XLON:ENDV Endeavour International Corp Quarterly Report 10-Q Filing - 6/30/2012

Effective Date 6/30/2012

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Table of Contents

 

 

United States

Securities and Exchange Commission

Washington, D.C. 20549

 

 

Form 10-Q

 

 

(Mark One)

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

For the Quarterly Period Ended June 30, 2012

or

 

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

For the transition period from                  to                

Commission file number: 1-32212

 

 

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)

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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    x  Yes    ¨  No

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

 

Large accelerated filer   ¨    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

As of August 6, 2012, 46.6 million shares of the registrant’s common stock were outstanding.

 

 

 


Table of Contents

Index

 

Part I: Financial Information

  

Item 1: Financial Statements

  

Condensed Consolidated Balance Sheets

     1   

Condensed Consolidated Statements of Operations

     3   

Condensed Consolidated Statements of Cash Flows

     4   

Notes to Condensed Consolidated Financial Statements

     5   

Item 2: Management’s Discussion and Analysis of Financial Condition and Results of Operations

     21   

Item 3: Quantitative and Qualitative Disclosures About Market Risk

     37   

Item 4: Controls and Procedures

     37   

Part II. Other Information

  

Item 1A: Risk Factors

     38   

Item 6: Exhibits

     38   

Signatures

     41   

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

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


Table of Contents

Part I: Financial Information

Item 1: Financial Statements

Endeavour International Corporation

Condensed Consolidated Balance Sheets

(Unaudited)

(Amounts in thousands)

 

     June 30,      December 31,  
     2012      2011  
Assets   

Current Assets:

     

Cash and cash equivalents

   $ 94,570      $ 106,036  

Restricted cash

     178        —     

Accounts receivable

     37,354        8,649  

Prepaid expenses and other current assets

     42,042        18,840  
  

 

 

    

 

 

 

Total Current Assets

     174,144        133,525  

Property and Equipment, Net ($355,211 and $258,334 not subject to amortization at June 30, 2012 and December 31, 2011, respectively)

     810,378        549,196  

Goodwill

     258,973        211,886  

Other Assets

     55,681        30,384  
  

 

 

    

 

 

 

Total Assets

   $ 1,299,176      $ 924,991  
  

 

 

    

 

 

 

See accompanying notes to condensed consolidated financial statements.

 

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Table of Contents

Endeavour International Corporation

Condensed Consolidated Balance Sheets

(Unaudited)

(Amounts in thousands)

 

     June 30,     December 31,  
     2012     2011  
Liabilities and Stockholders’ Equity   

Current Liabilities:

    

Accounts payable

   $ 87,596     $ 62,275  

Current maturities of debt

     12,500       12,350  

Accrued expenses and other

     36,844       20,549  
  

 

 

   

 

 

 

Total Current Liabilities

     136,940       95,174  

Long-Term Debt

     797,285       455,028  

Deferred Taxes

     106,022       115,759  

Other Liabilities

     77,500       61,248  
  

 

 

   

 

 

 

Total Liabilities

     1,117,747       727,209  

Commitments and Contingencies

    

Series C Convertible Preferred Stock:

    

Series C preferred stock - Liquidation preference: $37,000 and $37,000 at June 30, 2012 and December 31, 2011, respectively

     43,703       43,703  

Stockholders’ Equity:

    

Series B preferred stock - Liquidation preference: $3,509 and $3,430 at June 30, 2012 and December 31, 2011, respectively

     —          —     

Common stock; shares issued and outstanding – 46,629 and 37,663 shares at June 30, 2012 and December 31, 2011, respectively

     47       38  

Additional paid-in capital

     491,031       420,412  

Treasury stock, at cost - 72 and 72 shares at June 30, 2012 and December 31, 2011, respectively

     (587     (587

Accumulated deficit

     (352,765     (265,784
  

 

 

   

 

 

 

Total Stockholders’ Equity

     137,726       154,079  
  

 

 

   

 

 

 

Total Liabilities and Stockholders’ Equity

   $ 1,299,176     $ 924,991  
  

 

 

   

 

 

 

See accompanying notes to condensed consolidated financial statements.

 

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Table of Contents

Endeavour International Corporation

Condensed Consolidated Statement of Operations

(Unaudited)

(Amounts in thousands, except per share data)

 

     Three Months Ended     Six Months Ended  
     June 30,     June 30,  
     2012     2011     2012     2011  

Revenues

   $ 23,003     $ 19,053     $ 38,169     $ 33,157  

Cost of Operations:

        

Operating expenses

     5,742       6,352       10,640       11,392  

Depreciation, depletion and amortization

     10,627       7,004       18,533       13,326  

Impairment of oil and gas properties

     19,960       —          35,700       —     

General and administrative

     5,030       4,948       10,353       9,662  
  

 

 

   

 

 

   

 

 

   

 

 

 

Total Expenses

     41,359       18,304       75,226       34,380  
  

 

 

   

 

 

   

 

 

   

 

 

 

Income (Loss) From Operations

     (18,356     749       (37,057     (1,223
  

 

 

   

 

 

   

 

 

   

 

 

 

Other Income (Expense):

        

Derivatives:

        

Unrealized gains (losses)

     3,805       (6,448     (973     (1,984

Interest expense

     (25,255     (7,831     (44,963     (19,952

Loss on early extinguishment of debt

     (21,661     —          (21,661     (402

Interest income and other

     (3,676     (48     (6,346     (186
  

 

 

   

 

 

   

 

 

   

 

 

 

Total Other Expense

     (46,787     (14,327     (73,943     (22,524
  

 

 

   

 

 

   

 

 

   

 

 

 

Loss Before Income Taxes

     (65,143     (13,578     (111,000     (23,747

Income Tax Expense (Benefit)

     (14,335     2,026       (24,929     (687
  

 

 

   

 

 

   

 

 

   

 

 

 

Net Loss

     (50,808     (15,604     (86,071     (23,060

Preferred Stock Dividends

     456       506       911       1,052  
  

 

 

   

 

 

   

 

 

   

 

 

 

Net Loss to Common Stockholders

   $ (51,264   $ (16,110   $ (86,982   $ (24,112
  

 

 

   

 

 

   

 

 

   

 

 

 

Net Loss per Common Share:

        

Basic and Diluted

   $ (1.31   $ (0.42   $ (2.26   $ (0.74
  

 

 

   

 

 

   

 

 

   

 

 

 

Weighted Average Number of Common Shares Outstanding:

        

Basic and Diluted

     39,020       38,612       38,438       32,714  
  

 

 

   

 

 

   

 

 

   

 

 

 

See accompanying notes to condensed consolidated financial statements.

 

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Table of Contents

Endeavour International Corporation

Condensed Consolidated Statement of Cash Flows

(Unaudited)

(Amounts in thousands)

 

     Six Months Ended June 30,  
     2012     2011  

Cash Flows from Operating Activities:

    

Net loss

   $ (86,071   $ (23,060

Adjustments to reconcile net loss to net cash used in operating activities:

    

Depreciation, depletion and amortization

     18,533       13,326  

Impairment of oil and gas properties

     35,700       —     

Deferred tax benefit

     (24,008     (875

Unrealized losses on derivatives

     973       1,984  

Amortization of non-cash compensation

     3,114       1,792  

Amortization of loan costs and discount

     7,311       6,157  

Non-cash interest expense

     5,153       5,928  

Loss on early extinguishment of debt

     21,661       402  

Other

     4,687       2,790  

Changes in operating assets and liabilities:

    

Increase in receivables

     (15,670     (1,687

Increase in other current assets

     (23,970     (9,376

Increase (decrease) in liabilities

     24,500       (21,248
  

 

 

   

 

 

 

Net Cash Used in Operating Activities

     (28,087     (23,867

Cash Flows From Investing Activities:

    

Capital expenditures

     (116,458     (66,727

Acquisitions

     (228,105     (22,240

Increase in restricted cash

     (178     (1,347
  

 

 

   

 

 

 

Net Cash Used in Investing Activities

     (344,741     (90,314

Cash Flows From Financing Activities:

    

Repayments of borrowings

     (244,565     (92,050

Borrowings under debt agreements, net of debt discount

     580,000       —     

Proceeds from issuance of common stock

     61,088       118,444  

Dividends paid

     (416     (973

Payments for early extinguishment of debt

     (7,248     —     

Financing costs paid

     (27,500     (654

Other financing

     3       376  
  

 

 

   

 

 

 

Net Cash Provided by Financing Activities

     361,362       25,143  

Net Decrease in Cash and Cash Equivalents

     (11,466     (89,038

Cash and Cash Equivalents, Beginning of Period

     106,036       99,267  
  

 

 

   

 

 

 

Cash and Cash Equivalents, End of Period

   $ 94,570     $ 10,229  
  

 

 

   

 

 

 

See accompanying notes to condensed consolidated financial statements.

 

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Table of Contents

Endeavour International Corporation

Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

Note 1 – General

Endeavour International Corporation (a Nevada corporation) is an independent oil and gas company engaged in the acquisition, exploration and development of energy reserves. As used in these Notes to Condensed Consolidated Financial Statements, the terms “Endeavour,” “we,” “us,” “our” and similar terms refer to Endeavour International Corporation and, unless the context indicates otherwise, its consolidated subsidiaries. The accompanying financial statements should be read in conjunction with the audited consolidated financial statements and notes included in our Annual Report on Form 10–K for the year ended December 31, 2011.

Basis of Presentation and Use of Estimates

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

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

 

   

proved oil and gas reserves,

 

   

expected future cash flow from proved oil and gas properties,

 

   

future dismantlement and restoration costs,

 

   

fair values used in purchase accounting; and

 

   

fair value of derivative instruments.

New Accounting Developments

On January 1, 2012, we adopted the following accounting standards:

 

   

Fair Value—In May 2011, the Financial Accounting Standards Board (the “FASB”) issued an accounting standard on fair value measurements that clarified the application of existing guidance and disclosure requirements, changed certain fair value measurement principles and required additional disclosures about fair value measurements.

 

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Endeavour International Corporation

Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

 

   

Comprehensive Income—In June 2011, the FASB issued guidance impacting the presentation of comprehensive income. The guidance eliminated the option to report components of other comprehensive income in the statement of changes in equity or in a footnote to the financial statements.

 

   

Goodwill—In September 2011, the FASB amended 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.

The adoption of each of these standards did not have a material impact on our financial position or results of operations.

Note 2 Acquisitions

On December 23, 2011, we entered into a Sale and 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 for $330 million (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 $219.6 million.

Upon the closing of the Alba field portion of the COP acquisition, the net proceeds from the offering of our Senior Notes due 2018 were released from escrow. We used approximately $205 million of the net proceeds from the sale of the notes together with approximately $14 million of borrowings under our revolving credit facility (the “Revolving Credit Facility”) with Cyan Partners, LP (“Cyan”), as administrative agent and the other lenders party thereto, to fund the cash consideration for the acquisition of the Alba Property. Additional information on these related financing transactions is discussed in Note 4.

The acquisition of the additional interest in the Alba field was accounted for using the business combination method. The following summarizes the preliminary 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

     (35,823
  

 

 

 

Total purchase price

   $ 219,577  
  

 

 

 

Allocation of purchase price:

  

Property and equipment

   $ 189,442  

Goodwill

     47,087  

 

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Table of Contents

Endeavour International Corporation

Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

 

Current assets

     24,336  

Current liabilities

     (12,715

Deferred tax liability

     (11,831

Other long-term liabilities

     (16,742
  

 

 

 

Total purchase price

   $ 219,577  
  

 

 

 

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 purchase price allocation is based on a preliminary assessment of the fair value of the assets acquired and liabilities assumed in the Alba field portion of the COP Acquisition. 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. These estimates are subject to change as additional information becomes available and is assessed by Endeavour.

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.

 

     Three Months Ended
June 30,
    Six Months Ended
June 30,
 
     2012     2011     2012     2011  

Revenues

     23,013        85,603        110,685        165,408   

Net income (loss) to common shareholders

     (25,186     (16,612     (50,642     (26,482

Net income (loss) per share - basic and diluted

     (0.65     (0.51     (1.32     (0.69

Revenues of and income from operations associated with the acquired interest in the Alba field for the period from May 31, 2012 through June 30, 2012 did not have a significant impact on our revenues and results of operations.

The remaining producing assets yet to be acquired include a 40% net working interest in the MacCulloch field and an 18% net working interest in the Nicol field. In connection with closing the acquisition of the Alba Property separately from the other two fields, we paid an additional $2 million deposit to the Sellers relating to the remaining properties, bringing our total deposit to $10 million. We intend to pursue closing on the remaining interests of the COP Acquisition in the near future, though there can be no assurance that we will be able to do so successfully.

 

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Endeavour International Corporation

Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

 

Note 3 – Property and Equipment

Property and equipment included the following at the dates indicated below:

 

     June 30,
2012
    December 31,
2011
 

Oil and gas properties under the full cost method:

    

Subject to amortization

   $ 673,297     $ 496,667  

Not subject to amortization:

    

Incurred in 2012

     133,737       —     

Incurred in 2011

     121,293       138,912  

Incurred in 2010

     44,156       47,208  

Incurred prior to 2010

     56,025       72,214  
  

 

 

   

 

 

 
     1,028,508       755,001  

Computers, furniture and fixtures

     8,286       6,421  
  

 

 

   

 

 

 

Total property and equipment

     1,036,794       761,422  

Accumulated depreciation, depletion and amortization

     (226,416     (212,226
  

 

 

   

 

 

 

Net property and equipment

   $ 810,378     $ 549,196  
  

 

 

   

 

 

 

The costs not subject to amortization relate to unproved properties and properties being made ready to be placed into service, which are excluded from amortizable capital costs until it is determined whether or not proved reserves can be assigned to such properties. 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 and Bacchus projects. We expect exploration costs not subject to amortization to be transferred to the amortization base over the next three years as development plans are completed and production commences on existing discoveries, including the Rochelle and Bacchus projects. We capitalized $6.3 million and $4.1 million in interest related to drilling, development and exploration activities for the quarters ended June 30, 2012 and 2011, respectively. The capitalized interest for each period is primarily related to our U.K. activities, such as the Bacchus and Rochelle projects. For the six months ended June 30, 2012 and 2011, we capitalized $11.9 million and $5.9 million, respectively, in interest related to exploration and development.

For the second quarter of 2012, we recorded a pre-tax impairment of $20.0 million related to our U.S. oil and gas properties through the application of the full cost ceiling test at the end of the quarter. For the six months ended June 30, 2012 we recorded a pre-tax impairment of $35.7 million related to our U.S. oil and gas properties. The impairment was primarily due to the decline in U.S. gas prices. The prices used to determine the impairment for our U.S. properties were $95.54 per barrel for oil and $3.13 per Mcf for gas. We did not have an impairment of U.K. oil and gas properties through the application of the full cost ceiling test at the end of the second quarter 2012, which utilized prices of $112.40 per barrel for oil and $8.68 per Mcf for gas.

 

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Endeavour International Corporation

Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

 

Note 4 – Debt Obligations

At June 30, 2012, we had $831.0 million in outstanding debt. Our debt consisted of the following at June 30, 2012 and December 31, 2011:

 

     June 30,     December 31,  
     2012     2011  

Senior term loan, 15% fixed rate, due 2013

   $ —        $ 240,349  

Subordinated notes, 12% fixed rate, due 2014

     29,820       32,012  

Convertible bonds, 11.5% until March 31, 2014 and 7.5% thereafter, due 2016

     66,170       62,523  

Senior notes, 12% fixed rate, due 2018

     500,000       —     

Convertible senior notes, 5.5% fixed rate, due 2016

     135,000       135,000  

Revolving credit facility, 12% fixed rate, due 2013

     100,000       —     
  

 

 

   

 

 

 
     830,990       469,884  

Less: debt discount

     (21,205     (2,506

Less: current maturities

     (12,500     (12,350
  

 

 

   

 

 

 

Long-term debt

   $ 797,285     $ 455,028  
  

 

 

   

 

 

 

Standby letters of credit outstanding for abandonment liabilities

   $ —        $ 31,724  
  

 

 

   

 

 

 

Senior Notes Offering

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 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.

Prior to the closing of the Alba field portion of the COP Acquisition, the net proceeds of the 2018 Note offering were held in escrow. On May 31, 2012, concurrent with the closing of the Alba field portion of the COP Acquisition, the net proceeds were released from escrow and used to fund the acquisition and repay all outstanding amounts under the Senior Term Loan (defined below).

 

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Endeavour International Corporation

Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

 

5.5% Convertible Senior Notes

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

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 COP 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 COP 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 field portion of the COP Acquisition. In connection with the closing of the acquisition of the Alba property, 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.

11.5% Convertible Bonds

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

Senior Term Loan

In August 2010, we entered into a credit agreement with Cyan, as administrative agent, and various lenders for a senior term loan, in the aggregate amount of $150 million, which was subsequently increased to $235 million (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.

 

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Endeavour International Corporation

Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

 

Subordinated Notes

Our Subordinated Notes due 2014 bear interest at an annual rate of 10%, plus 2% capitalized to the outstanding principal amount. We pay interest, in cash, on the unpaid principal amount of the Subordinated Notes quarterly on March 31, June 30, September 30 and December 31 of each year.

Fair Value

The fair value of our outstanding debt obligations was $832 million and $420 million at June 30, 2012 and December 31, 2011, respectively. The fair value of our long-term debt was valued using an income approach, using credit adjusted discount rate at the reporting date, and classified as Level 3 in the fair value hierarchy.

Note 5 – Income Taxes

Our income tax expense relates primarily to our operations in the U.K., including current tax expense (benefit) related to Petroleum Revenue Tax on our Alba field in the U.K. of 50%. We currently do not record tax benefits due to losses in the U.S. as there was no assurance that we could generate any U.S. taxable earnings, resulting in a full valuation allowance of all deferred tax assets generated. During July 2011, the U.K. government enacted an increase in the supplemental corporate tax rate due to a tax law change that raised the existing supplementary charge on profits from North Sea oil and gas production from 20% to 32%, in addition to the U.K. corporate tax of 30%.

For 2011 and the first quarter of 2012, we determined our tax expense utilizing our estimated annual effective tax rate. Due to the significant impact of closing the Alba field portion of the COP Acquisition during the second quarter of 2012 on the estimated annual effective tax rate, management has determined that an estimated annual effective tax rate is not reliable for the current interim reporting period and is recording income taxes using the actual tax rate for the year-to-date results.

Note 6 – Asset Retirement Obligations

Our asset retirement obligations relate to obligations for the future plugging and abandonment of oil and gas properties. The following table provides a rollforward of our asset retirement obligations for the six months ended June 30, 2012 and 2011:

 

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Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

 

     Six Months Ended  
     June 30,  
     2012     2011  

Carrying amount of asset retirement obligations as of beginning of period

   $ 47,258     $ 42,997  

Accretion expense (included in DD&A expense)

     3,750       2,434  

Impact of foreign currency exchange rate changes

     1,162       1,871  

Payment of asset retirement obligations

     (4,741     (10,680

Liabilities incurred related to acquired properties

     16,742       —     
  

 

 

   

 

 

 

Carrying amount of asset retirement obligations as of end of period

     64,171       36,622  

Less: Current portion

     (2,117     (6,677
  

 

 

   

 

 

 

Long-term asset retirement obligations

   $ 62,054     $ 29,945  
  

 

 

   

 

 

 

Note 7 – Equity Transactions

On June 13, 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. We intend to use the offering proceeds for general corporate purposes.

On May 23, 2012, we entered into Warrant Agreements through which we issued certain investors warrants to purchase a total of 2,000,000 shares of our common stock at an exercise price of $10.50 per share. The Warrant Agreements were entered into in connection with the May 31, 2012 Reimbursement Agreement (see Note 13 for additional discussion of the Reimbursement Agreement.) The terms of all 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.

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.

Note 8 – Stock-Based Compensation Arrangements

We grant restricted stock and stock options to employees and directors as incentive compensation. The restricted stock and options generally vest over three years. Non-cash stock-based compensation is recorded in general and administrative (“G&A”) expenses or capitalized G&A as follows:

 

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Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

 

     Three Months Ended
June  30,
     Six Months Ended
June 30,
 
     2012      2011      2012      2011  

G & A Expenses

   $ 1,141      $ 634      $ 2,258      $ 1,277  

Capitalized G & A

     415        283        856        515  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total non-cash stock-based compensation

   $ 1,556      $ 917      $ 3,114      $ 1,792  
  

 

 

    

 

 

    

 

 

    

 

 

 

At June 30, 2012, total compensation cost related to awards not yet recognized was approximately $11.8 million and is expected to be recognized over a weighted average period of less than three years.

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 stock options during 2011 or 2012. Information relating to outstanding stock options is summarized as follows:

 

     Number of
Shares
Underlying
Options
    Weighted
Average
Exercise
Price per
Share
     Weighted
Average
Contractual
Life in
Years
     Aggregate
Intrinsic
Value
 

Balance outstanding—January 1, 2012

     299     $ 8.95        

Exercised

     (1     6.73        

Forfeited

     (31     9.20        

Expired

     (14     14.28        
  

 

 

   

 

 

       

Balance outstanding—June 30, 2012

     253     $ 8.62        5.7      $ 401  
  

 

 

   

 

 

    

 

 

    

 

 

 

Currently exercisable—June 30, 2012

     253     $ 8.62        5.7      $ 401  
  

 

 

   

 

 

    

 

 

    

 

 

 

Restricted Stock

Restricted stock awards are valued based on the closing price of our common stock on the measurement date, which is typically the date of grant. The status of the restricted shares granted as of June 30, 2012 and the changes during the six months ended June 30, 2012 are presented below:

 

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Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

 

     Number of
Shares
    Weighted
Average Grant
Date Fair
Value per
Share
 

Balance outstanding—January 1, 2012

     830     $ 10.13  

Granted

     357       9.53  

Vested

     (356     9.29  

Forfeited

     (40     9.95  
  

 

 

   

 

 

 

Balance outstanding—June 30, 2012

     791     $ 10.36  
  

 

 

   

 

 

 

Total grant date fair value of shares vesting during the period

   $ 3,309    
  

 

 

   

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. The shares issued may range from 0% to 200% of the number of Performance Units specified in the agreements. At June 30, 2012, 422,310 Performance Units were issued pursuant to these agreements, whereby an equal number of shares of common stock would be issued if the grant reaches a payout of 100% at the end of the performance period.

Note 9 – Loss Per Share

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

For each of the periods presented, shares associated with stock options, warrants, convertible debt, convertible preferred stock and certain stock incentive plans were not included because their inclusion would be anti-dilutive.

 

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Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

 

The common shares potentially issuable arising from these instruments, which were outstanding during the periods presented in the financial statements consisted of:

 

     June 30,  
     2012      2011  

Warrants, options and stock-based compensation

     2,896        141  

Convertible debt

     11,298        3,576  

Convertible preferred stock

     4,229        4,686  
  

 

 

    

 

 

 
     18,423        8,403  
  

 

 

    

 

 

 

Note 10 – 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, 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.

 

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Notes to Condensed Consolidated Financial Statements

(Unaudited)

(Amounts in tables 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. The following table summarizes the valuation of our investments and financial instruments by pricing levels as of June 30, 2012 and 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
 

As of June 30, 2012:

          

Oil and gas puts

   $ —         $ 1,587      $ 32     $ 1,619  

Embedded derivatives

     —           —           (15,136     (15,136
  

 

 

    

 

 

    

 

 

   

 

 

 

Total derivative liabilities

   $ —         $ 1,587      $ (15,104   $ (13,517
  

 

 

    

 

 

    

 

 

   

 

 

 

As of December 31, 2011:

          

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 were measured using income approach 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.

We use a derivative valuation model to derive the value of our embedded derivative features. Key inputs into this valuation model are our current stock price, risk-free interest rates, the stock volatility and our implied credit spread. The first three aforementioned inputs are based on observable market data and are considered Level 2 inputs while the last two aforementioned inputs are unobservable and thus require management’s judgment and are considered Level 3 inputs. A decrease or increase in the implied credit spread of 5% would increase or decrease, respectively, the liability by approximately $2 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 a $2 million decrease or increase, respectively. The fair value measurement is considered a Level 3 measurement within the fair value hierarchy.

 

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Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

 

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

 

     Six Months Ended
June 30,
 
     2012     2011  

Balance at beginning of period

   $ (15,858   $ (26,703

Realized and unrealized gains (losses) included in earnings

     754       (226
  

 

 

   

 

 

 

Balance at end of period

   $ (15,104   $ (26,929
  

 

 

   

 

 

 

Changes in unrealized gains (losses) relating to derivatives assets and liabilities still held at the end of the period

   $ 754     $ (226
  

 

 

   

 

 

 

Note 11 – Derivative Instruments

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, or 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.

The fair market value of these derivative instruments is included in our balance sheet as follows for the periods indicated:

 

     June 30,
2012
    December 31,
2011
 

Derivatives not designated as hedges:

    

Oil and gas commodity derivatives:

    

Assets:

    

Prepaid expenses and other current assets

   $ 1,619     $ 1,247  

Embedded derivatives related to debt and equity instruments:

    

Liabilities:

    

Other liabilities - long-term

   $ (15,136   $ (16,067

If all counterparties failed to perform, our maximum loss would have been $1.6 million as of June 30, 2012.

 

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Notes to Condensed Consolidated Financial Statements

(Unaudited)

(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 for the periods indicated:

 

     Three Months Ended     Six Months Ended  
     June 30,     June 30,  
     2012     2011     2012     2011  

Derivatives not designated as hedges:

        

Oil and gas commodity derivatives

        

Unrealized gains (losses)

   $ (887   $ (378     (1,904     (2,389
  

 

 

   

 

 

   

 

 

   

 

 

 
     (887     (378     (1,904     (2,389

Embedded derivatives related to debt and equity instruments

        

Unrealized gains (losses)

   $ 4,692     $ (6,070     931       405  
  

 

 

   

 

 

   

 

 

   

 

 

 

As of June 30, 2012, our outstanding commodity derivatives covered approximately 566 Mbbls of oil and 248 MMcf of natural gas cumulative through the end of 2012 and consisted of eight oil and three natural gas option contracts with three major counterparties.

Note 12 – Supplemental Cash Flow Information

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

 

     Six Months Ended June 30,  
     2012      2011  

Interest paid

   $ 25,147      $ 15,923  
  

 

 

    

 

 

 

Income taxes paid

   $ 2,089      $ 5,786  
  

 

 

    

 

 

 

Note 13 – Commitments and Contingencies

Terminated Acquisition of Marcellus Assets

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

 

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Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

 

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.

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.

One of the reimbursement agreements, 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. 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 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 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.

 

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Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

 

The second reimbursement agreement covers approximately $120 million related to our decommissioning obligations for the Alba field. 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 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 June 30, 2012, we do not expect to begin decommissioning activities for the Alba field until 2030 or later.

The letters of credit supporting our abandonment liabilities expire during 2013. Upon expiration, we may either enter into new facilities or pledge our own cash to secure new letters of credit for our abandonment liabilities. We are engaged in the bank syndication process to put a new revolving credit facility in place that will encompass both our existing Revolving Credit Facility and replace these two reimbursement agreements at an appropriate time in the future.

 

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Item 2: Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion should be read in conjunction with our unaudited Condensed Consolidated Financial Statements and related notes thereto included elsewhere in this report. 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.

Strategy

We are an independent oil and gas company engaged in the production, exploration, development and acquisition of crude oil and natural gas in the central U.K. North Sea and U.S. onshore. Our strategy is to build a balanced portfolio across multiple dimensions by:

 

   

Pursuing low risk exploration and development activities in the central U.K. North Sea.

 

   

Balancing the longer cycle times and layer up-front development costs of the U.K. North Sea with onshore North America activities in areas known to have proven petroleum systems. Although active in proven onshore unconventional plays in Haynesville and Marcellus, we are pursuing new and evolving plays. This in an evolving area for us.

 

   

Focusing on both oil and natural gas by not picking one commodity over the other, but investing capital where we believe we can achieve acceptable returns.

 

   

Constantly analyzing our portfolio of assets to determine whether continued investment, exploitation or monetization is the best method for capturing return on invested capital.

 

   

Allocating resources among producing properties, development projects and potential acquisitions to maximize value and effectively pursue our strategy.

 

   

Utilizing conventional and unconventional technologies in basins that have historically generated and produced substantial quantities of oil and gas and that we believe will yield commercial quantities of oil and gas reserves through improved drilling, completion and operating technologies.

We remain committed and on-track with our strategy to build a sustainable producing asset base that generates cash flow in excess of its annual capital and operating expense requirements. We continue to view our producing assets as the foundation for organic growth through our development projects and other growth activities in our core areas in the central U.K. North Sea and onshore North America.

2012 Overview

We began the year with three primary goals to further our strategy. Throughout the first six months of 2012, we have reached several milestones toward these goals. We expect to maintain our focus and concentration on these goals through the remainder of the year.

 

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Goals

  

Objectives

  

Performance Results

Bacchus Development

  

-        Commence production in a timely and cost-effective manner.

 

-        Increase exposure to oil.

  

-        The first Bacchus development well achieved production during the second quarter.

 

-        Our physical production from Bacchus was approximately 85,000 BOE for the second quarter of 2012.

 

-        The second development well began production on July 29, 2012.

COP Acquisition

  

-        Complete the COP Acquisition.

 

-        Increase current production levels and cash flows.

  

-        Alba Field portion of the COP Acquisition closed on May 31, 2012.

 

-        Physical production from our additional Alba interest was approximately 180,000 BOE for the month ended June 30, 2012.

 

-        We are working to close on the remaining interests in the COP Acquisition.

Rochelle Development

  

-        Commence production in a timely and cost-effective manner.

  

-        The Rochelle development continues on schedule for first production in the fourth quarter of 2012.

 

-        The contracted drilling rig arrived in July 2012 and commenced operations to drill the first of two planned production wells.

 

-        The required modifications to the Scott Platform are expected to be substantially complete during the third quarter.

Reaching these milestones required financing activity during the first six months of 2012 as further discussed in “Liquidity and Capital Resources, including:

 

   

Senior Note Offering: On February 23, 2012, we closed the private placement of $500 million aggregate principal amount of the 2018 Notes. We used the net proceeds from the 2018 Notes to fund the Alba field portion of the COP Acquisition, to repay all amounts outstanding under our Senior Term Loan, and for general corporate purposes.

 

   

Equity Offering: On June 13, 2012, we completed an underwritten public offering of 8.6 shares of our 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. We intend to use the offering proceeds for our development projects.

 

   

Revolving Credit Facility: On April 12, 2012, we entered into a $100 million Revolving Credit Facility, with Cyan Partners, LP, as administrative agent. We intend to use proceeds from the $100 million borrowings under the Revolving Credit Facility for general corporate purposes.

 

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Results of Operations

Net loss to common stockholders for the six months ended June 30, 2012 was $87.0 million, or $2.26 per share, compared to $24.1 million, or $0.74 per share, for the same period in 2011. The change in the net loss to common stockholders for these periods is primarily due to impairments of oil and gas properties and increased interest expenses, partially offset by increased revenues as our sales volumes increased and increased deferred tax benefits.

Net loss to common stockholders for the second quarter of 2012 increased to $51.3 million compared to $16.1 million for the same period in 2011 primarily due to impairments of oil and gas properties and increased interest expenses, partially offset by increased revenues as our sales volumes increased and increased deferred tax benefits.

In addition to our operations, our net income can be significantly affected by various non-cash items, such as unrealized gains and losses on our derivatives, impairment of oil and gas properties, and foreign currency impact of long-term liabilities. Excluding these non-cash items, Net Loss as Adjusted for the six months ended June 30, 2012 was $50.6 million compared to Net Loss as Adjusted of $22.3 million for the same period in 2011. Net Loss as Adjusted for the second quarter 2012 was $35.2 million as compared to Net Loss as Adjusted of $9.3 million for the same period in 2011. The increase in Net Loss as Adjusted is primarily due to increased interest expenses, partially offset by increased revenues.

Adjusted EBITDA decreased to $10.7 million for the six months ended June 30, 2012 from $11.7 million for the same period in 2011. The decrease in Adjusted EBITDA was due to expenses related to our reimbursement agreements covering certain of our abandonment liabilities and foreign currency impact of long-term liabilities, partially offset by increased revenue from the initial production at Bacchus.

Adjusted EBITDA increased to $8.4 million for the second quarter of 2012 from $7.6 million for the same period in 2011 due to increased revenue from the initial production at Bacchus and foreign currency gain on long-term liabilities, partially offset by expenses related to our reimbursement agreements covering certain of our abandonment liabilities. For definitions of Net Income (Loss) as Adjusted and Adjusted EBITDA, and a reconciliation of each to the nearest comparable GAAP measure, please see “Reconciliation of Non-GAAP Measures.”

Our cash flows used in operating activities increased to $28.1 million for the six months ended June 30, 2012 as compared to cash flows used in operating activities of $23.9 million for the same period in 2011. The change was primarily due to increased interest expense related to our outstanding indebtedness, partially offset by increased revenue from the initial production at Bacchus.

Revenue and Sales Volume

Our physical daily production was approximately 6,437 BOE and 3,204 BOE for the second quarter of 2012 and 2011, respectively, and 5,205 BOE and 3,198 BOE for the six months ended June 30, 2012 and 2011, respectively, reflecting the impact of the initial production from Bacchus, our increased interest in Alba and increased U.S. gas production.

 

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We record oil revenues using the sales method, i.e. when delivery has occurred. While certain of our U.K. oil fields produce into pipelines and thereby allow us to record revenue each month, the remaining fields, including the Alba field, are dependent upon tanker liftings to deliver oil production to the buyers. The May 31, 2012 closing of the Alba field portion of the COP Acquisition did not allow sufficient time for our production at the field to satisfy a full tanker lifting. While our physical production for acquired interest in the Alba field was approximately 180,000 BOE for the month ended June 30, 2012, we will not record revenue for any of the production associated with our incremental additional interest until the third quarter. Our first tanker lifting for our newly acquired interest in Alba occurred during the first week of July 2012. The July lifting covered approximately 545,000 barrels, including a one-time catch-up of Alba production for periods prior to closing, and placed us in an overlift position at the end of July. During the remainder of July and August 2012, our Alba production is expected to replenish inventory and eliminate our overlift position, thereby providing no further liftings for the period. Due to scheduled maintenance, we anticipate that liftings at Alba will be lower for the remainder of 2012, but more frequent, averaging 150,000 to 200,000 barrels per month for September through December. Beginning in January 2013, we anticipate a tanker lifting for our Alba production approximately every six weeks covering 220,000 to 260,000 barrels. While we anticipate Alba production to remain steady, revenue will accordingly fluctuate in connection with the frequency and volume of tanker liftings, which are factors not entirely within our control.

For the second quarter of 2012 and 2011, we had sales volume of 4,677 BOE per day and 3,295 BOE per day, respectively. For the six months ended June 30, 2012 and 2011, we had sales volume of 4,426 BOE per day and 3,149 BOE per day, respectively. The increases in sales volume are primarily attributable to the initial production from Bacchus and an increase in U.S. gas sales volumes.

Our revenues increased from $33.2 million during the six months ended June 30, 2011 to $38.2 million in the same period of 2012. Our revenues increased from $19.1 million during second quarter of 2011 to $23.0 million in the same period of 2012. These increases are primarily as a result of increased U.S. gas sales volumes and initial production from Bacchus, partially offset by lower commodity prices in both the U.S. and U.K. As discussed above, we recorded no revenue during the second quarter of 2012 related to our newly acquired interest in the Alba field.

The following table shows our average sales volumes and realized sales prices for our operations for the periods presented.

 

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     Three Months Ended      Six Months Ended  
     June 30,      June 30,  
     2012      2011      2012      2011  

Sales volume (1)

           

Oil and condensate sales (Mbbls):

           

United Kingdom

     191        125        286        225  

United States

     1        1        2        2  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     192        126        288        227  
  

 

 

    

 

 

    

 

 

    

 

 

 

Gas sales (MMcf):

           

United Kingdom

     30        34        51        78  

United States

     1,375        1,012        3,052        1,976  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     1,405        1,046        3,103        2,054  
  

 

 

    

 

 

    

 

 

    

 

 

 

Oil equivalent sales (MBOE)

           

United Kingdom

     196        131        295        238  

United States

     230        169        510        332  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     426        300        805        570  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total BOE per day

     4,677        3,295        4,426        3,149  
  

 

 

    

 

 

    

 

 

    

 

 

 

Physical production volume (BOE per day) (1)

           

United Kingdom

     3,910        1,316        2,401        1,311  

United States

     2,527        1,888        2,804        1,887  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     6,437        3,204        5,205        3,198  
  

 

 

    

 

 

    

 

 

    

 

 

 

Realized Price, before and after derivatives

           

Oil and condensate price ($ per Bbl)

   $ 104.46      $ 117.34      $ 108.67      $ 109.03  
  

 

 

    

 

 

    

 

 

    

 

 

 

Gas price ($ per Mcf)

   $ 2.14      $ 4.13      $ 2.20      $ 4.07  
  

 

 

    

 

 

    

 

 

    

 

 

 

Equivalent oil price ($ per BOE)

   $ 54.05      $ 63.54      $ 47.39      $ 58.18  
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) We record oil revenues using the sales method, i.e. when delivery has occurred. Physical production may differ based on the timing of tanker liftings for international sales. We use the entitlements method to account for sales of gas production.

Our revenues, net income and cash flows from operating activities are very sensitive to changes in the prices we receive for our products. Our production is sold at prevailing market prices, which may be volatile and subject to numerous factors which are outside of our control. It is our business policy to utilize various oil and gas derivative instruments to achieve more predictable cash flows by reducing our exposure to price fluctuations. Further, the current tightly-balanced supply and demand market allows a small variation in supply or demand to significantly impact the market prices for these commodities.

The markets in which we sell our oil and natural gas also materially impact our revenues and cash flows. Oil trades on a worldwide market, and, consequently, price movements for all types and grades of crude oil generally trend in the same direction and within a relatively narrow price range. However, natural gas prices vary among geographic areas as the prices received are

 

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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 majority of our gas sales occur in the U.S. where the gas market is heavily impacted by the increased supply from shale drilling, which has served to significantly depress natural gas prices relative to the U.K. market.

Expenses

For the second quarter of 2012, operating expenses decreased to $5.7 million as compared to $6.4 million for the same period in 2011. For the six months ended June 30, 2012, operating expenses decreased to $10.6 million as compared to $11.4 million for the same period in 2011. The decrease in operating expense from 2011 to 2012 was primarily related to the impact of higher workover expenses during 2011. Operating costs per BOE decreased from $21.18 per BOE for the second quarter of 2011 to $13.49 per BOE for the same period in 2012. Operating costs per BOE decreased from $19.99 per BOE for the six months ended June 30, 2011, to $13.21 per BOE for the six months ended June 30, 2012.

Depreciation, depletion and amortization (“DD&A”) expense increased to $10.6 million from $7.0 million for the second quarter of 2012 and 2011, respectively. DD&A expense also increased to $18.5 million from $13.3 million for the six months ended June 30, 2012 and 2011, respectively. These increases were primarily a result of the increased sales volumes discussed previously and additional accretion expense related to the abandonment liabilities assumed upon the closing of the Alba portion of the COP acquisition.

For the second quarter of 2012, the prices used in the full cost ceiling test for our U.S. properties were $95.54 per barrel for oil and $3.13 per Mcf for gas. We recorded an impairment of $20.0 during the second quarter of 2012 for our U.S. properties. For the second quarter of 2012, the prices used in the full cost ceiling test for our U.K. properties were $112.40 per barrel for oil and $8.68 per Mcf for gas. We have not recorded any impairment during 2012 related to our U.K. properties. The risk that we will be required to record additional impairments of our oil and gas properties, through the application of the full cost ceiling test in subsequent periods, increases when oil and gas prices are low or volatile. If U.S. gas prices continue to face the adverse effects of high gas supply or other factors, we may experience further ceiling test write-downs or other impairments in the future.

General and administrative (“G&A”) expenses increased slightly to $5.0 million during the second quarter of 2012 as compared to $4.9 million for the corresponding period in 2011. G&A expenses increased to $10.4 million during the six months ended June 30, 2012 as compared to $9.7 million for the corresponding period in 2011. These increases primarily resulted from consulting expense and travel cost related to our U.K. acquisition, occupancy fees and other costs. Components of G&A expenses for these periods are as follows:

 

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     Three Months Ended
June 30,
    Six Months Ended
June 30,
 
(Amounts in thousands)    2012     2011     2012     2011  

Compensation

   $ 5,308     $ 4,829     $ 10,506     $ 9,867  

Consulting, legal and accounting fees

     2,331       1,437       4,105       3,158  

Occupancy costs

     622       385       1,004       750  

Other expenses

     73       1,211       764       1,715  
  

 

 

   

 

 

   

 

 

   

 

 

 

Total gross cash G&A expenses

     8,334       7,862       16,379       15,490  

Non-cash stock-based compensation

     1,556       917       3,114       1,792  
  

 

 

   

 

 

   

 

 

   

 

 

 

Gross G&A expenses

     9,890       8,779       19,493       17,282  

Less: capitalized G & A expenses

     (4,860     (3,831     (9,140     (7,620
  

 

 

   

 

 

   

 

 

   

 

 

 

Net G&A expenses

   $ 5,030     $ 4,948     $ 10,353     $ 9,662  
  

 

 

   

 

 

   

 

 

   

 

 

 

Interest expense increased by $17.5 million to $25.3 million for the second quarter of 2012 as compared to $7.8 million for the corresponding period in 2011. Interest expense increased by $25.0 million to $45.0 million for the six months ended June 30, 2012 as compared to $20.0 million for the corresponding period in 2011. For the six months ended June 30, 2012 and 2011, we had non-cash interest expense, including amortization of loan costs and discount, of $12.5 million and $12.1 million, respectively. As discussed in “Liquidity and Capital Resources,” we have completed several financing transactions during 2012 and 2011 that have had a significant impact on our interest expense. Interest expense has increased with the issuance of the Revolving Credit Facility in April 2012, 2018 Notes in February 2012 and the 5.5% Convertible Senior Notes in July 2011. This increase has been partially offset by our repayment of the 6% Convertible Notes April 2011 and the Senior Term Loan in May 2012. As part of the repayment of the Senior Term Loan, we paid an early termination fee of approximately $7 million and wrote off of the remaining deferred financing costs related to the Senior Term Loan of $15 million. In addition, we capitalized a greater portion of interest during 2012 as a result of our increased development activity at Bacchus and Rochelle. The components of interest expense are as follows:

 

     Three Months Ended
June 30,
    Six Months Ended
June 30,
 
(Amounts in thousands)    2012     2011     2012     2011  

Interest expense on debt outstanding at June 30, 2012

   $ 21,699     $ 3,270     $ 32,647     $ 6,016  

Interest expense on retired debt

     6,240       6,420       16,856       13,695  

Amortization of loan costs and discount

     3,642       2,241       7,311       6,157  
  

 

 

   

 

 

   

 

 

   

 

 

 

Gross interest expense

     31,581       11,931       56,814       25,868  

Less: capitalized interest

     (6,326     (4,100     (11,851     (5,916
  

 

 

   

 

 

   

 

 

   

 

 

 

Net interest expense

   $ 25,255     $ 7,831     $ 44,963     $ 19,952  
  

 

 

   

 

 

   

 

 

   

 

 

 

 

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Income Taxes

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

 

(amounts in thousands)    U.K.     U.S.     Other     Total  

Six Months Ended June 30, 2012:

        

Net loss before taxes

   $ (52,449   $ (56,462   $ (2,089   $ (111,000

Current tax benefit

     (920     —          —          (920

Deferred tax benefit

     (24,009     —          —          (24,009
  

 

 

   

 

 

   

 

 

   

 

 

 

Income tax benefit

     (24,929     —          —          (24,929
  

 

 

   

 

 

   

 

 

   

 

 

 

Net loss

   $ (27,520   $ (56,462   $ (2,089   $ (86,071
  

 

 

   

 

 

   

 

 

   

 

 

 

Six Months Ended June 30, 2011:

        

Net loss before taxes

   $ (1,723   $ (17,195   $ (4,829   $ (23,747

Current tax expense

     184       4       —          188  

Deferred tax benefit

     (875     —          —          (875
  

 

 

   

 

 

   

 

 

   

 

 

 

Income tax expense (benefit)

     (691     4       —          (687
  

 

 

   

 

 

   

 

 

   

 

 

 

Net loss

   $ (1,032   $ (17,199   $ (4,829   $ (23,060
  

 

 

   

 

 

   

 

 

   

 

 

 

The change in income tax expense (benefit) from $(0.7) million to $(24.9) million for the six months ended June 30, 2011 and 2012, respectively, was primarily the result of increased losses in the U.K. due to increased interest expense from $8.6 million to $52.8 million in 2011 and 2012, respectively. The current tax expense (benefit) in both 2012 and 2011 is related to Petroleum Revenue Tax on our Alba field in the U.K.

In 2012 and 2011, we did not record any income tax benefits in the U.S. as there was no assurance that we could generate any U.S. taxable earnings, resulting in a full valuation allowance against the deferred tax assets generated.

Reconciliation of Non-GAAP Measures

Net income can be significantly affected by various non-cash items, such as unrealized gains and losses on our commodity derivatives, currency impact of long-term liabilities and deferred taxes. Given the significant impact that non-cash items may have on our net income, we use various measures in addition to net income and net cash provided by operating activities, including non-financial performance indicators and non-GAAP measures as key metrics to manage our business and measure our results of operations. These metrics demonstrate our ability to maintain or grow production levels and reserves, internally fund capital expenditures and service debt as well as provide comparisons to other oil and gas exploration and production companies. Net Loss as Adjusted and Adjusted EBITDA are internal, supplemental measures of our performance that are not required by, or presented in accordance with, GAAP. 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.

 

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Because Net Loss as Adjusted and Adjusted EBITDA are not determined in accordance with GAAP and thus are susceptible to varying calculations among companies, our non-GAAP measures as presented may not be comparable to similarly titled measures of other companies. Net Loss as Adjusted and Adjusted EBITDA have limitations as analytical tools, and you should not consider these measures in isolation, or as a substitute for analysis of our financial statement data presented in the consolidated financial statements as reported under GAAP.

Provided below are reconciliations of net loss to Net Loss as Adjusted and Adjusted EBITDA:

 

      Three Months Ended
June 30,
    Six Months Ended
June 30,
 

(amounts in thousands)

   2012     2011     2012     2011  

Net loss

   $ (50,808   $ (15,604   $ (86,071   $ (23,060

Impairment of oil and gas properties (net of tax) (1)

     19,960       —          35,700       —     

Unrealized loss on derivatives (net of tax) (2)

     (4,355     6,259       (207     790  
  

 

 

   

 

 

   

 

 

   

 

 

 

Net Loss as Adjusted

   $ (35,203   $ (9,345   $ (50,578   $ (22,270
  

 

 

   

 

 

   

 

 

   

 

 

 

Net loss

   $ (50,808   $ (15,604   $ (86,071   $ (23,060

Unrealized loss on derivatives

     (3,805     6,448       973       1,984  

Net interest expense

     25,133       7,732       44,784       19,748  

Loss on early extinguishment of debt

     21,661       —          21,661       402  

Depreciation, depletion and amortization

     10,627       7,004       18,533       13,326  

Impairment of oil and gas properties

     19,960       —          35,700       —     

Income tax expense (benefit)

     (14,335     2,026       (24,929     (687
  

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

   $ 8,433     $ 7,606     $ 10,651     $ 11,713  
  

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) 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.
(2) Net of tax (benefit) expense of $550 and $189 and $1,180 and $1,195, respectively.

Liquidity and Capital Resources

The following table summarizes our net cash flows from operating, investing and financing activities for the periods indicated. For additional details regarding the components of our primary cash flow amounts, see the Condensed Consolidated Statements of Cash Flows under Item 1 of this report.

 

      Six Months Ended
June 30,
 

(amounts in thousands)

   2012     2011  

Net cash used in operating activities

   $ (28,087   $ (23,867
  

 

 

   

 

 

 

Net cash used in investing activities

   $ (344,741   $ (90,314
  

 

 

   

 

 

 

Net cash provided by financing activities

   $ 361,362     $ 25,143  
  

 

 

   

 

 

 

 

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The net cash flows used in operating activities are primarily impacted by the earnings from our business activities. The cash flows used in operating activities were $28.1 million for the six months ended June 30, 2012 as compared to $23.9 million used in operating activities for the six months ended June 30, 2011, primarily due to our increased interest expense related to our debt issuances.

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 field portion of the COP Acquisition. Under these agreements, we agreed to reimburse the issuers of letters of credit covering 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. Fees and expenses related to the reimbursement agreements are included in other expenses on our consolidated statement of operations.

Concurrent with the issuance of the first reimbursement agreement, the restrictions on our restricted cash securing a letter of credit were removed, the cash was returned to us, and our letter of credit facility agreement was extinguished. 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.

The second reimbursement agreement covers approximately $120 million related to our decommissioning obligations for the Alba field. We pay a fee of 13% per year, payable quarterly, computed based on the outstanding amount of each letter of credit. As of June 30, 2012, we do not expect to begin decommissioning activities for the Alba field until 2030 or later.

We are engaged in the bank syndication process to secure a new revolving credit facility that will encompass both our existing Revolving Credit Facility and replace these two reimbursement agreements.

The cash used in investing activities represents expenditures for capital projects, including acquisitions. For the six months ended June 30, 2012, cash used in investing activities was $344.7 million as opposed to $90.3 million in the corresponding period of the prior year.

For the six months ended June 30, 2012 and 2011, we spent $116.5 million and $66.7 million, respectively, in capital expenditures for the year. The increased capital expenditures are related to our development projects at Bacchus and Rochelle.

For the six months ended June 30, 2012 and 2011, we spent $228.1 million and $22.2 million, respectively, in acquisitions for the year. During 2012, our acquisition expenditures were primarily related to the Alba field portion of the COP Acquisition for aggregate cash consideration of approximately $219.6 million. During 2011, our acquisition expenditures were primarily related to the purchase of an additional 20% working interest in the Bacchus field.

 

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The cash provided by financing activities includes repayments and borrowings of debt, payments of preferred dividends, payment of financing costs, and proceeds from the issuance of common stock.

On February 23, 2012, we closed the private placement of $500 million aggregate principal amount of the 2018 Notes. We used the proceeds from the 2018 Notes to fund the Alba field portion of COP Acquisition, to repay all amounts outstanding under our Senior Term Loan due 2013 and for general corporate purposes.

On April 12, 2012, we entered into a $100 million Credit Agreement (the “Revolving Credit Facility”), with Cyan Partners, LP, 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 field portion of the COP 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 COP 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 field portion of the COP Acquisition. In connection with the closing of the acquisition of the Alba property, we borrowed the additional $60 million available under the facility to fund a portion of the purchase price and related obligations. The First Amendment to the Revolving Credit Facility contained certain amendments allowing us to enter into certain reimbursement agreements discussed in Note 13 to the unaudited financial statements included elsewhere in this report.

Also, on May 31, 2012, we used approximately $255 million of the net proceeds, upon release from escrow, 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 Endeavour UK’s obligations were released.

On June 13, 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. We intend to use the offering proceeds for our development projects.

Certain of our outstanding debt instruments contain certain financial ratio covenants. We were in compliance with all financial covenants in our debt obligations as of June 30, 2012 and December 31, 2011.

 

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Capital Program

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. During the second quarter of 2012, our capital expenditures were primarily related to our two development projects in the U.K. – Bacchus and Rochelle. Now that Bacchus has achieved first production, we expect to earmark a substantial portion of the cash flows from its production to complete the necessary development program for the Rochelle area to allow first production during the second half of 2012. Remaining capital will be divided among our smaller commitments, including evaluation of our Montana vertical pilot wells and minimal drilling and completions in the Marcellus and Haynesville areas as required to hold strategic acreage. The full extent of our U.S. drilling program will be determined by our anticipated available cash and any changes in the U.S. natural gas markets and prices.

As of June 30, 2012, we had spent $116.5 million in capital expenditures for the year.

North Sea Acquisition

On December 23, 2011, we entered into the COP Purchase Agreement to acquire certain oil and natural gas interests in the North Sea for approximately $330 million in cash. The COP Purchase Agreement provides for the possibility that the COP Acquisition may close in multiple stages. On May 31, 2012, we closed the portion of the COP Acquisition consisting of a 23.43% interest in the Alba field. Prior to this recent acquisition, we held a 2.25% interest in the Alba field. This additional working interest, combined with our previous ownership position, increases 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 $219.6 million. The interest in the Alba field accounts for approximately 62% and 59% of the acquired assets’ total proved reserves and production as of December 31, 2011.

In connection with closing the acquisition of the Alba field portion separately from the other two fields, we paid an additional $2 million deposit to the Sellers relating to the remaining properties in the COP Acquisition. The remaining interests to be acquired include a 40% interest in the MacCulloch field and an 18% interest in the Nicol field. Subject to partner and U.K. regulatory approvals, we expect that we will be the operator of the MacCulloch field following the closing of the acquisition of the interest in the field. We intend to pursue closing of the remaining interests in the COP Acquisition in the near future.

United Kingdom Capital Program

We currently have two large development projects in the North Sea — the Bacchus and Rochelle fields — which have the potential to significantly increase our proved reserves and current production levels over the next several years. We intend to efficiently manage our interests in each of these prospects in order to commence production in a timely and cost-effective manner.

We hold a 30% working interest in our Bacchus field asset located in Block 22/06a in the U.K. Central North Sea, which is operated by Apache Corporation, who owns a 50% working interest.

 

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The field development plan (“FDP”) for the Bacchus field calls for a subsea development with three wells to be drilled and linked to production facilities at the nearby Forties field. On April 30, 2012 we announced that we had achieved production from the first development well on the Bacchus field. Drilling at the second of three planned development wells was completed in July 2012. The second development well started production on July 29, 2012. The latest horizontal well, Bacchus West, penetrated Jurassic-aged Fulmar reservoir sandstones and logged 889 feet (measured depth) of net pay in three sections. The well is currently producing approximately 8,500 gross barrels per day at significantly restricted choke rates. Current combined production from the two Bacchus wells is approximately 13,000 barrels per day. 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. Drilling on the third well will commence once that analysis has been completed.

The Rochelle area is comprised of three blocks in the North Sea. In July 2011, the unitization of the Rochelle area, including our interests in blocks 15/27 and 15/26c, was completed resulting in a single set of interest across the field for the interest owners. 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. In late July, the contracted drilling rig arrived and commenced operations to drill the first of two planned development wells. Final modifications to the Scott Platform, the off-take solution for the Rochelle development, will be completed during the third quarter in preparation for Rochelle production later in the year. Installation of the pipe and manifolds on the seabed floor is also scheduled to commence later in the third quarter. The Rochelle development continues on schedule for first production in the fourth quarter of 2012.

United States Capital Program

Our primary focus in the U.S. is onshore unconventional oil and gas shale developments targeting reserve and production growth in the Haynesville and Marcellus areas and interests in the emerging Heath shale oil play in Montana. Our strategy for our U.S. operations has been to employ a measured approach that seeks to balance U.S. natural gas prices with drilling costs. In our Haynesville and Marcellus shale gas plays, we plan to continue this disciplined approach and expect to drill only those wells necessary to secure leasehold positions. Additional drilling opportunities will be assessed when future natural gas prices improve.

During the first quarter, we completed one minority-interest well and drilled a second joint interest well in the Haynesville area. We have deferred the completion of that well and suspended drilling operations due to low gas prices. We anticipate limited drilling activity in our Haynesville and Marcellus shale gas plays for the remainder of 2012 as we monitor U.S. natural gas prices.

In the Marcellus area, we are working on expanding the Daniel Field gathering pipeline infrastructure, including options to connect with one of three major pipelines in Cameron County. We are currently obtaining necessary rights-of-way and permits. Upon completion of these items, we expect to begin construction of a gathering line to tie our production to an existing pipeline.

 

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In the Heath Shale tight oil play, we and our partners have completed the core and log data analysis from four vertical pilot wells drilled in 2011. The partnership has prioritized the wells to be re-entered and is in the process of securing a rig to drill the first lateral in the coming months.

Outlook

2012 Planned Capital Expenditures

We expect that our total capital expenditure budget for the full year 2012 will be between $175 million and $200 million, including approximately $25 million related to assets acquired in the COP Acquisition, of which we had spent $116.5 million through June 30, 2012. We expect to spend approximately $150 million to $175 million of the total 2012 budget in the U.K., primarily on the advancement of our development projects. With our existing cash position, cash flows from existing production and the start up of production from Bacchus, we believe we have sufficient cash flows to complete the necessary development program for the Rochelle area to reach first production in the fourth quarter of 2012. We expect to spend the remainder of our 2012 capital budget in the U.S. to evaluate our Heath Shale Oil Play pilot wells, to maintain our acreage positions and to fulfill minor drilling commitments. Our 2012 capital expenditure budget is subject to change depending on a number of factors, including 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 factors typically affecting the oil and gas industry.

We intend to fund our remaining 2012 capital expenditures and acquisitions primarily through cash on hand and cash flow generated from operations, including cash flow from the Alba field and the remaining assets to be acquired in the COP Acquisition.

 

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Disclosures About Contractual Obligations and Commercial Commitments

The following table sets forth our obligations and commitments to make future payments under our lease agreements and other long-term obligations as of June 30, 2012:

 

(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

   $ 830,990      $ 12,500      $ 117,320      $ 201,170      $ 500,000  

Interest

     423,277        84,215        140,640        153,922        44,500  

Asset retirement obligations

     64,171        2,117        3,921        29,042        29,091  

Operating leases for office leases and equipment

     6,659        1,402        2,476        2,287        494  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Contractual Obligations

   $ 1,325,097      $ 100,234      $ 264,357      $ 386,421      $ 574,085  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) Interest on certain of our debt instruments is added to the outstanding principal balance each quarter and reflected as due upon maturity.

Cautionary Statement for Forward-Looking Statements

Certain statements and information in this Quarterly Report on Form 10-Q may constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. In particular, this report contains forward-looking statement pertaining to the following:

 

   

our future financial position;

 

   

our business strategy;

 

   

recent and pending acquisitions;

 

   

budgets;

 

   

projected costs, savings and plans;

 

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objectives of management for future operations;

 

   

legal strategies; and

 

   

legal proceedings.

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

 

   

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

 

   

decreases in proved reserves due to technical or economic factors;

 

   

drilling of wells and other planned exploitation activities;

 

   

timing and amount of future production of oil and gas;

 

   

the volatility of oil and gas prices;

 

   

availability and terms of capital;

 

   

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

 

   

our future operating or financial results;

 

   

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

 

   

cash flow and anticipated liquidity;

 

   

availability of drilling and production equipment;

 

   

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

 

   

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

 

   

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; and

 

   

factors not known to us at this time.

Any of these factors, or a combination of these factors, could materially affect our future financial condition or results of operations and the ultimate accuracy of the forward-looking statements. The forward-looking statements are not guarantees of our future performance, and our actual results and future developments may differ materially from those projected in the forward-looking statements. In addition, any or all of our forward-looking statements in this Quarterly Report on Form 10-Q 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 “Item 1A. Risk Factors” and elsewhere in our Annual Report on Form 10-K for the year ended December 31, 2011. 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 report. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

 

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Item 3: Quantitative and Qualitative Disclosures about Market Risk

Commodity Price Risk

We produce and sell crude oil and natural gas. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and regional gas spot market prices that have been volatile and unpredictable for several years. As a result, our financial results can be significantly impacted as these commodity prices fluctuate widely in response to changing market forces. We may engage in oil and gas hedging activities to realize commodity prices which we consider favorable. For additional information regarding our derivative instruments, see Note 11 to the Condensed Consolidated Financial Statements.

At June 30, 2012, we had the following commodity derivative instruments outstanding:

 

     2012      Total  

Oil:

     

Fixed Price Puts (Mbbl)—Brent

     566        566  

Weighted Average Price ($/Barrel)

   $ 88.46      $ 88.46  

Gas: (1)

     

Fixed Price Puts (MMcf)—Heren National Balancing Point

     248        248  

Weighted Average Price ($/Mcf)

   $ 8.53      $ 8.53  

 

(1) 

Gas derivative contracts are designated in pence per therms and have been converted to Mcf at a rate of 10 therm to 1 Mcf. The exchange rate at June 30, 2012 was $1.57 to £1.00.

Item 4: Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended, we have evaluated, under the supervision and with the participation of our management, including our chief executive officer (the “CEO”) and chief financial officer (the “CFO”), the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) or 15d-15(e) of the Securities Exchange Act of 1934, as amended) as of the end of the period covered by this Form 10-Q. Based on that evaluation, the CEO and CFO concluded:

(i) that our disclosure controls and procedures are designed 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 (a) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (b) is accumulated and communicated to our management, including the CEO and CFO, as appropriate, to allow timely decisions regarding required disclosure; and

(ii) that our disclosure controls and procedures were effective as of June 30, 2012.

 

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Changes in Internal Control over Financial Reporting

There was no change in our system of internal control over financial reporting (as defined in Rules 13a-15(f), and 15d-15(f) under the Securities Exchange act of 1934, as amended), during the last fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Part II. Other Information

Item  1A: Risk Factors

In addition to the factors discussed elsewhere in this report, including the financial statements and related notes, you should consider carefully the risks and uncertainties described in our Annual Report on Form 10-K for the year ended December 31, 2011 under Item 1A “Risk Factors,” which could materially adversely affect our business, financial condition and results of operations. Additional risks and uncertainties not presently known to us or that we currently deem immaterial also could impair our business operations and financial condition. If any of these risks or uncertainties were to occur, our business, financial condition or results of operation could be adversely affected.

Item 6: Exhibits

 

3.1(a)   Amended and Restated Articles of Incorporation (Incorporated by reference to Exhibit 3.2 of our Quarterly Report on Form 10-Q (Commission File No. 001-32212) for the quarter ended June 30, 2004).
3.1(b)   Certificate of Amendment dated June 1, 2006 (Incorporated by reference to Exhibit 4.2 of our Registration Statement on Form S-3 (Commission File No. 333-139304) filed on December 13, 2006).
3.1(c)  

Certificate of Amendment dated June 1, 2010 (Incorporated by reference to Exhibit 3.1 to our Current Report on

Form 8-K (Commission File No. 001-32212) filed on June 3, 2010).

3.1(d)   Amendment to Articles of Incorporation, dated November 17, 2010 (Incorporated by reference to Exhibit 3.1(d) of our Annual Report on Form 10-K (Commission File No. 001-32212) for the year ended December 31, 2010).
3.1(e)   Amendment to Amended and Restated Articles of Incorporation, dated May 24, 2012 (Incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on May 29, 2012).
3.2(a)   Amended and Restated Bylaws (Incorporated by reference to Exhibit 3.4 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on November 6, 2006).

 

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3.2(b)      Amendment to Amended and Restated Bylaws dated December 12, 2007 (Incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on December 13, 2007).
4.1      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).
10.1           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).
10.2      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 Form 8-K (Commission File No. 001-32212) filed on May 30, 2012).
10.3      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).
10.4 (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 quarter ended March 31, 2012).
10.4 (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).
10.5      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).
10.6     *†       Restricted Stock Award Agreement between Endeavour International Corporation and Ralph A. Midkiff, dated as of June 1, 2012.
31.1     *       Certification of William L. Transier, Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2     *       Certification of J. Michael Kirksey, Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 

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32.1    *    Certification of William L. Transier, Chief Executive Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2
   *    Certification of J. Michael Kirksey, Chief Financial Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS    **    XBRL Instance Document.
101.SCH    **    XBRL Taxonomy Extension Schema Document.
101.CAL    **    XBRL Taxonomy Extension Calculation Linkbase.
101.DEF    **    XBRL Taxonomy Extension Definition Linkbase.
101.LAB    **    XBRL Taxonomy Extension Label Linkbase.
101.PRE    **    XBRL Taxonomy Extension Presentation Linkbase.

 

* Filed or furnished (in the case of Exhibits 31.1, 31.2, 32.1, 32.2 and 101) with this Form 10-Q.
** To be filed by amendment.
Management contracts and compensatory plans or arrangements.

 

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Signatures

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Endeavour International Corporation

 

Date: August 8, 2012   

/s/ J. Michael Kirksey

  

/s/ Robert L. Thompson

   J. Michael Kirksey    Robert L. Thompson
   Executive Vice President and    Senior Vice President and
   Chief Financial Officer    Chief Accounting Officer
   (Principal Financial Officer)    (Principal Accounting Officer)

 

41

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