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United States

Securities and Exchange Commission

Washington, D.C. 20549

Form 10-K

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

For the Fiscal Year Ended December 31, 2012

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

For the transition period from to 

Commission File Number: 001-32212

Endeavour International Corporation

(Exact name of registrant as specified in its charter)

Nevada 88-0448389

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

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:

Title of Each Class of Stock Name of Each Exchange on Which Registered

Common Stock - $0.001 par value per share New York Stock Exchange

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

Indicate by check mark if the registrant is a well-known seasoned issuer as defined in Rule 405 of the Securities Act.  ̈ Yes x 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 x 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. x 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). x 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. x

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  ̈ Accelerated filer x

Non-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 x No
The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant was $364.1 million computed by reference to

the closing sale price of the registrant’s common stock on the New York Stock Exchange on June 29, 2012, 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 13, 2013, 47.4 million shares of the registrant’s common stock were outstanding.

Documents Incorporated By Reference:

Portions of the registrant’s definitive proxy statement relating to the 2013 Annual Meeting of Stockholders, which will be filed within 120 days of

December 31, 2012, are incorporated by reference into Part III of this Annual Report on Form 10-K.
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Table of Contents

 Page

Part I

 1 

Item 1. Business 1 

Item 1A. Risk Factors 13 

Item 1B. Unresolved Staff Comments 34 

Item 2. Properties 34 

Item 3.

 Legal Proceedings 40 

Item 4.

 Mine Safety Disclosures 40 

Part II 41 

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 41 

Item 6. Selected Financial Data 43 

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 45 

Item 7A. Quantitative and Qualitative Disclosures About Market Risk 6 9 

Item 8. Financial Statements and Supplementary Data 70 

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 141 

Item 9A. Controls and Procedures 141 

Item 9B. Other Information 144 

Part III 145 

Item 10. Directors, Executive Officers and Corporate Governance of the Registrant 145 

Item 11. Executive Compensation 145 

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 145 

Item 13. Certain Relationships and Related Transactions, and Director Independence 145 

Item 14. Principal Accounting Fees and Services 146 

Part IV 146 

Item 15. Exhibits and Financial Statement Schedules 146 

Signatures 147 

Quantities of natural gas are expressed in this Annual Report on Form 10-K in terms of thousand cubic feet (“Mcf”) and million cubic feet (“MMcf”).

Oil, which includes natural gas liquids, is quantified in terms of barrels (“Bbls”) and thousands of barrels (“Mbbls”). Natural gas is compared to oil

in terms of barrels of oil equivalent (“BOE”), thousand barrels of oil equivalent (“MBOE’) or million barrels of oil equivalent (“MMBOE”). One

barrel of oil is the approximate energy equivalent of six Mcf of natural gas. This is a physical correlation and does not reflect a value or price

relationship between the commodities. With respect to information relating to our working interest in wells or acreage, “net” oil and gas wells or

acreage is determined by multiplying gross wells or acreage by our working interest therein. References to number of potential well locations are

gross, unless otherwise indicated. References to “GAAP” refer to U.S. generally accepted accounting principles.
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Endeavour International Corporation

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. We began our operations

focused on the U.K. and Norwegian sectors of the North Sea. In 2008, we initiated operations in the U.S. and announced our first production there in January

2009. In 2009 we sold our Norwegian operations, utilizing the proceeds to expand our U.S. position in the fourth quarter of 2009 and early 2010, purchasing

both producing properties and exploration acreage. Since 2010, our focus has been advancing development projects in the U.K. and completing the acquisition

of additional interests in two of our U.K. fields – Bacchus in 2011 and Alba in 2012.

Strategic Alternatives

On February 14, 2013, we announced that our board of directors approved a review of strategic alternatives. The primary objective of the strategic review is to

accelerate the deleveraging of the balance sheet and unlock the value of our underlying assets. The Board of Directors will consider a full range of options,

including:

• a sale, joint venture or partnership in respect of our activities in the North Sea;

• a sale of specific assets;

• a sale or merger of the Company; or

• continuing to execute on our operational plan.

Tudor, Pickering, Holt & Co. and Lambert Energy Advisory Ltd. have been engaged as our financial advisors in this process. We will announce the results of

the effort once a course of action is chosen.

Our Areas of Operation

Our operations are organized into two main geographic regions as follows: the U.K. North Sea and U.S. onshore. As of December 31, 2012, our estimated

proved reserves were 25.7 MMBOE, up 13% from 22.7 MMBOE as of December 31, 2011, of which approximately 90% were located in the U.K. and

approximately 10% were located in the U.S. U.K. proved reserves increased by 10.7 MMBOE from 2011 to 2012; however, this increase was offset by a

decrease in U.S. reserves of 7.8 MMBOE, primarily as a result of lower U.S. natural gas prices.

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 As of December 31, 2012 Year Ended

 

Estimated Proved

Reserves December 31, 2012

 

Total

(MMBOE) % Oil

% Proved

Developed

Average Daily Production

(BOE/d)

U.K. North Sea 

Alba 9.9 9 6% 44% 3,452

Bacchus 1.9 9 5% 57% 1,613

Rochelle 9.0 17% — — 

Other fields 2.4 6 5% 0% 424

Total North Sea 23.2 5 9% 25% 5,489

U.S. Onshore 2.5 — 100% 2,379

Total 25.7 5 9% 32% 7,868

U.K. North Sea

The North Sea is a proven resource area where we have a significant development project, producing properties and additional 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.

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%. During 2012,

Alba production volumes were impacted by water handling issues. While production volumes are still being impacted, the matter is being dealt with by the

operator and it is anticipated that the asset will return to normal production levels during 2013.

Bacchus

At December 31, 2012, we held a 30% working interest in our Bacchus field asset, which is operated by Apache Corporation, who owns a 50% working

interest. In April and July 2012, we achieved production from the first and second development wells, respectively, on the Bacchus field. Following completion

of the second development well, the Bacchus partners decided to evaluate the positive data gained from the second development well and observe production

results before making a final decision on the placement of the third development well to ensure optimization of the entire reservoir. That analysis has been

completed and we expect to begin drilling the third well toward the end of the first quarter of 2013.

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Rochelle

Our working interest in the Rochelle area is 44% and we are the operator of the field, which is comprised of Blocks 15/26b, 15/26c and 15/27. During the

third quarter of 2012, we began drilling the first of two planned development wells. With drilling delays, the Rochelle project subsea infrastructure outpaced

the drilling operations. The joint interest partners decided to suspend the first well due to the inability to perform simultaneous pipe-lay and development

drilling operations. In October 2012, the drilling rig moved off location to allow for the hook-up of the pipelines and flow-lines to the subsea manifolds,

thereby delaying our estimated start of production from the fourth quarter of 2012 to the first quarter of 2013. Since October 2012, the pipeline system,

umbilicals and tie-ins to the offtake solution at the Scott platform have been completed and tested. In January 2013, the rig returned to the East Rochelle site to

continue final drilling.

In February 2013, following a severe storm lasting several days, we performed a routine inspection of the conductor, well head and blow out preventer systems

which revealed that the cement around the top of the conductor pipe, which anchors the well to the seabed floor, had been lost creating a non- uniform hole

around the conductor. The hole extended approximately 4 to 7 feet in diameter and 25 feet in depth.

As a result of this finding, drilling operations were suspended on the East Rochelle well. The work to repair the cementing around the conductor pipe has been

completed. We are conducting a thorough analysis to identify the cause of the cement loss and evaluate if there has been any potential fatigue damage to the

conductor pipe itself. Our preliminary findings suggest that swirling currents caused by severe storms created vibrations that liquidized the sands

surrounding the cement anchorage. With the loss of integrity of the surrounding sands, those sands were eroded, creating the resulting crater. Our investigation

is still ongoing. We are also investigating the structural integrity of the conductor pipe to determine if we can safely re-enter the existing well to complete the

drilling phase.

To mitigate delays while we conduct our analysis, we moved the rig to the West Rochelle area and commenced drilling of the second production well. By

switching to the West Rochelle area, drilling and completion of the second production well may proceed without the delay. If drilling and completion proceed as

expected, we anticipate first production from the West Rochelle well could begin in mid-2013 at the earliest.

U.S. Onshore

During 2009, we began acquiring acreage in U.S. onshore resource plays. 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 the

Montana Heath oil play and our new interests in the Colorado Niobrara area.

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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:

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

• expanding the existing Marcellus gathering infrastructure at our Daniel field in 2013 and completing up to three gross Marcellus wells which have

already been drilled and cased;

• drilling only necessary wells in the Haynesville area to maintain acreage positions, and no wells are currently planned in 2013;

• leasing and testing new areas that we believe provide liquids-rich potential, such as our Colorado Niobrara acreage; and

• a thorough analysis of well results in the Heath Shale oil play in Montana before finalizing any development plans in this exploratory shale oil

play.

Our U.S. operations are spending minimal capital, primarily on strategic positioning, while we monitor U.S. gas prices and await the outcome of our strategic

review.

Marcellus Area

We have 31,200 net acres in the Pennsylvania Marcellus area, an increase of 12,800 net acres from December 31, 2011. In October 2012, we completed an

exchange with domestic co-venturer, J-W Operating Company (“J-W”), whereby we exchanged our Bull Bayou Haynesville and Willow Springs Cotton Valley

properties, a total of approximately 2,100 net acres, for 15,500 net acres of J-W’s upstream and midstream interests in the Pennsylvania Marcellus area. In

parallel, we secured a third party gas gathering agreement for the Daniel Project in Cameron County, Pennsylvania. We now operate and control the Marcellus

assets while retaining a 50% position in our remaining producing Haynesville acreage.

In addition to ownership of the existing gathering facilities in Cameron County, we have secured additional take-away capacity of up to 10 MMCF/D which

will be operational by year-end 2013. We currently have five producing wells and three horizontal wells which have been drilled and are expected to be

completed in 2013 once the expanded gathering facilities are operational. No new drilling is required until late 2014 to hold key leasehold acreage in Cameron

County.

Haynesville Area

Following the exchange with J-W, we retained our 50% interest in three remaining Haynesville producing project areas in Louisiana totaling approximately

7,450 gross acres and 3,370 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. These undeveloped locations are not reflected in the

proved reserve report as of year-end 2012 but represent reserve potential for the Company with improved gas prices in the future. No new drilling is currently

required in the Haynesville area to maintain our acreage position.

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Heath Shale Oil Play

We have interests in approximately 88,900 net acres in the emerging Heath Shale oil play in Montana, primarily in Rosebud and Garfield Counties. During

2012, we continued to evaluate our four vertical pilot test wells drilled in 2011 and the associated horizontal targets within the Heath Shale and Tyler

Formation. We are evaluating offset well results in the surrounding area and will consider that information as we determine our next operational steps, which

could include a horizontal reentry of one of our existing pilot wells or some other operation. Until we have completed our evaluation, we do not expect to have

significant capital expenditures related our interests in the Heath Shale oil play.

Niobrara Play

During 2012, we acquired leasehold and drilling rights to earn over 23,000 gross acres in the Niobrara play in northwest Colorado which has liquids-rich

potential. We have formed a 23,000 acre Federal Unit and plan to drill an initial test well in 2013. We expect to continue building our inventory of prospects in

Colorado through leasehold acquisitions and drill-to-earn arrangements.

2013 Planned Expenditures

With the uncertainties around our strategic review, we have not finalized our total capital expenditures budget for 2013. While we perform our strategic review,

we are monitoring our capital expenditures and delaying discretionary or other spending where appropriate. Our board of directors has approved a preliminary

capital expenditures budget for 2013, that is dependent upon a positive outcome from our strategic review, as follows:

 Preliminary Capital Budget

United Kingdom: 

Drilling and completions $90 million to $100 million

Maintenance capital $35 million

Exploration, seismic and other $15 million

Total U.K. $140 million - $150 million

United States $30 million to $40 million 

Total direct oil and gas capital $170 million to $190 million

Primarily discretionary and dependent on the outcome of our strategic review. The U.S. capital expenditures are anticipated to primarily occur in the

latter half of 2013.

In the U.K., the anticipated capital expenditures are primarily to bring the Rochelle development on line, drill the third well at Bacchus and maintain

production at Alba. Once the analysis of the East Rochelle well is concluded, we will be able to determine if we can safely re-enter the existing well to complete

the drilling phase or should plug and abandon the well and drill a new

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well. The anticipated capital expenditures do not include the capital expenditures to drill a new well at East Rochelle, if it is required. Anticipated exploration

expenditures in the U.K. include the drilling of a well at our Centurion prospect, where we hold a 33.3% interest. The exploration well at Centurion represents a

firm well commitment that was originally scheduled by the operator to be drilled in 2012 and has been delayed until 2013.

The U.S. anticipated capital expenditures are primarily discretionary and will be re-evaluated once Rochelle production is on-line and after the completion of

the strategic review process.

Our 2013 anticipated capital expenditures are also subject to change depending on a number of factors, including the result of our strategic review, 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.

Decommissioning Expenditures

Production from each of our Ivanhoe, Rob Roy, Hamish (collectively, “IVRRH”), Renee, Rubie and Goldeneye fields has ceased and we have performed minor

maintenance and decommissioning activities over the last several years. Previously, we expected to re-develop our IVRRH, Renee and Rubie fields if

commercially viable once the development activities at Rochelle are operational. During 2012, we determined that it was no longer practicable to re-develop these

fields. As a result, decommissioning work on the fields will be accelerated and we expect to incur approximately $36 million in decommissioning charges

during 2013.

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 — 2013 Liquidity and Capital Resources.”

Geographical Data

We operate in one industry segment, that being oil and gas exploration and production, in two geographical areas. See Notes 21 and 25 to our consolidated

financial statements in “Item 8, Financial Statements and Supplementary Data” for geographic operating segment information, including results of operations

and segment assets.

Competition

We encounter intense competition from other oil and gas companies in all areas of our operations, including the acquisition of producing properties and

undeveloped acreage. Our competitors include major integrated oil and gas companies, numerous independent oil and gas companies and individuals. Many of

our competitors are large, well-established companies with substantially larger operating staffs and greater capital resources and have been engaged in the oil

and gas business for a much longer time than our company.

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Petroleum and natural gas producers also compete with other suppliers of energy and fuel to industrial, commercial and individual customers. Competitive

conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the governments and/or

agencies thereof and other factors out of our control including, international political conditions, overall levels of supply and demand for oil and gas, and the

markets for synthetic fuels and alternative energy sources.

Significant Customers

Our sales in the U.K. are to a limited number of customers, each of which accounted for more than 10% of revenue for the year ended December 31, 2012:

Chevron North Sea Ltd and Shell U.K. Limited. 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.

Employees

As of March 8, 2013, we 60 full-time employees and 27 consultants, primarily in the operations area. We believe that we maintain good relationships with our

employees, none of whom are covered by a collective bargaining agreement.

Environmental Matters and Regulation

Endeavour was established on a commitment to find and develop energy resources in a manner that protects the health and safety of people and preserves the

quality of the environment. Adhering to high performance standards in the areas of health, safety and the environment (“HSE”) is a primary goal of our

operations and an integral part in our efforts to end each day “injury and incident free.”

North Sea

Our operations in the U.K. portions of the North Sea are subject to numerous U.K. and European Union (“E.U.”) laws and regulations relating to

environmental matters, health and safety. Environmental matters are addressed before oil and gas production activities commence and during the exploration

and production activities. Before a U.K. licensing round begins, the 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. In response to the apparent blowout of the Deepwater Horizon

drilling rig in the Gulf of Mexico in 2010, the DECC has increased rig inspections over the last several years. In addition, more

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rigor has been introduced in the approval process for emergency plans and the provision of financial responsibility for well control contingencies. The E.U. is

also proposing to introduce a directive on offshore safety. We expect these measures to continue, or increase, over the near term. 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”). 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 that are being abandoned. Failure to comply with these laws and regulations may result in the assessment of administrative, civil

or criminal penalties, imposition of remedial obligations, incurrence of capital costs to comply with governmental standards, and even injunctions that limit or

prohibit exploration and production operations or the disposal of substances generated in connection with our operations.

We currently lease a number of properties that for many years have been used for the exploration and production of oil and gas. Although we have utilized

operating and disposal practices that were standard in the industry at the time, hydrocarbons or wastes may have been disposed of or released on or under the

properties operated or leased by us or on or under other locations where such hydrocarbons or wastes have been taken for recycling or disposal. In addition,

many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or wastes was not under our control.

These properties and the hydrocarbons and wastes disposed thereon may be subject to laws and regulations imposing joint and several, strict liability, without

regard to fault or the legality of the original conduct, that could require us to remove or remediate previously disposed wastes or environmental contamination,

or to perform remedial well plugging or pit closure to prevent future contamination.

Hydraulic Fracturing

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 United States Environmental Protection Agency (the “EPA”) recently asserted federal regulatory

authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s Underground Injection Control Program.

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While the EPA has yet to take any action to enforce or implement this newly asserted regulatory authority, industry groups have filed suit challenging the

EPA’s recent decision. At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities on water

resources. The EPA’s study includes 18 separate research projects addressing topics such as water acquisition, chemical mixing, well injection, flowback and

produced water, and wastewater treatment and disposal. The EPA has indicated that it expects to issue its study report in late 2014. 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, Colorado, and Wyoming have each

adopted a variety of well construction, set back, and disclosure regulations limiting how fracturing can be performed and requiring various degrees of

chemical disclosure. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for

us to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of

federal legislation or regulatory initiatives by the EPA, our fracturing activities could become subject to additional permitting requirements, and also to

attendant permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are

ultimately able to produce from our reserves.

Climate Change

Globally, our operations may be impacted by various international, national, and local efforts to respond to climate change by controlling greenhouse gas

(“GHG”) emissions. With the second commitment period of the Kyoto Protocol — which began on January 1, 2013 — still under negotiation, there is

uncertainty as to the precise nature of commitments that will be made by the parties. The Durban Platform, which was recently approved, renews the

possibility of a broader global climate agreement entering into force by 2020, but substantial uncertainties regarding the ultimate structure of such an agreement

remain. However, any new international agreements and domestic laws to implement them may adversely impact our operations by imposing GHG emission

limits on our activities and potentially reducing demand for our products. Within Europe, the European Union has 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. is currently considering proposals to increase credit prices by deferring the marketability of allowances through

backloading. In addition, the U.K. has instituted a carbon floor price that will be effective beginning April 1, 2013. The carbon floor price sets a minimum

price for carbon in the U.K. and is administered as a top-up payment levied on U.K.-based generators of fossil-fuel fired electricity when E.U. carbon

allowances are below the U.K.’s desired price. Many other countries, including the United States, are weighing a variety of legislative and regulatory strategies

that may impose controls on GHG emissions.

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Beginning in 2009, the EPA took a series of steps to begin regulating GHG emissions under the Clean Air Act. As of January 2, 2011, the EPA’s rules impose

limitations on GHG emissions from motor vehicles and certain large stationary sources. In addition, the EPA has issued regulations requiring certain sectors to

monitor and report their greenhouse gas emissions, and requiring the permitting of certain GHG emissions sources under the New Source Review and Title V

programs (which are administered by state or local governments in certain jurisdictions). On January 1, 2011, our exploration and production activities also

became subject to the monitoring and reporting requirements, and we will incur costs related to compliance with these regulations.

In addition, Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have

already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories

and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric

power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of

allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal.

The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases in areas where we operate could require us to incur increased

operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting

requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas

we produce. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business,

financial condition and results of operations.

Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce

climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If

any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

We have made, and will continue to make, expenditures in connection with our effort to comply with environmental laws and regulations. We believe that we

are in compliance with applicable environmental laws and regulations currently in effect and that continued compliance with existing requirements will not

have a material adverse impact on us. However, we also believe that it is reasonably likely that the trend in environmental legislation and regulation will

continue toward stricter standards and, thus, we cannot give any assurance that we will not be adversely affected in the future.

We have established internal guidelines to be followed in order to comply with environmental laws and regulations in the U.S. We employ a safety department

whose responsibilities include providing assurance that our operations are carried out in accordance with applicable environmental guidelines and safety

precautions. Although we maintain pollution insurance to cover a portion of the potential costs of cleanup obligations, public liability and physical damage,

there is no assurance that such insurance will be adequate to cover all such costs or that such insurance will continue to be available in the future. To date, we

believe that compliance with existing requirements of such governmental bodies has not had a material effect on our operations.

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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 London and Aberdeen in the 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 web page, www.sec.gov.

Our website is available at www.endeavourcorp.com. We make available, free of charge, on our website, 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

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available on our website and in print to any stockholder who provides a written request to the Corporate Secretary at 811 Main Street, Suite 2100, Houston,

Texas 77002. Our Code of Conduct applies to all directors, officers and employees, including the chief executive officer and chief financial officer.

Information contained on or connected to our website is not incorporated by reference into this Annual Report on Form 10-K and should not be considered part

of this report or any other filing that we make with the SEC.

Financial Information about Segment and Geographical Areas

We operate in one industry segment, that being oil and gas exploration and production, in two geographical areas. See Note 25 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 21 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 future financial position;

• the outcome of our strategic review;

• our business strategy;

• recent and pending acquisitions;

• budgets;

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• projected costs, savings and plans;

• objectives of management for future operations;

• legal strategies; and

• legal proceedings.

We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these

expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks,

contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks, contingencies and

uncertainties, which may not be exhaustive, relate to, among other matters, the following:

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

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

• drilling of wells and other planned exploitation activities;

• our high level of indebtedness;

• adverse weather conditions;

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

• the volatility of oil and gas prices;

• availability and terms of capital;

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

• our future operating or financial results;

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

• cash flow and anticipated liquidity;

• availability of drilling and production equipment;

• uncertainties related to drilling and production operations;

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

• outcome of legal disputes;

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

• business strategy and the availability of acquisition opportunities;

• the outcome of our strategic review; and

• factors not known to us at this time.

Any of these factors, or a combination of these factors, could materially affect our future financial condition or results of operations and the ultimate accuracy

of 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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Risks related to access to capital and financing

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

As of December 31, 2012, we had $874.2 million in outstanding indebtedness. Subsequent to December 31, 2012, we entered into a forward sale and an

agreement providing for the sale and purchase of a monetary production payment to provide us additional liquidity for our operations. Our indebtedness and

other obligations could have important consequences on our operations, including:

• placing restrictions on certain operating activities;

• making it more difficult for us to satisfy our obligations under our indentures or the terms of our other debt instruments and increasing the risk

that we may default on our debt obligations;

• requiring us to dedicate a substantial portion of our cash flow from operating activities to required payments on debt and other obligations, thereby

reducing the availability of cash flow for working capital, capital expenditures and other general business activities;

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

activities;

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

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

We may not have sufficient funds to repay our outstanding debt and other obligations. In addition, we cannot assure you that we will be able to generate

sufficient cash flow from operating activities to pay the interest on our debt and other obligations or that future borrowings, equity financings or proceeds from

the sale of assets will be available to repay or refinance such debt. Furthermore, any future debt instruments we enter into may contain certain restrictions on

our ability to repay other debt.

Factors that will affect our ability to raise cash through an offering of our capital stock, a refinancing of our debt or a sale of assets include financial market

conditions, our market value, our reserve levels and our operating performance at the time of such offering or other financing. We cannot assure you that any

such offering, refinancing or sale of assets can be successfully completed. The inability to repay or refinance our debt could have a material adverse effect on

our operations and negatively impact our capital program.

A change of control may adversely affect our liquidity, 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

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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 Mr. Transier’s employment agreement and through change in control agreements with each of our remaining executive

vice presidents. 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. We intend to finance our future capital expenditures primarily with cash on

hand, cash flow from operations and access to the debt and equity markets. 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;

• our oil and gas reserves;

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

• the timing and amount of capital expenditures;

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

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

If our revenues decrease as a result of lower oil and gas prices, operating difficulties, declines in reserves or for any other reason 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. 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.

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

interest.

Our ability to retain oil and gas interests will depend on our ability to fulfill the commitments made with respect to each interest. We cannot assure you that we

or the other participants in the projects will have the financial ability to fund these potential commitments. If we are unable to fulfill commitments under any of

our interests, we will lose our interest, and our entire investment, in such interest.

Risks 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 issues and mechanical difficulties. 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.

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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. 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.

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

Offshore operations are subject to a variety of operating risks specific to the marine environment, such as capsizing, collisions and damage or loss from

hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production. As a result, we could

incur substantial liabilities that could reduce or eliminate the funds available for exploration, development or leasehold acquisitions, or result in loss of

equipment and properties. Offshore drilling in the North Sea generally requires more time and more advanced drilling technologies, involving a higher risk of

technological failure and usually higher drilling costs. Moreover, offshore projects often lack proximity to the physical and oilfield service infrastructure,

necessitating significant capital investment in subsea flow line infrastructure. Subsea tieback production systems require substantial time and the use of

advanced and very sophisticated installation equipment supported by remotely operated vehicles. These operations may encounter mechanical difficulties and

equipment failures that could result in significant cost overruns. As a result, a significant amount of time and capital must be invested before we can market

the associated oil or gas 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

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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.

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 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 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

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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.

We are involved in litigation related to a terminated acquisition for Marcellus shale play assets, and such litigation, if resolved adversely to us,

could have a material adverse effect on us.

On July 17, 2011, we entered into agreements (the “SM Purchase Agreements”) with SM Energy Company and certain other sellers named therein (collectively,

“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 (the “SM Acquisition”). On December 14, 2011, we terminated the SM Purchase Agreements 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, exceeded the contractual threshold of 15% of the

applicable purchase price; and (ii) the condition of the pipeline was not in compliance with applicable regulatory standards, which would constitute a material

violation of a representation and warranty contained in the applicable SM Purchase Agreement. Following our termination of each of the SM Purchase

Agreements, SM Energy filed a lawsuit against us in Texas state court on December 20, 2011 alleging, among other things, breach of contract for refusing to

close on the SM Acquisition. SM Energy is seeking an award of unspecified actual damages, including costs and reasonable attorney’s fees, and specific

performance to complete the SM Acquisition. If we are unsuccessful in defending against these claims, we may be subject to a range of potential adverse

outcomes. While we intend to contest these claims vigorously, we cannot predict with any certainty the outcome of this litigation, and the lawsuit, if resolved

adversely to us, could have a material adverse effect on our business, results of operations or financial condition.

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

Our decisions to purchase, explore, develop and exploit prospects or properties depend in part on data obtained through geophysical and geological analyses,

production data and engineering studies, the results of which are often uncertain. Seismic data and visualization techniques only assist geoscientists and

geologists in identifying subsurface structures and hydrocarbon indicators and do not enable an interpreter to conclusively determine whether hydrocarbons

are present or producible economically. In addition, the use of seismic and other advanced technologies may require greater predrilling expenditures than other

drilling strategies. Because of these factors and the inherent uncertainties surrounding the evaluation of exploration prospects, we could incur losses as a result

of exploratory drilling expenditures. Poor results from drilling activities would have a material adverse effect on our future cash flows, ability to replace

reserves and results of operations.

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Reserve estimates depend on many assumptions that may turn out to be inaccurate and any material inaccuracies in the reserve estimates or

underlying assumptions of our assets will materially affect the quantities and present value of those reserves.

Estimating oil and gas reserves is complex and inherently imprecise. It requires interpretation of the available technical data and making many assumptions

about future conditions, including price and other economic factors. In preparing such estimates, projection of production rates, timing of development

expenditures and available geological, geophysical, production and engineering data are analyzed. The extent, quality and reliability of these data can vary.

This process also requires economic assumptions about matters such as oil and gas prices, drilling and operating expenses, capital expenditures, taxes and

availability of funds. If our interpretations or assumptions used in arriving at our reserve estimates prove to be inaccurate, the amount of oil and gas that will

ultimately be recovered may differ materially and adversely from the estimated quantities and net present value of reserves owned by us.

A significant portion of our total estimated net proved reserves at December 31, 2012 were undeveloped, and those reserves may not ultimately

be developed.

At December 31, 2012, approximately 68% of our total estimated net proved reserves were undeveloped. Recovery of undeveloped reserves requires significant

capital expenditures and successful drilling. Our reserve data assumes that we can and will make these expenditures and conduct these operations

successfully. These assumptions, however, may not prove correct. If we choose not to spend the capital to develop these reserves or if we are not otherwise able

to successfully develop these reserves we may be required to write-off these reserves. Any such write-offs of our reserves could materially reduce our ability to

borrow money and the value of our securities.

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, which is

expected to remain relatively steady.

Actual production could differ significantly from forecasts.

From time to time we provide forecasts of expected quantities of future oil and gas production. These forecasts are based on a number of estimates, including

expectations of production decline rates from existing wells, outcomes from future drilling activity and assumptions relating to ongoing operations and

maintenance of producing wells. Should these estimates prove inaccurate, actual production could be adversely impacted. Furthermore, downturns in

commodity prices could make certain drilling activities or production uneconomical, which would also adversely impact production. We may also adjust

estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of

which are beyond our control.

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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 are required to post

collateral as security over certain of our decommissioning liabilities in the North Sea. If actual decommission or abandonment costs exceed our estimates or

reserves to satisfy such obligations, or we are required to provide a significant amount of collateral in cash or other security for these future costs, our

financial condition, results of operations and prospects could be materially adversely affected.

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

business.

As part of our growth strategy, we intend to continue to pursue strategic acquisitions of new properties or businesses that expand our current asset base and

potentially offer unexploited reserve potential. Our growth strategy could be impeded if we are unable to acquire additional interests in oil and gas prospects on

a profitable basis. Acquisition opportunities in the oil and gas industry are very competitive, which can increase the cost of, or cause us to refrain from,

completing acquisitions. The success of any acquisition will depend on a number of factors and involves potential risks, including among other things:

• the inability to estimate accurately the costs to develop the interests in oil and gas prospects, the recoverable volumes of reserves, rates of future

production and future net cash flows attainable from the reserves;

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

• the validity of assumptions about costs, including synergies;

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

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

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

All of these factors affect whether an acquisition will ultimately generate cash flows sufficient to provide a suitable return on investment. Consistent with

industry practices, we typically are only able to perform limited reviews of the properties we seek to acquire. As a result, among other risks, our initial

estimates of reserves, and the costs associated with developing those estimated reserves, may be subject to revision following an acquisition, which may

materially and adversely impact the desired benefits of the acquisition.

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Risks related to our business

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

We currently have operations in the U.S. and U.K. and may expand our operations to other countries or regions. International operations are subject to

political, economic and other uncertainties, including:

• the risk of war, acts of terrorism, revolution, border disputes, expropriation, renegotiation or modification of existing contracts, and import,

export and transportation regulations and tariffs;

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

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

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

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

foreign persons to the jurisdiction of courts in the U.S.

The exploration, production and sale of oil and gas are extensively regulated by governmental bodies, which 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 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.

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Economic conditions in the U.S. and key international markets may materially adversely impact our operating results, which could hinder or

prevent us from meeting our future capital needs.

The U.S., U.K. and other world economies are slowly recovering from a recession which began in 2008 and extended into 2009. Growth has resumed, but

remains modest. There are likely to be significant long-term effects resulting from the recession and credit market crisis, including a future global economic

growth rate that is slower than what was experienced prior to the recession. In addition, more volatility may occur before a sustainable, yet lower, growth rate is

achieved. Because global economic growth drives demand for energy from all sources, including fossil fuels, a lower future economic growth rate will result in

decreased demand growth for our crude oil and natural gas production as well as lower commodity prices, which will reduce our cash flows from operations

and our profitability and may adversely affect our ability to obtain funding for our projects.

Due to these and other factors, we cannot be certain that funding will be available if needed, and to the extent required, on acceptable terms or at all. If funding

is not available as needed, or is available only on unfavorable terms, we may be unable to (i) meet our obligations as they come due, 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.

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. 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. 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;

• 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.

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Lower oil and gas prices may not only decrease our revenues on a per unit basis, but significant or extended price declines may also reduce the amount of oil

and gas that we can produce economically. A reduction in production could result in a shortfall in expected cash flows and require us to reduce capital

spending or borrow funds to cover any such shortfall. Any of these factors could negatively impact our future rate of growth and ability to replace our

production.

In addition, we may, from time to time, enter into long-term contracts based upon our reasoned expectations for commodity price levels. If commodity prices

subsequently decrease significantly for a sustained period, we may be unable to perform our obligations or otherwise breach any such contract and be liable

for damages.

Competition for oil and gas properties and prospects is intense and some of our competitors have larger financial, technical and personnel

resources that give them an advantage in evaluating, obtaining and developing properties and prospects.

We operate in a highly competitive environment for reviewing prospects, acquiring properties, marketing oil and gas and securing trained personnel. Many of

our competitors are major or independent oil and gas companies that have longer operating histories in our areas of operation and employ superior financial

resources which allow them to obtain substantially greater technical and personnel resources and which better enable them to acquire and develop the prospects

that they have identified. We also actively compete with other companies when acquiring new licenses or oil and gas properties. Specifically, competitors with

greater resources than our own have certain advantages that are particularly important in reviewing prospects and purchasing properties. Competitors may be

able to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Competitors may also be

able to pay more for producing oil and gas properties and exploratory prospects than we are able or willing to pay. If we are unable to compete successfully in

these areas in the future, our future revenues and growth may be diminished or restricted.

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.

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

Our future success depends in large part on the service of our executive officers. The loss of these executives could have a material adverse effect on our

business. Although we have employment agreements with certain of our executive officers, there can be no assurance that we will have the ability to retain their

services. Further, we do not maintain key-person life insurance on any executive officers.

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Our future success also depends upon our ability to attract, assimilate and retain highly qualified technical and other management personnel who are essential

for the identification and development of our prospects. There can be no assurance that we will be able to attract, integrate and retain key personnel, and our

failure to do so would have a material adverse effect on our business.

Our 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.

Our use of derivative transactions may limit future revenues from price increases and involves the risk that our counterparties may be unable

to satisfy their obligations to us.

To manage our exposure to price risk with our production, we may enter into commodity derivative contracts. The goal of these derivative contracts is to limit

volatility and increase the predictability of cash flow. Although the use of derivative contracts limits the downside risk of price declines, their use also may

limit future revenues from price increases. In addition, derivative contracts may expose us to the risk of financial loss in certain circumstances, including

instances in which our production is less than expected or a sudden, unexpected event materially impacts oil or gas prices.

Derivative contracts also involve the risk that counterparties, which generally are financial institutions, may be unable to satisfy their obligations to us. If any

one of our counterparties were to default on its obligations to us under the derivative contracts or seek bankruptcy protection, it could have a material adverse

effect on our expected cash flows and our ability to fund our planned activities and could result in a larger percentage of our future production being subject to

commodity price changes. In addition, in the current economic environment and tight financial markets, the risk of a counterparty default is heightened and it

is possible that fewer counterparties will participate in future derivative transactions, which could result in greater concentration of our exposure to any one

counterparty or a larger percentage of our future production being subject to commodity price changes.

Risks related to environmental and other regulations

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

Our operations are subject to a variety of national, state, local and international laws and regulations governing the discharge of materials into the environment

or otherwise relating to environmental protection. Failure to comply with these laws and regulations can result in the imposition of substantial fines and

penalties as well as potential orders suspending or terminating

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our rights to operate. Some environmental laws to which we are subject to provide for strict liability for pollution damages and cleanup costs, rendering a

person liable without regard to negligence or fault on the part of such person. In addition, we may be subject to claims alleging personal injury or property

damage as a result of alleged exposure to hazardous substances such as oil and gas related products. Aquatic environments in which we operate are often

particularly sensitive to environmental impacts, which may expose us to greater potential liability than that associated with exploration, development and

production at many onshore locations.

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly requirements for oil and gas

exploration and production activities could require us, as well as others in our industry, to make significant expenditures to attain and maintain compliance

which could have a corresponding material adverse effect on our competitive position, financial condition or results of operations. We cannot provide

assurance that we will be able to comply with future laws and regulations to the same extent that we have complied in the past. Similarly, we cannot always

precisely predict the potential impact of environmental laws and regulations which may be adopted in the future, including whether any such laws or

regulations would restrict our operations in any area.

Current and future environmental regulations, including restrictions on emissions of greenhouse gases due to concerns about climate change, could reduce the

demand for our products. Our business, financial condition and results of operations could be materially and adversely affected if this were to occur.

Under certain environmental laws and regulations, we could be subject to liability arising out of the conduct of operations or conditions caused by others, or

for activities that were in compliance with all applicable laws at the time they were performed. Such liabilities can be significant, and if imposed could have a

material adverse effect on our financial condition or results of operations.

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

regulations could be substantial.

Oil and gas exploration, development and production are subject to various types of regulation by local, state and national agencies. Regulations and laws

affecting the oil and gas industry are comprehensive and under constant review for amendment and expansion. These regulations and laws carry substantial

penalties for failure to comply. The regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, adversely affects our

profitability. In addition, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to

time by the governments and/or agencies thereof.

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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 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., UK, 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 from tight formations. We routinely utilize

hydraulic fracturing techniques in many of our 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. In the U.S., the process is typically regulated by state oil and gas

commissions. However, the EPA recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking

Water Act’s Underground Injection Control Program.

At the same time, the White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic-fracturing practices, and the

EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities on water resources. The EPA’s study includes 18

separate research projects addressing topics such as water acquisition, chemical mixing, well injection, flowback and produced water, and wastewater

treatment and disposal. The EPA has indicated that it expects to issue its study report in late 2014. In addition, the U.S. Department of Energy is conducting

an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic-fracturing completion methods.

Additionally, certain members of Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might

adversely affect water resources, the SEC to investigate the natural gas industry and any

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possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing,

and the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves

from shale formations, as well as uncertainties associated with those estimates. Legislation also has been introduced before Congress to provide for federal

regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. These ongoing or proposed studies,

depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the Safe

Drinking Water Act or other regulatory mechanism.

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, Colorado, Pennsylvania, and Wyoming have each adopted a variety of well

construction, set back, and disclosure regulations limiting how fracturing can be performed and requiring various degrees of chemical disclosure. In addition,

Texas and several other states have adopted laws requiring public disclosure of certain information regarding chemical ingredients and additives used in the

hydraulic fracturing process. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well

drilling in general and/or hydraulic fracturing in particular. In the event state, local, or municipal legal restrictions are adopted in areas where we are currently

conducting, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be significant in nature,

experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling of wells.

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. At this time, there is substantial uncertainty

about the future of GHG emission limitations in the areas where we operate. For example, the first commitment period of the Kyoto Protocol expired on

December 31, 2012 and the details of the third commitment period, which began on January 1, 2013, are still being negotiated. In addition, the Parties to the

Framework Convention on Climate Change continue negotiations under the Durban Platform, an approach to develop a new legally binding agreement on

climate change by 2015 that will enter into force by 2020. While this agreement will not impact our operations in the near term, a new agreement on global

climate change could further reduce demand for the oil and natural gas that we produce.

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Rapidly evolving domestic legal and regulatory structures governing GHG emissions may increase the costs imposed upon our operations. For example, since

December 2009, the EPA has declared that GHGs threaten the environment, imposed limitations on GHGs from mobile sources and certain large stationary

sources, and required certain industries to monitor and report their GHG emissions. Entities involved in the production and distribution of oil and natural gas

currently subject to the requirements of Subpart W of the Mandatory Reporting of Greenhouse Gases Rule, and must report 2011 GHG emissions to the EPA.

These reports are in addition to those required under Subpart Y for petroleum refineries. On March 27, 2012, the EPA proposed New Source Performance

Standards (“NSPS”) under the Clean Air Act. These standards will require all new power plants 73 MW or larger to achieve a GHG emission rate of 1,000

pounds CO2 per MWh which the EPA estimates can be achieved by natural-gas combined cycle plants. In addition, the EPA is obligated under a consent

decree to promulgate GHG NSPS for petroleum refineries and is expected to promulgate GHG standards for existing stationary sources. At the state level,

California is implementing the cap and trade program called for in the Global Warming Solutions Act, and beginning in 2015, distributors of transportation,

natural gas, and other fuels will be subject to the requirements of the program. To the extent we or our customers are subject to any of these regulations, we

may face increased costs and decreased demand for our product.

The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to

purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such

legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produced.

Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition

and results of operations.

Recently proposed or finalized rules and guidance imposing more stringent requirements on the oil and gas exploration and production industry

could cause us to incur increased capital expenditures and operating costs as well as decrease our levels of production.

On April 17, 2012, the EPA approved final regulations under the Clean Air Act that, among other things, require additional emissions controls for natural gas

and natural gas liquids production, including NSPS to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of

emission standards to address hazardous air pollutants frequently associated with such production activities. The final regulations require, among other

things, the reduction of VOC emissions from natural gas wells through the use of reduced emission completions or “green completions” on all hydraulically

fractured wells constructed or refractured after January 1, 2015. For well completion operations occurring at such well sites before January 1, 2015, the final

regulations allow operators to capture and direct flowback emissions to completion combustion devices, such as flares, in lieu of performing green

completions. These regulations also establish specific new requirements regarding emissions from dehydrators, storage tanks and other production equipment.

Compliance with these requirements could increase our costs of development and production, which costs may be significant.

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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 establishes 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 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 of the Act and CFTC rules 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 a separate entity, which may not be as creditworthy as the current counterparty.

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 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 us, our financial condition, and our results of operations.

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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.

Risks related to potential impairments

Our financial results could be adversely affected by goodwill impairments.

As a result of mergers, acquisitions and dispositions, at December 31, 2012 we had $262.8 million of goodwill on our balance sheet. Goodwill is not

amortized, but instead must be tested at least annually for impairment by applying a fair-value-based test. Goodwill is deemed impaired to the extent that its

carrying amount exceeds the implied fair value of the reporting unit. Although our latest tests indicate that no goodwill impairment is currently required, future

deterioration in market conditions could lead to goodwill impairments that could have a substantial negative effect on our profitability.

Lower oil and gas prices and other factors may result in ceiling test write-downs or other impairments.

We capitalize the costs to acquire, find and develop our oil and gas properties under the full cost accounting method. The net capitalized costs of our oil and

gas properties may not exceed the present value of estimated future net cash flows from proved reserves, plus the lower of cost or fair market value for

unproved properties. This quarterly test is called a “ceiling test.” If net capitalized costs of our oil and gas properties exceed this ceiling test, we must charge the

amount of the excess to earnings. Although a ceiling test write-down does not impact cash flow from operating activities, it does reduce net income and our

stockholders’ equity. Once recorded, a ceiling test write-down is not reversible at a later date even if oil and gas prices increase.

We review the net capitalized costs of our properties quarterly, based on prices in effect (excluding the effect of our hedging contracts that are not designated for

hedge accounting) as of the end of each quarter or as of the time of reporting our results. We also assess investments in unproved properties periodically to

determine whether impairment has occurred.

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The risk that we will be required to further write down the carrying value of our oil and gas properties increases when oil and gas prices are low or volatile. In

addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves or our unproved property values, or if

estimated future development costs increase. We may experience further ceiling test write-downs or other impairments in the future. In addition, any future

ceiling test cushion would be subject to fluctuation as a result of acquisition or divestiture activity.

Risks relating to our common stock

An active liquid trading market for our common stock may not be maintained and the trading price of our common stock may be volatile.

Liquid and active trading markets usually result in less price volatility and more efficiency in carrying out stockholders’ purchase and sale orders. Smaller

capitalized companies like ours often experience substantial fluctuations in the trading price of their securities. An active and liquid trading market for our

common stock may not be maintained. The trading price of our common stock has fluctuated significantly and may be subject to similar fluctuations in the

future. The market price of our common stock could vary significantly as a result of a number of factors, some of which are beyond our control.

If we, our existing stockholders or holders of our securities that are convertible into shares of our common stock sell any shares of our common

stock, the market price of our common stock could significantly decline.

The market price of our common stock could decline as a result of sales of a large number of shares of common stock in the public market or the perception

that such sales could occur. These sales, or the possibility that these sales may occur, might make it more difficult for us to sell equity securities in the future

at a time and at a price that we deem appropriate.

As of March 13, 2013, we had approximately 47.4 million shares of common stock outstanding. Of those shares, approximately 1.1 million shares are

restricted shares subject to vesting periods of up to three years. The remainder of these shares are freely tradable.

In addition, 0.2 million shares are issuable upon the exercise of presently outstanding stock options under our employee incentive plans and 3.0 million shares

are issuable upon the exercise of presently outstanding options and warrants outside our employee incentive plans. Also 7.3 million shares are issuable upon

the conversion of our 5.5% convertible notes, based upon the conversion price of $18.51 per share; 4.2 million shares are issuable upon conversion of our

Series C preferred stock (“Series C Preferred Stock”), based upon the conversion price of $8.75 per share; and 4.3 million shares are issuable upon

conversion of our 11.5% Convertible Bonds (as defined below), based on a conversion price of $16.52 per share.

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

Certain provisions of our amended and restated articles of incorporation and amended and restated bylaws and the Nevada Revised Statutes (“NRS”) could

delay or make more difficult a change of control transaction or other business combination that may be beneficial to stockholders. These provisions include,

but are not limited to, the ability of our board of directors to issue a series of preferred stock, classification of our board of directors into three classes and

limiting the ability of our stockholders to call a special meeting.

We are subject to the “Combinations with Interested Stockholders Statute” and the “Control Share Acquisition Statute” of the NRS. The Combinations Statute

with Interested Stockholders provides that specified persons who, together with affiliates and associates, own, or within three years did own, 10% or more of

the outstanding voting stock of a corporation cannot engage in specified business combinations with the corporation for a period of two years after the date on

which the person became an interested stockholder, unless the combination or the transaction by which the person first became an interested stockholder is

approved by the corporation’s board of directors before the person first became an interested stockholder.

The Control Share Acquisition Statute provides that persons who acquire a “controlling interest” as defined by the statute, in a company may only be given

full voting rights in their shares if such rights are conferred by the stockholders of the company at an annual or special meeting. However, any stockholder

that does not vote in favor of granting such voting rights is entitled to demand that the company pay fair value for their shares if the acquiring person has

acquired at least a majority of all of the voting power of the company. As such, persons acquiring a controlling interest may not be able to vote their shares.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

Drilling Statistics

A well is considered productive for purposes of the following table if it justifies the installation of permanent equipment for the production of oil or gas. The

information contained in the table should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation

between the number of productive wells drilled, quantities of reserves found or economic value. The following table shows the results of the oil and gas wells

in which we participated, drilled and tested during 2012, 2011 and 2010:

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 Productive Wells Dry Holes In Progress Wells

 Gross Net Gross Net Gross Net

Exploration 

2012: 

United States — — — — 4 1.00

2011: 

United Kingdom — — — — 1 0.20

United States — — 2 1.00 4 1.00

2010: 

United Kingdom 3 0.38 1 0.10 — — 

United States — — — — 2 1.00

Development 

2012: 

United Kingdom 4 1.11 — — 1 0.44

United States 2 0.66 — — 3 3.00

2011: 

United Kingdom 4 0.09 — — 3 0.90

United States 16 4.36 — — 4 1.66

2010: — — — — 2 0.05

United Kingdom 13 3.00 — — 2 1.00

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, 2012, our productive wells included the following:

 Oil Wells Gas Wells

 Gross Net Gross Net

United Kingdom 37 8.66 — — 

United States 3 1.63 44 14.91

Total 40 10.29 44 14.91

Reserves

Our proved oil and gas reserves at December 31, 2012, 2011 and 2010 included the following:

 Oil Gas Oil Equivalents

 (MBbls) (MMcf) (MBOE)

2012: 

United Kingdom 13,733 56,901 23,217

United States 6 14,690 2,454

 13,739 71,591 25,671

2011: 

United Kingdom 4,060 50,723 12,514

United States 41 60,978 10,204

 4,101 111,701 22,718

2010: 

United Kingdom 3,664 56,177 13,027

United States 5 9 31,777 5,355

 3,723 87,954 18,382

At December 31, 2012, the Alba field, in the U.K. North Sea, represented more than 15% of our proved reserves, with 9.9 MMBOE, 1.2 MMBOE and 0.9

MMBOE of our proved reserves at December 31, 2012, 2011 and 2010, respectively.

The Rochelle field, one of our non-producing North Sea development assets, represented more than 15% of our proved reserves at December 31, 2012, 2011,

and 2010. Rochelle had 9.0 MMBOE, 8.2 MMBOE and 9.4 MMBOE of proved reserves at December 31, 2012, 2011and 2010, respectively.

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At December 31, 2011, the Grand Cane field, a gas field in the Haynesville area, represented more than 15% of our proved reserves, with 3.8 MMBOE and

0.1 MMBOE of proved reserves at December 31, 2011 and 2010, respectively.

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. We

expect our proved undeveloped reserves in the U.K. to become proved developed reserves over the next two years as development plans are completed and

production commences on Rochelle. In the U.S., all proved undeveloped reserves in 2012 were removed from proved reserves due to adverse gas market

conditions. When market conditions improve, it is expected that these undeveloped reserves will be economic to develop and will be restored to proved reserves.

See Note 5 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 unproved properties. Our proved developed and undeveloped oil and gas reserves at December 31, 2012,

2011 and 2010 included the following:

 

Proved

Developed

Reserves 

Proved

Undeveloped

Reserves 

Total

Proved

Reserves

 (MBOE) (MBOE) (MBOE)

2012: 

United Kingdom 5,785 17,432 23,217

United States 2,454 — 2,454

 8,239 17,432 25,671

2011: 

United Kingdom 1,402 11,112 12,514

United States 3,825 6,379 10,204

 5,227 17,491 22,718

2010: 

United Kingdom 1,333 11,694 13,027

United States 2,227 3,128 5,355

 3,560 14,822 18,382

Preparation of Oil and Gas Reserve Information

We have established internal controls over reserve estimation processes and procedures to support the accurate and timely preparation and disclosure of reserve

estimations in accordance with SEC and GAAP requirements. These controls include oversight of the reserves estimation reporting processes by our technical

staff, annual external audits of all of our proved reserves by independent reserve engineers and secured access to reservoir databases and systems. Proved

reserve estimates are prepared by our technical staff and reviewed and approved by our executive team, including our Executive Vice-President – International

and Executive Vice President –

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North America. In addition, we have a “Technology and Reserves” committee of our Board of Directors. The committee supports the board by providing

increased focus on emerging technologies in the upstream industry and oversight of our reserve evaluation and reporting processes. Reserves are reviewed

internally with senior management quarterly and presented to the Technology and Reserves Committee and our Board of Directors on an annual basis for their

review.

Our oil and gas reserve estimates were prepared by our internal reservoir engineers and audited by 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.

Qualification of Reserves Preparers and Auditors

We employ oil and gas technical professionals, including geophysicists, petrophysicists, geologists, and reservoir engineers, who have 10 to 35 years of

experience in their technical fields. Our Director of Reservoir Engineering, who has over 25 years of experience and a master’s degree in petroleum engineering,

supervises our technical professionals in the evaluation and estimation of our oil and gas reserves. In addition, we engage experienced and qualified consultants

to perform various comprehensive seismic acquisitions, processing, reprocessing, interpretation, and other related services.

The reserves estimates shown herein have been independently evaluated by Netherland, Sewell & Associates, Inc. (“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 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 reserves for the reviewed properties as estimated by us are, in the aggregate, reasonable,

prepared in accordance with generally accepted petroleum engineering and evaluation principles and conform to the SEC’s definition of proved reserves as set

forth in Rule 210.4-10(a) of Regulation S-X. NSAI has informed us that the tests and procedures used during its reserves audit conform to the Standards

Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Paragraph 2.2(f) of the

Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information defines a reserves audit as the process of reviewing certain of the

pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves prepared by others and the rendering of an opinion about:

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• 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, 2012, in the areas indicated.

 Developed Undeveloped

 Gross Net Gross Net

United Kingdom 48,971 15,393 268,124 86,077

United States 8,301 4,219 516,371 149,628

Total 57,272 19,612 784,495 235,705

As of December 31, 2012, we had approximately 49,300, 15,800 and 36,000 net acres in the U.K. and U.S combined that are scheduled to expire by

December 31, 2013, 2014 and 2015, respectively, if we take no action to continue the term of the underlying license through operational or administrative

actions. This includes all of our acreage in Alabama, where we have 14,800 net acres and have suspended operations. It also includes approximately 33,600

net acres in Montana that will expire in 2013-2015, where we have rights to extend certain leases for an additional five years. We have a total of 88,900 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 25 to our consolidated financial statements under Item 8 of this Annual Report on Form 10-K.

At December 31, 2011, the Grand Cane field, in the Haynesville area, represented more than 15% of our proved reserves. Grand Cane is a gas field and

represented 1,921 MMcf, 662 MMcf and 48 MMcf of our gas sales in 2012, 2011 and 2010, respectively.

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At December 31, 2012, the Alba field, in the U.K. North Sea, represented more than 15% of our proved reserves. Alba is an oil field and represented 1,263

Mbbls, 191 Mbbls and 231 Mbbls of our oil sales in 2012, 2011 and 2010, respectively.

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.

Terminated Acquisition of Marcellus Assets

On July 17, 2011, we entered into agreements with 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. 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, exceeded the contractual threshold of 15% of the purchase price for the applicable asset group ($85 million); and (ii) the condition of

the pipeline was not in compliance with applicable regulatory standards, which would constitute a material violation of a representation and warranty

contained in the applicable SM Purchase Agreement.

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. Specifically, SM Energy has alleged, among other things, that most of our asserted title defects are without merit

and, in any event, would not exceed 15% of the applicable purchase price. SM Energy seeks the award of unspecified actual damages, including costs and

reasonable attorney’s fees, and specific performance. On January 17, 2012, we filed an answer and counterclaim denying the allegations and seeking the

return of our $6 million deposit, which we believe we are entitled to recover pursuant to the terms of the SM Purchase Agreements, and for the damages that we

suffered as a result of SM Energy’s misrepresentations. We intend to contest the case vigorously.

Item 4. Mine Safety Disclosures

Not applicable.

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Part II

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

On March 15, 2011, we completed the transfer of the primary listing for our common stock from the NYSE Amex to the New York Stock Exchange

(“NYSE”) under the symbol “END.” Our common stock is also listed on the London Stock Exchange under the symbol “ENDV.”

Reverse Stock Split

In October 2010, our Board of Directors authorized a share consolidation of our common stock, in the form of a one-for-seven reverse stock split, effective at

the opening of trading on November 18, 2010. As a result of the share consolidation, every seven shares of our common stock outstanding were automatically

combined into one share of our common stock. All share information and prices per share discussed in this Annual Report on Form 10-K have been restated to

reflect the share consolidation.

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, and prior to March 15, 2011, the NYSE Amex. These quotations represent inter-dealer prices, without retail mark-up, markdown or commission,

and may not represent actual transactions.

 2012 2011

 High Low High Low

First Quarter

 $13.48 $8.81 $14.51 $ 11.13

Second Quarter 13.21 5.73 15.14 11.59

Third Quarter 10.48 7.37 16.43 7.27

Fourth Quarter 10.02 4.66 10.23 5.80

Holders

As of March 13, 2013, the number of holders of record of our common stock was 165. We believe that there are a number of additional beneficial owners of

our common stock who hold such shares in street name.

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Dividends

We have not paid any cash dividends on our common stock to date and have no intention of declaring or paying any cash dividends on our common stock in

the foreseeable future. The declaration and payment of dividends is subject to the discretion of our Board of Directors and to certain limitations imposed under

Nevada corporate laws and the agreements governing our debt obligations. The timing, amount and form of dividends, if any, will depend on, among other

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

Our Series B preferred stock is subject to a cumulative 8% dividend (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.

Shareholder Return Performance Presentation

The performance graph shown below was prepared based upon the following assumptions:

• $100 was invested in our Common Stock on December 31, 2007, and $100 was invested in each of the S&P 500 Index and the industry peer

group (“Peer Group”) on December 31, 2007 at the closing price on such date.

• The Peer Group investment is weighted based on the market capitalization of each individual company within the applicable peer group at the

beginning of the period and each year.

• Dividends are reinvested on the ex-dividend dates.

The Peer Group is comprised of the following oil and gas producers: Carrizo Oil & Gas Inc.; Crimson Exploration Inc.; Gastar Exploration, Ltd.; Goodrich

Petroleum Corp.; McMoRan Exploration Co.; Rosetta Resources, Inc.; Swift Energy Co.; and W&T Offshore Inc. The performance of the indices is shown

on a total return (dividend reinvestment) basis; however, we paid no dividends on our Common Stock during the period shown. The graph lines merely

connect the beginning and end of the measuring periods and do not reflect fluctuations between those dates.

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There can be no assurance that the Company’s stock performance will continue into the future with the same or similar trends depicted in the performance

graph. The Company will not make or endorse any predictions as to future stock performance.

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, 2012. 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.” The selected consolidated

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

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Summary Financial Data

(Amounts in thousands, except per share data) Year Ended December 31,

 2012 2011 2010 2009 2008

Summary Income Statement Data: 

Revenues $ 219,058 $ 60,091 $ 71,675 $ 62,293 $ 170,781

Operating Profit (Loss) 19,801 (67,614) 1,327 (50,398) 18,236

Net Income (Loss) to Common Shareholders (128,049) (132,969) 54,304 (62,206) 45,681

Net Income (Loss) Per Common Share - Basic: 

Continuing Operations $ (3.01) $ (3.70) $ 2.34 $ (5.84) $ 0.82

Discontinued Operations — — — 2.50 1.67

Total $ (3.01) $ (3.70) $ 2.34 $ (3.34) $ 2.49

Net Income (Loss) Per Common Share - Diluted: 

Continuing Operations $ (3.01) $ (3.70) $ 1.95 $ (4.70) $ 0.59

Discontinued Operations — — — 2.50 1.20

Total $ (3.01) $ (3.70) $ 1.95 $ (2.20) $ 1.79

Summary Balance Sheet Data: 

Working Capital $ (39,605) $ 38,351 $ 71,145 $ 24,885 $ 22,902

Total Assets 1,442,472 924,991 750,287 538,879 737,470

Debt, net of discount 859,506 467,378 345,306 223,385 227,855

Convertible Preferred Stock 43,703 43,703 53,152 59,058 125,000

Equity 99,431 154,079 154,618 60,133 117,971

(1) Includes the following:

• 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 2009 and 2010;

• disposition of our interests in the Cygnus reserves in 2010 for a gain of $87 million;

• disposition of our discontinued operations in Norway in 2009 for a gain of $47 million;

• impairments of $53.1 million, $65.7 million, $7.7 million, $43.9 million, and $37.0 million, in 2012, 2011, 2010, 2009, and 2008,

respectively; and

• unrealized gains (losses) on derivatives of $5.1 million, $8.4 million, $12.3 million, $(55.6) million, and $76.7 million, in 2012, 2011, 2010,

2009, and 2008, respectively.

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

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

This Management’s Discussion and Analysis of Financial Condition and Results of Operations and other parts of this Annual Report on Form 10-K contain

forward-looking statements that involve risks and uncertainties. All forward-looking statements included in this Annual Report on Form 10-K are based on

information available to us on the date hereof, and we assume no obligation to update any such forward-looking statements. Our actual results could differ

materially from those anticipated in these forward-looking statements as a result of a number of factors, including those set forth in the section captioned

“Risk Factors” in Item 1A and elsewhere in this Annual Report on Form 10-K. The following should be read in conjunction with the audited financial

statements and the notes thereto included in “Item 8. Financial Statements and Supplementary Data.” The following discussion also includes non-GAAP

financial measures, which may not be comparable to similarly titled measures presented by other companies. Accordingly, we strongly encourage investors to

review our financial statements in their entirety and not rely on any single financial measure.

Overview

We are an 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 our U.S. operations are spending

minimal capital, primarily on strategic positioning, while we monitor U.S. gas prices. During 2012 and 2011, 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.

By the end of 2012, we had made progress toward those goals. 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. Our goal for 2012 was to increase production, cash flows and proved reserves as we believe

that longer-term this creates value for our shareholders. During 2012, and as a result of the above events, we:

• increased production year over year by 231%;

• increased proved reserves year over year in the UK by 186% and overall by 113%; and

• increased production cash flows to $160.6 million.

During the third quarter of 2012, we began drilling the first of two planned development wells at Rochelle. We completed the hook-up of the pipelines and flowlines to the subsea manifolds for the field but encountered operational difficulties following severe weather in early 2013. As a result, we have suspended

drilling operations on the East Rochelle well and moved the rig to the second well site at West Rochelle. While we had originally anticipated first production at

Rochelle would occur in the fourth quarter of 2012, delays in receiving the drilling rig, the operational difficulties at East Rochelle and the further estimated

time to drill West Rochelle have delayed our anticipated first production until mid-2013 at the earliest.

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During 2010, we acquired 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.

In the last two years, we have incurred substantial capital expenditures and acquisition costs as we advanced development projects at Bacchus and Rochelle

and completed acquisitions. We also experienced delays in the timing of first production from our Bacchus and Rochelle developments, a slowing of

production from our U.S. drilling operations as we curtailed the U.S. drilling program in response to declining U.S. gas prices, increased capital costs due to

the production delays at Bacchus and Rochelle projects and increased debt service costs required to financing the drilling and acquisition program. The

production delays and increased capital costs and debt service costs placed a strain on our cash flow from operations and our ability to reduce our debt

leverage.

Strategic Alternatives

As discussed previously, in February 2013, we initiated a review of strategic alternatives and will announce the results of the effort once a course of action is

chosen. The primary objective of the strategic review is to accelerate the deleveraging of the balance sheet and unlock the value of our underlying assets. The

Board of Directors will consider a full range of options, including:

• a sale, joint venture or partnership in respect of our activities in the North Sea;

• a sale of specific assets;

• a sale or merger of the Company; or

• continuing to execute on our operational plan.

Tudor, Pickering, Holt & Co. and Lambert Energy Advisory Ltd. have been engaged as our financial advisors in this process. There is no assurance that this

strategic alternatives review will result in a change to our current business plan, pursuing a particular transaction or completing any such transaction.

Since year-end 2012, we have also completed several transactions to improve our liquidity position and extended the maturities of some of our debt and other

obligations. The completion of these recent financing activities are designed to provide sufficient liquidity to bring the Rochelle development on line, drill a

third well at Bacchus and allow sufficient time for a thoughtful and disciplined strategic review process. These transactions include:

• extended or replaced reimbursement agreements covering certain of our abandonment liabilities in the U.K. which would have expired in 2013;

• entered into a forward sale agreement for a payment of approximately $22.5 million in return for a specified volume of crude oil in excess of

200,000 barrels to be delivered over a six month delivery period from our UK North Sea production;

• entered into a sale and purchase agreement (the “Sale and Purchase Agreement”) for $107.5 million providing for the sale and purchase of a

monetary production payment; and

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• extended the maturity of approximately $100 million of the commitments under our revolving credit facility (“ Revolving Credit Facility”) from

October 12, 2013 to June 30, 2014.

Each of these transactions are discussed in Note 24 to our consolidated financial statements in “Item 8. Financial Statements and Supplementary Data.”

2013 Liquidity and Capital Resources

During 2013, our primary uses of financial resources are expected to be:

• our drilling activities, principally at our Alba, Bacchus and Rochelle fields in the U.K.; and

• interest payments on existing credit facilities and fees related to our reimbursement agreements covering our abandonment obligations.

As of December 31, 2012, we had $815.0 million in outstanding indebtedness, net of $59.2 million in cash. Being highly leveraged, servicing our debt and

other long-term obligations will continue to require a significant portion of our cash flow from operations and available cash on hand. The combination of these

debt servicing requirements, capital expenditures and the delay in cash flow resulting from the mechanical issues experienced at the Rochelle field may exceed

the cash flow from our current operations. Ultimately, our primary uses and sources of financial resources will be impacted by the outcome of our strategic

review.

If we are unable to meet any short-term liquidity needs out of cash on hand, we would attempt to refinance debt, sell forward our production, sell assets, issue

debt or equity, delay discretionary capital expenditures, decline to participate in non-operated drilling or perform any other alternatives resulting from our

strategic review. No assurance can be given however that we could successfully consummate any of these alternatives.

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. 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, increased from $48.67 per BOE in 2011 to $76.07 per BOE in 2012. Our revenues increased from $60.1

million for the year ended December 31, 2011 to $219.1 million for 2012, primarily as a result of higher production volumes related to first production from

Bacchus in the second quarter of 2012 and our purchase of the additional interest in Alba. Our revenues decreased from $71.7 million for the year ended

December 31, 2010 to $60.1 million for 2011 primarily as a result of lower production volumes from our producing assets partially offset by higher

commodity prices.

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In October 2010, we sold our interests in the Cygnus reserves in the Southern Gas Basin of the North Sea for $110 million (the “Cygnus Sale”). Upon the

closing of that transaction, we recognized a gain of $87 million. The cash proceeds were not burdened by any taxes payable and were primarily used to

accelerate our development projects and fund our acquisition of an additional 20% interest in the Bacchus field, which closed in February 2011.

For 2012, net loss to common stockholders was $(128.0) million, or $(3.01) per diluted share. This net loss includes a $53.1 impairment related to our U.S.

properties, increased interest expense resulting from borrowings under existing debt agreements and issuances of new debt obligations and a loss on the early

extinguishment of debt of $21.7 million. Net loss to common stockholders was $(133.0) million for 2011, or $(3.70) per diluted share. Net income to common

stockholders for 2010 was $54.3 million, or $1.95 per diluted share, including a gain on the Cygnus Sale of $87 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 (used in) operations was $38.6 million in 2012 versus $(39.3) million in 2011 and $17.0

million in 2010. Adjusted EBITDA (as defined below) was $129.9 million in 2012, as compared to $25.1 million in 2011 and $124.8 million in 2010.

These fluctuations in Adjusted EBITDA are primarily due to the changes in our production volumes, interest expense and operating costs. In addition,

Adjusted EBITDA for 2010 includes the gain on the Cygnus Sale.

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 company’s ability to maintain or

grow production levels and reserves, internally fund capital expenditures and service debt as well as provide comparisons to other oil and gas exploration and

production companies. These measures include, among others, debt and cash balances, production levels, oil and gas reserves, drilling results, adjusted

earnings before interest, taxes, depreciation, depletion and amortization (“Adjusted EBITDA”) and net income as adjusted.

Net loss as adjusted for 2012 was $(54.2) million. Net loss as adjusted for 2011 was $(49.7) million, as compared to net income as adjusted of $57.4

million in 2010.

For definitions of net income 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.”

Revenues

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

• Our revenues increased from $60.1 million for the year ended December 31, 2011 to $219.1 million for the year ended December 31, 2012,

primarily due to increases in U.K. oil production from our increased interest in the Alba field and initial production from the Bacchus field.

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• As a result of substantially decreased U.K. gas production from the Goldeneye field and decreases in U.S. natural gas prices, partially offset by

increased oil prices, our revenues decreased from $71.7 million for the year ended December 31, 2010 to $60.1 million for the year ended

December 31, 2011.

• U.S. production increased from 2010 to 2011 primarily due to the results of our successful drilling and completion of wells during 2010.

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

 Year Ended December 31,

 2012 2011 2010

Sales volume 

Oil and condensate sales (Mbbls): 

United Kingdom 1,994 373 545

United States 3 7 6

Total 1,997 380 551

Gas sales (MMcf): 

United Kingdom 91 94 3,071

United States 5,207 5,033 2,636

Total 5,298 5,127 5,707

Oil equivalent sales (MBOE) 

United Kingdom 2,009 388 1,057

United States 871 846 445

Total 2,880 1,234 1,502

Total BOE per day 7,868 3,382 4,115

Physical production volume (BOE per day) : 

United Kingdom 5,494 1,095 2,904

United States 2,379 2,319 1,221

Total 7,873 3,414 4,125

Realized Price, before and after derivatives: 

Oil and condensate price ($ per Bbl) 103.56 109.20 76.39

Gas price ($ per Mcf) 2.32 3.63 5.18

Equivalent oil price ($ per BOE) $ 76.07 $ 48.67 $ 47.72

Operating Costs ($ per BOE) $ 20.33 $ 14.31 $ 10.22

(1) We record oil revenues on the sales method and 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

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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 2012, operating expenses increased to $58.5 million as compared to $17.7 million for 2011, primarily due to costs related to our increased interest in the

Alba field and initial production from the Bacchus field. Operating costs per BOE increased to $20.33 per BOE for 2012 from $14.31 per BOE for 2011

primarily due to the increasing portion of U.K. operations to our total expenses. In addition, 2012 operating expenses increased as a result of the sale of $9.7

million of oil inventory purchased in the Alba Acquisition. 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.

For 2011, operating expenses increased to $17.7 million as compared to $15.3 million for 2010, primarily due to increased U.S. workover expense and

increases in transportation expense and production taxes as a result of increased U.S. sales volumes. Operating costs per BOE increased to $14.31 per BOE

for 2011 from $10.22 per BOE for 2010. The increase in operating costs per BOE is due to the impact of both the increases in the dollar levels of operating

expenses and the decreased volumes discussed above.

DD&A and Impairment of Oil and Gas Properties

Depreciation, depletion and amortization (“DD&A”) expense increased from 2011 to 2012 primarily due to increased production due to our acquisition of

additional interest in Alba and initial production from Bacchus. DD&A expense decreased from 2010 to 2011 as a result of impairments in oil and gas

properties. DD&A per BOE was $23.11, $21.45 and $19.24 for the years ended December 31, 2012, 2011 and 2010, respectively.

In 2012, 2011 and 2010, we recorded $53.1 million, $65.7 million and $7.7 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 2012 impairment was primarily related to the declines in U.S. gas prices. The 2011

impairment was primarily related to declines in U.S. gas prices and the impact of our determination that the likely economic returns in the future would not

warrant further investment in our test wells in the Alabama area. Our decision to discontinue activities in that area resulted in the reclassification of related

amounts as being evaluated for full cost accounting purposes.

The impairment during 2010 was also related to our U.S. oil and gas properties, pre-tax, and was primarily due to the declaration of two wells as dry holes

during the first quarter of 2010.

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General and Administrative (“G&A”) Expenses

Our G&A expenses increased from $17.9 million in 2011 to $21.1 million for 2012 as a result of an increase in employee compensation expense and an

increase in consulting costs associated with the additional staff to pursue the Rochelle development as operator and our expanding U.K. operations. The

decrease in G&A expense from $18.4 million in 2010 to $17.9 million in 2011 was a result of a decrease in employee compensation expense, partially offset

by an increase in consulting costs.

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 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 13 to our consolidated financial statements in “Item 8. Financial Statements and Supplementary Data.”

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

 Year Ended December 31,

(Amounts in thousands) 2012 2011 2010

Compensation $ 20,520 $ 17,363 $ 18,110

Consulting, legal and accounting fees 9,160 6,461 5,843

Other expenses 3,299 3,600 3,888

Total gross cash G&A expenses 32,979 27,424 27,841

Non-cash stock-based compensation 6,036 3,697 3,692

Gross G&A expenses 39,015 31,121 31,533

Less: capitalized G&A expenses (17,930) (13,268) (13,118) 

Net G&A expenses $ 21,085 $ 17,853 $ 18,415

Interest Expense and Other

The increase in interest expense from $44.9 million in 2011 to $84.1 million in 2012 reflects the increases in interest expense that occurred as we completed

several financing transactions during 2012 and 2011 that have had a significant impact on our interest expense, including the issuance of new debt facilities

and the repayment of extinguished debt. Components of interest expense are as follows:

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 Year Ended December 31,

(Amounts in thousands) 2012 2011 2010

Interest expense on debt outstanding $ 77,128 $ 10,706 $ 8,461

Interest expense on retired debt 19,701 36,664 19,794

Amortization of loan costs and discount 14,179 12,234 10,262

Gross interest expense 111,008 59,604 38,517

Less: capitalized interest (26,886) (14,711) (3,925) 

Net interest expense $ 84,122 $ 44,893 $34,592

Each of our debt instruments and transactions are discussed in Note 9 to our consolidated financial statements in “Item 8. Financial Statements and

Supplementary Data.”

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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, 2012: 

Net income (loss) before taxes $(22,959) $ (91,383) $ 2,344 $(111,998) 

Current tax expense 31,796 — 26 31,822

Deferred tax benefit (26,181) — — (26,181) 

Deferred tax expense related to U.K. tax law change 8,587 — — 8,587 

Total tax expense 14,202 — 26 14,228

Net income (loss) after taxes $ (37,161) $ (91,383) $ 2,318 $(126,226) 

Year Ended December 31, 2011: 

Net income (loss) before taxes $ (9,806) $(99,409) $ 5,281 $ (103,934) 

Current tax (benefit) expense 5,926 4 15 5,945

Deferred tax benefit (4,308) — — (4,308) 

Deferred tax expense related to U.K. tax law change 25,424 — — 25,424

Total tax expense 27,042 4 15 27,061

Net income (loss) after taxes $ (36,848) $(99,413) $5,266 $(130,995) 

Year Ended December 31, 2010: 

Net income (loss) before taxes $ 90,160 $ (30,978) $ (3,439) $ 55,743

Current tax (benefit) expense 2,734 — (154) 2,580

Deferred tax (benefit) expense (2,388) — (929) (3,317) 

Foreign currency losses on deferred tax liabilities — — (51) (51) 

Total tax (benefit) expense 346 — (1,134) (788) 

Net income (loss) after taxes $ 89,814 $ (30,978) $(2,305) $ 56,531

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 of all deferred tax assets generated. Therefore, our income tax expense relates primarily to our operations in the U.K. 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.

During 2011, $25.4 million of the tax expense is attributable to the increase in the supplemental corporate tax rate due to a tax law change, enacted by the U.K.

government, in July 2011, that raised the existing supplementary charge on profits from North Sea oil and gas production from 20% to 32%.

Our current tax expense is related to Petroleum Revenue Tax (“PRT”) on our Alba field in the U.K. The increase in current tax expenses from 2011 to 2012 is

primarily due to our acquisition of the additional interest in the Alba field in 2012.

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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,

 2012 2011 2010

Federal income tax expense (benefit) at statutory rate $(39,199) $(36,378) $19,500

Taxation of foreign operations 5,859 3,254 (579) 

Effect of out-of-period adjustment 6,997 — — 

Tax-free gain on sale of reserves in place — — (30,510) 

Change in valuation allowance – U.S. 30,329 24,604 (2,252) 

U.K. Tax increase from tax law and rate changes 8,587 25,424 — 

Foreign currency (gain) loss on deferred taxes — — (50) 

Deemed foreign dividend of wholly owned subsidiaries — 8,572 11,466

Disallowed executive compensation 1,655 1,585 765

Other — — 872

Total Income Tax Expense $ 14,228 $ 27,061 $ (788) 

Effective Income Tax Rate -13% -26% -1% 

Liquidity and Capital Resources

Our capital expenditures and acquisitions were as follows:

 Year Ended December 31,

(Amounts in thousands) 2012 2011 2010

Direct Oil & Gas Capital Expenditures: 

U.K. $ 174,138 $ 97,829 $ 42,765

U.S. 14,271 76,021 41,682

 188,409 173,850 84,447

Acquisitions 192,214 51,542 43,725

 380,623 225,392 128,172

Capitalized G&A, Interest and Other 49,215 31,897 19,682

Asset Retirement Obligations 137,675 14,612 2,819

Total Capital Expenditures and Acquisitions $567,513 $271,901 $150,673

Asset Retirement Obligations Paid $ 8,521 $ 15,256 $ 9,508

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North Sea Acquisition

On December 23, 2011, we entered into a purchase agreement (the “COP Purchase Agreement”), through our wholly owned subsidiary Endeavour Energy UK

Limited (“EEUK”), with ConocoPhillips (U.K.) Limited, ConocoPhillips Petroleum Limited and ConocoPhillips (U.K.) Lambda Limited, subsidiaries of

ConocoPhillips (collectively, the “Sellers”), to acquire their interest in three producing U.K. oil fields in the Central North Sea. On May 31, 2012, we closed

the Alba field portion of this acquisition (the “Alba Acquisition”), which consisted of an additional 23.43% interest in the Alba field. 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 pay a fee of 13% per year, payable quarterly, computed based on the outstanding amount of each letter of credit. As of

December 31, 2012, we do not expect to begin decommissioning activities for the Alba field for many years.

After substantial effort and extensions, we and the Sellers (as defined in Note 3 to the Consolidated Financial Statements) were unable to reach the unanimous

agreement and consent required to transfer the interests in the two remaining U.K. oil fields (the MacCulloch and Nicol fields) due to failure to agree on certain

commercial terms related to the future timing and amount of collateral required to be posted for future decommissioning costs. As a result of the parties being

unable to reach agreement to enable the transfers to occur, the purchase agreement with respect to these two fields was terminated in accordance with its terms

on December 14, 2012.

United Kingdom Capital Program

Our capital program in the U.K. for 2012 was focused on two large projects in the North Sea, the Bacchus and Rochelle fields, as well as infield drilling at

Alba.

At December 31, 2012, we held a 30% working interest in our Bacchus field asset, which is operated by Apache Corporation, who owns a 50% working

interest. During 2012, we drilled the first and second development wells and achieved production in April and July, respectively. With the additional positive

data gained from the second development well, the Bacchus partners have decided to observe production results before making a final decision on the

placement of the third development well to insure optimization of the entire reservoir. That analysis has been completed and we expect to begin drilling the third

well toward the end of the first quarter of 2013.

Our working interest in the Rochelle area is 44% and we are the operator of the field, which is comprised of Blocks 15/26b, 15/26c and 15/27. During the

third quarter of 2012, we began drilling the first of two planned development wells. With drilling delays, the Rochelle project subsea infrastructure outpaced

the drilling operations. The joint interest partners decided to

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suspend the first well due to the inability to perform simultaneous pipe-lay and development drilling operations. In October 2012, the drilling rig moved off

location to allow for the hook-up of the pipelines and flow-lines to the subsea manifolds, thereby delaying our estimated start of production from the fourth

quarter of 2012 to the first quarter of 2013. Since October 2012, the pipeline system, umbilicals and tie-ins to the offtake solution at the Scott platform have

been completed and tested. In January 2013, the rig returned to the East Rochelle site to continue final drilling.

In February 2013, following a severe storm lasting several days, we performed a routine inspection of the conductor, well head and blow out preventer systems

which revealed that the cement around the top of the conductor pipe, which anchors the well to the seabed floor, had been lost creating a non- uniform hole

around the conductor. The hole extended approximately 4 to 7 feet in diameter and 25 feet in depth.

As a result of this finding, drilling operations were suspended on the East Rochelle well. The work to repair the cementing around the conductor pipe has been

completed. We are conducting a thorough analysis to identify the cause of the cement loss and evaluate if there has been any potential fatigue damage to the

conductor pipe itself. Our preliminary findings suggest that swirling currents caused by severe storms created vibrations that liquidized the sands

surrounding the cement anchorage. With the loss of integrity of the surrounding sands, those sands were eroded, creating the resulting crater. Our investigation

is still ongoing. We are also investigating the structural integrity of the conductor pipe to determine if we can safely re-enter the existing well to complete the

drilling phase.

To mitigate delays while we conduct our analysis, we moved the rig to the West Rochelle area and commenced drilling of the second production well. By

switching to the West Rochelle area, drilling and completion of the second production well may proceed without the delay. If drilling and completion proceed as

expected, we anticipate first production from the West Rochelle well could begin in mid-2013 at the earliest.

We had previously disclosed a potential commitment on a drilling rig in our North Sea operations relating to a dispute with the rig operator. On June 6, 2011,

we entered into a settlement agreement with the rig operator whereby the parties were mutually released from all future claims. We incurred costs of $14 million

related to the settlement, which are included in capital expenditures.

United States Capital Program

Our primary focus in the U.S. has been onshore unconventional oil and gas developments. During 2011 and 2010, we completed 16 and 13 productive wells,

respectively, and had an additional eight and four wells, respectively, awaiting on completion. During 2012, we completed two Haynesville gas wells and

currently have three Marcellus wells and four Heath wells waiting on completion. With declining U.S. gas prices, we have limited drilling our capital

expenditures in 2012 to primarily those expenditures necessary to maintain our acreage positions and fulfill minor drilling commitments.

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Capital Resources

 Year Ended December 31,

(Amounts in thousands) 2012 2011 2010

Net cash provided by (used in) operating activities $ 38,613 $ (39,343) $ 17,019

Net cash used in investing activities $(484,550) $(166,411) $ (56,314) 

Net cash provided by financing activities $399,086 $ 212,523 $111,275

Our primary sources of financial resources and liquidity are cash on hand, internally generated cash flows from operations and access to the credit and capital

markets, to the extent necessary.

Cash flow provided by (used in) operations increased to $38.6 million for 2012 from $(39.3) million for 2011 due to cash flows from our purchase of the

additional interest in Alba. Cash flow provided by (used in) operations decreased to $(39.3) million for 2011 from $17.0 million for 2010 primarily due to

lower oil and gas revenue resulting from lower production, and working capital changes, lower gas prices in the U.S. and increased interest expense following

our issuance of additional debt facilities. Net cash provided by financing activities has provided the necessary funding for our capital expenditures, primarily

related to our two drilling activities at our Bacchus and Rochelle fields in the U.K., and our acquisitions of additional interests in Bacchus and Alba and U.S.

acreage.

Our debt facilities, letters of credit, reimbursement agreements and related transactions for 2012, 2011 and 2010 are as follows:

• Revolving Credit Facility: In April 2012, we entered into a $100 million Credit Agreement with Cyan, as administrative agent, which was

subsequently increased to $125 million. At December 31, 2012, we have $115 million outstanding under the Revolving Credit Facility.

Subsequent to December 31, 2012, we extended the maturity of $100 million of the commitments under our Revolving Credit Facility from

October 12, 2013 to June 30, 2014.

• 2018 Notes: In 2012, we closed the private placement of $554 million of 12% notes due 2018 (the “2018 Notes”). The private placement took

place in three parts:

• $350 million aggregate principal amount of 12% first priority notes due 2018 (the “First Priority Notes”) in February, priced at 96% of

par;

• $150 million aggregate principal amount of 12% second priority notes due 2018 (the “Second Priority Notes,”) also in February, priced at

96% of par; and

• an additional $54 million aggregate principal amount of the First Priority Notes in October, priced at 109% of par.

Prior to the closing of the Alba Acquisition, the net proceeds of the offering were held in an escrow account. In May 2012, concurrent with the

closing of the Alba Acquisition, the net proceeds were used to fund the acquisition and repay all outstanding amounts under the Senior Term Loan

(see below).

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• 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 that replaced previously outstanding letters of credit and assisted in the closing of the Alba

Acquisition. 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. We have no cash collateral associated with the reimbursement agreements

and the commitments under the reimbursement agreements have not been recorded as liabilities.

• 5.5% Convertible Notes: In July 2011, we issued $135 million aggregate principal amount of our 5.5% Convertible Notes. We issued the 5.5%

Convertible Notes, expecting to utilize the majority of the net proceeds of this offering to fund an acquisition of acreage and related midstream

assets in the Marcellus shale play. As we terminated the acquisition agreement in December 2011, these proceeds have been used for general

corporate purposes.

• Letters of Credit: In July 2011, we secured new letters of credit that allowed us to release $33 million of restricted cash that served as collateral for

previous letters of credit related to certain of our abandonment liabilities. We terminated this letter of credit facility agreement in May 2012.

• Senior Term Loan: In August 2010, we entered into a credit agreement with Cyan, as administrative agent, and various lenders for a senior,

secured term loan, in the aggregate amount of $150 million, which was subsequently increased to $160 million (the “Senior Term Loan”). In July

2011, we amended our Senior Term Loan providing for an increase of $75 million in the amounts available under the Senior Term Loan. In May

2012, we repaid the outstanding balance of our Senior Term Loan with a portion of the proceeds from our 2018 Notes offering.

• 6% Senior Convertible Notes: In April 2011, we redeemed all $81.25 million of our outstanding 6% Senior Convertible Notes with a portion of

the proceeds from our common stock offering completed in March 2011.

• 11.5% Convertible Senior Bonds: In January 2008, we issued 11.5% Convertible Bonds due 2014 for gross proceeds of $40 million. In March

2011, we amended our 11.5% Convertible Bonds to: extend of the maturity date of the 11.5% Convertible Bonds; extend the date on which

holders may exercise a put right, and the occurrence of price reset if not exercised; and reduce the interest rate payable after March 31, 2014 to

7.5%.

• $50 million Subordinated Notes: In November 2009, we issued an aggregate $50 million of subordinated notes due 2014 (the “Subordinated

Notes”). We utilized a portion of the proceeds from our October 2012 offering of additional First Priority Notes to redeem our outstanding

Subordinated Notes.

Our equity issuances for 2012, 2011 and 2010 are as follows:

• June 2012: a public offering of 8.6 million shares of our common stock offering for net proceeds of $61.3 million;

• March 2011: a public offering of 11.5 million shares of our common stock offering for net proceeds of $118.4 million.

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2013 Planned Expenditures

With the uncertainties around our strategic review, we have not finalized our total capital expenditures budget for 2013. While we perform our strategic review,

we are monitoring our capital expenditures and delaying discretionary or other spending where appropriate. Our board of directors has approved a preliminary

capital expenditures budget for 2013, that is dependent upon a positive outcome from our strategic review, as follows:

 Preliminary Capital Budget

United Kingdom: 

Drilling and completions $90 million to $100 million

Maintenance capital $35 million

Exploration, seismic and other $15 million

Total U.K. $140 million -$150 million

United States $30 million to $40 million 

Total direct oil and gas capital $170 million to $190 million

Primarily discretionary and dependent on the outcome of our strategic review. The U.S. capital expenditures are anticipated to primarily occur in the

latter half of 2013.

In the U.K., the anticipated capital expenditures are primarily to bring the Rochelle development on line, drill the third well at Bacchus and maintain

production at Alba. Once the analysis of the East Rochelle well is concluded, we will be able to determine if we can safely re-enter the existing well to complete

the drilling phase or should plug and abandon the well and drill a new well. The anticipated capital expenditures do not include the capital expenditures to drill

a new well at East Rochelle, if it is required. Anticipated exploration expenditures in the U.K. include the drilling of a well at our Centurion prospect, where we

hold a 33.3% interest. The exploration well at Centurion represents a firm well commitment that was originally scheduled by the operator to be drilled in 2012

and has been delayed until 2013.

The U.S. anticipated capital expenditures are primarily discretionary and will be re-evaluated once Rochelle production is on-line and after the completion of

the strategic review process.

Our 2013 anticipated capital expenditures are also subject to change depending on a number of factors, including the result of our strategic review, 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.

Decommissioning Expenditures

Production from each of our Ivanhoe, Rob Roy, Hamish (collectively, “IVRRH”), Renee, Rubie and Goldeneye fields has ceased and we have performed minor

maintenance and decommissioning activities over the last several years. Previously, we expected to re-develop

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our IVRRH, Renee and Rubie fields if commercially attractive and practicable once the development activities at Rochelle are operational. During 2012, we

determined that it was no longer practicable to re-develop these fields. As a result, decommissioning work on the fields will be accelerated and we expect to

incur approximately $36 million in decommissioning charges during 2013.

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 income (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 income (loss), as adjusted” as net income (loss), without the effect of impairments, derivative transactions and currency impacts of deferred taxes.

We define “Adjusted EBITDA” as net income (loss) before interest, taxes, depreciation, depletion and amortization adjusted for the early termination of

commodity derivatives and income (loss) from discontinued operations. 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 income (loss) to these nonGAAP 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 income (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. Net income (loss) as adjusted and Adjusted EBITDA have

limitations as analytical tools, and you should not consider these measures in isolation, or as a substitute for analysis of our financial statement data presented

in the consolidated financial statements as reported under GAAP.

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 Year Ended December 31,

(Amounts in thousands) 2012 2011 2010

Net income (loss)

 $(126,226) $(130,995) $ 56,531

Impairment of oil and gas properties (net of tax) 53,072 65,706 7,692

Unrealized gain on derivatives (net of tax) (7,326) (10,269) (6,820) 

Loss on early extinguishment of debt (net of tax) 17,662 402 — 

Deferred tax expense related to U.K. tax rate change 8,587 25,484

Currency impact on deferred taxes — — (51) 

Net Income (Loss) as Adjusted $ (54,231) $ (49,672) $ 57,352

Net income (loss) $(126,226) $(130,995) $ 56,531

Unrealized gain on derivatives (5,141) (8,378) (12,291) 

Net interest expense 83,872 44,781 34,517

Letter of credit fees 21,903 — — 

Loss on early extinguishment of debt 21,661 402 — 

Depreciation, depletion and amortization 66,564 26,478 28,894

Impairment of oil and gas properties 53,072 65,706 7,692

Income tax expense (benefit) 14,228 27,061 (788) 

Early termination of commodity derivatives — — 10,201

Adjusted EBITDA $ 129,933 $ 25,055 $ 124,756

Since the impairments related to U.S. oil and gas properties, we recognized no tax benefits as there was no assurance that we could generate any U.S.

taxable earnings.

Net of tax (expense) benefit of $(2,185), $(1,891) and $5,471 in 2012, 2011 and 2010, respectively.

Net of tax benefit of $3,899 for 2012.

Disclosures about Contractual Obligations and Commercial Commitments

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

December 31, 2012:

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(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 $ 874,192 $115,163 $ — $ 205,029 $ 554,000

Interest 411,594 88,895 147,810 159,309 15,580

Asset retirement obligations 176,076 36,255 69,497 33,553 36,771

Letter of credit fees 27,734 19,934 7,800 — — 

Leases for offices and equipment 6,101 1,665 2,931 1,505 — 

Total Contractual Obligations $1,495,697 $261,912 $228,038 $399,396 $606,351

Our debt and letter of credit fees reflect the amounts outstanding at December 31, 2012 and reflect the maturity dates in effect at that date. Subsequent to

December 31, 2012, portions of our debt and reimbursement agreements were extended. See Note 24 for additional discussion.

Interest on our 11.5% convertible bonds is added to the outstanding principal balance each quarter and reflected as due upon maturity.

Off-Balance Sheet Arrangements

At December 31, 2012, our reimbursement agreements related to abandonment liabilities were off-balance sheet arrangements. The reimbursement agreements

cover approximately $153 million of our 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. See Note 20 to our consolidated financial statements in “Item 8. Financial Statements and Supplementary Data” for

additional discussion.

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.

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

(1) estimates of proved oil and gas reserves, (2) estimates as to the expected future cash flow from proved oil and gas properties, (3) estimates of future

dismantlement and restoration costs, (4) estimates of fair values used in purchase accounting and (5) estimates of the fair value of derivative instruments. In

addition, alternatives may exist among various accounting methods. In such cases, the choice of accounting method may also have a significant impact on

reported amounts.

Our critical accounting policies are as follows:

Full Cost Accounting

Under the full cost method 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.

Future net cash flows use the average, first-day-of-the-month price for commodities during 2012, 2011 and 2010.

We utilize a single cost center for each country where we have operations for amortization purposes. Any sales or other conveyances of properties are treated as

adjustments to the cost of oil and gas properties with no gain or loss recognized unless the operations are suspended in the entire cost center or the conveyance

is significant in nature.

Unproved property costs include the costs associated with unevaluated properties and properties under development and are not initially included in the full

cost amortization base (where proved reserves exist) until the project is evaluated. These costs include unproved leasehold acreage, seismic data, wells and

production facilities in progress and wells pending determination, together with interest costs capitalized for these projects. Seismic data costs are associated

with specific unevaluated properties where the seismic data is acquired for the purpose of evaluating acreage or trends covered by a leasehold interest owned by

us.

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Significant unproved properties are assessed periodically for possible impairment or reduction in value. If a reduction in value has occurred, these property

costs are considered impaired and are transferred to the related full cost pool. Geological and geophysical costs included in unproved properties are transferred

to the full cost amortization base along with the associated leasehold costs on a specific project basis. Costs associated with wells in progress and wells

pending determination are transferred to the amortization base once a determination is made whether or not proved reserves can be assigned to the property.

Costs of dry holes are transferred to the amortization base immediately upon determination that the well is unsuccessful. Unproved properties whose

acquisition costs are not individually significant are aggregated and the portion of such costs estimated to be ultimately nonproductive, based on experience,

are amortized to the full cost pool over an average holding period.

In countries where the existence of proved reserves has not yet been determined, unevaluated property costs remain capitalized in unproved property cost

centers until proved reserves have been established, exploration activities cease or impairment and reduction in value occurs. If exploration activities result in

the establishment of a proved reserve base, amounts in the unproved property cost center are reclassified as proved properties and become subject to

amortization and the application of the ceiling test. When it is determined that the value of unproved property costs have been permanently diminished (in part

or in whole) based on the impairment evaluation and future exploration plans, the unproved property cost centers related to the area of interest are impaired,

and accumulated costs charged against earnings.

We capitalize interest on expenditures for significant exploration and development projects while activities are in progress to bring the assets to their intended

use. Capitalized interest is calculated by multiplying our weighted-average interest rate on debt by the amount of qualifying costs and is limited to gross interest

expense. As costs are transferred to the full cost pool, the associated capitalized interest is also transferred to the full cost pool.

Business Combinations

Assets and liabilities acquired through a business combination are recorded at estimated fair value. We use all available information to make these fair value

determinations, including information commonly considered by our engineers in valuing individual oil and gas properties and sales prices for similar assets.

Estimated deferred taxes are based on available information concerning the tax basis of the acquired company’s assets and liabilities and carryforwards at the

merger date.

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

the amounts assigned to assets and liabilities over the acquisition of the acquired business is recorded as a gain on acquisition on the income statement. The

amount of goodwill recorded in any particular business combination can vary significantly depending upon the fair values attributed to assets acquired and

liabilities assumed relative to the total acquisition cost.

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Goodwill and Intangible Assets

Goodwill represents the excess of the purchase price over the estimated fair value of the assets acquired and liabilities assumed in an acquisition. 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.

At December 31, 2012, we had $262.8 million of goodwill recorded related to past business combinations. This goodwill is not amortized, but is required to

be assessed for impairment annually, or more often as facts and circumstances warrant. The first step of that process is to compare the fair value of the

reporting unit to which goodwill has been assigned to the carrying amount of the associated net assets and goodwill. The reporting units used to evaluate and

measure goodwill for impairment are determined from the manner in which the business is managed. We have determined we have a single reporting unit.

Goodwill is tested annually at year end. Although we cannot predict when or if goodwill will be impaired, impairment charges may occur if we are unable to

replace the value of our depleting asset base or if other adverse events (for example, lower sustained oil and gas prices) reduce the fair value of the reporting

unit.

We completed our 2012 annual goodwill impairment test with no impairment indicated as the estimated fair value of our reporting unit was substantially

greater than its book value. We considered our market capitalization based on average stock prices for 20 days before December 31, 2012.

A lower fair value estimate in the future could result in impairment. Examples of factors that could cause a lower fair value estimate could be sustained

declines in prices, increases in costs, and changes in discount rate assumptions due to market conditions.

Dismantlement, Restoration and Environmental Costs

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

and natural gas processing plants, with a corresponding increase in the related long-lived asset. The asset retirement cost is depreciated along with the property

and equipment in the full cost pool. The asset retirement obligation is recorded at fair value and accretion expense, recognized over the life of the property,

increases the liability to its expected settlement value. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded for both

the asset retirement obligation and the asset retirement cost.

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Estimating future asset retirement obligations requires us to make estimates and judgments regarding timing, amount and existence of a liability, as well as

what constitutes adequate restoration. We use the present value of estimated cash flows related to our asset retirement obligations to determine fair value. Our

liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, inflation factors, the productive lives of

wells and our risk-adjusted interest rate. In addition, there are other external factors which could significantly affect the ultimate settlement costs for these

obligations including changes in environmental regulations and other statutory requirements, fluctuations in industry costs and advances in technology.

Revenue Recognition

We use the entitlements method to account for sales of gas production. We may receive more or less than our entitled share of production. Under the

entitlements method, if we receive more than our entitled share of production, the imbalance is treated as a liability at the market price at the time the imbalance

occurred. If we receive less than our entitled share, the imbalance is recorded as an asset at the lower of the current market price or the market price at the time

the imbalance occurred. Oil revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred, title

has transferred and collectability of the revenue is probable.

Derivative Instruments and Hedging Activities

From time to time, we may utilize derivative financial instruments to hedge cash flows from operations or to hedge the fair value of financial instruments. We

may use derivative financial instruments with respect to a portion of our oil and gas production or a portion of our variable rate debt to achieve a more

predictable cash flow by reducing our exposure to price fluctuations. These transactions are likely to be swaps, collars or options and to be entered into with

major financial institutions or commodities trading institutions. Derivative financial instruments are intended to reduce our exposure to declines in the market

prices of crude oil and natural gas that we produce and sell, to increases in interest rates and to manage cash flows in support of our annual capital expenditure

budget. We also have embedded derivatives related to our debt instruments and convertible preferred stock.

We record all derivatives at fair market value in our Consolidated Balance Sheets at the end of each period. The accounting for the fair market value, and the

changes from period to period, depends on the intended use of the derivative and the resulting designation. This evaluation is determined at each derivative’s

inception and begins with the decision to account for the derivative as a hedge, if applicable. The accounting for changes in the fair value of a derivative

instrument that is not accounted for as a hedge is included in other (income) expense as an unrealized gain or loss.

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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 nonemployees 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, 2012, we had approximately 2.4 million

additional shares available for issuance pursuant to our existing stock incentive plan.

Fair Value

We estimate fair value for the measurement of derivatives, long-lived assets during certain impairment tests, reporting units for goodwill impairment testing,

the initial measurement of an asset retirement obligation and the initial measurement of our Series C Preferred Stock upon its redemption and modification.

When we are required to measure fair value, and there is not a market observable price for the asset or liability, or a market observable price for a similar asset

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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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Foreign Exchange Risk

The international scope of our business operations exposes us to the risk of fluctuations in foreign currency markets. As a result, we are subject to foreign

currency exchange rate risk due to effects that foreign exchange rate movements have on our costs and on the cash flows that we receive from foreign

operations. Our oil revenues are received in U.S. dollars while gas revenues in the U.K. are received in pounds sterling. Capital expenditures, payroll and

operating expenses may be denominated in U.S. dollars or pounds sterling. We operate a centralized currency management operation to take advantage of

potential opportunities to naturally offset exposures against each other. To date, we have addressed our foreign currency exchange rate risks principally by

maintaining our liquid assets in interest-bearing accounts, until payments in foreign currency are required. 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, 2012, we have exposure to exchange rate changes applicable to cash balances in 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

Our exposure to changes in interest rates is not significant as all of our borrowings are subject to fixed interest rates. Changes in interest rates only affect the

interest earned on cash and cash equivalents.

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Item 8. Financial Statements and Supplementary Data

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders of

Endeavour International Corporation

We have audited the accompanying consolidated balance sheet of Endeavour International Corporation and subsidiaries as of December 31, 2012 and the

related consolidated statements of operations, stockholders’ equity and cash flows for the year then ended. These financial statements are the responsibility of

the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our 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 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 audit

provides 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, 2012 and the consolidated results of their operations and their cash flows for the year then ended, in conformity

with U.S. generally accepted accounting principles.

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, 2012, based on criteria established in Internal Control-Integrated

Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 18, 2013 expressed an

unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ Ernst & Young LLP

Houston, Texas

March 18, 2013

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Endeavour International Corporation:

We have audited the accompanying consolidated balance sheet of Endeavour International Corporation and subsidiaries (the Company) as of December 31,

2011, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the two-year period ended

December 31, 2011. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion

on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that

we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit

includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the

accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that

our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Endeavour International

Corporation and subsidiaries as of December 31, 2011, and the results of their operations and their cash flows for each of the years in the two-year period

ended December 31, 2011, in conformity with U.S. generally accepted accounting principles.

(signed) KPMG LLP

Houston, Texas

March 7, 2012, except for Note 23, as to which date is March 18, 2013

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Consolidated Balance Sheets

(Amounts in thousands)

 December 31,

 2012 2011

Assets 

Current Assets: 

Cash and cash equivalents $ 59,185 $ 106,036

Restricted cash 178 — 

Accounts receivable 46,003 8,649

Prepaid expenses and other current assets 20,995 18,840

Total Current Assets 126,361 133,525

Property and Equipment, Net ($349,433 and $258,334 not subject to amortization at 2012 and 2011, respectively) 1,003,441 549,196

Goodwill 262,764 211,886

Other Assets 49,906 30,384

Total Assets $1,442,472 $924,991

See accompanying notes to consolidated financial statements.

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Consolidated Balance Sheets

(Amounts in thousands)

 December 31,

 2012 2011

Liabilities and Stockholders’ Equity 

Current Liabilities: 

Accounts payable $ 60,153 $ 62,275

Current maturities of debt 15,713 12,350

Accrued expenses and other 90,100 20,549

Total Current Liabilities 165,966 95,174

Long-Term Debt 843,793 455,028

Deferred Taxes 141,887 115,759

Other Liabilities 147,692 61,248

Total Liabilities 1,299,338 727,209

Commitments and Contingencies 

Series C Convertible Preferred Stock: 

Series C preferred stock - Liquidation preference: $37,000 and $37,000 December 31, 2012 and 2011, respectively 43,703 43,703

Stockholders’ Equity: 

Series B preferred stock (Liquidation preference: $3,588 and $3,430 at 2012 and 2011, respectively) — — 

Common stock; shares issued and outstanding (46,691 and 37,663 shares at 2012 and 2011, respectively) 47 38

Additional paid-in capital 493,804 420,412

Treasury stock, at cost (72 and 72 shares at 2012 and 2011, respectively) (587) (587) 

Accumulated deficit (393,833) (265,784) 

Total Stockholders’ Equity 99,431 154,079

Total Liabilities and Stockholders’ Equity $ 1,442,472 $ 924,991

See accompanying notes to consolidated financial statements.

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Consolidated Statement of Operations

(Amounts in thousands, except per share data)

 Year Ended December 31,

 2012 2011 2010

Revenues $ 219,058 $ 60,091 $71,675

Cost of Operations: 

Operating expenses 58,536 17,668 15,347

Depreciation, depletion and amortization 66,564 26,478 28,894

Impairment of oil and gas properties 53,072 65,706 7,692

General and administrative 21,085 17,853 18,415

Total Expenses 199,257 127,705 70,348

Income (Loss) From Operations 19,801 (67,614) 1,327

Other Income (Expense): 

Derivatives: 

Realized gains (losses) — — (11,753) 

Unrealized gains 5,141 8,378 12,291

Interest expense (84,122) (44,893) (34,592) 

Gain on sale of reserves in place — — 87,171

Loss on early extinguishment of debt (21,661) (402) — 

Letter of credit fees (21,903) — — 

Other income (expense) (9,254) 597 1,299

Total Other Income (Expense) (131,799) (36,320) 54,416

Income (Loss) Before Income Taxes (111,998) (103,934) 55,743

Income Tax Expense (Benefit) 14,228 27,061 (788) 

Net Income (Loss) (126,226) (130,995) 56,531

Preferred Stock Dividends: 1,823 1,974 2,227

Net Income (Loss) to Common Stockholders $ (128,049) $(132,969) $ 54,304

Net Income (Loss) per Common Share: 

Basic $ (3.01) $ (3.70) $ 2.34

Diluted $ (3.01) $ (3.70) $ 1.95

Weighted Average Number of Common Shares Outstanding: 

Basic 42,533 35,957 23,252

Diluted 42,533 35,957 28,886

See accompanying notes to consolidated financial statements.

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Consolidated Statement of Cash Flows

(Amounts in thousands)

 Year Ended December 31,

 2012 2011 2010

Cash Flows from Operating Activities: 

Net income (loss) $(126,226) $(130,995) $ 56,531

Adjustments to reconcile net income (loss) to net cash provided by operating activities: 

Depreciation, depletion and amortization 66,564 26,478 28,894

Impairment of oil and gas properties 53,072 65,706 7,692

Deferred tax expense (benefit) (17,594) 21,116 (3,367) 

Unrealized gains on derivatives (5,141) (8,378) (12,291) 

Gain on sales of reserves in place — — (87,171) 

Amortization of non-cash compensation 4,401 3,697 3,692

Amortization of loan costs and discount 14,179 12,234 10,262

Non-cash interest expense 8,684 12,811 8,764

Loss on early extinguishment of debt 21,661 402 — 

Other 15,365 1,518 (2,086) 

Changes in operating assets and liabilities: 

(Increase) decrease in receivables (24,319) (531) 6,732

Increase in other current assets (592) (13,328) (4,668) 

Increase (decrease) in liabilities 28,559 (30,073) 4,035

Net Cash Provided by (Used in) Operating Activities 38,613 (39,343) 17,019

Cash Flows From Investing Activities: 

Capital expenditures (246,925) (165,062) (92,007) 

Acquisitions, net of cash acquired (238,854) (33,075) (43,726) 

Proceeds from sales, net of cash 1,407 — 108,316

(Increase) decrease in restricted cash (178) 31,726 (28,897) 

Net Cash Used in Investing Activities (484,550) (166,411) (56,314) 

Cash Flows From Financing Activities: 

Repayments of borrowings (274,629) (103,225) (75,342) 

Borrowings under debt agreements, net of debt discount 654,023 210,000 185,000

Proceeds from issuance of common stock 60,805 118,444 30,181

Dividends paid (1,665) (1,816) (2,070) 

Payments for early extinguishment of debt (7,248) — — 

Financing costs paid (32,204) (11,401) (26,590) 

Other financing 4 521 9 6

Net Cash Provided by Financing Activities 399,086 212,523 111,275

Net Increase (Decrease) in Cash and Cash Equivalents (46,851) 6,769 71,980

Cash and Cash Equivalents, Beginning of Period 106,036 99,267 27,287

Cash and Cash Equivalents, End of Period $ 59,185 $ 106,036 $ 99,267

See accompanying notes to consolidated financial statements.

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Consolidated Statement of Stockholders’ Equity

(Amounts in thousands)

 Additional Total

 Common Treasury Paid-In Accumulated Stockholder’s

 Stock Stock Capital Deficit Equity

Balance, January 1, 2010 $ 19 $(587) $ 247,820 $(187,119) $ 60,133

Preferred stock dividend — — — (2,227) (2,227) 

Common stock issuance 5 — 30,176 — 30,181

Series C preferred stock conversion 1 — 5,906 — 5,907

Amortization of deferred compensation — — 3,660 — 3,660

Other — — 433 — 433

Net Income — — — 56,531 56,531

Balance, December 31, 2010 $ 25 $(587) $287,995 $ (132,815) $ 154,618

Preferred stock dividend — — — (1,974) (1,974) 

Common stock issuance 12 — 118,433 — 118,445

Series C preferred stock conversion 1 — 9,448 — 9,449

Amortization of deferred compensation — — 3,697 — 3,697

Other — — 839 — 839

Net Loss — — — (130,995) (130,995) 

Balance, December 31, 2011 $ 38 $(587) $ 420,412 $(265,784) $ 154,079

Preferred stock dividend — — — (1,823) (1,823) 

Common stock issuance 9 — 60,796 — 60,805

Issuance of Warrants 6,273 6,273

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

See accompanying notes to consolidated financial statements.

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Notes to Consolidated Financial Statements

(Amounts in tables in thousands, except per unit 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.

2013 Liquidity and Capital Resources

As of December 31, 2012, we had $874.2 million in outstanding indebtedness. Being highly leveraged, servicing our debt and other long-term obligations will

continue to require a significant portion of our cash flow from operations and available cash on hand. The combination of these debt servicing requirements,

capital expenditures and the delay in cash flow resulting from the Rochelle mechanical issues may exceed the cash flow from our current operations.

Ultimately, our primary uses and sources of financial resources will be impacted by the outcome of our strategic review.

During 2013, our primary uses of financial resources are expected to be:

• our capital expenditures, primarily related to our drilling activities at our Alba, Bacchus and Rochelle fields in the U.K.; and

• interest payments on existing credit facilities and payments in support of our reimbursement agreements covering our abandonment obligations.

We believe we will be able to fund operations for the foreseeable future including our capital expenditures and other expenditure requirements based on our

projections of funds generated from operations, cash available and existing sources of financing. Since year-end 2012, we have also completed several

transactions to improve our liquidity position and extended the maturities of some of our debt and other obligations. The completion of these recent financing

activities are designed to provide sufficient liquidity to bring the Rochelle development on line, drill a third well at Bacchus and allow sufficient time for a

thoughtful and disciplined strategic review process. These transactions include:

• extending or replacing reimbursement agreements covering certain of our abandonment liabilities in the U.K. which would have expired in 2013;

• entering into a forward sale agreement;

• entering into a sale and purchase agreement providing for the sale and purchase of a production payment; and

• extending the maturity of a majority of the commitments under our revolving credit facility.

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Notes to Consolidated Financial Statements

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

If we are unable to meet any short-term liquidity needs out of cash on hand, we would attempt to refinance debt, sell forward our production, sell assets, issue

debt or equity or perform any other alternatives resulting from our strategic review.

Note 2 – Summary of Significant Accounting Policies

Basis of Presentation and Use of Estimates

The accompanying financial statements have been prepared on the accrual basis of accounting in accordance with accounting principles generally accepted in

the United States of America (“US GAAP”) and have been presented on a going concern basis, which contemplates the realization of assets and satisfaction of

liabilities in the normal course of business. In the opinion of management, all normal recurring adjustments considered necessary for a fair presentation have

been included in these financial statements. Certain amounts for prior periods have been reclassified to conform to the current presentation.

These accounting principles require management to use estimates, judgments and assumptions that affect the amounts of assets, liabilities, revenues and

expenses reported herein. While management 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.

Principles of Consolidation

The accompanying consolidated financial statements include all of the accounts of Endeavour and our consolidated subsidiaries. All significant intercompany

accounts and transactions have been eliminated. Investments in entities over which we have significant influence, but not control, are carried at cost adjusted

for equity in earnings or (losses) and distributions received.

Cash and Cash Equivalents

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

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Notes to Consolidated Financial Statements

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

Restricted Cash

Restricted cash has historically included amounts held in escrow for drilling rig commitments, as collateral for lines of credit, and for acquisitions.

Inventories

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

Full Cost Accounting for Oil and Gas Operations

Under the full cost method 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

10%, of:

• 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.

Unproved property costs include the costs associated with unevaluated properties and properties under development and are not initially included in the full

cost amortization base (where proved reserves exist) until the project is evaluated. These costs include unproved leasehold acreage, seismic data, wells and

production facilities in progress and wells pending determination, together with interest costs capitalized for these projects. Seismic data costs are associated

with specific unevaluated properties where the seismic data is acquired for the purpose of evaluating acreage or trends covered by a leasehold interest owned by

us.

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Notes to Consolidated Financial Statements

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

Significant unproved properties are assessed periodically for possible impairment or reduction in value. If a reduction in value has occurred, these property

costs are considered impaired and are transferred to the related full cost pool. Geological and geophysical costs included in unproved properties are transferred

to the full cost amortization base along with the associated leasehold costs on a specific project basis. Costs associated with wells in progress and wells

pending determination are transferred to the amortization base once a determination is made whether or not proved reserves can be assigned to the property.

Costs of dry holes are transferred to the amortization base immediately upon determination that the well is unsuccessful. Unproved properties whose

acquisition costs are not individually significant are aggregated and the portion of such costs estimated to be ultimately nonproductive, based on experience,

are amortized to the full cost pool over an average holding period.

In countries where the existence of proved reserves has not yet been determined, unevaluated property costs remain capitalized in unproved property cost

centers until proved reserves have been established, exploration activities cease or impairment and reduction in value occurs. If exploration activities result in

the establishment of a proved reserve base, amounts in the unproved property cost center are reclassified as proved properties and become subject to

amortization and the application of the ceiling test. When it is determined that the value of unproved property costs have been permanently diminished (in part

or in whole) based on the impairment evaluation and future exploration plans, the unproved property cost centers related to the area of interest are impaired,

and accumulated costs charged against earnings.

Other Property and Equipment

Other oil and gas assets, computer equipment and furniture and fixtures are recorded at cost, less accumulated depreciation. The assets are depreciated using

the straight-line method over their estimated useful lives of two to five years.

Capitalized Interest

We capitalize interest on expenditures for significant exploration and development projects while activities are in progress to bring the assets to their intended

use. Capitalized interest is calculated by multiplying our weighted-average interest rate on debt by the amount of qualifying costs and is limited to gross interest

expense.

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.

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Notes to Consolidated Financial Statements

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

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

the amounts assigned to assets and liabilities over the acquisition of the acquired business is recorded as a gain on acquisition on the income statement. The

amount of goodwill recorded in any particular business combination can vary significantly depending upon the fair values attributed to assets acquired and

liabilities assumed relative to the total acquisition cost.

Goodwill and Intangible Assets

We assess the carrying amount of goodwill and other indefinite-lived intangible assets by testing the asset for impairment annually at year-end, or more

frequently if events or changes in circumstances indicate that the asset might be impaired. The impairment test requires allocating goodwill and all other assets

and liabilities to reporting units. The fair value of each reporting unit is determined and compared to the book value of the reporting unit. An impairment loss

is recognized to the extent that the carrying amount exceeds the asset’s fair value.

Dismantlement, Restoration and Environmental Costs

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

and natural gas processing plants, with a corresponding increase in the related long-lived asset. The asset retirement cost is depreciated along with the property

and equipment in the full cost pool. The asset retirement obligation is recorded at fair value and accretion expense, recognized over the life of the property,

increases the liability to its expected settlement value. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded for both

the asset retirement obligation and the asset retirement cost.

Revenue Recognition

We use the entitlements method to account for sales of gas production. We may receive more or less than our entitled share of production. Under the

entitlements method, if we receive more than our entitled share of production, the imbalance is treated as a liability at the market price at the time the imbalance

occurred. If we receive less than our entitled share, the imbalance is recorded as an asset at the lower of the current market price or the market price at the time

the imbalance occurred. Oil revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred, title

has transferred and collectability of the revenue is probable.

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Notes to Consolidated Financial Statements

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

Significant Customers

Our sales in the U.K. are to a limited number of customers, each of which accounted for more than 10% of revenue for the year ended December 31, 2012:

Chevron North Sea Ltd and Shell U.K. Limited. 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.

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, 2012 and 2011, we had no

outstanding derivatives that were accounted for as a hedge.

Where we intend to account for a derivative as a hedge, we document, at its inception, the hedging relationship, the risk management objective and the strategy

for undertaking the hedge. The documentation includes the identification of the hedging instrument, the hedged item or transaction, the nature of the risk being

hedged, and the method that will be used to assess effectiveness of derivative instruments that receive hedge accounting treatment.

Changes in fair value to hedge instruments, to the extent the hedge is effective, are recognized in other comprehensive income until the forecasted transaction

occurs. Hedge effectiveness is assessed at least quarterly based on total changes in the derivative’s fair value. Any ineffective portion of the derivative

instrument’s change in fair value is recognized immediately in other (income) expense.

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Notes to Consolidated Financial Statements

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

We discontinue hedge accounting prospectively when: (1) we determine that the derivative is no longer effective in offsetting changes in the fair value or cash

flows of a hedged item (including hedged items such as firm commitments or forecasted transactions); (2) the derivative expires; (3) it is no longer probable

that the forecasted transaction will occur; (4) a hedged firm commitment no longer meets the definition of a firm commitment; or (5) management determines

that designating the derivative as a hedging instrument is no longer appropriate.

Concentrations of Credit and Market Risk

Financial instruments that potentially subject us to concentrations of credit risk consist principally of cash deposits at financial institutions. At various times

during the year, we may exceed the federally insured limits. To mitigate this risk, we place our cash deposits only with high credit quality institutions.

Management believes the risk of loss is minimal.

Derivative financial instruments that hedge the price of oil and gas, interest rates or currency exposure will be generally executed with major financial or

commodities trading institutions which expose us to market and credit risks, and may at times be concentrated with certain counterparties or groups of

counterparties. Although notional amounts are used to express the volume of these contracts, the amounts potentially subject to credit risk, in the event of nonperformance by the counterparties, are substantially smaller. We review the credit ratings of our counterparties to derivative contracts on a regular basis and to

date we have not experienced any non-performance by any of our various counterparties.

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.

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Notes to Consolidated Financial Statements

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

Income Taxes

We use the liability method of accounting for income taxes under which deferred tax assets and liabilities are recognized for the estimated future tax

consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities, and their respective tax bases.

Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or

settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized as part of the provision for income taxes in the period that includes

the enactment date. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion

of, or all of, the deferred tax assets will not be realized.

Share-Based Payments

We recognize all share-based payments to employees, including grants of employee stock options, based on their fair values. The share-based compensation

cost is measured at the grant date, based on the calculated fair value of the award, and is recognized as general and administrative expense over the employee’s

requisite service period (generally the vesting period of the equity award). We apply the fair value method in accounting for stock option grants using the

Black-Scholes Method.

It is our policy to use authorized but unissued shares of stock when stock options are exercised. At December 31, 2012, we had approximately 2.4 million

additional shares available for issuance pursuant to our existing stock incentive plan.

Adoption of New Accounting Standards

On January 1, 2012, we adopted the following new standards without material effects on our results of operations or financial position:

• Fair Value - An accounting standard on fair value measurements that clarifies the application of existing guidance and disclosure requirements,

changes certain fair value measurement principles and requires additional disclosures about fair value measurements.

• Comprehensive Income - Guidance impacting the presentation of comprehensive income. The guidance eliminates the current option to report

components of other comprehensive income in the statement of changes in equity or in a footnote to the financial statements.

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Notes to Consolidated Financial Statements

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

• Goodwill - Amendment to the previously issued guidance on testing goodwill for impairment. The revised guidance provides entities with an

option of performing a qualitative assessment prior to calculating the fair value of the reporting unit.

Note 3 – Business Combinations

On December 23, 2011, we entered into a Sale and Purchase Agreement (the “Purchase Agreement”), through our wholly owned subsidiary EEUK, with

ConocoPhillips (U.K.) Limited, ConocoPhillips Petroleum Limited and ConocoPhillips (U.K.) Lambda Limited, subsidiaries of ConocoPhillips (collectively,

the “Sellers”), to acquire their interest in three producing U.K. oil fields in the Central North Sea.

On May 31, 2012, we closed the Alba field portion of the acquisition, which consisted of an additional 23.43% interest in the Alba field. 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.

Upon the closing of the Alba Acquisition, the net proceeds from the offering of our 2018 Notes were released from escrow. We used approximately $205

million of the net proceeds from the sale of the Senior Notes due 2018 together with approximately $24 million of borrowings under our Revolving Credit

Facility with Cyan, as administrative agent and the other lenders party thereto, to fund the cash consideration for the acquisition of the Alba field portion of the

COP Acquisition. Additional information on these related financing transactions is discussed in Note 9.

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Notes to Consolidated Financial Statements

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

The acquisition of the additional interest in the Alba field was accounted for using the business combination method. The following summarizes the allocation

of the purchase price for the Alba Acquisition:

Purchase Price $ 255,400

Purchase Price adjustments for estimated after-tax cash flows from the acquired asset

and interest costs from effective date of January 1, 2011 to closing (25,823) 

Total purchase price $229,577

Allocation of purchase price: 

Property and equipment $ 186,801

Goodwill 50,878

Current assets 24,632

Current liabilities (12,815) 

Deferred tax liability (5,818) 

Other long-term liabilities (14,101) 

Total purchase price $229,577

Goodwill was the excess of the consideration transferred over the net assets recognized and represents the future economic benefits arising from assets acquired

that could not be individually identified and separately recognized. The assessments of the fair values of oil and gas properties acquired were based on

projections of expected future net cash flows, discounted to present value.

The following table sets forth unaudited pro forma condensed combined financial and operating data which are presented to give effect to the Alba acquisition

as if it had occurred January 1, 2011. The information does not purport to be indicative of actual results, if any of these transactions had been in effect for the

periods indicated, or future results.

 Year Ended December 31,

 2012 2011

Revenues $291,575 $ 318,476

Net income (loss) to common shareholders $ (95,245) $(131,881) 

Net Income (loss) per share - basic and diluted $ (2.24) $ (3.67) 

Revenues and income from operations associated with the acquired interest in the Alba field for the period from May 31, 2012 through December 31, 2012

were $ 119.7 million and $ 13.7 million, respectively.

After substantial effort and extensions, we and the Sellers were unable to reach the unanimous agreement and consent required to transfer the interests in the

two remaining U.K. oil fields due to failure to agree on certain commercial terms related to the future timing and amount of collateral required to be posted for

future decommissioning costs.

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Notes to Consolidated Financial Statements

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

As a result of the parties being unable to reach agreement to enable the transfers to occur, the Purchase Agreement terminated in accordance with its terms on

December 14, 2012. As previously disclosed, we paid a $10 million deposit in connection with the acquisition of the interests in the two remaining fields,

which ConocoPhillips retained.

Note 4 – Prepaid Expenses and Other Current Assets

Prepaid expenses and other current assets consisted of the following:

 December 31,

 2012 2011

Prepaid well and drilling costs $ 2,843 $ 3,053

Prepaid insurance 3,330 1,346

Inventory 5,127 1,629 

Fair market value of commodity derivatives – current — 1,247

Deposits and other costs related to the Alba Acquisition — 9,064

Deferred tax asset 8,089 — 

Other 1,606 2,501 

 $20,995 $18,840

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Notes to Consolidated Financial Statements

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

Note 5 – Property and Equipment

Property and equipment included the following:

 December 31,

 2012 2011

Oil and gas properties under the full cost method: 

Subject to amortization $ 915,801 $496,667

Not subject to amortization: 

Acquired in 2012 141,837 — 

Acquired in 2011 107,510 138,912

Acquired in 2010 47,148 47,208

Acquired prior to 2010 52,938 72,214

 1,265,234 755,001

Computers, furniture and fixtures 8,863 6,421

Total property and equipment 1,274,097 761,422

Accumulated depreciation, depletion and amortization (270,656) (212,226) 

Net property and equipment $ 1,003,441 $549,196

The costs not subject to amortization include

• values assigned to unproved reserves acquired,

• exploration costs such as drilling costs for projects awaiting approved development plans or the determination of whether or not proved reserves

can be assigned, and

• other seismic and geological and geophysical costs.

These costs are transferred to the amortization base when it is determined whether or not proved reserves can be assigned to such properties. This analysis is

dependent upon well performance, results of infield drilling, approval of development plans, drilling results and development of identified projects and

periodic assessment of reserves. We expect acquisition costs excluded from amortization to be transferred to the amortization base over the next five years due to

a combination of well performance and results of infield drilling relating to currently producing assets and the drilling and development of identified projects

acquired, such as the Rochelle field. We expect exploration costs not subject to amortization to be transferred to the amortization base over the next three years

as development plans are completed and production commences on existing discoveries.

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Notes to Consolidated Financial Statements

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

The following is a summary of our oil and gas properties not subject to amortization as of December 31, 2012:

 Costs Incurred in the Year Ended December 31,

 2012 2011 2010 Prior to 2010 Total

Acquisition costs $ 47,995 $ 48,904 $23,648 $15,176 $135,723

Exploration costs 72,490 54,729 23,500 37,762 188,481

Capitalized interest 21,352 3,877 — — 25,229

Total oil and gas properties not subject to amortization $141,837 $107,510 $47,148 $52,938 $ 349,433

During 2012, 2011 and 2010, we capitalized $17.9 million, $13.3 million and $13.1 million, respectively, in certain directly related employee costs. During

2012, 2011 and 2010, we capitalized $26.9 million, $14.7 million and $3.9 million, respectively, in interest.

During 2012, 2011 and 2010, we recorded $53.1 million, $65.7 million and $7.7 million, respectively, of impairment through the application of the full cost

ceiling test. The 2012 impairment was primarily due to the decline in U.S. oil and gas prices. The 2011 impairment was primarily related to declines in U.S.

gas prices and the impact of our determination that the likely economic returns in the future would not warrant further investment in our test wells in the

Alabama area. Our decision to discontinue activities in that area resulted in the reclassification of related amounts as being evaluated for full cost accounting

purposes.

The impairment during 2010 was also related to our U.S. oil and gas properties, pre-tax, and was primarily due to the declaration of two wells as dry holes

during the first quarter of 2010 – the Alligator Bayou well which was spud in 2008 and a well under a participation agreement.

Assets Acquisitions

United Kingdom

On February 23, 2011, we closed our acquisition of an additional 20% working interest in the Bacchus field for approximately $9.2 million in cash paid at

closing and approximately $6.2 million in cash paid in 2012. In addition, we paid capital costs incurred by the seller of $9.4 million. Following the

acquisition, we hold an aggregate 30% working interest in the Bacchus field.

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Notes to Consolidated Financial Statements

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

Marcellus and Haynesville

During 2010, we entered into a participation agreement with a private oil and gas operator, and acquired interests in certain acreage in North Louisiana/East

Texas and Western Pennsylvania, primarily in the Haynesville and Marcellus areas. Our initial investment was $15 million in cash, and we will pay a share

of that operator’s drilling and completion expenditures as wells are drilled in Haynesville over the next few years. Under this agreement, we also acquired

additional acreage in the Marcellus area for approximately $7.5 million during the second quarter of 2010.

On October 26, 2012, we completed a nonmonetary exchange with our domestic co-venturer whereby we exchanged our Bull Bayou Haynesville and Willow

Springs Cotton Valley properties for all of the co-venturer’s upstream and midstream interests in the Pennsylvania Marcellus area. In parallel, we secured a

third party gas gathering agreement for the Daniel Project in Cameron County, Pennsylvania. We now operate and control the Marcellus assets while retaining a

50% position in our remaining producing Haynesville acreage.

Alabama

During 2010, we also acquired interests in an exploratory gas shale play in Alabama with an initial net investment of approximately $8.0 million. During the

third quarter of 2011, we completed our analysis of our test wells in the Alabama area and determined that the likely economic returns in the future would not

warrant further investment and therefore reclassified these amounts as evaluated for full cost accounting purposes.

Business Combination

On May 31, 2012, we closed the Alba Acquisition, which consisted of an additional 23.43% interest in the Alba field. 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.

Asset Disposition

On October 19, 2010, we completed the Cygnus Sale for $110 million in cash, and recorded a gain of $87 million. The cash proceeds were not burdened by

any current taxes payable and were primarily used to accelerate our development projects.

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Notes to Consolidated Financial Statements

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

Note 6 – 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.

 December 31,

 2012 2011

Balance at beginning of year

 $211,886 $211,886

Additions related to acquisitions 50,878 — 

Balance at end of year $262,764 $211,886

Note 7 – Other Assets

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

 2012 2011

Debt issuance costs $30,599 $23,460

Deferred issuance costs related to reimbursement agreements 11,290 — 

Deposits related to SM Energy litigation 6,000 6,000

Other 2,017 924

 $49,906 $ 30,384

Debt issuance costs and deferred issuance costs related to our reimbursement agreements are amortized over the life of the related obligation. During 2012, we

incurred $32.2 million in debt issuance costs related to the issuance of our 2018 Notes and Revolving Credit Facility. See Note 9 for additional discussion.

As discussed in Note 20, we are in litigation concerning the terminated acquisition of properties from SM Energy. We paid $6.0 million in a deposit upon

executing the acquisition agreement with SM Energy, and SM Energy has retained the deposit, which we believe we are entitled to recover.

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Notes to Consolidated Financial Statements

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

Note 8 – Accrued Expenses

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

 December 31,

 2012 2011

Foreign taxes payable $18,989 $ 445

Accrued interest 25,932 3,186

Preferred dividends 1,617 1,459

Accrued compensation 1,882 4,671

Current portion of asset retirement obligations 36,255 2,078

Development asset accrual — 6,160

Other 5,425 2,550

 $ 90,100 $20,549

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Notes to Consolidated Financial Statements

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

Note 9 – Debt Obligations

Our debt consisted of the following at December 31:

 2012 2011

Senior notes, 12% fixed rate, due 2018 $ 554,000 $ — 

Convertible senior notes, 5.5% fixed rate, due 2016 135,000 135,000

Revolving credit facility, 13% fixed rate, due 2013 115,163 — 

Convertible bonds, 11.5% until March 31, 2014 and 7.5% thereafter, due 2016 70,029 62,523

Senior term loan, 15% fixed rate, due 2013 — 240,349

Subordinated notes, 12% fixed rate, due 2014 — 32,012

 874,192 469,884

Less: debt discount, net of premium (14,686) (2,506) 

Less: current maturities (15,713) (12,350) 

Long-term debt $ 843,793 $455,028

Standby letters of credit outstanding for abandonment liabilities $ — $ 31,724

Principal maturities of debt at December 31, 2012 are as follows:

2013 $ 15,713

2014 99,450

2015 — 

2016 205,029

2017 — 

Thereafter 554,000

Senior Notes

On February 23, 2012, we closed the private placement of $350 million aggregate principal amount of 12% first priority notes due 2018 (the “First Priority

Notes”) and $150 million aggregate principal amount of 12% second priority notes due 2018 (the “Second Priority Notes,” and, together with the First Priority

Notes, the “2018 Notes”). Each series of 2018 Notes issued in February 2012 was priced at 96% of par, at a yield to maturity of 12.975% for the First

Priority Notes and 12.954% for the Second Priority Notes, for an aggregate $20 million discount. We also paid approximately $21 million in other financing

costs related to the 2018 Notes.

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Notes to Consolidated Financial Statements

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

On May 31, 2012, concurrent with the closing of the Alba Acquisition, the net proceeds were used to fund the acquisition and repay all outstanding amounts

under the senior term loan (“Senior Term Loan”) (discussed below).

On October 15, 2012 we completed a private placement of an additional $54 million aggregate principal amount of our First Priority Notes, priced at 109% of

par. In connection with the offering of the First Priority Notes, we received net proceeds of $57.9 million. The new first priority notes and those first priority

notes initially issued in February 2012 are treated as a single class of debt securities under the same indenture. We utilized a portion of the proceeds from the

October 2012 offering to retire the $25 million outstanding under our 12% senior subordinated notes due 2014. We will use the remainder of the net proceeds to

finance a portion of the construction, improvement and other capital costs related to our U.S. and U.K. properties.

Revolving Credit Facility

On April 12, 2012, we entered into a $100 million Revolving Credit Facility, with Cyan, as administrative agent, and borrowed $40 million. The Revolving

Credit Facility matures on October 12, 2013.

Prior to the termination of the Senior Term Loan, the closing of the Alba Acquisition and certain other conditions, borrowings under the Revolving Credit

Facility were limited to $40 million and incurred interest at a rate of 12% per year, with an additional 3% payment-in-kind. After the termination of the Senior

Term Loan and the closing of the Alba Acquisition, borrowings under the Revolving Credit Facility bear interest at a rate of 13% per year.

On May 31, 2012, we entered into a First Amendment to the Revolving Credit Facility, providing for an increase in the amount available for borrowing under

the Revolving Credit Facility from $40 million to $100 million upon closing of the acquisition of the Alba Acquisition. In connection with the closing of the

Alba Acquisition, we drew down the additional $60 million available for borrowing. The First Amendment to the Revolving Credit Facility contained certain

amendments allowing us to enter certain reimbursement agreements discussed in Note 13.

On September 27, 2012, we increased the amount available for borrowing under the Revolving Credit Facility to $125 million. In connection with the

increase, we agreed to pay a fee of $1.25 million to Cyan. On September 28, 2012, we borrowed an additional $15 million under the Revolving Credit

Facility.

Subsequent to December 31, 2012, we amended the Revolving Credit Facility to extend the maturity date of $100 million of the facility to June 30, 2014. See

Note 24 for additional discussion.

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Notes to Consolidated Financial Statements

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

Senior Term Loan

In August 2010, we entered into a credit agreement with Cyan, as administrative agent, and various lenders for the Senior Term Loan, in the aggregate amount

of $150 million, which was subsequently increased to $235 million. We paid $25.4 million in financing costs related to the issuance of the Senior Term

Loan.

On May 31, 2012, we used approximately $255 million of the net proceeds from our offering of the 2018 Notes to repay all amounts outstanding under

Senior Term Loan. This repayment included a prepayment fee of approximately $7 million. Following the repayment the Senior Term Loan was terminated

and all of the liens on the collateral securing our obligations were released.

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 (the “5.5% Convertible Senior

Notes”). Interest on these notes is payable semiannually at a rate of 5.5% per annum. The 5.5% Convertible Senior Notes are convertible into shares of our

common stock at an initial conversion rate of 54.019 shares (equivalent to $18.51 per share) of common stock per $1,000 principal amount of the notes,

subject to certain anti-dilution adjustments. In addition, following certain Make-Whole Fundamental Changes, as defined, we will increase the conversion rate

for a holder who elects to convert its 5.5% Convertible Senior Notes.

The 5.5% Convertible Senior Notes are unsecured but guaranteed by our existing material domestic subsidiaries. We may not redeem the 5.5% Convertible

Senior Notes prior to their maturity. The indenture governing the 5.5% Convertible Senior Notes provides for customary events of default.

If we undergo a “fundamental change” as defined, the holders of the 5.5% Convertible Senior Notes have the right, subject to certain conditions, to redeem the

5.5% Convertible Senior Notes and accrued interest. The 5.5% Convertible Senior Notes may become immediately due upon the occurrence of certain events

of default, as defined.

11.5% Convertible Bonds

In January 2008, we issued 11.5% convertible bonds due 2014 (the “11.5% Convertible Bonds”) for gross proceeds of $40 million pursuant to a private

offering to a sophisticated investor in Norway. The net proceeds from the issuance of the 11.5% Convertible Bonds were used to repay a portion of our

outstanding indebtedness. The 11.5% Convertible Bonds bear interest at a rate of 11.5% per annum, compounded quarterly. Interest is compounded quarterly

and added to the outstanding principal balance each quarter. The bonds are convertible into shares of our

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Notes to Consolidated Financial Statements

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

common stock at a conversion price of $16.52 per $1,000 of principal, which represents a conversion rate of approximately 61 shares of our common stock

per $1,000 of principal. The conversion price will be adjusted in accordance with the terms of the bonds upon occurrence of certain events, including payment

of common stock dividends, common stock splits or issuance of common stock at a price below the then current market price.

If we undergo a “change of control” as defined, the holders of the bonds have the right, subject to certain conditions, to redeem the bonds and accrued interest.

The bonds may become immediately due upon the occurrence of certain events of default, as defined.

Two derivatives are associated with the conversion and change in control features of the 11.5% Convertible Bonds. At December 31, 2012, the combined fair

market value of these derivatives is $4.4 million, reflecting a $9.4 million decrease during 2012 that was recorded in unrealized gains (losses) on derivatives.

On March 11, 2011, we entered into an amendment to the Trust Deed related to our 11.5% Convertible Bonds. The amendment provided for:

• the amendment of the maturity date of the 11.5% Convertible Bonds from January 24, 2014 to January 24, 2016;

• the amendment of the date upon which the holders of the 11.5% Convertible Bonds may first exercise a put right, and the occurrence of the

conversion price reset if such put right is not exercised, from January 24, 2012 to January 24, 2016; and

• a reduction in the interest rate payable from 11.5% to 7.5% on and after March 31, 2014.

We recorded a loss of $0.8 million in other expenses related to this amendment, representing the difference between the fair value of the debt and the book value

of the debt at March 11, 2011.

Subordinated Notes

Our Subordinated Notes bear interest at an annual rate of 10%, plus 2% capitalized to the outstanding principal amount. We utilized a portion of the proceeds

from our October 2012 offering of additional First Priority Notes due 2018 to redeem, repurchase, or otherwise retire our outstanding 12% senior subordinated

notes.

Fair Value

The fair value of our outstanding debt obligations was $869.5 million and $419.8 million at December 31, 2012 and 2011, 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.

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Notes to Consolidated Financial Statements

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

Letter of Credit Agreement

In July 2011, we entered into a letter of credit facility agreement with Commonwealth Bank of Australia (“CBA”), pursuant to which CBA issued letters of

credit to us in the amount of £20.6 million (approximately $35 million upon issuance). The letters of credit secured decommissioning obligations in

connection with certain of our United Kingdom Continental Shelf Petroleum Production Licenses. Concurrent with the issuance of the letters of credit, prior

restrictions on £20.6 million of our restricted cash were removed and the cash returned for general corporate purposes. We terminated this letter of credit

facility agreement in May 2012.

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Endeavour International Corporation

Notes to Consolidated Financial Statements

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

Note 10 – Income Taxes

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

follows:

(Amounts in thousands) U.K. U.S. Other Total

Year Ended December 31, 2012: 

Net income (loss) before taxes $(22,959) $ (91,383) $ 2,344 $(111,998) 

Current tax expense 31,796 — 26 31,822

Deferred tax expense related to U.K. tax rate change 8,587 — — 8,587

Deferred tax benefit (26,181) — — (26,181) 

Total tax expense 14,202 — 26 14,228

Net income (loss) after taxes $ (37,161) $ (91,383) $ 2,318 $(126,226) 

Year Ended December 31, 2011: 

Net income (loss) before taxes $ (9,806) $(99,409) $ 5,281 $ (103,934) 

Current tax expense 5,926 4 15 5,945

Deferred tax expense related to U.K. tax rate change 25,424 — — 25,424

Deferred tax benefit (4,308) — — (4,308) 

Total tax expense 27,042 4 15 27,061

Net income (loss) after taxes $ (36,848) $(99,413) $5,266 $(130,995) 

Year Ended December 31, 2010: 

Net income (loss) before taxes $ 90,160 $ (30,978) $ (3,439) $ 55,743

Current tax (benefit) expense 2,734 (154) 2,580

Deferred tax (benefit) expense (2,388) (929) (3,317) 

Foreign currency losses on deferred tax liabilities — — (51) (51) 

Total tax (benefit) expense 346 — (1,134) (788) 

Net income (loss) after taxes $ 89,814 $ (30,978) $(2,305) $ 56,531

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Endeavour International Corporation

Notes to Consolidated Financial Statements

(Amounts in tables in thousands, except per unit 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,

 2012 2011 2010

Federal income tax expense (benefit) at statutory rate $(39,199) $(36,378) $19,500

Effect of out-of-period adjustment 6,997 — — 

Taxation of foreign operations 5,859 3,254 (579) 

Tax-free gain on sale of reserves in place — — (30,510) 

Change in valuation allowance – U.S. 30,329 24,604 (2,252) 

U.K. Tax increase from tax law and rate changes 8,587 25,424 — 

Foreign currency (gain) loss on deferred taxes — — (50) 

Deemed foreign dividend of wholly owned subsidiaries — 8,572 11,466

Disallowed executive compensation 1,655 1,585 765

Other — — 872

Total Income Tax Expense $ 14,228 $ 27,061 $ (788) 

Effective Income Tax Rate -13% -26% -1% 

During 2012, 2011 and 2010, we incurred taxes primarily related to our operations in the U.K. In 2012, 2011 and 2010, we had a loss before taxes of $91.4

million, $99.4 million and $31.0 million, respectively, in the U.S. and we did not record any income tax benefits on these losses as there was no assurance

that we could generate any future U.S. taxable earnings. As a result, we recorded a valuation allowance on the full amount of all deferred tax assets generated in

the U.S.

Deferred 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. The tax effects of temporary differences that give rise to significant portions of

deferred tax assets and liabilities are as follows at December 31:

9 9
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Endeavour International Corporation

Notes to Consolidated Financial Statements

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

 2012 2011

Deferred tax asset: 

Deferred compensation $ 2,268 $ 5,859

Unrealized loss on commodity derivative instruments — 1,260

Asset retirement obligation 87,787 29,122

Net operating loss and capital loss carryforward 334,121 157,570

Unrealized loss on embedded derivative instruments 1,084 4,005

Property, plant and equipment 19,596 12,427

Inventory / other 8,089 — 

Total deferred tax assets 452,945 210,243

Less valuation allowance (84,691) (58,532) 

Total deferred tax assets after valuation allowance 368,254 151,711

Deferred tax liability: 

Property, plant and equipment (478,719) (258,779) 

Petroleum revenue tax, net of tax benefit (22,703) (229) 

Debt discount (630) (752) 

Other — (7,710) 

Total deferred tax liabilities (502,052) (267,470) 

Net deferred tax liability $(133,798) $(115,759) 

Tax Attributes

At December 31, 2012, we had the following tax attributes available to reduce future income taxes:

 As of December 31,

 2012 2011

 

Types of

Tax

Attributes 

Years of

Expiration 

Carryforward

Amount 

Years of

Expiration 

Carryforward

Amount

U.K. 

Corporate tax NOL Indefinite $500,789 Indefinite $ 228,701

Supplemental Corporate tax NOL Indefinite 378,602 Indefinite 159,316

U.S. 

Corporate Income tax NOL 2023 - 2032 177,206 2023 - 2031 106,535

Capital gains tax Capital loss 2015 1,848 2015 1,848

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Endeavour International Corporation

Notes to Consolidated Financial Statements

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

As of December 31, 2012, the U.K. tax attributes shown above have been recognized for financial statement reporting purposes to reduce deferred tax liability.

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

$84.7 million and $58.5 million as of December 31, 2012 and 2011, respectively, primarily related to our U.S. operations. 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. During 2011, the valuation

allowance in the U.S. increased $24.6 million due to net operating losses and decreased $3.9 million in other jurisdictions. During 2010, the valuation

allowance in the U.S. decreased $2.2 million due to net revisions of the net operating loss and increased $1.3 million for net operating losses in other

jurisdictions.

For U.S. federal income tax purposes, certain limitations are imposed on an entity’s ability to utilize its net operating losses (“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, 2012, we have an unrecognized tax benefit of $6.8 million relating to various U.K. tax matters. Any interest and penalties that may be

incurred as part of this liability would be recognized as a component of interest expense and other expense, respectively. As of December 31, 2012, no interest

or penalty expense had been incurred.

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Endeavour International Corporation

Notes to Consolidated Financial Statements

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

The following represents a reconciliation of the change in our unrecognized tax benefits, for the year ended December 31, 2012.

 

Year Ended

December 31,

 2012 2011 2010

Balance at the beginning of the year

 $ — $— $— 

Increase in unrecognized tax benefits from current period tax position 6,820 — — 

Balance at the end of the year $6,820 $— $— 

As of December 31, 2012, we believe that no current tax positions that have resulted in unrecognized tax benefits will significantly increase or decrease within

the next year. If recognized, none of the unrecognized tax benefits would have an impact on our effective tax rate.

The following tax years remain subject to examination:

Tax Jurisdiction 

U.K. 2011

All others 2009 - 2011

Foreign Earnings and Credits

As of December 31, 2012, 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.

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Endeavour International Corporation

Notes to Consolidated Financial Statements

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

Note 11 – Other Liabilities

Other liabilities included the following:

 December 31,

 2012 2011

Asset retirement obligations $139,821 $ 45,180

Long-term derivative liabilities 7,402 16,067

Other 469 1

Total Other Liabilities $147,692 $61,248

Our asset retirement obligations relate to obligation of the plugging and abandonment of oil and gas properties. The asset retirement obligation is recorded at fair

value and accretion expense, recognized over the life of the property, increases the liability to its expected settlement value. If the fair value of the estimated asset

retirement obligation changes, an adjustment is recorded for both the asset retirement obligation and the asset retirement cost. The following table provides a

rollforward of the asset retirement obligations for the year ended December 31, 2012 and 2011:

 

Year Ended

December 31,

 2012 2011

Carrying amount of asset retirement obligations, as of beginning of period $ 47,258 $ 42,997

Increase due to revised estimates 102,447 14,609

Accretion expense (included in DD&A expense) 7,542 4,478

Impact of foreign currency exchange rate changes 3,019 430

Payment of asset retirement obligations (8,521) (15,256) 

Liabilities incurred and assumed 24,331 — 

Carrying amount of asset retirement obligations, as of end of year 176,076 47,258

Less: current portion of asset retirement obligations (36,255) (2,078) 

Long-term asset retirement obligations $139,821 $ 45,180

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Endeavour International Corporation

Notes to Consolidated Financial Statements

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

Note 12 – Equity

The activity in shares of our common and preferred stock during 2012, 2011 and 2010 included the following:

 Year Ended December 31,

 2012 2011 2010

Common Stock: 

Outstanding at the beginning of the year 37,663 24,784 18,803

Issuance of common stock 8,625 11,531 4,638

Exercise of stock options — 93 23

Conversion of preferred stock — 914 572

Issuance of stock based compensation 403 341 748

Outstanding at the end of the year 46,691 37,663 24,784

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 45 50

Conversion to common stock — (8) (5) 

Outstanding at the end of the year 37 37 45

Treasury Stock: 

Outstanding at the beginning of the year (72) (72) (72) 

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 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 $61.3 million.

In May 2012, we entered into warrant agreements (the “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 Warrant Agreements were entered into in connection with the May 31,

2012 reimbursement agreement (see Note 19 for additional discussion of this reimbursement agreement). The terms of each of the Warrant Agreements 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.

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Endeavour International Corporation

Notes to Consolidated Financial Statements

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

The Warrant Agreements include a cashless exercise provision entitling each investor 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 addition, any in-the-money warrants still outstanding at the expiration

date are subject to an automatic cashless exercise.

In March 2011, we completed an underwritten public offering of 11.5 million shares of common stock at a price of $11.00 per common share ($10.34 per

common share, net of underwriting discounts) for net proceeds of $118.4 million. In April 2011, we used a portion of the offering proceeds to redeem all

$81.25 million of our outstanding 6% senior notes.

In October 2010, our Board of Directors authorized a one-for-seven share consolidation of our common stock, in the form of a reverse stock split. This

consolidation was effective at the opening of trading on November 18, 2010. As a result of the share consolidation, every seven shares of our common stock

outstanding were automatically combined into one share of our common stock. Each shareholder continues to hold the same percentage of our outstanding

common shares. The shares were rounded up to the next whole share for those holders who would have otherwise received fractional shares. The share

consolidation was intended to make our common stock available to a broader range of investors and reposition the company’s trading metrics.

In August 2010, in connection with the issuance of the Senior Term Loan, we completed a registered direct offering to Cyan of 1.3 million shares of our

common stock for aggregate net cash consideration of approximately $10.1 million, after deducting expenses. The purchase price per share was $7.91, the

closing price of our common stock on the NYSE Amex on August 13, 2010. The net proceeds from this offering were used for general corporate purposes.

In February 2010, we completed a private placement of 3.4 million shares of our common stock to certain existing stockholders, certain directors and other

third-party investors, for aggregate net cash consideration of approximately $20.5 million. The purchase price per share was $6.30, the closing price of our

common stock on February 3, 2010. The net proceeds from this private placement were used to partially fund our 2010 capital budget.

Series C Convertible Preferred Stock

We have 37,000 shares of Series C convertible preferred stock (the “Series C Preferred Stock”) outstanding, convertible into 4.2 million shares of common

stock. The Series C Preferred Stock is convertible into common stock at any time at the option of the holders. 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;

• 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.

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Endeavour International Corporation

Notes to Consolidated Financial Statements

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

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

In November 2009, we redeemed 60% of the outstanding shares of Series C Preferred Stock, which required the modified Series C Preferred Stock to be

recorded at fair market value at the redemption date. The fair value of the modified Series C Preferred Stock was greater than the carrying value by $11.5

million. This excess of fair value over carrying value was recorded as a non-cash charge to preferred stock dividends and increased the carrying value of the

Series C Preferred Stock. As holders convert the Series C Preferred Stock, the $11.5 million non-cash charge will be transferred to equity on a ratio of shares

converted to shares of Series C Preferred Stock outstanding.

We have an embedded derivative associated with the change in control features of the Series C Preferred Stock. This embedded derivative is recorded in other

liabilities.

The Series C Preferred Stock is convertible into common stock at any time at the option of the preferred stock investors, at (i) a conversion price of $8.75 and

(ii) in an amount of common stock equal to the quotient of the liquidation preference of $1,000 per share plus accrued but unpaid dividends (the “Liquidation

Preference”) divided by the conversion price.

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 resaleable 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.

We may redeem all of the Series C Preferred Stock in exchange for a cash payment to the preferred stock investors of an amount equal to 102% of the sum of

the Liquidation Preference. If we call the Series C Preferred Stock for redemption, the holders thereof will have the right to convert their shares into a newly

issued preferred stock identical in all respects to the Series C Preferred Stock except that such newly issued preferred stock will not bear a dividend (the

“Alternate Preferred Stock”). We may not redeem the Series C Preferred Stock if the Equity Conditions are not then satisfied with respect to the common stock

into which the Alternate Preferred Stock is convertible.

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Endeavour International Corporation

Notes to Consolidated Financial Statements

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

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.

In January 2010, we and the holders of our outstanding Series C Preferred Stock corrected a technical oversight in the Subscription and Registration Rights

Agreement for our Series C Preferred Stock. The amendment aligns the number of common shares reserved for the potential conversion of the Series C

Preferred Stock to the terms of the Series C Preferred Stock after our partial redemption in November 2009. In March 2010, we also amended the Certificate of

Designation for the Series C Preferred Stock and the $50 million subordinated notes issued to the holders of the Series C Preferred Stock to make certain

technical changes that align certain definitions and provisions relating to potential repurchases of securities by us.

During 2011, holders of a portion of our Series C Preferred Stock converted 8,000 preferred shares, with a face value of $8 million, into 0.9 million shares of

our common stock. In 2010, a combined 5,000 shares of our Series C Preferred Stock were converted into 0.6 million shares of our common stock.

Series B Preferred Stock

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

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Endeavour International Corporation

Notes to Consolidated Financial Statements

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

Note 13 – 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, 2012, total compensation cost related to nonvested awards not yet recognized was approximately $7.7 million and is expected to be recognized

over a weighted average period of less than three years. For the year ended December 31, 2012, we included approximately $1.6 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 did not grant any options during 2012,

2011 and 2010. 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

Currently exercisable - December 31, 2012 188 $ 6.72 5.5 $ 85

Of options granted prior to 2009, 0.2 million options were granted pursuant to incentive plans which have been approved by our stockholders. All other stock

options have been granted pursuant to stock option plans that were not subject to stockholder approval.

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Endeavour International Corporation

Notes to Consolidated Financial Statements

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

Information relating to stock options outstanding at December 31, 2012 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 61 6.0 $ 3.78 61 $ 3.78

$5.00 - $8.00 36 5.8 5.25 36 5.25

Greater than $8.00 91 5.0 9.23 91 9.23

Total 188 5.5 $6.72 188 $6.72

Restricted Stock

At December 31, 2012, our employees and directors held 0.8 million restricted shares of our common stock that vest over the service period of up to three

years. The restricted stock awards were valued based on the closing price of our common stock on the measurement date, typically the date of grant, and

compensation expense is recorded on a straight-line basis over the restricted share vesting period.

Status of the restricted shares as of December 31, 2012 and the changes during the year ended December 31, 2012 are presented below:

 Weighted

 Average Grant

 Date Fair

 Number of Value per

 Shares Share

Balance outstanding - January 1, 2012 830 $ 10.13

Granted 458 9.09

Vested (452) 9.28

Forfeited (82) 10.34

Balance outstanding - December 31, 2012 754 $ 10.11

Total grant date fair value of shares vesting during the period $ 4,199

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Endeavour International Corporation

Notes to Consolidated Financial Statements

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

Non-Cash stock-based compensation is recorded in G&A expenses or capitalized G&A as follows:

 

Year Ended

December 31,

 2012 2011 2010

G&A Expenses $ 4,641 $2,988 $3,191

Capitalized G&A 1,634 1,051 988

Total non-cash stock-based compensation $6,275 $ 4,039 $4,179

Performance-Based Share Awards

In January 2012, certain of our executive officers were granted 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, 2012 and the changes during the year ended December 31, 2012 are presented below:

 Weighted

 Average Grant

 Date Fair

 Number of Value per

 Shares Share

Granted 422 16.72

Forfeited (65) 16.72

Balance outstanding - December 31, 2012 357 $ 16.72

Note 14 – Earnings per Share

Basic income (loss) per common share is computed by dividing net income (loss) to common stockholders by the weighted average number of common shares

outstanding for the period. Diluted income (loss) per share includes the effect of our outstanding stock options, warrants and shares issuable pursuant to

convertible debt, convertible preferred stock and certain stock incentive plans under the treasury stock method, if including such instruments is dilutive.

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Endeavour International Corporation

Notes to Consolidated Financial Statements

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

 Year Ended December 31,

 2012 2011 2010

Net income (loss) to common shareholders 

Basic $(128,049) $(132,969) $ 54,304

Add Effect of: 

Preferred dividends — — 2,070

Diluted $(128,049) $(132,969) $56,374

Weighted Average Number of Common Shares Outstanding: 

Basic 42,533 35,957 23,252

Add Effect of: 

Stock compensation grants and warrants — — 380

Preferred stock — — 5,254

Diluted 42,533 35,957 28,886

For each of the periods presented, shares associated with stock options, warrants, convertible debt, convertible preferred stock and certain stock incentive

plans are not included when their inclusion would be antidilutive (i.e., reduce the net loss per share). The common shares potentially issuable arising from

these instruments excluded from weighted average diluted shares outstanding consisted of:

 For the Year Ended December 31,

 2012 2011 2010

Options, warrants and stock-based compensation 2,111 111 — 

Convertible debt 11,532 11,078 5,691

Convertible preferred stock 4,229 4,229 — 

Common shares potentially issuable 17,872 15,418 5,691

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Endeavour International Corporation

Notes to Consolidated Financial Statements

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

Note 15 – Supplementary Cash Flow Disclosures

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

 Year Ended December 31,

 2012 2011 2010

Interest paid $66,365 $31,928 $18,668

Income taxes paid (refunded) $ 426 $ 9,427 $ (172) 

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.

As discussed in Note 12, in 2011, a combined 8,000 shares of our Series C Preferred Stock were converted into 0.9 million shares of our common stock.

In 2012, 2011 and 2010, we recorded $8.7 million, $12.8 million and $8.8 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.

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Endeavour International Corporation

Notes to Consolidated Financial Statements

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

Note 16 – Financial Instruments

 

December

31, 2012 

December

31, 2011

 Fair Value 

Carrying

Value Fair Value 

Carrying

Value

Assets: 

Derivative instruments $ — $ — $ 1,247 $ 1,247

Liabilities: 

Debt 869,488 859,506 419,847 467,378

Derivative instruments 7,402 7,402 16,067 16,067

The carrying amounts reflected in the consolidated balance sheets for cash and equivalents, short-term receivables and short-term payables approximate their

fair value due to the short maturity of the instruments. The fair values of commodity derivative instruments and interest rate swaps were determined based

upon quotes obtained from brokers. The fair values of long-term debt were determined based upon quotes obtained from brokers for our senior notes and

discounted cash flows for our other debt.

Note 17 – 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. In connection with the increase, 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 18 – Fair Value Measurements

We measure the fair value of financial assets and liabilities on a recurring basis, defining fair value as the price that would be received to sell an asset or paid

to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value is based on assumptions that market

participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to

valuations. This includes not only the credit standing of counterparties involved and the impact of credit enhancements but also the impact of our own

nonperformance risk on our liabilities. Fair value measurements are classified and disclosed in one of the following categories:

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Endeavour International Corporation

Notes to Consolidated Financial Statements

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

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. The following table

summarizes the valuation of our investments and financial instruments by pricing levels as of December 31, 2012:

 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, 2012: 

Embedded derivatives $ — $ — $ (7,402) $ (7,402) 

Total derivative liabilities $ — $ — $ (7,402) $ (7,402) 

As of December 31, 2011: 

Oil and gas derivative contracts: 

Oil and gas puts $ — $ 1,038 $ 209 1,247

Embedded derivatives — — (16,067) (16,067) 

Total derivative liabilities $ — $ 1,038 $ (15,858) $ (14,820) 

Our commodity derivative contracts have been measured using models that consider various inputs including current market and contractual prices for the

underlying instruments, quoted forward prices for natural gas and crude oil, volatility factors and interest rates, such as a LIBOR curve for a similar length

of time as the derivative contract term. The inputs for the fair value models for our oil puts, which terminated as of December 31, 2012, were all observable

market data and those instruments were classified as Level 2. Although we utilized the same option

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

pricing models to assess the fair values of our gas puts, an active futures market did not exist for our U.K. gas derivatives, which also terminated as of

December 31, 2012. We based the inputs to the option models for our U.K. gas derivatives on observable market data in other markets to verify the

reasonableness of the counterparty quotes. These U.K. gas derivatives were classified as Level 3.

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. At December 31, 2012, a decrease or increase in the implied credit spread of 5% would increase or decrease, respectively, the liability by approximately

$0.9 million. A similar 5% decrease or increase in the stock volatility has an inverse effect to the change in the liability and would result in an approximately

$0.6 million decrease or increase, respectively.

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

 Year Ended

 December 31,

 2012 2011

Balance at beginning of period $(15,858) $ (26,703) 

Total gains or losses (realized/unrealized) 

Included in earnings 8,456 11,428

Purchases — 1,239

Settlements — (1,822) 

Balance at end of period $ (7,402) $(15,858) 

Changes in unrealized gains (losses) relating to derivatives assets and liabilities still

held at the end of the period $ 8,665 $ 11,428

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.

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

When we are required to measure fair value, and there is not a market observable price for the asset or liability, or a market observable price for a similar asset

or liability, we generally utilize an income valuation approach. This approach utilizes management’s best assumptions regarding expectations of projected cash

flows, and discounts the expected cash flows using a commensurate risk adjusted discount rate. Such evaluations involve a significant amount of judgment

since the results are based on expected future events or conditions, such as sales prices; estimates of future oil and gas production; development and operating

costs and the timing thereof; economic and regulatory climates and other factors. Our estimates of future net cash flows are inherently imprecise because they

reflect management’s expectation of future conditions that are often outside of management’s control. However, assumptions used reflect a market participant’s

view of long-term prices, costs and other factors, and are consistent with assumptions used in our business plans and investment decisions.

Note 19 – Derivative Instruments

We had embedded derivatives related to debt instruments at December 31, 2012 and 2011. The fair market value of these derivative instruments is included in

our balance sheet as follows:

 December 31,

 2012 2011

Derivatives not designated as hedges: 

Oil and gas commodity derivatives: 

Prepaid expenses and other current assets $ — $ 1,247

Embedded derivatives related to debt instrument: 

Other liabilities - long-term (7,402) (16,067) 

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

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

 Year Ended December 31,

 2012 2011 2010

Derivatives not designated as hedges: 

Oil and gas commodity derivatives: 

Realized gains (losses) $ — $ — $(11,753) 

Unrealized gains (losses) (3,524) (3,050) 10,943

 (3,524) (3,050) (810) 

Embedded derivatives related to debt and equity instruments: 

Unrealized gains $8,665 $11,428 $ 1,348

Note 20 – Commitments and Contingencies

General

The oil and gas industry is subject to regulation by federal, state and local authorities. In particular, oil and gas production operations and economics are

affected by environmental protection statutes, tax statutes and other laws and regulations relating to the petroleum industry. We believe we are in compliance

with all federal, state and local laws, regulations applicable to Endeavour and its properties and operations, the violation of which would have a material

adverse effect on us or our financial condition.

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, exceeded the contractual threshold of 15% of

the purchase price for the applicable asset group ($85 million); and (ii) the condition of the pipeline was not in compliance with applicable regulatory

standards, which would constitute a material violation of a representation and warranty contained in the applicable SM Purchase Agreement.

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. Specifically, SM Energy has alleged, among other things, that most of our asserted title defects are without merit

and, in any event, would not exceed 15% of the applicable purchase price. SM Energy seeks the award of unspecified actual damages, including costs and

reasonable attorney’s fees, and specific performance. On January 17, 2012, we filed an answer

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

and counterclaim denying the allegations and seeking the return of our $6 million deposit, which we believe we are entitled to recover pursuant to the terms of

the SM Purchase Agreements, and for the damages that we suffered as a result of SM Energy’s misrepresentations. Discovery is proceeding. We intend to

contest the case vigorously.

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, covering approximately $33 million relates to our decommissioning obligations at the IVRRH, Renee and Rubie fields

where we are currently paying certain asset retirement costs (the “IVRRH Reimbursement Agreement”). We pay a fee of 11.5% per year, computed based on the

outstanding amount of each letter of credit (capitalized quarterly and payable upon release of the letters of credit). We are also required to pay a fee equal to 1%

of the outstanding letters of credit on May 22, 2013 (the expiration date of the letters of credit). If we have not obtained replacement letters of credit before the

expiration date of the letters of credit, then we must reimburse the pledgor for all amounts pledged. Concurrent with the issuance of the IVRRH Reimbursement

Agreement, the restrictions on our previously restricted cash were removed, the cash was returned to us, and our letter of credit facility agreement was

extinguished. We unconditionally guarantee the obligations under the IVRRH Reimbursement Agreement, but our reimbursement obligations are unsecured. In

connection with this reimbursement agreement, we issued warrants to purchase two million shares of our common stock, with an exercise price of $10.50 per

share, to the investors.

On January 10, 2013, we entered into a letter of credit procurement agreement (the “LOC Procurement Agreement”). (See Note 24 “Subsequent Events” for

additional discussion.) In connection with the LOC Procurement Agreement, we terminated the IVRRH Reimbursement Agreement and paid all outstanding and

accrued fees totaling approximately $3.8 million.

The second reimbursement agreement covers approximately $120 million related to our decommissioning obligations for the Alba field (the “Alba

Reimbursement Agreement). We pay a fee of 13% per year, payable quarterly, computed based on the outstanding amount of each letter of credit. We have

agreed to procure the release of the pledged cash securing the letter of credit on or before December 31, 2013 (the expiration date of the letter of credit). In

addition,

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

our obligations under the Alba Reimbursement Agreement are 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, 2012, 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 performance and life of the reservoir.

Rig Commitments

We have previously disclosed a potential commitment on a drilling rig in our North Sea operations relating to a dispute with the rig operator. In June 2011, we

entered into a settlement agreement with the rig operator whereby the parties were mutually released from all future claims. We incurred costs of $14 million

related to the settlement, which are included in capital expenditures.

Operating Leases

At December 31, 2012, we have leases for office space and equipment with lease payments as follows:

2013 $1,665

2014 1,457

2015 1,474

2016 1,250

2017 255

Thereafter — 

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Note 21 – Segment and Geographic Information

We have determined we have one reportable operating segment being the acquisition, exploration and development of oil and gas properties. Our operations are

conducted in geographic areas as follows:

 2012 2011 2010

 Revenue 

Long-lived

Assets Revenue 

Long-lived

Assets Revenue 

Long-lived

Assets

United States $ 11,877 $ 123,977 $ 18,337 $ 139,236 $ 11,174 $115,114

United Kingdom 207,181 1,189,870 41,754 650,943 60,501 486,467

Other — 2,264 — 1,287 — 877

Total $219,058 $1,316,111 $60,091 $791,466 $71,675 $602,458

Total International $ 207,181 $1,192,134 $41,754 $ 652,230 $ 60,501 $ 487,344

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Note 22 – Quarterly Financial Data (Unaudited)

 

First

Quarter

Second

Quarter

Third

Quarter

Fourth

Quarter

 2012 (1) (3)

Revenues $15,165 $ 23,003 $ 83,275 $97,615

Operating expenses 33,866 41,359 64,175 59,857

Operating profit (loss) (18,701) (18,356) 19,100 37,758

Net loss to common stockholders (35,718) (51,264) (34,158) (6,910) 

Net loss per common share - basic and diluted (0.94) (1.31) (0.73) (0.15) 

 2011 (2)

Revenues $ 14,104 $ 19,053 $ 10,302 $ 16,632

Operating expenses 16,077 18,304 42,524 50,800

Operating profit (loss) (1,973) 749 (32,222) (34,168) 

Net loss to common stockholders (8,002) (16,110) (63,756) (45,101) 

Net loss per common share - basic and diluted (0.30) (0.42) (1.63) (1.15) 

(1) Includes impairments of oil and gas properties of $15.7 million, $20.0 million, $11.4 million, and $6.0 million for the first, second, third and fourth

quarters of 2012, respectively.

(2) Includes impairments of oil and gas properties of $28.8 million and $36.9 million, for the third and fourth quarters of 2011, respectively.

(3) Includes $7.0 million in the fourth quarter of 2012 related to the correction of an error in deferred income taxes in prior periods that was not material to

the current year operations.

Note 23 – 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.

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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 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.

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Condensed consolidating financial statements for our guarantor subsidiaries and non-guarantor subsidiaries are presented in the following tables:

As of December 31, 2012

 

Endeavour

International

Corporation 

Combined

Guarantor

Subsidiaries

Combined NonGuarantor

Subsidiaries Eliminations Consolidated

Cash and cash equivalents $ — $ 27,800 $ 31,385 $ — $ 59,185

Restricted cash — 50 128 — 178

Accounts receivable — 2,645 43,358 — 46,003

Current receivables due from affiliates 950,210 36,725 71,964 (1,058,899) — 

Prepaid expenses and other — 508 20,487 — 20,995

Current Assets 950,210 67,728 167,322 (1,058,899) 126,361

Property, plant and equipment, net — 92,692 910,749 — 1,003,441

Goodwill — — 262,764 — 262,764

Long-term receivables due from affiliates — 599,000 — (599,000) — 

Investments in subsidiaries 57,662 120,058 — (177,720) — 

Other assets 25,200 6,085 18,621 — 49,906

Total Assets $1,033,072 $885,563 $1,359,456 $ (1,835,619) $ 1,442,472

Accounts payable $ — $ 2,622 $ 57,531 $ — $ 60,153

Current maturities of debt — — 15,713 — 15,713

Current liabilities due to affiliates 34,509 987,664 36,726 (1,058,899) — 

Accrued expenses and other 27,549 1,516 61,035 — 90,100

Current Liabilities 62,058 991,802 171,005 (1,058,899) 165,966

Long-term debt 676,413 — 167,380 — 843,793

Long-term liabilities due to affiliates — — 599,000 (599,000) — 

Deferred taxes — — 141,887 — 141,887

Other liabilities 3,032 562 144,098 — 147,692

Total Liabilities 741,503 992,364 1,223,370 (1,657,899) 1,299,338

Series C convertible preferred stock 43,703 — — — 43,703

Stockholders’ equity 247,866 (106,801) 136,086 (177,720) 99,431

Total Liabilities and Equity $1,033,072 $885,563 $1,359,456 $ (1,835,619) $ 1,442,472

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As of December 31, 2011

 

Endeavour

International

Corporation 

Combined

Guarantor

Subsidiaries

Combined NonGuarantor

Subsidiaries Eliminations Consolidated

Cash and cash equivalents $ — $ 2,951 $ 103,085 $ — $ 106,036

Accounts receivable — 4,141 4,508 — 8,649

Current receivables due from affiliates 388,676 45,305 11,142 (445,123) — 

Prepaid expenses and other — 1,129 17,711 — 18,840

Current Assets 388,676 53,526 136,446 (445,123) 133,525

Property, plant and equipment, net — 127,739 421,457 — 549,196

Goodwill — — 211,886 — 211,886

Long-term receivables due from affiliates — 99,000 57,250 (156,250) — 

Investments in subsidiaries 57,662 120,077 — (177,739) — 

Other assets 5,414 6,083 18,887 — 30,384

Total Assets $451,752 $ 406,425 $ 845,926 $ (779,112) $924,991

Accounts payable $ — $ 17,655 $ 44,620 $ — $ 62,275

Current maturities of debt 10,000 — 2,350 — 12,350

Current liabilities due to affiliates — 513,914 45,715 (559,629) — 

Accrued expenses and other 4,847 4,799 10,903 — 20,549

Current Liabilities 14,847 536,368 103,588 (559,629) 95,174

Long-term debt 157,012 — 298,016 — 455,028

Long-term liabilities due to affiliates — (57,250) 99,000 (41,750) — 

Deferred taxes — — 108,762 6,997 115,759

Other liabilities 2,326 282 58,634 6 61,248

Total Liabilities 174,185 479,400 668,000 (594,376) 727,209

Series C convertible preferred stock 43,703 — — — 43,703

Stockholders’ equity 233,864 (72,975) 177,926 (184,736) 154,079

Total Liabilities and Equity $451,752 $ 406,425 $ 845,926 $ (779,112) $924,991

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

For the Year Ended December 31, 2012

 

Endeavour

International

Corporation

Combined

Guarantor

Subsidiaries

Combined NonGuarantor

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 (54,241) (951) (67,673) 38,743 (84,122) 

Letter of credit fees — — (21,903) — (21,903) 

Loss on early extinguishment of debt — — (21,661) — (21,661) 

Other income (expense) — 33,796 (4,307) (38,743) (9,254) 

Loss before taxes (57,575) (33,808) (20,615) — (111,998) 

Income tax expense — — 21,225 (6,997) 14,228

Net loss (57,575) (33,808) (41,840) 6,997 (126,226) 

Preferred stock dividends 1,823 — — — 1,823

Net loss to common shareholders $(59,398) $ (33,808) $ (41,840) $ 6,997 $ (128,049) 

For the Year Ended December 31, 2011

 

Endeavour

International

Corporation

Combined

Guarantor

Subsidiaries

Combined NonGuarantor

Subsidiaries Eliminations Consolidated

Revenue $ — $ 18,337 $ 41,754 $ — $ 60,091

Operating expenses — 9,046 8,622 — 17,668

DD&A expense — 11,490 14,988 — 26,478

Impairment of oil and gas properties — 65,706 — — 65,706

G&A expenses 2,198 10,789 4,866 — 17,853

Income (loss) from Operations (2,198) (78,694) 13,278 — (67,614) 

Derivatives: 

Unrealized gains (losses) (2,642) — 11,020 — 8,378

Interest expense (10,623) (3,964) (38,894) 8,588 (44,893) 

Loss on early extinguishment of debt (402) — — — (402) 

Other income (expense) (211) (678) 10,074 (8,588) 597

Loss before taxes (16,076) (83,336) (4,522) — (103,934) 

Income tax expense — 3 27,058 — 27,061

Net loss (16,076) (83,339) (31,580) — (130,995) 

Preferred stock dividends 1,974 — — — 1,974

Net loss to common shareholders $ (18,050) $ (83,339) $ (31,580) $ — $(132,969) 

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For the Year Ended December 31, 2010

 

Endeavour

International

Corporation

Combined

Guarantor

Subsidiaries

Combined NonGuarantor

Subsidiaries Eliminations Consolidated

Revenue $ — $ 11,174 $ 60,501 $ — $71,675

Operating expenses (19) 4,280 11,086 — 15,347

DD&A expense — 6,202 22,692 — 28,894

Impairment of oil and gas properties — 7,692 — — 7,692

G&A expenses 2,629 11,465 4,321 — 18,415

Income (loss) from Operations (2,610) (18,465) 22,402 — 1,327

Derivatives: 

Realized losses — — (11,753) — (11,753) 

Unrealized gains 2,258 — 10,033 — 12,291

Interest expense (11,476) (591) (25,079) 2,554 (34,592) 

Gain on sale of reserves in place — — 87,171 — 87,171

Other income (expense) (1) (93) 3,947 (2,554) 1,299

Income (loss) before taxes (11,829) (19,149) 86,721 — 55,743

Income tax benefit — — (788) — (788) 

Net income (loss) (11,829) (19,149) 87,509 — 56,531

Preferred stock dividends 2,227 — — — 2,227

Net income (loss) to common shareholders $(14,056) $(19,149) $ 87,509 $ — $ 54,304

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

For the Year Ended December 31, 2012

 

Endeavour

International

Corporation

Combined

Guarantor

Subsidiaries

Combined NonGuarantor

Subsidiaries Eliminations Consolidated

Cash Flows from Operating Activities: 

Net loss $ (57,575) $ (33,808) $ (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 (gains) losses 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: 

(Increase) decrease in receivables — 1,495 (25,814) — (24,319) 

(Increase) decrease in other current assets — (9,223) 8,631 — (592) 

Increase (decrease) in liabilities (493,026) 546,749 (21,617) (3,547) 28,559

Net Cash Provided by (Used in) 

Operating Activities (541,406) 567,066 12,953 — 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

Dividends paid (1,665) — — — (1,665) 

Payments for early extinguishment of debt — — (7,248) — (7,248) 

Financing costs paid (24,141) — (8,063) — (32,204) 

Other financing 4 — — — 4

Net Cash Provided by (Used in) 

Financing Activities 541,406 — 357,680 (500,000) 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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Notes to Consolidated Financial Statements

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

For the Year Ended December 31, 2011

 

Endeavour

International

Corporation

Combined

Guarantor

Subsidiaries

Combined NonGuarantor

Subsidiaries Eliminations Consolidated

Cash Flows from Operating Activities: 

Net loss $ (16,076) $ (83,339) $ (31,580) $ — $(130,995) 

Adjustments to reconcile net income (loss) to net cash provided by (used

in) operations 

DD&A expense — 11,490 14,988 — 26,478

Impairment of oil and gas properties — 65,706 — — 65,706

Deferred tax expense (benefit) — — 21,116 — 21,116

Unrealized (gains) losses on derivatives 2,642 — (11,020) — (8,378) 

Amortization of non-cash compensation 624 — — 3,073 3,697

Amortization of loan costs and discount 1,049 (403) 11,588 — 12,234

Loss on early extinguishment of debt 402 — — — 402

Non-cash interest expense 880 — 11,931 — 12,811

Other (82) 105 1,495 — 1,518

Changes in operating assets and liabilities: 

(Increase) decrease in receivables — (1,597) 1,066 — (531) 

(Increase) decrease in other current assets 34 2,872 (16,234) — (13,328) 

Increase (decrease) in liabilities (134,457) 95,725 11,732 (3,073) (30,073) 

Net Cash Provided by (Used in) 

Operating Activities (144,984) 90,559 15,082 — (39,343) 

Cash Flows From Investing Activities: 

Capital expenditures — (80,279) (84,783) — (165,062) 

Acquisitions, net of cash acquired — (8,027) (25,048) — (33,075) 

(Increase) decrease in restricted cash — — 31,726 — 31,726

Net Cash Provided by (Used in) 

Investing Activities — (88,306) (78,105) — (166,411) 

Cash Flows From Financing Activities: 

Repayments of borrowings (101,250) — (1,975) — (103,225) 

Borrowings under debt agreements, net of debt discount 135,000 — 75,000 — 210,000

Proceeds from issuance of common stock 118,444 — — — 118,444

Dividends paid (1,816) — — — (1,816) 

Financing costs paid (5,926) — (5,475) — (11,401) 

Other financing 532 (11) — — 521

Net Cash Provided by Financing Activities 144,984 (11) 67,550 — 212,523

Net Increase in Cash and Cash Equivalents — 2,242 4,527 — 6,769

Cash and Cash Equivalents, Beginning of Period — 709 98,558 — 99,267

Cash and Cash Equivalents, End of Period $ — $ 2,951 $ 103,085 $ — $ 106,036

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Endeavour International Corporation

Notes to Consolidated Financial Statements

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

For the Year Ended December 31, 2010

 

Endeavour

International

Corporation

Combined

Guarantor

Subsidiaries

Combined NonGuarantor

Subsidiaries Eliminations Consolidated

Cash Flows from Operating Activities: 

Net loss $(11,829) $(19,149) $ 87,509 $ — $ 56,531

Adjustments to reconcile net loss to net cash provided by (used in)

operations 

DD&A expense — 6,202 22,692 — 28,894

Impairment of oil and gas properties — 7,692 — — 7,692

Deferred tax expense (benefit) — — (3,367) — (3,367) 

Unrealized (gains) losses on derivatives (2,258) — (10,033) — (12,291) 

Gain on sale — — (87,171) — (87,171) 

Amortization of non-cash compensation 689 — — 3,003 3,692

Amortization of loan costs and discount 537 — 9,725 — 10,262

Non-cash interest expense 1,010 — 7,754 — 8,764

Other 307 (20) (2,373) — (2,086) 

Changes in operating assets and liabilities: 

Decrease in receivables — (829) 7,561 — 6,732

(Increase) decrease in other current assets 1,252 (4,907) (1,013) — (4,668) 

Increase (decrease) in liabilities (17,915) 85,445 (3,242) (60,253) 4,035

Net Cash Provided by (Used in) 

Operating Activities (28,207) 74,434 28,042 (57,250) 17,019

Cash Flows From Investing Activities: 

Capital expenditures — (34,036) (57,971) — (92,007) 

Acquisitions, net of cash acquired — (42,542) (1,184) — (43,726) 

Proceeds from sales, net of cash — 1 108,315 — 108,316

Issuance of note receivable to affiliate — — (57,250) 57,250 — 

(Increase) decrease in restricted cash — 2,450 (31,347) — (28,897) 

Net Cash Provided by (Used in) 

Investing Activities — (74,127) (39,437) 57,250 (56,314) 

Cash Flows From Financing Activities: 

Repayments of borrowings — — (75,342) — (75,342) 

Borrowings under debt agreements, net of debt discount — 185,000 — 185,000

Proceeds from issuance of common stock 30,181 — — — 30,181

Dividends paid (2,070) — — — (2,070) 

Financing costs paid — — (26,590) — (26,590) 

Other financing 9 6 — — — 9 6

Net Cash Provided by (Used in) 

Financing Activities 28,207 — 83,068 — 111,275

Net Decrease in Cash and Cash Equivalents — 307 71,673 — 71,980

Cash and Cash Equivalents, Beginning of Period — 402 26,885 — 27,287

Cash and Cash Equivalents, End of Period $ — $ 709 $ 98,558 $ — $ 99,267

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Endeavour International Corporation

Notes to Consolidated Financial Statements

(Amounts in tables in thousands, except per unit 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 current year statement of operations for Endeavour.

Note 24 – Subsequent Events

Entry into Procurement Agreement

In January 2013, we entered into 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.

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;

• 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.

Strategic Alternatives

On February 14, 2013, we announced that our board of directors approved a review of strategic alternatives. In an effort to unlock the value of our underlying

assets, we will consider a full range of options, including:

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Endeavour International Corporation

Notes to Consolidated Financial Statements

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

• A sale, joint venture or partnership in respect of our activities in the North Sea;

• A sale of specific assets;

• A sale or merger of the Company; or

• Continuing to execute on our operational plan.

We will announce the results of the effort once a course of action is chosen. There is no assurance that this strategic alternatives review will result in a change

to our current business plan, pursuing a particular transaction or completing any such transaction.

Forward Sale

In February 2013, we entered into a forward sale agreement with one of our established purchasers for a payment of approximately $22.5 million, which was

received on March 1, 2013 in return for a specified volume of crude oil in excess of 200,000 barrels to be delivered over a six month delivery period from our

UK North Sea production.

Production Payment

In March 2013, our wholly-owned subsidiary, EEUK, entered into a sale and purchase agreement (the “Sale and Purchase Agreement”) for $107.5 million

providing for the sale and purchase of a production payment over the proceeds of sale from a proportion of EEUK’s entitlement to production from its interests

in the Alba and Bacchus fields located in the UK sector of the North Sea (the “Production Payment Transaction”) and the issuance of warrants (discussed

below). Repayment of the production payment will come solely from the proceeds from the sale of production from EEUK’s entitlement from the Alba and

Bacchus fields.

In the event that the Production Payment Transaction is not consummated under the terms of the Sale and Purchase Agreement, the deposit paid to EEUK

upon signing of the Sale and Purchase Agreement and all or part of a $1.2 million termination fee would become due and payable by EEUK.

The completion of the Production Payment Transaction is conditional upon, amongst other things, the approval of the UK Secretary of State for Energy and

Climate Change. Contemporaneously with completion under the Sale and Purchase Agreement, we expect to issue 3,440,000 warrants to purchase shares of

common stock at an exercise price of $3.014 per share (the “Warrants”).

EEUK’s obligations to refund the deposit and pay the termination fee are secured by first priority liens on EEUK’s interests in the licenses and certain joint

operating agreements governing the fields giving rise to the production subject to the production payment. Upon closing of the purchase and sale of the

production payment, EEUK’s obligations under the production payment will be secured by first priority liens in the same assets and second priority liens in

certain other assets of the Company and its subsidiaries.

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Endeavour International Corporation

Notes to Consolidated Financial Statements

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

Revolving Credit Agreement

In March 2013, the Company, EEUK, Cyan, and certain lenders entered into a third amendment to the Revolving Credit Facility whereby (i) the lenders

consented to the Production Payment Transaction and (ii) the maturity of $100 million of the commitments under the under the Revolving Credit Facility was

extended from October 12, 2013 to June 30, 2014. The remaining principal of the Revolving Credit Facility will mature on October 12, 2013, as previously

provided.

Reimbursement Agreement

In March 2013, we amended the Alba Reimbursement Agreement to (i) allow us to enter the Production Payment Transaction, (ii) extend the maturity of the

obligations under the Alba Reimbursement Agreement from December 31, 2013 to June 30, 2014, and (iii) the parties agreed to agree to take the steps necessary

to extend the letter of credit issued pursuant to the Alba Reimbursement Agreement from December 31, 2013 to December 31, 2014.

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Endeavour International Corporation

Notes to Consolidated Financial Statements

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

Note 25 – Supplemental Oil and Gas Disclosures (Unaudited)

Capitalized Costs Relating to Oil and Gas Producing Activities

 

United

Kingdom

United

States Total

December 31, 2012: 

Proved $ 876,536 $ 39,265 $ 915,801

Unproved 273,298 76,135 349,433

Total capitalized costs 1,149,834 115,400 1,265,234

Accumulated depreciation, depletion and amortization (241,338) (24,269) (265,607) 

Net capitalized costs $ 908,496 $ 91,131 $ 999,627

December 31, 2011: 

Proved $ 429,246 $ 67,421 $ 496,667

Unproved 183,110 75,224 258,334

Total capitalized costs 612,356 142,645 755,001

Accumulated depreciation, depletion and amortization (192,027) (16,735) (208,762) 

Net capitalized costs $ 420,329 $125,910 $ 546,239

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Endeavour International Corporation

Notes to Consolidated Financial Statements

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

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

 

United

Kingdom 

United

States Total

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 302,038 8,099 310,137

Total costs incurred $ 538,650 $ 25,828 $ 564,478

Year Ended December 31, 2011: 

Acquisition costs: 

Proved $ 2,595 $ — $ 2,595

Unproved 46,107 2,840 48,947

Exploration costs 51,820 75,880 127,700

Development costs 79,898 10,560 90,458

Total costs incurred $ 180,420 $ 89,280 $ 269,700

Year Ended December 31, 2010: 

Acquisition costs: 

Proved $ — $ 2,386 $ 2,386

Unproved 1,184 40,155 41,339

Exploration costs 50,328 32,027 82,355

Development costs 22,047 1,884 23,931

Total costs incurred $ 73,559 $ 76,452 $ 150,011

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Endeavour International Corporation

Notes to Consolidated Financial Statements

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

Results of Operations for Oil and Gas Producing Activities

 

United

Kingdom 

United

States Total

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

Year Ended December 31, 2011: 

Revenues $ 41,754 $ 18,337 $ 60,091

Production expenses 8,622 9,046 17,668

DD&A 14,312 10,713 25,025

Impairment of oil and gas properties — 65,706 65,706

Income tax expense (benefit) 11,104 (23,495) (12,391) 

Results of activities $ 7,716 $ (43,633) $ (35,917) 

Year Ended December 31, 2010: 

Revenues $ 60,501 $ 11,174 $ 71,675

Production expenses 11,086 4,261 15,347

DD&A 22,020 5,273 27,293

Impairment of oil and gas properties — 7,692 7,692

Income tax expense (benefit) 13,698 (2,118) 11,580

Results of activities $ 13,697 $ (3,934) $ 9,763

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, 2012, 2011 and 2010.

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Endeavour International Corporation

Notes to Consolidated Financial Statements

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

 

United

Kingdom

United

States Total

Proved Oil Reserves (MBbls): 

Proved reserves at January 1, 2010 3,348 18 3,366

Production (545) (6) (551) 

Extensions and discoveries 457 34 491

Revisions of previous estimates 404 13 417

Proved reserves at December 31, 2010 3,664 5 9 3,723

Production (373) (7) (380) 

Purchases of reserves 303 — 303

Revisions of previous estimates 466 (11) 455

Proved reserves at December 31, 2011 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

Proved Developed Oil Reserves (MBbls): 

At December 31, 2010 1,240 14 1,254

At December 31, 2011 1,270 41 1,311

At December 31, 2012 5,261 6 5,267

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Endeavour International Corporation

Notes to Consolidated Financial Statements

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

 

United

Kingdom

United

States Total

Proved Gas Reserves (MMcf): 

Proved reserves at January 1, 2010 78,316 10,784 89,100

Production (3,071) (2,636) (5,707) 

Purchases of reserves — 2,657 2,657

Sales of reserves in place (51,522) — (51,522) 

Extensions and discoveries 26,692 24,181 50,873

Revisions of previous estimates 5,762 (3,209) 2,553

Proved reserves at December 31, 2010 56,177 31,777 87,954

Production (94) (5,076) (5,170) 

Purchases of reserves 90 — 90

Extensions and discoveries — 46,100 46,100

Revisions of previous estimates (5,450) (11,823) (17,273) 

Proved reserves at December 31, 2011 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

Proved Developed Gas Reserves (MMcf): 

At December 31, 2010 555 13,281 13,836

At December 31, 2011 795 22,704 23,499

At December 31, 2012 3,147 14,690 17,837

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Endeavour International Corporation

Notes to Consolidated Financial Statements

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

 

United

Kingdom

United

States Total

Proved Reserves (MBOE): 

Proved reserves at January 1, 2010 16,401 1,815 18,216

Production (1,057) (445) (1,502) 

Extensions and discoveries 4,906 4,064 8,970

Purchase of proved reserves, in place — 443 443

Sales of reserves (8,587) — (8,587) 

Revisions of previous estimates 1,364 (522) 842

Proved reserves at December 31, 2010 13,027 5,355 18,382

Production (389) (853) (1,242) 

Extensions and discoveries — 7,683 7,683

Purchase of proved reserves, in place 318 — 318

Revisions of previous estimates (442) (1,981) (2,423) 

Proved reserves at December 31, 2011 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

Proved Developed Reserves (MBOE): 

At December 31, 2010 1,333 2,227 3,560

At December 31, 2011 1,402 3,825 5,227

At December 31, 2012 5,785 2,454 8,239

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.

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Endeavour International Corporation

Notes to Consolidated Financial Statements

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

At December 31, 2012 and 2011, the prices used to determine the estimates of future cash inflows were as follows:

 December 31,

 2012 2011

 Oil Gas Oil Gas

United Kingdom ($/Barrel)

 111.13 9.34 110.77 8.75

United States ($/Mcf) 94.71 2.75 96.04 4.14

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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Endeavour International Corporation

Notes to Consolidated Financial Statements

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

Standardized Measure of Discounted Future Net Cash Flows

 

United

Kingdom

United

States Total

December 31, 2012: 

Future cash inflows $2,035,208 $ 31,258 $2,066,466

Future production costs (568,414) (10,101) (578,515) 

Future development costs (581,277) (896) (582,173) 

Future income tax expense (277,436) — (277,436) 

Future net cash flows (undiscounted) 608,081 20,261 628,342

Annual discount of 10% for estimated timing 122,780 6,584 129,364

Standardized measure of future net cash flows $ 485,301 $ 13,677 $ 498,978

December 31, 2011: 

Future cash inflows $ 941,208 $218,295 $1,159,503

Future production costs (144,106) (47,344) (191,450) 

Future development costs (306,628) (64,757) (371,385) 

Future income tax expense (238,111) — (238,111) 

Future net cash flows (undiscounted) 252,363 106,194 358,557

Annual discount of 10% for estimated timing 37,250 56,435 93,685

Standardized measure of future net cash flows $ 215,113 $ 49,759 $ 264,872

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

 2012 2011 2010

Standardized measure, beginning of period $ 264,872 $ 111,297 $ 55,698

Net changes in prices and production costs (33,520) 147,776 86,915

Future development costs incurred 172,462 76,721 21,112

Net changes in estimated future development costs (193,359) (9,261) (48,356) 

Revisions of previous quantity estimates (56,525) (36,421) 16,375

Extensions and discoveries 102,386 68,452 110,059

Accretion of discount 42,589 18,801 2,630

Changes in income taxes, net (74,778) (136,157) (35,306) 

Sale of oil and gas produced, net of production costs (165,547) (44,556) (56,327) 

Purchased reserves 457,033 26,340 2,386

Sales of reserves in place (6,971) — (48,310) 

Change in production, timing and other (9,664) 41,880 4,421

Standardized measure, end of period $ 498,978 $ 264,872 $111,297

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Endeavour International Corporation

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, 2012. 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, 2012. In making this assessment, our

management used the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway

Commission (COSO). Based on our assessment, management concluded our internal control over financial reporting was effective as of December 31, 2012.

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, 2012 and issued their attestation report set forth in this Item 9A.

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Endeavour International Corporation

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, 2012 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, 2012, based on criteria

established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (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.

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Endeavour International Corporation

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of

effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance

with the policies or procedures may deteriorate.

In our opinion, Endeavour International Corporation and subsidiaries maintained, in all material respects, effective internal control over financial reporting as

of December 31, 2012, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the 2012 consolidated financial

statements of Endeavour International Corporation and subsidiaries and our report dated March 18, 2013 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Houston, Texas

March 18, 2013

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Endeavour International Corporation

Item 9B. Other Information

None.

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Endeavour International Corporation

Part III

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

Our Definitive Proxy Statement for our 2013 Annual Meeting of Stockholders, when filed pursuant to Regulation 14A under the Securities Exchange Act of

1934, will be incorporated by reference into this Annual Report on Form 10-K pursuant to General Instruction G(3) of Form 10-K and will provide the

information required under Part III, Item 10.

Our Code of Business Conduct and the Code of Ethics for Senior Officers can be found on our 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.

Item 11. Executive Compensation

Our Definitive Proxy Statement for our 2013 Annual Meeting of Stockholders, when filed pursuant to Regulation 14A under the Securities Exchange Act of

1934, will be incorporated by reference into this Annual Report on Form 10-K pursuant to General Instruction G(3) of Form 10-K and will provide the

information required under Part III, Item 11.

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

Our Definitive Proxy Statement for our 2013 Annual Meeting of Stockholders, when filed pursuant to Regulation 14A under the Securities Exchange Act of

1934, will be incorporated by reference into this Annual Report on Form 10-K pursuant to General Instruction G(3) of Form 10-K and will provide the

information required under Part III, Item 12.

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

Our Definitive Proxy Statement for our 2013 Annual Meeting of Stockholders, when filed pursuant to Regulation 14A under the Securities Exchange Act of

1934, will be incorporated by reference into this Annual Report on Form 10-K pursuant to General Instruction G(3) of Form 10-K and will provide the

information required under Part III, Item 13.

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Endeavour International Corporation

Item 14. Principal Accounting Fees and Services

Our Definitive Proxy Statement for our 2013 Annual Meeting of Stockholders, when filed pursuant to Regulation 14A under the Securities Exchange Act of

1934, will be incorporated by reference into this Annual Report on Form 10-K pursuant to General Instruction G(3) of Form 10-K and will provide the

information required under Part III, Item 14.

Part IV

Item 15. Exhibits and Financial Statement Schedules

(a) (1) and (2) Financial Statements and Financial Statement Schedules.

See our consolidated financial statements included in Item 8 herein.

(a) (3) Exhibits.

See “Index of Exhibits” herein which lists the documents filed as exhibits with this Annual Report on Form 10-K.

(b) Exhibits.

See “Index of Exhibits” herein which lists the documents filed as exhibits with this Annual Report on Form 10-K.

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Endeavour International Corporation

Signatures

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Annual Report on Form 10-K to

be signed on its behalf by the undersigned, thereunto duly authorized.

Endeavour International Corporation

By: /s/ Catherine L. Stubbs

Catherine L. Stubbs

Senior Vice President and Chief Financial Officer

Date: March 18, 2013

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and

in the capacities and on the dates indicated.

Signature Title Date

/s/ William L. Transier

William L. Transier

 

Chief Executive Officer,

President and Director

(Principal Executive Officer)

March 18, 2013

/s/ Catherine L. Stubbs

Catherine L. Stubbs 

Chief Financial Officer

(Principal Financial Officer)

March 18, 2013

/s/ Stanley W. Farmer

Stanley W. Farmer

 

Chief Accounting Officer

(Principal Accounting Officer)

March 18, 2013

/s/ John B. Connally III

John B. Connally III

 

Director March 18, 2013

/s/ Sheldon R. Erikson

Sheldon Erikson 

Director March 18, 2013

/s/ Charles Hue Williams

Charles Hue Williams 

Director March 18, 2013

/s/ Nancy K. Quinn

Nancy K. Quinn 

Director March 18, 2013

/s/ John N. Seitz

John N. Seitz 

Director March 18, 2013

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Endeavour International Corporation

Exhibit Index

Exhibit Description

**2.1 Purchase and Sale Agreement, dated as of July 17, 2011, by and among Endeavour Operating Corporation, SM Energy Company, Potato Creek

LLC, Open Flow Gas Supply Corporation and SJ Exploration LLC (Incorporated by reference to Exhibit 2.1 of our Quarterly Report on Form

10-Q (Commission File No. 001-32212) for the quarter ended June 30, 2011).

**2.2 Membership Interest Purchase Agreement, dated as of July 17, 2011, by and among Endeavour Operating Corporation, SM Energy Company,

and Potato Creek LLC. (Incorporated by reference to Exhibit 2.1 of our Quarterly Report on Form 10-Q (Commission File No. 001-32212) for the

quarter ended June 30, 2011).

**2.3 Sale and Purchase Agreement between Endeavour Energy UK Limited and ConocoPhillips (U.K.) Limited, ConocoPhillips Petroleum Limited

and ConocoPhillips (U.K.) Lambda Limited. Schedules and Exhibits are omitted pursuant to Section 601(b)(2) of Regulation S-K. Endeavour

agrees to furnish supplementally a copy of any omitted Schedule to the SEC upon request. (Incorporated by reference to Exhibit 2.1 of our

Current Report on Form 8-K (Commission File No. 001-32212) filed on December 30, 2011).

2.3(b) Letter agreement to amend Sale and Purchase Agreement between Endeavour Energy UK Limited and ConocoPhillips (U.K.) Limited,

ConocoPhillips Petroleum Limited and ConocoPhillips (U.K.) Lambda Limited (Incorporated by Reference to Exhibit 2.1 to our Current Report

on Form 8-K (Commission File No. 001-32212) filed on December 3, 2012).

3.1(a) Amended and Restated Articles of Incorporation (Incorporated by reference to Exhibit 3.2 of our Quarterly Report on Form 10-Q (Commission

File No. 001-32212) for the quarter ended June 30, 2004).

3.1(b) Certificate of Amendment dated June 1, 2006 (Incorporated by reference to Exhibit 4.2 of our Registration Statement on Form S-3 (Commission

File No. 333-139304) filed on December 13, 2006).

3.1(c) Certificate of Amendment dated June 1, 2010 (Incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K (Commission File No.

001-32212) filed on June 3, 2010).

3.1(d) Amendment to Articles of Incorporation, dated November 17, 2010 (Incorporated by reference to Exhibit 3.1(d) of our Annual Report on Form 10-

K (Commission File No. 001-32212) for the year ended December 31, 2010).

*3.2 Amended and Restated Bylaws.

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).

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Exhibit Description

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).

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 (a) Warrants to Purchase Common Stock issued to Trident Growth Fund, LP dated July 29, 2003 (warrant # 2003-3) (Incorporated by reference to

Exhibit 4.7 of our Annual Report on Form 10-KSB (Commission File No. 000-33439) for the year ended December 31, 2003).

4.1 (b) First Amendment to Warrants to Purchase Common Stock dated February 26, 2004 (warrant # 2003-3) (Incorporated by reference to Exhibit

4.7 of our Annual Report on Form 10-KSB (Commission File No. 000-33439) for the year ended December 31, 2003).

4.2(a) Warrants to Purchase Common Stock issued to Gemini Capital, L.P. (Warrant #2002-1) (Incorporated by reference to Exhibit 4.6 of our

Quarterly Report on Form 10-QSB (Commission File No. 000-33439) for the Quarter Ended June 30, 2002).

4.2(b) First Amendment to Warrants to Purchase Common Stock dated July 29, 2003 (Warrant # 2002-1) (Incorporated by reference to Exhibit 4.5 of

our Annual Report on Form 10-KSB (Commission File No. 000-33439) for the year ended December 31, 2003).

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Exhibit Index

Exhibit Description

4.2(c) Second Amendment to Warrants to Purchase Common Stock dated February 26, 2004 (Warrant # 2002-1) (Incorporated by reference to Exhibit

4.5 of our Annual Report on Form 10-KSB (Commission File No. 000-33439) for the year ended December 31, 2003).

4.3 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).

4.4(a) Trust Deed dated January 24, 2008 by and among Endeavour International Corporation, Endeavour Energy Luxembourg S.a.r.l. and BNY

Corporate Trustee Services Limited, as trustee (Incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K (Commission File

No. 001-32212) filed on January 28, 2008).

4.4(b) Amendment Deed dated March 11, 2011, to Trust Deed dated January 24, 2008 by and among Endeavour International Corporation,

Endeavour Energy Luxembourg S.a.r.l. and BNY Corporate Trustee Services Limited, as trustee (Incorporated by reference to Exhibit 4.1 to our

Current Report on Form 8-K (Commission File No. 001-32212) filed on March 14, 2011).

4.5 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).

4.6 Form of 5.5% Global Note, dated July 22, 2011 (included in Exhibit 4.5).

4.7 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).

4.8 Form of First Priority 12% Senior Notes due 2018 (included in Exhibit 4.7).

4.9 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).

4.10 Form of Second Priority 12% Senior Notes due 2018 (included in Exhibit 4.9).

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Exhibit Description

4.11 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).

4.12 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).

†10.1 2004 Incentive Plan, effective February 26, 2004 (Incorporated by reference to Exhibit 10.36 of our Annual Report on Form 10-KSB

(Commission File No. 000-33439) for the year ended December 31, 2003).

†10.2 2007 Incentive Plan (Incorporated by reference to Exhibit 10.1 to our Quarterly Report (Commission File No. 001-32212) for the quarter ended

June 30, 2007).

†10.3(a) 2010 Incentive Plan (Incorporated by reference to Exhibit A to our definitive proxy statement on Schedule 14A filed on April 20, 2010).

†10.3(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).

†10.4 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 Employment Offer Letter to Carl Grenz, dated August 15, 2008 (Incorporated by reference to Exhibit 10.1 of our Quarterly Report on Form 10-

Q (Commission File No. 001-32212) for the quarter ended September 30, 2008).

†10.6 Form of Change in Control on Termination of Benefits Agreement (Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K

(Commission File No. 000-32212) filed on February 15, 2008).

†10.7 Form of Amended Change in Control Termination Benefits Agreement between Endeavour International Corporation and Grenz (Incorporated

by reference to Exhibit 10.8 of our Annual Report on Form 10-K for the year ended December 31, 2008).

†10.8 Change in Control and Termination Benefits Agreement dated January 11, 2010, by and between Endeavour International Corporation and

James Joseph Emme (Incorporated by reference to Exhibit 10.7 of our Annual Report on Form 10-K for the year ended December 31, 2009).

†10.9 Form of Restricted Stock Agreement under the 2010 Incentive Plan (Incorporated by reference to Exhibit 10.2 of our Quarterly Report on Form

10-Q (Commission File No. 001-32212) for the quarter ended September 30, 2010).

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Exhibit Index

Exhibit Description

†10.10 Form of Stock Option Agreement under the 2010 Incentive Plan (Incorporated by reference to Exhibit 10.3 to our Quarterly Report on Form 10-

Q (Commission File No. 001-32212) for the quarter ended September 30, 2010).

10.11(a) Subscription and Registration Rights Agreement, dated October 19, 2006, by and among Endeavour International Corporation and the

Investors party thereto (Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on

October 25, 2006).

10.11(b) Amendment No. 1 to Subscription and Registration Rights Agreement, January 29, 2010, by and among Endeavour International Corporation

and the Investors party thereto (Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K (Commission File No. 001-32212)

filed on February 1, 2010).

**10.12 Final Participation Agreement between Endeavour and Cohort Energy Company (Incorporated by reference to Exhibit 10.2 to our Current

Report on Form 8-K (Commission File No. 001-32212) filed on January 19, 2010).

10.13(a) Credit Agreement dated as of April 12, 2012 among Endeavour International Corporation, Endeavour Energy UK Limited, Cyan Partners,

LP, as administrative agent, and certain lenders party thereto (Incorporated by reference to Exhibit 10.3 to our Quarterly Report on Form 10-Q

(Commission File No. 001-32212) for the quarterly period ended March 31, 2012).

10.13(b) First Amendment to Credit Agreement; U.S. Security Agreement and Subsidiaries Guaranty dated as of May 31, 2012, by and among

Endeavour International Corporation, Endeavour Energy U.K. Limited, the subsidiary guarantors party thereto, Cyan Partners, LP, as

administrative agent and collateral agent, and the other lenders party thereto. (Incorporated by reference to Exhibit 10.1 to our Current Report on

Form 8-K (Commission File No. 001-32212) filed on June 6, 2012).

10.13(c) 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).

10.13(d) 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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Exhibit Index

Exhibit Description

10.13(e) Second Amendment to Credit Agreement, dated as of October 10, 2012, between Endeavour International Corporation, Endeavour Energy UK

Limited, Cyan Partners, LP, and the other lenders party thereto (Incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K

(Commission File No. 001-32212) filed on October 15, 2012).

†10.14 Stock Option Agreement between Endeavour International Corporation and Carl D. Grenz dated November 3, 2008 (Incorporated by reference

to Exhibit 10.22 to our Annual Report on Form 10-K (Commission File No. 001-32212) for the year ended December 31, 2008).

†10.15 Stock Option Agreement between Endeavour International Corporation and Carl D. Grenz dated November 3, 2008 (Incorporated by reference

to Exhibit 10.23 to our Annual Report on Form 10-K (Commission File No. 001-32212) for the year ended December 31, 2008).

†10.16 Restricted Stock Award Agreement between Endeavour International Corporation and James J. Emme dated January 10, 2010 (Incorporated by

reference to Exhibit 10.22 of our Annual Report on Form 10-K (Commission File No. 001-32212) for the year ended December 31, 2010).

†10.17 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).

†10.18 Form of Stock Redemption Agreement dated November 17, 2009 by and among Endeavour International Corporation and the holders of its

Series C Preferred Stock (Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K (Commission File No. 001-32212) filed

on November 23, 2009).

10.19(a) Form of Note Agreement dated November 17, 2009 by and among Endeavour International Corporation and the holders of its Series C

Preferred Stock (Incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on

November 23, 2009).

10.19(b) Amendment to Note Agreement dated November 17, 2009 by and among Endeavour International Corporation and the holders of its Series C

Preferred Stock, dated March 10, 2010 (Incorporated by reference to Exhibit 10.26(b) of our Annual Report on Form 10-K for the year ended

December 31, 2009).

10.20 Letter of Credit Facility Agreement dated as of July 25, 2011 by and between Endeavour International Corporation and Commonwealth Bank

of Australia (Incorporated by reference to Exhibit 10.3 to our Quarterly Report on Form 10-Q (Commission File No. 001-32212) for the quarter

ended June 30, 2011).

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Exhibit Index

Exhibit Description

10.21 Purchase Agreement, dated July 18, 2011 between the Company, the Guarantors, Citigroup Global Markets Inc. and Morgan Stanley & Co.

LLC (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on July 22, 2011).

10.22 Purchase Agreement dated as of February 13, 2012, among Endeavour International Corporation, the guarantors named therein and Citigroup

Global Markets Inc., as representative of the Initial Purchasers named therein (incorporated by reference to Exhibit 10.1 to our Current Report

on Form 8-K (Commission File No. 001-32212) filed on February 13, 2012).

10.23 First Priority Registration Rights Agreement, dated February 23, 2012, among Endeavour International Corporation, the subsidiary guarantors

party thereto and Citigroup Global Markets Inc., as representative of the initial purchasers named therein (incorporated by reference to Exhibit

4.5 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on February 29, 2012).

10.24 Second Priority Registration Rights Agreement, dated February 23, 2012, among Endeavour International Corporation, the subsidiary

guarantors party thereto and Citigroup Global Markets Inc. (incorporated by reference to Exhibit 4.6 to our Current Report on Form 8-K

(Commission File No. 001-32212) filed on February 29, 2012).

10.25 Reimbursement Agreement, dated as of May 23, 2012, among Endeavour International Corporation, Endeavour Energy U.K. Limited and

Yellow Rock S.a.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).

10.26 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).

10.27(a) Reimbursement Agreement, dated May 31, 2012, among Endeavour International Corporation, Endeavour Energy U.K. Limited, New Pearl

S.a.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).

10.27(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).

10.28 Registration Rights Agreement, dated October 15, 2012 (Incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K

(Commission File No. 001-32212) filed on October 15, 2012).

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Exhibit Description

10.29

 

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 14, 2013).

*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 (Incorporated by reference to Exhibit 14.1 to our Annual Report on Form 10-K

(Commission File No. 001-32212) for the year ended December 31, 2011).

*21.1 List of Subsidiaries.

*23.1 Consent of Independent Registered Public Accounting Firm – KPMG LLP.

*23.2 Consent of Independent Registered Public Accounting Firm – KPMG LLP.

*23.3 Consent of Independent Registered Public Accounting Firm – KPMG LLP.

*23.4 Consent of Independent Reserve Engineers – Netherland, Sewell & Associates, Inc.

*23.5 Consent of Independent Registered Public Accounting Firm – Ernst & Young LLP.

*23.6 Consent of Independent Registered Public Accounting Firm – Ernst & Young LLP.

*23.7 Consent of Independent Registered Public Accounting Firm – Ernst & Young LLP.

*31.1

 

Certification of William L. Transier, Chief Executive Officer, pursuant to Rule 13a-14(a) of the Securities and Exchange Act of 1934, as

amended.

*31.2

 

Certification of Catherine L. Stubbs, Chief Financial Officer, pursuant to Rule 13a-14(a) of the Securities and Exchange Act of 1934, as

amended.

‡32.1

 

Certification of William L. Transier, Chief Executive Officer, pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the

Sarbanes-Oxley Act of 2002.

‡32.2

 

Certification of Catherine L. Stubbs, Chief Financial Officer, pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the

Sarbanes-Oxley Act of 2002.

‡99.1 Report of Netherland, Sewell & Associates, Inc., Independent Petroleum Engineers and Geologists.

*99.2 Audited Financial Statements of Endeavour Energy UK Limited.

*99.3 Audited Financial Statements of Endeavour International Holding B.V.

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Exhibit Description

*101.INS XBRL Instance Document.

*101.SCH XBRL Taxonomy Extension Schema Document.

*101.CA XBRL Taxonomy Extension Calculation Linkbase.

*101.DEF XBRL Taxonomy Extension Definition Linkbase.

*101.LAB XBRL Taxonomy Extension Label Linkbase.

*101.PRE 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.

156
Exhibit 3.2

CONFORMED COPY

AMENDED AND RESTATED

BYLAWS

OF

ENDEAVOUR INTERNATIONAL CORPORATION

A Nevada Corporation

ARTICLE I

Stockholders

Section 1. Annual Meeting. Annual meetings of the stockholders, commencing with the year 2000, shall be held on the 13TH day of January each year if

not a legal holiday and, if a legal holiday, then on the next secular day following, or at such other time as may be set by the Board of Directors from time to

time, at which the stockholders shall elect by vote a Board of Directors and transact such other business as may be properly be brought before the meeting.

Section 2. Special Meetings.

(a) Special meetings of the stockholders may be called by the President or the Secretary by resolution of the Board of Directors.

(b) Special meetings of the stockholders shall be called by the President or the Secretary upon the request in writing of stockholders owning a majority of the

stock of the corporation issued and outstanding and generally entitled to vote in the election of directors. Such request must be (i) delivered to the Secretary at

the principal executive offices of the corporation; (ii) signed by the requesting stockholders (the “Requesting Stockholders”) or a duly authorized agent of the

Requesting Stockholders; and (iii) accompanied by a notice that fulfills the requirements of paragraph (c) of Section 8 of this Article I (such provisions to

apply mutatis mutandis to the “Requesting Stockholders” as if they were the “Proposing Stockholder” referred to therein). At any special meeting requested by

stockholders, the business transacted shall be limited to the purposes stated in the request for meeting, except that the Board of Directors shall have the

authority in its discretion to submit additional matters to the stockholders and to cause other business to be transacted. Notwithstanding the foregoing, only the

business that has been brought before the meeting pursuant to the corporation’s notice of meeting shall be conducted at a special meeting of stockholders.

Note: Article I, Section 2 was amended pursuant to an amendment dated January 14, 2013 (filed on Form 8-K filed on January 15, 2013).

1

1
(c) The Board of Directors shall fix the date, time and place for each special meeting; provided, however, that the date of any special meeting called pursuant

to paragraph (b) of this Section 2 shall be not more than 90 days after the date a proper request to call the special meeting is received by the Secretary.

Notwithstanding the foregoing, a special meeting requested by stockholders shall not be held if (i) the stated business to be brought before the special meeting

is not a proper subject for stockholder action under applicable law; (ii) the Board of Directors has called or calls for an annual or special meeting of

stockholders to be held within 90 days after the date the Secretary receives the request for the special meeting and the Board of Directors determines in good

faith that the business of such meeting includes the business described in the request; (iii) the request for the special meeting is received by the Secretary

during the period commencing 120 days prior to the first anniversary date of the previous year’s annual meeting of stockholders and ending on the date of the

annual meeting of stockholders; or (iv) an identical or substantially similar item was presented at any meeting of stockholders held within 90 days prior to

receipt by the Secretary of the request for special meeting (and, for purposes of this clause (iv), the election of directors shall be deemed a similar item with

respect to all items of business involving the election or removal of directors). The Board of Directors shall set a record date for the determination of

stockholders entitled to vote for each special meeting in the manner set forth in Section 4 of Article V.

(d) At a special meeting of stockholders, nominations of persons for election to the Board of Directors shall be made only as set forth in paragraph (b) of

Section 8 of this Article I.

(e) The Requesting Stockholders may revoke the request for a special meeting at any time by delivering a written revocation to the Secretary at the principal

executive offices of the corporation.

Section 3. Place of Meetings. All annual meetings of the stockholders shall be held at the registered office of the corporation or at such other place within

or without the State of Nevada as the directors shall determine. Special meetings of the stockholders may be held at such time and place within or without the

State of Nevada as shall be stated in the notice of the meeting, or in a duly executed waiver of notice thereof. Business transacted at any special meeting of

stockholders shall be limited to the purposes stated in the notice.

Section 4. Quorum: Adjourned Meetings. The holders of a majority of the stock issued and outstanding and entitled to vote thereat, present in person or

represented by proxy, shall constitute a quorum at all meetings of the stockholders for the transaction of business except as otherwise provided by statute or by

the Articles of Incorporation. If, however, such quorum is not present or represented at any meeting of the stockholders, the presiding officer of the meeting

shall have the power to adjourn the meeting from time to time, without notice other than announcement at the meeting, until a quorum is present or represented.

At such adjourned meeting at which a quorum shall be present or represented, any business may be transacted which might have been transacted at the

meeting as originally notified.

Section 5. Voting. Each stockholder of record of the corporation holding stock which is entitled to vote at this meeting shall be entitled at each meeting of

stockholders to one vote for each share of stock standing in his name on the books of the corporation. Upon the demand of any stockholder, the vote for

directors and the vote upon any question before the meeting shall be by ballot.

Note: Article I, Section 4 was amended pursuant to an amendment dated January 14, 2013 (filed on Form 8-K filed on January 15, 2013).

2

2
When a quorum is present or represented at any meeting, the vote of the holders of a majority of the stock having voting power present in person or represented

by proxy shall be sufficient to decide any question brought before such meeting (other than for the election of directors), unless the question is one upon which

by express provision of the statutes or of the Articles of Incorporation, a different vote is required in which case such express provision shall govern and

control the decision of such question.

Section 6. Proxies. At any meeting of the stockholders any stockholder may be represented and vote by a proxy or proxies appointed by an instrument in

writing. In the event that any such instrument in writing shall designate two or more persons to act as proxies, a majority of such persons present at the

meeting, or, if only one shall be present, then that one shall have and may exercise all of the powers conferred by such written instrument upon all of the

persons so designated unless the instrument shall otherwise provide. No proxy or power of attorney to vote shall be used to vote at a meeting of the

stockholders unless it shall have been filed with the secretary of the meeting. All questions regarding the qualification of voters, the validity of proxies and the

acceptance or rejection of votes shall be decided by the inspectors of election who shall be appointed by the Board of Directors, or if not so appointed, then by

the presiding officer of the meeting.

Section 7. Action Without Meeting. Unless otherwise provided by the Articles of Incorporation, any action required or permitted to be taken by the

stockholders of the corporation must be effected at a duly held meeting of stockholders of the corporation at which a quorum is present or represented and may

not be effected by any consent in writing by the stockholders.

Section 8. Advance Notice of Stockholder Nominations and Proposals .

(a) Annual Meetings of Stockholders.

(i) At any annual meeting of the stockholders, only such nominations of persons for the election of directors and such other business shall be conducted as

shall have been properly brought before the meeting. To be properly brought before an annual meeting, director nominations or the proposal of other business to

be considered and acted upon by stockholders must be: (A) specified in the notice of meeting (or any supplement thereto) or given or otherwise properly

brought before the meeting by or at the direction of the Board of Directors or any committee thereof; or (B) properly brought before an annual meeting by a

stockholder who is a stockholder of record of the corporation at the time such notice provided for in this Section 8 is delivered, who is entitled to vote at the

meeting and who complies with the notice procedures set forth in this Section 8. The foregoing clause (B) shall be the exclusive means for a stockholder to

make nominations or submit other business (other than matters properly brought under Rule 14a-8 (or any successor thereto) under the Exchange Act and

included in the corporation’s notice of meeting) before an annual meeting of stockholders.

Note: Article I, Section 5 was amended pursuant to an amendment dated January 14, 2013 (filed on Form 8-K filed on January 15, 2013).

Note: Article I, Section 7 was amended pursuant to an amendment dated January 14, 2013 (filed on Form 8-K filed on January 15, 2013).

Note: Article I, Section 8 was added to the Bylaws pursuant to an amendment dated January 14, 2013 (filed on Form 8-K filed on January 15, 2013).

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(ii) For director nominations and other business to be properly brought before an annual meeting by a stockholder, the stockholder of record intending to make

such nominations or propose such business (the “Proposing Stockholder”) must have delivered timely notice thereof meeting the requirements of paragraph

(c) of this Section 8 (even if such matter is already the subject of any notice to the stockholders or Public Disclosure from the Board of Directors) and any

such proposed business (other than the nominations of persons for election to the Board of Directors) must constitute a proper matter for stockholder action

under applicable law. To be timely, such notice must be delivered: (A) for any annual meeting of stockholders held after June 30, 2013, not earlier than the

close of business on the 120th day prior to the first anniversary of the previous year’s annual meeting nor later than the close of business on the 90th day;

provided, however, that if the date of the annual meeting is more than 30 days before or more than 60 days after such anniversary date, notice by a Proposing

Stockholder to be timely must be delivered not earlier than the close of business on the 120th day prior to such annual meeting and not later than the 90th day

prior to such annual meeting or, if later, the tenth day following the day on which Public Disclosure of the date of such annual meeting was first made; and

(B) for any annual meeting of stockholders held prior to June 30, 2013, not later than the close of business the 60th day following the day on which Public

Disclosure of the adoption of this Bylaw was first made. In no event shall the Public Disclosure of an adjournment or postponement of an annual meeting

commence a new time period (or extend any time period) for the giving of notice by a Proposing Stockholder as described herein. Notwithstanding anything in

this paragraph (a) to the contrary, in the event that the number of directors to be elected to the Board of Directors of the corporation at the annual meeting is

increased effective after the time period for which nominations would otherwise be due under this paragraph (a) and there is no Public Disclosure by the

corporation of the nominees for the additional directorships at least 100 days prior to the first anniversary of the preceding year’s annual meeting, a Proposing

Stockholder’s notice shall also be considered timely, but only with respect to nominees for the additional directorships, if it shall be delivered not later than the

close of business on the 10th day following the day on which such Public Disclosure is first made by the corporation.

(b) Special Meetings of Stockholders. Only such business shall be conducted at a special meeting of stockholders as shall have been brought before the

meeting pursuant to the corporation’s notice of meeting with respect to such special meeting. Nominations of persons for election to the Board of Directors may

be made at a special meeting of stockholders (i) by or at the direction of the Board of Directors or any committee thereof or (ii) by any stockholder of the

corporation who is a stockholder of record at the time the notice provided for in this Section 8 is delivered, who is entitled to vote at the meeting and upon such

election and who complies with the notice procedures set forth in this Section 8. In the event the corporation calls a special meeting of stockholders for the

purpose of electing one or more directors to the Board of Directors, any such stockholder entitled to vote in such election of directors may nominate a person or

persons (as the case may be) for election to such positions as specified in the corporation’s notice of meeting if a stockholder’s notice meeting the requirements

of paragraph (c) of this Section 8 (such provisions to apply mutatis mutandis to such stockholder as if it was the “Proposing Stockholder” referred to therein)

not earlier than the close of business on the later of the 120th day prior to such special meeting nor later than the close of business on the 90th day prior to

such special meeting or if later, the tenth day following the date of Public Disclosure of the date of the special meeting
and of the nominees proposed by the Board of Directors to be elected at such meeting. In no event shall the Public Disclosure of an adjournment or

postponement of a special meeting commence a new time period (or extend any time period) for the giving of a Proposing Stockholders notice required hereby.

(c) Notice Requirements. A Proposing Stockholder’s written notice must be delivered to the Secretary at the principal executive offices of the corporation and

shall set forth:

(i) as to each nominee proposed in such notice: (A) the name, age, business address and residence address of each such nominee; (B) the principal occupation

or employment of each such nominee; (C) the number of shares of stock of the corporation which are owned of record and beneficially by such nominee, if

any; (D) such other information concerning each such nominee as would be required to be disclosed in a proxy statement soliciting proxies for the election of

such nominee as a director in an election contest (even if an election contest is not involved) or that is otherwise required to be disclosed, under Section 14(a) of

the Exchange Act and the rules and regulations promulgated thereunder; and (E) the signed consent to being named in the proxy statement as a nominee and to

serving as a director if elected of each such nominee being proposed;

(ii) as to any business other than director nominations that a Proposing Stockholder proposes to bring , as to each matter the Proposing Stockholder proposes

to bring before the meeting: (A) a brief description of the business desired to be brought before the meeting; (B) the text of each proposal or matter of business

(including the text of any resolutions to be proposed for consideration and in the event that such proposal or matter of business includes a proposal to amend

the Bylaws of the corporation, the text of the proposed amendment); (C) the reasons for conducting such business at the meeting; (D) any material interest of

such Proposing Stockholder or beneficial owner, if any, on whose behalf the proposal; and (E) any other information concerning the proposal as would be

required to be disclosed in a proxy statement soliciting proxies for the proposal or that is otherwise required to be disclosed, under Section 14(a) of the

Exchange Act and the rules and regulations promulgated thereunder; and

(iii) in each case as to the Proposing Stockholder and the beneficial owner, if any, on whose behalf the nominations or other business proposal is made: (A) the

name and address of the Proposing Stockholder as they appear on the corporation’s books and of the beneficial owner, if any, on whose behalf the nomination

or other business proposal is being made; (B) the class, series, if any, and number of shares of stock of the corporation which are owned by the Proposing

Stockholder (beneficially and of record) and owned by the beneficial owner, if any, on whose behalf the nomination or other business proposal is being made,

as of the date of the Proposing Stockholder’s notice, and a covenant that the Proposing Stockholder will notify the corporation in writing of the class and

number of such shares owned of record and beneficially as of the record date for the meeting promptly following the later of the record date or the date notice of

the record date is first publicly disclosed; (C) a description of any agreement, arrangement or understanding with respect to such nomination or other business

proposal between or among the Proposing Stockholder, any such beneficial owner on whose behalf the nomination or other business proposal is being made

and any of their respective affiliates or associates, and any others (naming them) acting in concert with any of the foregoing, including in the case of a

nomination, the nominee, and a covenant that the Proposing Stockholder will notify the corporation in writing of any such agreement, arrangement or

understanding in effect as of the record date for the meeting promptly following the later of the record date or the date notice of the record date is first publicly

disclosed; (D) a description of any
proxy, contract, arrangement, understanding, or relationship pursuant to which the Proposing Stockholder, any beneficial owner on whose behalf the

nomination or other business proposal is being made and any of their respective affiliates or associates has a right to vote or has granted a right to vote any

shares of any security of the corporation, and a covenant that the Proposing Stockholder will notify the corporation in writing of any such proxy, contract,

arrangement, understanding, or relationship in effect as of the record date for the meeting promptly following the later of the record date or the date notice of the

record date is first publicly disclosed; (E) a description of any agreement, arrangement or understanding (including any derivative or short positions, profit

interests, options, warrants, convertible securities, stock appreciation or similar rights, hedging transactions, and borrowed or loaned shares) that has been

entered into as of the date of the Proposing Stockholder’s notice by, or on behalf of, the Proposing Stockholder, any beneficial owner on whose behalf the

nomination or other business proposal is being made or any of their respective affiliates or associates, whether or not such instrument or right shall be subject

to settlement in underlying shares of stock of the corporation, the effect or intent of which is to mitigate loss to, manage risk or benefit of share price changes

for, or increase or decrease the voting power of the Proposing Stockholder, any beneficial owner on whose behalf the nomination or other business proposal is

being made or any of their respective affiliates or associates with respect to securities of the corporation, and a covenant that the Proposing Stockholder will

notify the corporation in writing of any such agreement, arrangement or understanding in effect as of the record date for the meeting promptly following the

later of the record date or the date notice of the record date is first publicly disclosed; (F) a representation that the Proposing Stockholder is a holder of record of

shares of stock of the corporation entitled to vote at the meeting and intends to appear in person or by proxy at the meeting to nominate the person or persons or

propose the business in each case as specified in the notice; (G) a representation whether the Proposing Stockholder, any beneficial owner on whose behalf the

nomination or other business proposal is being made or any of their respective affiliates or associates intends to deliver a proxy statement or form of proxy to

holders of at least the percentage of the corporation’s outstanding stock required to elect the nominees or to approve or adopt any other proposal and/or

otherwise to solicit proxies from stockholders in support of the nominations or other proposal; and (H) such other information concerning the Proposing

Stockholder and the beneficial owner, if any, on whose behalf the nominations or other business proposal is made as would be required to be disclosed in a

proxy statement soliciting proxies for the proposal or the election of nominee as a director in an election contest (even if an election contest is not involved) or

that is otherwise required to be disclosed, under Section 14(a) of the Exchange Act and the rules and regulations promulgated thereunder.

The corporation may require any proposed nominee to furnish such other information as it may reasonably require to determine the eligibility of such proposed

nominee to serve as a director of the corporation or that could be material to a reasonable stockholder’s understanding of the independence, or lack thereof, of

such nominee.

The foregoing notice requirements of this paragraph (c) shall be deemed satisfied by a stockholder with respect to business other than a nomination if the

stockholder has notified the corporation of his, her or its intention to present a proposal at a meeting and such stockholder’s proposal has been included in a

proxy statement that has been prepared by the corporation to solicit proxies for use at such meeting.
(d) General. Except as otherwise expressly provided in any applicable rule or regulation promulgated under the Exchange Act, only such persons who are

nominated in accordance with the procedures set forth in this Section 8 shall be eligible to be elected at an annual or special meeting of stockholders of the

corporation to serve as directors and only such business shall be conducted at a meeting of stockholders as shall have been brought before the meeting in

accordance with the procedures set forth in this Section 8. Unless otherwise required by law, if a Proposing Stockholder intending to propose business or

make nominations at a meeting pursuant to this Section 8 does not provide the information required under paragraph (c) of this Section 8 to the corporation

promptly following the later of the record date or the date notice of the record date is first Publicly Disclosed, or the Proposing Stockholder (or a qualified

representative of the Proposing Stockholder) does not appear at the meeting to present the proposed business or nominations, such business or nominations

shall not be considered, notwithstanding that proxies in respect of such business or nominations may have been received by the corporation. Except as

otherwise provided by law, the presiding officer of the meeting shall have the power and duty (i) to determine whether a nomination or any business proposed

to be brought before the meeting was made or proposed, as the case may be, in accordance with the procedures set forth in this Section 8 (including whether the

stockholder or beneficial owner, if any, on whose behalf the nomination or proposal is made, solicited (or is part of a group which solicited) or did not so

solicit, as the case may be, proxies or votes in support of such stockholder’s nominee or proposal in compliance with such stockholder’s representation as

required by this Section 8); and (ii) if any proposed nomination or business was not made or proposed in compliance with this Section 8, to declare that such

nomination shall be disregarded or that such proposed business shall not be transacted. The requirements of this Section 8 shall apply to any business or

nominations to be brought before an annual meeting by a stockholder, whether such business or nominations are to be included in the corporation’s proxy

statement pursuant to Rule 14a-8 of the Exchange Act or presented to stockholders by means of an independently financed proxy solicitation. Notwithstanding

the foregoing provisions of this Section 8, a stockholder shall also comply with all applicable requirements of the Exchange Act and the rules and regulations

promulgated thereunder with respect to the matters set forth in this Section 8; provided, however, that any references in these Bylaws to the Exchange Act or

the rules and regulations promulgated thereunder are not intended to and shall not limit any requirements applicable to nominations or proposals as to any

other business to be considered pursuant to this Section 8 and compliance with paragraphs (a) and (b) of this Section 8 shall be the exclusive means for a

stockholder to make nominations or submit other business (other than, as provided in the last sentence of paragraph (a), business other than nominations

brought properly under and in compliance with Rule 14a-8 of the Exchange Act, as may be amended from time to time). Nothing in this Section 8 shall be

deemed to affect any rights of (A) the stockholders to request inclusion of proposals or nominations in the corporation’s proxy statement pursuant to applicable

rules and regulations promulgated under the Exchange Act; or (B) the holders of any series of Preferred Stock to elect directors pursuant to any applicable

provisions of the Articles of Incorporation. The requirements of this Section 8 are included to provide the corporation notice of a stockholder’s intention to

bring business or nominations before a meeting and shall in no event be construed as imposing upon any stockholder the requirement to seek approval from

the corporation as a condition precedent to bringing any such business or make such nominations before a meeting.

(e) Certain Definitions. For purposes of this Section 8, (i) “Exchange Act” means the Securities Exchange Act of 1934, as amended, and the rules and

regulations promulgated thereunder; (ii) “Public Disclosure” or “Publicly Disclosed” means a disclosure made in a press release issued publically by the

corporation through its customary channels of public dissemination of press releases or in a document
filed by the corporation with the U.S. Securities and Exchange Commission pursuant to Section 13, 14 or 15(d) of the Exchange Act; and (iii) “qualified

representative” of means a person who is (A) a duly authorized officer, manager or partner of such stockholder; or (B) authorized by a writing executed by

such stockholder or an electronic transmission delivered by such stockholder to act for such stockholder as proxy at the meeting of stockholders, and such

person must produce such writing or electronic transmission, or a reliable reproduction thereof, at the meeting of stockholders.

ARTICLE II

Directors

Section 1. Management of Corporation. The business of the corporation shall be managed by its Board of Directors which may exercise all such powers

of the corporation and do all such lawful acts and things as are not by statute or by the Articles of Incorporation or by these Bylaws directed or required to be

exercised or done by the stockholders.

Section 2. Number, Term of Office and Classification. The number of directors which shall constitute the entire Board of Directors shall be at least one.

The number of directors may from time to time be increased or decreased to not less than one nor more than fifteen as determined by resolution of the Board of

Directors. Directors need not be stockholders. The directors shall be divided into three classes, designated Class I, Class II, and Class III. Each class shall

consist, as nearly as possible, of one-third of the total number of directors constituting the entire Board of Directors, and in any event at least one-fourth in

number of the directors constituting the entire Board of Directors shall be elected annually. The term of each incumbent director of the Company as of the date

upon which these Bylaws were amended to provide for three classes of directors shall terminate at the next annual meeting of stockholders (the “Effective

Time”), and prior to the Effective Time the Board of Directors shall designate the class to which each director nominee for election at the next annual meeting

of stockholders shall be a member if elected. The initial term of the directors in Class I shall extend until the first annual meeting of stockholders following the

Effective Time; the initial term of directors in Class II shall extend until the second annual meeting of stockholders following the Effective Time; and the initial

term of the directors in Class III shall extend until the third annual meeting of stockholders following the Effective Time. At each succeeding annual meeting of

stockholders, successors to directors of the class whose term expires at such annual meeting will be elected to serve for three-year terms and until their

successors are elected and qualified or they resign or are removed. Directors for each class being elected at an annual meeting of stockholders will be elected by

a plurality of the votes cast by the holders of shares entitled to vote in such an election.

In the event the number of directors constituting any class of directors does not constitute at least one-fourth of the entire board of directors to be elected at the

annual meeting of stockholders, the Board of Directors shall take, at or prior to such annual meeting, such action as it deems necessary or appropriate to

ensure that at least one-fourth of the directors constituting the entire Board of Directors is elected at such annual meeting, including, without limitation,

increasing the number of directors constituting any class of directors.

In the event of any changes in the number of directors, each director then continuing to serve shall nevertheless continue as a director of the class of which

such director is a member until the expiration of such director’s current term, or prior death, resignation or removal. The Board of Directors shall specify the

class to which a newly created directorship shall be allocated.
Section 3. Vacancies. Vacancies in the Board of Directors including those caused by an increase in the number of directors, may be filled by a majority

of the remaining directors, though less than a quorum, or by a sole remaining director, and each director so elected shall hold office until his successor is

elected at an annual or special meeting of the stockholders. The holders of two-thirds of the outstanding shares of stock entitled to vote may at any time

peremptorily terminate the term of office of all or any of the directors by vote at a meeting called for such purpose. Such removal shall be effective immediately,

even if successors are not elected simultaneously.

A vacancy or vacancies in the Board of Directors shall be deemed to exist in case of the death, resignation or removal of any directors, or if the authorized

number of directors be increased, or if the stockholders fail at any annual or special meeting of stockholders at which any director or directors are elected to

elect the full authorized number of directors to be voted for at that meeting.

If the Board of Directors accepts the resignation of a director tendered to take effect at a future time, the Board or the stockholders shall have power to elect a

successor to take office when the resignation is to become effective.

No reduction of the authorized number of directors shall have the effect of removing any director prior to the expiration of his term of office.

Section 4. Annual and Regular Meetings. Regular meetings of the Board of Directors shall be held at any place within or without the State which has

been designated from time to time by resolution of the Board or by written consent of all members of the Board. In the absence of such designation regular

meetings shall be held at the registered office of the corporation. Special meetings of the Board may be held either at a place so designated or at the registered

office.

Regular meetings of the Board of Directors may be held without call or notice at such time and at such place as shall from time to time be fixed and determined

by the Board of Directors.

Section 5. First Meeting. The first meeting of each newly elected Board of Directors shall be held immediately following the adjournment of the meeting

of stockholders and at the place thereof. No notice of such meeting shall be necessary to the directors in order legally to constitute the meeting, provided a

quorum be present. In the event such meeting is not so held, the meeting may be held at such time and place as shall be specified in a notice given as

hereinafter provided for special meetings of the Board of Directors.

Section 6. Special Meetings. Special meetings of the Board of Directors may be called by the Chairman or the President or by any Vice-President or by

any two directors.

Note: Article II, Section 3 was added to the Bylaws pursuant to an amendment dated January 14, 2013 (filed on Form 8-K filed on January 15, 2013).

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Written notice of the time and place of special meetings shall be delivered personally to each director, or sent to each director by mail or by other form of

written communication, charges prepaid, addressed to him at his address as it is shown upon the records or if such address is not readily ascertainable, at the

place in which the meetings of the directors are regularly held. In case such notice is mailed or telegraphed, it shall be deposited in the United States mail or

delivered to the telegraph company at least three (3) days prior to the time of the holding of the meeting. In case such notice is hand delivered as above provided,

it shall be so delivered at least twenty-four (24) hours prior to the time of the holding of the meeting. Such mailing, telegraphing or delivery as above provided

shall be due, legal and personal notice to such director.

Section 7. Business of Meetings. The transactions of any meeting of the Board of Directors, however called and noticed or wherever held, shall be as

valid as though had at a meeting duly held after regular call and notice, if a quorum be present, and if, either before or after the meeting, each of the directors

not present signs a written waiver of notice, or a consent to holding such meeting, or an approval of the minutes thereof. All such waivers, consents or

approvals shall be filed with the corporate records or made a part of the minutes of the meeting.

Section 8. Quorum: Adjourned Meetings. A majority of the authorized number of directors shall be necessary to constitute a quorum for the transaction

of business, except to adjourn as hereinafter provided. Every act or decision done or made by a majority of the directors present at a meeting duly held at

which a quorum is present shall be regarded as the act of the Board of Directors, unless a greater number be required by law or by the Articles of

Incorporation. Any action of a majority, although not at a regularly called meeting, and the record thereof, if assented to in writing by all of the other members

of the Board shall be as valid and effective in all respects as if passed by the Board in regular meeting.

A quorum of the directors may adjourn any directors meeting to meet again at a stated day and hour; provided, however, that in the absence of a quorum, a

majority of the directors present at any directors meeting, either regular or special, may adjourn from time to time until the time fixed for the next regular

meeting of the Board.

Notice of the time and place of holding an adjourned meeting need not be given to the absent directors if the time and place be fixed at the meeting adjourned.

Section 9. Committees. The Board of Directors may, by resolution adopted by a majority of the whole Board, designate one or more committees of the

Board of Directors, each committee to consist of at least one or more of the directors of the corporation which, to the extent provided in the resolution, shall

have and may exercise the power of the Board of Directors in the management of the business and affairs of the corporation and may have power to authorize

the seal of the corporation to be affixed to all papers which may require it. Such committee or committees shall have such name or names as may be determined

from time to time by the Board of Directors. The members of any such committee present at any meeting and not disqualified from voting may, whether or not

they constitute a quorum, unanimously appoint another member of the Board of Directors to act at the meeting in the place of any absent or disqualified

member. At meetings of such committees, a majority of the members or alternate members shall constitute a quorum for the transaction of business, and the

act of a majority of the members or alternate members at any meeting at which there is a quorum shall be the act of the committee.
The committees shall keep regular minutes of their proceedings and report the same to the Board of Directors.

Section 10. Action Without Meeting. Any action required or permitted to be taken at any meeting of the Board of Directors or of any committee thereof

may be taken without a meeting if a written consent thereto is signed by all members of the Board of Directors or of such committee, as the case may be, and

such written consent is filed with the minutes of proceedings of the Board or committee.

Section 11. Special Compensation. The directors may be paid their expenses of attendance at each meeting of the Board of Directors and may be paid a

fixed sum for attendance at each meeting of the Board of Directors or a stated salary as director. No such payment shall preclude any director from serving the

corporation in any other capacity and receiving compensation therefor. Members of special or standing committees may be allowed like reimbursement and

compensation for attending committee meetings.

ARTICLE III

Notices

Section I. Notice of meetings. Notices of meetings shall be in writing and signed by the President or a Vice-President or the Secretary or an Assistant

Secretary or by such other person or persons as the directors shall designate. Such notice shall state the purpose or purposes for which the meeting is called

and the time and the place, which may be within or without this State, where it is to be held. A copy of such notice shall be either delivered personally to or

shall be mailed, postage prepaid, to each stockholder of record entitled to vote at such meeting not less than ten (10) nor more than sixty (60) days before such

meeting. If mailed, it shall be directed to a stockholder at his address as it appears upon the records of the corporation and upon such mailing of any such

notice, the service thereof shall be complete and the time of the notice shall begin to run from the date upon which such notice is deposited in the mail for

transmission to such stockholder. Personal delivery of any such notice to any officer of a corporation or association or to any member of a partnership shall

constitute delivery of such notice to such corporation, association or partnership. In the event of the transfer of stock after delivery of such notice of and prior

to the holding of the meeting it shall not be necessary to deliver or mail notice of the meeting to the transferee.

Section 2. Effect of Irregularly Called Meetings. Whenever all parties entitled to vote at any meeting, whether of directors or stockholders, consent, either

by a writing on the records of the meeting or filed with the secretary, or by presence at such meeting and oral consent entered on the minutes, or taking part in

the deliberations at such meeting without objection, the doings of such meeting shall be as valid as if had at a meeting regularly called and noticed, and at such

meeting any business may be transacted which is not excepted from the written consent or to the consideration of which no objection for want of notice is made

at the time, and if any meeting be irregular for want of notice or of such consent, provided a quorum was present at such meeting, the proceedings of said

meeting may be ratified and approved and rendered likewise valid and the irregularity or defect therein waived by a writing signed by all parties having the

right to vote at such meeting; and such consent or approval of stockholders may be by proxy or attorney, but all such proxies and powers of attorney must be

in writing.
Section 3. Waiver of Notice. Whenever any notice whatever is required to be given under the provisions of the statutes, of the Articles of Incorporation or

of these Bylaws, a waiver thereof in writing, signed by the person or persons entitled to said notice, whether before or after the time stated therein, shall be

deemed equivalent thereto.

ARTICLE IV

Officers

Section 1. Election. The officers of the corporation shall be chosen by the Board of Directors and shall be a President, a Secretary and a Treasurer, none

of whom need be directors. Any person may hold two or more offices. The Board of Directors may appoint a Chairman of the Board, Vice-Chairman of the

Board, one or more vice-presidents, assistant treasurers and assistant secretaries.

Section 2. Chairman of the Board. The Chairman of the Board shall preside at meetings of the stockholders and the Board of Directors, and shall see

that all orders and resolutions of the Board of Directors are carried into effect.

Section 3. Vice-Chairman of the Board. The Vice-Chairman shall, in the absence or disability of the Chairman of the Board, perform the duties and

exercise the powers of the Chairman of the Board and shall perform such other duties as the Board of Directors may from time to time prescribe.

Section 4. President. The President shall be the chief executive officer of the corporation and shall have active management of the business of the

corporation. He shall execute on behalf of the corporation all instruments requiring such execution except to the extent the signing and execution thereof shall be

expressly designated by the Board of Directors to some other officer or agent of the corporation. In the absence of the President the Vice-President will assume

all of the President’s responsibilities.

Section 5. Vice-President. The Vice-President shall act under the direction of the President and in the absence or disability of the President shall perform

the duties and exercise the powers of the President. They shall perform such other duties and have such other powers as the President or the Board of Directors

may from time to time prescribe. The Board of Directors may designate one or more Executive Vice-Presidents or may otherwise specify the order of seniority

of the Vice-Presidents. The duties and powers of the President shall descend to the Vice-Presidents in such specified order of seniority.

Section 6. Secretary. The Secretary shall act under the direction of the President. Subject to the direction of the President he shall attend all meetings of

the Board of Directors and all meetings of the stockholders and record the proceedings. He shall perform like duties for the standing committees when required.

He shall give, or cause to be given, notice of all meetings of the stockholders and special meetings of the Board of Directors, and shall perform such other

duties as may be prescribed by the President or the Board of Directors. In the absence of the Secretary the Vice-President will assume all of the Secretary’s

responsibilities.

Section 7. Assistant Secretaries. The Assistant Secretaries shall act under the direction of the President. In order of their seniority, unless otherwise

determined by the President or the Board of Directors, they shall, in the absence or disability of the Secretary, perform the duties and exercise the powers of the

Secretary. They shall perform such other duties and have such other powers as the President or the Board of Directors may from time to time prescribe.
Section 8. Treasurer. The Treasurer shall act under the direction of the President. Subject to the direction of the President he shall have custody of the

corporate funds and securities and shall keep full and accurate accounts of receipts and disbursements in books belonging to the corporation and shall deposit

all monies and other valuable effects in the name and to the credit of the corporation in such depositories as may be designated by the Board of Directors. He

shall disburse the funds of the corporation as may be ordered by the President or the Board of Directors, taking proper vouchers for such disbursements, and

shall render to the President and the Board of Directors, at its regular meetings, or when the Board of Directors so requires, an account of all his transactions

as Treasurer and of the financial condition of the corporation. In the absence of the Treasurer the Vice-President will assume all of the Treasurer’s

responsibilities.

If required by the Board of Directors, he shall give the corporation a bond in such sum and with such surety or sureties as shall be satisfactory to the Board of

Directors for the faithful performance of the duties of his office and for the restoration to the corporation, in case of his death, resignation, retirement or

removal from office, of all books, papers, vouchers, money and other property of whatever kind in his possession or under his control belonging to the

corporation.

Section 9. Assistant Treasurers. The Assistant Treasurers in the order of their seniority, unless otherwise determined by the President or the Board of

Directors, shall, in the absence or disability of the Treasurer, perform the duties and exercise the powers of the Treasurer. They shall perform such other

duties and have such other powers as the President or the Board of Directors may from time to time prescribe.

Section 10. Compensation. The salaries and compensation of all officers of the corporation shall be fixed by the Board of Directors.

Section 11. Removal: Resignation. The officers of the corporation shall hold office at the pleasure of the Board of Directors. Any officer elected or

appointed by the Board of Directors may be removed at any time by the Board of Directors. Any vacancy occurring in any office of the corporation by death,

resignation, removal or otherwise shall be filled by the Board of Directors.

ARTICLE V

Capital Stock

Section 1. Certificated and Uncertificated Shares. The Board of Directors shall be authorized to issue any of the classes or series of shares of the capital

stock of the corporation with or without certificates. The fact that the shares are not represented by certificates shall have no effect on the rights and obligations

of stockholders. If the shares are represented by certificates, such shares shall be represented by consecutively numbered certificates signed by the President or

a Vice-President and the Treasurer or an Assistant Treasurer, or the Secretary or an Assistant Secretary of the corporation, certifying the number of shares

owned by the stockholder in the corporation. If the corporation shall be authorized to issue more than one class of stock or more than one series of any class,

the designations,

Note: Article V was amended pursuant to an amendment dated December 12, 2007 (filed on Form 8-K filed on December 13, 2007).

7

7
preferences and relative, participating, optional or other special rights of the various classes of stock or series thereof and the qualifications, limitations or

restrictions of such rights, shall be set forth in full or summarized on the face or back of the certificate, which the corporation shall issue to represent such

stock.

If a certificate is countersigned or otherwise authenticated (1) by a transfer agent other than the corporation or its employees and (2) by a registrar other than the

corporation or its employees, the signatures of the officers of the corporation may be facsimiles. In case any officer who has signed or whose facsimile

signature has been placed upon a certificate shall cease to be such officer before such certificate is issued, such certificate may be issued with the same effect

as though the person had not ceased to be such officer. The seal of the corporation, or a facsimile thereof, may, but need not be, affixed to certificates of stock.

If shares are not represented by certificates, within a reasonable time following the issue or transfer of such shares, the corporation shall send the stockholder a

written statement of all of the information required to be provided to holders of uncertificated shares by the Nevada General Corporation Law.

Section 2. Surrendered: Lost or Destroyed Certificates. The Board of Directors may direct a new certificate or certificates to be issued in place of any

certificate or certificates theretofore issued by the corporation alleged to have been lost or destroyed upon the making of an affidavit of that fact by the person

claiming the certificate of stock to be lost or destroyed. When authorizing such issue of a new certificate or certificates, the Board of Directors may, in its

discretion and as a condition precedent to the issuance thereof, require the owner of such lost or destroyed certificate or certificates, or his legal representative,

to advertise the same in such manner as it shall require and/or give the corporation a bond in such sum as it may direct as indemnity against any claim that

may be made against the corporation with respect to the certificate alleged to have been lost or destroyed.

Section 3. Replacement Certificates. Upon surrender to the corporation or the transfer agent of the corporation of a certificate for shares duly endorsed or

accompanied by proper evidence of succession, assignment or authority to transfer, it shall be the duty of the corporation, if it is satisfied that all provisions

of the laws and regulations applicable to the corporation regarding transfer and ownership of shares have been complied with, to issue a new certificate to the

person entitled thereto (provided, however, if the Board of Directors determines or has determined that the ownership of such shares shall be represented by

uncertificated shares, the corporation need not issue a new certificate but shall provide the stockholder with a written statement of all of the information

required to be provided to holders of uncertificated shares by the Nevada General Corporation Law), cancel the old certificate and record the transaction upon

its books.

Section 4. Record Date. The Board of Directors may fix in advance a date not exceeding sixty (60) days nor less than ten (10) days preceding the date of

any meeting of stockholders, or the date for the payment of any distribution, or the date for the allotment of rights, or the date when any change or conversion

or exchange of capital stock shall go into effect, or a date in connection with obtaining the consent of stockholders for any purpose, as a record date for the

determination of the stockholders entitled to notice of and to vote at any such meeting, and any adjournment thereof, or entitled to receive payment of any such

distribution, or to give such consent, and in such case, such stockholders, and only such stockholders as shall be stockholders of record on the date so fixed,

shall be entitled to notice of and to
vote at such meeting, or any adjournment thereof, or to receive payment of such distribution, or to receive such allotment of rights, or to exercise such rights,

or to give such consent, as the case may be, notwithstanding any transfer of any stock on the books of the corporation after any such record date fixed as

aforesaid.

Section 5. Registered Owner. The corporation shall be entitled to recognize the person registered on its books as the owner of shares to be the exclusive

owner for all purposes including voting and distribution, and the corporation shall not be bound to recognize any equitable or other claim to or interest in such

share or shares on the part of any other person, whether or not it shall have express or other notice thereof, except as otherwise provided by the laws of Nevada.

ARTICLE VI

General Provisions

Section 1. Registered Office. The registered office of this corporation shall be in the State of Nevada.

The corporation may also have offices at such other places both within and without the State of Nevada as the Board of Directors may from time to time

determine or the business of the corporation may require.

Section 2. Distributions. Distributions upon the capital stock of the corporation, subject to the provisions of the Articles of Incorporation, if any, may be

declared by the Board of Directors at any regular or special meeting, pursuant to law. Distributions may be paid in cash, in property or in shares of the capital

stock, subject to the provisions of the Articles of Incorporation.

Section 3. Reserves. Before payment of any distribution, there may be set aside out of any funds of the corporation available for distributions such sum

or sums as the directors from time to time, in their absolute discretion, think proper as a reserve or reserves to meet contingencies, or for equalizing

distributions or for repairing or maintaining any property of the corporation or for such other purpose as the directors shall think conducive to the interest of

the corporation, and the directors may modify or abolish any such reserve in the manner in which it was created.

Section 4. Checks: Notes. All checks or demands for money and notes of the corporation shall be signed by such officer or officers or such other person

or persons as the Board of Directors may from time to time designate.

Section 5. Fiscal Year. The fiscal year of the corporation shall be fixed by resolution of the Board of Directors.

Section 6. Corporate Seal. The corporation may or may not have a corporate seal, as may from time to time be determined by resolution of the Board of

Directors. If a corporate seal is adopted, it shall have inscribed thereon the name of the corporation and the words “Corporate Seal” and “Nevada”. The seal

may be used by causing it or a facsimile thereof to be impressed or affixed or in any manner reproduced.
ARTICLE VII

Indemnification

Section 1. Indemnification of Officers and Directors, Employees and Other Persons . Every person who was or is a party or is threatened to be made a

party to or is involved in any action, suit or proceeding, whether civil, criminal, administrative or investigative, by reason of the fact that he or a person of

whom he is the legal representative is or was a director or officer of the corporation or is or was serving at the request of the corporation or for its benefit as a

director or officer of another corporation, or as its representative in a partnership, joint venture, trust or other enterprise, shall be indemnified and held

harmless to the fullest extent legally permissible under the general corporation law of the State of Nevada from time to time against all expenses, liability and

loss (including attorneys’ fees, judgments, fines and amounts paid or to be paid in settlement) reasonably incurred or suffered by him in connection therewith.

The expenses of officers and directors incurred in defending a civil or criminal action, suit or proceeding must be paid by the corporation as they are incurred

and in advance of the final disposition of the action, suit or proceeding upon receipt of an undertaking by or on behalf of the director or officer to repay the

amount if it is ultimately determined by a court of competent jurisdiction that he is not entitled to be indemnified by the corporation. Such right of

indemnification shall be a contract right which may be enforced in any manner desired by such person. Such right of indemnification shall not be exclusive of

any other right which such directors, officers or representatives may have or hereafter acquire and, without limiting the generality of such statement, they shall

be entitled to their respective rights of indemnification under any bylaw, agreement, vote of stockholders, provision of law or otherwise, as well as their rights

under this Article.

Section 2. Insurance. The Board of Directors may cause the corporation to purchase and maintain insurance on behalf of any person who is or was a

director or officer of the corporation, or is or was serving at the request of the corporation as a director or officer of another corporation, or as its representative

in a partnership, joint venture, trust or other enterprise against any liability asserted against such person and incurred in any such capacity or arising out of

such status, whether or not the corporation would have the power to indemnify such person.

Section 3. Further Bylaws. The Board of Directors may from time to time adopt further Bylaws with respect to indemnification and may amend these

and such Bylaws to provide at all times the fullest indemnification permitted by the General Corporation Law of the State of Nevada.

ARTICLE VIII

Amendments

Section I. Amendments by Stockholders. The Bylaws may be amended by a majority vote of all the stock issued and outstanding and entitled to vote

for the election of directors of the stockholders, provided notice of intention to amend shall have been contained in the notice of the meeting.

Section 2. Amendments by Board of Directors. The Board of Directors by a majority vote of the whole Board at any meeting may amend these Bylaws,

including Bylaws adopted by the stockholders, but the stockholders may from time to time specify particular provisions of the Bylaws which shall not be

amended by the Board of Directors.
ARTICLE IX

Nevada’s Acquisition of Controlling Interest Act Opt-Out

The Corporation shall not be subject to the provisions of Nevada Revised Statutes Sections 78.378 to 78.3793, inclusive (Acquisition of Controlling Interest).
Exhibit 12.1

Endeavour International Corporation

Endeavour International Corporation

Computation of Ratios of Earnings to Fixed Charges

(Amounts in thousands)

 Year Ended December 31,

 2012 2011 2010

Earnings: 

Income (Loss) before Taxes $(111,998) $(103,934) $55,743

Add: Fixed charges 84,122 44,893 34,592

Earnings $ (27,876) $ (59,041) $90,335

Fixed Charges: 

Interest expense $ 84,122 $ 44,893 $34,592

Capitalized interest 26,886 14,711 3,925

Total fixed charges $ 111,008 $ 59,604 $38,517

Ratio of earnings to fixed charges — — 2.3

For purposes of this computation, earnings are defined as pretax earnings from continuing operations before adjustment for minority interest and equity losses

in entities with oil and gas properties, plus interest expense, and amortization of debt discount and expense related to indebtedness. Fixed charges are interest

expense, including amortization of debt discount and expenses on indebtedness.

Earnings were insufficient to cover fixed charges by $138.9 million and $118.6 million for the year ended December 31, 2012 and 2011.
Exhibit 12.2

Endeavour International Corporation

Endeavour International Corporation

Computation of Ratios of Earnings to Fixed Charges

and Preference Securities Dividends

(Amounts in thousands)

 Year Ended December 31,

 2012 2011 2010

Earnings: 

Income (Loss) before Taxes $(111,998) $(103,934) $ 55,743

Add: Fixed charges, excluding capitalized interest 85,945 46,867 36,819

Earnings $ (26,053) $ (57,067) $92,562

Fixed Charges: 

Interest expense $ 84,122 $ 44,893 $ 34,592

Preferred dividends 1,823 1,974 2,227

Capitalized interest 26,886 14,711 3,925

Total fixed charges $ 112,831 $ 61,578 $ 40,744

Ratio of earnings to fixed charges — — 2.2

For purposes of this computation, earnings are defined as pretax earnings from continuing operations before adjustment for minority interest and equity losses

in entities with oil and gas properties, plus interest expense, and amortization of debt discount and expense related to indebtedness. Fixed charges are interest

expense, including amortization of debt discount and expenses on indebtedness.

Earnings were insufficient to cover fixed charges by $138.9 million and $118.6 million for the year ended December 31, 2012 and 2011.
Endeavour International Corporation

Exhibit 21.1

SUBSIDIARIES

Name: Jurisdiction of Organization

1. Endeavour Operating Corporation Delaware

2. Endeavour Energy UK Limited England and Wales

3. Endeavour Energy Netherlands B.V. The Netherlands

4. Endeavour International Holding B.V. The Netherlands

5. Endeavour Energy New Ventures, Inc. Delaware

6. END Management Company Delaware

7. Endeavour Energy Luxembourg S.a.r.l. Luxembourg
Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

The Board of Directors

Endeavour International Corporation:

We consent to the use of our reports dated March 7, 2012, except as to Note 23, which is as of March 18, 2013, with respect to the consolidated balance sheet

of Endeavour International Corporation as of December 31, 2011, and the related consolidated statements of operations, stockholders’ equity, and cash flows

for each of the years in the two-year period ended December 31, 2011, incorporated herein by reference.

/s/ KPMG LLP

Houston, Texas

March 18, 2013
Exhibit 23.2

Consent of Independent Registered Public Accounting Firm

The Board of Directors

Endeavour International Holding B.V.:

We consent to the use of our reports dated January 24, 2013, except as to Note 2 and 10, which is as of March 18, 2013, with respect to the consolidated

balance sheet of Endeavour International Holding B.V. as of December 31, 2011, and the related consolidated statements of operations, stockholders’ equity,

and cash flows for each of the years in the two-year period ended December 31, 2011, incorporated herein by reference.

/s/ KPMG LLP

Houston, Texas

March 18, 2013
Exhibit 23.3

Consent of Independent Registered Public Accounting Firm

The Board of Directors

Endeavour Energy UK Limited:

We consent to the use of our reports dated January 24, 2013, except as to Note 2 and 10, which is as of March 18, 2013, with respect to the consolidated

balance sheet of Endeavour Energy UK Limited as of December 31, 2011, and the related consolidated statements of operations, stockholders’ equity, and

cash flows for each of the years in the two-year period ended December 31, 2011, incorporated herein by reference.

/s/ KPMG LLP

Houston, Texas

March 18, 2013
Exhibit 23.4

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

We hereby consent to the inclusion in the Endeavour International Corporation (the “Company”) Form 10-K for the year ended December 31, 2012, and the

incorporation by reference in the Company’s Registration Statement Nos. 333-118503, 333-130515, 333-132684, 333-139304, 333-149744, 333-163781, and

333-165853 on Form S-3, as amended; No. 333-186274 on Form S-4; and Nos. 333-119577, 333-128692, 333-143794, 333-149743, 333-157967, 333-

169851, 333-171392 , 333-183251, and 333-183250 on Form S-8, as amended, of the reference to Netherland, Sewell & Associates, Inc.

NETHERLAND, SEWELL & ASSOCIATES, INC.

By: /s/ Danny D. Simmons

Danny D. Simmons, P.E.

President and Chief Operating Officer

Houston, Texas

March 18, 2013
Exhibit 23.5

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in the Registration Statements:

(1) Registration Statement (Form S-3 Nos. 333-118503, 333-130515, 333-132684, 333-139304, 333-149744, 333-163781 and 333-165853) of Endeavour

International Corporation and in the related Prospectuses,

(2) Registration Statement (Form S-4 No. 333-186274) of Endeavour International Corporation and in the related Prospectuses, and

(3) Registration Statement (Form S-8 Nos. 333-119577, 333-128692, 333-143794, 333-149743, 333-157967, 333-169851, 333-171392, 333-183250 and

333-183251) of Endeavour International Corporation and in the related Prospectuses;

of our reports dated March 18, 2013, with respect to the consolidated financial statements of Endeavour International Corporation and the effectiveness of

internal control over financial reporting of Endeavour International Corporation, included in this Annual Report (Form 10-K) for the year ended December 31,

2012.

/s/ Ernst & Young LLP

Houston, Texas

March 18, 2013
Exhibit 23.6

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in the Registration Statements:

(1) Registration Statement (Form S-3 Nos. 333-118503, 333-130515, 333-132684, 333-139304, 333-149744, 333-163781 and 333-165853) of Endeavour

International Corporation and in the related Prospectuses,

(2) Registration Statement (Form S-4 No. 333-186274) of Endeavour International Corporation and in the related Prospectuses, and

(3) Registration Statement (Form S-8 Nos. 333-119577, 333-128692, 333-143794, 333-149743, 333-157967, 333-169851, 333-171392, 333-183250 and

333-183251) of Endeavour International Corporation and in the related Prospectuses;

of our report dated March 18, 2013, with respect to the consolidated financial statements of Endeavour International Holdings B.V. included in this Annual

Report (Form 10-K) for the year ended December 31, 2012.

/s/ Ernst & Young LLP

Houston, Texas

March 18, 2013
Exhibit 23.7

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in the Registration Statements:

(1) Registration Statement (Form S-3 Nos. 333-118503, 333-130515, 333-132684, 333-139304, 333-149744, 333-163781 and 333-165853) of Endeavour

International Corporation and in the related Prospectuses,

(2) Registration Statement (Form S-4 No. 333-186274) of Endeavour International Corporation and in the related Prospectuses, and

(3) Registration Statement (Form S-8 Nos. 333-119577, 333-128692, 333-143794, 333-149743, 333-157967, 333-169851, 333-171392, 333-183250 and

333-183251) of Endeavour International Corporation and in the related Prospectuses;

of our report dated March 18, 2013, with respect to the consolidated financial statements of Endeavour Energy UK Limited included in this Annual Report

(Form 10-K) for the year ended December 31, 2012.

/s/ Ernst & Young LLP

Houston, Texas

March 18, 2013
Endeavour International Corporation

Exhibit 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, William L. Transier, certify that:

1. I have reviewed this Annual Report on Form 10-K of Endeavour International Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements

made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial

condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange

Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant

and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure

that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities,

particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision,

to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in

accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness

of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal

quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the

registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the

registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely

to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
Endeavour International Corporation

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over

financial reporting.

Date: March 18, 2013

/s/ William L. Transier

William L. Transier, Chief Executive Officer
Endeavour International Corporation

Exhibit 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Catherine L. Stubbs, certify that:

1. I have reviewed this Annual Report on Form 10-K of Endeavour International Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements

made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial

condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange

Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant

and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure

that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities,

particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision,

to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in

accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness

of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal

quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the

registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the

registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely

to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
Endeavour International Corporation

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over

financial reporting.

Date: March 18, 2013

/s/ Catherine L. Stubbs

Catherine L. Stubbs, Chief Financial Officer
Endeavour International Corporation

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Endeavour International Corporation (the “Company”) on Form 10-K for the period ended December 31,

2012 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, William L. Transier, Chief Executive Officer of the

Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge:

1. The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ William L. Transier

William L. Transier

Chief Executive Officer

Date: March 18, 2013

A signed original of this written statement required by Section 906 has been provided to Endeavour International Corporation and will be retained

by Endeavour International Corporation and furnished to the Securities and Exchange Commission or its staff upon request.
Endeavour International Corporation

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Endeavour International Corporation (the “Company”) on Form 10-K for the period ended December 31,

2012 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, Catherine L. Stubbs, Chief Financial Officer of the

Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge:

1. The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Catherine L. Stubbs

Catherine L. Stubbs

Chief Financial Officer

Date: March 18, 2013

A signed original of this written statement required by Section 906 has been provided to Endeavour International Corporation and will be retained

by Endeavour International Corporation and furnished to the Securities and Exchange Commission or its staff upon request.
Exhibit 99.1

February 12, 2013

Mr. Derek Neilson

Endeavour International Corporation

40 Queens Road

Aberdeen AB15 4YE

United Kingdom

Dear Mr. Neilson:

In accordance with your request, we have audited the estimates prepared by Endeavour International Corporation (Endeavour), as of December 31, 2012, of

the proved reserves and future revenue to the Endeavour interest in certain oil and gas properties located in the United Kingdom and the United States. It is our

understanding that the proved reserves estimates shown herein constitute all of the proved reserves owned by Endeavour. We have examined the estimates with

respect to reserves quantities, reserves categorization, future producing rates, future net revenue, and the present value of such future net revenue, using the

definitions set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Rule 4-10(a). The estimates of reserves and future revenue have been

prepared in accordance with the definitions and regulations of the SEC and, with the exception of the exclusion of future income taxes, conform to the FASB

Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. We completed our audit on or about the date of this letter. This report has

been prepared for Endeavour’s use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this

report are appropriate for such purpose.

The following table sets forth Endeavour’s estimates of the net reserves and future net revenue, as of December 31, 2012, for the audited properties:

 Net Reserves Future Net Revenue ($)

 Oil NGL Gas Present Worth

Country/Category (Barrels) (Barrels) (MCF) Total at 10%

UNITED KINGDOM 

Proved Developed Producing 4,635,261 0 2,884,191 168,731,776 230,228,842 

Proved Developed Non-Producing 625,696 0 263,023 39,032,829 36,558,307 

Proved Undeveloped 8,461,035 10,814 53,754,276 873,273,598 670,574,886 

Total Proved 13,721,992 10,814 56,901,490 1,081,038,203 937,362,035 

UNITED STATES 

Proved Developed Producing 5,627 0 11,617,762 16,757,051 11,644,342 

Proved Developed Non-Producing 162 0 3,072,487 3,503,924 2,032,973 

Proved Undeveloped 0 0 0 0 0 

Total Proved 5,790 0 14,690,249 20,260,975 13,677,315 

(1)
 Net Reserves Future Net Revenue ($)

 Oil NGL Gas Present Worth

Country/Category (Barrels) (Barrels) (MCF) Total at 10%

ALL PROPERTIES 

Proved Developed Producing 4,640,889 0 14,501,953 185,488,827 241,873,184 

Proved Developed Non-Producing 625,858 0 3,335,510 42,536,753 38,591,280 

Proved Undeveloped 8,461,035 10,814 53,754,276 873,273,598 670,574,886 

Total Proved 13,727,781 10,814 71,591,740 1,101,299,177 951,039,349 

Totals may not add because of rounding.

There are no proved undeveloped reserves for the United States properties at the prices and costs used in this report.

The oil reserves shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in barrels that are equivalent to 42 United

States gallons. Gas volumes are expressed in thousands of cubic feet (MCF) at standard temperature and pressure bases. Monetary values shown in this report

are expressed in United States dollars ($) using the 12-month unweighted arithmetic average of the first-day-of-the-month U.S. Federal Reserve exchange rate

for each month in the period January through December 2012 of $1.58 equals 1 British pound sterling.

When compared on a field-by-field basis, some of the estimates of Endeavour are greater and some are less than the estimates of Netherland, Sewell &

Associates, Inc. (NSAI). However, in our opinion the estimates of Endeavour’s proved reserves and future revenue shown herein are, in the aggregate,

reasonable and have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information

promulgated by the Society of Petroleum Engineers (SPE Standards). Additionally, these estimates are within the recommended 10 percent tolerance threshold

set forth in the SPE Standards. We are satisfied with the methods and procedures used by Endeavour in preparing the December 31, 2012, estimates of

reserves and future revenue, and we saw nothing of an unusual nature that would cause us to take exception with the estimates, in the aggregate, as prepared

by Endeavour.

The estimates shown herein are for proved reserves. Endeavour’s estimates do not include probable or possible reserves that exist for these properties, nor do

they include any value for undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Reserves categorization conveys the

relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included

herein have not been adjusted for risk.

Oil and NGL prices used by Endeavour are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the

period January through December 2012. The average Platts Dated Brent price of $111.13 per barrel is used for the United Kingdom properties, and the

average Wall Street Journal West Texas Intermediate price of $94.71 per barrel is used for the United States properties. These average prices are adjusted by

lease for quality, transportation fees, and regional price differentials. Oil and NGL prices are held constant throughout the lives of the properties. The average

adjusted product prices weighted by production over the remaining lives of the properties are $109.04 per barrel of oil and $49.39 per barrel of NGL.

Gas prices used by Endeavour either are the fixed contract price or are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price

for each month in the period January through December 2012. The average Platts National Balancing Point spot price of 59.14 pence per therm (equivalent to

$9.34 per

(1)
MMBTU) is used for all United Kingdom properties except for Bacchus and Enoch Fields, and the average Wall Street Journal Henry Hub spot price of

$2.75 per MMBTU is used for the United States properties. These average prices are adjusted by lease for energy content, transportation fees, and regional

price differentials. The fixed contract gas prices for Bacchus and Enoch Fields are held constant until contract expiration. At contract expiration, the prices are

adjusted to the spot price and held constant thereafter. All other gas prices are held constant throughout the lives of the properties. The average adjusted gas

price weighted by production over the remaining lives of the properties is $7.949 per MCF.

Operating costs used by Endeavour are based on historical operating expense records. These costs include the overhead expenses allowed under joint operating

agreements along with estimates of costs to be incurred at and below the district and field levels. Headquarters general and administrative overhead expenses of

Endeavour are included to the extent that they are covered under joint operating agreements for the operated properties. These costs have been divided into fixed

field costs and variable costs. The fixed field costs are allocated by well based on the proportionate share of total proved reserves. Estimates of proved

developed producing reserves and revenue are consequently dependent upon completion of the drilling and workover programs scheduled by Endeavour.

Capital costs used by Endeavour are based on business development plans and budgets presented in technical committee meetings. Capital costs are included

as required for workovers, new development wells, and production equipment. Abandonment costs used are Endeavour’s estimates of the costs to abandon the

wells, platforms, and production facilities, net of any salvage value. Operating costs are held constant throughout the lives of the properties, and capital costs

and abandonment costs are held constant to the date of expenditure.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which,

by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are

those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of

market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed

herein, estimates of Endeavour and NSAI are based on certain assumptions including, but not limited to, that the properties will be developed consistent with

current development plans, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that

would impact the ability of the interest owner to recover the reserves, and that projections of future production will prove consistent with actual performance. If

the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental

policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary

from assumptions made while preparing these estimates.

It should be understood that our audit does not constitute a complete reserves study of the audited oil and gas properties. Our audit consisted primarily of

substantive testing, wherein we conducted a detailed review of all properties. In the conduct of our audit, we have not independently verified the accuracy and

completeness of information and data furnished by Endeavour with respect to ownership interests, oil and gas production, well test data, historical costs of

operation and development, product prices, or any agreements relating to current and future operations of the properties and sales of production. However, if in

the course of our examination something came to our attention that brought into question the validity or sufficiency of any such information or data, we did not

rely on such information or data until we had satisfactorily resolved our questions relating thereto or had independently verified such information or data. Our

audit did not include a review of Endeavour’s overall reserves management processes and practices.
We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, analogy, and

reservoir modeling, that we considered to be appropriate and necessary to establish the conclusions set forth herein. As in all aspects of oil and gas evaluation,

there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed

professional judgment.

Supporting data documenting this audit, along with data provided by Endeavour, are on file in our office. The technical persons responsible for conducting

this audit meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. We are independent

petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

Sincerely,

NETHERLAND, SEWELL & ASSOCIATES, INC.

Texas Registered Engineering Firm F-2699

/s/ C.H. (Scott) Rees III

By:

C.H. (Scott) Rees III, P.E.

Chairman and Chief Executive Officer

 /s/ Derek F. Newton /s/ David E. Nice /s/ John R. Cliver

By: By: By: 

 Derek F. Newton David E. Nice John R. Cliver

 Texas P.E. 97689 Texas P.G. 346 Louisiana P.E. 37090

 Vice President Vice President Petroleum Engineer

Date Signed: February 12, 2013 Date Signed: February 12, 2013 Date Signed: February 12, 2013

DFN:JLM

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients.

The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the

parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original

document, the original document shall control and supersede the digital document.
Exhibit 99.2

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders of

Endeavour Energy UK Limited

We have audited the accompanying consolidated balance sheet of Endeavour Energy UK Limited and subsidiary as of December 31, 2012 and the related

consolidated statements of operations, stockholders’ equity and cash flows for the year then ended. These financial statements are the responsibility of the

Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our 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 the financial statements are free of material misstatement. We were not engaged to

perform an audit of the Company’s internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a

basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the

Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence

supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management,

and evaluating the overall financial statement presentation. We believe that our audit provides 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 Energy UK

Limited and subsidiary at December 31, 2012 and the consolidated results of their operations and their cash flows for the year then ended, in conformity with

U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Houston, Texas

March 18, 2013
Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Endeavour Energy UK Limited:

We have audited the accompanying consolidated balance sheet of Endeavour Energy UK Limited and subsidiary as of December 31, 2011 and the related

consolidated statements of operations, stockholders’ equity and cash flows for each of the years in the two-year period ended December 31, 2011. These

consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated

financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that

we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit

includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the

accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that

our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Endeavour Energy UK

Limited and subsidiary as of December 31, 2011, and the results of their operations and their cash flows for each of the years in the two-year period ended

December 31, 2011, in conformity with U.S. generally accepted accounting principles.

(signed) KPMG LLP

Houston, Texas

January 24, 2013, except for Note 2 and 10, as to which date is March 18, 2013
Endeavour Energy UK Limited

Consolidated Balance Sheets

(Amounts in thousands)

 December 31,

 2012 2011

Assets 

Current Assets: 

Cash and cash equivalents $ 31,311 $ 103,031

Restricted cash 128 — 

Accounts receivable 43,356 4,508

Current receivables due from affiliates 121,751 60,864

Prepaid expenses and other current assets 20,487 17,711

Total Current Assets 217,033 186,114

Property and Equipment, Net ($273,298 and $183,110 not subject to amortization at 2012 and 2011, respectively) 910,749 421,457

Goodwill 262,764 211,886

Long-term receivables due from affiliates — 57,250

Other Assets 16,357 17,600

Total Assets $1,406,903 $ 894,307

See accompanying notes to consolidated financial statements.

3
Endeavour Energy UK Limited

Consolidated Balance Sheets

(Amounts in thousands)

 December 31,

 2012 2011

Liabilities and Stockholders’ Equity 

Current Liabilities: 

Accounts payable $ 57,531 $ 44,620

Current liabilities due to affiliates 96,882 105,920

Current maturities of debt 15,713 2,350

Accrued expenses and other 60,970 10,862

Total Current Liabilities 231,096 163,752

Long-Term Debt 99,450 237,999

Long-Term Liabilities due to Affiliates 500,000 — 

Deferred Taxes 141,887 108,762

Other Liabilities 139,728 44,894

Total Liabilities 1,112,161 555,407

Commitments and Contingencies 

Stockholders’ Equity: 

Common stock; shares issued and outstanding - 1,400 and 1,400 shares at 2012 and 2011, respectively — — 

Additional paid-in capital 342,846 342,846

Accumulated deficit, as adjusted (48,104) (3,946) 

Total Stockholders’ Equity 294,742 338,900

Total Liabilities and Stockholders’ Equity $ 1,406,903 $ 894,307

See accompanying notes to consolidated financial statements.

4
Endeavour Energy UK Limited

Consolidated Statement of Operations

(Amounts in thousands)

 Year Ended December 31,

 2012 2011 2010

Revenues $ 207,181 $ 41,754 $ 60,501

Cost of Operations: 

Operating expenses 51,568 8,622 11,086

Depreciation, depletion and amortization 57,961 14,988 22,692

General and administrative 8,479 4,756 4,195

Total Expenses 118,008 28,366 37,973

Income From Operations 89,173 13,388 22,528

Other Income (Expense): 

Derivatives: 

Realized gains (losses) — — (11,753) 

Unrealized gains (losses) (3,524) (3,050) 10,943

Interest expense (60,735) (30,990) (22,676) 

Letter of credit fees (21,903) — — 

Loss on early extinguishment of debt (21,661) — — 

Gain on sale of reserves in place — — 87,171

Interest income and other (4,309) 10,847 3,946

Total Other Income (Expense) (112,132) (23,193) 67,631

Income (Loss) Before Income Taxes (22,959) (9,805) 90,159

Income Tax Expense 21,199 27,042 345

Net Income (Loss) $ (44,158) $(36,847) $ 89,814

See accompanying notes to consolidated financial statements.

5
Endeavour Energy UK Limited

Consolidated Statement of Cash Flows

(Amounts in thousands)

 Year Ended December 31,

 2012 2011 2010

Cash Flows from Operating Activities: 

Net income (loss) $ (44,158) $ (36,847) $ 89,814

Adjustments to reconcile net income (loss) to net cash provided by operating activities: 

Depreciation, depletion and amortization 57,961 14,988 22,692

Deferred tax expense (benefit) (10,597) 21,116 (2,388) 

Unrealized (gains) losses on derivatives 3,524 3,050 (10,943) 

Gain on sales of reserves in place — — (87,171) 

Amortization of loan costs and discount 6,745 9,662 5,499

Non-cash interest expense 1,823 5,953 1,771

Loss on early extinguishment of debt 21,661 — — 

Other 14,910 1,495 (2,375) 

Changes in operating assets and liabilities: 

(Increase) decrease receivables (25,813) 1,066 7,561

(Increase) decrease prepaids 8,631 (16,384) (1,013) 

Increase (decrease) in liabilities (21,754) 12,691 64,838

Net cash provided by operating activities 12,933 16,790 88,285

Cash Flows From Investing Activities: 

Capital expenditures (207,131) (86,503) (57,972) 

Acquisitions, net of cash acquired (236,482) (25,048) (1,184) 

Issuance of note receivable to affiliates — — (57,250) 

Proceeds from sales, net of cash 1,407 — 108,316

Change in restricted cash (128) 31,726 (31,347) 

Net cash (used in) investing activities (442,334) (79,825) (39,437) 

Cash Flows From Financing Activities: 

Repayments of borrowings (124,658) (1,975) (201,565) 

Borrowings under debt agreements, net of debt discount — 75,000 185,000

Borrowings from affiliates 500,000 — — 

Proceeds from issuance of common stock — — 65,996

Financing costs paid (10,413) (5,475) (26,590) 

Other financing (7,247) — — 

Net cash provided by financing activities 357,681 67,550 22,841

Net increase (decrease) in cash (71,720) 4,515 71,689

Cash and Cash Equivalents, Beginning of Period 103,031 98,516 26,827

Cash and Cash Equivalents, End of Period $ 31,311 $ 103,031 $ 98,516

See accompanying notes to consolidated financial statements.

6
Endeavour Energy UK Limited

Consolidated Statement of Stockholders’ Equity

(Amounts in thousands)

 

Common

Stock 

Additional

Paid-In

Capital 

Retained

Earnings

(Deficit)

Total

Stockholders’

Equity

Balance, January 1, 2010 $ — $181,168 $(56,913) $124,255

Common stock issuance — 161,678 — 161,678

Net Income — — 89,814 89,814

Balance, December 31, 2010 $ — $ 342,846 $ 32,901 $ 375,747

Net Loss — — (36,847) (36,847) 

Balance, December 31, 2011 $ — $ 342,846 $ (3,946) $ 338,900

Net Loss — — (44,158) (44,158) 

Balance, December 31, 2012 $ — $ 342,846 $ (48,104) $ 294,742

See accompanying notes to consolidated financial statements.

7
Endeavour Energy UK Limited

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

Note 1 – General

Description of Business

Endeavour Energy UK Limited is an independent oil and gas company engaged in the exploration, development, production and acquisition of energy reserves

in the U.K. As used in these Notes to Consolidated Financial Statements, the terms “EEUK”, “we”, “us”, “our” and similar terms refer to Endeavour Energy

UK Limited and, unless the context indicates otherwise, its consolidated subsidiaries. EEUK was incorporated in England and Wales and is a wholly-owned

subsidiary of Endeavour International Corporation (“EIC”).

2013 Liquidity and Capital Resources

As of December 31, 2012, we had $115 million in outstanding indebtedness to third parties and $500 million in outstanding indebtedness to affiliates. Being

highly leveraged, servicing our debt and other long-term obligations will continue to require a significant portion of our cash flow from operations and available

cash on hand. The combination of these debt servicing requirements, capital expenditures and the delay in cash flow resulting from the Rochelle mechanical

issues may exceed the cash flow from our current operations. Ultimately, our primary uses and sources of financial resources will be impacted by the outcome

of our strategic review.

During 2013, our primary uses of financial resources are expected to be:

• our capital expenditures, primarily related to our drilling activities at our Alba, Bacchus and Rochelle fields in the U.K.; and

• interest payments on existing credit facilities and payments in support of our reimbursement agreements covering our abandonment obligations.

We believe we will be able to fund operations for the foreseeable future including our capex and other expenditure requirements based on our projections of

funds generated from operations, cash available and existing sources of financing. Since year-end 2012, we have also completed several transactions to

improve our liquidity position and extended the maturities of some of our debt and other obligations. The completion of these recent financing activities are

designed to provide sufficient liquidity to bring the Rochelle development on line, drill a third well at Bacchus and allow sufficient time for a thoughtful and

disciplined strategic review process. These transactions include:

• extending or replacing reimbursement agreements covering certain of our abandonment liabilities in the U.K. which would have expired in 2013;

• entering into a forward sale agreement;

• entering into a sale and purchase agreement providing for the sale and purchase of a production payment; and

• extending the maturity of a majority of the commitments under our revolving credit facility.

8
Endeavour Energy UK Limited

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

If we are unable to meet any short-term liquidity needs out of cash on hand, we would attempt to refinance debt, sell forward our production, sell assets, issue

debt or equity or perform any other alternatives resulting from our strategic review.

Summary of Significant Accounting Policies

Basis of Presentation and Use of Estimates

The accompanying financial statements have been prepared on the accrual basis of accounting in accordance with accounting principles generally accepted in

the United States of America (“US GAAP”) and have been presented on a going concern basis, which contemplates the realization of assets and satisfaction of

liabilities in the normal course of business. In the opinion of management, all normal recurring adjustments considered necessary for a fair presentation have

been included in these financial statements. Certain amounts for prior periods have been reclassified to conform to the current presentation.

These accounting principles require management to use estimates, judgments and assumptions that affect the amounts of assets, liabilities, revenues and

expenses reported herein. While management 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.

Our financial statements include allocations of general, administrative costs of EIC that are attributable to our operations and use of centralized general and

administrative services. Management believes the assumptions and allocations underlying the combined financial statements are reasonable. However, these

combined financial statements do not include all of the actual expenses that would have been incurred had we been a stand-alone entity during the periods

presented and do not reflect our results of operations, financial position and cash flows had we been a stand-alone company during the periods presented.

9
Endeavour Energy UK Limited

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

Principles of Consolidation

The accompanying consolidated financial statements include all of the accounts of EEUK and our consolidated subsidiaries. All significant intercompany

accounts and transactions have been eliminated. Investments in entities over which we have significant influence, but not control, are carried at cost adjusted

for equity in earnings or (losses) and distributions received.

Cash and Cash Equivalents

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

Restricted Cash

Restricted cash has historically included amounts held in escrow for drilling rig commitments, as collateral for lines of credit, and for acquisitions.

Inventories

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

Full Cost Accounting for Oil and Gas Operations

Under the full cost method of accounting for oil 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, 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.

10
Endeavour Energy UK Limited

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

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.

Unproved property costs include the costs associated with unevaluated properties and properties under development and are not initially included in the full

cost amortization base (where proved reserves exist) until the project is evaluated. These costs include unproved leasehold acreage, seismic data, wells and

production facilities in progress and wells pending determination, together with interest costs capitalized for these projects. Seismic data costs are associated

with specific unevaluated properties where the seismic data is acquired for the purpose of evaluating acreage or trends covered by a leasehold interest owned by

us.

Significant unproved properties are assessed periodically for possible impairment or reduction in value. If a reduction in value has occurred, these property

costs are considered impaired and are transferred to the related full cost pool. Geological and geophysical costs included in unproved properties are transferred

to the full cost amortization base along with the associated leasehold costs on a specific project basis. Costs associated with wells in progress and wells

pending determination are transferred to the amortization base once a determination is made whether or not proved reserves can be assigned to the property.

Costs of dry holes are transferred to the amortization base immediately upon determination that the well is unsuccessful. Unproved properties whose

acquisition costs are not individually significant are aggregated and the portion of such costs estimated to be ultimately nonproductive, based on experience,

are amortized to the full cost pool over an average holding period.

In countries where the existence of proved reserves has not yet been determined, unevaluated property costs remain capitalized in unproved property cost

centers until proved reserves have been established, exploration activities cease or impairment and reduction in value occurs. If exploration activities result in

the establishment of a proved reserve base, amounts in the unproved property cost center are reclassified as proved properties and become subject to

amortization and the application of the ceiling test. When it is determined that the value of unproved property costs have been permanently diminished (in part

or in whole) based on the impairment evaluation and future exploration plans, the unproved property cost centers related to the area of interest are impaired,

and accumulated costs charged against earnings.

Other Property and Equipment

Other oil and gas assets, computer equipment and furniture and fixtures are recorded at cost, less accumulated depreciation. The assets are depreciated using

the straight-line method over their estimated useful lives of two to five years.

11
Endeavour Energy UK Limited

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

Capitalized Interest

We capitalize interest on expenditures for significant exploration and development projects while activities are in progress to bring the assets to their intended

use. Capitalized interest is calculated by multiplying our weighted-average interest rate on debt by the amount of qualifying costs and is limited to gross interest

expense.

Business Combinations

Assets and liabilities acquired through a business combination are recorded at estimated fair value. We use all available information to make these fair value

determinations, including information commonly considered by our engineers in valuing individual oil and gas properties and sales prices for similar assets.

Estimated deferred taxes are based on available information concerning the tax basis of the acquired company’s assets and liabilities and carryforwards at the

merger date.

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

the amounts assigned to assets and liabilities over the acquisition of the acquired business is recorded as a gain on acquisition on the income statement. The

amount of goodwill recorded in any particular business combination can vary significantly depending upon the fair values attributed to assets acquired and

liabilities assumed relative to the total acquisition cost.

Goodwill and Intangible Assets

We assess the carrying amount of goodwill and other indefinite-lived intangible assets by testing the asset for impairment annually at year-end, or more

frequently if events or changes in circumstances indicate that the asset might be impaired. The impairment test requires allocating goodwill and all other assets

and liabilities to reporting units. The fair value of each reporting unit is determined and compared to the book value of the reporting unit. An impairment loss

is recognized to the extent that the carrying amount exceeds the asset’s fair value.

Dismantlement, Restoration and Environmental Costs

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

and natural gas processing plants, with a corresponding increase in the related long-lived asset. The asset retirement cost is depreciated along with the property

and equipment in the full cost pool. The asset retirement 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.

12
Endeavour Energy UK Limited

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

We utilize EIC’s credit adjustment to the risk-free interest rate in determining the fair value of our estimated asset retirement obligation as EIC could also be

held responsible for satisfying the obligation.

Revenue Recognition

We use the entitlements method to account for sales of gas production. We may receive more or less than our entitled share of production. Under the

entitlements method, if we receive more than our entitled share of production, the imbalance is treated as a liability at the market price at the time the imbalance

occurred. If we receive less than our entitled share, the imbalance is recorded as an asset at the lower of the current market price or the market price at the time

the imbalance occurred. Oil revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred, title

has transferred and collectability of the revenue is probable.

Significant Customers

Our sales are to a limited number of customers, each of which accounted for more than 10% of revenue for the year ended December 31, 2012: Chevron North

Sea Ltd and Shell U.K. Limited.

Derivative Instruments and Hedging Activities

From time to time, we may utilize derivative financial instruments to hedge cash flows from operations or to hedge the fair value of financial instruments.

We may use derivative financial instruments with respect to a portion of our oil and gas production or a portion of our variable rate debt to achieve a more

predictable cash flow by reducing our exposure to price fluctuations. These transactions are likely to be swaps, collars or options and to be entered into with

major financial institutions or commodities trading institutions. Derivative financial instruments are intended to:

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

• 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, 2012 and 2011, we had no

outstanding derivatives that were accounted for as a hedge.

13
Endeavour Energy UK Limited

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

Where we intend to account for a derivative as a hedge, we document, at its inception, the hedging relationship, the risk management objective and the strategy

for undertaking the hedge. The documentation includes the identification of the hedging instrument, the hedged item or transaction, the nature of the risk being

hedged, and the method that will be used to assess effectiveness of derivative instruments that receive hedge accounting treatment.

Changes in fair value to hedge instruments, to the extent the hedge is effective, are recognized in other comprehensive income until the forecasted transaction

occurs. Hedge effectiveness is assessed at least quarterly based on total changes in the derivative’s fair value. Any ineffective portion of the derivative

instrument’s change in fair value is recognized immediately in other (income) expense.

We discontinue hedge accounting prospectively when: (1) we determine that the derivative is no longer effective in offsetting changes in the fair value or cash

flows of a hedged item (including hedged items such as firm commitments or forecasted transactions); (2) the derivative expires; (3) it is no longer probable

that the forecasted transaction will occur; (4) a hedged firm commitment no longer meets the definition of a firm commitment; or (5) management determines

that designating the derivative as a hedging instrument is no longer appropriate.

Concentrations of Credit and Market Risk

Financial instruments that potentially subject us to concentrations of credit risk consist principally of cash deposits at financial institutions. At various times

during the year, we may exceed the federally insured limits. To mitigate this risk, we place our cash deposits only with high credit quality institutions.

Management believes the risk of loss is minimal.

Derivative financial instruments that hedge the price of oil and gas, interest rates or currency exposure will be generally executed with major financial or

commodities trading institutions which expose us to market and credit risks, and may at times be concentrated with certain counterparties or groups of

counterparties. Although notional amounts are used to express the volume of these contracts, the amounts potentially subject to credit risk, in the event of nonperformance by the counterparties, are substantially smaller. We review the credit ratings of our counterparties to derivative contracts on a regular basis and to

date we have not experienced any non-performance by any of our various counterparties.

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

14
Endeavour Energy UK Limited

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

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 operations with the U.S. dollar as the functional currency, monetary assets and liabilities are remeasured into U.S. dollars at

the exchange rate on the balance sheet date. Nonmonetary assets and liabilities are translated into U.S. dollars at historical exchange rates. Income and expense

items are translated at exchange rates prevailing during each period. Adjustments are recognized currently as a component of foreign currency gain or loss and

deferred income taxes. To the extent that business transactions are not denominated in U.S. dollars, we are exposed to foreign currency exchange rate risk.

Income Taxes

We use the liability method of accounting for income taxes under which deferred tax assets and liabilities are recognized for the estimated future tax

consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities, and their respective tax bases.

Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or

settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized as part of the provision for income taxes in the period that includes

the enactment date. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion

of, or all of, the deferred tax assets will not be realized.

Share-Based Payments

EIC grants restricted stock and stock options of its stock to our employees and directors as incentive compensation. We recognize all share-based payments to

employees, including grants of employee stock options, based on their fair values. The share-based compensation cost is measured at the grant date, based on

the calculated fair value of the award, and is recognized as general and administrative expense over the employee’s requisite service period (generally the vesting

period of the equity award). We apply the fair value method in accounting for stock option grants using the Black-Scholes Method.

Note 2 – Revision of prior period financial statements

During 2012, we identified an overstatement of our deferred tax liabilities of $7.0 million. The overstatements resulted from differences between GAAP income

and taxable income that had accumulated over several prior periods. We corrected this overstatement, decreasing our deferred tax liability and accumulated

deficit in our consolidated balance sheet by $7.0 million as of December 31, 2011.

15
Endeavour Energy UK Limited

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

In evaluating whether our previously issued consolidated financial statements were materially misstated, we considered the guidance in ASC 250, Accounting

Changes and Error Corrections, SAB Topic 1.M, Assessing Materiality, and SAB Topic 1.N, Considering the Effects of Prior Year Misstatements when

Quantifying Misstatements in Current Year Financial Statements. We concluded these errors were not material individually or in the aggregate to any of the

prior reporting periods, and therefore, amendments of previously filed reports were not required. As such, the revisions for these corrections to the applicable

prior periods are reflected in the financial information herein and will be reflected in future filings containing such financial information. The consolidated

statement of stockholders’ equity was revised to reflect the cumulative effect of these adjustments resulting in an increase to retained earnings and total

stockholders’ equity of $7.0 million which is reflected in the beginning balance as of January 1, 2010.

The prior period financial statements included in this filing have been revised to reflect the corrections of these errors, the effects of which have been provided

in summarized format below.

Revised consolidated balance sheet amounts:

 As of December 31, 2011

 

As Previously

Reported Adjustment As Revised

Deferred tax liability $115,759 $(6,997) $108,762 

Total liabilities 562,404 (6,997) 555,407 

Accumulated deficit (10,943) 6,997 (3,946) 

Total stockholders’ equity 331,903 6,997 338,900 

Adoption of New Accounting Standards

On January 1, 2012, we adopted the following new standards without material effects on our results of operations or financial position:

• Fair Value – An accounting standard on fair value measurements that clarifies the application of existing guidance and disclosure requirements,

changes certain fair value measurement principles and requires additional disclosures about fair value measurements.

• Comprehensive Income - Guidance impacting the presentation of comprehensive income eliminates the current option to report components of

other comprehensive income in the statement of changes in equity or in a footnote to the financial statements.

16
Endeavour Energy UK Limited

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

• Goodwill – Amendment to the the previously issued guidance on testing goodwill for impairment. The revised guidance provides entities with an

option of performing a qualitative assessment prior to calculating the fair value of the reporting unit.

Note 3 – Acquisitions

On December 23, 2011, we entered into a Sale and Purchase Agreement (the “Purchase Agreement”) with ConocoPhillips (U.K.) Limited, ConocoPhillips

Petroleum Limited and ConocoPhillips (U.K.) Lambda Limited, subsidiaries of ConocoPhillips (collectively, the “Sellers”), to acquire their interest in three

producing U.K. oil fields in the Central North Sea (the “COP Acquisition”).

On May 31, 2012, we closed a portion of the COP Acquisition consisting of an additional 23.43% interest in the Alba field increasing our total working interest

in the Alba field to 25.68%. The Alba field portion of the COP Acquisition was closed for aggregate cash consideration of approximately $229.6 million.

The acquisition of the additional interest in the Alba field was accounted for using the business combination method. The following summarizes the allocation

of the purchase price for the Alba field portion of the COP Acquisition:

Purchase price $ 255,400

Purchase price adjustments for estimated after-tax cash flows from the acquired asset

and interest costs from economic date of January 1, 2011 to closing (25,823) 

Total purchase price $229,577

Allocation of purchase price: 

Property and equipment $ 186,801

Goodwill 50,878

Current assets 24,632

Current liabilities (12,815) 

Deferred tax liability (5,818) 

Other long-term liabilities (14,101) 

Total purchase price $229,577

Goodwill was the excess of the consideration transferred over the net assets recognized and represents the future economic benefits arising from assets acquired

that could not be individually identified and separately recognized. The assessments of the fair values of oil and gas properties acquired were based on

projections of expected future net cash flows, discounted to present value.

17
Endeavour Energy UK Limited

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

The following table sets forth unaudited pro forma condensed combined financial and operating data which are presented to give effect to the Alba acquisition

as if it had occurred January 1, 2011. The information does not purport to be indicative of actual results, if any of these transactions had been in effect for the

periods indicated, or future results.

 Year Ended December 31,

 2012 2011

Revenues $279,697 $300,139

Net income (loss) $ (31,541) $(38,693) 

Revenues and income from operations associated with the acquired interest in the Alba field for the period from May 31, 2012 through December 31, 2012

were $ 119.7 million and $ 13.7 million, respectively.

After substantial effort and extensions, we and the Sellers were unable to reach the unanimous agreement and consent required to transfer the interests in the

two remaining U.K. oil fields due to failure to agree on certain commercial terms related to the future timing and amount of collateral required to be posted for

future decommissioning costs.

As a result of the parties being unable to reach agreement to enable the transfers to occur, the Purchase Agreement terminated in accordance with its terms on

December 14, 2012. As previously disclosed, we paid a $10 million deposit in connection with the acquisition of the interests in the two remaining fields,

which ConocoPhillips retained.

18
Endeavour Energy UK Limited

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

Note 4 – Prepaid Expenses and Other Current Assets

Prepaid expenses and other current assets consisted of the following:

 December 31,

 2012 2011

Fair market value of commodity derivatives – current

 $ — $ 1,247

Prepaid well and drilling costs 2,798 2,240

Prepaid insurance 3,288 1,303

Inventory 5,127 1,622 

Deposits and other costs related to the Alba Acquisition — 9,064

Deferred tax asset 8,089 — 

Other 1,185 2,235 

 $20,487 $17,711

Note 5 – Property and Equipment

Property and equipment included the following:

 December 31,

 2012 2011

Oil and gas properties under the full cost method: 

Subject to amortization $ 876,536 $ 429,246

Not subject to amortization: 

Acquired in 2012 126,128 — 

Acquired in 2011 89,118 99,794

Acquired in 2010 10,106 14,101

Acquired prior to 2010 47,946 69,215

 1,149,834 612,356

Computers, furniture and fixtures 5,505 3,232

Total property and equipment 1,155,339 615,588

Accumulated depreciation, depletion and amortization (244,590) (194,131) 

Net property and equipment $ 910,749 $ 421,457

The costs not subject to amortization include

• values assigned to unproved reserves acquired,

• exploration costs such as drilling costs for projects awaiting approved development plans or the determination of whether or not proved reserves

can be assigned, and

• other seismic and geological and geophysical costs.

19
Endeavour Energy UK Limited

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

These costs are transferred to the amortization base when it is determined whether or not proved reserves can be assigned to such properties. This analysis is

dependent upon well performance, results of infield drilling, approval of development plans, drilling results and development of identified projects and

periodic assessment of reserves. We expect acquisition costs excluded from amortization to be transferred to the amortization base over the next five years due to

a combination of well performance and results of infield drilling relating to currently producing assets and the drilling and development of identified projects

acquired, such as the Rochelle field. We expect exploration costs not subject to amortization to be transferred to the amortization base over the next three years

as development plans are completed and production commences on existing discoveries.

The following is a summary of our oil and gas properties not subject to amortization as of December 31, 2012:

 Costs Incurred in the Year Ended December 31,

 2012 2011 2010 Prior to 2010 Total

Acquisition costs $ 46,819 $45,975 $ — $ 8,198 $100,992

Exploration costs 60,595 42,833 10,106 39,747 153,281

Capitalized interest 18,714 310 — 1 19,025

Total oil and gas properties not subject to amortization $126,128 $89,118 $10,106 $ 47,946 $273,298

During 2012, 2011 and 2010, we capitalized $11.7 million, $7.7 million and $9.1 million, respectively, in certain directly related employee costs. During

2012, 2011 and 2010, we capitalized $24.2 million, $10.1 million and $2.0 million, respectively, in interest.

Asset Acquisitions

On February 23, 2011, we closed our acquisition of an additional 20% working interest in the Bacchus field for approximately $9.2 million in cash paid at

closing and approximately $6.2 million in cash paid in 2012. In addition, we paid capital costs incurred by the seller of $9.4 million. Following the

acquisition, we hold an aggregate 30% working interest in the Bacchus field.

Business Combination

On May 31, 2012, we closed the Alba Acquisition, which consisted of an additional 23.43% interest in the Alba field. This increased our total working interest

in the Alba field to 25.68%.

20
Endeavour Energy UK Limited

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

Asset Disposition

On October 19, 2010, we completed the sale of our Cygnus field for $110 million in cash, and recorded a gain of $87 million. The cash proceeds were not

burdened by any current taxes payable and were primarily used to accelerate our development projects.

Note 6 – 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.

 December 31,

 2012 2011

Balance at beginning of year

 $211,886 $211,886

Additions related to acquisitions 50,878 — 

Balance at end of year $262,764 $211,886

Note 7 – Other Assets

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

 2012 2011

Debt issuance costs $ 4,949 $17,482

Deferred issuance costs related reimbursement agreements 11,290 — 

Other 118 118

 $16,357 $17,600

Debt issuance costs and deferred issuance costs related to reimbursement agreements are amortized over the life of the related obligations. See Note 9 and Note

19 for additional discussion.

21
Endeavour Energy UK Limited

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

Note 8 – Accrued Expenses

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

 December 31,

 2012 2011

Foreign taxes payable $18,924 $ 406

Accrued compensation 797 760

Current portion of asset retirement obligations 36,144 2,078

Development asset accrual — 6,160

Other 5,105 1,458

 $60,970 $10,862

Note 9 – Debt Obligations

Our debt consisted of the following at December 31:

 2012 2011

Senior term loan, 15% fixed rate, due 2013 $ — $ 240,349

Revolving credit facility, 13% fixed rate, due 2014 115,163 — 

Less: current maturities (15,713) (2,350) 

Long-term debt $ 99,450 $237,999

Standby letters of credit outstanding for abandonment liabilities $ — $ 31,724

Principal maturities of debt at December 31, 2012 are as follows:

2013 $15,713

2014 99,450

Thereafter — 

Senior Term Loan

In August 2010, we entered into a credit agreement with Cyan Partners, LP (“Cyan”), as administrative agent, and various lenders for the Senior Term Loan,

in the aggregate amount of $150 million, which was subsequently increased to $235 million. We paid $25.4 million in

22
Endeavour Energy UK Limited

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

financing costs related to the issuance of the Senior Term Loan. In May 2012, we repaid all amounts outstanding under Senior Term Loan. This repayment

included a prepayment fee of approximately $7 million. Following the repayment the Senior Term Loan was terminated and all of the liens on the collateral

securing our obligations were released.

Revolving Credit Facility

On April 12, 2012, we entered into a $100 million Credit Agreement (the “Revolving Credit Facility”), with Cyan, as administrative agent, and borrowed $40

million. The Revolving Credit Facility matures on October 12, 2013.

Prior to the termination of the Senior Term Loan, the closing of the Alba Acquisition and certain other conditions, borrowings under the Revolving Credit

Facility were limited to $40 million and incurred interest at a rate of 12% per year, with an additional 3% payment-in-kind. After the termination of the Senior

Term Loan and the closing of the Alba Acquisition, borrowings under the Revolving Credit Facility bear interest at a rate of 13% per year.

On May 31, 2012, we entered into a First Amendment to the Revolving Credit Facility, providing for an increase in the amount available for borrowing under

the Revolving Credit Facility from $40 million to $100 million upon closing of the acquisition of the Alba Acquisition. In connection with the closing of the

Alba Acquisition, we drew down the additional $60 million available for borrowing. The First Amendment to the Revolving Credit Facility contained certain

amendments allowing us to enter certain reimbursement agreements discussed in Note 19.

On September 27, 2012, we increased the amount available for borrowing under the Revolving Credit Facility to $125 million. In connection with the

increase, we agreed to pay a fee of $1.25 million to Cyan Partners, LP. The Founding Partner and Chief Investment Officer of Cyan Partners, LP was a

member of EIC’s Board of Directors until he resigned in March 2013.

On September 28, 2012, we borrowed an additional $15 million under the Revolving Credit Facility.

Subsequent to December 31, 2012, we amended the Revolving Credit Facility to extend the maturity date of $100 million of the facility to June 30, 2014. See

Note 20 “Subsequent Events” for additional discussion.

Fair Value

The fair value of our outstanding debt obligations was $122 million and $237 million at December 31, 2012 and 2011, respectively. The fair values of longterm debt were determined based upon discounted cash flows for our debt, which results in a Level 3 fair-value measurement.

23
Endeavour Energy UK Limited

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

Letter of Credit Agreement

In July 2011, we entered into a letter of credit facility agreement with Commonwealth Bank of Australia (“CBA”), pursuant to which CBA issued letters of

credit to us in the amount of £20.6 million (approximately $35 million upon issuance). The letters of credit secured decommissioning obligations in

connection with certain of our United Kingdom Continental Shelf Petroleum Production Licenses. Concurrent with the issuance of the letters of credit, prior

restrictions on £20.6 million of our restricted cash were removed and the cash returned for general corporate purposes. We terminated this letter of credit

facility agreement in May 2012.

Note 10 – Income Taxes

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

follows:

 2012 2011 2010

Net income (loss) before taxes $(22,959) $ (9,805) $90,159

Current tax expense 31,796 5,926 2,733

Deferred tax expense related to U.K. tax rate change 8,587 25,424 — 

Deferred tax benefit (19,184) (4,308) (2,388) 

Total tax expense 21,199 27,042 345

Net income (loss) after taxes $ (44,158) $(36,847) $ 89,814

Effective Tax Rate Reconciliation

The following table presents the principal reasons for the difference between our effective tax rates and the United Kingdom statutory income tax rate of 50% in

2010 and 62% in 2011 and 2012.

24
Endeavour Energy UK Limited

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

 Year Ended December 31,

 2012 2011 2010

U.K. tax at statutory rate $ (14,235) $ (6,079) $ 45,080

Non-taxable income — — (54,158) 

PRT tax 6,399 2,141 727

Non-deductible interest expense 44,758 12,897 10,710

Ring fence expenditure supplement (25,918) (7,268) (1,844) 

U.K. Tax increase from tax law change 8,587 25,424 — 

Other / non-deductible costs 1,608 (73) (170) 

Total Income Tax Expense $ 21,199 $ 27,042 $ 345

Effective Income Tax Rate -92% -276% 0% 

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. The tax effects of temporary differences that give rise to significant portions of

deferred tax assets and liabilities are as follows at December 31:

 2012 2011

Deferred tax asset: 

Deferred compensation $ 357 $ 956

Unrealized loss on commodity derivative instruments — 1,260

Asset retirement obligation 87,787 29,122

Net operating loss and capital loss carryforward 271,392 119,592

Inventory / other 8,089 — 

Total deferred tax assets 367,625 150,930

Deferred tax liability: 

Property, plant and equipment (478,720) (258,779) 

Petroleum revenue tax, net of tax benefit (22,703) (229) 

Other — (684) 

Total deferred tax liabilities (501,423) (259,692) 

Net deferred tax liability $(133,798) $ (108,762) 

25
Endeavour Energy UK Limited

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

Tax Attributes

At December 31, 2012, we had the following tax attributes available to reduce future income taxes:

 As of December 31,

 2012 2011

 

Types of

Tax

Attributes 

Years of

Expiration 

Carryforward

Amount 

Years of

Expiration 

Carryforward

Amount

U.K. 

Corporate tax NOL Indefinite $500,798 Indefinite $ 228,701

Supplemental Corporate tax NOL Indefinite 378,602 Indefinite 159,316

As of December 31, 2012, the U.K. tax attributes shown above have been recognized for financial statement reporting purposes to reduce deferred tax liability.

Uncertain Tax Positions

At December 31, 2012, we have an unrecognized tax benefit of $6.8 million relating to various U.K. tax matters. Any interest and penalties that may be

incurred as part of this benefit would be recognized as a component of interest expense and other expense, respectively. As of December 31, 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, 2012.

 Year Ended

 December 31,

 2012 2011 2010 

Balance at the beginning of the year

 $ — $— $— 

Increase in unrecognized tax benefits from current period tax position 6,820 — — 

Balance at the end of the year $6,820 $— $— 

As of December 31, 2012, we believe that no current tax positions that have resulted in unrecognized tax benefits will significantly increase or decrease within

the next year. If recognized, none of the unrecognized tax benefits would have an impact on our effective tax rate.

26
Endeavour Energy UK Limited

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

The following tax years remain subject to examination:

Tax Jurisdiction 

U.K. 2011-2012 

Note 11 – Other Liabilities

Other liabilities included the following:

 December 31,

 2012 2011

Asset retirement obligations $ 139,431 $44,894

Other 297 — 

Total Other Liabilities $139,728 $44,894

Other liabilities included our asset retirement obligations related to 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, 2012 and 2011:

27
Endeavour Energy UK Limited

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

 Year Ended

 December 31,

 2012 2011

Carrying amount of asset retirement obligations, beginning of year

 $ 46,972 $ 42,741

Increase due to revised estimates 102,272 14,614

Accretion expense (included in DD&A expense) 7,502 4,443

Impact of foreign currency exchange rate changes 3,019 430

Payments of asset retirement obligations (8,521) (15,256) 

Liabilities incurred and assumed 24,331 — 

Asset retirement obligations, end of year 175,575 46,972

Less: current portion of asset retirement obligations (36,144) (2,078) 

Long-term asset retirement obligations $ 139,431 $ 44,894

Note 12 – Equity

Common Stock

The Common Stock is £0.10 par value common stock, 10,000 shares authorized.

Endeavour Energy North Sea L.P. (EENSLP) is the immediate parent company. In October of 2009, EENSLP acquired an additional 100 ordinary shares of

the company at a premium of $0.7 million per share.

In 2010, EENSLP subscribed for an additional 200 ordinary shares of the company for approximately $161 million. The company used the proceeds to

repay amounts due to EIHBV and for general corporate purposes.

Note 13 – Stock-Based Compensation Arrangements

EIC grants restricted stock, stock options and performance-based share awards to our employees and directors as incentive compensation. This stock-based

compensation generally vests over three years and EIC bills us for its cost of the awards over the vesting schedule. 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.

For the year ended December 31, 2012, we included approximately $0.6 million of stock-based compensation in capitalized G&A in property and equipment.

28
Endeavour Energy UK Limited

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

Stock-based compensation is recorded in G&A expenses or capitalized G&A as follows:

 Year Ended

 December 31,

 2012 2011 2010

G&A Expenses $229 215 116

Capitalized G&A 347 192 149

Total stock-based compensation $576 $ 407 $265

Note 14 – Amounts due to/from Affiliates

Our amounts due (to) from affiliates consisted of the following at December 31:

 2012 2011

Assets: 

Current receivables due from affiliates $ 121,751 $ 60,864

Note receivables due from affiliates — 57,250

 $ 121,751 $ 118,114

Liabilities: 

Current payables due to affiliates $ (96,882) $(105,920) 

Note payables due to affiliates (500,000) — 

 $(596,882) $(105,920) 

Current Receivables (Payables) due from (to) Affiliates

We record current receivables from and payables to our affiliates in the ordinary course of business. The amounts payable to and receivable from our affiliates

do not bear interest and have no set maturity date.

Notes Receivable due from Affiliates

On January 1, 2010, we executed an unsecured revolving loan facility (the “EOC Note Receivable”) with a group undertaking, Endeavour Operating

Corporation (“EOC”), the parent company of EEUK, as borrower. The EOC Note Receivable has a principal amount of $100 million, of which $57.3 million

was outstanding at December 31, 2011 and 2010. The EOC Note Receivable was repaid in full during 2012.

29
Endeavour Energy UK Limited

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

Notes Payable due to Affiliates

On May 31, 2012, we entered into a $550 million unsecured Revolving Intercompany Loan Agreement with EOC (“EOC Intercompany Loan”) in conjunction

with the repayment of the Senior Term Loan and the closing of the Alba field portion of the COP Acquisition. We may borrow up to the maximum principal

amount of the facility, at the discretion of EOC. At December 31, 2012, we had $500 million outstanding under the facility. We may drawdown one or more

advances, subject to approval by EOC, and may repay any advance, in whole or in part, at any time prior to its maturity, December 31, 2017. Interest will be

paid semi-annually at a rate consistent with EIC’s weighted average cost of funds, as determined by EOC. This rate is determined on each semi-annual interest

payment date. As of December 31, 2012, the interest rate was 12% per annum.

Note 15 – Supplementary Cash Flow Disclosures

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

 Year Ended December 31,

 2012 2011 2010

Interest paid $29,805 $23,805 $8,743

Income taxes paid (refunded) $ 426 $ 9,427 $ (172) 

Non-Cash Investing and Financing Transactions

In 2012, 2011 and 2010, we recorded $1.8 million, $6.0 million and $1.8 million, respectively, in non-cash interest expense that was added to the principal

balance of the Senior Term Loan.

Note 16 – Financial Instruments

 December 31, December 31,

 2012 2011

 Fair Value 

Carrying

Value Fair Value 

Carrying

Value

Assets: 

Derivative instruments $ — $ — $ 1,247 $ 1,247

Liabilities: 

Debt 121,576 115,163 236,945 240,349

30
Endeavour Energy UK Limited

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

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 were determined based upon quotes obtained from

brokers. The fair values of long-term debt were determined based upon discounted cash flows for our other debt.

Note 17 – Fair Value Measurements

We measure the fair value of financial assets and liabilities on a recurring basis, defining fair value as the price that would be received to sell an asset or paid

to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value is based on assumptions that market

participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to

valuations. This includes not only the credit standing of counterparties involved and the impact of credit enhancements but also the impact of our own

nonperformance risk on our liabilities. Fair value measurements are classified and disclosed in one of the following categories:

Level 1: Fair value is based on actively-quoted market prices, if available.

Level 2: In the absence of actively-quoted market prices, we seek price information from external sources, including broker quotes and industry

publications. Substantially all of these inputs are observable in the marketplace during the entire term of the instrument, can be derived from

observable data, or supported by observable levels at which transactions are executed in the marketplace.

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. We seek to maximize the use of observable

inputs and minimize the use of unobservable inputs when measuring fair value.

31
Endeavour Energy UK Limited

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. At December 31, 2012, we had

no outstanding derivative instruments. The following table summarized the valuation of our investments and financial instruments by pricing levels as of

December 31, 2011:

 

Quoted Market Prices

in Active Markets -

Level 1 

Significant Other

Observable Inputs 

-

Level 2 

Significant

Unobservable Inputs 

-

Level 3 

Total

Fair Value

Oil and gas puts $ — $ 1,038 $ 209 $1,247

Our commodity derivative contracts were measured using models that consider various inputs including current market and contractual prices for the

underlying instruments, quoted forward prices for natural gas and crude oil, volatility factors and interest rates, such as a LIBOR curve for a similar length

of time as the derivative contract term. The inputs for the fair value models for our oil puts were all observable market data and these instruments have been

classified as Level 2. Although we utilized the same option pricing models to assess the fair values of our gas puts, an active futures market does not exist for

our U.K. gas derivatives. We based the inputs to the option models for our U.K. gas derivatives on observable market data in other markets to verify the

reasonableness of the counterparty quotes. These U.K. gas derivatives are classified as Level 3.

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

 Year Ended

 December 31,

 2012 2011

Balance at beginning of period $ 209 $ 792

Total gains or losses (realized/unrealized) 

Purchases — 1,239

Included in earnings (209) (1,822) 

Balance at end of period $ — $ 209

Changes in unrealized gains (losses) relating to derivatives assets and liabilities still held at the end of

the period $ — $(1,822) 

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:

32
Endeavour Energy UK Limited

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

Goodwill - Goodwill is tested annually at year end for impairment. The first step of that process is to compare the fair value of the reporting unit to which

goodwill has been assigned to the carrying amount of the associated net assets and goodwill. Significant Level 3 inputs may be used in the determination of the

fair value of the reporting unit, including present values of expected cash flows from operations.

When we are required to measure fair value, and there is not a market observable price for the asset or liability, or a market observable price for a similar asset

or liability, we generally utilize an income valuation approach. This approach utilizes management’s best assumptions regarding expectations of projected cash

flows, and discounts the expected cash flows using a commensurate risk adjusted discount rate. Such evaluations involve a significant amount of judgment

since the results are based on expected future events or conditions, such as sales prices; estimates of future oil and gas production; development and operating

costs and the timing thereof; economic and regulatory climates and other factors. Our estimates of future net cash flows are inherently imprecise because they

reflect management’s expectation of future conditions that are often outside of management’s control. However, assumptions used reflect a market participant’s

view of long-term prices, costs and other factors, and are consistent with assumptions used in our business plans and investment decisions.

Note 18 – Derivative Instruments

We had oil and gas commodity derivatives at December 31, 2011. The fair market value of these derivative instruments is included in our balance sheet as

follows:

 December 31,

 2012 2011

Derivatives not designated as hedges: 

Oil and gas commodity derivatives: 

Assets: 

Prepaid expenses and other current assets $— $1,247

 $— $1,247

33
Endeavour Energy UK Limited

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

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

 Year Ended December 31,

 2012 2011 2010

Derivatives not designated as hedges: 

Oil and gas commodity derivatives 

Realized gains (losses) $ — $ — $(11,753) 

Unrealized gains (losses) (3,524) (3,050) 10,943

 $(3,524) $(3,050) $ (810) 

Note 19 – 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.

Guarantees

On February 23, 2012, EIC, the company’s ultimate parent company, entered into an Indenture (the “First Priority Indenture”) with the subsidiary guarantors

party thereto (the “Guarantors”) and Wells Fargo Bank, National Association, as trustee (the “First Priority Trustee”) and collateral agent, relating to the

issuance and sale of $350,000,000 in aggregate principal amount of EIC’s 12% First Priority Notes due 2018 (the “First Priority Notes”), subsequently

increased by an additional $54 million aggregate principal amount.

Also on February 23, 2012, EIC concurrently entered into an Indenture (the “Second Priority Indenture,” and together with the First Priority Indenture, the

“Indentures”) with the Guarantors, Wilmington Trust, National Association, as trustee (the “Second Priority Trustee,” and together with the First Priority

Trustee, the “Trustees”), and Wells Fargo Bank, National Association, as collateral agent, relating to the issuance and sale of $150,000,000 in aggregate

principal amount of EIC’s 12% Second Priority Notes due 2018 (the “Second Priority Notes,” and together with the First Priority Notes, the “2018 Notes”).

The First Priority Notes and related guarantees are secured by first-priority liens on (1) 65% of our capital stock and all of EIC’s future first-tier foreign

subsidiaries and (2) the EOC Intercompany Loan and all future intercompany indebtedness owing by any of the EIC’s foreign subsidiaries to EIC or any of

its domestic subsidiaries (collectively, the “Collateral”). The Second Priority Notes and related guarantees will be secured by second priority liens on the

Collateral.

34
Endeavour Energy UK Limited

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

The Indentures restrict the Company’s and its restricted subsidiaries’ ability to: (i) pay distributions or repurchase or redeem the Company’s capital stock or

subordinated debt; (ii) 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 restricted subsidiaries to the

Company; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries. These covenants are subject to a number of important

exceptions and qualifications, including that certain of the covenants will be terminated if at any time no default has occurred and is continuing and either

series of the 2018 Notes, as applicable, receives an investment grade rating from both Standard & Poor’s Ratings Services and Moody’s Investors Service,

Inc.

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, covering approximately $33 million relates to our decommissioning obligations at the Ivanhoe, Rob Roy, Hamish

(collectively, “IVRRH”), Renee and Rubie fields where we are currently paying certain asset retirement costs (the “IVRRH Reimbursement Agreement”). We pay

a fee of 11.5% per year, computed based on the outstanding amount of each letter of credit (capitalized quarterly and payable upon release of the letters of

credit). We are also required to pay a fee equal to 1% of the outstanding letters of credit on May 22, 2013 (the expiration date of the letters of credit). If we have

not obtained replacement letters of credit before the expiration date of the letters of credit, then we must reimburse the pledgor for all amounts pledged.

Concurrent with the issuance of the IVRRH Reimbursement Agreement, the restrictions on our previously restricted cash were removed, the cash was returned

to us, and our letter of credit facility agreement was extinguished. We unconditionally guarantee the obligations under the IVRRH Reimbursement Agreement,

but our reimbursement obligations are unsecured. In connection with this reimbursement agreement, we issued warrants to purchase two million shares of our

common stock, with an exercise price of $10.50 per share, to the investors.

35
Endeavour Energy UK Limited

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

On January 10, 2013, we entered into a letter of credit procurement agreement (the “Procurement Agreement”). See Note 20 “Subsequent Events” for additional

discussion. In connection with the Procurement Agreement, we terminated the IVRRH Reimbursement Agreement and paid all outstanding and accrued fees

totaling approximately $3.8 million.

The second reimbursement agreement covers approximately $120 million related to our decommissioning obligations for the Alba field (the “Alba

Reimbursement Agreement”). We pay a fee of 13% per year, payable quarterly, computed based on the outstanding amount of each letter of credit. We have

agreed to procure the release of the pledged cash securing the letter of credit on or before December 31, 2013 (the expiration date of the letter of credit). In

addition, our obligations under the Alba Reimbursement Agreement are 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, 2012, 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 performance and life of the reservoir.

Subsequent to December 31, 201, we amended the Alba Reimbursement Agreement to extend the maturity date to June 30, 2014. See Note 20 “Subsequent

Events” for additional discussion.

Rig Commitments

We have previously disclosed a potential commitment on a drilling rig in our North Sea operations relating to a dispute with the rig operator. In June 2011, we

entered into a settlement agreement with the rig operator whereby the parties were mutually released from all future claims. We incurred costs of $14 million

related to the settlement, which are included in capital expenditures.

Operating Leases

At December 31, 2012, we have leases for office space and equipment with lease payments as follows:

2013 $ 997

2014 1,009

2015 1,021

2016 741

Thereafter — 

36
Endeavour Energy UK Limited

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

Note 20 – Subsequent Events

Entry into Procurement Agreement

In January 2013, we entered into 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 agreement, the third party pledged cash, contributed by one of our shareholders, to secure letters of credit in the amount of approximately

$33.0 million. The letters of credit secure decommissioning obligations in connection with certain of our U.K. license agreements.

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;

• pay a fee of 0.65% per year of the aggregate balance of any outstanding letters of credit.

The Procurement Agreement contains customary representations, warranties and non-financial covenants. EIC issued warrants to purchase a total of 1,000,000

shares of EIC’s 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, which secured letters of credit. Upon

termination of the IVRRH Reimbursement Agreement, we paid all outstanding and accrued fees totaling approximately $3.8 million.

Strategic Alternatives

On February 14, 2013, EIC announced that its board of directors approved a review of strategic alternatives. In an effort to unlock the value of EIC’s

underlying assets, EIC will consider a full range of options, including:

• a sale, joint venture or partnership in respect of its activities in the North Sea;

• a sale of specific assets;

• a sale or merger of EIC; or

• continuing to execute on its operational plan.

37
Endeavour Energy UK Limited

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

EIC will announce the results of the effort once a course of action is chosen. There is no assurance that this strategic alternatives review will result in a change

to our current business plan, pursuing a particular transaction or completing any such transaction.

Forward Sale

In February 2013, we entered into a forward sale agreement with one of our established purchasers for a payment of approximately $22.5 million, which was

received on March 1, 2013 in return for a specified volume of crude oil in excess of 200,000 barrels to be delivered over a six month delivery period from our

UK North Sea production.

Production Payment

In March 2013, we entered into a sale and purchase agreement (the “Sale and Purchase Agreement”) for $107.5 million providing for the sale and purchase of

a production payment over the proceeds of sale from a proportion of our entitlement to production from its interests in the Alba and Bacchus fields located in

the UK sector of the North Sea (the “Production Payment Transaction”) and the issuance of warrants (discussed below). Repayment of the production

payment will come solely from the proceeds from the sale of production from our entitlement from the Alba and Bacchus fields.

In the event that the Production Payment Transaction does not complete under the terms of the Sale and Purchase Agreement, the deposit paid to us upon

signing of the Sale and Purchase Agreement and all or part of a $1.2 million termination fee would become due and payable by us.

The completion of the Production Payment Transaction is conditional upon, amongst other things, the approval of the UK Secretary of State for Energy and

Climate Change. Contemporaneously with completion under the Sale and Purchase Agreement, EIC expects to issue 3,440,000 warrants to purchase shares of

common stock at an exercise price of $3.014 per share (the “Warrants”).

Our obligations to refund the deposit and pay the termination fee are secured by first priority liens on our interests in the licenses and certain joint operating

agreements governing the fields giving rise to the production subject to the production payment. Upon closing of the purchase and sale of the production

payment, our obligations under the production payment will be secured by first priority liens in the same assets and second priority liens in certain other

assets of the Company and its subsidiaries.

38
Endeavour Energy UK Limited

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

Revolving Credit Agreement

In March 2013, we, Cyan, and certain lenders entered into a third amendment to the Revolving Credit Facility whereby (i) the lenders consented to the

Production Payment Transaction and (ii) the maturity of approximately $100 million of the commitments under the under the Revolving Credit Facility was

extended from October 12, 2013 to June 30, 2014. The remaining principal of the Revolving Credit Facility will mature on October 12, 2013, as previously

provided.

Reimbursement Agreement

In March 2013, we amended the Alba Reimbursement Agreement to (i) allow us to enter the Production Payment Transaction, (ii) extend the maturity of the

obligations under the Alba Reimbursement Agreement from December 31, 2013 to June 30, 2014, and (iii) the parties agreed to agree to take the steps necessary

to extend the letter of credit issued pursuant to the Alba Reimbursement Agreement from December 31, 2013 to December 31, 2014.

Note 21 – Supplemental Oil and Gas Disclosures (Unaudited)

Capitalized Costs Relating to Oil and Gas Producing Activities

 2012 2011

Proved $ 876,536 $ 429,246

Unproved 273,298 183,110

Total capitalized costs 1,149,834 612,356

Accumulated depreciation, depletion and amortization (241,338) (192,027) 

Net capitalized costs $ 908,496 $ 420,329

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

 Year Ended December 31,

 2012 2011 2010

Acquisition costs: 

Proved $ 143,004 $ 2,595 $ — 

Unproved 46,878 46,107 1,184

Exploration costs 46,730 51,820 50,328

Development costs 302,038 79,898 22,047

Total costs incurred $538,650 $180,420 $73,559

39
Endeavour Energy UK Limited

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

Results of Operations for Oil and Gas Producing Activities

 Year Ended December 31,

 2012 2011 2010

Revenues $207,181 $41,754 $60,501

Production expenses 51,568 8,622 11,086

DD&A 56,813 14,312 22,020

Income tax expense (benefit) 61,256 11,104 13,698

Results of activities $ 37,544 $ 7,716 $13,697

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, 2012, 2011 and 2010.

 2012 2011 2010

Proved Oil Reserves (MBbls): 

Proved reserves at beginning of year 4,060 3,664 3,348

Production (1,994) (373) (545) 

Purchases of reserves 11,071 303 — 

Extensions and discoveries 1,992 — 457

Revisions of previous estimates (1,396) 466 404

Proved reserves at end of year 13,733 4,060 3,664

Proved Developed Oil Reserves (MBbls) 5,261 1,270 1,240

40
Endeavour Energy UK Limited

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

 2012 2011 2010

Proved Gas Reserves (MMcf): 

Proved reserves at January 1, 2010 50,723 56,177 78,316

Production (91) (94) (3,071) 

Purchases of reserves 1,409 90 — 

Sales of reserves in place — — (51,522) 

Extensions and discoveries 473 — 26,692

Revisions of previous estimates 4,387 (5,450) 5,762

Proved reserves at December 31, 2010 56,901 50,723 56,177

Proved Developed Gas Reserves (MMcf) 3,147 795 555

 2012 2011 2010

Proved Reserves (MBOE): 

Proved reserves at December 31, 2009 12,514 13,027 16,401

Production (2,009) (389) (1,057) 

Extensions and discoveries 2,071 — 4,906

Purchase of proved reserves, in place 11,306 318 — 

Sales of reserves — — (8,587) 

Revisions of previous estimates (665) (442) 1,364

Proved reserves at December 31, 2010 23,217 12,514 13,027

Proved Developed Reserves (MBOE) 5,785 1,402 1,333

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 2012, 2011 and 2010. 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, 2012 and 2011, the prices used to determine the estimates of future cash inflows were as follows:

 December 31,

 2012 2011

 Oil Gas Oil Gas

 ($/Barrel) ($/Mcf) ($/Barrel) ($/Mcf)

United Kingdom 111.13 9.34 110.77 8.75

41
Endeavour Energy UK Limited

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

Estimated future cash inflows are reduced by estimated future development, production, abandonment and dismantlement costs based on year-end cost levels,

assuming continuation of existing economic conditions, and by estimated future income tax expense. Income tax expense, both U.S. and foreign, is calculated

by applying the existing statutory tax rates, including any known future changes, to the pretax net cash flows giving effect to any permanent differences and

reduced by the applicable tax basis. The effect of tax credits is considered in determining the income tax expense.

The standardized measure of discounted future net cash flows is not intended to present the fair market value of our oil and gas reserves. An estimate of fair

value would also take into account, among other things, the recovery of reserves in excess of proved reserves, anticipated future changes in prices and costs,

an allowance for return on investment and the risks inherent in reserve estimates.

Standardized Measure of Discounted Future Net Cash Flows

 2012 2011

Future cash inflows $2,035,208 $ 941,208

Future production costs (568,414) (144,106) 

Future development costs (581,277) (306,628) 

Future income tax expense (277,436) (238,111) 

Future net cash flows (undiscounted) 608,081 252,363

Annual discount of 10% for estimated timing 122,780 37,250

Standardized measure of future net cash flows $ 485,301 $ 215,113

42
Endeavour Energy UK Limited

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

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

 2012 2011 2010

Standardized measure, beginning of period $ 215,113 $ 73,550 $ 49,192

Net changes in prices and production costs 7,389 155,630 83,525

Future development costs incurred 164,562 66,156 19,259

Net changes in estimated future development costs (219,581) 13,359 (38,039) 

Revisions of previous quantity estimates (32,876) (18,771) 20,870

Extensions and discoveries 102,386 — 75,066

Accretion of discount 37,613 15,050 1,979

Changes in income taxes, net (74,778) (136,157) (35,306) 

Sale of oil and gas produced, net of production costs (159,450) (33,083) (49,415) 

Purchased reserves 456,810 26,340 — 

Sales of reserves in place — — (63,448) 

Change in production, timing and other (11,887) 53,039 9,867

Standardized measure, end of period $ 485,301 $ 215,113 $ 73,550

43
Exhibit 99.3

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholder

Endeavour International Holding B.V.:

We have audited the accompanying consolidated balance sheet of Endeavour International Holdings B.V. and subsidiaries as of December 31, 2012 and the

related consolidated statements of operations, stockholder’s equity and cash flows for the year then ended. These financial statements are the responsibility of

the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our 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 the financial statements are free of material misstatement. We were not engaged to

perform an audit of the Company’s internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a

basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the

Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence

supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management,

and evaluating the overall financial statement presentation. We believe that our audit provides 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

Holdings B.V. and subsidiaries at December 31, 2012 and the consolidated results of their operations and their cash flows for the year then ended, in

conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Houston, Texas

March 18, 2013
Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Endeavour International Holding B.V.:

We have audited the accompanying consolidated balance sheet of Endeavour International Holding B.V. and subsidiaries as of December 31, 2011, and the

related consolidated statements of operations, stockholders’ equity and cash flows for each of the years in the two-year period ended December 31, 2011.

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated

financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that

we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit

includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the

accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that

our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Endeavour International

Holding B.V. and subsidiaries as of December 31, 2011, and the results of their operations and their cash flows for each of the years in the two-year period

ended December 31, 2011, in conformity with U.S. generally accepted accounting principles.

(signed) KPMG LLP

Houston, Texas

January 24, 2013, except for Note 2 and 10, as to which date is March 18, 2013
Endeavour International Holding B.V.

Consolidated Balance Sheets

(Amounts in thousands)

 December 31,

 2012 2011

Assets 

Current Assets: 

Cash and cash equivalents $ 31,385 $ 103,085

Restricted cash 128 — 

Accounts receivable 43,358 4,508

Current receivables due from affiliates 71,964 11,142

Prepaid expenses and other current assets 20,487 17,711

Total Current Assets 167,322 136,446

Property and Equipment, Net ($273,298 and $183,110 not subject to amortization at 2012 and 2011, respectively) 910,749 421,457

Goodwill 262,764 211,886

Long-term receivables due from affiliates — 57,250

Other Assets 18,621 18,887

Total Assets $1,359,456 $845,926

See accompanying notes to consolidated financial statements.

3
Endeavour International Holding B.V.

Consolidated Balance Sheets

(Amounts in thousands)

 December 31,

 2012 2011

Liabilities and Stockholder’s Equity 

Current Liabilities: 

Accounts payable $ 57,531 $ 44,620

Current maturities of debt 15,713 2,350

Current liabilities due to affiliates 36,726 45,715

Accrued expenses and other 61,035 10,903

Total Current Liabilities 171,005 103,588

Long-Term Debt 167,380 298,016

Long-Term Liabilities due to Affiliates 599,000 99,000

Deferred Taxes 141,887 108,762

Other Liabilities 144,098 58,634

Total Liabilities 1,223,370 668,000

Commitments and Contingencies 

Stockholder’s Equity: 

Common stock; shares issued and outstanding - 180 and 180 shares at 2012 and 2011, respectively 25 25

Additional paid-in capital 120,033 120,033

Accumulated earnings, as adjusted 16,028 57,868

Total Stockholders’ Equity 136,086 177,926

Total Liabilities and Stockholder’s Equity $1,359,456 $845,926

See accompanying notes to consolidated financial statements.

4
Endeavour International Holding B.V.

Consolidated Statement of Operations

(Amounts in thousands)

 Year Ended December 31,

 2012 2011 2010

Revenues $ 207,181 $ 41,754 $ 60,501

Cost of Operations: 

Operating expenses 51,568 8,622 11,086

Depreciation, depletion and amortization 57,961 14,988 22,692

General and administrative 8,569 4,866 4,321

Total Expenses 118,098 28,476 38,099

Income From Operations 89,083 13,278 22,402

Other Income (Expense): 

Derivatives: 

Realized gains (losses) — — (11,753) 

Unrealized gains 5,846 11,020 10,033

Interest expense (67,672) (38,894) (25,079) 

Gain on sale of reserves in place — — 87,171

Letter of credit fees (21,903) — — 

Loss on early extinguishment of debt (21,661) — — 

Interest income and other (4,308) 10,074 3,947

Total Other Income (Expense) (109,698) (17,800) 64,319

Income (Loss) Before Income Taxes (20,615) (4,522) 86,721

Income Tax Expense (Benefit) 21,225 27,058 (788) 

Net Income (Loss) $ (41,840) $(31,580) $ 87,509

See accompanying notes to consolidated financial statements.

5
Endeavour International Holding B.V.

Consolidated Statement of Cash Flows

(Amounts in thousands)

 Year Ended December 31,

 2012 2011 2010

Cash Flows from Operating Activities: 

Net income (loss) $ (41,840) $ (31,580) $ 87,509

Adjustments to reconcile net income (loss) to net cash provided by operating activities: 

Depreciation, depletion and amortization 57,961 14,988 22,692

Deferred tax expense (benefit) (10,597) 21,116 (3,367) 

Unrealized gains on derivatives (5,846) (11,020) (10,033) 

Gain on sales of reserves in place — — (87,171) 

Amortization of loan costs and discount 7,266 11,588 9,725

Non-cash interest expense 8,239 11,931 7,754

Loss on early extinguishment of debt 21,661 — — 

Other 14,909 1,495 (2,373) 

Changes in operating assets and liabilities: 

(Increase) decrease in receivables (25,814) 1,066 7,561

(Increase) decrease in prepaids 8,631 (16,234) (1,013) 

Increase (decrease) in liabilities (21,617) 11,732 (3,242) 

Net cash provided by operating activities 12,953 15,082 28,042

Cash Flows From Investing Activities: 

Capital expenditures (207,131) (84,783) (57,971) 

Acquisitions (236,482) (25,048) (1,184) 

Proceeds from sales, net of cash 1,407 — 108,315

Issuance of note receivable to affiliates — — (57,250) 

Change in restricted cash (128) 31,726 (31,347) 

Net cash used in investing activities (442,334) (78,105) (39,437) 

Cash Flows From Financing Activities: 

Repayments of borrowings (242,171) (1,975) (75,342) 

Borrowings under debt agreements 115,163 75,000 185,000

Borrowings from affiliates 500,000 — — 

Financing costs paid (8,063) (5,475) (26,590) 

Payment on early extinguishment of debt (7,248) — — 

Net cash provided by financing activities 357,681 67,550 83,068

Net increase (decrease) in cash (71,700) 4,527 71,673

Cash and Cash Equivalents, Beginning of Period 103,085 98,558 26,885

Cash and Cash Equivalents, End of Period $ 31,385 $103,085 $ 98,558

See accompanying notes to consolidated financial statements.

6
Endeavour International Holding B.V.

Consolidated Statement of Stockholder’s Equity

(Amounts in thousands)

 

Common

Stock 

Additional

Paid-In

Capital 

Retained

Earnings

(Deficit)

Total

Stockholder’s

Equity

Balance, January 1, 2010 $ 25 $120,033 $ 1,939 $121,997

Net Loss — — 87,509 87,509

Balance, December 31, 2010 $ 25 $120,033 $ 89,448 $209,506

Net Income — — (31,580) (31,580) 

Balance, December 31, 2011 $ 25 $120,033 $57,868 $177,926

Net Loss — — (41,840) (41,840) 

Balance, December 31, 2012 $ 25 $120,033 $ 16,028 $ 136,086

See accompanying notes to consolidated financial statements.

7
Endeavour International Holding B.V.

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

Note 1 – General

Description of Business

Endeavour International Holding B.V. is an independent oil and gas company engaged in the exploration, development, production and acquisition of energy

reserves in the U.K. As used in these Notes to Consolidated Financial Statements, the terms “EIHBV”, “we”, “us”, “our” and similar terms refer to

Endeavour International Holding B.V. and, unless the context indicates otherwise, its consolidated subsidiaries. EIHBV was incorporated in The Netherlands

in 2005 and is a wholly-owned subsidiary of Endeavour International Corporation (“EIC”).

2013 Liquidity and Capital Resources

As of December 31, 2012, we had $185 million in outstanding indebtedness to third parties and $599 million in outstanding indebtedness to affiliates. Being

highly leveraged, servicing our debt and other long-term obligations will continue to require a significant portion of our cash flow from operations and available

cash on hand. The combination of these debt servicing requirements, capital expenditures and the delay in cash flow resulting from the Rochelle mechanical

issues may exceed the cash flow from our current operations. Ultimately, our primary uses and sources of financial resources will be impacted by the outcome

of our strategic review.

During 2013, our primary uses of financial resources are expected to be:

• our capital expenditures, primarily related to our drilling activities at our Alba, Bacchus and Rochelle fields in the U.K.; and

• interest payments on existing credit facilities and payments in support of our reimbursement agreements covering our abandonment obligations.

We believe we will be able to fund operations for the foreseeable future including our capex and other expenditure requirements based on our projections of

funds generated from operations, cash available and existing sources of financing. Since year-end 2012, we have also completed several transactions to

improve our liquidity position and extended the maturities of some of our debt and other obligations. The completion of these recent financing activities are

designed to provide sufficient liquidity to bring the Rochelle development on line, drill a third well at Bacchus and allow sufficient time for a thoughtful and

disciplined strategic review process. These transactions include:

• extending or replacing reimbursement agreements covering certain of our abandonment liabilities in the U.K. which would have expired in 2013;

• entering into a forward sale agreement;

• entering into a sale and purchase agreement providing for the sale and purchase of a production payment; and

• extending the maturity of a majority of the commitments under our revolving credit facility.

8
Endeavour International Holding B.V.

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

If we are unable to meet any short-term liquidity needs out of cash on hand, we would attempt to refinance debt, sell forward our production, sell assets, issue

debt or equity or perform any other alternatives resulting from our strategic review.

Summary of Significant Accounting Policies

Basis of Presentation and Use of Estimates

The accompanying financial statements have been prepared on the accrual basis of accounting in accordance with accounting principles generally accepted in

the United States of America (“US GAAP”) and have been presented on a going concern basis, which contemplates the realization of assets and satisfaction of

liabilities in the normal course of business. In the opinion of management, all normal recurring adjustments considered necessary for a fair presentation have

been included in these financial statements. Certain amounts for prior periods have been reclassified to conform to the current presentation.

These accounting principles require management to use estimates, judgments and assumptions that affect the amounts of assets, liabilities, revenues and

expenses reported herein. While management 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.

Our financial statements include allocations of general, administrative costs of EIC that are attributable to our operations and use of centralized general and

administrative services. Management believes the assumptions and allocations underlying the combined financial statements are reasonable. However, these

combined financial statements do not include all of the actual expenses that would have been incurred had we been a stand-alone entity during the periods

presented and do not reflect our results of operations, financial position and cash flows had we been a stand-alone company during the periods presented.

9
Endeavour International Holding B.V.

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

Principles of Consolidation

The accompanying consolidated financial statements include all of the accounts of EIHBV and our consolidated subsidiaries. All significant intercompany

accounts and transactions have been eliminated. Investments in entities over which we have significant influence, but not control, are carried at cost adjusted

for equity in earnings or (losses) and distributions received.

Cash and Cash Equivalents

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

Restricted Cash

Restricted cash has historically included amounts held in escrow for drilling rig commitments, as collateral for lines of credit, and for acquisitions.

Inventories

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

Full Cost Accounting for Oil and Gas Operations

Under the full cost method 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, 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.

10
Endeavour International Holding B.V.

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

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.

Unproved property costs include the costs associated with unevaluated properties and properties under development and are not initially included in the full

cost amortization base (where proved reserves exist) until the project is evaluated. These costs include unproved leasehold acreage, seismic data, wells and

production facilities in progress and wells pending determination, together with interest costs capitalized for these projects. Seismic data costs are associated

with specific unevaluated properties where the seismic data is acquired for the purpose of evaluating acreage or trends covered by a leasehold interest owned by

us.

Significant unproved properties are assessed periodically for possible impairment or reduction in value. If a reduction in value has occurred, these property

costs are considered impaired and are transferred to the related full cost pool. Geological and geophysical costs included in unproved properties are transferred

to the full cost amortization base along with the associated leasehold costs on a specific project basis. Costs associated with wells in progress and wells

pending determination are transferred to the amortization base once a determination is made whether or not proved reserves can be assigned to the property.

Costs of dry holes are transferred to the amortization base immediately upon determination that the well is unsuccessful. Unproved properties whose

acquisition costs are not individually significant are aggregated and the portion of such costs estimated to be ultimately nonproductive, based on experience,

are amortized to the full cost pool over an average holding period.

In countries where the existence of proved reserves has not yet been determined, unevaluated property costs remain capitalized in unproved property cost

centers until proved reserves have been established, exploration activities cease or impairment and reduction in value occurs. If exploration activities result in

the establishment of a proved reserve base, amounts in the unproved property cost center are reclassified as proved properties and become subject to

amortization and the application of the ceiling test. When it is determined that the value of unproved property costs have been permanently diminished (in part

or in whole) based on the impairment evaluation and future exploration plans, the unproved property cost centers related to the area of interest are impaired,

and accumulated costs charged against earnings.

Other Property and Equipment

Other oil and gas assets, computer equipment and furniture and fixtures are recorded at cost, less accumulated depreciation. The assets are depreciated using

the straight-line method over their estimated useful lives of two to five years.

11
Endeavour International Holding B.V.

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

Capitalized Interest

We capitalize interest on expenditures for significant exploration and development projects while activities are in progress to bring the assets to their intended

use. Capitalized interest is calculated by multiplying our weighted-average interest rate on debt by the amount of qualifying costs and is limited to gross interest

expense.

Business Combinations

Assets and liabilities acquired through a business combination are recorded at estimated fair value. We use all available information to make these fair value

determinations, including information commonly considered by our engineers in valuing individual oil and gas properties and sales prices for similar assets.

Estimated deferred taxes are based on available information concerning the tax basis of the acquired company’s assets and liabilities and carryforwards at the

merger date.

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

the amounts assigned to assets and liabilities over the acquisition of the acquired business is recorded as a gain on acquisition on the income statement. The

amount of goodwill recorded in any particular business combination can vary significantly depending upon the fair values attributed to assets acquired and

liabilities assumed relative to the total acquisition cost.

Goodwill and Intangible Assets

We assess the carrying amount of goodwill and other indefinite-lived intangible assets by testing the asset for impairment annually at year-end, or more

frequently if events or changes in circumstances indicate that the asset might be impaired. The impairment test requires allocating goodwill and all other assets

and liabilities to reporting units. The fair value of each reporting unit is determined and compared to the book value of the reporting unit. An impairment loss

is recognized to the extent that the carrying amount exceeds the asset’s fair value.

Dismantlement, Restoration and Environmental Costs

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

and natural gas processing plants, with a corresponding increase in the related long-lived asset. The asset retirement cost is depreciated along with the property

and equipment in the full cost pool. The asset retirement 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.

12
Endeavour International Holding B.V.

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

We utilize EIC’s credit adjustment to the risk-free interest rate in determining the fair value of our estimated asset retirement obligation as EIC could also be

held responsible for satisfying the obligation.

Revenue Recognition

We use the entitlements method to account for sales of gas production. We may receive more or less than our entitled share of production. Under the

entitlements method, if we receive more than our entitled share of production, the imbalance is treated as a liability at the market price at the time the imbalance

occurred. If we receive less than our entitled share, the imbalance is recorded as an asset at the lower of the current market price or the market price at the time

the imbalance occurred. Oil revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred, title

has transferred and collectability of the revenue is probable.

Significant Customers

Our sales are to a limited number of customers, each of which accounted for more than 10% of revenue for the year ended December 31, 2012: Chevron North

Sea Ltd and Shell U.K. Limited.

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.

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, 2012 and 2011, we have

no outstanding derivatives that are accounted for as a hedge.

13
Endeavour International Holding B.V.

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

Where we intend to account for a derivative as a hedge, we document, at its inception, the hedging relationship, the risk management objective and the strategy

for undertaking the hedge. The documentation includes the identification of the hedging instrument, the hedged item or transaction, the nature of the risk being

hedged, and the method that will be used to assess effectiveness of derivative instruments that receive hedge accounting treatment.

Changes in fair value to hedge instruments, to the extent the hedge is effective, are recognized in other comprehensive income until the forecasted transaction

occurs. Hedge effectiveness is assessed at least quarterly based on total changes in the derivative’s fair value. Any ineffective portion of the derivative

instrument’s change in fair value is recognized immediately in other (income) expense.

We discontinue hedge accounting prospectively when: (1) we determine that the derivative is no longer effective in offsetting changes in the fair value or cash

flows of a hedged item (including hedged items such as firm commitments or forecasted transactions); (2) the derivative expires; (3) it is no longer probable

that the forecasted transaction will occur; (4) a hedged firm commitment no longer meets the definition of a firm commitment; or (5) management determines

that designating the derivative as a hedging instrument is no longer appropriate.

Concentrations of Credit and Market Risk

Financial instruments that potentially subject us to concentrations of credit risk consist principally of cash deposits at financial institutions. At various times

during the year, we may exceed the federally insured limits. To mitigate this risk, we place our cash deposits only with high credit quality institutions.

Management believes the risk of loss is minimal.

Derivative financial instruments that hedge the price of oil and gas, interest rates or currency exposure will be generally executed with major financial or

commodities trading institutions which expose us to market and credit risks, and may at times be concentrated with certain counterparties or groups of

counterparties. Although notional amounts are used to express the volume of these contracts, the amounts potentially subject to credit risk, in the event of nonperformance by the counterparties, are substantially smaller. We review the credit ratings of our counterparties to derivative contracts on a regular basis and to

date we have not experienced any non-performance by any of our various counterparties.

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

14
Endeavour International Holding B.V.

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

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 operations with the U.S. dollar as the functional currency, monetary assets and liabilities are remeasured into U.S. dollars at

the exchange rate on the balance sheet date. Nonmonetary assets and liabilities are translated into U.S. dollars at historical exchange rates. Income and expense

items are translated at exchange rates prevailing during each period. Adjustments are recognized currently as a component of foreign currency gain or loss and

deferred income taxes. To the extent that business transactions are not denominated in U.S. dollars, we are exposed to foreign currency exchange rate risk.

Income Taxes

We use the liability method of accounting for income taxes under which deferred tax assets and liabilities are recognized for the estimated future tax

consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities, and their respective tax bases.

Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or

settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized as part of the provision for income taxes in the period that includes

the enactment date. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion

of, or all of, the deferred tax assets will not be realized.

Share-Based Payments

EIC grants restricted stock and stock options of its stock to our employees and directors as incentive compensation. We recognize all share-based payments to

employees, including grants of employee stock options, based on their fair values. The share-based compensation cost is measured at the grant date, based on

the calculated fair value of the award, and is recognized as general and administrative expense over the employee’s requisite service period (generally the vesting

period of the equity award). We apply the fair value method in accounting for stock option grants using the Black-Scholes Method. It is our policy to use

authorized but unissued shares of stock when stock options are exercised.

15
Endeavour International Holding B.V.

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

Note 2 – Revision of prior period financial statements

During 2012, we identified an overstatement of our deferred tax liabilities of $7.0 million. The overstatement resulted from differences between GAAP income

and taxable income that had accumulated over several prior periods. We corrected this overstatement, decreasing our deferred tax liability and accumulated

deficit in our consolidated balance sheet by $7.0 million as of December 31, 2011.

In evaluating whether our previously issued consolidated financial statements were materially misstated, we considered the guidance in ASC 250, Accounting

Changes and Error Corrections, SAB Topic 1.M, Assessing Materiality, and SAB Topic 1.N, Considering the Effects of Prior Year Misstatements when

Quantifying Misstatements in Current Year Financial Statements. We concluded these errors were not material individually or in the aggregate to any of the

prior reporting periods, and therefore, amendments of previously filed reports were not required. As such, the revisions for these corrections to the applicable

prior periods are reflected in the financial information herein and will be reflected in future filings containing such financial information. The consolidated

statement of stockholder’s equity was revised to reflect the cumulative effect of these adjustments resulting in an increase to retained earnings and total

stockholder’s equity of $7.0 million which is reflected in the beginning balance as of January 1, 2010.

The prior period financial statements included in this filing have been revised to reflect the corrections of these errors, the effects of which have been provided

in summarized format below.

Revised consolidated balance sheet amounts:

 As of December 31, 2011

 

As Previously

Reported Adjustment As Revised

Deferred tax liability $115,759 $(6,997) $ 108,762 

Total liabilities 674,997 (6,997) 668,000 

Retained earnings 50,871 6,997 57,868 

Total stockholder’s equity 170,929 6,997 177,926 

Adoption of New Accounting Standards

On January 1, 2012, we adopted the following new standards without material effects on our results of operations or financial position:

• Fair Value – An accounting standard on fair value measurements that clarifies the application of existing guidance and disclosure requirements

changes certain fair value measurement principles and requires additional disclosures about fair value measurements.

• Comprehensive Income - Guidance impacting the presentation of comprehensive income eliminates the current option to report components of

other comprehensive income in the statement of changes in equity or in a footnote to the financial statements.

16
Endeavour International Holding B.V.

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

• Goodwill – Amendment to the the previously issued guidance on testing goodwill for impairment. The revised guidance provides entities with an

option of performing a qualitative assessment prior to calculating the fair value of the reporting unit.

Note 3 – Business Combination

On December 23, 2011, we entered into a Sale and Purchase Agreement (the “Purchase Agreement”), through our wholly owned subsidiary Endeavour Energy

UK Limited (“EEUK”), with ConocoPhillips (U.K.) Limited, ConocoPhillips Petroleum Limited and ConocoPhillips (U.K.) Lambda Limited, subsidiaries

of ConocoPhillips (collectively, the “Sellers”), to acquire their interest in three producing U.K. oil fields in the Central North Sea.

On May 31, 2012, we closed a portion of the COP Acquisition consisting of an additional 23.43% interest in the Alba field (the “Alba Acquisition”) increasing

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.

The acquisition of the additional interest in the Alba field was accounted for using the business combination method. The following summarizes the allocation

of the purchase price for the Alba Acquisition:

Purchase price $ 255,400

Purchase price adjustments for estimated after-tax cash flows from the acquired asset

and interest costs from economic date of January 1, 2011 to closing (25,823) 

Total purchase price $229,577

Allocation of purchase price: 

Property and equipment $ 186,801

Goodwill 50,878

Current assets 24,632

Current liabilities (12,815) 

Deferred tax liability (5,818) 

Other long-term liabilities (14,101) 

Total purchase price $229,577

Goodwill was the excess of the consideration transferred over the net assets recognized and represents the future economic benefits arising from assets acquired

that could not be individually identified and separately recognized. The assessments of the fair values of oil and gas properties acquired were based on

projections of expected future net cash flows, discounted to present value.

17
Endeavour International Holding B.V.

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

The following table sets forth unaudited pro forma condensed combined financial and operating data which are presented to give effect to the Alba acquisition

as if it had occurred January 1, 2011. The information does not purport to be indicative of actual results, if any of these transactions had been in effect for the

periods indicated, or future results.

 Year Ended December 31,

 2012 2011

Revenues $279,697 $ 318,476

Net income (loss) $ (29,223) $(131,881) 

Revenues and income from operations associated with the acquired interest in the Alba field for the period from May 31, 2012 through December 31, 2012

were $ 119.7 million and $ 13.7 million, respectively.

After substantial effort and extensions, we and the Sellers were unable to reach the unanimous agreement and consent required to transfer the interests in the

two remaining U.K. oil fields due to failure to agree on certain commercial terms related to the future timing and amount of collateral required to be posted for

future decommissioning costs.

As a result of the parties being unable to reach agreement to enable the transfers to occur, the Purchase Agreement terminated in accordance with its terms on

December 14, 2012. As previously disclosed, we paid a $10 million deposit in connection with the acquisition of the interests in the remaining two fields,

which ConocoPhillips retained.

Note 4 – Prepaid Expenses and Other Current Assets

Prepaid expenses and other current assets consisted of the following:

 December 31,

 2012 2011

Fair market value of commodity derivatives – current

 $ — $ 1,247

Prepaid well and drilling costs 2,798 2,240

Prepaid insurance 3,288 1,303

Inventory 5,127 1,622 

Deposits and other costs related to the Alba Acquisition — 9,064

Deferred tax asset 8,089 — 

Other 1,185 2,235 

 $20,487 $17,711

18
Endeavour International Holding B.V.

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

Note 5 – Property and Equipment

Property and equipment included the following:

 December 31,

 2012 2011

Oil and gas properties under the full cost method: 

Subject to amortization $ 876,536 $ 429,246

Not subject to amortization: 

Acquired in 2012 126,128 — 

Acquired in 2011 89,118 99,794

Acquired in 2010 10,106 14,101

Acquired prior to 2010 47,946 69,215

 1,149,834 612,356

Computers, furniture and fixtures 5,505 3,232

Total property and equipment 1,155,339 615,588

Accumulated depreciation, depletion and amortization (244,590) (194,131) 

Net property and equipment $ 910,749 $ 421,457

The costs not subject to amortization include

• values assigned to unproved reserves acquired,

• exploration costs such as drilling costs for projects awaiting approved development plans or the determination of whether or not proved reserves

can be assigned, and

• other seismic and geological and geophysical costs.

These costs are transferred to the amortization base when it is determined whether or not proved reserves can be assigned to such properties. This analysis is

dependent upon well performance, results of infield drilling, approval of development plans, drilling results and development of identified projects and

periodic assessment of reserves. We expect acquisition costs excluded from amortization to be transferred to the amortization base over the next five years due to

a combination of well performance and results of infield drilling relating to currently producing assets and the drilling and development of identified projects

acquired, such as the Rochelle field. We expect exploration costs not subject to amortization to be transferred to the amortization base over the next three years

as development plans are completed and production commences on existing discoveries.

19
Endeavour International Holding B.V.

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

The following is a summary of our oil and gas properties not subject to amortization as of December 31, 2012:

Costs Incurred in the Year Ended December 31,

 2012 2011 2010 Prior to 2010 Total

Acquisition costs $ 46,819 $45,975 $ — $ 8,198 $100,992

Exploration costs 60,595 42,833 10,106 39,747 153,281

Capitalized interest 18,714 310 — 1 19,025

Total oil and gas properties not subject to amortization $126,128 $89,118 $10,106 $ 47,946 $273,298

During 2012, 2011 and 2010, we capitalized $11.7 million, $7.7 million and $9.1 million, respectively, in certain directly related employee costs. During

2012, 2011 and 2010, we capitalized $24.2 million, $10.1 million and $2.0 million, respectively, in interest.

Asset Acquisitions

On February 23, 2011, we closed our acquisition of an additional 20% working interest in the Bacchus field for approximately $9.2 million in cash paid at

closing and approximately $6.2 million in cash paid in 2012. In addition, we paid capital costs incurred by the seller of $9.4 million. Following the

acquisition, we hold an aggregate 30% working interest in the Bacchus field.

Business Combination

On May 31, 2012, we closed the Alba COP Acquisition, which consisted of an additional 23.43% interest in the Alba field. This increased our total working

interest in the Alba field to 25.68%.

Asset Disposition

In October 2010, we sold our interests in the Cygnus reserves in the U.K. North Sea for $110 million and recorded a gain of $87 million. The cash proceeds

were not burdened by any current taxes payable and are being primarily used to accelerate our development projects.

20
Endeavour International Holding B.V.

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

Note 6 – 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.

 December 31,

 2012 2011

Balance at beginning of year

 $211,886 $211,886

Additions related to acquisitions 50,878 — 

Balance at end of year $262,764 $211,886

Note 7 – Other Assets

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

 2012 2011

Debt issuance costs $ 5,399 $18,046

Deferred issuance costs related to reimbursement agreements 11,290 — 

Other 1,932 841

 $18,621 $18,887

Debt issuance costs and deferred issuance costs related to reimbursement agreements are amortized over the life of the related obligations. See Notes 9 and 19

for additional discussion.

21
Endeavour International Holding B.V.

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

Note 8 – Accrued Expenses

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

 December 31,

 2012 2011

Foreign taxes payable $18,989 $ 445

Accrued compensation 797 760

Current portion of asset retirement obligations 36,144 2,078

Development asset accrual — 6,160

Other 5,105 1,460

 $ 61,035 $10,903

Note 9 – Debt Obligations

Our debt consisted of the following at December 31:

 2012 2011

Senior term loan, 15% fixed rate, due 2013 $ — $ 240,349

Revolving credit facilty, 13% fixed rate, due 2014 115,163 — 

Convertible bonds, 11.5% until March 31, 2014 and 7.5% thereafter, due 2016 70,029 62,523

 185,192 302,872

Less: debt discount (2,099) (2,506) 

Less: current maturities (15,713) (2,350) 

Long-term debt $ 167,380 $298,016

Standby letters of credit outstanding for abandonment liabilities $ — $ 31,724

Principal maturities of debt at December 31, 2012 are as follows:

2013 $15,713

2014 99,450

2015 — 

2016 70,029

Thereafter — 

22
Endeavour International Holding B.V.

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

Revolving Credit Facility

On April 12, 2012, we entered into a $100 million Credit Agreement (the “Revolving Credit Facility”), with Cyan, as administrative agent, and borrowed $40

million. The Revolving Credit Facility matures on October 12, 2013.

Prior to the termination of the Senior Term Loan, the closing of the Alba Acquisition and certain other conditions, borrowings under the Revolving Credit

Facility were limited to $40 million and incurred interest at a rate of 12% per year, with an additional 3% payment-in-kind. After the termination of the Senior

Term Loan and the closing of the Alba Acquisition, borrowings under the Revolving Credit Facility bear interest at a rate of 13% per year.

On May 31, 2012, we entered into a First Amendment to the Revolving Credit Facility, providing for an increase in the amount available for borrowing under

the Revolving Credit Facility from $40 million to $100 million upon closing of the Alba Acquisition. In connection with the closing of the Alba Acquisition, we

drew down the additional $60 million available for borrowing. The First Amendment to the Revolving Credit Facility contained certain amendments allowing

us to enter certain reimbursement agreements discussed in Note 13.

On September 27, 2012, we increased the amount available for borrowing under the Revolving Credit Facility to $125 million. In connection with the

increase, we agreed to pay a fee of $1.25 million to Cyan Partners, LP. The Founding Partner and Chief Investment Officer of Cyan Partners, LP was a

member of EIC’s Board of Directors until he resigned in March 2013.

On September 28, 2012, we borrowed an additional $15 million under the Revolving Credit Facility.

Subsequent to December 31, 2012, we amended the Revolving Credit Facility to extend the maturity date of $100 million of the facility to June 30, 2014. See

Note 21 “Subsequent Events” for additional discussion.

11.5% Convertible Bonds

In January 2008, we issued 11.5% convertible bonds due 2014 (the “11.5% Convertivle Bonds”) for gross proceeds of $40 million pursuant to a private

offering to a sophisticated investor in Norway. The net proceeds from the issuance of the 11.5% Convertible Bonds were used to repay a portion of our

outstanding indebtedness. The 11.5% Convertible Bonds bear interest at a rate of 11.5% per annum, compounded quarterly. Interest is compounded quarterly

and added to the outstanding principal balance each quarter. The bonds are convertible into shares of EIC’s common stock at a conversion price of $16.52

per $1,000 of principal, which represents a conversion rate of approximately 61 shares of our common stock per $1,000 of principal. The conversion price

will be adjusted in accordance with the terms of the bonds upon occurrence of certain events, including payment of common stock dividends, common stock

splits or issuance of common stock at a price below the then current market price.

23
Endeavour International Holding B.V.

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

If EIC undergoes a “change of control” as defined, the holders of the bonds have the right, subject to certain conditions, to redeem the bonds and accrued

interest. The bonds may become immediately due upon the occurrence of certain events of default, as defined.

Two derivatives are associated with the conversion and change in control features of the 11.5% Convertible Bonds. At December 31, 2012, the combined fair

market value of these derivatives is $4.4 million, reflecting a $9.4 million decrease during 2012 that was recorded in unrealized gains (losses) on derivatives.

On March 11, 2011, we entered into an amendment to the Trust Deed related to our 11.5% Convertible Bonds. The amendment provided for:

• the amendment of the maturity date of the 11.5% Convertible Bonds from January 24, 2014 to January 24, 2016;

• the amendment of the date upon which the holders of the 11.5% Convertible Bonds may first exercise a put right, and the occurrence of the

conversion price reset if such put right is not exercised, from January 24, 2012 to January 24, 2016; and

• a reduction in the interest rate payable from 11.5% to 7.5% on and after March 31, 2014.

We recorded a loss of $0.8 million in other expenses related to this amendment, representing the difference between the fair value of the debt and the book value

of the debt at March 11, 2011.

Senior Term Loan

In August 2010, we entered into a credit agreement with Cyan, as administrative agent, and various lenders for the Senior Term Loan, in the aggregate amount

of $150 million, which was subsequently increased to $235 million. We paid $25.4 million in financing costs related to the issuance of the Senior Term

Loan. In May 2012, we repaid all amounts outstanding under Senior Term Loan. This repayment included a prepayment fee of approximately $7 million.

Following the repayment the Senior Term Loan was terminated and all of the liens on the collateral securing our obligations were released.

Fair Value

The fair value of our outstanding debt obligations was $189.7 million and $284.2 million at 2012 and 2011, respectively. The fair values of long-term debt

were determined based upon discounted cash flows, which results in a Level 3 fair-value measurement.

24
Endeavour International Holding B.V.

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

Letter of Credit Agreement

In July 2011, we entered into a letter of credit facility agreement with Commonwealth Bank of Australia (“CBA”), pursuant to which CBA issued letters of

credit to us in the amount of £20.6 million (approximately $35 million upon issuance). The letters of credit secured decommissioning obligations in

connection with certain of our United Kingdom Continental Shelf Petroleum Production Licenses. Concurrent with the issuance of the letters of credit, prior

restrictions on £20.6 million of our restricted cash were removed and the cash returned for general corporate purposes. We terminated this letter of credit

facility agreement in May 2012.

25
Endeavour International Holding B.V.

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

Note 10 – Income Taxes

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

follows:

(Amounts in thousands) U.K. Other Total

Year Ended December 31, 2012: 

Net income (loss) before taxes $(22,959) $ 2,344 $(20,615) 

Current tax expense 31,796 26 31,822

Deferred tax expense related to U.K. tax rate change 8,587 — 8,587

Deferred tax benefit (19,184) — (19,184) 

Total tax expense 21,199 26 21,225

Net income (loss) after taxes $ (44,158) $ 2,318 $ (41,840) 

Year Ended December 31, 2011: 

Net income (loss) before taxes $ (9,805) $ 5,283 $ (4,522) 

Current tax (benefit) expense 5,926 16 5,942

Deferred tax benefit (4,308) — (4,308) 

Deferred tax expense related to U.K. tax rate change 25,424 — 25,424

Total tax expense 27,042 16 27,058

Net income (loss) after taxes $ (36,847) $5,267 $ (31,580) 

Year Ended December 31, 2010: 

Net income (loss) before taxes $ 90,159 $ (3,438) $ 86,721

Current tax (benefit) expense 2,733 (154) 2,579

Deferred tax (benefit) expense (2,388) (929) (3,317) 

Foreign currency losses on deferred tax liabilities — (50) (50) 

Total tax (benefit) expense 345 (1,134) (788) 

Net income (loss) after taxes $ 89,814 $ (2,304) $ 87,509

26
Endeavour International Holding B.V.

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

Effective Tax Rate Reconciliation

The following table presents the principal reasons for the difference between our effective tax rates and The Netherlands statutory income tax rate of 25.5%.

 Year Ended December 31,

 2012 2011 2010

The Netherlands tax expense (benefit) at statutory rate of 25.5% $ (5,257) $ (1,153) $ 22,114

Taxation of foreign operations 17,895 2,787 (22,851) 

U.K. Tax increase from tax law change 8,587 25,424 — 

Foreign currency (gain) loss on deferred taxes — — (51) 

Total Income Tax Expense (Benefit) $21,225 $27,058 $ (788) 

Effective Income Tax Rate -103% -598% -1% 

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. The tax effects of temporary differences that give rise to significant portions of

deferred tax assets and liabilities are as follows at December 31:

27
Endeavour International Holding B.V.

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

 2012 2011

Deferred tax asset: 

Deferred compensation $ 357 $ 956

Unrealized loss on commodity derivative instruments — 1,260

Asset retirement obligation 87,787 29,122

Net operating loss and capital loss carryforward 271,452 119,637

Embedded derivative 767 3,905

Inventory / other 8,089 — 

Total deferred tax assets 368,452 154,880

Less valuation allowance (198) (3,198) 

Total deferred tax assets after valuation allowance 368,254 151,682

Deferred tax liability: 

Property, plant and equipment (478,720) (258,779) 

Petroleum revenue tax, net of tax benefit (22,703) (229) 

Debt discount (630) (752) 

Other — (684) 

Total deferred tax liabilities (502,053) (260,444) 

Net deferred tax liability $(133,799) $ (108,762) 

Tax Attributes

At December 31, 2012, we had the following tax attributes available to reduce future income taxes:

 As of December 31,

 2012 2011

 

Types of

Tax

Attributes 

Years of

Expiration 

Carryforward

Amount 

Years of

Expiration 

Carryforward

Amount

U.K. 

Corporate tax NOL Indefinite $500,798 Indefinite $ 228,701

Supplemental Corporate tax NOL Indefinite 378,602 Indefinite 159,316

As of December 31, 2012, the U.K. tax attributes shown above have been recognized for financial statement reporting purposes to reduce deferred tax liability.

28
Endeavour International Holding B.V.

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

Uncertain Tax Positions

At December 31, 2012, we have an unrecognized tax benefit of $6.8 million relating to various U.K. tax matters. Any interest and penalties that may be

incurred as part of this benefit would be recognized as a component of interest expense and other expense, respectively. As of December 31, 2012, no interest or

penalty expense had been incurred.

The following represents a reconciliation of the change in our unrecognized tax benefits, included in “Deferred Taxes” on the balance sheet, for the year ended

December 31, 2012.

 

Year Ended

December 31,

 2012 2011 2010

Balance at the beginning of the year

 — — — 

Increase in unrecognized tax benefits from current period tax position 6,820 — — 

Balance at the end of the year $6,820 $— $— 

As of December 31, 2012, we believe that no current tax positions that have resulted in unrecognized tax benefits will significantly increase or decrease within

the next year. If recognized, none of the unrecognized tax benefits would have an impact on our effective tax rate.

The following tax years remain subject to examination:

Tax Jurisdiction 

U.K. 2011 - 2012 

All others 2009 - 2012

Foreign Earnings and Credits

As of December 31, 2012, we had de minimus unremitted earnings in our foreign subsidiaries.

29
Endeavour International Holding B.V.

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

Note 11 – Other Liabilities

Other liabilities included the following:

 December 31,

 2012 2011

Asset retirement obligations $139,431 $ 44,894

Other

 4,667 13,740

Total Other Liabilities $144,098 $58,634

Our asset retirement obligations relate to obligation of the plugging and abandonment of oil and gas properties. The asset retirement obligation is recorded at fair

value and accretion expense, recognized over the life of the property, increases the liability to its expected settlement value. If the fair value of the estimated asset

retirement obligation changes, an adjustment is recorded for both the asset retirement obligation and the asset retirement cost. The following table provides a

rollforward of the asset retirement obligations for the year ended December 31, 2012 and 2011:

 

Year Ended

December 31,

 2012 2011

Carrying amount of asset retirement obligations, beginning of year

 $ 46,972 $ 42,741

Increase due to revised estimates 102,272 14,614

Accretion expense (included in DD&A expense) 7,502 4,443

Impact of foreign currency exchange rate changes 3,019 430

Payments of asset retirement obligations (8,521) (15,256) 

Liabilities incurred and assumed 24,331 — 

Asset retirement obligations, end of year 175,575 46,972

Less: current portion of asset retirement obligations (36,144) (2,078) 

Long-term asset retirement obligations $ 139,431 $ 44,894

Note 12 – Equity

Common Stock

The Common Stock is Euro 100 par value common stock, 900 shares authorized.

30
Endeavour International Holding B.V.

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

Note 13 – Stock-Based Compensation Arrangements

EIC grants restricted stock, stock options and performance-based share awards to our employees and directors as incentive compensation. This stock-based

compensation generally vests over three years and EIC bills us for its cost of the awards over the vesting schedule. 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.

For the year ended December 31, 2012, we included approximately $ 0.6 million of stock-based compensation in capitalized G&A in property and equipment.

Stock-based compensation is recorded in G&A expenses or capitalized G&A as follows:

 

Year Ended

December 31,

 2012 2011 2010

G&A Expenses $229 215 116

Capitalized G&A 347 192 149

Total stock-based compensation $576 $ 407 $265

Note 14 – Amounts due to/from Affiliates

Our amounts due (to) from affiliates consisted of the following at December 31:

 2012 2011

Assets: 

Current receivables due from affiliates $ 71,964 $ 11,142

Note receivables due from affiliates — 57,250

 $ 71,964 $ 68,392

Liabilities: 

Current payables due to affiliates $ 36,726 $ 45,715

Note payables due to affiliates 599,000 99,000

 $635,726 $144,715

31
Endeavour International Holding B.V.

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

Current Receivables (Payables) due from (to) Affiliates

We record current receivables from and payables to our affiliates in the ordinary course of business. The amounts payable to and receivable from our affiliates

do not bear interest and have no set maturity date.

Notes Receivable due from Affiliates

On January 1, 2010, we executed an unsecured revolving loan facility (the “EOC Note Receivable”) with a group undertaking, Endeavour Operating

Corporation (“EOC”), the parent company of Endeavour International Holding BV, as borrower. The EOC Note Receivable has a principal amount of $100

million, of which $57.3 million was outstanding at December 31, 2011. The EOC Note Receivable was repaid in full during 2012.

Notes Payable due to Affiliates

We have a $250 million unsecured Revolving Loan Facility Agreement with EOC, which matures on December 31, 2013. We may borrow up to the maximum

principal amount of the facility, at the discretion of EOC. Subject to EOC’s approval, we may repay the loan at any time prior to its maturity. At December 31,

2012 and 2011, the company owed $99 million to EOC pursuant to this loan.

On May 31, 2012, we entered into a $550 million unsecured Revolving Intercompany Loan Agreement with EOC (“EOC Intercompany Loan”) in conjunction

with the repayment of the Senior Term Loan and the closing of the Alba field portion of the COP Acquisition. We may borrow up to the maximum principal

amount of the facility, at the discretion of EOC. At December 31, 2012, we had $500 million outstanding under the facility. We may drawdown one or more

advances, subject to approval by EOC, and may repay any advance, in whole or in part, at any time prior to its maturity, December 31, 2017. Interest will be

paid semi-annually at a rate consistent with EIC’s weighted average cost of funds, as determined by EOC. This rate is determined on each semi-annual interest

payment date. As of December 31, 2012, the interest rate was 12% per annum.

Note 15 – Supplementary Cash Flow Disclosures

Cash paid for interest and income taxes was as follows:

32
Endeavour International Holding B.V.

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

 Year Ended December 31,

 2012 2011 2010

Interest paid $29,805 $23,805 $8,743

Income taxes paid (refunded) $ 426 $ 9,427 $ (172) 

Non-Cash Investing and Financing Transactions

In 2012, 2011 and 2010, we recorded $8.2 million, $11.9 million and $7.8 million, respectively, in non-cash interest expense that was added to the principal

balance of the 11.5% Convertible Bonds and the Senior Term Loan.

Note 16 – Financial Instruments

 December 31, December 31,

 2012 2011

 Fair Value 

Carrying

Value Fair Value 

Carrying

Value

Assets: 

Derivative instruments $ — $ — $ 1,247 $ 1,247

Liabilities: 

Debt 189,696 183,093 284,165 300,366

Derivative instruments 4,370 4,370 13,740 13,740

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 were determined based upon quotes obtained from

brokers. The fair values of long-term debt were determined based upon discounted cash flows.

Note 17 – Fair Value Measurements

We measure the fair value of financial assets and liabilities on a recurring basis, defining fair value as the price that would be received to sell an asset or paid

to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value is based on assumptions that market

participants would use when pricing an asset or liability, including

33
Endeavour International Holding B.V.

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

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. The following table

summarizes the valuation of our investments and financial instruments by pricing levels as of December 31, 2012:

 

Quoted Market

Prices

in Active Markets -

Level 1 

Significant Other

Observable Inputs 

-

Level 2 

Significant

Unobservable Inputs 

-

Level 3

Total

Fair Value

As of December 31, 2012: 

Embedded derivatives $ — $ — $ (4,370) $ (4,370) 

As of December 31, 2011: 

Oil and gas puts $ — $ 1,038 $ 209 1,247

Embedded derivatives — — (13,740) (13,740) 

Total derivative liabilities $ — $ 1,038 $ (13,531) $(12,493) 

Our commodity derivative contracts were measured using models that consider various inputs including current market and contractual prices for the

underlying instruments, quoted forward prices for natural gas and crude oil, volatility factors and interest rates, such as a LIBOR curve for a similar length

of time as the derivative contract term. The inputs for the fair value models for our oil puts were all observable market data and these instruments have been

classified as Level 2. Although we utilized the same option pricing models to assess the fair values of our gas puts, an active futures market does not exist for

our U.K. gas derivatives. We based the inputs to the option models for our U.K. gas derivatives on observable market data in other markets to verify the

reasonableness of the counterparty quotes. These U.K. gas derivatives are classified as Level 3.

34
Endeavour International Holding B.V.

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

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. At December 31, 2012, a decrease or increase in the implied credit spread of 5% would increase or decrease, respectively, the liability by approximately

$0.7 million. A similar 5% decrease or increase in the stock volatility has an inverse effect to the change in the liability and would result in an approximately

$0.6 million decrease or increase, respectively.

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

 

Year Ended

December 31,

 2012 2011

Balance at beginning of period $(13,531) $(27,018) 

Total gains or losses (realized/unrealized) 

Included in earnings 9,161 14,070

Purchases — 1,239

Settlements — (1,822) 

Balance at end of period $ (4,370) $(13,531) 

Changes in unrealized gains (losses) relating to derivatives assets and liabilities still

held at the end of the period $ 9,370 $ 14,070

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.

35
Endeavour International Holding B.V.

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

When we are required to measure fair value, and there is not a market observable price for the asset or liability, or a market observable price for a similar asset

or liability, we generally utilize an income valuation approach. This approach utilizes management’s best assumptions regarding expectations of projected cash

flows, and discounts the expected cash flows using a commensurate risk adjusted discount rate. Such evaluations involve a significant amount of judgment

since the results are based on expected future events or conditions, such as sales prices; estimates of future oil and gas production; development and operating

costs and the timing thereof; economic and regulatory climates and other factors. Our estimates of future net cash flows are inherently imprecise because they

reflect management’s expectation of future conditions that are often outside of management’s control. However, assumptions used reflect a market participant’s

view of long-term prices, costs and other factors, and are consistent with assumptions used in our business plans and investment decisions.

Note 18 – Derivative Instruments

We had oil and gas commodity derivatives and embedded derivatives related to debt instruments at December 31, 2012 and 2011. The fair market value of

these derivative instruments is included in our balance sheet as follows:

 December 31,

 2012 2011

Derivatives not designated as hedges: 

Oil and gas commodity derivatives: 

Prepaid expenses and other current assets $ — $ 1,247

Embedded derivatives related to debt instrument: 

Other liabilities - long-term (4,370) (13,740) 

36
Endeavour International Holding B.V.

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

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

 Year Ended December 31,

 2012 2011 2010

Derivatives not designated as hedges: 

Oil and gas commodity derivatives 

Realized gains (losses) $ — $ — $(11,753) 

Unrealized gains (losses) (3,524) (3,050) 10,943

 (3,524) (3,050) (810) 

Embedded derivatives related to debt and equity instruments 

Unrealized gains (losses) $ 9,370 $14,070 $ (910) 

Note 19 – 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 and regulations applicable to EIHBV and its properties and operations, the violation of which would have a material

adverse effect on us or our financial condition.

Guarantees

On February 23, 2012, EIC, the company’s ultimate parent company, entered into an Indenture (the “First Priority Indenture”) with the subsidiary guarantors

party thereto (the “Guarantors”) and Wells Fargo Bank, National Association, as trustee (the “First Priority Trustee”) and collateral agent, relating to the

issuance and sale of $350,000,000 in aggregate principal amount of EIC’s 12% First Priority Notes due 2018 (the “First Priority Notes”), subsequently

increased by an additional $54 million aggregate principal amount.

Also on February 23, 2012, EIC concurrently entered into an Indenture (the “Second Priority Indenture,” and together with the First Priority Indenture, the

“Indentures”) with the Guarantors, Wilmington Trust, National Association, as trustee (the “Second Priority Trustee,” and together with the First Priority

Trustee, the “Trustees”), and Wells Fargo Bank, National Association, as collateral agent, relating to the issuance and sale of $150,000,000 in aggregate

principal amount of EIC’s 12% Second Priority Notes due 2018 (the “Second Priority Notes,” and together with the First Priority Notes, the “2018 Notes”).

37
Endeavour International Holding B.V.

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

The First Priority Notes and related guarantees are secured by first-priority liens on (1) 65% of our capital stock and all of EIC’s future first-tier foreign

subsidiaries and (2) the EOC Intercompany Loan and all future intercompany indebtedness owing by any of the EIC’s foreign subsidiaries to EIC or any of

its domestic subsidiaries (collectively, the “Collateral”). The Second Priority Notes and related guarantees will be secured by second priority liens on the

Collateral.

The Indentures restrict the Company’s and its restricted subsidiaries’ ability to: (i) pay distributions or repurchase or redeem the Company’s capital stock or

subordinated debt; (ii) 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 restricted subsidiaries to the

Company; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries. These covenants are subject to a number of important

exceptions and qualifications, including that certain of the covenants will be terminated if at any time no default has occurred and is continuing and either

series of the 2018 Notes, as applicable, receives an investment grade rating from both Standard & Poor’s Ratings Services and Moody’s Investors Service,

Inc.

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, covering approximately $33 million relates to our decommissioning obligations at the Ivanhoe, Rob Roy, Hamish

(collectively, “IVRRH”), Renee and Rubie fields where we are currently paying certain asset retirement costs (the “IVRRH Reimbursement Agreement”). We pay

a fee of 11.5% per year, computed based on the outstanding amount of each letter of credit (capitalized quarterly and payable upon release of the letters of

credit). We are also required to pay a fee equal to 1% of the outstanding letters of credit on May 22, 2013 (the expiration date of the letters of credit). If we have

not obtained replacement letters of credit before the expiration date of the letters of credit, then we must reimburse the pledgor for all amounts pledged.

Concurrent with the issuance of the IVRRH Reimbursement Agreement, the restrictions on our previously restricted cash were removed, the cash was returned

to us, and our letter of credit facility agreement was extinguished. We unconditionally guarantee the obligations under the IVRRH Reimbursement Agreement,

but our reimbursement obligations are unsecured. In connection with this reimbursement agreement, EIC issued warrants to purchase two million shares of our

common stock, with an exercise price of $10.50 per share, to the investors.

38
Endeavour International Holding B.V.

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

On January 10, 2013, we entered into a letter of credit procurement agreement (the “Procurement Agreement”). See Note 21 “Subsequent Events” for additional

discussion. In connection with the Procurement Agreement, we terminated the IVRRH Reimbursement Agreement and paid all outstanding and accrued fees

totaling approximately $3.8 million.

The second reimbursement agreement covers approximately $120 million related to our decommissioning obligations for the Alba field (the “Alba

Reimbursement Agreement”). We pay a fee of 13% per year, payable quarterly, computed based on the outstanding amount of each letter of credit. We have

agreed to procure the release of the pledged cash securing the letter of credit on or before December 31, 2013 (the expiration date of the letter of credit). In

addition, our obligations under the Alba Reimbursement Agreement are 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, 2012, 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 performance and life of the reservoir.

Subsequent to December 31, 201, we amended the Alba Reimbursement Agreement to extend the maturity date to June 30, 2014. See Note 21 “Subsequent

Events” for additional discussion.

Rig Commitments

We have previously disclosed a potential commitment on a drilling rig in our North Sea operations relating to a dispute with the rig operator. In June 2011, we

entered into a settlement agreement with the rig operator whereby the parties were mutually released from all future claims. We incurred costs of $14 million

related to the settlement, which are included in capital expenditures.

Operating Leases

At December 31, 2012, we have leases for office space and equipment with lease payments as follows:

2013 $ 997

2014 1,009

2015 1,021

2016 741

Thereafter — 

39
Endeavour International Holding B.V.

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

Note 20 – 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:

 2012 2011 2010

 Revenue 

Longlived

Assets Revenue 

Longlived

Assets Revenue 

Long-l

ived

Assets

United Kingdom $207,181 $1,189,870 $41,754 $650,943 $60,501 $486,467

Other — 2,264 — 1,287 — 878

Total $207,181 $1,192,134 $41,754 $652,230 $60,501 $ 487,345

Note 21– Subsequent Events

Entry into Procurement Agreement

In January 2013, we entered into the letter of credit 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 agreement, the third party pledged cash, contributed by one of our shareholders, to secure letters of

credit in the amount of approximately $33.0 million. The letters of credit secure decommissioning obligations in connection with certain of our U.K. license

agreements.

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;

• pay a fee of 0.65% per year of the aggregate balance of any outstanding letters of credit.

The Procurement Agreement contains customary representations, warranties and non-financial covenants. EIC issued warrants to purchase a total of 1,000,000

shares of EIC’s 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.

40
Endeavour International Holding B.V.

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

Concurrent with our entry into the Procurement Agreement, we terminated the IVRRRH 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.

Strategic Alternatives

On February 14, 2013, EIC announced that its board of directors approved a review of strategic alternatives. In an effort to unlock the value of EIC’s

underlying assets, EIC will consider a full range of options, including:

• a sale, joint venture or partnership in respect of its activities in the North Sea;

• a sale of specific assets;

• a sale or merger of EIC; or

• continuing to execute on its operational plan.

EIC will announce the results of the effort once a course of action is chosen. There is no assurance that this strategic alternatives review will result in a change

to our current business plan, pursuing a particular transaction or completing any such transaction.

Forward Sale

In February 2013, we entered into a forward sale agreement with one of our established purchasers for a payment of approximately $22.5 million, which was

received on March 1, 2013 in return for a specified volume of crude oil in excess of 200,000 barrels to be delivered over a six month delivery period from our

UK North Sea production.

Production Payment

In March 2013, our wholly-owned subsidiary, EEUK, entered into a sale and purchase agreement (the “Sale and Purchase Agreement”) for $107.5 million

providing for the sale and purchase of a production payment over the proceeds of sale from a proportion of our entitlement to production from its interests in

the Alba and Bacchus fields located in the UK sector of the North Sea (the “Production Payment Transaction”) and the issuance of warrants (discussed

below). Repayment of the production payment will come solely from the proceeds from the sale of production from EEUK’s entitlement from the Alba and

Bacchus fields.

In the event that the Production Payment Transaction does not complete under the terms of the Sale and Purchase Agreement, the deposit paid to EEUK upon

signing of the Sale and Purchase Agreement and all or part of a $1.2 million termination fee would become due and payable by EEUK.

41
Endeavour International Holding B.V.

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

The completion of the Production Payment Transaction is conditional upon, amongst other things, the approval of the UK Secretary of State for Energy and

Climate Change. Contemporaneously with completion under the Sale and Purchase Agreement, EIC expects to issue 3,440,000 warrants to purchase shares of

common stock at an exercise price of $3.014 per share (the “Warrants”).

EEUK’s obligations to refund the deposit and pay the termination fee are secured by first priority liens on EEUK’s interests in the licenses and certain joint

operating agreements governing the fields giving rise to the production subject to the production payment. Upon closing of the purchase and sale of the

production payment, EEUK’s obligations under the production payment will be secured by first priority liens in the same assets and second priority liens in

certain other assets of the Company and its subsidiaries.

Revolving Credit Agreement

In March 2013, the Company, EEUK, Cyan, and certain lenders entered into a third amendment to the Revolving Credit Facility whereby (i) the lenders

consented to the Production Payment Transaction and (ii) the maturity of approximately $100 million of the commitments under the under the Revolving

Credit Facility was extended from October 12, 2013 to June 30, 2014. The remaining principal of the Revolving Credit Facility will mature on October 12,

2013, as previously provided.

Reimbursement Agreement

In March 2013, we amended the Alba Reimbursement Agreement to (i) allow us to enter the Production Payment Transaction, (ii) extend the maturity of the

obligations under the Alba Reimbursement Agreement from December 31, 2013 to June 30, 2014, and (iii) the parties agreed to agree to take the steps necessary

to extend the letter of credit issued pursuant to the Alba Reimbursement Agreement from December 31, 2013 to December 31, 2014.

42
Endeavour International Holding B.V.

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

Note 22 - Supplemental Oil and Gas Disclosures (Unaudited)

Capitalized Costs Relating to Oil and Gas Producing Activities

 2012 2011

Proved $ 876,536 $ 429,246

Unproved 273,298 183,110

Total capitalized costs 1,149,834 612,356

Accumulated depreciation, depletion and amortization (241,338) (192,027) 

Net capitalized costs $ 908,496 $ 420,329

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

 Year Ended December 31,

 2012 2011 2010

Acquisition costs: 

Proved $ 143,004 $ 2,595 $ — 

Unproved 46,878 46,107 1,184

Exploration costs 46,730 51,820 50,328

Development costs 302,038 79,898 22,047

Total costs incurred $538,650 $180,420 $73,559

Results of Operations for Oil and Gas Producing Activities

 Year Ended December 31,

 2012 2011 2010

Revenues $207,181 $41,754 $60,501

Production expenses 51,568 8,622 11,086

DD&A 56,813 14,312 22,020

Income tax expense (benefit) 61,256 11,104 13,698

Results of activities $ 37,544 $ 7,716 $13,697

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

43
Endeavour International Holding B.V.

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

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, 2012, 2011 and 2010.

 Year Ended December 31,

 2012 2011 2010

Proved Oil Reserves (MBbls): 

Proved reserves at beginning of year 4,060 3,664 3,348

Production (1,994) (373) (545) 

Purchases of reserves 11,071 303 — 

Sale of reserves in place — — — 

Extensions and discoveries 1,992 — 457

Revisions of previous estimates (1,396) 466 404

Proved reserves at end of year 13,733 4,060 3,664

Proved Developed Oil Reserves (MBbls) - end of year 5,261 1,270 1,240

 Year Ended December 31,

 2012 2011 2010

Proved Gas Reserves (MMcf): 

Proved reserves at beginning of year 50,723 56,177 78,316

Production (91) (94) (3,071) 

Purchases of reserves 1,409 90 — 

Sales of reserves in place — — (51,522) 

Extensions and discoveries 473 — 26,692

Revisions of previous estimates 4,387 (5,450) 5,762

Proved reserves at end of year 56,901 50,723 56,177

Proved Developed Gas Reserves (MMcf) - end of year 3,147 795 555

44
Endeavour International Holding B.V.

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

 Year Ended December 31,

 2012 2011 2010

Proved Reserves (MBOE): 

Proved reserves at beginning of year 12,514 13,027 16,401

Production (2,009) (389) (1,057) 

Extensions and discoveries 2,071 — 4,906

Purchase of proved reserves, in place 11,306 — — 

Sales of reserves — — (8,587) 

Purchase of proved reserves, in place — 318 — 

Revisions of previous estimates (665) (442) 1,364

Proved reserves at end of year 23,217 12,514 13,027

Proved Developed Reserves (MBOE) - end of year 5,785 1,402 1,333

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. 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, 2012 and 2011, the prices used to determine the estimates of future cash inflows were as follows:

 December 31,

 2012 2011

 Oil Gas Oil Gas

 ($/Barrel) ($/Mcf) ($/Barrel) ($/Mcf)

United Kingdom 111.13 9.34 110.77 8.75

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.

45
Endeavour International Holding B.V.

Notes to Consolidated Financial Statements

(Amounts in thousands, except per unit data)

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.

Standardized Measure of Discounted Future Net Cash Flows

 2012 2011

Future cash inflows $2,035,208 $ 941,208

Future production costs (568,414) (144,106) 

Future development costs (581,277) (306,628) 

Future income tax expense (277,436) (238,111) 

Future net cash flows (undiscounted) 608,081 252,363

Annual discount of 10% for estimated timing 122,780 37,250

Standardized measure of future net cash flows $ 485,301 $ 215,113

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

 2012 2011 2010

Standardized measure, beginning of period $ 215,113 $ 73,550 $ 49,192

Net changes in prices and production costs 7,389 155,630 83,525

Future development costs incurred 164,562 66,156 19,259

Net changes in estimated future development costs (219,581) 13,359 (38,039) 

Revisions of previous quantity estimates (32,876) (18,771) 20,870

Extensions and discoveries 102,386 — 75,066

Accretion of discount 37,613 15,050 1,979

Changes in income taxes, net (74,778) (136,157) (35,306) 

Sale of oil and gas produced, net of production costs (159,450) (33,083) (49,415) 

Purchased reserves 456,810 26,340 — 

Sales of reserves in place — — (63,448) 

Change in production, timing and other (11,887) 53,039 9,867

Standardized measure, end of period $ 485,301 $ 215,113 $ 73,550

46