due to mechanical problems on the Scott Platform related to the export gas compressor. Production from Rochelle recommenced on October 11, 2014.

As a result of these events, Rochelle was down for approximately five months during 2014, all of which was out of our control. This downtime negatively affected our production rates and associated revenue in 2014, as well as our near-term liquidity. When both E2 and W1 wells are producing, the production from the Rochelle field is able to exceed the available production capacity at the Scott Platform. The Rochelle 2014 exit rate was approximately 8,600 boed gross. During January 2015 when Rochelle was producing, the production rate has been approximately 8,500 boed gross.

Rochelle was shut-in again on January 31, 2015 for a planned seven day shutdown to tie-in an additional compressor on the Scott Platform to increase reliability. Issues with the existing compressor and mechanical issues at the platform delayed the restart. As a result, Rochelle had approximately six weeks of downtime during the first quarter of 2015.

If we continue to experience unanticipated downtime, our future daily production rates and associated revenue and near-term liquidity will be negatively impacted.

Other

We were not awarded licenses in the 28th U.K. licensing rounds due to financial concerns. The inability to obtain new licenses could adversely impact our plans for growth in the U.K.

U.S. Onshore

During 2009, we began acquiring acreage in U.S. onshore resource plays. Our primary focus in the U.S. has been onshore unconventional oil and gas developments. We believe that our U.S. acreage provides us with development projects with shorter time frames to first production at lower costs than our North Sea assets. Our U.S. activity has targeted reserve and production growth in proven shale gas plays, including the Louisiana Haynesville and Pennsylvania Marcellus areas. We are also targeting emerging oil-prone and liquids-rich plays, including our new interests in the Colorado Niobrara play area. With U.S. gas prices remaining relatively depressed during 2013 and 2014, we limited our capital expenditures to primarily those expenditures necessary to maintain our acreage positions and fulfill minor drilling commitments.

Our strategy for our U.S. operations has been to employ a measured approach that seeks to balance U.S. natural gas prices with drilling costs. We plan to continue this disciplined approach, which includes:

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using our flexibility to curtail drilling expenditures, where possible, until U.S. natural gas prices and well economics improve;

drilling only necessary wells in the Marcellus area to maintain acreage positions; and

leasing and testing new areas that we believe provide liquids-rich potential, with emphasis on the Niobrara play area in Colorado.

Marcellus Area

On November 8, 2013, we closed on a purchase and sale agreement and formed a joint venture partnership with Samson Exploration LLC (“Samson”), which included a sale of 50% of our upstream and midstream assets in the Pennsylvania Marcellus area to Samson. The agreement provides for the joint development of the Marcellus assets and includes a financing component. This joint venture provides the necessary capital for the next development phase in the core Daniel Field in Cameron County, Pennsylvania. Our working interest in the joint venture is 50%.

During 2014, we successfully completed hydraulic fracture stimulations of the C-13, C-14 and C-20 horizontal wells. The operations consisted of an average 28-stage frac for each well, or double the number of frac stages on the longest laterals to date, relative to our previous wells. Initial flowback rates for the C-14 and C-20 wells were in the range of 4.5 mmcfd to 6.5 mmcfd gross each. These wells were tied to a new pipeline constructed by EQT Corporation that allows firm capacity up to 10 mmcfd, with potential for future expansion. We expect to begin production from these wells in mid 2015. Operatorship of our Pennsylvania Marcellus properties was transferred to Samson on July 1, 2014.

At December 31, 2014, we had approximately 26,200 gross acres and 12,900 net acres in the Pennsylvania Marcellus area. In the first quarter of 2015, we drilled two new horizontal wells to maintain our leasehold. One of those wells was successfully cased and the other was plugged and abandoned following mechanical issues. Later in 2015, we expect to complete the successfully cased well. The costs of these wells are carried by Samson and do not require us to contribute capital towards their drilling and completion.

Haynesville Area

We have working interests in three Haynesville producing project areas in Louisiana totaling approximately 7,100 gross acres and 3,200 net acres. We have working interests in 19 Haynesville units which are currently held by production with an estimated 80 or more remaining gross locations yet to be developed, depending on ultimate development well spacing. No new drilling is currently required in the Haynesville area to maintain our acreage position.

Niobrara Play

We have leasehold of approximately 33,500 gross and 20,700 net acres in the liquids-rich Niobrara play in northwest Colorado with drilling rights to earn an additional estimated 10,000 net acres. In 2013, we formed a 23,000 acre Federal Unit in Rio Blanco and Moffat Counties, which we operate and own an approximate 60% interest in the Federal Unit and 72% working interest in the drilling block, and drilled an initial vertical pilot test well in the Wiley Unit to

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evaluate the liquids-rich potential of the Niobrara and Frontier formations. During 2014, we completed the Wiley 23-3-97 H1 horizontal well (the “Wiley well”) and had initial oil and gas production in the fourth quarter. During the 23-day flowback period, the Wiley well averaged 602 barrels of oil per day gross plus 1.3 to 1.8 mmcfd, with a peak daily oil rate of 805 barrels of oil per day gross. After beginning production in the fourth quarter of 2014, we shut in the Wiley well in December to complete the production facilities and gas pipeline tie-in. Production resumed in late March 2015.

Energy Industry Environment

Recently, global energy commodity prices have declined precipitously as a result of several factors including increased worldwide supplies, a stronger U.S. dollar, and strong competition among oil producing countries for market share. Commodity prices have not rebounded to date, and it is unknown if or when they might recover. Specifically, prices for Brent have declined from approximately $115.00 per bbl in June 2014 to less than $47.00 per bbl in January 2015. Prices for NBP natural gas in January 2014 traded for approximately $11.00 per mcf compared to prices in January 2015 of approximately $7.00 per mcf. In response to these market conditions, we have significantly reduced capital spending plans.

2015 Planned Expenditures

We expect that our total capital expenditure budget for 2015 will be approximately $40 million. In the current climate and until prices return to more favorable levels, we are actively managing our budget to reduce our capital expenditures to the minimal level essential to preserve our business. Additionally, our 2015 capital expenditure budget is subject to change depending on a number of factors, including the results of the Bankruptcy Cases, the availability and costs of drilling and completion equipment, crews, economic and industry conditions, prevailing and anticipated prices for oil and gas, the availability of sufficient capital resources, drilling success and other normal factors affecting the oil and gas industry.

For a complete discussion of our available sources of liquidity and our expected financing needs, please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations —Liquidity and Capital Resources.”

Decommissioning Expenditures

Production from each of our Ivanhoe, Rob Roy, Hamish (collectively, “IVRRH”), Renee, Rubie and Goldeneye fields has ceased and we have performed maintenance and decommissioning activities over the last several years. We estimate the budgeted cost of decommissioning activities for 2015 to be approximately $32 million. Costs incurred during 2015 will complete the IVRRH abandonment obligations and begin the Renee and Rubie abandonment obligations. In addition, certain decommissioning security agreements require us to put up security, which causes us to incur further costs and dedicate additional capital.

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Geographical Data

We operate in one industry segment, that being oil and gas exploration and production, in two geographical areas. See Note 25 – Segment and Geographic Information and Note 29 – Supplemental Oil and Gas Disclosures 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 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. For the year ended December 31, 2014, our sales to Shell U.K. Limited accounted for more than 10% of revenue. Our sales in the U.S. are sold through our arrangements with the operators of the fields, with the majority of the sales being to J-W Operating Company. As our Marcellus and Niobrara production comes on-line, J-W Operating Company will no longer be the majority purchaser of our U.S. production.

Employees

As of March 27, 2015, we had 38 full-time employees. We believe that we maintain good relationships with our employees, none of whom are covered by a collective bargaining agreement.

Environmental Matters and Regulation

North Sea

Our operations in the U.K. portions of the North Sea are subject to numerous U.K. and European Union (“E.U.”) laws and regulations relating to environmental matters, health and safety. Environmental matters are addressed before oil and gas production activities commence through licensing and environmental review requirements and during the exploration and production

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activities through license monitoring and reporting requirements. Before a U.K. licensing round begins, the Department of Energy and Climate Change (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 their management systems and how those systems will be applied to the proposed work program. Additionally, the Offshore Petroleum Production and Pipelines (Assessment of Environmental Effects) Regulations 1999 require the Secretary of State to exercise his licensing powers under the U.K. Petroleum Act in such a way to ensure that an environmental assessment is undertaken and considered before consent is given to certain projects.

There are a number of recent and forthcoming rules that may impact our North Sea operations. Following incidents in the Gulf of Mexico in 2010, the DECC has increased rig inspections over the last several years. In addition, more rigor has been introduced in the approval process for emergency plans and the provision of financial responsibility for well control contingencies. The E.U. has issued a directive on offshore safety, and the U.K. has published two consultations on how existing regulations will be amended to implement the E.U. Directive. Changes to the existing regulations include, amongst other items, enhanced reporting, emergency response planning, operator designation and offshore asset decommissioning requirements. At this time, we cannot predict the ultimate costs associated with any change in U.K. regulations designed to implement the E.U offshore safety directive. We expect these measures to continue, or increase, over the near term as the clear trend in environmental regulation is for stricter requirements. In addition, our operations in the North Sea are subject to the European Union’s REACH program, which requires the registration and ultimate phase out of certain hazardous chemicals. Finally, depending on the scale of our operations, our offshore production facilities may be subject to compliance obligations under the E.U. emissions trading system (“E.U. ETS”) for greenhouse gas (“GHG”) emissions. The E.U. ETS places a cap on GHG emissions from certain sources. Sources that emit above their applicable caps must purchase allowances in order to comply with the E.U. ETS. The E.U. has commenced the third phase of the E.U. ETS, running from 2013 to 2020, and therefore our activities in the North Sea are still potentially subject to the impacts of GHG limitations. While allowance prices on the E.U. ETS remain low, the E.U. has approved a proposal to increase allowances prices by deferring the marketability of allowances by withholding a number of allowances from auction, known as “backloading.” Compliance with the above regulations may cause us to incur additional costs in our North Sea operations.

United States

Our U.S. operations are subject to stringent federal, state and local laws and regulations relating to environmental protection, as well as controlling the manner in which various substances, including wastes generated in connection with oil and gas industry operations, are released into the environment. Compliance with these laws and regulations requires 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 prior to closure and abandonment. 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 and operating costs to comply with governmental standards, and even injunctions that limit or prohibit exploration and production operations or the disposal of

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substances generated in connection with such operations Additionally, a release of hydrocarbons or wastes into the environment could, to the extent the event is not insured, subject us to substantial expenses, including removal and remediation costs, costs to resolve claims by third parties for personal injury or property damage, or by the U.S. federal government or state governments for natural resources damages.

The environmental laws we are subject to include:

The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) and comparable state laws. CERCLA imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment.

The Resource Conservation and Recovery Act (“RCRA”) and comparable state laws. RCRA imposes detailed requirements for the generation, handling, storage, treatment and disposal of nonhazardous and hazardous solid wastes.

The Federal Water Pollution Control Act, or the Clean Water Act, and comparable state laws. The Clean Water Act imposes restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas wastes, into federal and state waters, as well as dredge and fill activities in wetlands.

The federal Clean Air Act and comparable state laws. The Clean Air Act restricts the emission of air pollutants from many sources, such as compressor stations, through air emissions standards, construction and operating permitting programs, and the imposition of other compliance requirements.

The National Environmental Policy Act (“NEPA”). NEPA required federal agencies, including the Department of Interior, to evaluate major agency actions, such as permitting oil and natural gas exploration and production activities on federal lands, which have the potential to significantly impact the environment.

In addition, we currently lease a number of properties that for many years have been used for the exploration and production of oil and gas. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or wastes may have been disposed of or released on or under the properties operated or leased by us or on or under other locations where such hydrocarbons or wastes have been taken for recycling or disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or wastes was not under our control. These properties and the hydrocarbons and wastes disposed thereon may be subject to laws and regulations imposing strict, joint and several, liability, without regard to fault or the legality of the original conduct, that could require us to remove or remediate previously disposed wastes or environmental contamination, or to perform remedial well plugging or pit closure activities to prevent future contamination.

Hydraulic Fracturing

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process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. However, the United States Environmental Protection Agency (the “EPA”) has asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s (“SDWA”) Underground Injection Control Program and issued permitting guidance under the SDWA for such activities. In addition, in May 2014, the EPA issued an Advance Notice of Proposed Rulemaking to collect data on chemicals used in hydraulic fracturing operations under the Toxic Substances Control Act. To date, no other action has been taken. Furthermore, in April 2012, the EPA adopted regulations requiring the reduction of volatile organic compound emissions from oil and natural gas production facilities by mandating the use of “green completions” for hydraulic fracturing activities. These regulations require the operator to recover rather than vent gas and natural gas liquids that return to the surface during well completion operations. Also, the EPA has announced its intention to propose regulations under the CWA by sometime in 2015 governing wastewater discharges from hydraulic fracturing and certain other natural gas operations. In addition, the EPA is conducting a study of the potential impacts of hydraulic fracturing activities on water resources and a draft final report is anticipated sometime in 2015 for peer review and public comment. The results of this study or similar governmental reviews could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise.

From time to time, legislation has been introduced before the United States Congress (“Congress”) to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In addition, some states have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations. For example, Pennsylvania, and Colorado, have each adopted a variety of well construction, set back, and disclosure regulations limiting how fracturing can be performed and requiring various degrees of chemical disclosure. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, our fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.

Climate Change

In response to findings that emissions of carbon dioxide, methane and other GHGs, present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, establish Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit reviews for certain large stationary sources. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by

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the states or, in some cases, by the EPA on a case-by-case basis. These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which include certain of our operations. We are monitoring GHG emissions from our operations in accordance with the GHG emissions reporting rule and believe that our monitoring activities are in substantial compliance with applicable reporting obligations. More recently, in January 2015, the Obama Administration announced that the EPA is expected to propose in the summer of 2015 new regulations that will set methane emission standards for new and modified oil and gas production and natural gas processing and transmission facilities as part of the Administration’s efforts to reduce methane emissions from the oil and gas sector by up to 45 percent from 2012 levels by 2025.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emission by means of cap and trade programs that typically require major sources of GHG emissions, to acquire and surrender emission allowances in return for emitting those GHGs. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. Substantial limitations on GHG emissions could also adversely affect demand for the oil and natural gas we produce.

Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic event; if any such effects were to occur, they could have an adverse effect on our exploration and production operations.

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

We have established internal guidelines to be followed in order to comply with environmental laws and regulations in the U.S. We employ personnel whose responsibilities include providing assurance that our operations are carried out safely and in accordance with applicable environmental guidelines and safety precautions. Although we maintain pollution insurance to cover a portion of the potential costs of cleanup obligations, public liability and physical damage, there is no assurance that such insurance will be adequate to cover all such costs or that such insurance will continue to be available in the future. To date, we believe that compliance with

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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 U.S. 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;

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.

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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 811 Main Street, Suite 2100, Houston, Texas 77002, and our telephone number is (713) 307-8700. We also have offices in Aberdeen, Scotland, United Kingdom and in Denver, Colorado.

Available Information

We file annual, quarterly and current reports with the Securities and Exchange Commission (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’s website, www.sec.gov.

Our website is available at www.endeavourcorp.com. We make available, free of charge, on our website, our 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, the Governance and Nominating Committee and the Technology & Reserves Committee, and the Code of Conduct and Code of Ethics for Senior Officers are available on our website and in print to any stockholder who provides a written request to the

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Corporate Secretary at 811 Main Street, Suite 2100, Houston, Texas 77002. Our Code of Conduct applies to all directors, officers and employees.

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

Financial Information about Segment and Geographical Areas

We operate in one industry segment, that being oil and gas exploration and production, in two geographical areas. See Note 29 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. Our revenues and long-lived assets by geographic area are included in Note 25 to our consolidated financial statements in “Item 8. Financial Statements and Supplementary Data” 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 (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These forward-looking statements include statements that express a belief, expectation, or intention, as well as those that are not statements of historical fact, and may include projections and estimates concerning the timing and success of specific projects and our future production, revenues, income and capital spending. Our forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “plan,” “goal” or other words that convey the uncertainty of future events or outcomes. We caution you not to rely on them unduly. In particular, this Annual Report on Form 10-K contains forward-looking statements pertaining to the following:

our financial position and liquidity;

our business strategy;

recent acquisitions;

budgets;

projected costs, savings and plans;

objectives of management for future operations;

legal strategies; and

legal proceedings.

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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:

risks and uncertainties associated with the Bankruptcy Cases and related liquidity concerns;

the significant recent decline in, and volatility of, oil and gas prices;

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

decreases in proved reserves due to technical or economic factors;

drilling of wells and other planned exploitation activities;

our high level of indebtedness and debt service costs;

adverse weather conditions;

uncertainties related to drilling and production operations;

timing and amount of future production of oil and gas;

ability to flow our production through aging infrastructure in the U.K. North Sea that is owned by others;

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;

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

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

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 financial condition or results of operations and the ultimate accuracy of a forward-looking statement. 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 risks and uncertainties, as mentioned in this “Item 1A. Risk Factors” and elsewhere in this Annual Report on Form 10-K. Except as required by law, we undertake no obligation to update publicly or release any revisions to these forward-looking statements to reflect events or circumstances after the date of this Annual Report on Form 10-K. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

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Risk Factors Related to Our Restructuring

We and certain of our subsidiaries filed for reorganization under Chapter 11 of the Bankruptcy Code on October 10, 2014 and are subject to the risks and uncertainties associated with the Bankruptcy Cases.

For the duration of the Bankruptcy Cases, our operations and our ability to execute our business strategy will be subject to the risks and uncertainties associated with bankruptcy. These risks include but are not limited to:

our ability to continue as a going concern;

our ability to obtain Bankruptcy Court approval with respect to motions filed in the Bankruptcy Cases from time to time;

our ability to develop, prosecute, confirm and consummate a plan of reorganization with respect to the Bankruptcy Cases;

the ability of third parties to seek and obtain court approval to terminate or shorten the exclusivity period for us to propose and solicit on a plan of reorganization, to appoint a trustee or to convert the Bankruptcy Cases to Chapter 7 cases;

our ability to obtain and maintain normal payment and other terms with customers, vendors and service providers;

our ability to maintain licenses, leases and other contracts that are critical to our operations;

our ability to attract, motivate and retain key employees;

our ability to retain key vendors or secure alternative supply sources;

our ability to fund and execute our business plan, operations and financial commitments;

our ability to obtain acceptable and appropriate financing; and

the cost of our restructuring efforts including professional fees, which reduce our available cash to operate our business.

We will also be subject to risks and uncertainties with respect to the actions and decisions of our creditors and other third parties who have interests in the Bankruptcy Cases that may be inconsistent with our plans.

These risks and uncertainties could affect our business and operations in various ways. For example, negative events or publicity associated with the Bankruptcy Cases could adversely affect our relationships with our vendors and employees, as well as with our customers, lessors and licensors which in turn could adversely affect our operations and financial condition. Also, pursuant to the Bankruptcy Code, we need Bankruptcy Court approval for transactions outside the ordinary course of business, which may limit our ability to respond timely to events or take advantage of opportunities. Because of the risks and uncertainties associated with the Bankruptcy Cases, we cannot predict or quantify the ultimate impact that events occurring during the Chapter 11 proceedings will have on our business, financial condition and results of operations, and there is no certainty as to our ability to continue as a going concern.

As a result of the Bankruptcy Cases, realization of assets and liquidation of liabilities are subject to uncertainty. While operating under the protection of the Bankruptcy Code, and subject to Bankruptcy Court, approval or otherwise as permitted in the normal course of business, we may

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sell or otherwise dispose of assets and liquidate or settle liabilities for amounts other than those reflected in our consolidated financial statements. Further, a plan of reorganization could materially change the amounts and classifications reported in our consolidated historical financial statements, which do not give effect to any adjustments to the carrying value of assets or amounts of liabilities that might be necessary as a consequence of confirmation of a plan of reorganization.

Our businesses could suffer from a long and protracted restructuring.

Our future results are dependent upon the successful confirmation and implementation of a plan of reorganization. Failure to obtain both in a timely manner could adversely affect our operating results, as our ability to obtain financing to fund our operations may be harmed by protracted bankruptcy proceedings. The recent decline in commodity prices, and the resulting need to amend our plan of reorganization, has significantly increased the amount of time that we expect to need to obtain approval of our plan. If a liquidation or protracted reorganization were to occur, there is a significant risk that the value of our enterprise would substantially decline to the detriment of all stakeholders. Through December 31, 2014, we have spent $9.7 million in cash on professional and advisory fees. A protracted restructuring will likely continue that trend and significantly impact our cash flows.

Furthermore, we cannot predict the ultimate amount of all settlement terms for the liabilities that will be subject to a plan of reorganization. Even after a plan of reorganization is approved and implemented, our operating results may be adversely affected by the possible reluctance of prospective lenders to do business with a company that recently emerged from bankruptcy proceedings.

Our emergence from the Bankruptcy Cases is not assured.

We will not be seeking confirmation of the RSA Plan and there can be no assurance that an alternative plan of reorganization that might be proposed will be accepted by our creditors or approved by the Bankruptcy Court, so we urge caution with respect to existing and future investments in our securities.

It is unclear whether we would be able to reorganize our business and what, if any, distributions holders of claims against or interests in us, including holders of our secured and unsecured debt and of our equity, would ultimately receive with respect to their claims and interests. We will incur significant costs in connection with developing and seeking approval of an alternative plan of reorganization, which might not be supported by any of the current debt holders, various formal and informal creditor committees or other stakeholders. If an alternative reorganization could not be agreed upon, it is possible that we would have to liquidate our assets through a Chapter 11 or Chapter 7 proceeding in the U.S. or a proceeding in the U.K., in which case it is likely that holders of claims would receive substantially less favorable treatment than they would receive if we were to emerge as a viable, reorganized entity. There can be no assurance as to whether we will successfully reorganize and emerge from the Bankruptcy Cases or, if we do successfully reorganize, as to when we would emerge from the Bankruptcy Cases.

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We depend on key personnel and may not be able to retain those employees or recruit additional qualified personnel.

We are highly dependent on the continuing efforts of our senior management team and other key personnel. Our business, financial condition and results of operations could be materially adversely affected if we lose any of these persons during or subsequent to the bankruptcy proceedings and are unable to attract and retain qualified replacements.

Our substantial indebtedness could adversely affect our business, financial condition and results of operations and prevent us from fulfilling our obligations under the terms of our indebtedness.

We have, and may continue to have, a significant amount of indebtedness. As of December 31, 2014, we had total indebtedness of approximately $1,230.2 million, of which $790.2 million related to indebtedness of the Debtors.

Our substantial indebtedness could make it more difficult for us to satisfy our obligations and has had and could continue to have other material adverse consequences for our business, including:

requiring us to dedicate a large portion of our cash flow to pay principal and interest on our indebtedness, which will reduce the availability of our cash flow to fund working capital, capital expenditures, research and development expenditures and other business activities;

increasing our vulnerability to general adverse economic and industry conditions, including especially the recent significant decline in commodity prices;

limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

restricting us from making strategic acquisitions, dispositions or exploiting business opportunities;

placing us at a competitive disadvantage compared to our competitors that have less debt; and

limiting our ability to borrow additional funds (even when necessary to maintain adequate liquidity) or dispose of assets.

We also are, and expect to continue to be, required to comply with certain financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control. Our cash flow is highly dependent on the prices we receive for oil and natural gas, which declined significantly in recent months. If oil and gas prices remain at their current depressed levels, we currently anticipate a breach of our leverage covenant under our Amended Credit Agreement (see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations”) applicable to our U.K. subsidiary in or about the third quarter of 2015. We are evaluating various alternatives with respect to our Amended Credit Agreement, but there is no certainty that we will be able to implement any alternatives or otherwise resolve our covenant issues. If an event of default occurs, and the lenders under the Amended Credit Agreement accelerate the maturity of any loans, we would not have sufficient liquidity to repay all of our outstanding indebtedness without new financing. Acceleration of

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debt of this magnitude would likely result in a further reorganization, other restructuring or liquidation.

In addition, a portion of our debt bears interest at variable rates. If market interest rates increase, the interest rate on our variable-rate debt will increase and will create higher debt service requirements, which would adversely affect our cash flow and could adversely impact our results of operations. While we may enter into agreements limiting our exposure to higher debt service requirements, any such agreements may not offer complete protection from this risk.

We may be subject to claims that will not be discharged in the Bankruptcy Cases, which could have a material adverse effect on our results of operations and profitability.

The Bankruptcy Code provides that the confirmation of a plan of reorganization discharges a debtor from substantially all debts arising prior to confirmation and specified debts arising afterwards. With few exceptions, all claims that arose prior to October 10, 2014 and before confirmation of the plan of reorganization (i) would be subject to compromise and/or treatment under the plan of reorganization or (ii) would be discharged in accordance with the Bankruptcy Code and the terms of the plan of reorganization. Any claims not ultimately discharged by the Bankruptcy Court could have an adverse effect on our results of operations and profitability.

Our financial results may be volatile and may not reflect historical trends.

While in bankruptcy, we expect our financial results to continue to be volatile as asset impairments, asset dispositions, restructuring activities, contract terminations and rejections and claims assessments may significantly impact our consolidated financial statements. As a result, our historical financial performance is likely not indicative of our financial performance after the date of the bankruptcy filing. In addition, if we emerge from bankruptcy, the amounts reported in subsequent consolidated financial statements may materially change relative to historical consolidated financial statements, including as a result of revisions to our operating plans pursuant to a plan of reorganization.

In addition, if we emerge from bankruptcy, we may be required to adopt fresh start accounting. If fresh start accounting is applicable, our assets and liabilities will be recorded at fair value as of the fresh start reporting date. The fair value of our assets and liabilities may differ materially from the recorded values of assets and liabilities on our consolidated balance sheets. In addition, if fresh start accounting is required, our financial results after the application of fresh start accounting may be different from historical trends.

Our shares are subject to risks associated with trading in an over-the-counter market.

Securities traded in the over-the-counter market generally have significantly less liquidity than securities traded on a national securities exchange, through factors such as a reduction in the number of investors that will consider investing in the securities, the number of market makers in the securities, reduction in securities analyst and news media coverage and lower market prices than might otherwise be obtained. As a result, holders of shares of our common stock may find it difficult to resell their shares at prices quoted in the market or at all. Furthermore, because of the limited market and generally low volume of trading in our common stock that could occur,

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the share price of our common stock could be more likely to be affected by broad market fluctuations, general market conditions, fluctuations in our operating results, changes in the markets perception of our business, and announcements made by us, our competitors or parties with whom we have business relationships.

Risks related to access to capital and financing

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, especially in light of the recent decline in commodity prices and our ongoing Bankruptcy Cases. If we are unable to fulfill commitments under any of our interests, we will lose our interest and our entire investment in such interest.

A change of control may adversely affect our liquidity, require refinancing of certain debt instruments and trigger severance payments or accelerated vesting of equity awards.

Upon certain specified change of control events, the lenders under our various debt facilities may cancel the facility and declare as due and payable any outstanding indebtedness, accrued interest and other outstanding fees. The terms of the indentures governing the 2018 Notes (as defined below) may require us to repurchase all or a portion of the notes if the proceeds from certain dispositions are not applied in a specific manner. We cannot assure you we would have sufficient financial resources to purchase the debt instruments for cash or repay the lenders upon the occurrence of a change of control or disposition. 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.

We provide severance benefits through change in control agreements with Mr. Emme, Ms. Stubbs and Mr. Neilson. These agreements provide for severance compensation to be paid if employment is terminated under certain conditions, such as at the executive’s election for “good reason” following a change in control, as defined in the agreements. Additionally, our long-term incentive grant agreements provide for accelerated vesting of equity awards upon the occurrence of a change in control.

Our development and exploration operations require substantial capital, and we may be unable to generate sufficient cash flow from operations or 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. In the past, we have utilized cash flow from operations and access to the debt and equity markets to fund our capital requirements; the recent declines in commodity prices and our ongoing Bankruptcy Cases make it more difficult for us to

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fund our capital requirements in that manner. Our cash flow from operations and access to capital is subject to a number of variables, including:

the level of natural gas and crude oil we are able to produce from existing wells and through infrastructure owned by others;

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

our oil and gas reserves;

uncertainties related to drilling and production operations;

the timing and amount of capital expenditures, decommissioning costs and security obligations;

our ability to control the development efforts, costs and timing of our operations; and

our ability to acquire, locate and produce new reserves.

Recently, global energy commodity prices have declined precipitously as a result of several factors including increased worldwide supplies, a stronger U.S. dollar, weather factors, and strong competition among oil producing countries for market share. Commodity prices have not rebounded to date, and it is unknown if or when they might recover. Specifically, prices for Brent have declined from approximately $115.00 per bbl in June 2014 to less than $47.00 per bbl in January 2015. Prices for NBP natural gas in January 2014 traded for approximately $11.00 per mcf compared to prices in January 2015 of approximately $7.00 per mcf. If our revenues decrease as a result of further or sustained lower oil and gas prices, operating difficulties, declines in reserves or for any other reason or our capital expenditures increase as a result of operating difficulties, higher drillings costs or for any other reason, we may have limited ability to generate sufficient cash flow from operations or 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. Any future indebtedness we incur may contain covenants restricting our ability to incur additional indebtedness without the consent of the lenders.

Furthermore, we may not be able to obtain debt or equity financing in the future on terms favorable to us, or at all. In addition, our existing debt contains restrictions on the incurrence of new debt. The failure to obtain additional financing could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our natural gas, crude oil and natural gas liquids reserves.

Risks related to executing our strategy and operations

Our business involves many uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.

Our development activities may be unsuccessful for many reasons, including adverse weather conditions (such as storms in the North Sea), cost overruns, equipment shortages, geological

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issues and mechanical difficulties. These operating risks may result in a loss or delay of cash flows from production or require additional capital expenditures. Moreover, the successful drilling of a natural gas or oil well does not assure we will realize a profit on our investment. A variety of factors, both geological and market-related, can cause a well to become uneconomical or only marginally economical. In addition to their costs, unsuccessful wells hinder our efforts to replace reserves.

Our oil and natural gas exploration and production activities, including well stimulation and completion activities such as hydraulic fracturing, involve a variety of operating risks, including:

fires;

explosions;

blow-outs and surface cratering;

uncontrollable flows of natural gas, oil and formation water;

natural disasters, such as severe storms, hurricanes and other adverse weather conditions;

inability to obtain insurance at reasonable rates;

failure to receive payment on insurance claims in a timely manner, or for the full amount claimed;

pipe, cement, subsea well or pipeline failures;

casing collapses or failures;

mechanical difficulties, such as lost or stuck oil field drilling and service tools;

abnormally pressured formations or rock compaction; and

environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures, encountering naturally occurring radioactive materials, and discharges of brine, well stimulation and completion fluids, toxic gases, or other pollutants into the surface and subsurface environment.

If we experience any of these problems, well bores, platforms, gathering systems and processing facilities could be affected, which could adversely affect our ability to conduct operations and receive the associated cash flows. We could also incur substantial losses as a result of:

injury or loss of life;

damage to and destruction of property, natural resources and equipment;

pollution and other environmental damage;

clean-up responsibilities;

regulatory investigation and penalties;

suspension of our operations;

repairs required to resume operations; and

loss of reserves.

Offshore operations are also subject to a variety of operating risks related to the marine environment, such as capsizing, collisions and damage or loss from severe storms, 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 funds available for exploration, exploitation and acquisitions or result in the loss of property and equipment.

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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. In addition, such mechanical difficulties are more difficult, expensive and time consuming to fix in an offshore environment. As a result, a significant amount of time and capital must be invested before we can market the associated oil or gas of a commercial discovery, 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.

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

Oil and gas operations are subject to particular hazards incident to the drilling and production of oil and gas, such as blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires and pollution and other environmental risks. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. We maintain insurance for some, but not all, of the potential risks and liabilities associated with our business. If a significant accident or other event resulting in damage to our operations, including severe weather, terrorist acts, war, civil disturbances, pollution or environmental damage, occurs and is not fully covered by insurance, it could adversely affect our financial condition and results of operations.

We do not currently operate all of our oil and gas properties. In the projects in which we own non-operating interests, the operator may maintain insurance of various types to cover our operations with policy limits and retention liability customary in the industry. The occurrence of a significant adverse event that is not fully covered by insurance could result in the loss of our total investment in a particular prospect and additional liability for us, which could have a material adverse effect on our financial condition and results of operations and prospects.

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

Our future oil and gas production is highly dependent upon our level of success in finding or acquiring additional reserves. Producing oil and gas reserves are generally characterized by declining production rates that vary depending on reservoir characteristics and other factors. Our reserves will decline unless we acquire properties with proved reserves or conduct successful development and exploration drilling activities. We accomplish this through successful drilling programs and the acquisition of properties. However, we may be unable to find, develop or acquire additional reserves or production at an acceptable cost or at all. Acquisition opportunities in the oil and gas industry are very competitive, which can increase the cost of, or cause us to refrain from, pursuing 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 and probable 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.

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

We have identified drilling locations, prospects for future drilling opportunities and development plans for our commercial discoveries, including development, exploratory and other drilling and enhanced recovery activities. These drilling and development locations and prospects represent a significant part of our future drilling and development plans. Our ability to drill and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, third-party operators, approval or other participants to drill wells and implement other work programs, availability of suitable drilling rigs, equipment and qualified operating personnel, regulatory approvals, negotiation of agreements with third parties, commodity prices, costs and drilling results. In particular, delays in obtaining regulatory approvals relating to our field development programs for our North Sea discoveries and operational issues can materially impact our ability to commence production at these discoveries which would materially impact our reserves, cash flow and results of operations. Furthermore, because of these uncertainties, we cannot give any assurance as to the timing of these activities or that they will ultimately result in the realization of proved reserves or meet our expectations for success. As such, our actual drilling and enhanced recovery activities may materially differ from our current expectations, which could have a significant adverse effect on our financial condition and results of operations.

Our drilling projects are based in part on seismic and other technical data, which cannot ensure the commercial success of a prospect.

Our decisions to purchase, explore, develop and exploit prospects or properties depend in part on data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often uncertain. Seismic data and visualization techniques only

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assist geoscientists and geologists in identifying subsurface structures and hydrocarbon indicators and do not enable an interpreter to conclusively determine whether hydrocarbons are present or producible economically. In addition, the use of seismic and other advanced technologies may require greater predrilling expenditures than other drilling strategies. Because of these factors and the inherent uncertainties surrounding the evaluation of exploration prospects, we could incur losses as a result of exploratory drilling expenditures. Poor results from drilling activities would have a material adverse effect on our future cash flows, ability to replace reserves and results of operations.

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

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

Certain of our U.K. oil fields are dependent upon tanker liftings to deliver oil production to buyers, which may result in fluctuations in our revenue and results of operations.

We record oil revenues using the sales method (i.e., when delivery has occurred). While certain of our U.K. fields produce into pipelines (causing revenue to be recorded consistently with such production), certain other fields are dependent upon tanker liftings to deliver oil production to buyers. As a result, our revenues from this oil production will fluctuate in connection with the frequency and volume of tanker liftings, which are factors not entirely within our control. Accordingly, the revenues from our oil production in the U.K. are expected to be more volatile than the associated physical production.

Actual production could differ significantly from forecasts.

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

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The cost of decommissioning is uncertain.

We expect to incur obligations to abandon and decommission certain structures associated with our producing properties. To date, the industry has little experience of removing oil and gas structures from the North Sea, because few of the structures in the North Sea have been removed. Because experience is limited, we cannot precisely predict the costs of any future decommissions for which we might become obligated. Furthermore, we have seen a dramatic increase in costs related to decommissioning activities subsequent to incidents in the Gulf of Mexico in 2010.

We are required to post collateral as security over certain of our decommissioning liabilities in the North Sea. If actual decommission or abandonment costs exceed our estimates or reserves to satisfy such obligations, or if we are required to provide a significant amount of collateral in cash or other security for these future costs, our financial condition, results of operations and prospects could be materially adversely affected. Moreover, applicable governmental authorities may increase the amount of collateral required as security for our North Sea operations. We cannot guarantee that we will be able to post sufficient collateral to secure such costs in the event of an increase in offshore collateral security requirements.

Risks related to our business

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. In addition, oil prices declined severely during the last quarter of 2014 and the first quarter of 2015 and have not rebounded to date. It is unknown if or when they might recover. Prices for Brent have declined from approximately $115.00 per bbl in June 2014 to less than $47.00 per bbl in January 2015. Prices for NBP natural gas in January 2014 traded for approximately $11.00 per mcf compared to prices in January 2015 of approximately $7.00 per mcf.

The U.S. market is heavily impacted by the increased supply from shale drilling, which has served to depress natural gas and oil prices relative to the U.K. market. The price for oil and gas in the U.K. and U.S. is affected by local production as well as by the production from OPEC and other sources. The price in the U.S. is affected by differential pricing reflecting the cost of transportation from the point of production to deliver to the recognized national market hub, such as Henry Hub for gas or WTI for oil. 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.

In part because of recent declines, we expect that we may be unable to comply with certain of the financial covenants in our Amended Credit Facility. Please see “—Risks related to access to capital and financing—Our debt levels could negatively impact our financial condition, results of operations and business prospects.” 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 and reserves. A reduction in production could result in a shortfall in expected cash flows and require us to reduce capital spending or borrow funds to cover any such shortfall. Any of these factors could negatively impact our future rate of growth and ability to replace our production.

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

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

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

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

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

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

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

The exploration, production and sale of oil and gas are extensively regulated by governmental bodies, which subject us to increased costs in order to comply with applicable laws and regulations as well as significant uncertainties due to the potential for such laws and regulations to change and evolve. Applicable legislation and regulations are under constant review for amendment or expansion. These efforts frequently result in an increase in the regulatory burden on companies in our industry and consequently an increase in the cost of doing business and decrease in profitability. Numerous governmental departments and agencies are authorized to, and have, issued rules and regulations imposing additional burdens on the oil and gas industry that often are costly to comply with and carry substantial penalties for failure to comply. Production operations are affected by changing tax and other laws relating to the petroleum

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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. As such, we may become subject to certain requirements, obligations and timelines as established or demanded by the holder of the oil and gas mineral rights and such requirements or obligations may adversely impact our operations, cash flow and capital plans.

We are subject to various governmental energy regulators

Each jurisdiction where we do business has one or more regulatory bodies who regulate our oil and gas business. Examples include the U.K. Department of Energy, the U.S. Bureau of Land Management, the Texas Railroad Commission, the Pennsylvania Department of Environmental Protection, the Colorado Oil and Gas Conservation Commission and the Louisiana Department of National Resources.

The consent of the regulatory bodies is generally required to acquire, develop, license, permit operation and produce oil and gas properties. Consent may be required to sell properties to third parties. Under certain circumstances, consent may be withheld or denied which could adversely impact or prohibit planned operations and activities.

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.

Because global economic growth drives demand for energy from all sources, including fossil fuels, a lower future economic growth rate will result in decreased demand growth for our crude oil and natural gas production as well as lower commodity prices, which will reduce our cash flows from operations and our profitability and may adversely affect our ability to obtain funding for our projects.

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

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

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

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. Larger competitors may also be able to absorb the burden of any changes in laws and regulations more easily than we can, which would also adversely affect our competitive position. In addition, most of our competitors have been operating for a much longer time and have demonstrated the ability to operate through industry cycles.

Our operations are sensitive to currency rate fluctuations.

Our operations are sensitive to fluctuations in foreign currency exchange rates, particularly between the U.S. dollar and the British pound. Our financial statements, presented in U.S. dollars, are affected by foreign currency fluctuations through both translation risk and transaction risk. Volatility in exchange rates may adversely affect our results of operations, particularly through the weakening of the U.S. dollar relative to other currencies.

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 emission and discharge of materials into the environment or otherwise relating to environmental protection. Failure to comply with these laws and regulations can result in the imposition of substantial fines and penalties as well as potential orders suspending or terminating our rights to operate. Some environmental laws to which we are subject to provide for strict liability for pollution damages and cleanup costs, rendering a person liable without regard to negligence or fault on the part of such person. In addition, we may be subject to claims alleging personal injury or property damage as a result of alleged exposure to hazardous substances such as oil and gas related products. Aquatic environments in which we

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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. 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. In addition, current and future environmental regulations, including restrictions on GHG emissions of 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.

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

Governmental regulations to which we are subject could subject us to increased compliance costs, which 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.

We may be exposed to liabilities under the U.S. Foreign Corrupt Practices Act and similar anti-corruption laws, and any determination that we violated such laws could have a material adverse effect on our business.

We are subject to the United States Foreign Corrupt Practices Act of 1977 (the “FCPA”), as amended, and may be subject to similar worldwide anti-bribery laws including the UK Bribery Act 2010 that generally prohibit companies and their personnel and intermediaries from offering, authorizing, or making improper payments to government officials and to other persons or entities for the purpose of obtaining or retaining business, or securing some improper advantage in business. We do business and may do additional business in the future in countries and regions in which we may face, directly or indirectly, corrupt demands by officials, tribal or insurgent organizations, or private entities. As a result, we face the risk that an unauthorized payment or offer of payment could be made by one of our employees or intermediaries, even if such parties are not always subject to our control or are not themselves subject to the FCPA or

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other anti-bribery laws to which we may be subject. It is our policy to implement safeguards to prohibit these practices. However, existing safeguards and any future improvements may not prevent all such conduct, and it is possible that our employees and intermediaries may engage in conduct for which we might be investigated by U.S., UK, or other authorities, and held responsible. Violations of the FCPA and other anti-bribery laws (either due to our acts or our inadvertence) may result in criminal and civil sanctions and could subject us to other liabilities in the U.S., U.K., and elsewhere. Even allegations of such violations could disrupt our business and result in a material adverse effect on our business and operations.

Federal and state legislative regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. We routinely utilize hydraulic fracturing techniques in many of our natural gas well drilling and completion programs. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. However, the EPA recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the SDWA Underground Injection Control Program and issued permitting guidance under the SDWA for such activities. In addition, in May 2014, the EPA issued an Advance Notice of Proposed Rulemaking to collect data on chemicals used in hydraulic fracturing operations under the Toxic Substances Control Act. To date, no other action has been taken. Further, the EPA has announced its intention to propose regulations under the CWA by sometime in 2015 governing wastewater discharges from hydraulic fracturing and certain other natural gas operations.

Furthermore, in April 2012, the EPA adopted regulations requiring the reduction of volatile organic compound emissions from oil and natural gas production facilities by mandating the use of “green completions” for hydraulic fracturing activities. These regulations require the operator to recover rather than vent gas and natural gas liquids that return to the surface during well completion operations. In addition, the EPA is conducting a study of the potential impacts of hydraulic fracturing activities on water resources and a draft final report is anticipated sometime in 2015 for peer review and for public comment. The results of this study or similar governmental reviews could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise. From time to time, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process.

In addition, some states have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations. For example, Pennsylvania, and Colorado have each adopted a variety of well construction, set back, and disclosure regulations limiting how fracturing can be performed and requiring various degrees of chemical disclosure. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular.

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If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, our fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.

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

There are a number of programs at the international, national, and local levels that aim to reduce GHG emissions. Changes to the existing laws or the enactment of new laws and regulations could increase our operating costs and reduce demand for our products. In the North Sea, depending on the scale of our operations, our offshore production facilities may be subject to compliance obligations under the E.U. ETS for GHG emissions. The E.U. ETS places a cap on GHG emissions from certain sources. Sources that emit above their applicable caps must purchase allowances in order to comply with the E.U. ETS. The E.U. has commenced the third phase of the E.U. ETS, running from 2013 to 2020, and therefore our activities in the North Sea are still potentially subject to the impacts of GHG limitations. While allowance prices on the E.U. ETS remain low, the E.U. has approved a proposal to increase allowances prices by deferring the marketability of allowances by withholding a number of allowances from auction, known as “backloading.” Compliance with the above regulations may cause us to incur additional costs in our North Sea operations.

In the U.S., in response to findings that emissions of carbon dioxide, methane and other GHGs, present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, establish PSD construction and Title V operating permit reviews for certain large stationary sources. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA on a case-by-case basis. These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which include certain of our operations. More recently, in January 2015, the Obama Administration announced that the EPA is expected to propose in the summer of 2015 new regulations that will set methane emission standards for new and modified oil and gas production and natural gas processing and transmission facilities as part of the Administration’s efforts to reduce methane emissions from the oil and gas sector by up to 45 percent from 2012 levels by 2025.

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by means of cap and trade programs that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. Substantial limitations on GHG emissions could also adversely affect demand for the oil and natural gas we produce. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our exploration and production operations.

The enactment of derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

On July 21, 2010, new comprehensive financial reform legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”), was enacted that established federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Act requires the U.S. Commodity Futures Trading Commission (“CFTC”), the SEC and other regulators to promulgate rules and regulations implementing the new legislation. In its rulemaking under the Act the CFTC has issued final regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions would be exempt from these position limits. The position limits rule was vacated by the United States District Court for the District of Colombia in September of 2012 although the CFTC has stated that it will appeal the District Court’s decision. The CFTC also has finalized other regulations, including critical rulemakings on the definition of “swap,” “security-based swap,” “swap dealer” and “major swap participant.” The Act and CFTC Rules also will require us in connection with certain derivatives activities to comply with clearing and trade-execution requirements (or take steps to qualify for an exemption to such requirements). In addition new regulations may require us to comply with margin requirements although these regulations are not finalized and their application to us is uncertain at this time. Other regulations also remain to be finalized, and the CFTC recently has delayed the compliance dates for various regulations already finalized. As a result, it is not possible at this time to predict with certainty the full effects that the Act and CFTC rules will have on us and the timing of such effects. The Act also may require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties.

The Act and any new regulations could significantly increase the cost of derivative contracts (including from swap recordkeeping and reporting requirements and through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivatives contract, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Act and regulations, our results of operations may become more volatile and our cash flows

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may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Act and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our business, financial condition, and results of operations.

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

Legislation has been proposed that would, if enacted into law, make significant changes to U.S. federal income tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of this legislation or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could have a material, adverse effect on us, our financial condition and results of operations.

In addition, our U.K. operations are subject to a variety of U.K. taxes, including the Petroleum Revenue Tax and a Supplemental Corporate Tax. The tax laws and rates are subject to change and the nature and amount of taxes owed has a direct effect on our financial results and U.K. production.

Risks related to potential impairments

A sustained period of lower oil and gas prices and other factors may result in ceiling test write-downs or other impairments.

We capitalize the costs to acquire, find and develop our oil and gas properties under the full cost accounting method. The net capitalized costs of our oil and gas properties may not exceed the present value of estimated future net cash flows from proved reserves, plus the lower of cost or fair market value for unproved properties on a country-by-country basis. This quarterly test is called a “ceiling test.” If net capitalized costs of our oil and gas properties exceed this ceiling test, we must charge the amount of the excess to earnings. Although a ceiling test write-down does not impact cash flow from operating activities, it does increase our net loss and stockholders’ deficit. 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

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the end of each quarter or as of the time of reporting our results. We also assess investments in unproved properties periodically to determine whether impairment has occurred.

The risk that we will be required to further write down the carrying value of our oil and gas properties increases when oil and gas prices are low or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves or our unproved property values, if estimated future development costs increase or we do not have the financial certainty to develop our proved undeveloped reserves. Oil prices declined severely during the last quarter of 2014 and the first quarter of 2015. The Brent crude oil price per barrel for the period from January 1, 2014 to January 31, 2015 ranged from a high of $115.00 to a low of $47.00, a decrease of 59.1%, and the NBP natural gas price per mcf for the period January 1, 2014 to December 31, 2014 ranged from a high of $11.00 to a low of $7.00, a decrease of 36.4%. We will likely experience further ceiling test write-downs or other impairments in the future. In addition, any future ceiling test cushion would be subject to fluctuation as a result of acquisition or divestiture activity.

Risks relating to our common stock

The prices of our debt and equity securities are volatile and, in connection with our reorganization, holders of our securities may receive no payment, or payment that is less than the face value or purchase price of such securities.

Prior to our announcement on September 2, 2014 that we had decided not to pay approximately $33.5 million in interest due on our Notes, the market price for our common stock was volatile. Following such announcement, the price of our common stock closed at less than $0.60 per share and was subsequently delisted from the New York Stock Exchange (“NYSE”) on October 13, 2014. After our delisting, our common stock has been trading on the Over the Counter (“OTC”) market under the symbol “ENDRQ.” Prices for our debt securities are also volatile and prices for such securities have generally been substantially below par following our bankruptcy filing.

In addition, following the delisting of our common stock from the NYSE, our equity securities are not listed on a public exchange. Accordingly, trading in our equity securities may be limited and holders of our securities may not be able to resell their securities for their purchase price or at all. We can make no assurance that the price of our securities will not fluctuate substantially in the future.

Under the terms of the RSA Plan (or any alternative plan of reorganization) , it is contemplated that all of the outstanding shares of our common and preferred stock and warrants would be cancelled, and holders of such securities would not be entitled to any payment in respect of their shares. In addition, new shares of our common stock may be issued. It is also possible that our obligations to holders of debt or preferred equity securities of Endeavour may be satisfied by payments to such holders that are less than both the par value of such securities and the price at which holders purchased such securities, or that shares of our common stock may be issued to certain of such holders in satisfaction of their claims. The value of any common stock so issued may be less than the par value or purchase price of such holders’ securities, and the price of any such common shares may be volatile.

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Accordingly, trading in our securities during the pendency of our Bankruptcy Cases is highly speculative and poses substantial risks to purchasers of such securities, as holders may not be able to resell such securities or, in connection with our reorganization, would receive no payment, or a payment or other consideration that is less than the par value or the purchase price of such securities.

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.

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The following table shows the results of the oil and gas wells in which we participated, drilled and tested during 2014, 2013 and 2012:



	Productive Wells		Dry Holes		In Progress Wells
	Gross	Net	Gross	Net	Gross	Net
Exploration
2014:
United Kingdom	—	—	—	—	—	—
United States	1.00	0.72	2.00	0.50	—	—

2013:
United Kingdom	—	—	1.00	0.33	—	—
United States	—	—	—	—	3.00	1.21

2012:
United Kingdom	—	—	—	—	—	—
United States	—	—	—	—	4.00	1.00

Development
2014:
United Kingdom	2.00	0.51	—	—	—	—
United States	3.00	1.50	—	—	2.00	1.00

2013:
United Kingdom	5.00	1.69	—	—	—	—
United States	—	—	—	—	3.00	1.50

2012:
United Kingdom	4.00	1.11	—	—	1.00	0.44
United States	2.00	0.66	—	—	3.00	3.00

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, 2014, our productive wells included the following:



	Oil Wells		Gas Wells
	Gross	Net	Gross	Net
United Kingdom	34	7.7	2	0.9
United States	4	1.4	44	13.7
Total	38	9.1	46	14.6

Reserves

Proved Reserves

Our proved oil and gas reserves at December 31, 2014, 2013 and 2012 included the following:



	Oil	Gas	Oil Equivalents
	(mbbls)	(mmcf)	(mboe)(1)
2014:
United Kingdom	5,963	24,183	9,994
United States	75	13,055	2,251
	6,038	37,238	12,245
2013:
United Kingdom	12,340	55,398	21,573
United States	2	11,775	1,965
	12,342	67,173	23,538
2012:
United Kingdom	13,733	56,901	23,217
United States	6	14,690	2,454
	13,739	71,591	25,671

⁽¹⁾

Mboe is calculated as mbbls plus mmcf divided by 6.

At December 31, 2014, the Alba field, in the U.K. North Sea, represented approximately 24% of our proved reserves. Alba had 2.9 mmboe, 9.2 mmboe and 9.9 mmboe of our proved reserves at December 31, 2014, 2013 and 2012, respectively. For more information, refer to the “Sales Volumes and Prices” section below.

The Rochelle field represented more than 41% of our proved reserves at December 31, 2014, 2013, and 2012. Rochelle had 5.0 mmboe, 8.9 mmboe and 9.0 mmboe of proved reserves at December 31, 2014, 2013 and 2012, respectively. For more information, refer to the “Sales Volumes and Prices” section below.

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Proved Developed and Undeveloped Reserves

Our proved undeveloped reserves are primarily related to our development projects in the U.K. and the results of successful exploration drilling in the U.S. Our proved developed and undeveloped oil and gas reserves at December 31, 2014, 2013 and 2012 included the following:



	Proved	Proved	Total
	Developed	Undeveloped	Proved
	Reserves	Reserves	Reserves
	(mboe)	(mboe)	(mboe)
2014:
United Kingdom	9,775	219	9,994
United States	1,984	267	2,251
	11,759	486	12,245

2013:
United Kingdom	8,723	12,850	21,573
United States	1,634	331	1,965
	10,357	13,181	23,538

2012:
United Kingdom	5,785	17,432	23,217
United States	2,454	—	2,454
	8,239	17,432	25,671

The following table is a reconciliation of the changes in our proved undeveloped (“PUD”) reserves:



	United Kingdom	United States	Total
Proved Undeveloped Reserves (mboe):
Proved undeveloped reserves at December 31, 2014	219	267	486
Transfers to proved developed	(7,030)	—	(7,030)
Revision of previous estimates	(5,601)	(64)	(5,665)
Proved undeveloped reserves at December 31, 2013	12,850	331	13,181
Additions	—	331	331
Transfers to proved developed	(4,582)	—	(4,582)
Proved undeveloped reserves at December 31, 2012	17,432	—	17,432

PUD reserves decreased from 13.2 mmboe at December 31, 2013 to 0.5 mmboe at December 31, 2014 due to:

The continuation of development drilling at Rochelle and Alba during 2014 resulted in transferring 7.0 mmboe of PUD reserves to proved developed reserves.

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The transfer of 8.0 mmboe of PUD reserves to probable undeveloped reserves. The transferred reserves are economically producible at December 31, 2014 and had they remained classified as proved would have had a standardized measure of discounted future net cash flows of approximately $75 million. The decision to transfer these PUD reserves was solely based on uncertainties that exist around the financing required to fund our participation in the development of these PUD reserves within five years of initial booking due to our filing of Chapter 11 under the Bankruptcy Code and the potential consequences resulting from our anticipated breach of our leverage covenant under our Amended Term Loan Facility which are further discussed in “Item 1. Business” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The transfer of all PUD reserves related to our Columbus field of 1.8 mmboe were reclassified to contingent resources as of December 31, 2014 as a final offtake solution has not been determined and a revised field development plan has not yet been approved.

PUD reserves in the U.K. decreased from 17.4 mmboe at December 31, 2012 to 12.9 mmboe at December 31, 2013 primarily due to development drilling at Rochelle and its initial production transferring PUD reserves to proved developed reserves. PUD reserves in the U.S. increased from none at December 31, 2012 to 0.3 mmboe at December 31, 2013 primarily due to higher U.S. gas pricing resulting in some undrilled locations becoming economic. During 2012, we invested approximately $182 million to convert our PUD and probable reserves to proved developed reserves primarily in the following areas:

Initial development operations at the Bacchus field were completed and the field commenced first production in the middle of 2012 as the first of three development wells came online. Additional development drilling was completed during 2013 with the third development well.

Development operations at the Rochelle field continued throughout 2012 and 2013 with the drilling of the E2 and W1 development wells, installation of the subsea infrastructure and the Scott brownfield modifications. Production started in October 2013.

The Alba field has historically completed infill drilling programs that moved PUD reserves to proved developed reserves. The Alba field completed two, three and two infill wells during 2014, 2013 and 2012, respectively.

See Note 7 to our consolidated financial statements in “Item 8. Financial Statements and Supplementary Data” for additional information on the costs associated with our proved developed reserves and PUD reserves.

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Probable Reserves

Our probable oil and gas reserves at December 31, 2014 included the following:



Probable Reserves at December 31, 2014
	Oil	Gas	Oil Equivalents
	(mbbls)	(mmcf)	(mboe)
Developed:
United Kingdom	6,707	4,276	7,420
United States	91	2,696	540
	6,798	6,972	7,960

Undeveloped:
United Kingdom	7,684	24,813	11,820
United States	—	35,332	5,889
	7,684	60,145	17,709

Total Probable:
United Kingdom	14,391	29,089	19,240
United States	91	38,028	6,429
	14,482	67,117	25,669

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 and probable 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 Managing Director - UK and Executive Vice President –North America. Reserves are reviewed internally with senior management quarterly and with our Board of Directors on an annual basis.

Our oil and gas reserve estimates were prepared by our internal reservoir engineers and audited by our independent reserve engineers, Netherland, Sewell & Associates, Inc. (“NSAI”).

Each year, our internal technical staff evaluates all technical data available on each field, including production data, well 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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Qualification of Reserves Preparers and Auditors

We employ oil and gas technical professionals, including geophysicists, petrophysicists, geologists, and reservoir engineers, who have 10 to 35 years of experience in their technical fields. Our Director Reservoir Engineering – UK, Mr. Alan Booth, who has 35 years of experience in the oil industry, is responsible for the preparation of our oil and gas reserve estimates and supervises our technical professionals in the evaluation and estimation of our oil and gas reserves. Mr. Booth graduated from Leeds University with a Bachelor of Science degree in Physics in 1980 and has broad experience covering field appraisal, developments, producing assets and exploration both in the U.K. and Norway. In addition, we engage experienced and qualified employees to perform various comprehensive seismic acquisitions, processing, reprocessing, interpretation, and other related services.

The reserves estimates shown herein have been independently audited by NSAI, a worldwide leader of petroleum property analysis for industry and 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-2699. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Derek Newton and Mr. David Nice. Mr. Newton has been practicing consulting petroleum engineering at NSAI since 1997. Mr. Newton is a Licensed Professional Engineer in the State of Texas (No. 97689) and has over 30 years of practical experience in petroleum engineering, with over 17 years’ experience in the estimation and evaluation of reserves. He graduated from University College, Cardiff, Wales, in 1983 with a Bachelor of Science Degree in Mechanical Engineering and from Strathclyde University, Scotland, in 1986 with a Master of Science Degree in Petroleum Engineering. Mr. Nice has been practicing consulting petroleum geology at NSAI since 1998. Mr. Nice is a Licensed Professional Geoscientist in the State of Texas, Geology (No. 346) and has over 30 years of practical experience in petroleum geosciences, with over 16 years’ experience in the estimation and evaluation of reserves. He graduated from University of Wyoming in 1982 with a Bachelor of Science Degree in Geology and in 1985 with a Master of Science Degree in Geology. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

NSAI opined that the overall proved and probable reserves for the reviewed properties as estimated by us are, in the aggregate, reasonable and conform to the SEC’s definitions of proved and probable reserves as set forth in Rule 210.4-10(a) of Regulation S-X. Proved reserves are reserves which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expires, unless evidence indicates that renewal is reasonably certain. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil or natural gas actually recovered will equal or exceed the estimate. To achieve reasonable certainty, we and the independent reserve engineers employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and

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economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps and available downhole and production data, micro seismic data and well test data. Probable reserves are reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Estimates of probable reserves which may potentially be recoverable through additional drilling or recovery techniques are by nature more uncertain than estimates of proved reserves and accordingly are subject to substantially greater risk of not actually being realized by us. Estimates of probable reserves are also continually subject to revisions based on production history, results of additional exploration and development, price changes and other factors.

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:

the appropriateness of the methodologies employed;

the adequacy and quality of the data relied upon;

the depth and thoroughness of the reserves estimation process;

the classification of reserves appropriate to the relevant definitions used; and

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.

Acreage

The following table sets forth certain information regarding our developed and undeveloped acreage as of December 31, 2014, in the areas indicated.



	Developed		Undeveloped
	Gross	Net	Gross	Net
United Kingdom	83,019	35,567	393,104	186,134
United States	9,464	4,525	290,746	79,295

Total	92,483	40,092	683,850	265,429

As of December 31, 2014, we had approximately 3,500, 138,200 and 47,300 net acres in the U.K. that are scheduled to expire by December 2015, 2016 and 2017, respectively, if we take no operational or administrative actions to continue the term of the underlying licenses.

As of December 31, 2014, we had approximately 29,800, 149,300 and 57,500 net acres in the U.S. that are scheduled to expire by December 2015, 2016 and 2017, respectively, if we take no

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operational or administrative actions to continue the term of the underlying licenses. This includes all of our acreage in Alabama, where we have 8,800 net acres and have suspended operations. It also includes approximately 8,400 net acres in Montana that will expire in 2015, where we have also suspended operations. We have a total of 37,100 net acres in Montana.

For our other acreage in the U.S. and U.K., we currently have plans to continue the terms of various licenses through operational or administrative actions and do not expect a significant portion of our net acreage position to expire before such actions occur.

Sales Volumes and Prices

Information regarding our annual average sales volumes, sales prices and average production costs is contained in Item 7 of this Annual Report on Form 10-K. Additional detail of production costs is contained in Note 29 to our consolidated financial statements under Item 8 of this Annual Report on Form 10-K.

At December 31, 2014, the Alba field, in the U.K. North Sea, represented approximately 24% of our proved reserves. The Alba field represented 1,314 mbbls, 1,612 mbbls and 1,263 mbbls of our oil sales in 2014, 2013 and 2012, respectively.

At December 31, 2014, the Rochelle field, in the U.K. North Sea, represented more than 41% of our proved reserves. Rochelle is a gas condensate field that began producing in late 2013 and represented 6,248 mmcf of our gas sales and 450 mbbls of our oil sales in 2014.

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.

Voluntary Reorganization under Chapter 11

On October 10, 2014, Endeavour and certain of our wholly owned U.S. subsidiaries – Endeavour Operating Corporation, Endeavour Colorado Corporation, Endeavour Energy New Ventures, Inc., and END Management Company - and one of our foreign subsidiaries - Endeavour Energy Luxembourg S.à.r.l. - filed voluntary petitions under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware. The Chapter 11 cases are being jointly administered by the Bankruptcy Court as Case No. 14-12308. We intend to continue to operate its business as debtor-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. As a result of the filings, attempts to collect, secure, or enforce remedies with

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respect to pre-petition claims against the Company are subject to the automatic stay provisions of section 362 of the Bankruptcy Code.

On December 16, 2015, William Transier, our former President and Chief Executive Officer and current Chairman of the Board of Directors, filed two claims against the Debtors in the bankruptcy proceedings described above. Mr. Transier is seeking to (i) obtain the pro-rated portion of his bonus owed for the year ended December 31, 2014 in the amount of $0.7 million and (ii) obtain severance compensation owed as a result of his resignation as President and Chief Executive Officer in the amount of $5.5 million.

The Bankruptcy Cases are discussed in greater detail in “Business,” Management’s Discussion and Analysis of Financial Condition and Results of Operations — Voluntary Reorganization under Chapter 11” and Note 3 - Voluntary Reorganization under Chapter 11 to our Consolidated Financial Statements. Additionally, further information pertaining to our bankruptcy filings may be obtained through our website at www.endeavourcorp.com. The content of the foregoing website is not a part of this report.

Terminated Acquisition of Marcellus Assets

On July 17, 2011, we entered into agreements with SM Energy Company and certain other sellers named therein (“SM Energy”) for the purchase of oil and gas leases, producing properties, geophysical data, a pipeline and related assets in the Marcellus shale play in Pennsylvania for aggregate consideration of approximately $110 million (the “SM Purchase Agreements”). We terminated the agreements on December 14, 2011, based on our conclusion that (i) the title defects we identified, after analyzing SM Energy’s responses to the notice of defects and valuation of the defects; and (ii) the condition of the pipeline was not in compliance with applicable regulatory standards.

SM Energy filed a lawsuit against us in Texas state court on December 20, 2011 alleging that we breached the SM Purchase Agreements by terminating them and refusing to close on the transactions.

On April 16, 2014, we reached an agreement with SM Energy to settle and dismiss the litigation. In accordance with the settlement agreement, we:

forfeited our $6 million deposit;

paid SM Energy $5 million;

will pay an additional $4.5 million in three graduated payments, beginning in April 2015; and

issued warrants to purchase 2.1 million shares of our common stock with exercise price of $5.29 per share.

As a result of this settlement, we recorded $19.0 million in total settlement expense during the first quarter of 2014.

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Item 4. Mine Safety Disclosures

Not applicable.

Part II

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

On October 13, 2014, our common stock was delisted from the NYSE. Prior to delisting, our stock traded under the symbol “END” on the NYSE and “ENDV” on the London Stock Exchange. After our delisting, our common stock has been trading on the OTC market under the symbol “ENDRQ.”

Historical Stock Prices

The following table sets forth the range of high and low prices per share of our common stock for each of the calendar quarters identified below as reported by the NYSE through October 7, 2014, and the high and low bid prices as reported on the OTC market commencing on October 13, 2014. These quotations represent inter-dealer prices, without retail mark-up, markdown or commission, and may not represent actual transactions.



	2014				2013
	High		Low		High		Low
First Quarter	$	6.89	$	3.16	$	6.11	$	2.42
Second Quarter		3.44		1.04		3.89		2.56
Third Quarter		1.48		0.26		5.82		3.70
Fourth Quarter		0.25		0.01		7.31		4.27

Holders

As of March 13, 2015, the number of holders of record of our common stock was 120. We believe that there are a number of additional beneficial owners of our common stock who hold such shares in street name.

Dividends

We have not paid any cash dividends on our common stock to date and have no intention of declaring or paying any cash dividends on our common stock in the foreseeable future. The declaration and payment of dividends is subject to the discretion of our Board of Directors and to certain limitations imposed under Nevada corporate laws and the agreements governing our debt obligations. The timing, amount and form of dividends, if any, will depend on, among other

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things, our results of operations, financial condition, cash requirements and other factors deemed relevant by our Board of Directors.

Our Series B preferred stock is subject to a cumulative 8% dividend (the “Series B Preferred Stock”). Unless the full amount of the foregoing dividends accrued for the Series B Preferred Stock is paid in full, we cannot declare or pay any dividend on our common stock. In addition, certain of our debt facilities contain restrictions on the payment of dividends to the holders of our common stock.

Our Series C Preferred Stock is subject to a cumulative dividend, payable in cash or common stock at 4.5% or 4.92%, respectively. Dividends on the Series C Preferred Stock also participate in any dividends paid on our common stock and are payable to the preferred stock investors prior to payment of any other dividend on any other shares of our capital stock.

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 do not maintain the effectiveness of the registration statement, 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.

Item 6. Selected Financial Data

The following table sets forth some of our historical consolidated financial data for each of the five years ended December 31, 2014. Significant property acquisitions and dispositions during these periods have materially affected the comparability of our year-to-year financial data.

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.”

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The selected consolidated financial data provided below are not necessarily indicative of our future results of operations or financial performance.



Summary Financial Data (1)
(Amounts in thousands, except per share data)		Year Ended December 31,
		2014		2013		2012		2011		2010
Summary Income Statement Data:
Revenues	$	316,032	$	337,664	$	219,058	$	60,091	$	71,675
Operating Profit (Loss)		(686,702)		60,482		19,801		(67,614)		1,327
Net Income (Loss) to Common Shareholders		(841,584)		(97,302)		(128,049)		(132,969)		54,304

Net Income (Loss) Per Common Share
Basic	$	(16.61)	$	(2.07)	$	(3.01)	$	(3.70)	$	1.95

Diluted	$	(16.61)	$	(2.07)	$	(3.01)	$	(3.70)	$	1.95

Summary Balance Sheet Data:
Working Capital (Deficit)	$	(364,691)	$	(61,559)	$	(39,605)	$	38,351	$	71,145
Total Assets		734,576		1,524,842		1,442,472		924,991		750,287
Current Maturities of Debt, Net of Discount (2)		432,181		—		—		—		—
Long-Term Debt, Net of Discount (3)		—		870,878		859,506		467,378		345,306
Liabilities Subject to Compromise (4)		841,044		—		—		—		—
Convertible Preferred Stock		17,481		43,703		43,703		43,703		53,152
Equity (Deficit)		(776,141)		18,388		99,431		154,079		154,618

⁽¹⁾

Includes the following:

goodwill impairment loss of $259.2 million in 2014;

oil and gas impairments of $476.7, $9.6 million, $53.1 million, $65.7 million, and $7.7 million, in 2014, 2013, 2012, 2011, and 2010, respectively;

unrealized gains (losses) on derivatives of $10.8 million, $(1.8) million, $5.1 million, $8.4 million, and $12.3 million in 2014, 2013, 2012, 2011, and 2010, respectively;

acquisition of an additional 23.43% interest in the Alba field in 2012;

acquisition of producing properties and exploration acreage in the U.S. in 2010; and

disposition of our interests in the Cygnus reserves in 2010 for a gain of $87.2 million.

⁽²⁾

The balance at December 31, 2014 represents the outstanding balance related to the Amended Term Loan Facility, net of discount. We anticipate a breach of our leverage covenant in or about the third quarter of 2015, which will result in a default under the terms of the Amended Term Loan Facility and a liquidity shortfall at the end of the fourth quarter of 2015. Based on this determination, we have classified the outstanding balance of the Amended Term Loan Facility as a current liability.

⁽³⁾

As of December 31, 2014, all long-term debt affected by the Chapter 11 process has been reclassified to the balance sheet line item “Liabilities Subject to Compromise.”

⁽⁴⁾

The balance at December 31, 2014 represents liabilities incurred prior to the Petition Date which may be affected by the Chapter 11 process. These amounts represent the Debtors’ allowed claims and their best estimate to be allowed which will be resolved as part of the bankruptcy proceedings.

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 independent oil and gas company engaged in the production, exploration, development and acquisition of crude oil and natural gas in the U.K. North Sea and U.S. onshore. Our U.K. operations have been focused on development projects and acquisition, while capital spending by our U.S. operations is primarily related to strategic positioning and proof-of-concept in Marcellus and Niobrara as we monitor U.S. gas prices. Since 2010, our primary focus has been on completing the acquisition of additional interests in both the Bacchus and Alba fields and then moving the Bacchus and Rochelle fields from development to first production. We closed on the Bacchus and Alba acquisitions in 2011 and 2012, respectively, and achieved first production at Bacchus during the second quarter of 2012. We achieved production at Rochelle during the fourth quarter of 2013.

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

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Voluntary Reorganization under Chapter 11

On September 2, 2014, although the Company had sufficient cash, we decided that it was in the best interest of all stakeholders, debt and equity, to expeditiously address the Company's capital structure with the goal of reducing debt and the cost of capital to position the Company for the future and announced that we had decided not to pay approximately $33.5 million in interest due on September 2, 2014 on our Notes. The Company used a 30-day grace period to continue discussions with our debt providers.

Ultimately, consensus was obtained on a long-term future plan for the Company from a significant majority of our debt holders. On October 10, 2014, the Company announced that it reached agreements with its Consenting Debt Holders, in the form of a consensual RSA that, if implemented as proposed, would significantly reduce the Company’s outstanding debt. The RSA contemplated that the recapitalization of the Company would occur pursuant to a pre-arranged plan of reorganization. On the Petition Date, Endeavour and its affiliated Debtors filed voluntary petitions under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Chapter 11 cases are being jointly administered by the Bankruptcy Court as Case No. 14-12308.

Since the Petition Date, the Debtors have operated their business as “debtors-in-possession” pursuant to Sections 1107(a) and 1108 of the Bankruptcy Code, which will allow us to continue operations and carry on the business in the ordinary course during the reorganization proceedings. Each Debtor will remain in possession of its assets and properties, and its business and affairs will continue to be managed by its directors and officers, subject in each case to the supervision of the Bankruptcy Court.

None of our subsidiaries or affiliates incorporated in the U.K. has filed under Chapter 11. Such non-filing subsidiaries and affiliates are called “non-Debtors.”

On November 17, 2014, we filed with the Bankruptcy Court a plan of reorganization (the “RSA Plan”) and related disclosure statement (the “Disclosure Statement”) to implement the terms of the RSA. The RSA Plan, if implemented as proposed, would significantly reduce our outstanding debt and recapitalize Endeavour.

The RSA provides for milestones for consummation and implementation of the consensual restructuring including:

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consummation of the confirmed plan no later than 200 days after the Petition Date (or Tuesday, April 28, 2015, as calculated under the Bankruptcy Rules).

The RSA Plan provides that the Company’s existing debt and accrued interest will be reduced by approximately $568 million, including the cancellation of all of the Company’s First Priority Notes, Second Priority Notes, 7.5% Convertible Bonds, 5.5% Convertible Senior Notes and 6.5% Convertible Senior Notes. As consideration for such cancellation, the reorganized Company would issue:

$262.5 million of new notes to the holders of its First Priority Notes;

an aggregate of approximately $237.5 million of new convertible preferred shares to holders of its First Priority Notes and Second Priority Notes; and

new common shares to holders of its Second Priority Notes, 6.5% Convertible Senior Notes, 7.5% Convertible Bonds and 5.5% Convertible Senior Notes.

All of our existing equity securities, including our shares of common stock and preferred stock and warrants, would be cancelled without receiving any distribution.

On the Petition Date, the Company sought, and thereafter obtained, authority to take a broad range of actions, including, among others, authority to pay royalty interests and joint interest billings, certain employee obligations and pre-Petition contractor claims and taxes. Additionally, other orders were obtained, including adequate assurance of payment to utility companies as well as continued use of cash management systems.

Notice of Adjournment

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We have and continue to engage in discussions with certain of our U.S. and U.K. creditors regarding the possibility of raising new capital to reduce the principal amount of outstanding indebtedness under the Amended Term Loan Facility in an amount adequate to avoid a potential default of the leverage covenant, refinancing all or a portion of the Amended Term Loan Facility, or obtaining a waiver or amendment from the lenders under the Amended Term Loan Facility prior to any default thereunder, or to sustain a restructuring and avoid default..

There can be no assurance that a reduction, refinancing, waiver or amendment of the Amended Term Loan Facility could be accomplished. If we are not able to reach a satisfactory agreement with certain of our U.S. and U.K. creditors and are unable to refinance the Amended Term Loan Facility, which is not possible without financial support from certain of our U.S. or U.K. creditors, we may be compelled, either voluntarily or involuntarily, into liquidation of our U.K. operations through an administration proceeding in the U.K., in addition to any Chapter 11 or Chapter 7 liquidation proceeding in the U.S.

Liquidity and Capital Resources

Financial Covenant Compliance

We are, and expect to continue to be, required to comply with certain financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control. Our cash flow is highly dependent on the prices we receive for oil and natural gas, which declined significantly in recent months. If oil and gas prices remain at their depressed levels, we currently anticipate a breach of our leverage covenant under our Amended Term Loan Facility applicable to our U.K. subsidiary in or about the third quarter of 2015, which will result in a default under the terms of the Amended Term Loan Facility and a liquidity shortfall at the end of the fourth quarter of 2015. We are evaluating various alternatives with respect to our Amended Credit Agreement, but there is no certainty that we will be able to implement any alternatives or otherwise resolve our covenant issues. If an event of default occurs, and the lenders under the Amended Credit Agreement accelerate the maturity of any loans, we would not have sufficient liquidity to repay all of our outstanding indebtedness without new financing. Acceleration of debt of this magnitude would likely result in a further reorganization, other restructuring or liquidation.

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Capital Expenditures

Our capital expenditures and acquisitions net of the impact of changes in asset retirement obligations were as follows:



	Year Ended December 31,
(Amounts in thousands)	2014		2013		2012
Direct Oil & Gas Capital Expenditures:
U.K.	$	41,709	$	160,499	$	174,138
U.S.		14,820		6,114		14,271
		56,529		166,613		188,409
Acquisitions		3,654		2,787		192,214
		60,183		169,400		380,623
Capitalized G&A, Interest and Other		21,355		36,308		49,215
Increase (Decrease) in Asset Retirement Obligations		(41,138)		(2,433)		137,675
Total Capital Expenditures and Acquisitions, Net	$	40,400	$	203,275	$	567,513
Asset Retirement Obligations Paid	$	49,418	$	27,690	$	8,521

North Sea Acquisition

In May 2012, we closed on the purchase of an additional 23.43% interest in the Alba field from a third party (the “Alba Acquisition”). This increased our total working interest in the Alba field to 25.68%. The Alba Acquisition was closed for aggregate cash consideration of approximately $229.6 million.

Concurrently with the closing of the Alba Acquisition, we entered into a reimbursement agreement related to approximately $120 million of abandonment liabilities for the Alba field. Under the agreement, we agreed to reimburse the issuers of letter of credit covering our abandonment liabilities in the event that the letter of credit is drawn. We paid a fee of 13% per year, payable quarterly, computed based on the outstanding amount of each letter of credit. As of December 31, 2014, we do not expect to begin decommissioning activities for the Alba field for many years. Additional information pertaining to the reimbursement agreement can be found in Note 24 - Commitments and Contingencies.

On January 24, 2014, we also entered into a letter of credit procurement agreement (the “Combined Procurement Agreement”) with an unaffiliated third party (“Payee”), where we agreed to reimburse the Payee for any expense incurred by it in connection with the posting of cash collateral to secure letters of credit issued for our account in the amount of approximately £78 million (approximately $130 million as of January 24, 2014). The letters of credit secure decommissioning obligations in connection with certain of our U.K. licences and have been outstanding and unchanged since 2006. The Combined Procurement Agreement was entered into to replace the Alba Reimbursement Agreement and the LOC Procurement Agreement. The Combined Procurement Agreement was replaced by the Amended Term Loan Facility on September 30, 2014. Additional information can be found in Note 12 - Debt Obligations.

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Due to a change in the U.K. tax treatment for decommissioning in 2013, we have amended our Decommissioning Securities Agreement for the Alba field. The new tax law, which allows companies to treat decommissioning on an after-tax basis (including PRT), enabled us to reduce our letter of credit amount on the Alba field from $120 million to approximately $55 million.

United Kingdom Capital Program

Our capital program in the U.K. for 2014, 2013 and 2012 was focused on two large projects in the North Sea, the Bacchus and Rochelle fields which are now complete, as well as infill drilling at the Alba field.

Alba

In May 2012, we acquired an additional 23.43% interest in the Alba field, which increased our total working interest in the field to 25.68%. Alba has a one to two well per year drilling campaign. In 2014 we completed one development well which spud during the second quarter of 2014, and first production began in August 2014. The Alba 2014 exit rate was approximately 17,300 barrels per day gross. An additional development well is scheduled to be drilled during 2015.

The operator identified that the water injection pipeline supplying pressure to the southern area of the field ruptured, causing a portion of the wells in the southern region to be shut-in. Partial subsea water injection was restored in May 2014 allowing some wells to be returned to production. The permanent replacement of the pipeline began in March 2015. The permanent replacement will resume production from all subsea wells, which is expected in May 2015. We have made an insurance claim to recover certain loss of production and replacement costs, and received $13 million in December 2014 as an interim settlement. The claims remain in progress for potential additional recoveries, which is estimated to be in the range of $10 million to $15 million.

Bacchus

At December 31, 2014, we held a 30% working interest in our Bacchus field asset, and oil field. In 2012, we achieved production from the first two development wells and the third well was completed in July 2013. During the third quarter of 2013, a 3D seismic survey was shot over the Bacchus field to identify additional Bacchus development opportunities. The field has experienced a slower decline curve than originally forecasted. Currently there are two gas-lifted wells producing, and the Bacchus 2014 exit rate was approximately 6,300 boed gross.

Rochelle

Our working interest in the Rochelle field, a gas-condensate field, is 44%. Development drilling and subsea tie-ins have been underway since 2012. In February 2013, following a severe storm lasting several days, we performed a routine inspection of the conductor, wellhead and blow out preventer systems which revealed that a non-uniform hole had formed around the conductor. As a result of this finding, the E1 well was plugged and abandoned. We have recovered certain abandonment and redrill costs through insurance, receiving $12.6 million in 2014.

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To mitigate delays while we conducted our analysis of the East Rochelle well, we moved the rig to the West Rochelle area and commenced drilling of the second production well. Drilling began on the West Rochelle W1 well in the first quarter of 2013 and it was completed and flow tested in June 2013.

Following the Scott Platform shutdown from July 11 to September 5, 2013, first production from the West Rochelle W1 well started on October 23, 2013. The Transocean Prospect rig returned to the Rochelle field and commenced drilling the second Rochelle development well (E2 well at East Rochelle) on July 25, 2013 and was completed in November 2013. The E2 well was tied-in to the East Rochelle manifold in December 2013 but due to continued periods of inclement weather in the U.K. North Sea start-up could not commence until mid-January 2014.

First production from Rochelle was achieved in October 2013, and by January 2014, both the E2 and W1 development wells at Rochelle were fully completed and tied-in to the production manifolds. Since completion, Rochelle has experienced significant downtime, both planned and unplanned. As part of the final installation and start-up of the E2 well, the W1 well was shut-in. During the well start-up procedure, a valve on the outlet side of the East Rochelle production manifold was stuck in the “shut” position. An attempt to open the valve manually was unsuccessful and the operator secured an intervention vessel to open the valve. The valve was successfully opened in February 2014. The E2 well commenced production on February 28, 2014 and the W1 well restarted production in March 2014.

As a result of these events Rochelle was down for approximately five months during 2014, all of which was out of our control. This downtime negatively affected our production rates and associated revenue for 2014, as well as our near-term liquidity. When both E2 and W1 wells are producing, the production from the Rochelle field is able to exceed the available production capacity at the Scott Platform. The Rochelle 2014 exit rate was approximately 8,600 boed gross. During January 2015 when Rochelle was producing, the production rate has been approximately 8,500 boed gross.

Rochelle was-shut in again on January 31, 2015 for a planned seven day shutdown to tie-in an additional compressor on the Scott Platform to increase reliability. Issues with the existing compressor and mechanical issues at the platform delayed the restart. As a result, Rochelle had approximately six weeks of downtime during the first quarter of 2015.

If we continue to experience unanticipated downtime, our future daily production rates and associated revenue and near-term liquidity could also be negatively impacted.

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United States Capital Program

Our primary focus in the U.S. has been onshore unconventional oil and gas developments. During 2011, we completed 16 productive wells, and had an additional eight wells, awaiting on completion. During 2012, we completed two Haynesville gas wells. With declining U.S. gas prices, we have limited our capital expenditures in 2013 and 2014 to primarily those expenditures necessary to maintain our acreage positions and fulfill minor drilling commitments.

Marcellus

During 2014, we successfully completed hydraulic fracture stimulations of the C-13, C-14 and C-20 horizontal wells. The operations consisted of an average 28-stage frac for each well, or double the number of frac stages on the longest laterals to date, relative to our previous wells. Initial flowback rates for the C-14 and C-20 wells were in the range of 4.5 mmcfd to 6.5 mmcfd gross each. These wells were tied to a new pipeline constructed by EQT Corporation that allows firm capacity up to 10 mmcfd, with potential for future expansion. Construction of the Daniel Field Gathering pipeline was completed in December 2014 at which time first gas commenced. Operatorship of our Pennsylvania Marcellus properties was transferred to Samson on July 1, 2014.

Niobrara Play

In the Piceance Basin Rim play in Northwest Colorado, Endeavour has leasehold of approximately 33,500 gross and 20,700 net acres with drilling rights to earn an additional estimated 10,000 net acres. Endeavour has two projects targeting liquids-rich Niobrara and Frontier objectives. The Company has formed two federal units and drilled an initial horizontal test in the Niobrara target zone during third quarter of 2014. The first of those wells is the Wiley 23-3-97 H1 horizontal well in Rio Blanco County (“Wiley well”), which spud in July 2014, reached total depth in August 2014 and was hydraulically fracture stimulated in October 2014. In November to December 2014, a 23-day average flowback rate of 602 barrels of oil per day gross plus 1.3 to 1.8 mmcfd was achieved, with a peak daily oil rate of 805 barrels of oil per day

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gross. In December 2014, we shut in the Wiley well to complete the production facilities and gas pipeline tie-in. Production resumed in late March 2015.

Liquidity



	Year Ended December 31,
(Amounts in thousands)	2014		2013		2012
Net cash provided by operating activities	$	67,887	$	57,448	$	38,613
Net cash used in investing activities	$	(175,259)	$	(221,768)	$	(484,550)
Net cash provided by financing activities	$	154,480	$	139,877	$	399,086

Our primary sources of financial resources and liquidity are funds generated from the sale of natural gas and crude oil production and the credit and capital markets.

Operating Activities

The net cash flows provided by operating activities are primarily impacted by the earnings from our business activities and changes in working capital. The net cash flows provided by operating activities were $67.9 million for the year ended December 31, 2014 compared to $57.4 million provided by operating activities for the year ended December 31, 2013, an increase of $10.5 million.

Cash flow provided by operations increased to $57.4 million for 2013 from $38.6 million for 2012 due to cash flows from our purchase of the additional interest in Alba.

We are primarily dependent upon our three fields in the U.K. – Alba, Bacchus and Rochelle – for our cash flows from operations. If we incur delays in production, such as those resulting from the mechanical issues experienced at the Rochelle field during 2014 and the subsequent unplanned shutdowns at the Scott Platform discussed in “Drilling Program,” it will negatively impact our operating cash flows.

During the pendency of the Bankruptcy Cases, we expect that our primary sources of liquidity will continue to be cash on hand, cash flows from operations and insurance proceeds. In part as a result of the recent decline in commodity prices, our cash flows from operations have decreased and may not be sufficient to fund our liquidity needs. In addition, the negative covenants under the Amended Term Loan Facility (see “Financing Activities” below) restrict us from obtaining additional capital, including limits on intercompany transfers.

In addition to the cash requirements necessary to fund ongoing operations, we have incurred and continue to incur significant professional fees and other costs in connection with preparation and handling of the Bankruptcy Cases. We anticipate that we will continue to incur significant professional fees and costs for the pendency of the Bankruptcy Cases. Pursuant to the terms of the RSA, we are obligated to pay the reasonable fees and costs of specified legal and financial advisors to each of the creditor parties to the RSA.

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We believe that our cash on hand and cash flow from operating activities will likely be inadequate to meet the short-term liquidity requirements of our existing business and by the end of the fourth quarter of 2015 the amount of cash available from operations will be insufficient to fund our operations and to make the required payments associated with the Bankruptcy Cases. Accordingly, we will face substantial liquidity problems and will likely be required to significantly reduce or delay capital expenditures, curtail, eliminate or dispose of substantial assets or operations, or undertake other significant restructuring measures; which could include reducing the size of our workforce or pursuing other alternatives to restructure or refinance our indebtedness, all of which could substantially affect our business, financial condition and results of operations. We are also seeking to obtain additional financing from our existing creditors but there is no assurance that we will receive such financing.

Additionally, due to the sustained lower oil and gas pricing environment, we project that a violation on our debt covenants related to our Amended Term Loan Facility applicable to our U.K. subsidiary will occur in or about the third quarter of 2015. We will also seek to refinance all or a portion of such indebtedness. There can be no assurance that a reduction, refinancing, waiver or amendment of the Amended Term Loan Facility could be accomplished.

For further discussion of liquidity risks and risks associated with the Bankruptcy Cases, please see “Item 1A. Risk Factors.”

Our ability to continue as a going concern is dependent upon, among other things, (i) our ability to obtain confirmation of a plan of reorganization under the Bankruptcy Code; (ii) the cost, duration and outcome of the reorganization process; (iii) our ability to achieve profitability as a Company; (iv) our ability to maintain adequate cash on hand; and (v) our ability to generate cash from operations.

Investing Activities

The net cash flows used in investing activities was $175.3 million for the year ended December 31, 2014 compared to $221.8 million used in investing activities for the year ended December 31, 2013, primarily the result of decreased development drilling related to Rochelle and Bacchus. During 2013, our U.K. capital program was focused on two large projects in the North Sea, the Bacchus and Rochelle fields, as well as infill drilling at Alba. With the completion of the development projects, our 2014 U.K. capital expenditures have shifted to maintenance and infill drilling.

Additionally, during the second quarter of 2014, we settled an insurance claim for the Rochelle E1Y well, which resulted in proceeds of $12.6 million paid to us from the insurance carrier. During December 2014, we received a $2.2 million insurance claim as a preliminary property damage settlement related to the Alba water injection pipeline.

Financing Activities

As of December 31, 2014, we had $1,230.2 million in outstanding indebtedness. Notwithstanding the Chapter 11 bankruptcy filing, servicing our existing debt, capital

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expenditures and other long-term obligations would require a significant portion of our cash flow from operations and available cash on hand.

During 2014 and 2013, we completed a number of transactions to improve our liquidity position, extend the maturities of some of our debt and other obligations and effectively hedge a portion of production from our U.K. North Sea assets by locking in pricing. These transactions included:

Procurement Agreement: In January 2013, we entered into a Procurement Agreement with an unaffiliated third party, under which cash was pledged to secure letters of credit in the amount of $33.0 million related to decommissioning obligations in connection with certain of our U.K. license agreements. Third parties have cash collateral associated with the commitments under the Procurement Agreement and we have not recorded the Procurement Agreement as a liability. The Procurement Agreement was terminated and replaced by the Combined Procurement Agreement in January 2014.

Forward Sale Agreements: In February and September 2013 and May 2014, we entered into forward sale agreements with one of our established purchasers of approximately $22.5 million each in return for a specified volume of crude oil in excess of 200,000 barrels from our U.K. North Sea production. The first forward sale commitment was fulfilled in June 2013; the second forward sale commitment was fulfilled in March 2014; and the third forward sale commitment was fulfilled during the fourth quarter of 2014.

Monetary Production Payments: In March 2013, we entered into a Production Payment Agreement for $125 million, which was subsequently increased to $175 million. The Production Payment Agreement was terminated and replaced by the Amended Term Loan Facility in September 2014.

Term Loan Facility: In January 2014, we entered into a $125 million Term Loan Facility and used the proceeds to repay the outstanding amounts under the Revolving Credit Facility. Subsequent to the repayment, the Revolving Credit Facility was terminated and all the associated liens on our collateral obligations were released. The Term Loan Facility was subsequently terminated and replaced by the Amended Term Loan Facility in September 2014.

Combined Procurement Agreement: In January 2014, we entered into a letter of credit procurement agreement with an unaffiliated third party whereby we secured letters of credit for our account of approximately $130 million and agreed to reimburse the third party any expense incurred with posted cash collateral. The letters of credit secure decommissioning obligations in connection with our U.K. licenses. The Combined Procurement Agreement replaced the Procurement Agreement and was subsequently terminated and replaced by the Amended Term Loan Facility in September 2014.

Securities Purchase Agreement: In February 2014, we entered into a securities purchase agreement which is related to the issuance of up to $55 million in common stock, warrants and convertible notes. We issued $12.5 million in common stock and warrants and $17.5 million in convertible notes under the Securities Purchase Agreement during the first quarter of 2014.

Amended Term Loan Facility: In September 2014, we entered into a $440 million Amended Credit Agreement and used the proceeds to repay the outstanding amounts under the Term Loan Facility, Combined Production Agreement and Monetary

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Production Payments. As of December 31, 2014, the outstanding balance on the Amended Term Loan Facility was $440.0 million.

Revolving Credit Facility: In April 2012, we entered into a $100 million Credit Agreement, which was subsequently increased to $125 million. At December 31, 2013, we had $115.2 million outstanding under the Revolving Credit Facility. Concurrent with our entry into a new credit agreement, the Revolving Credit Facility was terminated in January 2014.

2018 Notes: In 2012, we closed the private placement of $554 million of 12% notes due 2018 (the “2018 Notes”). In May 2012, concurrent with the closing of the Alba Acquisition, a portion of the net proceeds were used to fund the acquisition and repay all outstanding amounts under the Senior Term Loan (see below).

Reimbursement Agreements: During 2012, we entered into two reimbursement agreements related to abandonment liabilities for certain of our U.K. oil and gas properties. Under these agreements, we agreed to reimburse the issuers of letters of credit covering approximately $153 million of certain of our abandonment liabilities in the event that the letters of credit are drawn. In connection with the execution of the January 2013 Procurement Agreement, we terminated one of the agreements and paid all outstanding and accrued fees. Third parties have cash collateral associated with the commitments under the reimbursement agreements and we have not recorded the reimbursement agreements as liabilities. The second Reimbursement Agreements was terminated and replaced by the Combined Procurement Agreement in January 2014.

Our equity issuances for 2014, 2013 and 2012 were as follows:

June 2012: a public offering of 8.6 million shares of our common stock offering for net proceeds of $60.8 million;

February 2014: an issuance of 2.9 million shares of our common stock and 0.7 million of warrants, as related to the Securities Purchase Agreement; and

April 2014: an issuance of 2.1 million of warrants, as related to our litigation settlement.

Strategic Alternatives

As discussed previously, in February 2013, we announced that our Board of Directors approved a review of strategic alternatives. The primary objective of the strategic review was to accelerate the deleveraging of the balance sheet and unlock the value of our underlying assets. The strategic review was concluded in October 2013. The Board of Directors determined that it was in the best interest of our shareholders to retain and exploit our existing asset base, while initiating several organizational changes and cost-saving initiatives. As of December 31, 2014, we had consolidated our U.K. operations in Aberdeen, Scotland, closed our London office, and re-aligned several key personnel internally. As a result of these activities, we realized approximately $13 million in cash savings.

Results of Operations

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.

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Further, the current tightly balanced supply and demand market means a small variation in supply or demand can significantly impact the market prices for these commodities.

Our realized price per BOE, before derivatives, decreased from $92.36 per BOE in 2013 to $81.47 per BOE in 2014. As oil sales from Alba and Bacchus have decreased and gas sales for Rochelle has increased, the realized price per when converted to BOE has decreased. For example, the average realized sales price for U.K. oil production for the year ended December 31, 2014 was $100.67 per bbl, and the average realized sales price for U.K. gas production for the year ended December 31, 2014 was $8.16 per mcf. Since the conversion of mmcf to boe is 6 mmcf to 1 boe, increased gas sales relative to oil sales has the effect of lowering our overall blended realized price per BOE.

For 2014, net loss to common stockholders was $841.6 million, or $16.61 per diluted share. This net loss includes a $259.2 million goodwill impairment loss, impairments of $405.2 million and $71.6 million related to our U.K. and U.S. properties, respectively, and loss on early extinguishment of debt of $34.3 million. Net loss to common stockholders for 2013 was $97.3 million, or $2.07 per diluted share. This net loss includes a $9.6 million impairment related to our U.S. properties and increased interest expense resulting from borrowings under existing debt agreements. Net loss to common stockholders for 2012 was $128.0 million, or $3.01 per diluted share. The 2012 net loss includes a $53.1 impairment related to our U.S. properties, increased interest expense resulting from borrowings under existing debt agreements, issuances of new debt obligations and a loss on the early extinguishment of debt of $21.7 million.

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 operations was $67.9 million in 2014 versus $57.4 million in 2013 and $38.6 million in 2012. Adjusted EBITDA (as defined below) was $219.8 million in 2014, as compared to $203.3 million in 2013 and $129.9 million in 2012. These fluctuations in Adjusted EBITDA are primarily due to the changes in our production volumes, realized pricing and operating costs.

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 our ability to maintain or grow production levels and reserves, internally fund capital expenditures and service debt as well as provide comparisons to other oil and gas exploration and production companies. These measures include, among others, debt and cash balances, production levels, oil and gas reserves, drilling results, adjusted earnings before interest, taxes, depreciation, depletion and amortization (“Adjusted EBITDA”) and Net Loss, as Adjusted.

Net loss, as Adjusted for 2014, 2013 and 2012 was $279.0 million, $84.3 million and $54.2 million, respectively.

For definitions of Net Loss, as Adjusted and Adjusted EBITDA, and a reconciliation of these non-GAAP measures to the appropriate GAAP measure, please see “Non-GAAP Financial Measures and Reconciliations.”

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Revenues

Our revenues and sales volumes have fluctuated significantly during the last three years primarily due to the following:

Our revenues decreased from $337.7 million for the year ended December 31, 2013 to $316.0 million for year ended December 31, 2014 primarily as a result of decreased oil production from Alba and Bacchus. Alba and Bacchus revenue decreased $32.5 million and $54.0 million, respectively. Offsetting these decreases was production from Rochelle, which produced intermittently throughout 2014 and contributed approximately $69.9 million in additional revenues during 2014.

Our revenues increased from $219.1 million for the year ended December 31, 2012 to $337.7 million for the year ended December 31, 2013, primarily due to increases in U.K. oil production from our increased interest in the Alba field and initial production from the Bacchus field in the second quarter of 2012 and initial production from the Rochelle field in the fourth quarter of 2013.

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



	Year Ended December 31,
	2014		2013		2012
Sales volume (1)
Oil and condensate sales (mbbls):
United Kingdom		2,564		3,017		1,994
United States		8		1		3
Total		2,572		3,018		1,997

Gas sales (mmcf):
United Kingdom		6,253		1,194		91
United States		1,577		2,636		5,207
Total		7,830		3,830		5,298

Oil equivalent sales (mboe)
United Kingdom		3,606		3,216		2,009
United States		271		441		871
Total		3,877		3,657		2,880

Total BOED		10,622		10,017		7,868

Physical production volume (boed) (1):
United Kingdom		10,254		8,665		5,494
United States		770		1,257		2,379
Total		11,024		9,922		7,873

Average Realized Prices:

United Kingdom:
Oil and condensate price ($ per bbl)	$	100.67	$	104.40	$	103.56
Gas price ($ per mcf)		8.16		12.00		7.41
Equivalent oil price ($ per boe)	$	85.73	$	102.39	$	103.13

United States:
Oil and condensate price ($ per bbl)	$	66.13	$	94.47	$	94.67
Gas price ($ per mcf)		3.93		3.13		2.23
Equivalent oil price ($ per boe)	$	24.83	$	18.98	$	13.64

Total:
Oil and condensate price ($ per bbl)	$	100.57	$	104.40	$	103.55
Gas price ($ per mcf)		7.31		5.89		2.32
Equivalent oil price ($ per boe)	$	81.47	$	92.36	$	76.06

Operating Costs ($ per boe) (2):
United Kingdom	$	22.88	$	30.49	$	25.67
United States		16.55		16.78		8.00
Total	$	22.44	$	28.84	$	20.33

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⁽¹⁾

We record oil revenues when production is transported by pipeline or production is shipped out of our storage tanks. We use the entitlements method to account for sales of gas production. Physical production may differ from sales volumes based on the timing of tanker liftings for our international sales.

⁽²⁾

Operating costs 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 production and production related general and administrative costs.

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

The markets in which we sell our oil and natural gas also materially impact our revenues and cash flows. Oil trades on a worldwide market, and, consequently, price movements for all types and grades of crude oil generally trend in the same direction and within a relatively narrow price range. However, natural gas prices vary among geographic areas as the prices received are largely impacted by local supply and demand conditions as the global transportation infrastructure for natural gas is still developing. As such, the oil we produce and sell is typically sold at prices in line with global prices, whereas our natural gas is to a large extent impacted by regional supply and demand issues and to a lesser extent by global fuel prices, including oil and coal. The U.S. gas market is heavily impacted by the increased supply from shale drilling, which has served to depress natural gas prices relative to the U.K. market.

Operating Expenses

For 2014, operating expenses decreased to $87.0 million as compared to $105.4 million for 2013, primarily due to decreased operating costs at Alba, Bacchus and Enoch. Offsetting these decreases in operating expense were operating costs at Rochelle which was placed into production in the fourth quarter of 2013. Operating costs per boe decreased to $22.44 per boe for 2014 from $28.84 per boe for 2013.

For 2013, operating expenses increased to $105.4 million as compared to $58.5 million for 2012, primarily due to costs related to production from our Alba, Bacchus and Rochelle fields. Operating costs per boe increased to $28.84 per boe for 2013 from $20.33 per boe for 2012 primarily due to the continued increase in proportion of U.K. operations to our total expenses and workovers in our U.S. fields. On average, our U.K operations have higher operating costs per BOE than our U.S. operations, thereby increasing our overall operating costs per BOE in 2013.

DD&A

For 2013 and 2014, depreciation, depletion and amortization (“DD&A”) expense increased from $143.0 million to $175.7 million, respectively, primarily due to a decrease in proved oil and gas reserves coupled with a higher volume of oil and gas sales. Increasing oil and gas sales volumes represented a higher proportion of declining proved reserves. The effect of this is an increased write-off of our properties subject to amortization through DD&A expense.

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For 2012 and 2013, DD&A expense increased from $66.6 million to $143.0 million, respectively, primarily due to increased production from the Alba, Bacchus and Rochelle fields.

DD&A per boe was $45.38, $39.12 and $23.11 for the years ended December 31, 2014, 2013 and 2012, respectively. The increase in DD&A per boe resulted primarily from a decrease in our proved reserves over the three year period. Additionally, as accretion expense is a component of our DD&A expense, as accretion expense accelerates as it nears abandonment, DD&A per BOE will increase as a result.

Impairment of Oil and Gas Properties

In 2014, 2013 and 2012, we recorded $476.7 million, $9.6 million and $53.1 million, respectively, in impairment of oil and gas properties, pre-tax, through the application of the full cost ceiling test at the end of each quarter. The primary reasons for the 2014 impairment was (1) the transfer of $397.4 million in oil and gas properties from properties not subject to amortization to properties subject to amortization and (2) the transfer of substantially all of our PUD reserves to probable undeveloped reserves. The transferred reserves are economically producible at December 31, 2014 and have a standard measure of discounted cash flows of approximately $75 million. The transfer of unproved properties and related PUD reserves was based on uncertainties that exist around the financing required to fund our participation in the development of our unproved properties and related PUD reserves in a reasonable amount of time due to our filing of Chapter 11 under the Bankruptcy Code including the potential consequences from our anticipated breach of our leverage covenant under our Amended Term Loan Facility which are further discussed in “Item 1. Business” and “Item 2. Properties.”

As December 31, 2014, our properties not subject to amortization balance of $10.8 million relates to unevaluated well costs in Marcellus. Furthermore, should oil and gas prices remain depressed for an extended period of time, further impairments of our oil and gas properties are likely to be recorded both quarterly and annually in 2015.

Goodwill Impairment Loss

Goodwill impairment loss was $259.2 million for the year ended December 31, 2014. We recognized no goodwill impairment loss during 2013. Although the carrying amount of goodwill is tested annually for impairment, as a result of a number of factors which occurred during and subsequent to the third quarter of 2014, including our filing under Chapter 11 of the United States Bankruptcy Code, we performed a goodwill impairment test as of September 30, 2014. Our goodwill impairment test ultimately involved comparing the implied fair value of our goodwill with the carrying amount of our goodwill. When this analysis was performed as of September 30, 2014, it was determined that the fair value of our goodwill was $0. As a result, the entire amount of our goodwill, or $259.2 million, was charged to Goodwill impairment loss within cost of operations on our consolidated statements of operations for the year ended December 31, 2014.

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Insurance Proceeds

During 2014, we received $13 million in interim insurance proceeds related to our insurance claim for the loss of production income and property damage resulting from the rupture of the Alba water injection pipeline. The portion of the proceeds attributable to loss of production income was $10.8 million and the portion attributable to property damage was $2.2 million. The claims remain in progress for potential additional recoveries, which is estimated to be in the range of $10 million to $15 million. In addition, we received a $12.6 million insurance settlement regarding the loss, plug and abandonment and replacement of the E1Y well for Rochelle.

General and Administrative (“G&A”) Expenses

Our gross G&A expenses for the year ended December 31, 2014 and 2013 were $33.5 million and $45.6 million, respectively, or a decrease of $12.1 million. The primary reason for the decrease was lower employee compensation expense, occupancy costs and IT costs resulting from staff realignments and reductions in the U.K. resulting from a full year implementation of our strategic review. Our gross G&A expenses for the year ended December 31, 2013 and 2012 were $45.6 million and $48.5 million, respectively, or a decrease of $2.9 million, which was primarily the result of decreased consulting fees and travel expense primarily resulting from staff realignments and reductions in the U.K resulting from our strategic review which occurred late in 2013 and decreased stock-based compensation expense.

Non-cash stock-based compensation is comprised of expense related to grants of restricted stock and performance awards, which were granted for the first time in 2012. The restricted stock awards were valued based on the closing price of our common stock on the measurement date, typically the date of grant. The performance awards are valued on the date of grant using a Monte Carlo simulation model. In January 2014, 2013 and 2012, certain of our executive officers were granted a target number of performance shares that will be earned as the relative total shareholder return ranking is measured among a designated peer group at the end of a three-year performance period. Payouts will be based on a predetermined schedule at the end of the performance period and may range from 0% to 200% of the number of performance units. See Note 17 – Stock Based Compensation Arrangements to our consolidated financial statements in “Item 8. Financial Statements and Supplementary Data.”

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Components of G&A expenses for these periods are as follows:



	Year Ended December 31,
(Amounts in thousands)	2014		2013		2012
Compensation	$	14,070	$	20,225	$	20,520
Consulting, Legal and Accounting Fees		9,906		9,291		9,160
Occupancy Costs		1,252		2,795		2,437
IT Costs		1,776		2,334		2,250
Other Expenses		5,575		6,114		8,114
Total Gross Cash G&A Expenses		32,579		40,759		42,481

Non-Cash Stock-Based Compensation		939		4,843		6,036

Gross G&A Expenses		33,518		45,602		48,517
Less: G&A Expenses Billed to Third Parties		(764)		(7,518)		(3,791)
Less: Transfers to Operating Expenses		(6,261)		(6,513)		(5,711)
Less: Capitalized G&A Expenses		(11,666)		(12,447)		(17,930)
Net G&A expenses	$	14,827	$	19,124	$	21,085

Interest Expense

As discussed in “Liquidity and Capital Resources,” we completed several financing transactions during the first and third quarter of 2014 that have had a significant impact on our interest expense. The increase in interest expense from $104.5 million in 2013 to $108.9 million in 2014 reflects the increases in interest expense that occurred related to these financing transactions, including the Term Loan Facility, the Amended Term Loan Facility and the 6.5% Convertible Senior Notes and decreased capitalization of interest as a result of decreased drilling activities during 2014. Offsetting these increases was the impact of ceasing the recording of interest expense and amortization of debt issuance costs subsequent to the Petition Date related to all liabilities classified as “Liabilities Subject to Compromise” within our Consolidated Financial Statements. Contractual interest on liabilities subject to compromise not reflected in the Condensed Combined Statement of Operations was approximately $18.6 million representing interest expense from the Petition Date through December 31, 2014.

The increase in interest expense from $84.1 million in 2012 to $104.5 million in 2013 reflects the increases in interest expense that occurred as we completed several financing transactions during 2013 and 2012 that have had a significant impact on our interest expense, including the issuance of new debt facilities and the repayment of extinguished debt.

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Components of interest expense are as follows:



	Year Ended December 31,
(Amounts in thousands)	2014		2013		2012
Interest expense on debt outstanding (1)	$	76,803	$	106,148	$	77,116
Interest expense on retired debt (2)		19,667		—		19,713
Amortization of loan costs and discount		22,239		22,359		14,179
Gross interest expense		118,709		128,507		111,008
Less: capitalized interest		(9,775)		(23,991)		(26,886)
Net interest expense	$	108,934	$	104,516	$	84,122

⁽¹⁾

The 2014 column includes interest expense incurred in 2014 related to the 2018 Notes, 7.5% Convertible Bonds, 6.5% Convertible Senior Notes, 5.5% Convertible Senior Notes and Amended Term Loan Facility. Based on the terms of the RSA, all debt with the exception of the Amended Term Loan Facility would be cancelled. A full year of cash interest expense on the Amended Term Loan Facility is expected to be approximately $50.0 million.

⁽²⁾

The 2014 column includes interest expense incurred in 2014 related to the Monetary Production Payments, Revolving Credit Facility and Term Loan Facility.

Each of our debt instruments and transactions are discussed in Note 12 to our consolidated financial statements in “Item 8. Financial Statements and Supplementary Data.”

For the year ended December 31, 2014, 2013 and 2012, we had non-cash interest expense, including amortization of loan costs and discount, of $28.0 million, $29.4 million and $22.9 million, respectively.

Letter of Credit Fees

Letter of credit fees were $8.5 million and $33.4 million for the year ended December 31, 2014 and 2013, respectively. The letter of credit fees are expenses related to our reimbursement agreements covering certain of our abandonment liabilities. The decrease in the letter of credit fees was primarily due to the lower rates and financing costs of our Combined Procurement Agreement versus the previous agreements. On September 30, 2014, the Combined Procurement Agreement was replaced with the Amended Term Loan Facility. As such, letter of credit fees will be no longer be recognized through a procurement agreement arrangement, and the letter of credit fees will be displaced with interest expense attributable to the Amended Term Loan Facility.

Financing and Transaction Costs and Reorganization Items

Financing and transaction costs were $11.0 million and $7.0 million for the year ended December 31, 2014 and 2013, respectively. These costs are primarily attributable to debt restructuring costs, costs associated with the strategic review and pre-petition costs associated with the Company’s voluntary filing under Chapter 11 of the Bankruptcy Code.

Reorganization items were $42.9 million for the year ended December 31, 2014. These costs reflect the post-petition costs associated with the Company’s voluntary filing under Chapter 11 of the Bankruptcy Code and consisted of $33.5 million related to the write-off of the deferred

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financing costs and discounts of our debt affected by the Bankruptcy Cases and $9.4 million in professional fees.

Loss on Early Extinguishment of Financing Agreements

As part of the repayment of the Revolving Credit Facility and Alba Reimbursement Agreement during the first quarter of 2014, we recorded a loss on early extinguishment of financing agreements, which includes an early termination fee of $4.7 million, write off the remaining deferred financing costs of $6.9 million and foreign exchange gain of $8.0 million.

Also, on September 30, 2014, as part of the refinancing of the Term Loan Facility, Combined Procurement Agreement and Monetary Production Payments, we recorded a loss on early extinguishment of financing agreements, which includes an early termination fee of $13.0 million, write off the remaining deferred financing costs and debt discount of $14.0 million and $1.9 million, respectively, and a foreign exchange loss of $1.9 million.

Unrealized Gain (Loss) on Foreign Currency Exchange

The unrealized gains (loss) on foreign currency exchange are primarily attributable to the effects of foreign currency fluctuations on our abandonment liabilities which are predominantly denominated in pounds sterling.

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Income Taxes

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



(Amounts in thousands)	U.K.		U.S.		Other		Total
Year Ended December 31, 2014:
Net loss before taxes	$	(741,005)	$	(137,440)	$	(16,499)	$	(894,944)

PRT tax current expense		9,172		—		—		9,172
PRT tax deferred benefit		(4,272)		—		—		(4,272)
PRT tax expense		4,900		—		—		4,900

Corporate current expense (benefit)		(127)		—		21		(106)
Corporate deferred benefit		(59,483)		—		—		(59,483)
Corporate tax expense (benefit)		(59,610)		—		21		(59,589)

Total tax expense (benefit)		(54,710)		—		21		(54,689)

Net loss after taxes	$	(686,295)	$	(137,440)	$	(16,520)	$	(840,255)

Year Ended December 31, 2013:
Net loss before taxes	$	(35,273)	$	(44,591)	$	(9,173)	$	(89,037)

PRT tax current expense		20,667		—		—		20,667
PRT tax deferred benefit		(13,978)		—		—		(13,978)
PRT tax expense		6,689		—		—		6,689

Corporate current expense		—		—		30		30
Corporate deferred benefit		(277)		—		—		(277)
Corporate tax expense (benefit)		(277)		—		30		(247)

Total tax expense		6,412		—		30		6,442
Net loss after taxes	$	(41,685)	$	(44,591)	$	(9,203)	$	(95,479)

Year Ended December 31, 2012:
Net income (loss) before taxes	$	(22,959)	$	(91,383)	$	2,344	$	(111,998)

PRT tax current expense		31,796		—		—		31,796
PRT tax deferred benefit		(14,823)		—		—		(14,823)
PRT tax expense		16,973		—		—		16,973

Corporate current expense		—		—		26		26
Corporate deferred benefit		(11,358)		—		—		(11,358)
Deferred tax expense related to U.K. tax law change		8,587		—		—		8,587
Corporate tax expense (benefit)		(2,771)		—		26		(2,745)

Total tax expense		14,202		—		26		14,228
Net income (loss) after taxes	$	(37,161)	$	(91,383)	$	2,318	$	(126,226)

We currently do not record tax benefits for losses in the U.S. as there was no assurance that we could generate any U.S. taxable earnings, resulting in a full valuation allowance on all deferred tax assets generated. Furthermore, a valuation allowance was recorded against a portion of the deferred tax assets in the U.K. as there was no assurance that we could generate any U.K. taxable earnings.

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During 2012, the U.K. government enacted legislation (retroactive to March 2012) to restrict decommissioning expenditures to 20% for supplemental corporate tax, in addition to the U.K. corporate tax of 30%. This resulted in total tax relief available for decommissioning at 50%. As a result of this enactment, we incurred additional income tax expense of $8.6 million in 2012.

Our current tax expense is related to Petroleum Revenue Tax (“PRT”) on our Alba field in the U.K.

Tax Attributes

At December 31, 2014, we had the following tax attributes available to reduce future income taxes:



		As of December 31,
		2014			2013
	Types of Tax Attributes	Years of Expiration	Carry-forward Amount		Years of Expiration	Carry-forward Amount
U.K.
Corporate tax	NOL	Indefinite	$	610,743	Indefinite	$	638,466
Supplemental Corporate tax	NOL	Indefinite		346,828	Indefinite		455,318

U.S.
Corporate Income tax	NOL	2023 - 2034		354,171	2023 - 2033		232,745
State Income tax	NOL	2015 - 2034		84,069	2014 - 2033		83,613
Capital gains tax	Capital loss	2015		1,848	2015		1,848

In the U.S., as a result of the Bankruptcy Cases, the ultimate realization of our net operating losses (“NOL”) and tax basis is dependent on the terms of our restructuring. If a portion of our debt is cancelled upon emergence from Chapter 11, the amount of the cancelled debt will reduce tax attributes such as our NOLs and tax basis, which, depending on our plan of reorganization, could partially or fully reduce our available NOLs.

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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%.



	Year Ended December 31,
	2014		2013		2012
Federal income tax benefit at statutory rate	$	(313,230)	$	(31,163)	$	(39,199)
Taxation of foreign operations		(65,478)		21,998		5,859
Effect of out-of-period adjustment		—		—		6,997
Change in valuation allowance		232,513		15,343		30,329
U.K. tax increase from tax law and rate changes		—		—		8,587
Goodwill impairment		90,733		—		—
Disallowed executive compensation		88		247		1,655
Other		685		17		—

Total Income Tax Expense (Benefit)	$	(54,689)	$	6,442	$	14,228
Effective Income Tax Rate		6%		-7%		-13%

2015 Outlook

Planned Capital Expenditures

We expect that our total capital expenditure budget for 2015 will be approximately $40 million. In the current climate and until prices return to more favorable levels, we are actively managing our budget to reduce our capital expenditures to the minimal level essential to preserving our business. Additionally, our 2015 capital expenditure budget is subject to change depending on a number of factors, including the results of the Bankruptcy Cases, the availability and costs of drilling and completion equipment, crews, economic and industry conditions, prevailing and anticipated prices for oil and gas, the availability of sufficient capital resources, drilling success and other normal factors affecting the oil and gas industry.

Subject to a favorable result of the Bankruptcy Cases, we intend to fund our 2015 capital expenditures primarily through cash on hand and cash flow generated from operations.

Decommissioning Expenditures

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Non-GAAP Financial Measures and Reconciliations

Net income can be significantly affected by various non-cash items, such as unrealized gains and losses on our commodity derivatives, currency impact of long-term liabilities and deferred taxes. Given the significant impact that non-cash items may have on our net income, we use various measures in addition to net income and net cash provided by operating activities, including non-financial performance indicators and non-GAAP measures, such as Net Loss, as Adjusted and Adjusted EBITDA, as key metrics to manage our business. These metrics demonstrate our ability to maintain or grow production levels and reserves, internally fund capital expenditures and service debt as well as provide comparisons to other oil and gas exploration and production companies.

We define “Net Loss, as Adjusted” as net loss, without the effect of impairments, derivative transactions, loss on extinguishment of debt, goodwill impairment loss, litigation settlement expense and reorganization items. We define “Adjusted EBITDA” as net loss before interest, taxes, depreciation, depletion and amortization, impairments, derivative transactions, loss on extinguishment of debt, goodwill impairment loss, litigation settlement expense and reorganization items. These measures are internal, supplemental measures of our performance that are not required by, or presented in accordance with GAAP. The calculations of these non-GAAP measures and the reconciliation of net loss to these non-GAAP measures are provided below.

We view these non-GAAP measures, and we believe that others in the oil and gas industry, securities analysts, investors, and other interested parties view these, or similar, non-GAAP measures, as commonly used analytic indicators to compare performance among companies in our industry and in the evaluation of issuers.

Because Net Loss, as Adjusted and Adjusted EBITDA are not measures determined in accordance with GAAP and thus are susceptible to varying calculations, they may not be comparable to similarly titled measures of other companies.

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Net Loss, as Adjusted and Adjusted EBITDA have limitations as analytical tools, and you should not consider these measures in isolation or as a substitute for analysis of our financial statement data presented in the condensed consolidated financial statements as reported under GAAP.



	Year Ended December 31,
(Amounts in thousands)	2014		2013		2012
Net loss	$	(840,255)	$	(95,479)	$	(126,226)
Impairment of oil and gas properties (1)		225,522		9,566		53,072
Unrealized losses (gains) on derivatives (net of tax) (2)		(10,756)		1,843		(7,326)
Loss on early extinguishment of debt (net of tax) (3)		24,996		—		17,662
Goodwill impairment loss (4)		259,238		—		—
Litigation settlement expense (1)		19,034		—		—
Reorganization Items (1)		43,222		—		—
Deferred tax expense (benefit) related to U.K. tax rate change		—		(277)		8,587

Net Loss as Adjusted	$	(278,999)	$	(84,347)	$	(54,231)

Net loss	$	(840,255)	$	(95,479)	$	(126,226)
Net interest expense		108,862		104,452		83,872
Letter of credit fees		8,492		33,425		21,903
Depreciation, depletion and amortization		175,744		143,048		66,564
Impairment of oil and gas properties		476,721		9,566		53,072
Unrealized (gain) loss on derivatives		(10,818)		1,843		(5,141)
Loss on early extinguishment of financing arrangements		34,297		—		21,661
Goodwill impairment loss		259,238		—		—
Litigation settlement expense		19,034		—		—
Reorganization items		43,222		—		—
Income tax expense (benefit)		(54,689)		6,442		14,228

Adjusted EBITDA	$	219,848	$	203,297	$	129,933

⁽¹⁾

Net of tax benefit of $251.2 million in 2014. During 2013 and 2012, we included no tax benefits as there was no assurance that we could generate any U.S. taxable income.

⁽²⁾

Net of tax benefit of $0.1 million, none and $2.2 million in 2014, 2013 and 2012, respectively, related to U.K. commodity derivatives. We did not include tax expenses related to the embedded derivatives associated with our debt and equity instruments in the U.S. as there was no assurance that we could generate any taxable earnings.

⁽³⁾

Net of tax benefit of $9.3 million, none and $4.0 million in 2014, 2013 and 2012, respectively, related to the U.K. We did not include tax benefits related to the U.S. as there was no assurance that we could generate any taxable earnings.

⁽⁴⁾

We included no tax benefit as this is a permanent difference.

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Disclosures about Contractual Obligations and Commercial Commitments

The following table sets forth our obligations and commitments to make future payments under our lease agreements and other long-term obligations as of December 31, 2014:



(Amounts in thousands)		Payments due by Period
	Total		Less than 1 Year		1-3 Years		3-5 Years		After 5 Years
Long-term debt:
Principal (1)	$	1,231,816	$	—	$	677,816	$	554,000	$	—
Interest (2)(3)(4)		366,606		157,251		198,275		11,080		—
Asset retirement obligations		106,482		40,547		46,001		24		19,910
Leases for offices and equipment		2,058		1,018		1,040		—		—

Total Contractual Obligations	$	1,706,962	$	198,816	$	923,132	$	565,104	$	19,910

⁽¹⁾

Principal on long-term debt reflects the amounts contractually obligated at December 31, 2014 at the maturity dates in effect at that date. Principal does not reflect amounts that would be contractually obligated as a result of any reorganization under the Bankruptcy Cases. For further information on Bankruptcy Cases, refer to Item 1 – Business.

⁽²⁾

Interest on our 7.5% convertible bonds is added to the outstanding principal balance each quarter and reflected as due upon maturity.

⁽³⁾

Interest on long-term debt reflects the amounts contractually obligated on debt outstanding at December 31, 2014. As discussed above in Interest Expense and Other, we ceased recording interest expense subsequent to the Petition Date related to all liabilities classified as Liabilities Subject to Compromise within our Consolidated Financial Statements.

⁽⁴⁾

Interest presented in the column “Less than 1 Year” includes $33.8 million in interest payments due on September 2, 2014 and December 1, 2014 related to the Notes which the Company decided not to pay.

Off-Balance Sheet Arrangements

Prior to entry into the LC Issuance Agreement (as described below in Note 24 to the consolidated financial statements) on September 30, 2014, our Combined Procurement Agreement related to abandonment liabilities was an off-balance sheet arrangement which covered $90 million of our abandonment liabilities for certain of our U.K. oil and gas properties. Under the Combined Procurement Agreement, unaffiliated third parties pledged cash to secure letters of credit covering certain of our abandonment liabilities and we agreed to reimburse the pledged cash in the event that the letters of credit are drawn and pledged cash is utilized to satisfy the commitment. We had no cash collateral associated with the Combined Procurement Agreement and the commitments under the reimbursement agreements were not recorded as liabilities. Fees and expenses related to the reimbursement agreements were included in other expenses on our condensed consolidated statements of operations.

On September 30, 2014, we entered into the Amended Credit Agreement and used the proceeds to repay the outstanding amounts under the Combined Production Agreement and provided cash

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collateral for the LC Issuance Agreement. The posted cash collateral is reflected as restricted cash, long-term portion, in our condensed consolidated balance sheets. From time to time, as additional letters of credit are required for additional abandonment obligations, we may post cash collateral for additional letters of credit under the LC Issuance Agreement.

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. While management regularly reviews its estimates, including those related to the determination of proved reserves, estimates of future dismantlement costs, income taxes and litigation, actual results could 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 of accounting for oil and gas activities, all acquisition, exploration and development costs incurred for the purpose of finding oil and gas, are capitalized and accumulated in pools on a country-by-country basis. Capitalized costs include the cost of drilling and equipping productive wells, such as the estimated costs of dismantling and abandoning these assets, dry hole costs, lease acquisition costs, seismic and other geological and geophysical costs, delay rentals, costs related to such activities, certain directly-related employee costs and a portion of interest expense. Employee costs associated with production and other operating activities and general corporate activities are expensed in the period incurred.

Capitalized costs are limited on a country-by-country basis (the ceiling test). Under the ceiling test, if the capitalized cost of the full cost pool, net of deferred taxes, exceeds the ceiling limitation, the excess is charged as an impairment expense. The ceiling test limitation is calculated as the present value, discounted at 10%, of:

the future net cash flows related to estimated production of proved reserves;

the effect of derivative instruments that qualify as cash flow hedges;

the lower of cost or estimated fair value of unproved properties; and

the expected income tax effects of the above items.

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Future net cash flows use the average, first-day-of-the-month price for commodities during 2014, 2013 and 2012.

Unproved property costs include the costs associated with unevaluated properties and properties under development and are not initially included in the full cost amortization base (where proved reserves exist) until the project is evaluated. These costs include unproved leasehold acreage, seismic data, wells and production facilities in progress and wells pending determination, together with interest costs capitalized for these projects. Seismic data costs are associated with specific unevaluated properties where the seismic data is acquired for the purpose of evaluating acreage or trends covered by a leasehold interest owned by us.

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

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

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 a business acquisition. The reporting units used to evaluate and measure goodwill for impairment are determined from the manner in which the business is managed.

Goodwill is not amortized, but is required to be assessed for impairment annually, or more often as facts and circumstances warrant. 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. During the first step of a goodwill impairment test, the fair value of each reporting unit is determined and compared to the book value of the reporting unit. If the carrying amount of the reporting unit is greater than its fair value, the second step of the goodwill impairment test is performed, which is a comparison of the implied fair value of the reporting unit’s goodwill with the carrying amount of the reporting unit’s goodwill. An impairment loss, if any, is recognized to the extent that the carrying amount of the reporting unit’s goodwill exceeds its fair value. 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.

In connection with several business acquisitions, we recorded goodwill for the excess of the purchase price over the value assigned to individual assets acquired and liabilities assumed. At December 31, 2013, we had recorded $259.2 million in goodwill related to these business acquisitions. All of our goodwill was attributable to a single reporting unit.

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that a goodwill impairment existed at that date and the equity of the Company is negative, we were required to compare the implied fair value of goodwill with the carrying amount of the goodwill. The fair value of the reporting unit was determined based on a combination of gross asset value, present value of future cash flows and comparison with comparable trading companies. When this analysis was performed as of September 30, 2014, it was determined that the fair value of our goodwill was $0. As a result, the entire amount of our goodwill, or $259.2 million, was charged to Goodwill impairment loss within cost of operations on our consolidated statements of operations for the year ended December 31, 2014.

Dismantlement, Restoration and Environmental Costs

We recognize liabilities for asset retirement obligations associated with tangible long-lived assets, such as producing well sites, and offshore production platforms, 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.

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

Revenue Recognition

We use the entitlements method to account for sales of gas production. We may receive more or less than our entitled share of production. Under the entitlements method, if we receive more than our entitled share of production, the imbalance is treated as a liability at the market price at the time the imbalance occurred. If we receive less than our entitled share, the imbalance is recorded as an asset at the lower of the current market price or the market price at the time the imbalance occurred. Oil revenues are recorded when production is transported by pipeline or 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 due to volatility in commodity prices 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

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options and to be entered into with major financial institutions or commodities trading institutions. Derivative financial instruments are intended to reduce our exposure to declines in the market prices of crude oil and natural gas that we produce and sell, to increases in interest rates and to manage cash flows in support of our annual capital expenditure budget. We also have embedded derivatives related to our debt instruments and convertible preferred stock.

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

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, 2014, we had approximately 1.8 million additional shares available for issuance pursuant to our existing stock incentive plan.

Fair Value

We estimate fair value for the measurement of derivatives, long-lived assets during certain impairment tests, reporting units for goodwill impairment testing, the initial measurement of an asset retirement obligation and the initial measurement of our Series C Preferred Stock upon its redemption and modification. When we are required to measure fair value, and there is not a market observable price for the asset or liability, or a market observable price for a similar asset or liability, we generally utilize an income valuation approach. This approach utilizes

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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

Commodity Price Risk

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

Derivative Instruments and Risk Management Activities

Periodically, we enter into commodity derivatives, including puts, calls and collar agreements, to protect against exposure to price declines related to our U.K. natural gas production. All of our derivatives are used for risk management purposes and are not held for trading purposes.

As of December 31, 2014, we held no outstanding commodity derivative positions.

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. As the timing of expenditures in pounds sterling has been predictable, 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. At December 31, 2014, we have exposure to exchange rate changes applicable to cash balances in

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our U.K. pound denominated bank accounts. A 10% change in the foreign-currency exchange rate would not have a material effect on our financial position or results of operations.

Interest Rate Risk

At December 31, 2014, our exposure to changes in interest rates is not significant as all of our borrowings except for the Amended Term Loan Facility are subject to fixed interest rates. As further discussed in Note 15, the Amended Term Loan Facility bears interest quarterly at a rate of LIBOR plus 10.00% per year (with a LIBOR floor of 1% per year). A 10% change in the LIBOR rate would not have a material effect on our financial position or results of operations.

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Item 8. Financial Statements and Supplementary Data

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders of

Endeavour International Corporation

We have audited the accompanying consolidated balance sheets of Endeavour International Corporation and subsidiaries (the “Company”) as of December 31, 2014 and 2013, and the related consolidated statements of operations, stockholders' equity and cash flows for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these 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 financial statements referred to above present fairly, in all material respects, the consolidated financial position of Endeavour International Corporation and subsidiaries at December 31, 2014 and 2013, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, in conformity with U.S. generally accepted accounting principles.

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Notes 1 and 3, Endeavour International Corporation and certain of its subsidiaries filed for relief under Chapter 11 of Title 11 of the United States Bankruptcy Code on October 10, 2014. This condition raises substantial doubt about the Company’s ability to continue as a going concern. Management's plans in regard to these matters are also described in Notes 1 and 3. The consolidated financial statements do not include any adjustments to reflect the possible future effects on the recoverability and classification of assets or the amounts and classification of liabilities that may result from the outcome of this uncertainty.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Endeavour International Corporation and subsidiaries’ internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated March 31, 2015 expressed an unqualified opinion thereon.

/s/ Ernst & Young, LLP

Houston, Texas

March 31, 2015

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Endeavour International Corporation

(Debtor-in-Possession)

Consolidated Balance Sheets

(Amounts in thousands)



	December 31,
	2014		2013
Assets
Current Assets:
Cash and cash equivalents	$	81,850	$	34,742
Accounts receivable		35,507		65,171
Prepaid expenses and other current assets		47,397		60,318
Total Current Assets		164,754		160,231

Property and Equipment, Net ($10,784 and $368,660 not subject to
amortization at December 31, 2014 and 2013, respectively)		469,509		1,072,151
Goodwill		—		259,238
Restricted Cash, Long-Term Portion		100,241		—
Other Assets		72		33,222
Total Assets	$	734,576	$	1,524,842

See accompanying notes to consolidated financial statements.

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Endeavour International Corporation

(Debtor-in-Possession)

Consolidated Balance Sheets

(Amounts in thousands)



		December 31,
	2014		2013
Liabilities and Stockholders’ Equity
Current Liabilities:
Accounts payable	$	27,364	$	38,033
Accrued interest		—		29,512
Current maturities of debt		432,181		—
Deferred revenue		14,157		20,965
Monetary Production Payments, current portion		—		74,167
Asset retirement obligations, current portion		40,547		48,895
Accrued expenses and other		15,196		10,218
Total Current Liabilities		529,445		221,790
Long-Term Debt		—		870,878
Deferred Taxes		56,670		146,213
Monetary production payment, long-term portion		—		92,500
Other Liabilities		66,077		131,370
Total Liabilities Not Subject to Compromise		652,192		1,462,751
Liabilities Subject to Compromise		841,044		-
Total Liabilities		1,493,236		1,462,751

Commitments and Contingencies

Series C Convertible Preferred Stock:
Series C preferred stock - Liquidation preference: $14,800 and $37,000
at December 31, 2014 and 2013, respectively		17,481		43,703

Stockholders’ Equity (Deficit):
Series B preferred stock - Liquidation preference: $1,971 and $3,745
at December 31, 2014 and 2013, respectively		—		—
Common stock: shares issued and outstanding - 52,900 and 46,981
at December 31, 2014 and 2013, respectively		53		47
Additional paid-in capital		557,111		510,062
Treasury stock, at cost - 72 and 72 shares
at December 31, 2014 and 2013, respectively		(587)		(587)
Accumulated deficit		(1,332,718)		(491,134)
Total Stockholders’ Equity (Deficit)		(776,141)		18,388
Total Liabilities and Stockholders’ Equity		734,576		1,524,842

See accompanying notes to consolidated financial statements.

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Endeavour International Corporation

(Debtor-in-Possession)

Consolidated Statements of Operations

(Amounts in thousands)



	Year Ended December 31,
	2014		2013		2012
Revenues	$	316,032	$	337,664	$	219,058

Cost of Operations:
Operating expenses		86,990		105,444		58,536
Depreciation, depletion and amortization		175,744		143,048		66,564
Impairment of oil and gas properties		476,721		9,566		53,072
Goodwill impairment loss		259,238		—		—
Insurance proceeds		(10,786)		—		—
General and administrative		14,827		19,124		21,085
Total Expenses		1,002,734		277,182		199,257
Income (Loss) From Operations		(686,702)		60,482		19,801

Other Income (Expense):
Derivatives:
Realized losses		(175)		—		—
Unrealized gains (losses)		10,818		(1,843)		5,141
Interest expense		(108,934)		(104,516)		(84,122)
Letter of credit fees		(8,492)		(33,425)		(21,903)
Financing and transaction costs		(10,954)		(6,974)		(6,016)
Loss on early extinguishment of financing agreements		(34,297)		—		(21,661)
Litigation settlement expense		(19,034)		—		—
Reorganization items		(43,222)		—		—
Unrealized gain (loss) on foreign currency exchange		5,710		(3,116)		8,080
Other income (expense)		338		355		(11,318)
Total Other Expense		(208,242)		(149,519)		(131,799)

Loss Before Income Taxes		(894,944)		(89,037)		(111,998)

Petroleum Revenue Tax ("PRT") Expense		4,900		6,689		16,973
Corporate Tax Benefit		(59,589)		(247)		(2,745)
Income Tax Expense (Benefit)		(54,689)		6,442		14,228

Net Loss		(840,255)		(95,479)		(126,226)
Preferred Stock Dividends:		1,329		1,823		1,823

Net Loss to Common Stockholders	$	(841,584)	$	(97,302)	$	(128,049)

Net Loss per Common Share - Basic and Diluted	$	(16.61)	$	(2.07)	$	(3.01)

Weighted Average Number of Common Shares Outstanding -
Basic and Diluted		50,674		47,088		42,533

See accompanying notes to consolidated financial statements.

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Endeavour International Corporation

(Debtor-in-Possession)

Consolidated Statements of Cash Flows

(Amounts in thousands)


	Year Ended December 31,
	2014		2013		2012
Cash Flows from Operating Activities:
Net loss	$	(840,255)	$	(95,479)	$	(126,226)
Adjustments to reconcile net loss to net
cash provided by operating activities:
Depreciation, depletion and amortization		175,744		143,048		66,564
Impairment of oil and gas properties		476,721		9,566		53,072
Goodwill impairment loss		259,238		—		—
Deferred tax benefit		(63,755)		(14,255)		(17,594)
Unrealized (gains) losses on derivatives		(10,818)		1,843		(5,141)
Amortization of non-cash compensation		(116)		3,606		4,401
Amortization of loan costs and discount		22,239		22,359		14,179
Non-cash interest expense		5,739		7,082		8,684
Loss on early extinguishment of debt		22,708		—		21,661
Non-cash litigation settlement expense		14,034		—		—
Non-cash reorganization items		33,518		—		—
Other		(7,347)		16,330		15,365
Changes in operating assets and liabilities:
Decrease (increase) in receivables		29,486		(18,991)		(24,319)
Decrease (increase) in other current assets		(16,267)		1,324		(592)
Increase (decrease) in liabilities		(32,982)		(18,985)		28,559
Net Cash Provided by Operating Activities		67,887		57,448		38,613

Cash Flows From Investing Activities:
Capital expenditures		(91,619)		(225,755)		(246,925)
Acquisitions, net of cash acquired		—		(2,787)		(238,854)
Proceeds from sales, net of cash		1,353		6,774		1,407
Proceeds from insurance settlement		15,120		—		—
Increase in restricted cash		(100,113)		—		(178)
Net Cash Used in Investing Activities		(175,259)		(221,768)		(484,550)

Cash Flows From Financing Activities:
Repayments of borrowings		(240,163)		—		(274,629)
Borrowings under debt agreements, net of debt discount		571,825		—		654,023
Proceeds from issuance of common stock		12,396		—		60,805
Proceeds from issuance of Monetary Production Payments		—		175,000		—
Repayment of Monetary Production Payments		(166,667)		(8,333)		—
Payments for early extinguishment of debt		—		—		(7,248)
Financing costs paid		(19,809)		(25,210)		(32,204)
Other financing		(3,102)		(1,580)		(1,661)
Net Cash Provided by Financing Activities		154,480		139,877		399,086

Net Increase (Decrease) in Cash and Cash Equivalents		47,108		(24,443)		(46,851)
Cash and Cash Equivalents, Beginning of Period		34,742		59,185		106,036

Cash and Cash Equivalents, End of Period	$	81,850	$	34,742	$	59,185

See accompanying notes to consolidated financial statements.

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Endeavour International Corporation

(Debtor-in-Possession)

Consolidated Statement of Stockholders’ Equity (Deficit)

(Amounts in thousands)



					Additional				Total
	Common		Treasury		Paid-In		Accumulated		Stockholders'
	Stock		Stock		Capital		Deficit		Equity (Deficit)
Balance, January 1, 2012	$	38	$	(587)	$	420,412	$	(265,784)	$	154,079

Preferred stock dividend		—		—		—		(1,823)		(1,823)
Common stock issuance		9		—		60,796		—		60,805
Series C preferred stock		—		—		6,273		—		6,273
conversion
Amortization of deferred compensation		—		—		6,033		—		6,033
Other		—		—		290		—		290
Net Loss		—		—		-		(126,226)		(126,226)
Balance, December 31, 2012	$	47	$	(587)	$	493,804	$	(393,833)	$	99,431

Preferred stock dividend		—		—		—		(1,823)		(1,823)
Common stock issuance		—		—		11,286				11,286
Amortization of deferred compensation		—		—		4,843		—		4,843
Other		—		—		129		1		130
Net Loss		—		—		-		(95,479)		(95,479)
Balance, December 31, 2013	$	47	$	(587)	$	510,062	$	(491,134)	$	18,388

Preferred stock dividend		—		—		—		(1,329)		(1,329)
Common stock issuance		3		—		15,548		—		15,551
Issuance of warrants		—		—		1,542		—		1,542
Beneficial conversion feature		—		—		2,781		—		2,781
Series C preferred stock
conversion		3		—		26,219		—		26,222
Amortization of deferred compensation		—		—		939		—		939
Other		—		—		20		—		20
Net Loss		—		—		—		(840,255)		(840,255)
Balance, December 31, 2014	$	53	$	(587)	$	557,111	$	(1,332,718)	$	(776,141)

See accompanying notes to consolidated financial statements.

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Endeavour International Corporation

(Debtor-in Possession)

Notes to Consolidated Financial Statements

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

Note 1 – General

Description of Business

Endeavour International Corporation is an independent oil and gas company engaged in the exploration, development, production and acquisition of energy reserves in the U.S. and U.K. Endeavour was incorporated under the laws of the state of Nevada on January 13, 2000. As used in these Notes to Consolidated Financial Statements, the terms “Endeavour,” “Company,” “we,” “us,” “our” and similar terms refer to Endeavour International Corporation and, unless the context indicates otherwise, its consolidated subsidiaries.

Bankruptcy Cases

On October 10, 2014, (the “Petition Date”), Endeavour and certain of its wholly owned U.S. subsidiaries - Endeavour Operating Corporation, Endeavour Colorado Corporation, Endeavour Energy New Ventures Inc., and END Management Company - and one of its foreign subsidiaries - Endeavour Energy Luxembourg S.à.r.l. (collectively, the “Debtors”) - filed voluntary petitions under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”). The Chapter 11 cases are being jointly administered by the Bankruptcy Court as Case No. 14-12308 (the “Bankruptcy Cases”). See Note 3 – Voluntary Reorganization Under Chapter 11 for a discussion of the Bankruptcy Cases.

Going Concern

Our accompanying consolidated financial statements were prepared assuming that we will continue as a going concern, which contemplates realization of assets and the satisfaction of liabilities in the normal course of business for the twelve month period following the date of these consolidated financial statements. However, as a result of our Bankruptcy Cases and other matters described herein, including the uncertainties related to confirmation of the RSA Plan (see Note 3 - Voluntary Reorganization under Chapter 11) and the anticipated breach of our leverage covenant under our Amended Term Loan Facility applicable to our U.K. subsidiary in or about the third quarter of 2015 (see Note 3 – Voluntary Reorganization Under Chapter 11 and Note 12 – Debt Obligations), there is substantial doubt about our ability to continue as a going concern.

We continue to have discussions with certain of our creditors and their advisors and the advisors to the Official Committee of Unsecured Creditors appointed by the Bankruptcy Court concerning the impact of the price declines that began in late 2014 on the RSA Plan and potential amendments thereto and to the RSA. Additionally, we have and continue to engage in discussions with certain of our U.S. and U.K. creditors regarding the possibility of raising new

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Endeavour International Corporation

(Debtor-in Possession)

Notes to Consolidated Financial Statements

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

capital to reduce the principal amount of outstanding indebtedness under the Amended Term Loan Facility in an amount adequate to avoid a potential default of the leverage covenant, refinancing all or a portion of the Amended Term Loan Facility, or obtaining a waiver or amendment from the lenders under the Amended Term Loan Facility prior to any default thereunder.

Our ability to continue as a going concern is dependent on many factors, including, among other things: (i) the cost, duration and outcome of the Bankruptcy Cases; (ii) our ability to maintain adequate cash on hand and generate cash from operations; (iii) our ability to maintain compliance with debt covenant requirements of the Amended Term Loan Facility; and (iv) our ability to achieve profitability following a restructuring. The accompanying consolidated financial statements do not include any adjustments that might be necessary if our actions to address these factors are not successful.

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 (“U.S. GAAP”) and have been presented on a going concern basis, which contemplates the realization of assets and satisfaction of liabilities in the normal course of business. In the opinion of management, all normal recurring adjustments considered necessary for a fair presentation have been included in these financial statements. Certain amounts for prior periods have been reclassified to conform to the current presentation.

These accounting principles require management to use estimates, judgments and assumptions that affect the amounts of assets, liabilities, revenues and expenses reported herein. While management regularly reviews its estimates, actual results could differ from those estimates.

Management believes it is reasonably possible that the following material estimates affecting the financial statements could change in the coming year:

estimates of proved oil and gas reserves;

estimates as to the expected future cash flow from proved oil and gas properties;

estimates of future dismantlement and restoration costs;

estimates of fair values used in purchase accounting; and

estimates of the fair value of derivative instruments.

Table of Contents

Endeavour International Corporation

(Debtor-in Possession)

Notes to Consolidated Financial Statements

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

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.

Accounting for Reorganization

The accompanying consolidated financial statements of Endeavour have been prepared in accordance with U.S. GAAP guidance on reorganization. This guidance requires the following for the Debtors in the period following the filing of the bankruptcy petition and before emergence:

Disclose the effects of the application of U.S. GAAP guidance on reorganization on the consolidated financial statements.

Reclass unsecured or under-secured pre-petition liabilities to a separate line item Liabilities Subject to Compromise in the Consolidated Balance Sheets;

Segregate Reorganization Items (direct and incremental costs, such as professional fees, of being in bankruptcy) as a separate line item within Other Income (Expense) in the Consolidated Statements of Operations.

Non-accrual of interest expense to the extent not paid during bankruptcy and not expected to be an allowable claim. However, unpaid contractual interest is calculated for disclosure purposes.

Evaluate actual or potential bankruptcy claims which are not already reflected as a liability on the balance sheet.

Adjust unamortized deferred financing costs and discounts associated with debt classified as Liabilities Subject to Compromise to reflect the expected amount of the probable allowed claim.

Disclose condensed combined financial information of the Debtors, as our consolidated financial statements include material subsidiaries that did not file for bankruptcy protection.

Disclose the status of the plan of reorganization and voting by the creditors.

Cash and Cash Equivalents

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

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Endeavour International Corporation

(Debtor-in Possession)

Notes to Consolidated Financial Statements

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

Restricted Cash

Restricted cash includes amounts held as collateral for lines of credit.

Inventories

Materials and supplies and oil inventories are valued at the lower of cost or market value (net realizable value). Our inventories are stated on an average cost basis.

Full Cost Accounting for Oil and Gas Operations

the future net cash flows related to estimated production of proved reserves, utilizing the average, first-day-of-the-month price for commodities;

the effect of derivative instruments that qualify as cash flow hedges;

the lower of cost or estimated fair value of unproved properties; and

the expected income tax effects of the above items.

We utilize a single cost center for each country where we have operations for amortization purposes. Any sales or other conveyances of properties are treated as adjustments to the cost of oil and gas properties with no gain or loss recognized unless the operations are suspended in the entire cost center or the conveyance is significant in nature. Proved properties are amortized on a country-by-country basis using the units of production method (“UOP”). The amortization base in the UOP calculation includes the sum of proved property, net of accumulated DD&A, estimated future development costs (future costs to access and develop proved reserves), and asset retirement costs, less related salvage value.

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Endeavour International Corporation

(Debtor-in Possession)

Notes to Consolidated Financial Statements

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

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

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Endeavour International Corporation

(Debtor-in Possession)

Notes to Consolidated Financial Statements

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

costs and is limited to gross interest expense. We have ceased capitalizing interest related to our debt subject to the Bankruptcy Cases.

Business Combinations

Any excess of the acquisition cost of the acquired business over the fair value amounts assigned to assets and liabilities is recorded as goodwill. 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 reporting unit’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 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

Table of Contents

Endeavour International Corporation

(Debtor-in Possession)

Notes to Consolidated Financial Statements

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

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 recorded when production is transported by pipeline or 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

Derivative Instruments and Hedging Activities

From time to time, we may utilize derivative financial instruments to hedge cash flows from operations or to hedge the fair value of financial instruments. We also have embedded derivatives related to our debt instruments and convertible preferred stock.

We may use derivative financial instruments with respect to a portion of our oil and gas production or a portion of our variable rate debt to achieve a more predictable cash flow by reducing our exposure to price fluctuations. These transactions are likely to be swaps, collars or options and to be entered into with major financial institutions or commodities trading institutions. Derivative financial instruments are intended to:

reduce our exposure to declines in the market prices of crude oil and natural gas that we produce and sell;

reduce our exposure to increases in interest rates, and

manage cash flows in support of our annual capital expenditure budget.

We record all derivatives at fair market value in our Consolidated Balance Sheets at the end of each period. The accounting for the fair market value, and the changes from period to period, depends on the intended use of the derivative and the resulting designation. This evaluation is determined at each derivative’s inception and begins with the decision to account for the derivative as a hedge, if applicable. The accounting for changes in the fair value of a derivative instrument that is not accounted for as a hedge is included in other (income) expense as an unrealized gain or loss. At December 31, 2014 and 2013, we had no outstanding derivatives that were accounted for as a hedge.

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Endeavour International Corporation

(Debtor-in Possession)

Notes to Consolidated Financial Statements

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

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.

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

Foreign Currency Translation

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

Income Taxes

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Endeavour International Corporation

(Debtor-in Possession)

Notes to Consolidated Financial Statements

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

Share-Based Payments

Recent Accounting Pronouncements

In May 2014, the FASB issued a new standard on revenue recognition. The new revenue recognition standard provides a five-step analysis of transactions to determine when and how revenue is recognized. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The new standard is effective for annual periods beginning after December 31, 2016 and can be adopted either retrospectively to each reporting period or retrospectively with a cumulative-effect adjustment as of the date of adoption. We are currently evaluating the effect that adopting this guidance will have on our financial position, results of operations or cash flows.

In August 2014, the FASB also issued a new going concern standard which codifies management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. The new standard is effective for interim and annual periods beginning on or after December 15, 2016 and early adoption is permitted. We do not expect the adoption of this guidance to have a material impact on our financial position or results of operations.

Note 3 - Voluntary Reorganization under Chapter 11

Unanticipated events outside of our control forced us over the last three years to borrow funds at a high cost of capital and divert cash from our businesses to satisfy ongoing obligations. During 2012 to 2014, the Company was heavily involved in the development of the oil and gas fields Bacchus and Rochelle, and also experienced less-than-expected operating performance at the Alba field. These events, combined with unfavorable changes in the economic and political climate for the oil and gas industry, natural disasters, volatile commodity prices and unexpected

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Endeavour International Corporation

(Debtor-in Possession)

Notes to Consolidated Financial Statements

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

delays in new oil and gas production due to operating difficulties in the U.K. North Sea all contributed to our thin liquidity and the swift increase of our debt.

Our management has spent over a year exploring restructuring alternatives. We conducted a strategic review, implemented cost-cutting initiatives, restructured its organization, explored the potential sale of some or all of our assets to a third-party and attempted to negotiate an out-of-court restructuring with our creditors. None of these options materialized as a remedy capable of addressing the breadth of our financial troubles.

In late June 2014, the Company and its advisors began to engage with its major creditors in an attempt to arrive at a restructuring transaction that would significantly deleverage the Company and reduce its debt obligations. Discussions continued for months, but the parties failed to reach agreement on several key issues that would serves as a foundation of a restructuring transaction.

On September 2, 2014, the Company announced that it had decided not to pay approximately $33.5 million in interest due on September 2, 2014 on its 12% First Priority Notes due March 2018 (“First Priority Notes”), 12% Second Priority Notes due June 2018 (“Second Priority Notes”) and 6.5% Convertible Senior Notes due November 2017 (“6.5% Convertible Senior Notes”). Under the term of the indentures for the First Priority Notes, Second Priority Notes and 6.5% Convertible Senior Notes, there was a 30-day grace period during which the Company could elect to make the interest payment and cure any potential event of default for non-payment.

On September 30, 2014, the Company entered into forbearance agreements (the “Forbearance Agreements”) with holders of a majority of its debt as to which the interest payment was not made. Under the terms of the Forbearance Agreements, the holders agreed to forbear from exercising remedies against the Company arising from the failure by the Company to pay (following the passing of the 30-day grace period that ended on October 1, 2014) the September 2, 2014 interest payments due. The forbearance period, initially scheduled to expire on October 7, 2014, was subsequently extended to October 10, 2014.

On October 10, 2014, the Company announced that it reached agreements with holders of more than two-thirds of its First Priority Notes, Second Priority Notes and 7.5% Convertible Bonds (see Note 12 – Debt Obligations) and its 6.5% Convertible Senior Notes and 5.5% Convertible Senior Notes (see Note 12 – Debt Obligations and collectively, “Consenting Debt Holders”), in the form of a consensual Restructuring Support Agreement (“RSA”) that, if implemented as proposed, would significantly reduce the Company’s outstanding debt. The RSA contemplated that the recapitalization of the Company would occur pursuant to a pre-arranged plan of reorganization. On the Petition Date, the Debtors filed voluntary petitions under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Chapter 11 cases are being jointly administered by the Bankruptcy Court as Case No. 14-12308 (the “Bankruptcy Cases”).

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Endeavour International Corporation

(Debtor-in Possession)

Notes to Consolidated Financial Statements

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

Since the Petition Date, the Debtors have operated their business as “debtors-in-possession" pursuant to Sections 1107(a) and 1108 of the Bankruptcy Code, which will allow the Company to continue operations and carry on the business in the ordinary course of business during the reorganization proceedings. Each Debtor will remain in possession of its assets and properties, and its business and affairs will continue to be managed by its directors and officers, subject in each case to the supervision of the Bankruptcy Court.

None of our subsidiaries incorporated in the U.K. has filed under Chapter 11. Such non-filing subsidiaries are referred to herein as “non-Debtors.”

The RSA provides for milestones for consummation and implementation of the consensual restructuring including:

consummation of the confirmed plan no later than 200 days after the Petition Date (or Tuesday, April 28, 2015, as calculated under the Bankruptcy Rules).

$262.5 million of new notes to the holders of its First Priority Notes;

an aggregate of approximately $237.5 million of new convertible preferred shares to holders of its First Priority Notes and Second Priority Notes; and

new common shares to holders of its Second Priority Notes, 6.5% Convertible Senior Notes, 7.5% Convertible Bonds and 5.5% Convertible Senior Notes.

All of the our existing equity securities, including our shares of common stock and preferred stock and warrants, would be cancelled without receiving any distribution.

On the Petition Date, the Company sought, and thereafter obtained, authority to take a broad range of actions, including, among others, authority to pay royalty interests and joint interest

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Endeavour International Corporation

(Debtor-in Possession)

Notes to Consolidated Financial Statements

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

billings, certain employee obligations and pre-Petition contractor claims and taxes. Additionally, other orders were obtained, including adequate assurance of payment to utility companies as well as continued use of cash management systems.

Notice of Adjournment

We have and continue to engage in discussions with certain of our U.S. and U.K. creditors regarding the possibility of raising new capital to reduce the principal amount of outstanding indebtedness under the Amended Term Loan Facility in an amount adequate to avoid a potential default of the leverage covenant, refinancing all or a portion of the Amended Term Loan Facility, or obtaining a waiver or amendment from the lenders under the Amended Term Loan Facility prior to any default thereunder, or other agreed terms to sustain a restructuring and avoid default.

There can be no assurance that a reduction, refinancing, waiver or amendment of the Amended Term Loan Facility could be accomplished. If we are not able to reach a satisfactory agreement with certain of our U.S. and U.K. creditors and are unable to refinance the Amended Term Loan Facility, which is not possible without financial support from certain of our U.S. or U.K. creditors, we may be compelled, either voluntarily or involuntarily, into liquidation of our U.K. operations through an administration proceeding in the U.K., in addition to any Chapter 11 or Chapter 7 liquidation proceeding in the U.S.

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Endeavour International Corporation

(Debtor-in Possession)

Notes to Consolidated Financial Statements

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

Note 4 – Debtors Condensed Combined Financial Statements

Condensed combined financial statements of the Debtors are set forth below. The Endeavour Debtors’ condensed combined financial statements exclude the financial statements of the non-Debtors. Transactions and balances of receivables and payables between Debtors are eliminated in consolidation. However, the Debtors’ Condensed Combined Balance Sheet includes receivables from related non-Debtors and payables to related non-Debtors. Actual settlement of these related party receivables and payables is, by historical practice, made on a net basis or through an equity contribution.



Condensed Combined Balance Sheet
As of December 31, 2014

Assets:
Current Assets	$	41,844
Property and Equipment, Net ($10,724 not subject to amortization)		35,530
Long-Term Receivables Due from Affiliates (1)		633,801
Investments in Subsidiaries		295,816
Other Assets		10
Total Assets	$	1,007,001

Liabilities Not Subject to Compromise:
Accrued expenses and other	$	8,403
Current Liabilities Due to Affiliates (1)		105,060
Other		438
Liabilities Subject to Compromise (2)		841,044
Series C Convertible Preferred Stock - Liquidation Preference: $14,800		17,481
Stockholders' Equity (3)		34,575
Total Liabilities and Stockholders’ Equity	$	1,007,001

⁽¹⁾

It is expected that upon consummation of the Bankruptcy Cases, all intercompany receivables and payables will be offset and settled through equity contributions. No allowances for intercompany receivables from the Debtors have been recorded in the consolidated financial statements.

⁽²⁾

See Note 5 – Liabilities Subject to Compromise

⁽³⁾

It is expected that upon consummation of the Bankruptcy Cases, all common stock of the Debtors will be cancelled and new common stock will be issued to partially satisfy the bankruptcy claims.

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Endeavour International Corporation

(Debtor-in Possession)

Notes to Consolidated Financial Statements

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


Condensed Combined Statement of Operations
For the Year Ended December 31, 2014

Revenues	$	6,729
Cost of Operations		79,086
Loss from Operations		(72,357)

Other Income (Expense):
Interest expense		(4,086)
Unrealized gain on derivative instruments		10,825
Financing and transaction costs		(9,721)
Litigation settlement expense		(14,034)
Reorganization items (4)		(42,939)
Other expense		(5,944)
Total Other Expense		(65,899)

Net Loss		(138,256)

⁽⁴⁾

See Note 5 – Liabilities Subject to Compromise for additional discussion of Reorganization items.



Condensed Combined Cash Flow
For the Year Ended December 31, 2014

Net cash provided by (used in):
Operating	$	123,128
Investing		(335,793)
Financing		277,235
Net decrease in cash and cash equivalents		64,570

Cash and Cash Equivalents, Beginning of Period		67,086

Cash and Cash Equivalents, End of Period	$	131,656

Note 5 – Liabilities Subject to Compromise

Liabilities Subject to Compromise represents liabilities incurred prior to the Petition Date which may be affected by the Chapter 11 process. These amounts represent the Debtors’ allowed

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Endeavour International Corporation

(Debtor-in Possession)

Notes to Consolidated Financial Statements

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

claims and their best estimate of claims expected to be allowed which will be resolved as part of the bankruptcy proceedings.

Liabilities Subject to Compromise consists of the following as of December 31, 2014:



Accounts Payable	$	6,079
Debt		790,246
Accrued Interest and Dividends		44,719

Total Liabilities Subject to Compromise	$	841,044

Interest Expense

The Debtors have discontinued recording interest on unsecured or under secured liabilities subject to compromise on the Petition Date. Contractual interest on liabilities subject to compromise not reflected in the Condensed Combined Statement of Operations was approximately $18.6 million; representing interest expense from the Petition Date through December 31, 2014.

Reorganization Items

Reorganization items represent the direct and incremental costs of being in bankruptcy, such as professional fees, pre-petition liability claim adjustments and losses related to terminated contracts that are probable and can be estimated.

Reorganization items consist of the following for the year ended December 31, 2014:



Professional fees	$	(9,421)
Debt Issue Costs		(16,946)
Debt Discount		(16,572)

Total Reorganization Items	$	(42,939)

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Endeavour International Corporation

(Debtor-in Possession)

Notes to Consolidated Financial Statements

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

Note 6 – Prepaid Expenses and Other Current Assets

Prepaid expenses and other current assets consisted of the following:


	December 31,
	2014		2013
Prepaid well and drilling costs	$	7,425	$	24
Prepaid insurance		5,899		3,707
Inventory		9,927		5,117
Deferred tax asset		10,702		26,583
Deferred financing costs - current portion		9,186		22,134
Other		4,258		2,753

	$	47,397	$	60,318

The entirety of the unamortized deferred financing costs at December 31, 2014 relates to the Amended Term Loan Facility. See Note 12 – Debt Obligations.

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Endeavour International Corporation

(Debtor-in Possession)

Notes to Consolidated Financial Statements

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

Note 7 – Property and Equipment

Property and equipment included the following:



	December 31,
	2014		2013
Oil and gas properties under the full cost method:
Subject to amortization	$	989,758	$	1,084,669
Not subject to amortization:
Incurred in 2014		945		—
Incurred in 2013		774		52,748
Incurred in 2012		3,087		138,641
Incurred prior to 2012		5,978		177,271
		1,000,542		1,453,329

Computers, furniture and fixtures		8,733		8,734
Total property and equipment		1,009,275		1,462,063

Accumulated depreciation, depletion and amortization		(539,766)		(389,912)

Net property and equipment	$	469,509	$	1,072,151

As of December 31, 2014, our properties not subject to amortization balance of $10.8 million relates to unevaluated well costs in Marcellus. Due to the uncertainty that the Bankruptcy Cases have on our ability to develop unproved properties and the potential covenant breach, we transferred $397.4 million in oil and gas properties from properties not subject to amortization to properties subject to amortization.

These costs will be 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, drilling results and development of identified projects and periodic assessment of reserves. We expect costs excluded from amortization to be transferred to the amortization base over the next year as previously drilled wells in the U.S. are completed and tied into infrastructure. We have no unevaluated costs in the U.K.

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Endeavour International Corporation

(Debtor-in Possession)

Notes to Consolidated Financial Statements

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

The following is a summary of our oil and gas properties not subject to amortization as of December 31, 2014:



Costs Incurred in the Year Ended December 31,
	2014		2013		2012		Prior to 2012		Total

Acquisition costs	$	—	$	—	$	—	$	—	$	—
Exploration costs		945		774		3,087		5,978		10,784
Capitalized interest		—		—		—		—		—

Total oil and gas properties not
subject to amortization	$	945	$	774	$	3,087	$	5,978	$	10,784

During 2014, 2013 and 2012, we capitalized $11.7 million, $12.4 million and $17.9 million, respectively, in certain directly related employee costs. During 2014, 2013 and 2012, we capitalized $9.8 million, $24.0 million and $26.9 million, respectively, in interest. All of these costs have been transferred to the amortization base as of December 31, 2014.

Oil and Gas Impairments

During 2014, 2013 and 2012, we recorded $476.7 million, $9.6 million and $53.1 million, respectively, in impairment of oil and gas properties, pre-tax, through the application of the full cost ceiling test at the end of each quarter. The primary reasons for the 2014 impairment was (1) the transfer of $397.4 million in oil and gas properties from properties not subject to amortization to properties subject to amortization and (2) the transfer of substantially all of our PUD reserves to probable undeveloped reserves. The transferred reserves are economically producible at December 31, 2014 and have a standard measure of discounted cash flows of approximately $75 million. The transfer of unproved properties and related PUD reserves was based on uncertainties that exist around the financing required to fund our participation in the development of our unproved properties and related PUD reserves in a reasonable amount of time due to our filing of Chapter 11 under the Bankruptcy Code including the potential consequences from our anticipated breach of our leverage covenant under our Amended Term Loan Facility which are further discussed in Note 1 – General and Note 3 – Voluntary Reorganization under Chapter 11.

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Endeavour International Corporation

(Debtor-in Possession)

Notes to Consolidated Financial Statements

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

The primary reason for the 2013 impairment was the evaluation of certain U.S. assets not subject to amortization which we no longer intend to pursue and accordingly are included in the full cost pool. We did not have an impairment of our U.K. oil and gas properties through the application of the full cost ceiling test at the end of 2013. The 2012 impairment was primarily due to the decline in U.S. oil and gas prices.

Insurance Settlements

During 2014, we received $13 million in interim insurance proceeds related to our insurance claim for the loss of production income and property damage resulting from the rupture of the Alba water injection pipeline. The portion of the proceeds attributable to loss of production income was $10.8 million and the portion attributable to property damage was $2.2 million. In addition, we received a $12.6 million insurance settlement regarding the loss, plug and abandonment and replacement of the E1Y well for Rochelle.

Assets Acquisitions - Marcellus and Haynesville

Note 8 – Goodwill

In connection with several business acquisitions, we recorded goodwill for the excess of the purchase price over the value assigned to individual assets acquired and liabilities assumed. All of our goodwill is attributable to a single reporting unit.

Although the carrying amount of goodwill is tested annually for impairment, as a result of a number of factors which occurred during and subsequent to the third quarter of 2014, including our filing under Chapter 11 of the United States Bankruptcy Code, we performed a goodwill impairment test as of September 30, 2014. As a result of the goodwill impairment test, the entire amount of our goodwill, or $259.2 million, was charged to Goodwill impairment loss within cost of operations on our consolidated statements of operations for the year ended December 31, 2014.

Changes to goodwill for the year ended December 31, 2014 and 2013 were as follows:

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Endeavour International Corporation

(Debtor-in Possession)

Notes to Consolidated Financial Statements

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

	December 31,
	2014		2013
Balance at beginning of year	$	259,238	$	262,764
Purchase price adjustment		—		(3,526)
Goodwill impairment		(259,238)		—

Balance at end of year	$	—	$	259,238

Fair value of the reporting unit was determined based on a combination of gross asset value, present value of future cash flows and comparison with comparable trading companies.

Note 9 – Other Assets

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



	2014		2013
Deferred financing costs	$	—	$	27,105
Deposits related to SM Energy litigation		—		6,000
Other		72		117
	$	72	$	33,222

As of the Petition Date, all unamortized deferred financing costs associated with debt classified as Liabilities Subject to Compromise were written off to Reorganization Items to reflect the expected amount of the probable allowed claim.

As discussed in Note 24 – Commitments and Contingencies, on April 16, 2014 we reached an agreement with SM Energy to settle and dismiss the litigation concerning the terminated acquisition of properties from SM Energy. In accordance with the settlement agreement, we forfeited our $6.0 million deposit.

Note 10 – Accrued Interest, Accrued Expenses and Other Current Liabilities

We had the following accrued interest, accrued expenses and other current liabilities outstanding:



	December 31,

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Endeavour International Corporation

(Debtor-in Possession)

Notes to Consolidated Financial Statements

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

	2014		2013
Accrued interest	$	—	$	29,512
Accrued compensation		1,376		3,210
Accrued reorganization items		4,272		—
Foreign taxes payable		8,627		2,875
Preferred dividends		—		1,774
Other		921		2,359
	$	15,196	$	39,730

All accrued interest related to debt included within Liabilities Subject to Compromise have been reclassed to Liabilities Subject to Compromise. See Note 3 – Voluntary Reorganization under Chapter 11.

Note 11 – Deferred Revenue

For certain of our U.K. fields, we sell production on a monthly basis; however, the production remains in the field’s storage tanks. The inventory associated with these sales remains on our balance sheet and the revenue is deferred until the production is shipped out of our storage tanks.

In 2013 and 2014, we entered into three separate forward sale agreements with one of our established purchasers for payments of approximately $22.5 million each. This effectively hedged a portion of production from our U.K. North Sea assets by locking in pricing for in excess of 200,000 barrels of oil, over a six month delivery period for each forward sale transaction. Payment for two of these agreements was received in the first and third quarters of 2013. Payment for the 2014 transaction was received in the second quarter of this year.

The 2013 forward sale commitments were fulfilled in June 2013 and March 2014. The 2014 forward sale commitment was fulfilled during the fourth quarter of 2014. Payments received related to the forward sale commitments are included in deferred revenue until the purchaser takes possession of the product.

At December 31, 2014, our deferred revenue was attributable to our fields as follows:



	Amount		Delivery Date
Alba	$	12,338	Estimated for 1st Quarter 2015
Rochelle		1,819	Estimated for 1st Quarter 2015
Total	$	14,157

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(Debtor-in Possession)

Notes to Consolidated Financial Statements

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

Note 12 – Debt Obligations

Our debt consisted of the following at December 31:



	2014		2013
Senior notes, 12% fixed rate, due 2018 (1)	$	554,000	$	554,000
Convertible senior notes, 5.5% fixed rate, due 2016 (1)		135,000		135,000
Convertible bonds, 11.5% until March 31, 2014 and 7.5% thereafter, due 2016 (1)		83,746		78,437
Convertible senior notes, 6.5%, fixed rate, due 2017 (1)		17,500		—
Amended term loan facility, variable rate, due 2017		440,000		—
Revolving credit facility, 13% fixed rate, due 2014		—		115,163
		1,230,246		882,600
Less: Debt Discount		(7,819)		(11,722)
Less: Liabilities Subject to Compromise		(790,246)
Less: Current Maturities		(432,181)		—
Long-Term Debt	$	—	$	870,878

⁽¹⁾

Debt balance as of December 31, 2014 is included within Liabilities Subject to Compromise in the Consolidated Balance Sheets.

For a discussion of the potential impact of our filing under Chapter 11 of the Bankruptcy Code on our debt obligations, see Note 3 - Voluntary Reorganization under Chapter 11. As a result of our filing under Chapter 11 of the Bankruptcy Code, we are in default of the debt covenants related to the Senior Notes, 5.5% Convertible Senior Notes, 6.5% Convertible Senior Notes and 7.5% Convertible Bonds. All outstanding balances related to these obligations have been reclassified as Liabilities Subject to Compromise in our consolidated balance sheets.

Senior Notes

In February 2012, we closed the private placement of $350 million aggregate principal amount of 12% First Priority Notes due 2018 and $150 million aggregate principal amount of 12% Second Priority Notes due 2018. In October 2012, we completed a private placement of an additional $54 million aggregate principal amount of 12% First Priority Notes due 2018 (collectively, the “2018 Notes”).

5.5% Convertible Senior Notes

In July 2011, we issued $135 million aggregate principal amount of our 5.5% Convertible Senior Notes due July 15, 2016. Interest on these notes is payable semi-annually at a rate of 5.5% per

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(Debtor-in Possession)

Notes to Consolidated Financial Statements

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

annum. The 5.5% Convertible Senior Notes are convertible into shares of our common stock at an initial conversion rate of 54.019 shares (equivalent to $18.51 per share) of common stock per $1,000 principal amount of the notes, subject to certain anti-dilution adjustments.

7.5% Convertible Bonds

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

Term Loan Facility

On January 24, 2014, we entered into a $255 million agreement consisting of a $125 million senior secured first lien term loan facility (“Term Loan Facility”) and a $130 million Combined Procurement Agreement (see Note 16). The Term Loan Facility bore quarterly interest of LIBOR plus 7.00% annually (provided LIBOR equals at least 1.25% annually).

The Term Loan Facility matured the earlier of:

(i)

December 1, 2017; or

(ii)

92 days prior to the maturity date of our outstanding 5.5% Convertible Senior Notes or our 7.5% Convertible Bonds, if still outstanding on that date.

The proceeds of the Term Loan Facility were used to repay the outstanding amounts under our Revolving Credit Facility. The repayment included a prepayment fee and accrued interest of approximately $2.0 million. Subsequent to the repayment, the Revolving Credit Facility was terminated, all of the associated liens on our collateral obligations were released, and we recorded a loss of $3.5 million on the early extinguishment of financing agreements.

On September 30, 2014, we repaid the balance outstanding under the Term Loan Facility with proceeds from the Amended Term Loan Facility.

Amended Term Loan Facility

On September 30, 2014, two wholly-owned subsidiaries, Endeavour International Holding B.V. (“EIH”) and End Finco LLC (“Finco” and collectively, “Borrowers”) entered into an amended and restated credit agreement (the “Amended Credit Agreement”) in respect of our Term Loan Facility. EIH and Finco are non-Debtors, and as such, the Amended Credit Agreement is not subject to the RSA and related Bankruptcy Cases.

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(Debtor-in Possession)

Notes to Consolidated Financial Statements

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

Pursuant to the Amended Credit Agreement, the lenders advanced approximately $440 million in aggregate principal amount of term loans to the Borrowers (“Amended Term Loan Facility”). The proceeds were used to:

repay in full the balance outstanding under the existing Term Loan Facility;

repay in full the Monetary Production Payments (see Note 14);

repay in full all reimbursement obligations outstanding with respect to the Combined Procurement Agreement (see Note 24);

provide cash collateral for the LC Issuance Agreement (see Note 24) and pay related expenses; and

provide additional liquidity to the Company.

We deferred financing costs of $10.3 million related to the Amended Term Loan Facility. The repayments of the Term Loan Facility, Monetary Production Payments and Combined Procurement Agreement included prepayment fees of approximately $3.3 million, $7.8 million and $2.4 million, respectively, and accrued interest of $2.6 million, $3.7 million and $1.9 million, respectively.

Subsequent to their repayment, the Term Loan Facility, Monetary Production Payments and Combined Procurement Agreement were terminated, and all of the associated liens on our collateral obligations were released. As a result, we wrote off deferred financing costs of $7.3 million and $6.7 million related to the Term Loan Facility and Monetary Production Payments, respectively. Additionally, we wrote off a debt discount of $1.9 million related to the Term Loan Facility and charged $1.9 million to loss on foreign currency exchange related to the Combined Procurement Agreement. All charges related to prepayment fees and write off of deferred financing costs, debt discount and loss on foreign currency exchange are included in other income as “Loss on early extinguishment of financing agreements” in our condensed consolidated statements of operations.

The Amended Term Loan Facility bears interest quarterly at a rate of LIBOR plus 10.00% per year (with a LIBOR floor of 1% per year) and matures on January 2, 2017. The loans under the Amended Term Loan Facility were issued with original issue discount of 2.0%. Borrowings under the Amended Term Loan Facility are guaranteed by the Company and certain of its current and future subsidiaries, including Endeavour Operating Corporation and Endeavour UK, subject to certain exceptions. The Amended Term Loan Facility is secured by the same assets securing the Company’s Term Loan Facility other than cash and cash equivalents in the United States.

The Amended Credit Agreement contains covenants and provisions with respect to events of default that are substantially similar to the covenants in the Company’s Term Loan Facility including, but not limited to, restrictions on the Company’s and its subsidiaries’ abilities to: (i) pay distributions or repurchase or redeem the Company’s capital stock or subordinated debt; (ii)

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Endeavour International Corporation

(Debtor-in Possession)

Notes to Consolidated Financial Statements

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

make certain investments; (iii) incur additional indebtedness; (iv) create or incur certain liens; (v) sell assets; (vi) consolidate, merge or transfer all or substantially all of the Company’s assets; (vii) enter into agreements that restrict distributions from the Company’s subsidiaries to the Company; (viii) engage in transactions with affiliates; and (ix) allow EIH or any of its subsidiaries to make dividends, payments or other distributions of any kind to the Debtors, other than pursuant to specific limited amounts and for specified purposes.

The Amended Credit Agreement contains customary events of default, subject to certain exceptions. In particular, the following events do not constitute events of default under the Amended Credit Agreement: (a) payment defaults or other defaults to the Company’s existing notes or to certain intercompany indebtedness or (b) a bankruptcy filing by the Company or its domestic subsidiaries and one foreign subsidiary.

In addition, the Amended Credit Agreement contains various financial covenants as defined in the agreement, including:

a maximum leverage ratio of 2.75:1.00 beginning with the fiscal quarter ending December 31, 2014 and

a minimum asset coverage ratio of 1.0 to 1.0 as of June 30 and December 31 of each year.

If oil and gas prices remain at their depressed levels, we currently anticipate a breach of our leverage covenant under our Amended Term Loan Facility (see Note 12 – Debt Obligations) in or about the third quarter of 2015, which will result in a default under the terms of the Amended Term Loan Facility and a liquidity shortfall at the end of the fourth quarter of 2015. Based on this determination, we have classified the outstanding balance of the Amended Term Loan Facility as a current liability in the line item “Current maturities of debt” and the related remaining deferred financing costs as a current asset in our Consolidated Balance Sheets as of December 31, 2014.

Revolving Credit Facility

On April 12, 2012, we entered into a Revolving Credit Facility, with Cyan Partners, LP, as administrative agent, under which we ultimately borrowed $115 million.

On January 24, 2014, we repaid the balance outstanding under the Revolving Credit Facility with proceeds from the Term Loan Facility. Following the repayment, the Revolving Credit Facility was terminated and all of the associated liens on the collateral securing our obligations were released.

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Endeavour International Corporation

(Debtor-in Possession)

Notes to Consolidated Financial Statements

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

6.5% Convertible Senior Notes

On February 28, 2014, we entered into a securities purchase agreement (the “Securities Purchase Agreement”) relating to the issuance of up to $55 million in common stock, warrants and convertible notes. We closed on an initial $30 million in late February and early March 2014, comprised of:

2.9 million shares of our common stock;

warrants to purchase 0.7 million shares of our common stock at an exercise price of $5.292 per share, expiring on February 28, 2019; and

$17.5 million in aggregate principal amount of our 6.5% Convertible Senior Notes.

The 6.5% Convertible Senior Notes have a maturity date the same as the Term Loan Facility. Interest is payable on the 6.5% Convertible Senior Notes quarterly.

The 6.5% Convertible Senior Notes are:

convertible at any time;

convertible initially at a rate 214.5002 shares of our common stock per $1,000 principal amount of 6.5% Convertible Notes (equivalent to an initial conversion price of approximately $4.662 per share of our common stock);

subject to certain anti-dilution adjustments;

subject to customary events of default;

general unsecured and unsubordinated obligations; and

equally ranked in right of payment with all of our existing and future unsubordinated indebtedness and senior in right of payment to any of our future indebtedness that is expressly subordinated to the 6.5% Convertible Notes.

Five Year Debt Maturities

Assuming our debt is not accelerated due to our potential covenant breach, principal maturities of debt for which we are contractually obligated at December 31, 2014 are as follows:



2015	$	—
2016		220,316
2017		457,500
2018		554,000
2019		—
Thereafter		—

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Endeavour International Corporation

(Debtor-in Possession)

Notes to Consolidated Financial Statements

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

Fair Value

The fair value of our outstanding debt obligations was $446.1 million and $868.4 million at December 31, 2014 and 2013, respectively. The fair values of long-term debt were determined based upon external market quotes for our 2018 Notes and 5.5% Convertible Senior Notes and discounted cash flows for other debt, which results in a Level 3 fair-value measurement.

Note 13 – Income Taxes

The income (loss) before income taxes and the components of the income tax expense (benefit) recognized on the Consolidated Statement of Operation are as follows:

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Notes to Consolidated Financial Statements

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


(Amounts in thousands)	U.K.		U.S.		Other		Total
Year Ended December 31, 2014:
Net loss before taxes	$	(741,005)	$	(137,440)	$	(16,499)	$	(894,944)

PRT tax current expense		9,172		—		—		9,172
PRT tax deferred benefit		(4,272)		—		—		(4,272)
PRT tax expense		4,900		—		—		4,900

Corporate current expense (benefit)		(127)		—		21		(106)
Corporate deferred benefit		(59,483)		—		—		(59,483)
Corporate tax expense (benefit)		(59,610)		—		21		(59,589)

Total tax expense (benefit)		(54,710)		—		21		(54,689)

Net loss after taxes	$	(686,295)	$	(137,440)	$	(16,520)	$	(840,255)

Year Ended December 31, 2013:
Net loss before taxes	$	(35,273)	$	(44,591)	$	(9,173)	$	(89,037)

PRT tax current expense		20,667		—		—		20,667
PRT tax deferred benefit		(13,978)		—		—		(13,978)
PRT tax expense		6,689		—		—		6,689

Corporate current expense		—		—		30		30
Corporate deferred benefit		(277)		—		—		(277)
Corporate tax expense (benefit)		(277)		—		30		(247)

Total tax expense		6,412		—		30		6,442
Net loss after taxes	$	(41,685)	$	(44,591)	$	(9,203)	$	(95,479)

Year Ended December 31, 2012:
Net income (loss) before taxes	$	(22,959)	$	(91,383)	$	2,344	$	(111,998)

PRT tax current expense		31,796		—		—		31,796
PRT tax deferred benefit		(14,823)		—		—		(14,823)
PRT tax expense		16,973		—		—		16,973

Corporate current expense		—		—		26		26
Corporate deferred benefit		(11,358)		—		—		(11,358)
Deferred tax expense related to U.K. tax law change		8,587		—		—		8,587
Corporate tax expense (benefit)		(2,771)		—		26		(2,745)

Total tax expense		14,202		—		26		14,228
Net income (loss) after taxes	$	(37,161)	$	(91,383)	$	2,318	$	(126,226)

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Endeavour International Corporation

(Debtor-in Possession)

Notes to Consolidated Financial Statements

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

Effective Tax Rate Reconciliation

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%.



	Year Ended December 31,
	2014		2013		2012
Federal income tax benefit at statutory rate	$	(313,230)	$	(31,163)	$	(39,199)
Taxation of foreign operations		(65,478)		21,998		5,859
Effect of out-of-period adjustment		—		—		6,997
Change in valuation allowance		232,513		15,343		30,329
U.K. tax increase from tax law and rate changes		—		—		8,587
Goodwill impairment		90,733		—		—
Disallowed executive compensation		88		247		1,655
Other		685		17		—

Total Income Tax Expense (Benefit)	$	(54,689)	$	6,442	$	14,228
Effective Income Tax Rate		6%		-7%		-13%

During 2014, 2013 and 2012, we incurred taxes primarily related to our operations in the U.K. During 2014, in the U.K. we had a loss before taxes of $741.0 million that included significant oil and gas property impairments (see Note 7 – Property and Equipment). As a result, the U.K realized a net deferred tax asset at December 31, 2014. We recorded a valuation allowance on the deferred tax asset as there was no assurance that we could generate sufficient U.K. taxable earnings to fully utilize all of the deferred tax assets.

In 2014, 2013 and 2012, we had losses before taxes of $137.4 million, $44.6 million and $91.4 million, respectively, in the U.S. and we did not record any income tax benefits on these losses as there was no assurance that we could generate any future U.S. taxable earnings. As a result, we recorded a valuation allowance on the full amount of all deferred tax assets generated in the U.S.

Deferred Tax Assets and Liabilities

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.

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Notes to Consolidated Financial Statements

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

The tax effects of temporary differences that give rise to significant portions of deferred tax assets and liabilities are as follows at December 31:


	2014		2013
Net deferred tax asset:
Deferred compensation	$	1,861	$	2,401
Asset retirement obligation		53,140		84,941
Net operating loss and capital loss carryforward		422,828		423,374
Unrealized loss on embedded derivative instruments		—		1,265
Property, plant and equipment		19,633		14,086
Inventory / other		769		2,185
Total deferred tax assets		498,231		528,252
Less valuation allowance		(335,251)		(103,171)
Total deferred tax assets after valuation allowance		162,980		425,081

Deferred tax liability:
Property, plant and equipment		(192,847)		(526,274)
Petroleum revenue tax, net of tax benefit		(16,100)		(17,967)
Debt discount		—		(471)
Total deferred tax liabilities		(208,947)		(544,712)
Net deferred tax liability	$	(45,967)	$	(119,631)

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Endeavour International Corporation

(Debtor-in Possession)

Notes to Consolidated Financial Statements

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

Tax Attributes

At December 31, 2014, we had the following tax attributes available to reduce future income taxes:



		As of December 31,
		2014			2013
	Types of Tax Attributes	Years of Expiration	Carry-forward Amount		Years of Expiration	Carry-forward Amount
U.K.
Corporate tax	NOL	Indefinite	$	610,743	Indefinite	$	638,466
Supplemental Corporate tax	NOL	Indefinite		346,828	Indefinite		455,318

U.S.
Corporate Income tax	NOL	2023 - 2034		354,171	2023 - 2033		232,745
State Income tax	NOL	2015 - 2034		84,069	2014 - 2033		83,613
Capital gains tax	Capital loss	2015		1,848	2015		1,848

Valuation Allowances and Unrecognized Tax Benefits

Recognition of the benefits of the deferred tax assets requires that we generate future taxable income. In the U.S., 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 $149.7 million and $103.0 million as of December 31, 2014 and 2013, respectively, primarily related to our U.S. operations. In the U.K. there can be no assurance that we will generate sufficient earnings to fully utilize the existing deferred tax assets. Therefore, we established a valuation allowance for deferred tax assets of $185.5 million as of December 31, 2014.

During 2014, the valuation allowance in the U.S. increased $47.0 million due to net operating losses, increased $185.5 million in the U.K. and decreased $0.4 million in other jurisdictions.

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(Debtor-in Possession)

Notes to Consolidated Financial Statements

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

During 2013, the valuation allowance in the U.S. increased $18.3 million, $2.9 million for net revisions and $15.4 million due to net operating losses, and increased $0.2 million for net operating losses in other jurisdictions. During 2012, the valuation allowance in the U.S. increased $29.1 million due to net operating losses and decreased $3.0 million in other jurisdictions. For U.S. federal income tax purposes, certain limitations are imposed on an entity’s ability to utilize its NOLs in future periods if a change of control, as defined for federal income tax purposes, has taken place. In general terms, the limitation on utilization of NOLs and other tax attributes during any one year is determined by the value of an acquired entity at the date of the change of control multiplied by the then-existing long-term, tax-exempt interest rate. 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.

Uncertain Tax Positions

At December 31, 2013, we had an unrecognized tax benefit of $6.8 million relating to various U.K. tax matters. That amount increased $0.7 million during the year. However, the statute of limitations for assessing tax for this benefit expired at the end of 2014, thus allowing the full recognition of these benefits. The benefit was recorded as a reduction to tax expense.

For the years ended December 31, 2014, 2013 and 2012, no interest or penalty expense had been incurred.

The following represents a reconciliation of the change in our unrecognized tax benefits, for the year ended December 31, 2014.



		December 31,
		2014		2013
Balance at the beginning of the year	$	6,820	$	6,820
Decrease in unrecognized tax benefits from lapse in statute of limitations		(6,820)		—
Balance at the end of the year	$	—	$	6,820

The following tax years remain subject to examination:



Tax Jurisdiction
U.K.	2013 - 2014
All others	2012 - 2014

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Endeavour International Corporation

(Debtor-in Possession)

Notes to Consolidated Financial Statements

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

Foreign Earnings and Credits

As of December 31, 2014, we had de minimus unremitted earnings in our foreign subsidiaries. If these unremitted earnings had been dividend to the U.S., the U.S. NOLs 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 14 – Monetary Production Payment

Our monetary production payment liability, net of repayments, consisted of the following at December 31, 2014:



	December 31,
	2014		2013
Monetary production payment	$	—	$	166,667
Less: current portion		—		74,167

Long-term monetary production payment	$	—	$	92,500

During 2013, we entered into various monetary production payment arrangements (collectively, the “Monetary Production Payments”) covering the proceeds of sale from a portion of EEUK’s entitlement to production from its interests in the certain fields located in the U.K. sector of the North Sea. We issued the Monetary Production Payments in the following manner:

In March through May 2013, a total of $125 million, with an effective interest rate of 10.0%, associated with production from our interests in the Alba and Bacchus fields;

In August 2013, $25 million, with an effective interest rate of 8.75%, associated with production from our interests in the Alba and Bacchus fields; and

In December 2013, $25 million, with an effective interest rate of 9.75%, associated with production from our interests in the Rochelle field.

On September 30, 2014, we repaid the balance of the Monetary Production Payments outstanding with proceeds from the Amended Term Loan Facility. Following the repayment, the Monetary Production Payments were terminated and all of the associated liens on the collateral securing our obligations were released (see Note 12 – Debt Obligations).

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(Debtor-in Possession)

Notes to Consolidated Financial Statements

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

Note 15 – Other Long-Term Liabilities

Other long-term liabilities included the following:



	December 31,
	2014		2013
Asset retirement obligations	$	65,935	$	121,534
Long-term derivative liabilities		—		9,245
Other		142		591
Total Other Liabilities	$	66,077	$	131,370

Asset retirement obligations relate to our obligation for 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, 2014 and 2013:



	Year Ended
	December 31,
	2014		2013
Carrying amount of asset retirement obligations, as of beginning of period	$	170,429	$	176,076
Decrease due to revised estimates		(31,362)		(10,304)
Accretion expense (included in DD&A expense)		25,890		23,793
Impact of foreign currency exchange rate changes		(9,057)		3,205
Payment of asset retirement obligations		(49,418)		(27,690)
Liabilities incurred and assumed		—		5,349
Carrying amount of asset retirement obligations, as of end of year		106,482		170,429

Less: current portion of asset retirement obligations		(40,547)		(48,895)
Long-term asset retirement obligations	$	65,935	$	121,534

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Endeavour International Corporation

(Debtor-in Possession)

Notes to Consolidated Financial Statements

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

Note 16 – Equity

The activity in shares of our common and preferred stock during 2014, 2013 and 2012 included the following:



	Year Ended December 31, 2014
	2014	2013	2012
Common Stock:
Outstanding at the beginning of the year	46,981	46,691	37,663
Issuance of common stock	2,917	—	8,625
Exercise of stock options	—	23	—
Conversion of preferred stock	2,537	—	—
Issuance of stock based compensation	465	267	403
Outstanding at the end of the year	52,900	46,981	46,691

Series B Preferred Stock:
Outstanding at the end of the year	20	20	20

Series C Convertible Preferred Stock:
Outstanding at the beginning of the year	37	37	37
Conversion to common stock	(22)	—	—

Outstanding at the end of the year	15	37	37

Treasury Stock:
Outstanding at the end of the year	(72)	(72)	(72)

Common Stock

The Common Stock is $0.001 par value common stock, and 125,000,000 shares are authorized.

In April 2014, we issued the warrants to purchase 2,130,680 shares of our common stock, with an exercise price of $5.29 per share, in connection with our litigation settlement. The warrants expire on April 16, 2019 and are subject to customary anti-dilution provisions.

In February 2014, we entered into the Securities Purchase Agreement whereby we issued 2.9 million shares of our common stock and warrants to purchase 0.7 million shares of our common stock for a total of $12.5 million in cash. The warrants have an exercise price of $5.292

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Endeavour International Corporation

(Debtor-in Possession)

Notes to Consolidated Financial Statements

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

per share and expire on February 28, 2019 and are subject to customary anti-dilution provisions. See Note 12 for additional information.

In March 2013, we entered into warrant agreements through which we issued 3,440,000 warrants to purchase shares of our common stock at an exercise price of $3.014 per share, expiring on April 30, 2018, and warrants to purchase a total of 560,000 shares of our common stock at an exercise price of $3.685 per share, expiring on May 21, 2018. The warrants were entered into in connection with our Monetary Production Payments, additional discussion of which can be found in Note 14. Both warrant agreements are subject to customary anti-dilution provisions and include a cashless exercise provision which entitles investors to surrender a portion of the underlying common stock that has a value equal to the aggregate exercise price in lieu of paying cash upon exercise of a warrant.

In January 2013, in connection with our entry into the Procurement Agreement, we issued warrants to purchase a total of 1,000,000 shares of our common stock at an exercise price of $7.31 per share to the investor. The warrants expire on January 9, 2018 and are subject to customary anti-dilution provisions. Additional information concerning the Procurement Agreement can be found in Note 24.

In June 2012, we completed an underwritten public offering of 8.6 million shares of common stock at a price of $7.50 per common share ($7.13 per common share, net of underwriting discounts) for net proceeds of $60.8 million.

In May 2012, we entered into warrant agreements through which we issued certain investors warrants to purchase a total of 2,000,000 shares of our common stock at an exercise price of $10.50 per share. The warrants were entered into in connection with the May 31, 2012 reimbursement agreement (see Note 24 for additional discussion of this reimbursement agreement). The terms of each of the warrants are substantially identical. The warrants expire on January 24, 2016 and are subject to customary anti-dilution provisions. We also agreed to provide the investors with customary resale registration rights as soon as reasonably practicable.

Series C Convertible Preferred Stock

As of December 31, 2014, we have 14,800 shares of Series C convertible preferred stock (the “Series C Preferred Stock”) outstanding, convertible into 1.7 million shares of common stock. The Series C Preferred Stock is convertible into common stock at any time at the option of the holders at a conversion price of $8.75, plus accrued but unpaid dividends. The Series C Preferred Stock ranks senior to any of our other existing or future shares of capital stock. Dividends on the Series C Preferred Stock are:

cumulative;

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

compounded quarterly based on the original issue price;

payable in cash or common stock, at 4.5% or 4.92%, respectively; and

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

The Series C Preferred Stock also participates on an as-converted basis with respect to any dividends paid on the common stock.

The Series C Preferred Stock is redeemable for a cash payment of an amount equal to 102% of the sum of the liquidation preference of $1,000 per share plus accrued but unpaid dividends. If we call the Series C Preferred Stock for redemption, the holders have the right to convert their shares into a newly issued preferred stock identical in all respects to the Series C Preferred Stock except that such newly issued preferred stock will not bear a dividend.

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

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

During 2014, holders of a portion of our Series C Preferred Stock converted 22,200 preferred shares, with a face value of $22.2 million, into 2.5 million shares of our common stock.

Series B Preferred Stock

In September 2002, we authorized and designated 500,000 shares of preferred stock, as Series B preferred stock par value $.001 per share (the “Series B Preferred Stock”).

The Series B Preferred Stock is entitled to dividends of 8% of the original issuing price per share per annum, which are cumulative prior to any dividends on the common stock and on parity with the payment of any dividend or other distribution on any other series of preferred stock that has similar characteristics. The holders of each share of Series B Preferred Stock are entitled to be

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Notes to Consolidated Financial Statements

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

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.

For discussion of the potential impact of our filings under Chapter 11 of the Bankruptcy Code on our equity, see Note 3 – Voluntary Reorganization under Chapter 11.

Note 17 – Stock-Based Compensation Arrangements

We grant restricted stock, performance units 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.

At December 31, 2014, total compensation cost related to nonvested awards not yet recognized was approximately $2.1 million and is expected to be recognized over a weighted average period of less than two years. For the year ended December 31, 2014, we included approximately $0.9 million of stock-based compensation in capitalized G&A in property and equipment.

Stock Options

The fair value of each option award is estimated on the date of grant using the Black-Scholes option-pricing model. We have not granted any options during the last three years.

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Notes to Consolidated Financial Statements

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

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, 2012	299	$	8.95
Exercised	(1)		6.73
Expired	(110)		12.04

Balance outstanding - December 31, 2012	188	$	6.72	5.5	$	85

Exercised	(23)		3.78
Forfeited	(45)		5.98

Balance outstanding - December 31, 2013	120	$	7.55	4.3	$	55

Expired	(13)		5.76

Balance outstanding - December 31, 2014	107	$	7.76	0.8	$	—
Currently exercisable - December 31, 2014	107	$	7.76	0.8	$	—

Information relating to stock options outstanding at December 31, 2014 is summarized as follows:



	Options Outstanding				Options Exercisable
Range of Exercise Prices	Number of Options Outstanding	Weighted Average Remaining Contractual Life	Weighted Average Exercise Price Per Share		Number Exercisable	Weighted Average Exercise Price Per Share
Less than $5.00	32	2.0	$	4.36	32	$	4.36
$5.00 - $8.00	—	—		—	—		—
Greater than $8.00	75	0.3		9.24	75		9.24

Total	107	0.8	$	7.76	107	$	7.76

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Notes to Consolidated Financial Statements

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

Restricted Stock

At December 31, 2014, our employees and directors held 0.7 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, 2014 and the changes during the year ended December 31, 2014 are presented below:



			Weighted
			Average Grant
			Date Fair
	Number of		Value per
	Shares		Share
Balance outstanding - January 1, 2014		628	$	7.44
Granted		693		4.53
Vested		(353)		8.29
Forfeited		(228)		5.35

Balance outstanding - December 31, 2014		740	$	4.95

Total grant date fair value of shares vesting during the period	$	3,137

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



		Year Ended
		December 31, 2014
	2014		2013		2012

G&A Expenses (Income) (1)	$	(3)	$	3,607	$	4,641
Capitalized G&A		942		1,236		1,634
Total non-cash stock-based compensation	$	939	$	4,843	$	6,275

⁽¹⁾

Decrease in non-cash stock-based compensation recorded in G&A Expenses in 2014 is due to forfeitures which exceeded non-cash stock-based compensation expense recorded for the year.

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Notes to Consolidated Financial Statements

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

Performance-Based Share Awards

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

Status of the performance-based share awards as of December 31, 2014 and the changes during the year ended December 31, 2014 are presented below:



		Weighted
		Average Grant
		Date Fair
	Number of	Value per
	Shares	Share
Balance outstanding - January 1, 2014	707	$	11.01
Granted	516		8.29
Expired	(96)		16.72
Forfeited	(703)		10.04

Balance outstanding - December 31, 2014	424	$	8.04

For discussion of the potential impact of our filings under Chapter 11 of the Bankruptcy Code on our equity, see Note 3 – Voluntary Reorganization under Chapter 11.

Note 18 – Loss per Share

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

For each of the periods presented, shares associated with stock options, warrants, convertible debt, convertible preferred stock and certain stock incentive plans are not included when their

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Notes to Consolidated Financial Statements

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

inclusion would be antidilutive (i.e., reduce the net loss per share). The common shares potentially issuable arising from these instruments excluded from weighted average diluted shares outstanding consisted of:



	For the Year Ended December 31,
	2014	2013	2012
Options, warrants and stock-based compensation	10,272	7,981	2,111
Convertible debt	12,363	12,041	11,532
Convertible preferred stock	1,691	4,229	4,229

Common shares potentially issuable	24,326	24,251	17,872

For discussion of the potential impact of our filings under Chapter 11 of the Bankruptcy Code on our equity, see Note 3 – Voluntary Reorganization under Chapter 11.

Note 19 – Supplementary Cash Flow Disclosures

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



	Year Ended December 31,
	2014		2013		2012

Interest paid	$	81,577	$	94,941	$	66,365

Income taxes paid (refunded), all related to PRT	$	(21,519)	$	57,132	$	426

Reorganization items paid	$	5,432	$	—	$	—

The cash paid for income taxes for the year ended December 31, 2013 includes $17 million related to 2012 that was not payable until 2013. In addition, we paid $40 million in 2013 of which $21.5 million was refunded during 2014.

Non-Cash Investing and Financing Transactions

During 2012, we completed a nonmonetary exchange of our Bull Bayou Haynesville and Willow Springs Cotton Valley properties for all of J-W’s upstream and midstream interests in the Pennsylvania Marcellus area. The exchanged properties were recorded on a carryover basis.

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Notes to Consolidated Financial Statements

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

In 2014, 2013 and 2012, we recorded $5.7 million, $7.1 million and $8.7 million, respectively, in non-cash interest expense that was added to the principal balance of the 11.5% Convertible Bonds, the $50 million Subordinated Notes and the Senior Term Loan.

Note 20 – Financial Instruments



	December 31, 2014				December 31, 2013
	Fair Value		Carrying Value		Fair Value		Carrying Value
Liabilities:
Debt	$	446,139	$	432,181	$	868,406	$	870,878
Derivative instruments		—		—		9,245		9,245

The carrying amounts reflected in the consolidated balance sheets for cash and equivalents, short-term receivables and short-term payables approximate their fair value due to the short maturity of the instruments. The fair values of commodity derivative instruments and interest rate swaps were determined based upon quotes obtained from brokers. The fair values of long-term debt were determined based upon market quotes for our Senior Notes and discounted cash flows for our other debt. As of December 31, 2014, only the Amended Term Loan Facility is subject to fair value reporting. The fair value of our Amended Term Loan Facility was determined based upon a discounted cash flow model. As a result, all fair value measures related to our debt are considered Level 3.

Note 21 – Related Party Transactions

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

Note 22 – Fair Value Measurements

We measure the fair value of financial assets and liabilities on a recurring basis, defining fair value as the price that would be received to sell an asset or paid to transfer a liability in an

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Notes to Consolidated Financial Statements

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

orderly transaction between market participants at the measurement date. The fair value is based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. This includes not only the credit standing of counterparties involved and the impact of credit enhancements but also the impact of our own nonperformance risk on our liabilities. Fair value measurements are classified and disclosed in one of the following categories:

Level 1:Fair value is based on actively-quoted market prices, if available.

Level 2:In the absence of actively-quoted market prices, we seek price information from external sources, including broker quotes and industry publications. Substantially all of these inputs are observable in the marketplace during the entire term of the instrument, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace.

Level 3:If valuations require inputs that are both significant to the fair value measurement and less observable from objective sources, we must estimate prices based on available historical and near-term future price information and certain statistical methods that reflect our market assumptions.

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

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.

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Notes to Consolidated Financial Statements

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

The following table summarizes the valuation of our investments and financial instruments by pricing levels as of December 31, 2014 and 2013:



	Quoted Market Prices		Significant Other		Significant
	in Active Markets		Observable Inputs		Unobservable Inputs		Total
	Level 1		Level 2		Level 3		Fair Value
As of December 31, 2014:
Embedded derivatives	$	—	$	—	$	—		$	—

Total derivative liabilities	$	—	$	—	$	—		$	—

As of December 31, 2013:
Embedded derivatives		—		—		(9,245)			(9,245)

Total derivative liabilities	$	—	$	—	$	(9,245)		$	(9,245)

We use a derivative valuation model to derive the value of our embedded derivative features. Key inputs into this valuation model are our current stock price, risk-free interest rates, the stock volatility and our implied credit spread. The first three aforementioned inputs are based on observable market data and are considered Level 2 inputs while the last two aforementioned inputs are unobservable and thus require management’s judgment and are considered Level 3 inputs. A 5% decrease or increase in the stock volatility has an inverse effect to the change in the liability and would result in an approximately $0.5 million decrease or increase, respectively, at December 31, 2013. A 5% decrease or increase in the stock volatility would not impact the fair values at December 31, 2014.

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Notes to Consolidated Financial Statements

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

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



	Year Ended
	December 31,
	2014		2013
Liabilities at beginning of period	$	(9,245)	$	(7,402)
Derivative issuance		(1,755)		—
Realized losses included in earnings		175		—
Unrealized gains (losses) included in earnings		10,825		(1,843)
Liabilities at end of period	$	—	$	(9,245)

Changes in unrealized gains (losses) relating to derivative
liabilities still held at the end of the period	$	9,245	$	(1,843)

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

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

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

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

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Notes to Consolidated Financial Statements

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

Note 23 – Derivative Instruments

We had embedded derivatives related to debt and equity instruments outstanding at December 31, 2014 and 2013. The fair market value of these derivative instruments is included in our balance sheet as follows:



	December 31,
	2014		2013
Derivatives not designated as hedges:
Embedded derivatives related to debt and equity instruments:
Other liabilities - long-term	$	—	$	(9,245)

Based on our filing under Chapter 11 of the Bankruptcy Codes as discussed in Note 1 – General and the related probable cancellation of the underlying debt and equity instruments, we wrote off the entire amount of the embedded derivatives recorded as of the Petition Date and recognized a gain of $6.2 million during the third quarter of 2014.

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



	Year Ended December 31,
	2014		2013		2012
Derivatives not designated as hedges:
Oil and gas commodity derivatives:
Unrealized losses	$	(7)	$	—	$	(3,524)
Realized losses		(175)		—		—

Embedded derivatives related to debt and equity instruments:
Unrealized gains (losses)	$	10,825	$	(1,843)	$	8,665

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Notes to Consolidated Financial Statements

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

Note 24 – 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.

Commitments Related to Asset Retirement Obligations

We have entered into decommissioning security agreements related to abandonment liabilities for certain of our oil and gas properties. Under these agreements, we are required to post security from time to time in the form of letters of credit, cash or other agreed-upon consideration. Prior to entry into the LC Issuance Agreement on September 30, 2014 (see below), the commitments under these agreements were not recorded as liabilities, and fees and expenses related to these agreements were included in “Letter of credit fees” in other expenses on our Consolidated Statements of Operations.

Decommissioning Security Agreements

LC Issuance Agreement

On September 30, 2014, in conjunction with the Amended Term Loan Facility, the Company entered into an LC Issuance Agreement (the “LC Issuance Agreement”), pursuant to which Credit Suisse agreed to issue letters of credit for Endeavour UK’s account in the amount of approximately $100.2 million as of December 31, 2014.

The letters of credit secure decommissioning obligations in connection with certain of Endeavour’s U.K. Continental Shelf petroleum production. The Company has collateralized its obligations under the LC Issuance Agreement and all letters of credit issued thereunder by posting cash collateral, which has been funded with the proceeds from the Amended Term Loan Facility.

The posted cash collateral balance of $100.2 million related to the LC Issuance Agreement as of December 31, 2014 is reflected as “Restricted cash, long-term portion” in our condensed consolidated balance sheets. The liability related to the posted cash collateral is included as part of the $440 million Amended Term Loan Facility long-term debt obligation. The LC Issuance Agreement was entered into to replace the Combined Procurement Agreement.

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Endeavour International Corporation

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Notes to Consolidated Financial Statements

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

As of December 31, 2014, we do not expect to begin decommissioning activities for the Alba field for many years. The timing of decommissioning activities will be determined by the ultimate life of the reservoir, which is not expected to occur until 2029 or later.

Combined Procurement Agreement

On January 24, 2014, we entered into a letter of credit procurement agreement (the “Combined Procurement Agreement”) with an unaffiliated third party (“Payee”), where we agreed to reimburse the Payee for any expense incurred by it in connection with the posting of cash collateral to secure letters of credit issued for our account in the amount of approximately £78 million (approximately $130 million as of January 24, 2014, subsequently reduced as discussed below). The letters of credit secured decommissioning obligations in connection with certain of our U.K. licenses. The Combined Procurement Agreement was entered into to replace the LOC Procurement Agreement (see below) and a previous agreement related to the Alba field.

Due to a change in the U.K. tax treatment for decommissioning, we amended our Decommissioning Securities Agreement for the Alba field. The new tax law, which allows companies to treat decommissioning on an after-tax basis (including PRT), enabled us to reduce our current letter of credit amount. Prior to entry into the LC Issuance Agreement, we had approximately $90 million in outstanding letters of credit securing decommissioning obligations under the Combined Procurement Agreement.

Under the Combined Procurement Agreement, we paid a quarterly fee computed at a rate of LIBOR plus 7.00% per year (provided that LIBOR shall equal at least 1.25% per year) on the aggregate balance of posted cash collateral.

Concurrent with our entry into the LC Issuance Agreement on September 30, 2014, the Combined Procurement Agreement was terminated, and we paid all outstanding interest and fees of $1.9 million and $2.4 million, respectively.

Procurement Agreement

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

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Endeavour International Corporation

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Notes to Consolidated Financial Statements

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

Under the Procurement Agreement, we agreed to:

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

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

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

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

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

Concurrent with our entry into the Procurement Agreement, we terminated the IVRRH Reimbursement Agreement dated May 23, 2012, which secured letters of credit. Upon termination of the IVRRH Reimbursement Agreement, we paid all outstanding and accrued fees totaling approximately $3.8 million.

Concurrent with our entry into the Combined Procurement Agreement on January 24, 2014, the Procurement Agreement was terminated, and we paid all outstanding and accrued fees totaling approximately $0.2 million.

Reimbursement Agreements

During the second quarter of 2012, we entered into two reimbursement agreements related to abandonment liabilities for certain of our U.K. oil and gas properties. Under these agreements, unaffiliated third parties pledged cash to secure letters of credit covering certain of our abandonment liabilities and we agreed to reimburse the pledged cash in the event that the letters of credit are drawn and pledged cash is utilized to satisfy the commitment. We have no cash collateral associated with the reimbursement agreements and the commitments under the reimbursement agreements are not recorded as liabilities. The associated abandonment obligations are recorded in other long-term liabilities as part of our asset retirement obligations. Fees and expenses related to the reimbursement agreements are included in other expenses on our condensed consolidated statement of operations.

The first reimbursement agreement covered approximately $33 million and was related to our decommissioning obligations at the IVRRH, Renee and Rubie (collectively “IVRRH”) fields (“IVRRH Reimbursement Agreement”) where we are currently paying certain asset retirement costs. In connection with this reimbursement agreement, we issued warrants to purchase two

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Notes to Consolidated Financial Statements

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

million shares of our common stock, with an exercise price of $10.50 per share, to the investors. With the execution of the Procurement Agreement, on January 10, 2013, we terminated the IVRRH Reimbursement Agreement and paid all outstanding and accrued fees totaling approximately $3.8 million.

The second reimbursement agreement covered approximately $120 million related to our decommissioning obligations for the Alba field (the “Alba Reimbursement Agreement”) and matures on June 30, 2014. We paid a fee of 13% per year, payable quarterly, computed based on the outstanding amount of each letter of credit. Our obligations under the Alba Reimbursement Agreement were secured on a pari passu basis with our obligations under the Revolving Credit Facility by a first lien on substantially all of our assets. As of December 31, 2014, we do not expect to begin decommissioning activities for the Alba field for many years. The timing of decommissioning activities will be determined by the ultimate life of the reservoir, which is not expected to occur until 2029 or later.

With the execution of the Combined Procurement Agreement, on January 24, 2014, we terminated the Alba Reimbursement and paid all outstanding and accrued fees totaling approximately $122.0 million.

Terminated Acquisition of Marcellus Assets

SM Energy filed a lawsuit against us in Texas state court on December 20, 2011 alleging that we breached the SM Purchase Agreements by terminating them and refusing to close on the transactions.

On April 16, 2014, we reached an agreement with SM Energy to settle and dismiss the litigation. In accordance with the settlement agreement, we:

forfeited our $6 million deposit;

paid SM Energy $5 million;

will pay an additional $4.5 million in three graduated payments, beginning in April 2015; and

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Notes to Consolidated Financial Statements

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

issued warrants to purchase 2.1 million shares of our common stock with exercise price of $5.29 per share.

As a result of this settlement, we recorded $19 million in total settlement expense during the first quarter of 2014.

Claim by William Transier

We maintained an employment agreement with Mr. Transier that provided for certain severance benefits. Mr. Transier resigned from his positions as Chief Executive Officer and President effective December 1, 2014. Mr. Transier filed a claim with the United States Bankruptcy Court for the District of Delaware on December 16, 2014 in the amount of approximately $6.2 million.

Mr. Transier has asserted that, per his employment agreement, he is entitled to a pro-rata portion of his annual target bonus for the year in which his termination occurred which equates to approximately $0.7 million. Additionally he asserts that his contract requires the payment on termination of employment during the contract term (i) at the Company’s election other than as a result of the executive’s misconduct or disability or (ii) at the executive’s election following a “corporate change” or a breach of the employment agreement by us or other “good reason.” Citing “corporate change” and “good reason,” Mr. Transier’s severance claim of approximately $5.5 million is calculated as follows:

(i)

three times the sum of the executive’s most recent annual salary and deemed bonus (the average bonus paid during the most recent two years);

(ii)

all unvested employee restricted stock awards, performance shares and cash performance awards would vest upon any such termination; and

(iii)

three years of continued coverage for accident and group health insurance benefits substantially similar to those he received immediately prior to the date of termination.

We have not accrued any portion of the severance claim as a pre-petition liability as of December 31, 2014.

Legal Proceedings

Refer to Note 3 for information concerning the Bankruptcy Cases.

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Operating Leases

At December 31, 2014, we have leases for office space and equipment with lease payments as follows:



2015	$	1,018
2016		785
2017		255
2018		—
Thereafter		—

Note 25 – 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:



	2014				2013				2012
	Revenue		Long-lived Assets			Revenue	Long-lived Assets		Revenue		Long-lived Assets
United States	$	6,729	$	35,540	$	8,368	$	113,888	$	11,877	$	123,977
United Kingdom		309,303		434,042		329,296		1,247,248		207,181		1,189,870
Other		—		(1)		—		3,475		—		2,264

Total	$	316,032	$	469,581	$	337,664	$	1,364,611	$	219,058	$	1,316,111

Total International	$	309,303	$	434,041	$	329,296	$	1,250,723	$	207,181	$	1,192,134

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Note 26 – Quarterly Financial Data (Unaudited)



	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
	2014 (1) (2) (3) (4)
Revenues	$	94,163	$	44,857	$	86,445	$	90,567
Operating expenses		76,987		44,338		338,512		542,897
Operating profit (loss)		17,176		519		(252,067)		(452,330)
Net loss to common stockholders		(45,326)		(37,129)		(294,652)		(464,477)
Net income (loss) per common share -
basic and diluted		(0.91)		(0.72)		(5.64)		(9.34)

	2013 (5)
Revenues	$	57,672	$	126,165	$	36,901	$	116,926
Operating expenses		49,453		94,908		44,899		87,922
Operating profit (loss)		8,219		31,257		(7,998)		29,004
Net loss to common stockholders		(14,502)		(14,341)		(40,341)		(28,118)
Net loss per common share - basic and diluted		(0.31)		(0.30)		(0.86)		(0.60)

⁽¹⁾

Includes litigation settlement expense of $19.0 million for the first quarter of 2014.

⁽²⁾

Includes loss on early extinguishment of financing agreements of $3.5 million and $30.7 million for the first and third quarters of 2014, respectively.

⁽³⁾

Includes goodwill impairment loss of $259.2 million for the third quarter of 2014.

⁽⁴⁾

Includes reorganization items of $43.2 million for the fourth quarter of 2014.

⁽⁵⁾

Includes impairments of oil and gas properties of $3.5 million and $6.0 million for the first and third quarters of 2013, respectively, and $476.7 million for the fourth quarter of 2014.

Note 27 – Guarantor Subsidiaries

Certain of our wholly-owned domestic subsidiaries have, jointly and severally, fully and unconditionally guaranteed the 2018 Notes. Pursuant to SEC regulations, we have presented in columnar format the condensed consolidating financial information for Endeavour International Corporation, the guarantor subsidiaries on a combined basis, and all non-guarantor subsidiaries on a combined basis.

The subsidiary guarantees are unsecured obligations of each subsidiary guarantor and rank equally in right of payment with all senior indebtedness of that subsidiary guarantor and senior in right of payment to all subordinated indebtedness of that subsidiary guarantor. The subsidiary guarantees are effectively subordinated to any secured indebtedness of the subsidiary guarantor with respect to the assets securing the indebtedness. In addition, the subsidiary guarantees may be released in certain customary circumstances, including (i) the sale of all or substantially all of

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the properties or assets of a guarantor, (ii) the sale of the capital stock of a guarantor, (iii) the designation of a guarantor as an “Unrestricted Subsidiary,” (iv) upon legal defeasance of the 2018 Notes or satisfaction and discharge of the indentures governing the 2018 Notes, (v) upon the liquidation or dissolution of the guarantor or (vi) if the guarantor ceases to guarantee other of our indebtedness and ceases to be a material subsidiary, each of which is subject to important limitations in the indentures governing the 2018 Notes.

During 2014, we executed an intercompany loan agreement, effective May 2012, between Endeavour International Corporation and one of its wholly-owned subsidiaries that is a guarantor of the Senior Notes. As the intercompany loan is effective for prior periods, the revisions for this loan and related interest to the applicable prior periods are reflected in the financial information herein. The intercompany loan has no effect on our consolidated results of operations or financial statement position.

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

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As of December 31, 2014
	Endeavour International Corporation		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Cash and cash equivalents	$	-	$	32,055	$	49,795	$	-	$	81,850
Accounts receivable		-		2,427		33,080		-		35,507
Current receivables due from affiliates		477,351		53,174		104,085		(634,610)		-
Prepaid expenses and other		-		7,350		40,047		-		47,397
Current Assets		477,351		95,006		227,007		(634,610)		164,754

Property, plant and equipment, net		-		35,529		433,980		-		469,509
Restricted cash, long-term portion		-		-		100,241		-		100,241
Long-term receivables due from affiliates		554,000		500,000		-		(1,054,000)		-
Investments in subsidiaries		57,662		219,058		-		(276,720)		-
Other assets		-		10		62		-		72
Total Assets	$	1,089,013	$	849,603	$	761,290	$	(1,965,330)	$	734,576

Accounts payable	$	-	$	2,065	$	25,299	$	-	$	27,364
Current maturities of debt		-		-		432,181		-		432,181
Deferred revenue		-		-		14,157		-		14,157
Current liabilities due to affiliates		648		581,402		52,560		(634,610)		-
Asset retirement obligations, current portion		-		42		40,505		-		40,547
Accrued expenses and other		385		5,663		9,148		-		15,196
Current Liabilities		1,033		589,172		573,850		(634,610)		529,445

Long-term liabilities due to affiliates		-		554,000		500,000		(1,054,000)		-
Deferred taxes		-		-		56,670		-		56,670
Other liabilities		1		436		65,640				66,077
Total Liabilities Not Subject to Compromise		1,034		1,143,608		1,196,160		(1,688,610)		652,192
Liabilities Subject to Compromise		751,219		6,079		83,746		-		841,044

Series C convertible preferred stock		17,481		-		-		-		17,481
Stockholders' equity (deficit)		319,279		(300,084)		(518,616)		(276,720)		(776,141)
Total Liabilities and Equity	$	1,089,013	$	849,603	$	761,290	$	(1,965,330)	$	734,576

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As of December 31, 2013
	Endeavour International Corporation		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Cash and cash equivalents	$	-	$	2,417	$	32,325	$	-	$	34,742
Accounts receivable		-		1,832		63,339		-		65,171
Current receivables due from affiliates		853,900		20,782		45,982		(920,664)		-
Prepaid expenses and other		-		594		59,724		-		60,318
Current Assets		853,900		25,625		201,370		(920,664)		160,231

Property, plant and equipment, net		-		87,313		984,838		-		1,072,151
Goodwill		-		-		259,238		-		259,238
Long-term receivables due from affiliates		-		500,000		8		(500,008)		-
Investments in subsidiaries		57,662		219,066		-		(276,728)		-
Other assets		20,518		6,056		6,648		-		33,222
Total Assets	$	932,080	$	838,060	$	1,452,102	$	(1,697,400)	$	1,524,842

Accounts payable	$	-	$	1,214	$	36,819	$	-	$	38,033
Current maturities of debt		-		-		-		-		-
Deferred revenue		-		-		20,965		-		20,965
Monetary production payment deposit		-		-		74,167		-		74,167
Current liabilities due to affiliates		648		899,853		20,171		(920,672)		-
Accrued expenses and other		27,474		3,352		57,799		-		88,625
Current Liabilities		28,122		904,419		209,921		(920,672)		221,790

Long-term debt		678,850		-		192,028		-		870,878
Long-term liabilities due to affiliates		-		-		500,000		(500,000)		-
Deferred taxes		-		-		146,213		-		146,213
Monetary production payment, long-term portion		-		-		92,500		-		92,500
Other liabilities		3,535		601		127,234		-		131,370
Total Liabilities		710,507		905,020		1,267,896		(1,420,672)		1,462,751

Series C convertible preferred stock		43,703		-		-		-		43,703
Stockholders' equity		177,870		(66,960)		184,206		(276,728)		18,388
Total Liabilities and Equity	$	932,080	$	838,060	$	1,452,102	$	(1,697,400)	$	1,524,842

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For the Year Ended December 31, 2014
	Endeavour International Corporation		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Revenue	$	-	$	6,729	$	309,303	$	-	$	316,032
Operating expenses		-		4,486		82,504		-		86,990
DD&A expense		-		2,523		173,221		-		175,744
Impairment of oil and gas properties		-		71,562		405,159		-		476,721
Goodwill impairment loss		-		-		259,238		-		259,238
Insurance proceeds		-		-		(10,786)		-		(10,786)
G&A expenses		166		248		14,413		-		14,827
Loss from Operations		(166)		(72,090)		(614,446)		-		(686,702)

Derivatives:
Realized losses		-		-		(175)		-		(175)
Unrealized gains		5,115		-		5,703		-		10,818
Interest expense		(65,251)		(64,240)		(105,923)		126,480		(108,934)
Letter of credit fees		-		-		(8,492)		-		(8,492)
Financing and transaction costs		(516)		(9,204)		(1,234)		-		(10,954)
Loss on early extinguishment of financing agreements		-		-		(34,297)		-		(34,297)
Litigation settlement expense		-		(19,034)		-		-		(19,034)
Reorganization items		(29,619)		(9,318)		(4,285)		-		(43,222)
Unrealized foreign currency gains (losses)		-		(2)		5,712				5,710
Other income (expense)		66,480		60,405		(67)		(126,480)		338
Loss before taxes		(23,957)		(113,483)		(757,504)		-		(894,944)
Income tax benefit		-		-		(54,689)		-		(54,689)
Net loss		(23,957)		(113,483)		(702,815)		-		(840,255)
Preferred stock dividends		1,329		-		-		-		1,329
Net loss to common shareholders	$	(25,286)	$	(113,483)	$	(702,815)	$	-	$	(841,584)

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For the Year Ended December 31, 2013
	Endeavour International Corporation		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Revenue	$	-	$	8,368	$	329,296	$	-	$	337,664
Operating expenses		-		7,399		98,045		-		105,444
DD&A expense		-		4,249		138,799		-		143,048
Impairment of oil and gas properties		-		9,566		-		-		9,566
G&A expenses		2,502		7,764		8,858		-		19,124
Income (loss) from Operations		(2,502)		(20,610)		83,594		-		60,482

Derivatives:
Unrealized losses		(503)		-		(1,340)		-		(1,843)
Interest expense		(81,400)		2,988		(86,105)		60,001		(104,516)
Letter of credit fees		-		-		(33,425)		-		(33,425)
Financing and transaction costs		(27)		(2,542)		(4,405)		-		(6,974)
Loss on early extinguishment of financing agreements		-		-		-		-		-
Unrealized foreign currency losses		-		-		(3,116)		-		(3,116)
Other income (expense)		-		60,005		351		(60,001)		355
Income (loss) before taxes		(84,432)		39,841		(44,446)		-		(89,037)
Income tax expense		-		-		6,442		-		6,442
Net income (loss)		(84,432)		39,841		(50,888)		-		(95,479)
Preferred stock dividends		1,823		-		-		-		1,823
Net income (loss) to common shareholders	$	(86,255)	$	39,841	$	(50,888)	$	-	$	(97,302)

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For the Year Ended December 31, 2012
	Endeavour International Corporation		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Revenue	$	-	$	11,877	$	207,181	$	-	$	219,058
Operating expenses		-		6,968		51,568		-		58,536
DD&A expense		-		8,603		57,961		-		66,564
Impairment of oil and gas properties		-		53,072		-		-		53,072
G&A expenses		2,629		9,887		8,569		-		21,085
Income (loss) from Operations		(2,629)		(66,653)		89,083		-		19,801

Derivatives:
Unrealized gains (losses)		(705)		-		5,846		-		5,141
Interest expense		(54,163)		(66,645)		(67,673)		104,359		(84,122)
Letter of credit fees		-		-		(21,903)		-		(21,903)
Financing and transaction costs		-		(1,410)		(4,606)		-		(6,016)
Loss on early extinguishment of financing agreements		-		-		(21,661)		-		(21,661)
Unrealized foreign currency gains		-		-		8,080	-	-	-	8,080
Other income (expense)		53,082		47,740		(7,781)		(104,359)		(11,318)
Loss before taxes		(4,415)		(86,968)		(20,615)		-		(111,998)
Income tax expense		-		-		21,225		(6,997)		14,228
Net loss		(4,415)		(86,968)		(41,840)		6,997		(126,226)
Preferred stock dividends		1,823		-		-		-		1,823
Net loss to common shareholders	$	(6,238)	$	(86,968)	$	(41,840)	$	6,997	$	(128,049)

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For the Year Ended December 31, 2014
	Endeavour International Corporation		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Cash Flows from Operating Activities:
Net loss	$	(23,957)	$	(113,483)	$	(702,815)	$	—	$	(840,255)
Adjustments to reconcile net loss to
net cash provided by (used in) operations
DD&A expense		—		2,523		173,221		—		175,744
Impairment of oil and gas properties		—		71,562		405,159		—		476,721
Goodwill impairment loss		—		—		259,238		—		259,238
Deferred tax benefit		—		—		(63,755)		—		(63,755)
Unrealized gains on derivatives		(5,115)		—		(5,703)		—		(10,818)
Amortization of non-cash compensation		741		—		—		(857)		(116)
Amortization of loan costs and discount		7,065		—		15,174		—		22,239
Non-cash interest expense		—		—		5,739		—		5,739
Loss on early extinguishment of debt		—		—		22,708		—		22,708
Non-cash litigation settlement expense		—		—		—		14,034		14,034
Non-cash reorganization items		29,619		—		3,899		—		33,518
Other		—		(182,517)		175,170		—		(7,347)
Changes in operating assets and liabilities:
Decrease (increase) in receivables		—		55,069		(25,583)		—		29,486
Decrease (increase) in other current assets		142		(6,651)		(9,758)		—		(16,267)
Increase (decrease) in liabilities		19,405		150,614		(203,001)		—		(32,982)
Net Cash Provided by (Used in)
Operating Activities		27,900		(22,883)		49,693		13,177		67,887

Cash Flows From Investing Activities:
Capital expenditures		—		(16,077)		(75,542)				(91,619)
Proceeds from sales, net of cash		—		1,353		—		—		1,353
Proceeds from insurance settlement		—		—		15,120		—		15,120
Increase in restricted cash		—		—		(100,113)		—		(100,113)
Net Cash Used in Investing Activities		—		(14,724)		(160,535)		—		(175,259)

Cash Flows From Financing Activities:
Repayments of borrowings		—		—		(240,163)		—		(240,163)
Borrowings under debt agreements, net
of debt discount		17,500		—		554,325		—		571,825
Proceeds from issuance of common stock		12,396		—		—		—		12,396
Repayments of MPP		—		—		(166,667)				(166,667)
Financing costs paid		(625)		—		(19,184)		—		(19,809)
Intercompany cash management		(54,069)		67,246		—		(13,177)		—
Other financing		(3,102)		(1)		1		—		(3,102)
Net Cash Provided by (Used in)
Financing Activities		(27,900)		67,245		128,312		(13,177)		154,480

Net Change in Cash and Cash Equivalents		—		29,638		17,470		—		47,108
Cash and Cash Equivalents, Beginning
of Period		—		2,417		32,325		—		34,742
Cash and Cash Equivalents, End of Period	$	—	$	32,055	$	49,795	$	—	$	81,850

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For the Year Ended December 31, 2013
	Endeavour International Corporation		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Cash Flows from Operating Activities:
Net loss	$	(84,432)	$	39,841	$	(50,888)	$	—	$	(95,479)
Adjustments to reconcile net loss to
net cash provided by (used in) operations
DD&A expense		—		4,249		138,799		—		143,048
Impairment of oil and gas properties		—		9,566		—		—		9,566
Deferred tax benefit		—		—		(14,255)		—		(14,255)
Unrealized losses on derivatives		503		—		1,340		—		1,843
Amortization of non-cash compensation		622		—		—		2,984		3,606
Amortization of loan costs and discount		7,826		—		14,533		—		22,359
Non-cash interest expense (income)		—		(12,958)		20,040		—		7,082
Other		44		12,942		3,344		—		16,330
Changes in operating assets and liabilities:
Decrease (increase) in receivables		—		863		(19,854)		—		(18,991)
Decrease (increase) in other current assets		—		(14,252)		15,576		—		1,324
Increase (decrease) in liabilities		—		(13,628)		(24,395)		19,038		(18,985)
Net Cash Provided by (Used in)
Operating Activities		(75,437)		26,623		84,240		22,022		57,448

Cash Flows From Investing Activities:
Capital expenditures		—		(15,111)		(211,881)		1,237		(225,755)
Acquisitions, net of cash acquired		—		65		(2,852)		—		(2,787)
Proceeds from sales, net of cash		—		6,712		62		—		6,774
Net Cash Used in Investing Activities		—		(8,334)		(214,671)		1,237		(221,768)

Cash Flows From Financing Activities:
Proceeds from issuance of MPP		—		—		175,000		—		175,000
Repayments of MPP		—		—		(8,333)		—		(8,333)
Financing costs paid		(700)		(500)		(35,296)		11,286		(25,210)
Intercompany cash management		77,874		(43,329)		—		(34,545)		—
Other financing		(1,737)		157		—		—		(1,580)
Net Cash Provided by (Used in)
Financing Activities		75,437		(43,672)		131,371		(23,259)		139,877

Net Change in Cash and Cash Equivalents		—		(25,383)		940		—		(24,443)
Cash and Cash Equivalents, Beginning
of Period		—		27,800		31,385		—		59,185
Cash and Cash Equivalents, End of Period	$	—	$	2,417	$	32,325	$	—	$	34,742

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For the Year Ended December 31, 2012
	Endeavour International Corporation		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations (1)		Consolidated
Cash Flows from Operating Activities:
Net loss	$	(4,415)	$	(86,968)	$	(41,840)	$	6,997	$	(126,226)
Adjustments to reconcile net loss to
net cash provided by (used in) operations
DD&A expense		—		8,603		57,961		—		66,564
Impairment of oil and gas properties		—		53,072		—		—		53,072
Deferred tax benefit		—		—		(10,597)		(6,997)		(17,594)
Unrealized losses (gains) on derivatives		705		—		(5,846)		—		(5,141)
Amortization of non-cash compensation		854		—		—		3,547		4,401
Amortization of loan costs and discount		6,908		5		7,266		—		14,179
Non-cash interest expense		445		—		8,239		—		8,684
Loss on early extinguishment of debt		—		—		21,661		—		21,661
Other		283		173		14,909		—		15,365
Changes in operating assets and liabilities:
Decrease (increase) in receivables		—		1,495		(25,814)		—		(24,319)
Decrease (increase) in other current assets		—		(9,223)		8,631		—		(592)
Increase (decrease) in liabilities		—		88,635		(21,617)		(38,459)		28,559
Net Cash Provided by (Used in)
Operating Activities		4,780		55,792		12,953		(34,912)		38,613

Cash Flows From Investing Activities:
Capital expenditures		—		(39,794)		(207,131)		—		(246,925)
Acquisitions, net of cash acquired		—		(2,372)		(236,482)		—		(238,854)
Proceeds from sales, net of cash		—		—		1,407		—		1,407
Issuance of note receivable to affiliate		—		(500,000)		—		500,000		—
Increase in restricted cash		—		(50)		(128)		—		(178)
Net Cash Used in Investing Activities		—		(542,216)		(442,334)		500,000		(484,550)

Cash Flows From Financing Activities:
Repayments of borrowings		(32,457)		—		(242,172)		—		(274,629)
Borrowings under debt agreements, net
of debt discount		538,860		—		115,163		—		654,023
Borrowings from affiliates		—		—		500,000		(500,000)		—
Proceeds from issuance of common stock		60,805		—		—		—		60,805
Payments for early extinguishment of debt		—		—		(7,248)		—		(7,248)
Financing costs paid		(24,141)		—		(8,063)		—		(32,204)
Intercompany cash management		(546,186)		511,274		—		34,912		—
Other financing		(1,661)		(1)		1		—		(1,661)
Net Cash Provided by (Used in)
Financing Activities		(4,780)		511,273		357,681		(465,088)		399,086

Net Change in Cash and Cash Equivalents		—		24,849		(71,700)		—		(46,851)
Cash and Cash Equivalents, Beginning
of Period		—		2,951		103,085		—		106,036
Cash and Cash Equivalents, End of Period	$	—	$	27,800	$	31,385	$	—	$	59,185

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(Debtor-in Possession)

Notes to Consolidated Financial Statements

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

⁽¹⁾

The $7.0 million adjustment reflects the correction of an immaterial error in deferred income taxes that was corrected to beginning stockholder’s equity as of January 1, 2010 in the separate financials of the non-guarantor subsidiaries but reflected in the statement of operations for Endeavour for the year-ended December 31, 2012.

⁽²⁾

Revised to reflect intercompany cash management activities previously presented cash flows from operations in “Cash Flows From Financing Activities.” There was no impact to Consolidated balances.

Note 28– Subsequent Events

As a result of the recent decline in oil and gas prices and the implications on our liquidity and results of operations, we have had discussions with certain of our creditors and/or their advisors. Following these discussions, on February 3, 2015, we filed a Notice of Adjournment of Confirmation Hearing with the Bankruptcy Court. That notice discloses the delay of the Bankruptcy Court’s review and confirmation hearing regarding the RSA Plan. A new date for the confirmation hearing has not yet been determined. Subsequent to filing the Notice, we continued to have discussions with certain of our creditors and their advisors and the advisors to the Official Committee of Unsecured Creditors appointed by the Bankruptcy Court concerning the impact of such price declines on the RSA Plan and potential amendments thereto and to the RSA.

We have determined that as a result of this decline in commodity prices, the RSA Plan is not feasible and, accordingly, we will not continue to seek its confirmation. See Note 3 - Voluntary Reorganization under Chapter 11 for additional information concerning our Bankruptcy Cases and potential defaults under our Amended Term Loan Facility and liquidity concerns.

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Notes to Consolidated Financial Statements

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

Note 29 - Supplemental Oil and Gas Disclosures (Unaudited)



Capitalized Costs Relating to Oil and Gas Producing Activities
	United Kingdom		United States		Total
December 31, 2014:
Proved	$	935,557	$	54,201	$	989,758
Unproved		-		10,784		10,784
Total capitalized costs		935,557		64,985		1,000,542

Accumulated depreciation, depletion and amortization		(501,894)		(29,179)		(531,073)

Net capitalized costs	$	433,663	$	35,806	$	469,469

December 31, 2013:
Proved	$	1,043,927	$	40,742	$	1,084,669
Unproved		295,083		73,577		368,660
Total capitalized costs		1,339,010		114,319		1,453,329

Accumulated depreciation, depletion and amortization		(355,366)		(27,429)		(382,795)

Net capitalized costs	$	983,644	$	86,890	$	1,070,534

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Notes to Consolidated Financial Statements

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



Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
		United Kingdom		United States		Total
Year Ended December 31, 2014:
Acquisition costs:
Proved	$	—	$	—	$	—
Unproved		—		—		—
Exploration costs		18,976		20,107		39,083
Development costs		38,711		3,743		42,454
Total costs incurred	$	57,687	$	23,850	$	81,537

Year Ended December 31, 2013:
Acquisition costs:
Proved	$	—	$	—	$	—
Unproved		2,323		463		2,786
Exploration costs		39,202		11,644		50,846
Development costs		149,138		3,068		152,206
Total costs incurred	$	190,663	$	15,175	$	205,838

Year Ended December 31, 2012:
Acquisition costs:
Proved	$	143,004	$	1,176	$	144,180
Unproved		46,878		1,156		48,034
Exploration costs		46,730		15,397		62,127
Development costs		164,562		7,900		172,462
Total costs incurred	$	401,174	$	25,629	$	426,803

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(Debtor-in Possession)

Notes to Consolidated Financial Statements

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



Results of Operations for Oil and Gas Producing Activities
		United Kingdom	United States		Total
Year Ended December 31, 2014:
Revenues	$	309,303	$	6,729	$	316,032
Production expenses		82,504		4,486		86,990
DD&A		172,343		1,825		174,168
Impairment of oil and gas properties		405,159		71,562		476,721
Income tax expense		(217,436)		(24,900)		(242,336)
Results of activities	$	(133,267)	$	(46,244)	$	(179,511)

Year Ended December 31, 2013:
Revenues	$	329,296	$	8,368	$	337,664
Production expenses		98,045		7,399		105,444
DD&A		137,739		3,242		140,981
Impairment of oil and gas properties		—		9,566		9,566
Income tax expense (benefit)		57,977		(4,144)		53,833
Results of activities	$	35,535	$	(7,695)	$	27,840

Year Ended December 31, 2012:
Revenues	$	207,181	$	11,877	$	219,058
Production expenses		51,568		6,968		58,536
DD&A		56,813		7,574		64,387
Impairment of oil and gas properties		—		53,072		53,072
Income tax expense (benefit)		61,256		(19,508)		41,748
Results of activities	$	37,544	$	(36,229)	$	1,315

Oil and Gas Reserves

Proved reserves are estimated quantities of oil, gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can reasonably be expected to be recovered through existing wells with existing equipment and operating methods. The reserve volumes presented are estimates only and should not be construed as being exact quantities. These reserves may or may not be recovered and may increase or decrease as a result of our future operations and changes in economic conditions. Our oil and gas reserves were audited by independent reserve engineers at December 31, 2014, 2013 and 2012.

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Notes to Consolidated Financial Statements

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

	United Kingdom	United States	Total
Proved Oil Reserves (mbbls):
Proved reserves at January 1, 2012	4,060	41	4,101
Production	(1,994)	(3)	(1,997)
Purchases of reserves	11,071	—	11,071
Sales of reserves in place	—	(19)	(19)
Extensions and discoveries	1,992	—	1,992
Revisions of previous estimates	(1,396)	(13)	(1,409)
Proved reserves at December 31, 2012	13,733	6	13,739
Production	(3,017)	(1)	(3,018)
Purchases of reserves	—	—	—
Sales of reserves in place	—	—	—
Extensions and discoveries	—	—	—
Revisions of previous estimates	1,624	(3)	1,621
Proved reserves at December 31, 2013	12,340	2	12,342
Production	(2,564)	(8)	(2,572)
Purchases of reserves	—	—	—
Sales of reserves in place	—	—	—
Extensions and discoveries	—	73	73
Revisions of previous estimates	(3,813)	8	(3,805)
Proved reserves at December 31, 2014	5,963	75	6,038

Proved Developed Oil Reserves (mbbls):
At December 31, 2012	5,261	6	5,267
At December 31, 2013	5,659	2	5,661
At December 31, 2014	5,744	75	5,819

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Notes to Consolidated Financial Statements

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



	United Kingdom	United States	Total
Proved Gas Reserves (mmcf):
Proved reserves at January 1, 2012	50,723	60,978	111,701
Production	(91)	(5,206)	(5,297)
Purchases of reserves	1,409	998	2,407
Sales of reserves in place	—	(5,213)	(5,213)
Extensions and discoveries	473	—	473
Revisions of previous estimates	4,387	(36,867)	(32,480)
Proved reserves at December 31, 2012	56,901	14,690	71,591
Production	(1,194)	(2,636)	(3,830)
Purchases of reserves	—	—	—
Sales of reserves in place	—	(4,200)	(4,200)
Extensions and discoveries	—	—	—
Revisions of previous estimates	(309)	3,921	3,612
Proved reserves at December 31, 2013	55,398	11,775	67,173
Production	(6,253)	(1,577)	(7,830)
Purchases of reserves	—	—	—
Sales of reserves in place	—	—	—
Extensions and discoveries	—	24,285	24,285
Revisions of previous estimates	(24,962)	(21,428)	(46,390)
Proved reserves at December 31, 2014	24,183	13,055	37,238

Proved Developed Gas Reserves (mmcf):
At December 31, 2012	3,147	14,690	17,837
At December 31, 2013	18,384	9,792	28,176
At December 31, 2014	24,183	11,456	35,639

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Notes to Consolidated Financial Statements

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



	United Kingdom	United States	Total
Proved Reserves (mboe) (1):
Proved reserves at January 1, 2012	12,514	10,204	22,718
Production	(2,009)	(871)	(2,880)
Extensions and discoveries	2,071	—	2,071
Purchase of proved reserves, in place	11,306	166	11,472
Sale of reserves	—	(888)	(888)
Revisions of previous estimates	(665)	(6,157)	(6,822)
Proved reserves at December 31, 2012	23,217	2,454	25,671
Production	(3,216)	(440)	(3,656)
Extensions and discoveries	—	—	—
Purchase of proved reserves, in place	—	—	—
Sale of reserves	—	(700)	(700)
Revisions of previous estimates	1,572	651	2,223
Proved reserves at December 31, 2013	21,573	1,965	23,538
Production	(3,606)	(271)	(3,877)
Extensions and discoveries	—	4,120	4,120
Purchase of proved reserves, in place	—	—	—
Sale of reserves	—	—	—
Revisions of previous estimates	(7,973)	(3,563)	(11,536)
Proved reserves at December 31, 2014	9,994	2,251	12,245

Proved Developed Reserves (mboe):
At December 31, 2012	5,785	2,454	8,239
At December 31, 2013	8,723	1,634	10,357
At December 31, 2014	9,775	1,984	11,759

⁽¹⁾

Mboe is calculated as mbbls plus mmcf divided by 6.

Proved reserves decreased from 23.5 mmboe at December 31, 2013 to 12.2 mmboe at December 31, 2014 primarily due to:

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Notes to Consolidated Financial Statements

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

Chapter 11 under the Bankruptcy Code including the potential consequences from our anticipated breach of our leverage covenant under our Amended Term Loan Facility which are further discussed in Note 3 – Voluntary Reorganization under Chapter 11.

The transfer of all PUD reserves related to our Columbus field of 1.8 mmboe were reclassified to contingent resources as of December 31, 2014 as the field development plan has not yet been approved.

Standardized Measure of Discounted Future Net Cash Flows

Future cash inflows and future production and development costs are determined by applying average 12-month pricing for the year. Oil, gas and condensate prices are escalated only for fixed and determinable amounts under provisions in some contracts. Estimated future income taxes are computed using current statutory income tax rates where production occurs. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor.

At December 31, 2014 and 2013, the prices used to determine the estimates of future cash inflows were as follows:


	December 31,
	2014		2013
	Oil	Gas	Oil	Gas
	($/bbl)	($/mcf)	($/bbl)	($/mcf)
United Kingdom	98.72	8.10	104.45	10.38
United States	84.42	3.40	97.71	2.94

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

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

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Notes to Consolidated Financial Statements

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

Standardized Measure of Discounted Future Net Cash Flows of Proved Reserves
	United Kingdom		United States		Total
December 31, 2014:
Future cash inflows	$	778,119	$	50,693	$	828,812
Future production costs		(282,945)		(14,810)		(297,755)
Future development costs		(357,373)		(100)		(357,473)
Future income tax expense		159,266		—		159,266

Future net cash flows (undiscounted)		297,067		35,783		332,850
Annual discount of 10% for estimated timing		(201,859)		10,974		(190,885)

Standardized measure of future net cash flows	$	498,926		24,809	$	523,735

December 31, 2013:
Future cash inflows	$	1,862,137	$	34,852	$	1,896,989
Future production costs		(571,347)		(12,202)		(583,549)
Future development costs		(593,958)		(605)		(594,563)
Future income tax expense		(133,495)		—		(133,495)

Future net cash flows (undiscounted)		563,337		22,045		585,382
Annual discount of 10% for estimated timing		43,152		6,548		49,700

Standardized measure of future net cash flows	$	520,185	$	15,497	$	535,682

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Notes to Consolidated Financial Statements

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



Principal Sources of Change in the Standardized Measure of Discounted Future Net Cash Flows
	2014		2013		2012
Standardized measure, beginning of period	$	535,682	$	498,978	$	264,872
Net changes in prices and production costs		(133,641)		(33,792)		(33,520)
Future development costs incurred		91,872		140,436		172,462
Net changes in estimated future development costs		134,810		(132,092)		(193,359)
Revisions of previous quantity estimates		(428,696)		88,008		(56,525)
Extensions and discoveries		43,783		—		102,386
Accretion of discount		65,895		78,151		42,589
Changes in income taxes, net		152,102		104,891		(74,778)
Sale of oil and gas produced, net of production costs		(226,799)		(232,220)		(165,547)
Purchased reserves		—		—		457,033
Sales of reserves in place		—		(4,074)		(6,971)
Change in production, timing and other		288,727		27,396		(9,664)

Standardized measure, end of period	$	523,735	$	535,682	$	498,978

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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 and chief financial 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, 2014. Based on that evaluation, our chief executive officer and chief financial 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 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, 2014. 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) in Internal Control – Integrated Framework (2013). Based on our assessment, management concluded our internal control over financial reporting was effective as of December 31, 2014.

Ernst & Young LLP, an independent registered public accounting firm, audited the effectiveness of the Company’s internal control over financial reporting as of December 31, 2014 and issued their attestation report set forth in this Item 9A.

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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, 2014 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 of

Endeavour International Corporation

We have audited Endeavour International Corporation and subsidiaries’ internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). 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, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and 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.

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.

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In our opinion, Endeavour International Corporation and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the 2014 consolidated financial statements of Endeavour International Corporation and subsidiaries and our report dated March 31, 2015 expressed an unqualified opinion thereon.

Houston, Texas

March 31, 2015

Item 9B. Other Information

None.

Part III

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

Structure of the Board

Our Board of Directors consists of seven individuals (each, “directors”). Our Amended and Restated Bylaws allow the Board of Directors to increase or decrease the number of directors by resolution of the Board of Directors. There is no cumulative voting in the election of directors and the directors were elected by a plurality of the votes cast at the Company’s previous annual meetings. The following table sets forth biographical information on the current members of our Board of Directors:


Name	Age	Principal Occupation and Other Directorships
John B. Connally III	68	John B. Connally III has served as a director of the Company and its predecessor company since 2002 and as lead independent director since September 2010. He is an independent oil and gas investor, and he has served as Chairman, CEO and President of Gulf United Energy since September 2010. Mr. Connally also served as a founding director of Nuevo Energy and was a founding director and former CEO of both Pure Energy Group, Inc. and Pure Gas Partners. Mr. Connally was formerly a partner of the law firm Baker Botts in Houston, Texas from 1972 to 1983, specializing in corporate finance transactions in oil and gas. Mr. Connally received a Bachelor of Arts Degree from the University of Texas at Austin and a Juris Doctor from the University of Texas School of Law.

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James H. Browning	65	James H. Browning has served as a director of the Company since 2014. From 1980 until his retirement in 2009, Mr. Browning served as partner at KPMG and has served in a variety of roles, including as the senior technical partner for the Southwest Area, Partner-in-Charge of New Orleans Audit Practice and SEC Reviewing Partner. Mr. Browning has served as a director of Texas Capital Bancshares, Inc. since 2009. He has served as a director of RigNet Inc. since 2010 and has been the Chairman of the Board of RigNet Inc. since 2012. Mr. Browning received his Bachelor of Science degree from Louisiana State University and a Certified Public Accountant.
William D. Lancaster	59	William D. Lancaster has over 35 years of technical and management experience with both public and private entities in the domestic oil and gas industry. He joined GMT Exploration as Vice President of Exploration and Production in 2000, has served as President since April 2001 and has been a member of the board of managers since 2001. From 1978 to 2000, Mr. Lancaster served in various exploration and production positions from Division Geologist to Vice President of Exploration with various oil and gas producers including: Shell Oil Company, Union Pacific Resources, HS Resources, Bass Enterprises Production Company, and Santa Fe Snyder. Mr. Lancaster has extensive exploration, production and business management experience in most North American sedimentary basins. He is the former president of the Colorado Oil and Gas Association (COGA), a director for the Western Energy Alliance (formerly IPAMS), and a member of the Rocky Mountain Association of Geologists (RMAG) and the American Association of Petroleum Geologists (AAPS). Mr. Lancaster received a Bachelor’s degree in Geology from the University of Colorado.
Nancy K. Quinn	61	Nancy K. Quinn has served as a director of the Company since 2004. Ms. Quinn has served on the boards of directors of various energy companies including Helix Energy Solutions Group, Inc. since 2006 and Atmos Energy Corporation since 2004. Since 1996, she has been an independent energy consultant during which time she has held numerous positions including senior advisor to the Beacon Group, focusing on energy industry private equity opportunities and merger and acquisition transactions. Ms. Quinn gained extensive experience in independent exploration and production, as well as in diversified natural gas and oilfield service sectors, while holding leadership positions at Kidder, Peabody & Co. Incorporated from 1982 to 1994 and PaineWebber Incorporated from 1994 to 1995. Ms. Quinn was also previously a member of the boards of Louis Dreyfus Natural Gas from 1999 to 2001 and DeepTech International from 1995 to 1998. Ms. Quinn received her Bachelor of Arts degree from Louisiana State University and a M.B.A. from the University of Arkansas.

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John N. Seitz		63		John N. Seitz has served as a director of the Company since 2004 and as Vice Chairman of the Board of Directors since 2006. He was one of the original co-founders of the Company in 2004 and the strategist behind its focus on North Sea exploration. Mr. Seitz has served as Chairman and CEO of GulfSlope Energy, Inc. since May 2013. He has served as a director of ION Geophysical Corporation since 2003, director of Gulf United Energy, Inc. since 2011, member of the board of managers of Constellation Energy Partners, LLC from 2006 to 20013 and as Co-Chief Executive Officer of the Company from 2004 to 2006. Mr. Seitz has spent much of his career in various executive and management roles at Anadarko Petroleum Corporation, serving most recently as Chief Executive Officer. In 2000, the Houston Geological Society honored him as a “Legend in Wildcatting.” Mr. Seitz began his career as a petroleum geologist with Amoco Production Company. He is a Certified Professional Geological Scientist from the American Institute of Professional Geologists and a licensed professional geoscientist with the State of Texas. Mr. Seitz also serves as a trustee for the American Geological Institute Foundation. Mr. Seitz holds a Bachelor of Science degree in Geology from the University of Pittsburgh, and a Master of Science degree in Geology from Rensselaer Polytechnic Institute.
Sheldon R. Erikson		73		Sheldon R. Erikson has served as a director of the Company since 2010. Mr. Erikson has served as a director of Cameron International Corporation since 1996. He served as Chairman of the board of directors of Cameron from 1996 to 2011, Chief Executive Officer from 1995 through 2008, and was President from 1995 through 2007. Mr. Erikson has also served as a director of Rockwood Holdings, Inc. since 2006, and Frank’s International since August 2013. Previously, Mr. Erikson served as Chairman of the board of directors of the Western Company of North America, a worldwide petroleum service company engaged in pressure pumping, well stimulating and cementing and offshore drilling, from 1988 to 1995 and President and Chief Executive Officer from 1987 to April 1995. He also serves on the board of directors of the National Petroleum Council, the American Petroleum Institute, and the Petroleum Equipment Suppliers Association, of which he is a past chairman of the board of directors. Mr. Erikson received a M.B.A. degree from the Harvard Business School and studied Engineering and Economics at the University of Illinois.

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William L. Transier

Mr. Transier has served as Chairman of the Board of Directors of the Company since 2006. Prior to that, he served as the Company’s Co-Chief Executive Officer and Director since the founding of the Company in 2004. From 2003 to 2004, Mr. Transier was a founder and Co-Chief Executive Officer of NSNV, Inc. From 1999 to 2003, Mr. Transier was Executive Vice President and Chief Financial Officer for Ocean Energy, Inc., an oil and gas exploration and production company, prior to its merger with Devon Energy Corporation. Mr. Transier began his career in public accounting with KPMG LLP, an international audit and business strategy consulting firm, where he served in numerous roles including as partner from 1986 to 1996. Mr. Transier has also served as a director of Helix Energy Solutions Group, Inc. since October 2000 and Paragon Offshore since August 2014. He was also a director of Cal Dive International, Inc. from 2006 to 2012, and Reliant Resources Inc. (now GenOn Energy, Inc.) from 2002 to 2009. Mr. Transier is also a former Chairman of the Natural Gas Supply Association, and former chairman of the Texas Department of Information Resources, having been appointed to that post by Texas Governor Rick Perry. Mr. Transier received a M.B.A. degree from Regis University and a B.B.A in accounting from the University of Texas at Austin.

Mr. Connally brings his many years of experience as a successful independent oil and gas investor, attorney and businessman to the Board of Directors. As the founder of several oil and gas exploration and production companies and former partner of one of the most prestigious energy law firms in the country, Mr. Connally is well versed in our industry. Mr. Connally qualifies as an audit committee financial expert under SEC guidelines.

Mr. Browning brings his nearly 40 years of public accounting experience to the Board of Directors in addition to experience in the energy sector. His in-depth knowledge of oil and gas, financial markets and securities regulation is of immense value to the Board of Directors. Mr. Browning qualifies as an audit committee financial expert under SEC guidelines.

Mr. Lancaster brings over 35 years of U.S. onshore oil and gas experience to the Board of Directors. The technical and management knowledge acquired by Mr. Lancaster throughout his career in both public and private companies is especially valuable to the Board.

Mr. Transier serves as Chairman of the Board and brings his 37 years of experience in the energy industry to the Board of Directors, including a strong financial foundation from his experience as a CPA, as a partner in an international accounting firm and as a Chief Financial Officer prior to founding and leading the Company. On December 1, 2014, Mr. Transier resigned as Chief Executive Officer. On December 16, 2014, Mr. Transier, filed two claims against the Debtors in the bankruptcy proceedings described above. Mr. Transier is seeking to (i) obtain the pro-rated portion of his bonus owed for the year ended December 31, 2014 in the amount of $734,247 and (ii) obtain severance compensation owed as a result of his resignation as President and Chief Executive Officer in the amount of $5,454,344.

Mr. Erikson brings his many years of energy industry experience, knowledge and insight to the Board of Directors. His experience in the design, engineering and marketing of energy products

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and services is especially valuable to the Company. Mr. Erikson also brings over twenty years of corporate governance experience to the Board of Directors.

Ms. Quinn brings her many years of experience in the U.S. financial services industry as well as her superior business leadership skills to the Board of Directors. Ms. Quinn qualifies as an audit committee financial expert under SEC guidelines.

Mr. Seitz brings his many years of experience in executive and management roles within the oil and gas industry to the Board of Directors. Mr. Seitz also brings his knowledge and expertise as a petroleum geologist to the Board of Directors.

Board and Annual Meeting Attendance

Directors are expected to make every effort to attend each Board meeting and each meeting of any Committee on which he or she sits. Attendance in person is preferred but attendance by teleconference will be permitted if necessary. Directors are also expected to make every effort to attend in person the annual meeting of stockholders. Our Board of Directors held 30 meetings during 2014. Each director attended at least 75% of the aggregate total number of Board and committee meetings on which such director served during his or her tenure of service in 2014. In addition, all of the directors attended the 2014 Annual Meeting of Stockholders held in Houston, Texas on May 22, 2014. The Company filed for Chapter 11 reorganization on October 10, 2014 and to date, the Company has not scheduled an annual meeting of Stockholders for 2015.

Director Independence

Our Board of Directors is comprised of a majority of independent directors as required by the NYSE Rules. The Board has determined that Ms. Quinn and Messrs. Browning, Connally, Erikson, Lancaster and Seitz are “independent” as that term is defined by the NYSE Rules and the SEC. In making this determination, the board considered transactions and relationships between each director or his or her immediate family and the Company and its subsidiaries. The purpose of this review was to determine whether any such relationships or transactions were material and, therefore, inconsistent with a determination that the director is independent. When assessing the materiality of a director’s relationship with us, the Board of Directors considers the issue not merely from the standpoint of the director, but also from the standpoint of the person or organizations with which the director has an affiliation.

In particular, in 2014, the Board evaluated Mr. Erikson’s status as a member of the Board of Directors of Cameron International Corporation, to which the Company paid nothing in 2014 and approximately $1.1 million in 2013. Cameron International is a supplier of flow equipment, systems and services to worldwide oil, gas and process industries. The Board determined that, in accordance with the NYSE Rules, these transactions did not affect Mr. Erikson’s independence.

As a result of this review, the Board affirmatively determined, based on its understanding of such transactions and relationships, that, with the exception of Mr. Transier, none of the Company’s directors has any material relationships with the Company or its subsidiaries, and that all such directors are independent of the Company under the standards set forth by the NYSE and the SEC. Accordingly, as required, a majority of the members of the Board are independent.

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Mr. Transier is not independent because of his employment as an executive of the Company. This independence determination is analyzed annually to promote arms-length oversight.

Board Committees

The Board of Directors currently has the following four standing committees:

1.Audit Committee;

2.Compensation Committee;

3.Governance & Nominating Committee; and

4.Technology & Reserves Committee.

The charters for each Committee are available on our website at www.endeavourcorp.com or in print to any stockholder who requests it. Requests may be sent to the attention of the Corporate Secretary, Endeavour International Corporation at 811 Main Street, Suite 2100, Houston, Texas 77002.

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

Audit Committee

The Audit Committee currently consists of Ms. Quinn and Messrs. Browning and Connally. Ms. Quinn serves as Chair of the Audit Committee. While the Board has determined that Ms. Quinn and Messrs. Browning and Connally are qualified to serve as audit committee financial experts, Ms. Quinn is the designated Audit Committee financial expert. The Audit Committee held 6 meetings during 2014. The Board of Directors has determined that all of the members of the Audit Committee are independent in accordance with the requirements of the rules and regulations of the SEC promulgated under the Securities Exchange and the NYSE Rules. The Audit Committee is appointed by the Board of Directors to assist the Board in oversight of:

the integrity of the Company’s financial statements;

the Company’s compliance with legal and regulatory requirements;

the performance of the Company’s internal audit function and independent auditors; and

the independent auditor’s qualifications and independence.

Compensation Committee

The Compensation Committee consists of Ms. Quinn and Messrs. Connally and Erikson. Mr. Connally serves as Chair of the Compensation Committee. The Compensation Committee held 3 meetings during 2014. The Board of Directors has determined that all of the members of the Compensation Committee are independent in accordance with the NYSE Rules and meet the heightened standards of independence with respect to compensation committee members under the NYSE Rules and SEC. The Compensation Committee is appointed by the Board of Directors

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and has overall responsibility for reviewing, evaluating and approving our executive officer compensation arrangements, plans and policies.

The Compensation Committee oversees the administration of compensation programs applicable to all of our employees, including our executive officers, under its charter adopted by the Board of Directors. The Compensation Committee has the sole authority to approve, to the extent the Committee determines necessary or appropriate, the following compensation items for our executive officers:

annual base salary level;

annual incentive opportunity level;

long-term incentive opportunity level;

employment agreements and severance arrangements; and

any special or supplemental benefits, a significant portion of which should be, in the Committee’s view, equity-based compensation, intended to align the employees’ interests with those of our stockholders.

The Compensation Committee has the sole authority to decide whether to retain a compensation consultant to assist in the evaluation of executive officer compensation and has sole authority to approve any such consultant’s fees and other retention terms. The Committee currently retains Meridian Compensation Partners, LLC (“Meridian”) to serve as its executive compensation consultant. Meridian is directly accountable to the Committee for the performance of its consulting services. Meridian does not provide the Company with any other services. The service provided to the Compensation Committee by Meridian does not result in any conflict of interest in light of Rule 10C-1 of the Exchange Act. The Compensation Committee has concluded that no conflict of interest exists that would prevent Meridian from independently representing the Compensation Committee.

The Compensation Committee has delegated administration of compensation programs applicable to employees who are not executive officers to the Chief Executive Officer of the Company.

Governance and Nominating Committee

The Governance and Nominating Committee currently consists of Messrs. Erikson, Connally, and Seitz. Mr. Erikson serves as Chair of the Governance and Nominating Committee. The Governance and Nominating Committee held 2 meetings during 2014 and is appointed by the Board of Directors to:

assist the Board in identifying individuals qualified to become Board members and to recommend to the Board individuals to be nominees for election at the annual meetings of stockholders or to be appointed to fill vacancies;

recommend to the Board director nominees for each committee of the Board;

advise the Board about appropriate composition of the Board and its committees;

recommend corporate governance guidelines and assist the Board in implementing those guidelines; and

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assist the Board in its annual review of the performance of the Board and its committees.

Technology & Reserves Committee

The Technology & Reserves Committee currently consists of Messrs. Seitz and Browning. Mr. Seitz serves as Chair of the Technology & Reserves Committee. The Technology & Reserves Committee held 1 meeting during 2014. The Technology & Reserves Committee is appointed by the Board of Directors to:

provide understanding and clarification of the technical aspects of our business in order to enable the Board to make informed, strategic business decisions and vote on related matters;

review and monitor the Company’s technology strategy and significant technology investments in support of its evolving business needs;

monitor and evaluate current or emerging technologies which might be useful and applicable to the Company’s business;

assist the Company, in consultation with management, in identifying and deploying applicable technologies;

monitor and evaluate the Company’s reserve evaluation process in conjunction with current laws, regulations and industry standards; and

assist the Company, in consultation with management, to evaluate and select independent reserve engineering consultants.

Qualification and Nomination of Director Candidates

The Governance and Nominating Committee has the responsibility under its charter to recommend nominees for election and re-election as directors to the Board of Directors. In February 2007, the Governance and Nominating Committee recommended Board Governance Guidelines which the Board of Directors approved. The guidelines were reviewed and updated in September 2013. Among other governance matters, the Board Governance Guidelines set forth the Company’s Board membership criteria. The Board Governance Guidelines are available on the Company’s website at www.endeavourcorp.com. The Board Governance Guidelines provide that each member should bring a unique and valuable perspective to the governance of the Company. The guidelines envision that when these unique skill sets are combined in an environment of collegial interaction and respect, they provide the overall skill set of the Board and provide a strong governance structure.

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The Board Governance Guidelines delineates two primary areas of skills: business skills, and personal and social skills.



Director Candidate Skill Sets
Business Skill Set		Individual Personal and Social Skill Set

Demonstrated and recognized leadership and success in a professional area important to the company		High personal integrity

Executive experience, especially in the industry		Values compatible and consistent with Endeavour values

Financial expertise including experience with executive accounting, commercial banking, investment banking, mergers and acquisitions, structured financing, corporate finance, institutional management and investing. Knowledge of SEC procedure and regulation		Proven sound, social and business judgment

Board experience in other companies with a focus on the industry		Tough minded but fair team player

Legal expertise with a focus on securities, mergers and acquisitions, investments and corporate practice		Supportive but challenging of management

International expertise with a focus on project development, currency management and flow, markets structure, and socio-political context		Personal desire and willingness to advance the Company

Clear independence		Respected and active externally

The Governance and Nominating Committee is responsible for reviewing, with the Board on an annual basis, the appropriate skills and characteristics required of directors in the context of the current make-up of the Board. This assessment includes issues of diversity, age and skills. While the Governance and Nominating Committee does not have a formal policy with respect to diversity, it seeks nominees with a broad diversity of experience, professions, skills, geographic representation and backgrounds. The Governance and Nominating Committee does not assign specific weights to particular criteria and no particular criterion is necessarily applicable to all prospective nominees. The skill set of the overall Board provides a basis for the evaluation and establishes guidelines for an overall set of skills inherent in the group of members of the Board. In all cases, the skills an individual brings to the Board should be considered in the context of the overall needs for expertise on the Board.

In considering candidates for the Board, the Governance and Nominating Committee will identify the personal characteristics needed in a director nominee so that the Board as a whole will possess the Qualifications of the Board as a Whole as identified in the Board Governance Guidelines and as needed on the Board at the time of the selection of a director nominee. It is expected that the characteristics needed in a director nominee will depend on the skills of current directors and the current needs of the Company. There is currently no set of specific minimum qualifications that must be met by a nominee recommended by the Governance and Nominating Committee. The Governance and Nominating Committee will consider, through such means as

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it considers appropriate, potential director nominees thought to possess the Business Skill Set and the Individual Personal and Social Skill Set as identified in the Board Governance Guidelines.

Recommendation or Nomination of Directors by Stockholders

The Board Governance Guidelines and the Governance and Nominating Committee Charter provide proper procedures for identifying director nominees. The Board Governance Guidelines and the Governance and Nominating Committee Charter are available on the Company’s website at www.endeavourcorp.com or in print to any stockholder who requests it. Requests may be sent to the attention of the Corporate Secretary, Endeavour International Corporation, at 811 Main Street, Suite 2100, Houston, Texas 77002.

Any stockholder wishing to recommend a candidate for director should submit the recommendation in writing in care of the Corporate Secretary, Endeavour International Corporation, at 811 Main Street, Suite 2100, Houston, Texas 77002. The written notice should address all criteria required of such notice under Section 1.8 of the Bylaws. The notice must therefore contain, among other information, the name and address of the stockholder recommending the candidate, the candidate’s name and address, a description of all arrangements or understandings (if any) between the stockholder and the individual being recommended as a potential director, such information about the individual being recommended as would be required to be included in a proxy statement filed under then-current SEC rules, and an indication of the individual’s willingness to serve as a director. The Governance and Nominating Committee will consider all candidates recommended by any stockholder who complies with the foregoing procedures on the same basis as candidates recommended by our directors and other sources.

Codes of Conduct

The Company has adopted a Code of Business Conduct which applies to all employees, including all executive officers. The Code of Business Conduct was reviewed and updated in November 2011, and again in January 2014, and it covers topics including, but not limited to, conflicts of interest, insider trading, competition and fair dealing, discrimination and harassment, confidentiality, payments to government personnel, anti-bribery and anti-corruption laws, U.S. embargos and sanctions, compliance procedures and employee complaint procedures. The Code of Business Conduct is posted on the Company’s website at www.endeavourcorp.com.

The Company has also adopted a Code of Ethics for the Chief Executive Officer and Senior Financial Officers (the “Code of Ethics”), which is posted on our website at www.endeavourcorp.com. We intend to disclose any amendments to, or waivers from, our Code of Ethics on the Company’s website, www.endeavourcorp.com, promptly following the date of any such amendment or waiver.

Board Leadership Structure

William L. Transier currently serves as the Chairman of the Board. The Board believes that independent oversight of management is an important component of an effective Board of Directors, and since Mr. Transier served as the Company’s Chief Executive Officer until

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December 1, 2014, the Board elected to appoint John B. Connally III as Lead Director in September 2010. As Lead Director, Mr. Connally acts as liaison between the Chairman and the independent directors and presides over the executive sessions of the Board’s independent directors. The Board believes that this structure represents an appropriate allocation of roles and responsibilities for the Company at this time. The Board retains the authority to further modify this structure, as and when appropriate, to best address the Company’s circumstances.

Our Board’s Role in Risk Oversight

The Board generally administers its risk oversight function through the Board as a whole, and through its committees and the other executives named in this Form 10-K. Each of these executives attends the meetings of our Board, where the Board routinely receives reports on our financial results, the status of our operations and our safety performance, and other aspects of implementation of our business strategy, with ample opportunity for specific inquiries of management. The Audit Committee provides additional risk oversight through its quarterly meetings, where it receives a report from the Company’s Chief Financial Officer and Principal Accounting Officer, Controller, Internal Audit, and other senior financial officers who review our contingencies, significant transactions and subsequent events, among other matters, with management and our independent auditors. The Compensation Committee helps our Board to identify our exposure to any potential risks created by our compensation programs. The Governance and Nominating Committee oversees risks relating to our corporate compliance programs and assists the Board and management in promoting an organizational culture that encourages commitment to ethical conduct and compliance with the law. The Technology and Reserves Committee assists the Board in overseeing risk relating to our technology and reserves. Each of the Board’s committees makes regular reports to the Board.

Directors’ Continuing Education

The Company’s director education policy can be found in the Board Governance Guidelines. The governance guidelines are available on the Company’s website at www.endeavourcorp.com or in print to any stockholder who requests it. Requests may be sent to the attention of the Corporate Secretary, Endeavour International Corporation at 811 Main Street, Suite 2100, Houston, Texas 77002.

The Company’s policy encourages all members of the Board of Directors to attend director education programs appropriate to their individual backgrounds. The Company believes educational opportunities help directors to stay abreast of developments in corporate governance and best practices relevant to their contribution to Endeavour, the Board of Directors and their specific committee assignments. The director education policy provides that the Company will reimburse directors for all costs associated with attending any director education program.

Director Service on Other Boards

Recognizing the substantial time commitment required of directors, the Company’s expects that directors will serve on the boards of other public companies only to the extent that, in the judgment of our Board, such services do not detract from the directors’ ability to devote the necessary time and attention to the Company. Generally, directors who serve as the Company’s

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Chief Executive Officer should not be on the boards of more than three other public companies, and all other directors should limit their service to no more than five public company boards.

Directors Who Change Job Responsibilities

An individual director who changes the principal employment position he or she held when elected to the Board should notify the chairman of the Governance and Nominating Committee. This policy is not intended to require any director who changes employment to step down. There should, however, be an opportunity for the Board via the Governance and Nominating Committee to review the continued appropriateness of Board membership under these circumstances.

Term Limits and Retirement

The Company does not believe there should be term limits on service as a director on our Board. While term limits could help ensure fresh ideas and viewpoints, such limits have the disadvantage of losing the valuable contribution of directors who have been able to develop, over a period of time, intimate knowledge and in-depth insight into the Company and its operations. As an alternative to term limits, the Governance and Nominating Committee, in consultation with the Chairman, reviews the propriety of each director’s continuation on the Board prior to the conclusion of his or her term.

Stock Ownership Guidelines

The Board of Directors believes that significant stock ownership in the Company by our executive officers and directors leads to a stronger alignment of interests between management and stockholders that will result in enhanced stockholder value. In February 2007, the Board adopted stock ownership guidelines. These guidelines were further reviewed and updated on February 16, 2012 and are expressed as a multiple of annual base salary for executive officers and annual retainer for directors as follows:



Position	Ownership Levels
CEO	6X
All Other Executive Officers	3X
Directors	5X

Directors and executive officers have five years from the adoption of these guidelines, or from taking office, whichever is later, to reach the applicable stock ownership level.

Until the applicable stock ownership level is met, upon the vesting of a restricted stock award and after the payment of taxes due as a result of vesting, the officer or director is required to hold the net vested shares. Net vested shares are the shares remaining after payment of the applicable taxes owed as a result of vesting of the restricted stock. The officer or director will not be required to accumulate any shares in excess of the number of shares owned once the value of shares owned reaches the stock ownership level, regardless of subsequent changes in price of the shares. However, the officer or director may only sell shares, other than as required for the

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payment of taxes due as a result of a vesting, if, after the sale of shares, the officer or director will still be in compliance with the stock ownership level under these guidelines as of the day the shares are sold based on current share price and compensation level. In the event of personal hardship, the Compensation Committee of the Board of Directors has authority to approve deviations from these guidelines.

The Company filed for Chapter 11 reorganization on October 10, 2014. Per the terms of the RSA, all classes of the Company’s equity would be cancelled upon emergence from bankruptcy. Thus, at that time, all director and officer stockholdings will be deemed worthless, and the Board of Directors would expect to reevaluate stock ownership guidelines at that time.

Director Compensation

Compensation for non-employee (“outside”) directors was reviewed in December 2013. At that time, we determined our compensation program for outside directors to be in line with other publicly traded exploration and production companies of a similar market capitalization and peer group. However, the Compensation Committee and the Board as a whole elected to exercise negative discretion to reduce the Annual and “New Director” equity grants from $125,000 to $100,000 for the 2014 year. Directors’ fees are paid on a quarterly basis.

The Compensation Committee did not hold its regularly scheduled meeting in December 2014 and therefore the 2015 cash component remains unchanged. However, and as previously stated, the Company filed for Chapter 11 reorganization on October 10, 2014. At that time all Long-Term Stock Incentive plans were frozen pending cancellation rendering it impossible to award any stock based compensation to our directors in 2015.



	2014	2015
Upon first appointment or election to the Board	Restricted shares of common stock valued at $100,000 on date of grant	N/A

Annual compensation	$50,000	$50,000
	Restricted shares of common stock valued at $100,000 on date of grant	N/A

Attendance fees – Board Meeting	$2,000	Unchanged

Attendance fees – Committee Meetings	$1,500	Unchanged

Audit Committee Chairperson fee	$15,000	Unchanged

Compensation Committee Chairperson fee	$12,500	Unchanged

Committee Chairperson fee for Committees other than Audit & Compensation	$10,000	Unchanged

Lead Director	$20,000	Unchanged

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The following table provides compensation information for the year ended December 31, 2014 for each non-employee member of our Board of Directors.



	Fees Earned in 2014	Stock Awards	Option Awards	Total
Name	($)	($) (5)	($)	($)
James H. Browning (1)	89,500	100,000	-	189,500
John B. Connally III	157,503	100,000	-	257,503
Sheldon R. Erikson	121,500	100,000	-	221,500
Charles J. Hue Williams (2)	31,500	100,000	-	131,500
William D. Lancaster (3)	81,500	100,000	-	181,500
Nancy K. Quinn	138,500	100,000	-	238,500
John N. Seitz	105,000	100,000	-	205,000
William L. Transier (4)	4,167	-	-	4,167

⁽¹⁾

Mr. Browning was appointed to the Board in March 2014.

⁽²⁾

Mr. Hue Williams did not stand for re-election at the Annual Meeting of Stockholders on May 22, 2014. The Compensation Committee, and the Board as a whole, approved the accelerated vesting of all unvested awards upon his retirement.

⁽³⁾

Mr. Lancaster was elected to the Board at the Annual Meeting of Stockholders held on May 22, 2014

⁽⁴⁾

Mr. Transier resigned from his positions as CEO and President effective December 1, 2014.

⁽⁵⁾

These amounts represent the aggregate grant date fair value calculated pursuant to FASB ASC Topic 718, disregarding any estimates or forfeitures on the date of grant. See Note 17 regarding assumptions underlying valuation of equity awards.

The following table presents the grant date fair value of each award made to non-executive directors during 2014 and the aggregate number of share awards outstanding at December 31, 2014.



	Year Ended December 31, 2014		At December 31, 2014
Name	Aggregate Grant Date Fair Value for Restricted Stock Awards ($)	Aggregate Grant Date Fair Value for Stock Option Awards	Aggregate Number of Stock Awards Outstanding (#)	Aggregate Number of Stock Options Outstanding (#)

James H. Browning	100,000	-	29,499	-
John B. Connally III	100,000	-	39,157	-
Sheldon R. Erikson	100,000	-	39,157	-
Charles J. Hue Williams	100,000	-	-	-
William D. Lancaster	100,000	-	48,077	-
Nancy K. Quinn	100,000	-	39,157	-
John N. Seitz	100,000	-	39,157	-
William L. Transier	-	-	-	-

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Executive Officers



Name	Age	Position
Catherine L. Stubbs	48	Chief Financial Officer and Senior Vice President

James J. Emme	58	Executive Vice President, North America

Derek A. Neilson	53	Managing Director, U.K. Operations

Catherine L. Stubbs – Ms. Stubbs has been with the Company since 2004 serving in numerous roles including Director of Accounting and Financial Controls, Director of Treasury and Corporate Development, Vice President and Senior Vice President of Finance. Ms. Stubbs was promoted to the position of Chief Financial Officer on February 14, 2013. Prior to joining the Company, she served as Assistant Controller for Financial Reporting and Corporate Accounting at Devon Energy, Inc. (formerly Ocean Energy, Inc.) from 1997 to 2004. Ms. Stubbs began her career in public accounting with KPMG LLP, an international audit and business strategy consulting firm, where she rose to the position of Audit Manager.

James J. Emme – Mr. Emme joined the Company on January 20, 2010 as Executive Vice President for North America. Prior to joining the Company, Mr. Emme served as Senior Vice President of Exploration at Max Petroleum from September 2009 to January 2010 and President at Source Exploration, LLC from 2008 to 2010. He was also President and Chief Operating Officer for Elk Resources, Inc. from 2006 to 2008. He spent over twenty years with Anadarko Petroleum Corporation serving as Worldwide Vice President of Exploration and Business Development. Mr. Emme began his career at ARCO Oil & Gas in 1978. He is an active member of the American Association of Petroleum Geologists, the Rocky Mountain Association of Geologists and the Houston Geological Society. He also serves in various roles at the Colorado School of Mines.

Derek A. Neilson – Mr. Neilson joined the Company in April 2008 as Chief Reservoir Engineer and was promoted to Director of Reservoir Engineering in 2009. Mr. Neilson was promoted to his current position of Managing Director of U.K. Operations in October 2013. Mr. Neilson has over 30 years of experience in the energy industry and has served in various roles increasing responsibility in petroleum and reservoir engineering, development and management. He began his career with Chevron U.K. Ltd. before joining Total E&P UK Ltd. for assignments in the UK and Internationally.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires our officers and directors and persons who own more than ten percent of our common stock to file with the SEC initial reports of ownership and reports of changes in ownership of our common stock. Such officers, directors and ten percent stockholders are also required by applicable SEC rules to furnish us with copies of all forms filed with the SEC pursuant to Section 16(a) of the Exchange Act.

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Item 11. Executive Compensation

Compensation Discussion and Analysis

The compensation discussion and analysis (“CD&A”) set forth below provides an explanation of our compensation programs, including the objectives of such programs and the rationale for each element of compensation, for our Chief Executive Officer (“CEO”), and our three other most highly compensated Named Executive Officers (“NEO’s”) that were employed with us at the end of the 2014 year. This section also describes the actions and decisions of the Compensation Committee of our Board of Directors as it relates to 2014 compensation decisions. The discussion is divided into the following sections:



I.		The Purpose and Philosophy of Our Executive Compensation Program
II.		Role of the Compensation Committee and Executives in Setting Compensation
III.		Factors Influencing 2014 Compensation
IV.		Elements of Executive Compensation and Decisions for 2014
V.		2015 Compensation
VI.		Tax Matters

The Purpose and Philosophy of Our Executive Compensation Program

The purpose of our executive compensation program is to provide a meaningful reward system that motivates our executives to be good stewards over the interests of our stakeholders and stockholders. It is also intended to provide a competitive total reward program that allows us to attract and retain qualified executive talent from our industry, and among other industries, as appropriate.

Our executive compensation programs are intended to provide incentives for executives to:

Deliver annual performance that reflects the execution of our stated strategy based on annual goals;

Focus on delivering results as a leader in safety and environmental performance;

Remain with us over the long-term;

Reflect the value we place on innovation and personal contribution; and

Focus on being an active thought leader for the industry ensuring a continuing and important role for the upstream industries.

Our compensation philosophy reflects the realities of the competitive market in which we operate and the characteristics of our entrepreneurial environment. The program for executive officers, which consists of base salary, performance-based annual bonus and long-term stock-based incentive awards, is designed to promote the strategic objectives that are critical to our long-term success while closely aligning the interests of our executives with the interests of our

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stockholders. The Compensation Committee’s philosophy in establishing executive compensation programs is:

Compensation programs should be designed to allow us to attract and retain very experienced and high caliber professionals and executives in the oil and gas industry.

Compensation programs should relate to both individual and Company performance.

Compensation programs should reflect our place in the business cycle and the accompanying risk profile of the business.

II.Role of the Compensation Committee and Executives in Setting Compensation

Our executive compensation program is administered by the Compensation Committee of our Board of Directors. The Compensation Committee members include Mr. Sheldon R. Erikson, Ms. Nancy K. Quinn, and Mr. John B. Connally III, who has served as the committee chair since 2004. Mr. Erikson was appointed to the Committee in May 2011.

The Compensation Committee’s responsibilities include:

Evaluating and approving the Company’s overall compensation strategy;

Annually reviewing the performance of and setting the compensation (i.e., salary, incentive awards, and all other elements) for the Company’s CEO;

Annually reviewing the performance of and setting the compensation for the other executive officers after considering the CEO’s recommendations; and

Reviewing and approving annual incentive payouts and long-term incentive awards under our plans.

A more complete description of the Compensation Committee’s responsibilities and functions is set forth in the Compensation Committee’s charter, which can be found on our website at www.endeavourcorp.com.

Consistent with the listing requirements of the New York Stock Exchange, the Compensation Committee is composed entirely of independent, non-employee members of the Board of Directors. Each year, the Compensation Committee reviews any and all relationships that each director may have with us, and the Board of Directors reviews the Compensation Committee’s findings.

While the Compensation Committee has the responsibility to approve and monitor all compensation for our CEO and other NEO’s, the CEO plays an important role in determining executive compensation. At the Compensation Committee’s request, the CEO recommends appropriate company-wide and business unit financial and non-financial performance goals. Similarly, the CEO assists the Compensation Committee by providing his evaluation of the performance of the executive officers who report directly to him, and recommends compensation levels for such officers. The CEO does not provide recommendations to the Compensation Committee regarding his own compensation.

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The Compensation Committee retained the independent executive compensation consultant Meridian Compensation Partners, LLC (“Meridian”) to assist with the evaluation and determinations for our 2014 executive compensation program. Under the terms of the engagement, Meridian reports directly to the Compensation Committee. Meridian works with management to gather information necessary to carry out its obligations to the Compensation Committee, they do not however have a separate engagement with our management. Meridian’s review of 2014 compensation included:

(i)

a review and comparison of compensation programs at our peers;

(ii)

a comparison of executive positions against our compensation peer group and industry market groups; and

(iii)

a review of the design of the relative TSR performance share plan (described below).

In connection with its engagement of Meridian, the Compensation Committee assessed their independence pursuant to applicable SEC and NYSE rules, and concluded that their work for the Compensation Committee does not raise any conflicts of interest. Meridian does not provide any services to the company outside of the compensation analysis.

III.Factors Influencing 2014 Compensation

Market Data

During 2014, the Compensation Committee retained Meridian as an independent compensation consultant to assist it with a market analysis and provide general consulting services. Meridian provided the Compensation Committee with market data from a peer group of companies to assist with its determination of compensation. However, the market data was only used as a comparison for reference, and the Compensation Committee did not target a specific percentile within the market data. On an annual basis the Compensation Committee has historically conducted a review of the peer companies.

2014 Company Performance

Our Compensation Committee has always held that an assessment of Company performance is key in determining annual bonus compensation for the CEO and NEO’s. At the beginning of 2014, the Compensation Committee established a threshold, target and maximum for specific operational and financial goals, and set certain safety and corporate initiatives to use as guidelines to evaluate Company performance.

The Company filed for Chapter 11 reorganization on October 10, 2014, and although certain of the 2014 goals were achieved, to date bonuses for 2014 performance have not been determined or paid to any of our current NEO’s or employees.

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IV.Elements of Executive Compensation and Decisions for 2014

The following describes the primary elements of our executive compensation program and the influence of our philosophy on those elements.

Base Salary

All of our employees are paid a base salary which represents a fixed sum of compensation due the individual in return for their service to us. In establishing base salaries for the NEO’s, the Compensation Committee considers a number of factors including the executive’s job responsibilities, individual achievements and contributions, level of experience, personal compensation history, the base salaries typically paid for similar positions within the oil and gas industry, and the geographic location of our offices.

Our Compensation Committee reviews the base salary of our CEO and all other NEO’s annually to ensure that a competitive position is maintained. Generally, our CEO recommends to the Compensation Committee changes to salaries for executive officers other than himself, while the Compensation Committee independently considers and approves changes to our CEO’s salary. The Compensation Committee independently reviews the market data provided by Meridian, considers the CEO’s recommendations, and then makes its own independent determinations for our executives.

Incentive Compensation Overview

Annual incentive bonus payments are determined primarily by annual operational and financial results and are not directly linked to Endeavour’s stock price performance. Long-term incentive compensation is tied to Endeavour’s stock price performance and to total shareholder return performance relative to a designated industry peer group over a long-term time horizon.

Annual Incentive Bonus Compensation

Executive positions have a target annual incentive bonus range as a percentage of base salary that reflects their level of responsibility in the organization and industry practices. Percentage targets are established by the Compensation Committee with the assistance of market data provided by Meridian. While we use the company performance targets discussed above as guidelines in connection with determining annual incentive bonus amounts, we have retained discretion to make adjustments to potential bonus amounts as we deem necessary.

Individual annual incentive bonus targets for our CEO and NEO’s in 2014 were set in accordance with the table below.

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All potential bonuses would have been capped at 200% of the numbers below as a maximum earnable amount.


Name	2014 Annual Bonus Target (% of Base Salary)
William L. Transier	100%
James J. Emme	100%
Catherine L. Stubbs	65%
Derek A. Neilson	60%

Annual Incentive Bonus Awards for 2014 Performance

As previously described in “2014 Company Performance”, we achieved many of our quantitative operational and financial goals for 2014. However, the Company filed for Chapter 11 reorganization on October 10, 2014 and to date bonuses for 2014 performance have not been determined or paid but remain pending for determination.

Long-Term Incentive Compensation for 2014

Following a review of management’s proposal and in conjunction with Meridian’s market data report, the Compensation Committee approved the structure and amount of the awards at a meeting of the Compensation Committee held in December 2013. The Compensation Committee determined an aggregate target value for the long-term awards that each NEO would receive for the 2014 year with a focus on performance-based awards, and in January 2014, the Compensation Committee granted the CEO and the other NEO’s long-term incentive awards structured as set forth in the following tables:


Type of Award	Vesting Requirement	Vesting Period	Percentage of Total Award Value (CEO and NEO’s)
Restricted Stock	Time-based	One-third per year.	25%

Relative Total Shareholder Return Performance Shares	Performance-based	Performance based on a stock price performance relative to a designated peer group over a three-year performance period.	37.5%

Cash Performance Target Award	Performance-based	Performance based on stock price performance, one-third per year. Cash award made based on the average closing stock price for the last twenty trading days prior to the vesting date.	37.5%

The Company filed for Chapter 11 reorganization on October 10, 2014 and a Restructuring Support Agreement (“RSA”) was filed with bankruptcy court on November 17, 2014. The RSA states that all classes of the Company’s equity will be cancelled upon the Company’s emergence from bankruptcy, and thus all stock based grants awarded in 2014 (and before) will, at that time, be deemed to have no value. Similarly, the Company was delisted from the NYSE in October 2014 rendering all cash performance awards worthless since said awards are linked to stock price performance. We have provided a brief description of the awards that we did originally grant to our NEOs at the beginning of the 2014 year, but none of the NEOs will retain or benefit from the awards or plans described below.

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Relative Total Shareholder Return Performance Share Plan

When setting compensation for the 2014 year, the Compensation Committee maintained the perspective that long-term incentive awards should have a correlation to company performance by linking executive compensation with long-term relative stock performance. Beginning in 2012, the Company granted relative total shareholder return performance shares (TSR performance plan). Under the TSR performance plan, each NEO receives a target number of performance shares in January each year. To earn the performance shares, the relative total shareholder return ranking will be measured among a designated peer group at the end of a three-year performance period.

The peer group for the TSR performance plan was determined with the assistance of Meridian and the payouts are based on the following schedule:



The Company’s Performance Ranking Group Among Peers	Payout as a % of the Number of Target Performance Units
85th Percentile or above	200%

65th to 84th Percentile	150%

35th to 64th Percentile	100%

25th to 34th Percentile	50%

Below 25th Percentile	0%

Since the Company filed for Chapter 11 reorganization in October 2014, these awards will payout in neither stock nor cash. The filing effectively deemed the Company the worst performer in its peer group and therefore the percentage payout will be zero for awards granted under the plan in 2014 or previous years.

Cash Performance Awards

In addition to our relative TSR performance shares, the Company maintained a second long-term incentive vehicle during the 2014 year. Our cash performance award program further strove to link the CEO and other NEO’s performance to the Company’s long-term stock performance. We believed it was important to structure the cash performance award payout opportunities to align with shareholder value while also limiting our shareholder dilution. In 2014, the cash performance awards represented 37.5% of the CEO’s and the other NEO’s awards. The payout level of these awards was tied to stock performance.

The Company’s stock was delisted from the NYSE in October 2014, which means that there is no longer any value associated with the awards.

Restricted Stock Awards

We have historically utilized restricted stock awards to retain executive officers and reward them for absolute long-term stock price appreciation while providing some retention value. Restricted stock awards granted to the CEO and NEO’s in 2014 were designed to vest annually over three

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years from the grant date. As previously stated, the Company filed Chapter 11 reorganization on October 10, 2014 and a RSA was filed with bankruptcy court on November 17, 2014. The RSA states that all classes of the Company’s equity will be cancelled upon emergence from bankruptcy and thus all stock based grants awarded in 2014 (and before) will, at that time, be deemed to have no value.

Key Employee Retention Plan (“KERP”)

Under this plan, a non-debtor subsidiary agreed to pay our NEO’s and certain key employees out of cycle bonuses as an incentive to stay with the Company through our restructuring process. The non-debtor subsidiary agreed to pay our three NEO’s 100% of base salary in two installments, the first was paid in September 2014, and the second is to be paid within 15 days of the earlier of either (i) the closing date of any out of court agreement for the restructuring of Endeavour’s balance sheet, (ii) the effective date of a confirmed plan of reorganization under Chapter 11 of title 11 of the United States Code (the “Bankruptcy Code”) providing for the restructuring of Endeavour’s balance sheet, (iii) the closing date of a sale of all or substantially all of the assets or a majority of the outstanding stock of Endeavour in one or more transactions under section 363 of the Bankruptcy Code or pursuant to a confirmed Chapter 11 plan, and (iv) the date of the entry of an order of a United States Bankruptcy Court ordering the conversion of Endeavour’s Chapter 11 case to a case under Chapter 7 of the Bankruptcy Code. Mr. Transier, our former CEO, was not awarded a retention bonus by the board of directors.

Perquisites and Personal Benefits

We provide our executive officers the same employee benefits that we provide to all full-time employees, such as health, disability and life insurance. We provide a 401(k) savings plan for all employees. Our executive officers participate on the same level as all employees, with Company matching of contributions up to $10,400 for 2014, which was four percent of compensation up to the maximum annual compensation limit of $260,000 in accordance with Section 415 of the Internal Revenue Code of 1986, as amended. All amounts that we contributed to the NEO’s accounts during the 2014 are reflected in the Summary Compensation Table below.

Severance Benefits

We provide severance benefits through our CEO’s previous employment agreement and through change-in-control agreements with each of our remaining NEO’s. These agreements provide for severance compensation to be paid if employment is terminated under certain conditions, such as at the executive’s election for “good reason” following a change in control or a termination by us other than for “misconduct” or “disability”, each as defined in the agreements. The amount of the payments that would be due, however, may be subject to certain Bankruptcy Code limitations. See the Potential Payments Upon Termination or a Change in Control for further details regarding the potential severance or change in control benefits that could be provided to our NEOs.

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V.2015 Compensation

The Company filed for Chapter 11 reorganization on October 10, 2014 and as previously stated, the Compensation Committee did not meet in December 2014 to review executive compensation for 2015. Therefore, no changes were made to the salaries of any of our NEO’s for 2015. Additionally no long-term incentive grants were awarded in January 2015, and as previously stated, bonuses for 2014 performance were not paid.

VI.Tax Matters

Accounting and Tax Implications

Section 162(m) of the Internal Revenue Code of 1986, as amended, generally limits the corporate income tax deduction for compensation paid to the principal executive officer and the three most highly compensated financial officers (other than the chief executive officer) to $1,000,000 annually, unless the compensation is “performance-based compensation” and qualifies under certain other exceptions. Our policy is primarily to design and administer compensation plans which support the achievement of long-term strategic objectives and enhance stockholder value. Where it is consistent with our compensation philosophy, the Compensation Committee will also attempt to structure compensation programs that are tax-advantageous to the Company, although our primary objective will be to provide compensation that we deem to be appropriate in each individual situation. However, Section 162(m) of the Internal Revenue Code of 1986, as amended, is currently not an issue that impacted our compensation decisions in 2014 as the Company has no taxable income in the United States.

Executive Compensation

Summary Compensation Table

The following table sets forth the annual and long-term compensation for services in all capacities to the Company for the fiscal years ended December 31, 2014, 2013 and 2012 for the CEO and the other NEO’s.

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The table below reflects stock awards which require a valuation under FASB ASC Topic 718 which is higher than the target award value set by the Compensation Committee referenced in the footnotes below this table and does not reflect values actually received by any given NEO.



Name and Principal Position		Year	Salary ($)	Bonus ($)	Stock Awards ($)	Non-Equity Incentive Plan Awards ($)	All Other Compensation ($)	Total ($)
				(4)	(5)(6)	(7)	(8)

William L. Transier	(1)	2014	733,333	-	2,223,020	-	10,400	2,966,753
Chief Executive Officer,		2013	800,000	600,000	1,771,034	469,360	10,200	3,650,594
President and Chairman		2012	800,000	1,400,000	2,405,757	588,970	95,600	5,290,327

James J. Emme		2014	475,000	-	1,067,056	237,500	10,400	1,789,956
Executive Vice President –		2013	475,000	250,000	625,052	120,463	10,200	1,480,715
North America		2012	475,000	356,250	1,267,383	79,566	10,000	2,188,199

Catherine L. Stubbs	(2)	2014	325,000	-	533,528	162,500	10,400	1,031,428
Senior Vice President and		2013	293,750	175,000	392,936	28,223	18,482	908,391
Chief Financial Officer		2012	-	-	-	-	-	-

Derek A. Neilson	(3)	2014	320,000	-	533,528	160,000	28,800	1,042,328
Managing Director UK		2013	286,000	306,900	156,271	25,928	25,740	800,839
Operations		2012	-	-	-	-	-	-

⁽¹⁾

Mr. Transier resigned from his positions as CEO and President effective December 1, 2014.

⁽²⁾

Ms. Stubbs was promoted to Senior Vice President, Chief Financial Officer on February 13, 2013.

⁽³⁾

Mr. Neilson was promoted to Managing Director UK Operations on October 21, 2013.

⁽⁴⁾

The amounts represent annual bonus amounts earned during the year and paid at the beginning of the subsequent year.

⁽⁵⁾

For a discussion of long-term incentive awards granted in 2014, see “Compensation Discussion and Analysis – Long-Term Incentive Compensation.” It is our expectation that all classes of our equity will be eliminated in connection with our bankruptcy, but SEC disclosure rules require a grant date value of the awards for this table. The grant date fair value reflected in this table for the stock awards was calculated in accordance with FASB ASC Topic 718, disregarding any estimate of forfeitures. For further assumptions used in the calculation of our equity grants, please see Note 17 – Stock Based Compensation to our Consolidated Financial Statements for the year ended December 31, 2014.

⁽⁶⁾

The amounts reflect the full grant date fair value, assuming the target completion of relative TSR performance-based vesting conditions. FASB ASC Topic 718 requires that valuations of TSR-based performance shares take into account expected price movement performed through a Monte Carlo simulation model. As a result of the high volatility of the stock, this model resulted in an expense value per share of $8.25 which was significantly higher than the stock price on the grant date. Because the TSR conditions were not satisfied for these awards, the NEOs will not receive any value from the awards reflected in this column from any of the 2012, 2013 or 2014 years.

⁽⁷⁾

The amounts represent awards under a Key Employee Retention Plan (“KERP”)..

⁽⁸⁾

This column includes personal benefits and other items shown in the table below.

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2014 Grants of Plan-Based Awards

The following table sets forth certain information with respect to restricted stock awards granted during the year ended December 31, 2014 to each of our NEO’s.



	Grant	Approval	Estimated Future Payouts Under Non-Equity Awards		Estimated Future Payouts Under Equity Incentive Plan Awards		All Other Stock Awards: Number of Shares of	Grant Date Fair Value of Stock
Name	Date	Date	Target	Maximum	Target	Maximum	Stock or Units	Awards
	(1)	(1)	(2)	(2)	(3)(*)	(3)(*)	(*)

William L. Transier	1/2/2014	12/12/2013	937,500	1,875,000	193,699	387,398	117,703	625,003

James J. Emme	1/2/2014	12/12/2013	450,000	900,000	92,976	185,952	56,498	300,004

Catherine L. Stubbs	1/2/2014	12/12/2013	225,000	450,000	46,488	92,976	28,249	150,002

Derek A. Neilson	1/2/2014	12/12/2013	225,000	450,000	46,488	92,976	28,249	150,002

⁽¹⁾

Under our compensation policy, the Compensation Committee approves annual grants of stock awards at its regularly scheduled meeting in December for awards to be issued at the beginning of the following year.

⁽²⁾

The non-equity incentive plan awards reflect the cash performance awards granted in January 2014 which were designed to vest equally in thirds on the anniversary of the award. The total award granted is reflected in our “Target” column above. The “Maximum” column amounts reflect the potential 200% cap of the award, using the assumption that our stock price remains consistent for the remaining years left in the vesting period.

⁽³⁾

The values under these columns represent the number of performance shares granted to the CEO and the other NEO’s in 2014. It shows the potential target and maximum payout amounts granted for the three-year performance period from January 1, 2014 to December 31, 2017.

The Company filed for Chapter 11 reorganization on October 10, 2014. Per the terms of the RSA, all equity of the Company will be deemed to have no value upon emergence from bankruptcy; therefore these awards will never pay out.

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2014 Outstanding Equity Awards at Fiscal Year-End

The following table includes certain information with respect to the value of all unexercised options and unvested stock awards previously awarded to the CEO and other NEO’s at December 31, 2014.



Option Awards
Number of Securities Underlying Unexercised Options					Stock Awards
Name	Exercisable		Option Exercise Price ($)	Option Expiration Date	Number of Shares or units of Stock that have not vested		Market Value of Shares or units of Stock that have not vested ($)

William L. Transier	70,715	-	3.78	1/2/2019	117,703	(1)	-	(6)
	16,234	-	9.24	1/2/2018	432,705	(2)	-	(6)

James J. Emme	-	-	-	-	91,652	(3)	-	(6)
	-	-	-	-	150,338	(2)	-	(6)

Catherine L. Stubbs	1,461	-	3.78	1/2/2019	64,419	(4)	-	(6)
	1,572	-	9.24	1/2/2018	64,414	(2)	-	(6)

Derek A. Neilson	1,508	-	3.78	1/2/2019	36,380	(5)	-	(6)
	3,572	-	9.10	4/7/2018	60,829	(2)	-	(6)

⁽¹⁾

These restricted stock awards were granted on January 2, 2014 to vest in three equal installments commencing on January 2, 2015. Zero shares vested on January 2, 2015 and all unvested awards will be cancelled upon the Company’s emergence from bankruptcy.

⁽²⁾

Of these TSR performance shares, the performance condition was deemed not to be satisfied for all TSR awards, thus zero shares vested on December 31, 2014. All unvested awards will be cancelled upon the Company’s emergence from bankruptcy.

⁽³⁾

Of these restricted stock awards 9,660 were set to vest on January 3, 2015; 25,494 of these restricted stock awards vest in two equal annual installments beginning on January 2, 2015 and 56,498 of these restricted stock awards vest in three equal annual installments beginning on January 2, 2015. Zero shares vested in January 2015 and all unvested awards will be cancelled upon the Company’s emergence from bankruptcy.

⁽⁴⁾

Of these restricted stock awards 1,537 were set to vest on January 3, 2015; 7,967 of these restricted stock awards vest in two equal annual installments beginning on January 2, 2015; 26,666 vest in two equal annual installments beginning on February 13, 2015 and 28,249 of these restricted stock awards vest in three equal annual installments beginning on January 2, 2015. Zero shares vested in January or February 2015 and all unvested awards will be cancelled upon the Company’s emergence from bankruptcy.

⁽⁵⁾

Of these restricted stock awards 1,757 were set to vest on January 3, 2015; 6,374 of these restricted stock awards vest in two equal annual installments beginning on January 2, 2015 and 28,249 of these restricted stock awards vest in three equal annual installments beginning on January 2, 2015. Zero shares vested in January 2015 and all unvested awards will be cancelled upon the Company’s emergence from bankruptcy.

⁽⁶⁾

Represents the market value on December 31, 2014. The Company’s stock was delisted from the NYSE in October 2014 thus zero value is attributed.

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2014 Potential Payments upon Termination or Change in Control Table

The following table includes certain information with respect to potential payments upon termination or change in control to the CEO and NEO’s, assuming that the termination or change in control occurred on December 31, 2014. Actual amounts that could become due upon a termination of employment or a change in control can only be determined with certainty upon the occurrence of the actual event, thus the amounts in the table below are solely are best estimates as to the amounts that could have become payable on December 31, 2014. Mr. Transier’s potential severance compensation is described in the narrative following the table.



Name	Benefit		Termination without Cause or for Good Reason	Death	Disability	Change in Control ($)
James J. Emme	Severance	(1)	-	-	-	1,354,167
	Prorata performance bonus	(1)	-	-	-	475,000
	Restricted stock awards (unvested and accelerated)	(2)	-	-	-	-
	Performance Shares	(2)	-	-	-	-
	Cash performance awards	(2)	-	-	-	-
	Health and welfare benefits continuation	(1)	-	-	-	28,054

Catherine L. Stubbs	Severance	(1)	-	-	-	850,000
	Prorata performance bonus	(1)	-	-	-	211,250
	Restricted stock awards (unvested and accelerated)	(2)	-	-	-	-
	Performance Shares	(2)	-	-	-	-
	Cash performance awards	(2)	-	-	-	-
	Health and welfare benefits continuation	(1)	-	-	-	36,376

Derek A. Neilson	Severance	(1)	-	-	-	752,000
	Prorata performance bonus	(1)	-	-	-	208,000
	Restricted stock awards (unvested and accelerated)	(2)	-	-	-	-
	Performance Shares	(2)	-	-	-	-
	Cash performance awards	(2)	-	-	-	-
	Health and welfare benefits continuation	(1)	-	-	-	-

⁽¹⁾

Pursuant to change in control termination benefits agreements, each Named Executive Officer would receive (i) a payment of two times the sum of his annual salary and his average bonus for the last three years, (ii) a prorata portion of the Executive’s target bonus for the fiscal year in which the change in control termination occurs, and (iii) the standard health and welfare benefits available to our employees for 18 months following a change in control. Such benefits are payable only upon termination, as defined, upon a change in control. The amount for the health and welfare benefits is estimated based on health and welfare benefit costs for 2014. The amount of the payments that would be due, however, may be subject to certain Bankruptcy Code limitations.

⁽²⁾

The Company was delisted from the NYSE in October 2014, thus a value of zero is attributed.

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Employment, Change in Control and Severance Agreements

We provide all of our NEO’s with the opportunity to participate in a change in control termination arrangement and receive vesting acceleration provisions upon a change in control and other specified termination events with respect to their equity-based compensation awards.

We maintained an employment agreement with Mr. Transier that provided for certain severance benefits. The Company filed for Chapter 11 reorganization on October 10, 2014 and Mr. Transier resigned from his positions as Chief Executive Officer and President effective December 1, 2014. Mr. Transier filed a claim with the United States Bankruptcy Court for the District of Delaware on December 16, 2014 in the amount of $6,188,591.

Mr. Transier has asserted that, per his employment agreement, he is entitled to a pro-rata portion of his annual target bonus for the year in which his termination occurred which equates to $734,247. Additionally he asserts that his contract requires the payment on termination of employment during the contract term (i) at the Company’s election other than as a result of the executive’s misconduct or disability or (ii) at the executive’s election following a “corporate change” or a breach of the employment agreement by us or other “good reason.” Citing “corporate change” and “good reason,” Mr. Transier’s severance claim of $5,454,344 is calculated as follows:

(i)

three times the sum of the executive’s most recent annual salary and deemed bonus (the average bonus paid during the most recent two years);

(ii)

all unvested employee restricted stock awards, performance shares and cash performance awards would vest upon any such termination; and

(iii)

three years of continued coverage for accident and group health insurance benefits substantially similar to those he received immediately prior to the date of termination.

Mr. Transier has to date not received a severance payment, pro-rata bonus or a KERP.

We have not accrued any portion of the severance claim as a pre-petition liability as of December 31, 2014.

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Equity Compensation Plan Information

The following table sets forth, as of December 31, 2014, information with respect to securities authorized for issuance under equity compensation plans.



	Number of securities to be issued upon exercise of outstanding options, warrants and rights	Weighted-average exercise price of outstanding options, warrants and rights ($)	Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
	(a)	(b)	(c)

Equity compensation plans approved by security holders	107,226	9.89	2,971,365
Equity compensation plans not approved by security holders	-	-	-

Total	107,226	9.89	2,971,365

The options issued outside of equity compensation plans approved by security holders were issued to officers upon commencement of employment with a term of five years from the date of grant and vest equally over three years. The Company filed for Chapter 11 reorganization on October 11, 2014 and filed a RSA on November 17, 2014. Per the terms of the RSA, all classes of equity will be cancelled upon the Company’s emergence from bankruptcy.

Compensation Committee Report on Executive Compensation

We have reviewed and discussed with management the Compensation Discussion and Analysis as required by Item 402(b) of Regulation S-K. Based on the review and discussions, we recommend to the Board of Directors that the Compensation Discussion and Analysis referred to above be included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2014.

John B. Connally III, Chairman

Sheldon R. Erikson

Nancy K. Quinn

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

Common Stock and Series C Convertible Preferred Stock

The following table shows the amount of common stock and Series C Convertible Preferred Stock beneficially owned as defined by Section 13(d) of the Exchange Act and the rules and regulations promulgated thereunder (“Section 13(d)”) by (a) persons whom we know to be the beneficial owners of more than 5% of our outstanding common stock based solely on our review of the Schedule 13D/13G Statements of Beneficial Ownership filed by such persons with the SEC on the dates indicated, (b) persons whom we know to be the beneficial owners of more than 5% of our Series C Convertible Preferred Stock, (c) our Directors, (d) each Named Executive Officer and (e) our Directors and Executive Officers as a group. The beneficial holders listed below do not possess any additional voting rights with respect to the shares of our Common Stock that they own. The holders of the Series C Convertible Preferred Stock are entitled to 114.3 votes per share.

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The number of shares shown includes shares that are individually owned or jointly owned, as well as shares over which the individual has either sole or shared investment or voting authority.



Name and Address of Beneficial Owner	Common Stock Beneficially Owned as Defined by Section 13(d)		Percentage of Common Stock Beneficially Owned as Defined by Section 13(d) (1)	Series C Convertible Preferred Stock Beneficially Owned	Percentage of Series C Convertible Preferred Stock Beneficially Owned
Smedvig QIF Plc
39/40 Upper Mount Street
Dublin 2, Ireland	8,103,482	(2)	15.30%	-	-

Arthur J. Samberg
77 Bedford Road
Katonah, New York 10536	4,173,500	(3)	7.88%	-	-

Steelhead Partners, LLC
1301 First Avenue, Suite 201
Seattle, Washington 98101	3,000,000	(4)	5.66%	-	-

Goldman Sachs Asset Management, L.P.
One New York Plaza, 47th Floor
New York, New York 10004	1,371,429	(5)	2.59%	12,000	81.08%

William L.Transier	1,200,186	(6)	2.38%	-	-

John N. Seitz	1,162,379	(7)	2.19%	-	-

Nancy K. Quinn	249,251	(8)	*	-	-

James J, Emme	209,862	(9)	*	-	-

Catherine L. Stubbs	139,395	(10)	*	-	-

John B. Connally III	114,651	(11)	*	-	-

Derek A. Neilson	55,326	(12)	*	-	-

William D. Lancaster	48,077	(13)	*	-	-

James H. Browning	39,499	(14)	*	-	-

Sheldon R. Erikson	39,159	(15)	*	-	-

All directors and executive officers as a group (10 persons)	3,257,785	(16)	6.14%	-	-

Less than 1%.

⁽¹⁾

Pursuant to the rules and regulations promulgated under the Exchange Act, shares are deemed to be “beneficially owned” by a person if such person directly or indirectly has or shares the power to vote or dispose of such shares or to direct the vote or disposition of such shares, whether or not he has any pecuniary interest in such shares, or if he has the right to acquire the power to vote or dispose of such shares or to direct the vote or disposition of such shares within 60 days, including any right to acquire such power through the exercise of any option, warrant or right. This table has been prepared based on 52,961,272 shares of common stock outstanding and 14,800 shares of Series C Convertible Preferred Stock outstanding as of March 31, 2015. Unless otherwise indicated in the footnotes below, all shares are subject to the beneficial owner’s sole voting and dispositive power.

⁽²⁾

Based on the Schedule 13G/A filed with the SEC on February 17, 2015 with respect to its securities as of December 31, 2014. The number of shares reported as beneficially owned by Smedvig QIF Plc includes 1,653,294 shares of common stock, 5,215,910 shares of common stock issuable upon conversion of the convertible bonds due 2016, and 1,234,278 shares of common stock issuable upon the exercise of warrants. Smedvig QIF Plc and, by reason of Smedvig Asset Allocation AS being Smedvig QIF Plc’s investment manager and John Thore Olsen serving as its chief investment officer, Smedvig Asset Allocation AS and John Thore Olsen as well, have sole beneficial ownership, sole voting power and sole dispositive power over 8,103,482 shares.

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⁽³⁾

Based upon the 13G/A filed with the SEC on February 11, 2015 with respect to his securities as of December 31, 2014. The number of shares reported as beneficially owned by Arthur J. Samberg includes 2,673,500 shares of common stock and 1,500,000 shares of common stock deliverable upon the exercise of Options. Mr. Arthur J. Samberg has sole voting and dispositive power over 4,173,500 shares.

⁽⁴⁾

Based upon the Schedule 13G/A filed with the SEC on February 17, 2015 with respect to its securities as of December 31, 2014. Steelhead Navigator Master, L.P., has sole voting and dispositive powere over 3,000,000 shares. Steelhead Partners, LLC, Mr. James Michael Johnson, and Mr. Brian Katz Klein have shared voting and dispositive power over 3,000,000 shares. Mr. Johnston and Mr. Klein each disclaim beneficial ownership.

⁽⁵⁾

1,371,429 shares of common stock issuable upon conversion of the Series C Convertible Preferred Stock.

⁽⁶⁾

Mr. Transier Chairman of the Board. The shares beneficially owned by Mr. Transier include 86,949 shares of common stock underlying stock options.

⁽⁷⁾

Mr. Seitz is the Vice Chairman of the Board.

⁽⁸⁾

Ms. Quinn is a Director.

⁽⁹⁾

Mr. Emme is our Executive Vice President, North America.

⁽¹⁰⁾

Catherine Stubbs is our Senior Vice President and Chief Financial Officer. The shares beneficially owned by Ms. Stubbs include 3,033 shares of common stock underlying stock options.

⁽¹¹⁾

Mr. Connally is a Director. The shares beneficially owned by Mr. Connally include 4,579 shares owned of record by Pin Oak Energy Partnership, of which Mr. Connally owns 50% of the partnership interest and has voting and investing power.

⁽¹²⁾

Mr. Neilson is our Managing Director of U.K. Operations. The shares beneficially owned by Mr. Neilson include 5,083 shares of common stock underlying stock options.

⁽¹³⁾

Mr. Lancaster is a Director.

⁽¹⁴⁾

Mr. Browning is a Director.

⁽¹⁵⁾

Mr. Erikson is a Director.

⁽¹⁶⁾

Includes 95,062 shares of common stock issuable upon exercise of stock options.

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

Mr. Sheldon Erikson

In 2014, the Board evaluated Mr. Erikson’s status as a member of the Board of Directors of Cameron International Corporation, to which the Company paid nothing in 2014 and approximately $1.1 million in 2013. Cameron International is a supplier of flow equipment, systems and services to worldwide oil, gas and process industries. The Board determined that, in accordance with the NYSE Rules, these transactions did not affect Mr. Erikson’s independence.

Mr. William Transier

On December 16, 2014, William Transier, our former President and Chief Executive Officer and current Chairman of the Board of Directors, filed two claims against the Debtors in the bankruptcy proceedings described above. Mr. Transier is seeking to (i) obtain the pro-rated portion of his bonus owed for the year ended December 31, 2014 in the amount of $734,247 and (ii) obtain severance compensation owed as a result of his resignation as President and Chief Executive Officer in the amount of $5,454,344.

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Item 14. Principal Accounting Fees and Services

The following table presents fees for professional audit services performed by E&Y for the audit of our annual financial statements for the fiscal years ended December 31, 2014 and 2013.



	2014		2013

Audit Fees (1)	$	1,733,817	$	1,440,477
Audit-Related Fees (2)		32,968		45,595
Tax Fees (3)		145,619		228,580
All Other Fees		—		—
Total	$	1,912,404	$	1,714,652

⁽¹⁾

Audit fees relate to professional services rendered for the audit of the annual financial statements included in annual reports on Form 10-K, the review of financial statements included in quarterly reports on Form 10-Q and audit services provided in connection with statutory and regulatory filings, including audit of internal controls over financial reporting.

⁽²⁾

Audit-related fees relate to professional services rendered related to G&A rate audits.

⁽³⁾

Tax fees relate to professional services rendered related to international and U.S. tax compliance and/or consulting.

The Audit Committee pre-approved 100% of the fees paid to E&Y for audit, audit-related, and tax fees and pre-approves all non-audit services to be performed by our principal accountant.

Audit Committee Pre-Approval Policy

In accordance with its Charter, the Audit Committee must pre-approve both audit and non-audit services by Ernst & Young. The Audit Committee Chair, and any other member of the Audit Committee designated by the Committee, has the authority to grant pre-approvals, provided such approvals are within the pre-approval policy presented to the Audit Committee at a subsequent meeting.

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.

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See “Index of Exhibits” herein which lists the documents filed as exhibits with this Annual Report on Form 10-K.

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/ James J. Emme
		James J. Emme
		Executive Vice President – North America

		/s/ Catherine L. Stubbs
		Catherine L. Stubbs
		Senior Vice President and Chief Financial Officer

		/s/ Derek A. Neilson
		Derek A. Neilson
		Managing Director UK Operations

Date: March 31, 2015

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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

By:	/s/ James J. Emme	Executive Vice President – North America	March 31, 2015
	James J. Emme	(Co-Principal Executive Officer)

By:	/s/ Catherine L. Stubbs	Senior Vice President and Chief Financial Officer	March 31, 2015
	Catherine L. Stubbs	(Co-Principal Executive, Financial and Accounting Officer)

By:	/s/ Derek A. Neilson	Managing Director UK Operations	March 31, 2015
	Derek A. Neilson	(Co-Principal Executive Officer)

By:	/s/ James H. Browning	Director	March 31, 2015
	James H. Browning

By:	/s/ John B. Connally III	Director	March 31, 2015
	John B. Connally III

By:	/s/ Sheldon R. Erikson	Director	March 31, 2015
	Sheldon R. Erikson

By:	/s/ William D. Lancaster	Director	March 31, 2015
	William D. Lancaster

By:	/s Nancy K. Quinn	Director	March 31, 2015
	Nancy K. Quinn

By:	/s/ John N. Seitz	Director	March 31, 2015
	John N. Seitz

By:	/s/ William L. Transier	Director	March 31, 2015
	William L. Transier

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Exhibit Index
Exhibit	Description
2.1	Proposed Joint Chapter 11 Plan of Reorganization for the Debtors (Incorporated by reference to Exhibit 99.1 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on November 18, 2014).
3.1(a)	Amended and Restated Articles of Incorporation (Incorporated by reference to Exhibit 3.2 of our Quarterly Report on Form 10-Q (Commission File No. 001-32212) for the quarter ended June 30, 2004).
3.1(b)	Certificate of Amendment dated June 1, 2006 (Incorporated by reference to Exhibit 4.2 of our Registration Statement on Form S-3 (Commission File No. 333-139304) filed on December 13, 2006).
3.1(c)	Certificate of Amendment dated June 1, 2010 (Incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on June 3, 2010).
3.1(d)	Amendment to Articles of Incorporation, dated November 17, 2010 (Incorporated by reference to Exhibit 3.1(d) of our Annual Report on Form 10-K (Commission File No. 001-32212) for the year ended December 31, 2010).
3.1(e)	Amendment to Amended and Restated Articles of Incorporation, dated May 24 2012 (Incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on May 29, 2012).
3.2(a)	Amended and Restated Bylaws (Incorporated by reference to Exhibit 3.2 to our Annual Report on Form 10-K (Commission File No. 001-32212) for the year ended December 31, 2012).
3.2(b)	Amendment to Amended and Restated Bylaws dated May 22, 2013 (Incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on May 23, 2013).
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).

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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 4.1 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on November 23, 2009).
3.6(c)	Amendment to Certificate of Designation of Series C Preferred Stock of Endeavour International Corporation, dated March 10, 2010 (Incorporated by reference to Exhibit 3.6(c) of our Annual Report on Form 10-K (Commission File No. 001-32212) for the year ended December 31, 2009).
3.7	Certificate of Designation of Series D Junior 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	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 28, 2008).
4.2	Trust Deed dated January 24, 2008 by and among Endeavour International Corporation, Endeavour Energy Luxembourg S.à.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 28, 2008).
4.3	Amendment Deed dated March 11, 2011, to Trust Deed dated January 24, 2008 by and among Endeavour International Corporation, Endeavour Energy Luxembourg S.à.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 March 14, 2011).
4.4	Indenture dated as of July 22, 2011 among Endeavour International Corporation, the Guarantors named therein and Well Fargo Bank, National Association, as trustee (Incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on July 22, 2011).
4.5	Form of 5.5% Global Note, dated July 22, 2011 (included in Exhibit 4.4).

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4.6	First Priority Indenture, dated February 23, 2012, among Endeavour International Corporation, the subsidiary guarantors party thereto, and Wells Fargo Bank, National Association, as trustee and collateral agent (Incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on February 29, 2012).
4.7	Form of First Priority 12% Senior Notes due 2018 (included in Exhibit 4.6).
4.8	Second Priority Indenture, dated February 23, 2012, among Endeavour International Corporation, the subsidiary guarantors party thereto, Wilmington Trust, National Association, as trustee and Wells Fargo Bank, National Association, as collateral agent (Incorporated by reference to Exhibit 4.3 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on February 29, 2012).
4.9	Form of Second Priority 12% Senior Notes due 2018 (included in Exhibit 4.8).
4.10	Form of Warrant (Incorporated by reference as Exhibit A to Exhibit 10.2 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on May 30, 2012).
4.11	Warrant to Purchase Common Stock (Incorporated by reference as Exhibit A to Exhibit 10.2 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on January 14, 2013).
4.12	Form of Warrant to Purchase Common Stock (Incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on January 15, 2013).
4.13	Form of Warrant to Purchase Common Stock (Incorporated by reference to Exhibit 4.1 to our Quarterly Report (Commission File No. 001-32212) for the quarter ended June 30, 2013).
4.14	Form of Warrant to Purchase Common Stock (Incorporated by reference to Exhibit 4.2 to our Quarterly Report (Commission File No. 001-32212) for the quarter ended June 30, 2013).
4.15	Indenture dated as of March 3, 2014 among Endeavour International Corporation, the Guarantors named therein and Wilmington Savings Fund Society, FSB, as trustee (Incorporated by reference to Exhibit 4.15 to our Annual Report (Commission File No. 001-32212) for the year ended December 31, 2013).

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4.16	Registration Rights Agreement, dated as of February 28, 2014, between Endeavour International Corporation and certain affiliates of Whitebox Advisors LLC (Incorporated by reference to Exhibit 4.16 to our Annual Report (Commission File No. 001-32212) for the year ended December 31, 2013).
4.17	Form of 6.5% Convertible Senior Note (Incorporated by reference to Exhibit 4.17 of our Annual Report on Form 10-K (Commission File No. 001-32212) for the year ended December 31, 2013).
4.18	Form of Warrant (Incorporated by reference to Exhibit 4.18 of our Annual Report on Form 10-K (Commission File No. 001-32212) for the year ended December 31, 2013).
†10.1	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).
†10.2(a)	2010 Incentive Plan (Incorporated by reference to Exhibit A to our definitive proxy statement on Schedule 14A filed on April 20, 2010).
†10.2(b)	First Amendment to 2010 Incentive Plan, dated as of May 24, 2012 (Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on May 29, 2012).
†10.3	Endeavour International Corporation 2014 Long-Term Incentive Plan (Incorporated by reference to Appendix B to the Company’s definitive proxy statement on Schedule 14A filed on April 17, 2014).
†10.4	Employment Agreement, effective as of January 1, 2013, by and between William L. Transier and Endeavour International Corporation (Incorporated by reference to Exhibit 10.1 to our Current on Form 8-K (Commission File No. 001-32212) filed on January 11, 2013).
†10.5	Change in Control Termination Benefits Agreement between the Company and Catherine L. Stubbs (Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K (Commission File No. 001-32212) filed on January 6, 2014).
†10.6(a)	Change in Control and Termination Benefits Agreement dated January 11, 2010, by and between Endeavour International Corporation and James Joseph Emme (Incorporated by reference to Exhibit 10.7 of our Annual Report on Form 10-K for the year ended December 31, 2009).

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†10.6(b)	First Amendment to Change in Control Termination Benefits Agreement between the Company and James J. Emme (Incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K (Commission File No. 001-32212) filed on January 6, 2014).
†10.7	Form of Restricted Stock Agreement under the 2010 Incentive Plan (Incorporated by reference to Exhibit 10.2 of our Quarterly Report on Form 10-Q (Commission File No. 001-32212) for the quarter ended September 30, 2010).

†10.8	Form of Stock Option Agreement under the 2010 Incentive Plan (Incorporated by reference to Exhibit 10.3 to our Quarterly Report on Form 10-Q (Commission File No. 001-32212) for the quarter ended September 30, 2010).
10.9(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).
10.9(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).
**10.10	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).
10.11	Incremental Increase Agreement dated as of September 28, 2012 between Endeavour Energy UK Limited, Endeavour International Corporation, Whitebox Credit Arbitrage Partners, LP, Pandora Select Partners, LP and Whitebox Multi-Strategy Partners, LP and Cyan Partners, LP., as administrative agent (Incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q (Commission File No. 001-32212) for the quarterly period ended June 30, 2012).
10.12	Incremental Increase Agreement dated as of September 28, 2012 between Endeavour Energy UK Limited, Endeavour International Corporation, Farallon Capital Partners, L.P., Farallon Capital Institutional Partners, L.P., Farallon Capital Institutional Partners II, L.P., Farallon Capital Institution Partners II, L.P., and Cyan Partners, LP., as administrative agent (Incorporated by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q (Commission File No. 001-32212) for the quarterly period ended June 30, 2012).

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†10.13	Restricted Stock Award Agreement between Endeavour International Corporation and Ralph A. Midkiff, dated as of June 1, 2012 (Incorporated by Reference to Exhibit 10.6 to our Quarterly Report on Form 10-Q (Commission File No. 001-32212) for the quarterly period ended June 30, 2012).

10.14	Reimbursement Agreement, dated as of May 23, 2012, among Endeavour International Corporation, Endeavour Energy U.K. Limited and Yellow Rock S.à.r.l. (Incorporated by reference to Exhibit 10.1 to our Current Report on 8-K (Commission File No. 001-32212) filed on May 30, 2012).
10.15	Form of Warrant Agreement to Purchase Common Stock (Incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on May 30, 2012).
10.16(a)	Reimbursement Agreement, dated May 31, 2012, among Endeavour International Corporation, Endeavour Energy U.K. Limited, New Pearl S.à.r.l. and Cyan Partners, LP, as collateral agent. (Incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on June 6, 2012).
10.16(b)	First Amendment to Reimbursement Agreement, dated as of October 10, 2012, between Endeavour International Corporation, Endeavour Energy UK Limited, Cyan Partners, LP, and New Pearl, Sa.r.l. (Incorporated by reference to Exhibit 10.3 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on October 15, 2012).
†10.17	Employment Agreement between the Company and William L. Transier, effective January 1, 2013 (Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on January 11, 2013).

10.18	LOC Procurement Agreement dated as of January 1, 2013, among Endeavour International Corporation, Endeavour Energy U.K. Limited and Max Participations II S.à.r.l. (Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on January 15, 2013).
10.19	Warrant Agreement between Endeavour International Corporation and HBK Master Fund L.P. dated January 9, 2013 (Incorporated by reference to Exhibit 10.2 to our Current Report (Commission File No. 001-32212) filed on January 15, 2013).

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10.20	Deed of Grant of Production Payment between Endeavour Energy UK Limited and Cidoval S.à r.l. (Incorporated by reference to Exhibit 10.1 to our Current Report (Commission File No. 001-32212) filed on May 1, 2013).
†10.21	Separation Agreement and General Release by and between Endeavour International Corporation and Carl D. Grenz dated as of October 16, 2013 (Incorporated by reference to Exhibit 10.1 to our Current Report (Commission File No. 001-32212) filed on October 22, 2013).
10.22	Second Amendment to Reimbursement Agreement dated as of March 5, 2013, between Endeavour International Corporation, Endeavour Energy U.K. Limited, New Pearl S.à.r.l. and Cyan Partners, LP, as collateral agent, and the other lenders party thereto. (Incorporated by reference to Exhibit 10-5 of our Quarterly Report on Form 10-Q (Commission File No. 001-32212) for the quarter ended March 31, 2013.)
10.23	Warrant Agreement for the Purchase of Shares of Common Stock between Endeavour International Corporation and certain holders party thereto dated April 30, 2013. (Incorporated by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q (Commission File No. 001-32212) for the quarter ended June 30, 2013.
10.24	Warrant Agreement for the Purchase of Shares of Common Stock between Endeavour International Corporation and Macquarie Bank Limited dated May 21, 2013. (Incorporated by reference to Exhibit 10.3 to our Quarterly Report on Form 10-Q (Commission File No. 001-32212) for the quarter ended June 30, 2013.
10.25	Supplemental Deed of Amendment and Restatement between Endeavour Energy UK Limited and Cidoval S.à.r.l. dated May 21, 2013. (Incorporated by reference to Exhibit 10.4 to our Quarterly Report on Form 10-Q (Commisstion File No. 001-32212) for the quarter ended June 30, 2013).
10.26	Second Supplemental Deed of Amendment and Restatement between Endeavour Energy UK Limited and Cidoval S.à.r.l. dated August 15, 2013. (Incorporated by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q (Commission File No. 001-32212) for the quarter ended September 30, 2013).

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10.27	Conformed Credit Agreement reflecting First Amendments through Third Amendment among Endeavour International Corporation, Endeavour Energy UK Limited, various lenders and Cyan Partners L.P., as administrative agent, dated as of April 12, 2012. (Incorporated by reference to Exhibit 10.3 to our Quarterly Report on Form 10-Q (Commission File No. 001-32212) for the quarter ended September 30, 2013).
10.28	Deed of Grant of Production Payment between Endeavour Energy UK Limited and Sand Waves dated December 12, 2013 (Incorporated by reference to Exhibit 10.36 to our Annual Report (Commission File No. 001-32212) for the year ended December 31, 2013).
10.29	Sale and Purchase Agreement between Endeavour Energy UK Limited and Sand Waves S.A. dated December 12, 2013 (Incorporated by reference to Exhibit 10.37 to our Annual Report (Commission File No. 001-32212) for the year ended December 31, 2013).
10.30	Credit Agreement, dated as of January 24, 2014, among Endeavour International Corporation, Endeavour International Holdings B.V., End Finco LLC and Credit Suisse AG, as administrative agent and as collateral agent, and certain lenders party thereto (Incorporated by reference to Exhibit 10.38 to our Annual Report (Commission File No. 001-32212) for the year ended December 31, 2013).
10.31	LC Procurement Agreement, dated as of January 24, 2014, among Endeavour International Corporation, Endeavour Energy UK Limited, LC Finco S.à r.l. and Credit Suisse AG, as collateral agent (Incorporated by reference to Exhibit 10.39 to our Annual Report (Commission File No. 001-32212) for the year ended December 31, 2013).
10.32	Amended Credit Agreement, dated September 30, 2014, between Endeavour International Holding B.V., END Finco LLC, Endeavour International Corporation, Credit Suisse AG, Cayman Island Brach, as administrative agent for the Lenders (Incorporated by reference to Exhibit 99.1 to our Current Report on Form 8-K (Commission File No. 001-32212) filed October 1, 2014).
10.33	Securities Purchase Agreement, dated February 28, 2014, between Endeavour International Corporation, the Guarantors and certain affiliates of Whitebox Advisors LLC (Incorporated by reference to Exhibit 10.40 to our Annual Report (Commission File No. 001-32212) for the year ended December 31, 2013).

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10.34	Warrant Agreement for the Purchase of Shares of Common Stock, dated February 28, 2014, between Endeavour International Corporation and certain affiliates of Whitebox Advisors LLC (Incorporated by reference to Exhibit 10.41 to our Annual Report (Commission File No. 001-32212) for the year ended December 31, 2013).
10.35	Warrant Agreement for the Purchase of Shares of Common Stock between Endeavour International Corporation and SM Energy Company dated April 15, 2014 (Incorporated by reference to Exhibit 10.1 to our Quarterly Report (Commission File No. 001-32212) for the quarter ended June 30, 2014).
†10.36	Change in Control Termination Benefits Agreement between the Company and Derek Neilson. (Incorporated by reference to Exhibit 10.1 on our Current Report on Form 8-K (Commission File No. 001-32212) filed on September 24, 2014).
†10.37	Key Employee Retention Plan Agreement between the Company and James J. Emme (Incorporated by reference to Exhibit 10.2 on our Current Report on Form 8-K (Commission File No. 001-32212) filed on September 24, 2014).
†10.38	Key Employee Retention Plan Agreement between the Company and Catherine L. Stubbs (Incorporated by reference to Exhibit 10.3 on our Current Report on Form 8-K (Commission File No. 001-32212) filed on September 24, 2014).
†10.39	Key Employee Retention Plan Agreement between the Company and Derek Neilson (Incorporated by reference to Exhibit 10.4 on our Current Report on Form 8-K (Commission File No. 001-32212) filed on September 24, 2014).
10.40	Restructuring Support Agreement and related Term Sheet, dated October 10, 2014, among Endeavour International Corporation, certain of its subsidiaries and certain of its creditors (Incorporated by reference to Exhibits 99.2 and 99.3, respectively, to our Current Report on Form 8-K (Commission File No. 001-32212) filed on October 14, 2014).
*12.1	Computation of Ratios of Earnings to Fixed Charges.
*12.2	Computation of Ratios of Earnings to Fixed Charges and Preference Securities Dividends.
14.1	Code of Business Conduct of Endeavour International Corporation, adopted on December 2007 and updated on January 6, 2014.
*21.1	List of Subsidiaries.
*23.1	Consent of Independent Reserve Engineers – Netherland, Sewell & Associates, Inc.

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*23.2	Consent of Independent Registered Public Accounting Firm – Ernst & Young LLP.
*23.3	Consent of Independent Registered Public Accounting Firm – Ernst & Young LLP.
*23.4	Consent of Independent Registered Public Accounting Firm – Ernst & Young LLP.
*31.1	Certification of James J. Emme, Co-Principal Executive Officer, pursuant to Rule 13a-14(a) of the Securities and Exchange Act of 1934, as amended.
*31.2	Certification of Catherine L. Stubbs, Co-Principal Executive Officer, pursuant to Rule 13a-14(a) of the Securities and Exchange Act of 1934, as amended.
*31.3	Certification of Derek Neilson, Co-Principal Executive Officer, pursuant to Rule 13a-14(a) of the Securities and Exchange Act of 1934, as amended.
*31.4	Certification of Catherine L. Stubbs, Principal Financial Officer, pursuant to Rule 13a-14(a) of the Securities and Exchange Act of 1934, as amended.
‡32.1	Certification of James J. Emme, Co-Principal Executive Officer, pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
‡32.2	Certification of Catherine L. Stubbs, Co-Principal Executive Officer, pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
‡32.3	Certification of Derek Neilson, Co-Principal Executive Officer, pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
‡32.4	Certification of Catherine L. Stubbs, Principal 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.
*99.2	Audited Financial Statements of Endeavour Energy UK Limited.
*99.3	Audited Financial Statements of Endeavour International Holding B.V.
*101.INS	XBRL Instance Document.
*101.SCH	XBRL Taxonomy Extension Schema Document.
*101.CA	XBRL Taxonomy Extension Calculation Linkbase.

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*101.DEF	XBRL Taxonomy Extension Definition Linkbase.
*101.LAB	XBRL Taxonomy Extension Label Linkbase.
*101.PRE	Taxonomy Extension Presentation Linkbase.

*	Filed herewith.
‡	Furnished herewith.
†	Identifies management contracts and compensatory plans or arrangements.
**	Portions of this exhibit have been omitted pursuant to a request for confidential treatment under Rule 24b-2 of the Securities Exchange Act of 1934, and the omitted material has been separately filed with the Securities and Exchange Commission.

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