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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 March 31, 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 May 4, 2012, 37,889,671 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

     20   

Item 3: Quantitative and Qualitative Disclosures About Market Risk

     35   

Item 4: Controls and Procedures

     35   

Part II. Other Information

  

Item 1A: Risk Factors

     36   

Item 6: Exhibits

     36   

Signatures

     39   

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)

 

     March 31,      December 31,  
     2012      2011  

Assets

  

Current Assets:

     

Cash and cash equivalents

   $ 18,186      $ 106,036  

Restricted cash

     493,434        —     

Accounts receivable

     13,594        8,649  

Prepaid expenses and other current assets

     25,335        18,840  
  

 

 

    

 

 

 

Total Current Assets

     550,549        133,525  

Property and Equipment, Net ($284,523 and $258,334 not subject to amortization at March 31, 2012 and December 31, 2011, respectively)

     593,973        549,196  

Goodwill

     211,886        211,886  

Other Assets

     48,347        30,384  
  

 

 

    

 

 

 

Total Assets

   $ 1,404,755      $ 924,991  
  

 

 

    

 

 

 

See accompanying notes to condensed consolidated financial statements.

 

1


Table of Contents

Endeavour International Corporation

Condensed Consolidated Balance Sheets

(Unaudited)

(Amounts in thousands)

 

     March 31,     December 31,  
     2012     2011  

Liabilities and Stockholders’ Equity

  

Current Liabilities:

    

Accounts payable

   $ 102,970     $ 62,275  

Current maturities of debt

     14,850       12,350  

Accrued expenses and other

     14,147       20,549  
  

 

 

   

 

 

 

Total Current Liabilities

     131,967       95,174  

Long-Term Debt:

    

2018 Notes, net of debt discount

     480,000       —     

Other long-term debt

     456,090       455,028  
  

 

 

   

 

 

 

Total long-term debt

     936,090       455,028  

Deferred Taxes

     106,745       115,759  

Other Liabilities

     66,235       61,248  
  

 

 

   

 

 

 

Total Liabilities

     1,241,037       727,209  

Commitments and Contingencies

    

Series C Convertible Preferred Stock

    

Face value (liquidation preference)

     37,000       37,000  

Net non-cash premiums under fair value accounting on redemption

     6,703       6,703  
  

 

 

   

 

 

 

Total Series C Convertible Preferred Stock

     43,703       43,703  

Stockholders’ Equity:

    

Series B preferred stock - Liquidation preference: $3,470 and $3,430 at March 31, 2012 and December 31, 2011, respectively

     —          —     

Common stock; shares issued and outstanding – 37,956 and 37,663 shares at March 31, 2012 and December 31, 2011, respectively

     38       38  

Additional paid-in capital

     422,065       420,412  

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

     (587     (587

Accumulated deficit

     (301,501     (265,784
  

 

 

   

 

 

 

Total Stockholders’ Equity

     120,015       154,079  
  

 

 

   

 

 

 

Total Liabilities and Stockholders’ Equity

   $ 1,404,755     $ 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  
     March 31,  
     2012     2011  

Revenues

   $ 15,166     $ 14,104  

Cost of Operations:

    

Operating expenses

     4,898       5,041  

Depreciation, depletion and amortization

     7,906       6,323  

Impairment of oil and gas properties

     15,740       —     

General and administrative

     5,323       4,713  
  

 

 

   

 

 

 

Total Expenses

     33,867       16,077  
  

 

 

   

 

 

 

Loss From Operations

     (18,701     (1,973
  

 

 

   

 

 

 

Other Income (Expense):

    

Derivatives:

    

Unrealized gains (losses)

     (4,779     4,464  

Interest expense:

    

Interest expense related to the 2018 Notes

     (6,653     —     

Other interest expense

     (13,054     (12,523
  

 

 

   

 

 

 

Total interest expense

     (19,707     (12,523

Interest income and other

     (2,668     (139
  

 

 

   

 

 

 

Total Other Expense

     (27,154     (8,198
  

 

 

   

 

 

 

Loss Before Income Taxes

     (45,855     (10,171

Income Tax Benefit

     (10,593     (2,714
  

 

 

   

 

 

 

Net Loss

     (35,262     (7,457

Preferred Stock Dividends

     456       545  
  

 

 

   

 

 

 

Net Loss to Common Stockholders

   $ (35,718   $ (8,002
  

 

 

   

 

 

 

Net Loss per Common Share:

    

Basic and Diluted

   $ (0.94   $ (0.30
  

 

 

   

 

 

 

Weighted Average Number of Common Shares Outstanding:

    

Basic and Diluted

     37,854       26,750  
  

 

 

   

 

 

 

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)

 

     Three Months Ended March 31,  
     2012     2011  

Cash Flows from Operating Activities:

    

Net loss

   $ (35,262   $ (7,457

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

    

Depreciation, depletion and amortization

     7,906       6,323  

Impairment of oil and gas properties

     15,740       —     

Deferred tax benefit

     (9,014     (2,182

Unrealized (gains) losses on derivatives

     4,779       (4,464

Amortization of non-cash compensation

     1,559       875  

Amortization of loan costs and discount

     3,669       3,916  

Non-cash interest expense

     3,528       3,031  

Other

     1,892       2,602  

Changes in operating assets and liabilities:

    

(Increase) decrease in receivables

     (4,945     1,145  

Increase in other current assets

     (7,518     (2,787

Decrease in liabilities

     (3,487     (16,424
  

 

 

   

 

 

 

Net Cash Used in Operating Activities

     (21,153     (15,422

Cash Flows From Investing Activities:

    

Capital expenditures

     (23,242     (20,148

Acquisitions

     (8,017     (20,964

Increase in restricted cash

     (493,434     (1,295
  

 

 

   

 

 

 

Net Cash Used in Investing Activities

     (524,693     (42,407

Cash Flows From Financing Activities:

    

Repayments of borrowings

     (588     (5,400

Borrowings under debt agreements, net of debt discount

     480,000       —     

Financing costs related to the 2018 Notes

     (21,005     —     

Other financing costs paid

     —          (583

Proceeds from issuance of common stock

     —          116,822  

Dividends paid

     (416     (506

Other financing

     5       375  
  

 

 

   

 

 

 

Net Cash Provided by Financing Activities

     457,996       110,708  

Net Increase (Decrease) in Cash and Cash Equivalents

     (87,850     52,879  

Cash and Cash Equivalents, Beginning of Period

     106,036       99,267  
  

 

 

   

 

 

 

Cash and Cash Equivalents, End of Period

   $ 18,186     $ 152,146  
  

 

 

   

 

 

 

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 (“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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Table of Contents

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—Property and Equipment

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

 

     March 31,
2012
    December 31,
2011
 

Oil and gas properties under the full cost method:

    

Subject to amortization

   $ 520,046     $ 496,667  

Not subject to amortization:

    

Incurred in 2012

     48,754       —     

Incurred in 2011

     126,583       138,912  

Incurred in 2010

     44,448       47,208  

Incurred prior to 2010

     64,738       72,214  
  

 

 

   

 

 

 
     804,569       755,001  

Computers, furniture and fixtures

     7,464       6,421  
  

 

 

   

 

 

 

Total property and equipment

     812,033       761,422  

Accumulated depreciation, depletion and amortization

     (218,060     (212,226
  

 

 

   

 

 

 

Net property and equipment

   $ 593,973     $ 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

 

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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)

 

completed and production commences on existing discoveries, including the Rochelle and Bacchus projects. We capitalized $5.5 million and $1.8 million in interest related to drilling and exploration activities for the quarters ended March 31, 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 first quarter of 2012, we recorded a pre-tax impairment of $15.7 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. 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 $97.98 per barrel for oil and $3.71 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 first quarter 2012, which utilized prices of $113.89 per barrel for oil and $8.69 per Mcf for gas.

Pending Acquisition

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, to acquire their interest in three producing U.K. oil fields in the Central North Sea for $330 million (the “COP Acquisition”).

The producing assets to be acquired include the following net working interests:

 

Field Name

   Block      Net Working Interest  

Alba

     16/26a         23.43 % (1) 

MacCulloch

     15/24b         40.00

Nicol

     15/25a         18.00

 

(1) We currently have a 2.25% working interest in the Alba field which will increase to 25.68% upon consummation of the COP Acquisition.

The Purchase Agreement provides for the possibility that completion of this acquisition may occur individually for each field, and we expect to close the Alba field portion during the second quarter of 2012. In addition, the COP Purchase Agreement provides that we may close on the interest in the Alba field without subsequently closing on the remaining interests, in certain circumstances. In accordance with the terms of the COP Purchase Agreement, we will not, however, close on the remaining interests without closing on the acquisition of the interest in the Alba field. In addition to customary closing conditions, the purchase is subject to approval of governmental regulatory authorities and partner consents. The consideration for the acquisition is $330 million, including approximately $94 million of tax attributes, and may be adjusted for customary purchase price adjustments.

 

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Endeavour International Corporation

Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

 

We are working to close the North Sea acquisition. Completion of the Alba field transfer has been delayed due to the efforts of certain of the co-venturers who seek an agreement on the handling of future decommissioning costs, which was neither under discussion by the co-venturers at the execution of the purchase and sale agreement, nor is it required as a condition of closing. As a current owner in Alba field, we believe it is in the best interest of all parties to deal with future decommissioning plans and associated costs prudently in time, but proceed to closing the Alba transaction immediately. ConocoPhillips and Endeavour have proposed a solution to the Alba co-venturers who are considering the proposal. At this time, the resolution of this process is not clear.

In accordance with the terms of the 2018 Notes, if the Alba co-venturers do not reach a consensus by June 15, 2012 or other alternatives are not arranged, we would be required to redeem the 2018 Notes, including penalties and interest, which is more than the net proceeds from the offering now in escrow. In addition, we would be required to repay the $40 million of outstanding borrowings under our new revolving credit facility. There can be no assurance that we will have the necessary cash or will be able to obtain the necessary financing to fund these repayments.

Note 3 – Restricted Cash

At March 31, 2012, restricted cash represented amounts held in escrow as collateral for a letter of credit related to our abandonment obligations and the net proceeds of the private placement of the 2018 Notes. See Note 4 for additional discussion.

Note 4 – Debt Obligations

At March 31, 2012, we had $973.1 million in outstanding debt. Our debt consisted of the following at March 31, 2012 and December 31, 2011:

 

     March 31,     December 31,  
     2012     2011  

Senior term loan, 15% fixed rate, due 2013

   $ 241,584     $ 240,349  

Subordinated notes, 12% fixed rate, due 2014

     32,172       32,012  

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

     64,321       62,523  

Senior notes, 12% fixed rate, due 2018

     500,000       —     

Convertible senior notes, 5.5% fixed rate, due 2016

     135,000       135,000  
  

 

 

   

 

 

 
     973,077       469,884  

Less: debt discount

     (22,137     (2,506

Less: current maturities

     (14,850     (12,350
  

 

 

   

 

 

 

Long-term debt

   $ 936,090     $ 455,028  
  

 

 

   

 

 

 

Standby letters of credit outstanding for abandonment liabilities

   $ 32,960     $ 31,724  
  

 

 

   

 

 

 

 

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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)

 

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.

We intend to use the net proceeds from the 2018 Notes to fund the COP Acquisition, to repay all amounts outstanding under our Senior Term Loan due 2013 and for general corporate purposes. Prior to the closing of the COP Acquisition, the net proceeds of the offering are being held in an escrow account. In accordance with the terms of the 2018 Notes, if the COP acquisition does not close by June 15, 2012, or other alternatives are not arranged, we would be required to redeem the 2018 Notes, including penalties and interest, which is more than the net proceeds of the offering now in escrow. The COP Purchase Agreement provides for the possibility that the COP Acquisition may close in multiple stages. If we close on the first stage, the acquisition of an additional interest in the Alba field, the full amount of proceeds will be released from escrow.

Senior Term Loan

On January 18, 2012, we entered into a Consent and Fourth Amendment to Credit Agreement, U.S. Security Agreement and Subsidiaries Guaranty (the “Amendment”) with Cyan Partners, LP, as administrative agent, and certain lenders party thereto (the “Senior Term Loan”).

The primary provisions of the Amendment include the (i) consent and approval for the Company to issue up to $500 million of senior unsecured notes, (ii) exclusion of up to $500 million of senior unsecured notes, if any, from certain financial covenants and (iii) amendments to certain existing financial covenants, including a reduction in the minimum consolidated EBITDAX requirement to $20,000,000 for each of the test periods ended December 31, 2011 and March 31, 2012 and an extension of the increase in the minimum PDP coverage ratio from 0.25:1.00 to 0.50:1.00 after March 31, 2012.

After giving effect of this amendment, we were in compliance with all financial and restrictive covenants of our Senior Term Loan as of each of December 31, 2011 and March 31, 2012.

We plan to repay the Senior Term Loan in its entirety with a portion of the proceeds from the offering of the 2018 Notes upon release of the proceeds from escrow.

 

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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 will be payable semiannually at a rate of 5.5% per annum, commencing on January 15, 2012. 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.

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 a conversion price of $16.52 per $1,000 of principal, which represents a conversion rate of approximately 61 shares of our common stock per $1,000 of principal.

Subordinated Notes

Our Subordinated Notes 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.

Letter of Credit Agreement

During the first quarter of 2012, we entered into waivers and amendments for our letter of credit facility agreement with Commonwealth Bank of Australia (“CBA”). The primary provisions include (i) an amendment and waiver for certain existing financial covenants, including the minimum EBITDAX covenant and (ii) CBA’s consent to the issuance of up to $525 million of senior unsecured notes, and the escrow of the proceeds therefrom, including the exclusion of such proceeds from any requirement to grant a security interest in favor of CBA and the exclusion of the notes from the financial covenant calculations while the proceeds are held in escrow. The waiver includes express provisions to enable us to complete our previously disclosed acquisition of North Sea assets from several subsidiaries of ConocoPhillips. Additionally, we are required to replace the LC Agreement with another facility in the event that we utilize a senior secured credit facility to finance the COP acquisition. CBA has exercised the right to require us to cash collateralize the letter of credit agreement. We have reflected the $32.6 million of collateral as restricted cash in our financial statements herein.

After entering into this amendment, we were in compliance with all financial and restrictive covenants of our letter of credit facility as of each of December 31, 2011 and March 31, 2012.

 

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Endeavour International Corporation

Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

 

Revolving Credit Facility

On April 12, 2012, we entered into a $100 million Credit Agreement, (the “Revolving Credit Facility”) with Cyan Partners, LP, as administrative agent. For additional details regarding this new credit facility, see Note 13—“Subsequent Events.”

Fair Value

The fair value of our outstanding debt obligations was $947 million and $420 million at March 31, 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%.

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 three months ended March 31, 2012 and 2011:

 

     Three Months Ended
March 31,
 
     2012     2011  

Carrying amount of asset retirement obligations as of beginning of period

   $ 47,258     $ 42,997  

Accretion expense (included in DD&A expense)

     1,480       1,233  

Impact of foreign currency exchange rate changes

     1,733       1,765  

Payment of asset retirement obligations

     (1,976     (4,033

Carrying amount of asset retirement obligations as of end of period

     48,495       41,962  

Less: Current portion

     (2,157     (6,667
  

 

 

   

 

 

 

Long-term asset retirement obligations

   $ 46,338     $ 35,295  
  

 

 

   

 

 

 

 

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Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

 

Note 7 – 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:

 

     Three Months Ended
March 31,
 
     2012      2011  

G & A Expenses

   $ 1,175      $ 642  

Capitalized G & A

     441        233  
  

 

 

    

 

 

 

Total non-cash stock-based compensation

   $ 1,616      $ 875  
  

 

 

    

 

 

 

At March 31, 2012, total compensation cost related to awards not yet recognized was approximately $12.8 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        

Balance outstanding—March 31, 2012

     298     $ 8.95        5.7      $ 1,063  
  

 

 

   

 

 

    

 

 

    

 

 

 

Currently exercisable—March 31, 2012

     298     $ 8.95        5.7      $ 1,063  
  

 

 

   

 

 

    

 

 

    

 

 

 

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 March 31, 2012 and the changes during the three months ended March 31, 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

     302       9.49  

Vested

     (297     9.23  

Forfeited

     (32     9.19  
  

 

 

   

 

 

 

Balance outstanding—March 31, 2012

     803     $ 10.35  
  

 

 

   

 

 

 

Total grant date fair value of shares vesting during the period

   $ 2,747    
  

 

 

   

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 March 31, 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 8 – 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:

     March 31,  
     2012      2011  

Warrants, options and stock-based compensation

     911        148  

Convertible debt

     11,187        5,788  

Convertible preferred stock

     4,229        5,143  
  

 

 

    

 

 

 
     16,327        11,079  
  

 

 

    

 

 

 

Note 9 – 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 March 31, 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 March 31, 2012:

          

Oil and gas derivative contracts:

          

Oil and gas puts

   $ —         $ 169      $ 60     $ 229  

Embedded derivatives

     —           —           (19,828     (19,828
  

 

 

    

 

 

    

 

 

   

 

 

 

Total derivative liabilities

   $ —         $ 169      $ (19,768   $ (19,599
  

 

 

    

 

 

    

 

 

   

 

 

 

As of December 31, 2011:

          

Oil and gas derivative contracts:

          

Oil and gas puts

   $ —         $ 1,038      $ 209     $ 1,247  

Embedded derivatives

     —           —           (16,067     (16,067
  

 

 

    

 

 

    

 

 

   

 

 

 

Total derivative liabilities

   $ —         $ 1,038      $ (15,858   $ (14,820
  

 

 

    

 

 

    

 

 

   

 

 

 

Our commodity derivative contracts 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 $1 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 $1 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:

 

     Three Months Ended
March 31,
 
     2012     2011  

Balance at beginning of period

   $ (15,858   $ (26,703

Realized and unrealized gains (losses) included in earnings

     (3,910     6,010  
  

 

 

   

 

 

 

Balance at end of period

   $ (19,768   $ (20,693
  

 

 

   

 

 

 

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

   $ (3,910   $ 5,984  
  

 

 

   

 

 

 

Note 10 – 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:

 

     March 31,     December 31,  
     2012     2011  

Derivatives not designated as hedges:

    

Oil and gas commodity derivatives:

    

Assets:

    

Prepaid expenses and other current assets

   $ 229     $ 1,247  

Embedded derivatives related to debt and equity instruments:

    

Liabilities:

    

Other liabilities - long-term

   $ (19,828   $ (16,067

If all counterparties failed to perform, our maximum loss would have been $0.2 million as of March 31, 2012.

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

 

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Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

 

     Three Months Ended  
     March 31,  
     2012     2011  

Derivatives not designated as hedges:

    

Oil and gas commodity derivatives

    

Unrealized gains (losses)

   $ (1,018   $ (2,010
  

 

 

   

 

 

 
     (1,018     (2,010

Embedded derivatives related to debt and equity instruments

    

Unrealized gains (losses)

   $ (3,761   $ 6,475  
  

 

 

   

 

 

 

Under our Senior Term Loan, we are required to maintain commodity derivatives to manage our cash flows from operations. As of March 31, 2012, our outstanding commodity derivatives covered approximately 228 Mbbls of oil and 398 MMcf of natural gas cumulative through 2012 and consisted of six oil and three natural gas option contracts with three major counterparties.

Note 11 – Supplemental Cash Flow Information

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

 

     Three Months Ended March 31,  
     2012      2011  

Interest paid

   $ 10,859      $ 8,557  
  

 

 

    

 

 

 

Income taxes paid

   $ 1,121      $ 4,634  
  

 

 

    

 

 

 

Note 12 – 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

 

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Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

 

valuation of the defects, exceeded the contractual threshold of 15% of the purchase price for the applicable asset group ($85 million); and (ii) the condition of the pipeline was not in compliance with applicable regulatory standards, which would constitute a material violation of a representation and warranty contained in the applicable SM Purchase Agreement.

SM Energy filed a lawsuit against us in Texas state court on December 20, 2011 alleging that we breached the SM Purchase Agreements by terminating them and refusing to close on the transactions. Specifically, SM Energy has alleged, among other things, that most of our asserted title defects are without merit and, in any event, would not exceed 15% of the applicable purchase price. SM Energy seeks the award of unspecified actual damages, including costs and reasonable attorney’s fees, and specific performance. On January 17, 2012, we filed an answer and counterclaim denying the allegations and seeking the return of our $6 million deposit, which we believe we are entitled to recover pursuant to the terms of the SM Purchase Agreements, and for the damages that we suffered as a result of SM Energy’s misrepresentations. We intend to contest the case vigorously.

Rig Commitments

We currently have rig commitments for the drilling of two Rochelle production wells in 2012.

Note 13 – Subsequent Events

On April 12, 2012, in anticipation of the closing of the COP acquisition and the associated repayment of our Senior Term Loan with Cyan and the other lenders, we entered into the Revolving Credit Facility, with Cyan Partners, LP, as administrative agent, and certain other lenders.

During the first quarter of 2012, CBA exercised the right, under an existing letter of credit facility, to require us to cash collateralize a $33.0 million letter of credit issued under that facility. We used a portion of the funds available under the new Revolving Credit Facility to fully replace the funds used in connection with the cash collateralization. The new facility matures on October 12, 2013. However, if the Alba field portion of the COP acquisition is not completed by June 15, 2012, or any other escrow release conditions are not met, any outstanding borrowings under the Revolving Credit Facility will become due immediately.

Prior to the release of the net proceeds from the Company’s February 2012 offering of the 2018 Notes from escrow (such date, the “Escrow Release Date”), borrowings under the Revolving Credit Facility will be limited to an aggregate of $40 million at any time outstanding and will accrue interest at a rate of 12% per year, plus an additional 3% in annual interest “in-kind” through an increase in the outstanding principal amount of the borrowings. Obligations under the Revolving Credit Facility will be secured by a second lien until the Escrow Release Date. Additionally, prior to the Escrow Release Date, the Revolving Credit Facility will contain covenants similar to those contained in the credit agreement governing our Senior Term Loan, including, but not limited to, limitations on incurrence of investments, liens on assets, transactions with affiliates, mergers consolidations and sales of assets, along with customary events of default, conditions, representations and warranties and indemnification provisions.

 

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Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

 

From and after the Escrow Release Date, borrowings will accrue interest at a rate of 13% per year and will be limited to an aggregate of $100 million at any time outstanding. Such amount may be increased up to $150 million with the consent of the lenders representing at least a majority of the borrowings then outstanding under the Revolving Credit Facility and may be increased in excess of $150 million with the consent of the lenders representing at least two-thirds of the borrowings then outstanding under the Revolving Credit Facility. Such borrowings may be repaid at any time without premium. After the Escrow Release Date, the Revolving Credit Facility will contain similar covenants as the indentures governing the 2018 Notes including, but not limited to, restrictions on the Company’s and its restricted subsidiaries’ ability to:

 

   

pay distributions or repurchase or redeem the Company’s capital stock or subordinated debt;

 

   

make certain investments;

 

   

incur additional indebtedness;

 

   

create or incur certain liens;

 

   

sell assets;

 

   

consolidate, merge or transfer all or substantially all of the Company’s assets;

 

   

enter into agreements that restrict distributions from the Company’s restricted subsidiaries to the Company;

 

   

engage in transactions with affiliates; and

 

   

create unrestricted subsidiaries.

These covenants are subject to a number of important exceptions and qualifications.

On April 30, 2012 we announced that we had achieved first production from the first development well on the Bacchus field located in Block 22/06a in the U.K. Central North Sea. Initial production rates over the first five days were approximately 6,000 gross barrels of oil per day. Endeavour has a 30% interest in Bacchus. We commenced drilling the second development well on Bacchus field on April 20, 2012. It is expected that this well will be on production early in the third quarter of 2012.

 

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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 U.K. North Sea and U.S. Onshore areas. Our strategy is to expand and exploit our balanced portfolio of exploration and development assets using conventional and unconventional technologies in basins that have historically generated and produced substantial quantities of oil and gas and that we believe will yield commercial quantities of oil and gas reserves through improved drilling, completion and operating technologies.

Finding, developing and producing oil and gas reserves in the North Sea require both significant capital and time. Recognizing this, we have sought to balance our North Sea development assets, which have large potential reserves but long production-cycles, with current production from the North Sea assets we expect to acquire in the COP Acquisition and a portfolio of onshore assets in the U.S. that have lower development costs and shorter production-cycles. We also seek to achieve a balance of oil and gas reserves in our portfolio of assets, believing that both commodities present attractive opportunities for capital returns in the future.

Our producing assets have come primarily through acquisitions we have completed since our founding in 2004. The cash flows from these producing assets have been used to support our exploration program and development projects. Over the last couple of years, we have sold some of our non-core assets and accessed the capital markets to provide additional funding for our development projects. We continue to view our portfolio of producing assets as the foundation for organic growth through our development projects. We have incurred significant development expenditures since 2009 as we have pushed forward at Bacchus and Rochelle. Completing the development of these projects is a long, complicated process. While we are committed to the completing the projects, the exact timing of initial production can be affected by events outside of our control, such as:

 

   

weather delays;

 

   

non-operated control issues;

 

   

equipment malfunctions; and

 

   

regulatory delays.

 

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Despite these potential delays, we remain committed to our core strategy – building a producing asset base that generates cash flow in excess of its annual capital and operating expense requirements. We recognize that we have yet to reach this goal, but still believe in the potential of our assets to do so. With the first Bacchus development well having recently achieved production, we have achieved a significant milestone. In the meantime, we have accessed, and may continue to access, the capital markets. While we work toward bringing additional production online from Bacchus, first production at Rochelle and the closing of the COP Acquisition, we continue to face the risk that we will not be able to access the capital markets at rates that provide sufficient return to our investors.

Overview

Our major development projects in the U.K. sector of the North Sea — specifically, Bacchus and Rochelle — have the potential to significantly expand our total proved reserves and production levels. These projects are in various stages of development, with the first Bacchus development well having recently achieved production and first production expected from the second development well in the third quarter of 2012, and first production from the Rochelle area expected in the fourth quarter of 2012. We intend to continue to actively manage our North Sea assets in a manner that maximizes value and enables us to allocate resources to effectively pursue our growth strategy.

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. In the Haynesville/Cotton Valley area, we have approximately 7,300 net acres, with acreage located in Red River, DeSoto, Bienville and Caddo Parishes in Louisiana and in Harrison and Gregg Counties in Texas. Our Marcellus acreage is comprised of approximately 16,000 net acres in Pennsylvania located between two of the most active parts of the Marcellus play. We also have interests in approximately 94,400 net acres in the emerging Heath Shale Oil Play in Montana where we are evaluating the results of four pilot wells and ongoing technical work. The results from our pilot wells and ongoing technical work will determine the pace and scope of our subsequent exploration and development initiatives in this play.

In 2012, we intend to expand upon our foundation of U.K. assets by moving existing development assets towards their first production and integrating the assets we expect to acquire in the COP Acquisition. We also intend to maintain our interests in both established and emerging U.S. onshore resource plays. Specifically, during the first three months of 2012, we focused on achieving initial production from the first development well on the Bacchus oil field, which has occurred. During the remainder of 2012 we intend to focus on achieving first production from the second development well on the Bacchus oil field and the Rochelle gas field in the North Sea while integrating the assets we expect to acquire in the COP Acquisition and completing the evaluation of our assets in the Heath Shale Oil Play. We believe that the following actions taken during the three months ended March 31, 2012 will support us in executing our core business strategies:

 

   

Pending COP Acquisition: The closing of the COP Acquisition, which we entered into in late 2011, was pending as of March 31, 2012. Upon finalization, we will acquire an interest in three producing U.K. oil fields in the Central North Sea. We anticipate closing on the acquisition of the interest in the Alba field, which represented 62% and 59% of the

 

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acquired assets’ total proved reserves and production, respectively, at the end of 2011, during the second quarter of 2012. However, completion of the Alba field transfer has been delayed due to the efforts of certain of the co-venturers who seek an agreement on the handling of future decommissioning costs, and it is not clear if a resolution with regard to future decommissioning can be found in time for the Alba field portion of the acquisition to close as scheduled on or before May 31, 2012. We believe the assets to be acquired will significantly increase our current production levels, which we expect will have an immediate impact on our cash flows from operations.

 

   

Senior Note Offering: On February 23, 2012, we closed the private placement of $500 million aggregate principal amount of the 2018 Notes. We intend to use net proceeds from the 2018 Notes to fund the COP Acquisition, to repay all amounts outstanding under our Senior Term Loan, and for general corporate purposes. If the COP Acquisition does not close, by June 15, 2012, or other alternatives are not arranged, we would be required to redeem the 2018 Notes, including penalties and interest.

Results of Operations

Revenue, net income and cash flows from operating activities are very sensitive to changes in prices received for our products. 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.

Net loss to common shareholders for the three months ended March 31, 2012 was $35.7 million, or $0.94 per share, compared to $8.0 million, or $0.30 per share, for the same period in 2011. The change in the net loss to common shareholders for these periods is primarily due to an impairment of oil and gas properties, increased interest expenses and increased unrealized losses on derivatives, partially offset by increased revenues as our U.S. production increased.

In addition to our operations, our net income or loss 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 three months ended March 31, 2012 was $15.4 million as compared to Net Loss as Adjusted of $12.9 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 was $2.2 million for the first quarter March 31, 2012 compared to $4.1 million for the same period in 2011. The decrease in Adjusted EBITDA was due to increased foreign currency losses related to liabilities. For definitions of Net (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 $(21.2) million for the three months ended March 31, 2012 as compared to cash flows used in operating activities of $(15.4) million for the same period in 2011. The change was primarily due to increased interest expense related to our outstanding indebtedness.

 

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Revenue and Sales Volume

Our revenues increased from $14.1 million during the three months ended March 31, 2011 to $15.2 million in the same period of 2012 primarily as a result of increased U.S. gas sales volumes and higher oil prices, partially offset by lower U.S. natural gas prices. The significant increase in supply of natural gas from shale drilling has materially and adversely impacted the U.S. gas markets and prices, and has continued to depress U.S. gas prices.

For the first quarter of 2012 and 2011, we had sales volume of 4,174 BOE per day and 3,001 BOE per day, respectively. Our physical daily production was approximately 3,974 BOE and 3,192 BOE for the first quarter of 2012 and 2011, respectively. The increase in sales volume and daily production is primarily attributable to an increase in sales volumes and production from our U.S. assets.

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  
     March 31,  
     2012      2011  

Sales volume (1)

     

Oil and condensate sales (Mbbls):

     

United Kingdom

     96        100  

United States

     1        2  
  

 

 

    

 

 

 

Total

     97        102  
  

 

 

    

 

 

 

Gas sales (MMcf):

     

United Kingdom

     21        44  

United States

     1,677        965  
  

 

 

    

 

 

 

Total

     1,698        1,009  
  

 

 

    

 

 

 

Oil equivalent sales (MBOE)

     

United Kingdom

     100        108  

United States

     280        162  
  

 

 

    

 

 

 

Total

     380        270  
  

 

 

    

 

 

 

Total BOE per day

     4,174        3,001  
  

 

 

    

 

 

 

Physical production volume (BOE per day) (1)

     

United Kingdom

     893        1,307  

United States

     3,081        1,885  
  

 

 

    

 

 

 

Total

     3,974        3,192  
  

 

 

    

 

 

 

Realized Price, before and after derivatives

     

Oil and condensate price ($ per Bbl)

   $ 116.99      $ 98.79  
  

 

 

    

 

 

 

Gas price ($ per Mcf)

   $ 2.25      $ 4.00  
  

 

 

    

 

 

 

Equivalent oil price ($ per BOE)

   $ 39.92      $ 52.22  
  

 

 

    

 

 

 

 

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

The markets in which we sell our oil and natural gas also materially impact our revenues and cash flows. Oil trades on a worldwide market, and, consequently, price movements for all types and grades of crude oil generally trend in the same direction and within a relatively narrow price range. However, natural gas prices vary among geographic areas as the prices received are largely impacted by local supply and demand conditions as the global transportation infrastructure for natural gas is still developing. As such, the oil we produce and sell is typically

 

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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 first quarter of 2012, operating expenses remained consistent at $4.9 million as compared to $5.0 million for the same period in 2011. Operating costs per BOE decreased from $18.66 per BOE for the first quarter of 2011 to $12.89 per BOE for the same period in 2012. The decreases in operating costs per BOE were due to the impact of higher volumes of U.S. gas production which has lower cost per BOE than our U.K. production.

Depreciation, depletion and amortization (“DD&A”) expense increased to $7.9 million from $6.3 million for the first quarter of 2012 and 2011, respectively, as a result of the increased sales volumes in our U.S. operations.

For the first quarter of 2012, the prices used in the full cost ceiling test for our U.S. properties were $97.98 per barrel for oil and $3.71 per Mcf for gas. We recorded an impairment of $15.7 during the first quarter of 2012 for our U.S. properties. For the first quarter of 2012, the prices used in the full cost ceiling test for our U.K. properties were $113.89 per barrel for oil and $8.69 per Mcf for gas. We did not record an impairment during the first quarter of 2012 for 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 to $5.3 million during the first quarter of 2012 as compared to $4.7 million for the corresponding period in 2011. These increases primarily resulted from higher stock-based compensation expense due to a new performance-based award and increased travel expenses associated with our pending COP Acquisition and issuance of the 2018 Notes. Components of G&A expenses for these periods are as follows:

 

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      Three Months Ended  
     March 31,  

(Amounts in thousands)

   2012     2011  

Compensation

   $ 4,728     $ 5,038  

Consulting, legal and accounting fees

     1,765       1,721  

Occupancy costs

     382       365  

Other expenses

     1,169       503  
  

 

 

   

 

 

 

Total gross cash G&A expenses

     8,044       7,627  

Non-cash stock-based compensation

     1,559       875  
  

 

 

   

 

 

 

Gross G&A expenses

     9,603       8,502  

Less: capitalized G & A expenses

     (4,280     (3,789
  

 

 

   

 

 

 

Net G&A expenses

   $ 5,323     $ 4,713  
  

 

 

   

 

 

 

Interest expense increased by $7.2 million to $19.7 million for the first quarter of 2012 as compared to $12.5 million for the corresponding period in 2011. These increases were primarily due to increased interest costs related to additional issuances of the Senior Term Loan, the 5.5% Convertible Senior Notes and the 2018 Notes, partially offset by the reduction of interest expense related to the repayment of the 6% Convertible Notes. For the three months ended March 31, 2012 and 2011, we had non-cash interest expense, including amortization of loan costs and discount, of $7.2 million and $6.9 million, respectively.

Income Taxes

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

 

(amounts in thousands)

   U.K.     U.S.     Other     Total  

Three Months Ended March 31, 2012:

        

Net loss before taxes

   $ (14,659   $ (24,681   $ (6,515   $ (45,855

Current tax benefit

     (1,579     —          —          (1,579

Deferred tax benefit

     (9,014     —          —          (9,014
  

 

 

   

 

 

   

 

 

   

 

 

 

Income tax benefit

     (10,593     —          —          (10,593
  

 

 

   

 

 

   

 

 

   

 

 

 

Net loss

   $ (4,066   $ (24,681   $ (6,515   $ (35,262
  

 

 

   

 

 

   

 

 

   

 

 

 

Three Months Ended March 31, 2011:

        

Net income (loss) before taxes

   $ (3,881   $ (9,066   $ 2,776     $ (10,171

Current tax benefit

     (532     —          —          (532

Deferred tax benefit

     (2,182     —          —          (2,182
  

 

 

   

 

 

   

 

 

   

 

 

 

Income tax benefit

     (2,714     —          —          (2,714
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

   $ (1,167   $ (9,066   $ 2,776     $ (7,457
  

 

 

   

 

 

   

 

 

   

 

 

 

 

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The change in income tax expense (benefit) from $(2.7) million to $(10.6) million for the three months ended March 31, 2011 and 2012, respectively, is primarily the result of increased losses in the U.K. due to the change in foreign currency (gain) loss from $(0.6) million and $2.4 million in 2011 and 2012, respectively, and increased interest expense from $4.8 million to $13.5 million in 2011 and 2012, respectively. The current tax 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.

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

 

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Provided below are reconciliations of net loss to the following non-GAAP financial measures of: Net Loss as Adjusted and Adjusted EBITDA:

 

     Three Months Ended  
     March 31,  
(amounts in thousands)    2012     2011  

Net loss

   $ (35,262   $ (7,457

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

     15,740       —     

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

     4,148       (5,469
  

 

 

   

 

 

 

Net Loss as Adjusted

   $ (15,374   $ (12,926
  

 

 

   

 

 

 

Net loss

   $ (35,262   $ (7,457

Unrealized (gain) loss on derivatives

     4,779       (4,464

Net interest expense

     19,651       12,418  

Depreciation, depletion and amortization

     7,906       6,323  

Impairment of oil and gas properties

     15,740       —     

Income tax benefit

     (10,593     (2,714
  

 

 

   

 

 

 

Adjusted EBITDA

   $ 2,221     $ 4,106  
  

 

 

   

 

 

 

 

(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 of $631 and $1,006, 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.

 

      Three Months Ended March 31,  
(amounts in thousands)    2012     2011  

Net cash used in operating activities

   $ (21,153   $ (15,422
  

 

 

   

 

 

 

Net cash used in investing activities

   $ (524,693   $ (42,407
  

 

 

   

 

 

 

Net cash provided by financing activities

   $ 457,996     $ 110,708  
  

 

 

   

 

 

 

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 ($21.2) million for the three months ended March 31, 2012 as compared to $(15.4) million used in operating activities for the three months ended March 31, 2011, primarily due to our increased indebtedness following increased interest expense related to our debt issuances.

 

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The cash used in investing activities represents expenditures for capital projects, including acquisitions. On February 23, 2012, we closed the private placement of $500 million aggregate principal amount of the 2018 Notes. We intend to use the proceeds from the 2018 Notes to fund the COP Acquisition, to repay all amounts outstanding under our Senior Term Loan due 2013 and for general corporate purposes. The COP Purchase Agreement provides for the possibility that the COP Acquisition may close in multiple stages. If we close on the first stage, the acquisition of an additional interest in the Alba field prior to June 15, 2012, the full amount of proceeds will be released from escrow. Prior to the closing of the acquisition in the North Sea, the net proceeds of the offering are held in an escrow account as restricted cash.

In accordance with the terms of the 2018 Notes, if we are unable to close on the Alba field portion of the COP Acquisition, by June 15, 2012, or arrange other alternatives, we would be required to redeem the full amount of the notes, including penalties, which is more than the net proceeds from the offering now in escrow. In addition, we would be required to repay all outstanding borrowings under our new revolving credit facility.

Also included in restricted cash is approximately $33 million deposited after CBA exercised the right to require us to cash collateralize the letter of credit agreement during the first quarter. For the three months ended March 31, 2012, cash used in investing activities was $524.7 million as opposed to $42.4 million in the corresponding period of the prior year, primarily resulting from the increase in restricted cash.

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.

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

On April 12, 2012, we entered into a $100 million Revolving Credit Facility and utilized $40 million of the facility. For additional details regarding this new credit facility, see Note 13 to the Condensed Consolidated Financial Statements.

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. We strive to synchronize our capital expenditures with our cash flow and cash on hand. During the first 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

 

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U.S. drilling program will be determined by our anticipated available cash and any changes in the U.S. natural gas markets and prices.

Oil and gas prices continue to be impacted by supply and demand on a worldwide basis. Although oil and gas prices have remained volatile, the full impact on our cash flows will be partially mitigated by our balance of gas and oil production and our commodity derivative positions. As of March 31, 2012, we had spent $23.2 million in capital expenditures for the year.

North Sea Acquisition

On December 23, 2011, we entered into the COP Purchase to acquire certain oil and natural gas interests in the North Sea for approximately $330 million in cash. The interests to be acquired are composed of a 23.43% interest in the Alba field (in which we already own a 2.25% interest), a 40% interest in the MacCulloch field and an 18% interest in the Nicol field. 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. 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 Alba field. The COP Purchase Agreement provides for the possibility that the COP Acquisition may close in multiple stages. In addition, the COP Purchase Agreement provides that we may close on the interest in the Alba field without subsequently closing on the remaining interests, in certain circumstances. In accordance with the terms of the COP Purchase Agreement, we will not, however, close on the remaining interests without closing on the acquisition of the interest in the Alba field.

We are working to close the COP Acquisition. Completion of the Alba field transfer has been delayed due to the efforts of certain of the co-venturers who seek an agreement on the handling of future decommissioning costs, which was neither under discussion at the execution of the purchase and sale agreement with the seller, nor is it required as a condition of closing. As a current owner in Alba field, we believe it is in the best interest of all parties to deal with future decommissioning plans and associated costs prudently in time, but proceed to closing immediately. At this time, the resolution of this process is not clear. See “Risk Factors” herein for additional discussion of the delays in closing the acquisition.

The assets to be acquired in the pending COP Acquisition produced at an average of approximately 11,000 BOE/d at the end of 2011. After giving pro forma effect to the COP Acquisition, our production at the end of 2011 would have been approximately 14,400 BOE/d. Further, we expect that if we consummate the COP Acquisition, oil production will increase to approximately 84% of our total production.

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.

 

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We hold a 30% working interest in our Bacchus field asset, which is operated by Apache Corporation, who owns a 50% working interest. The field development plan (“FDP”) for the Bacchus field calls for a subsea development with three wells to be drilled and linked to production facilities at the nearby Forties field. The 6.5 kilometer subsea bundled pipeline is in place, and the first of the three planned development wells has been drilled. On April 30, 2012 we announced that we had achieved production from the first development well on the Bacchus field located in Block 22/06a in the U.K. Central North Sea. Initial production rates over the first five days were approximately 6,000 gross barrels of oil per day. Endeavour has a 30% interest in Bacchus. When the full field development is completed and on-line, we will be able to provide reliable long-term sustainable production estimates. We commenced drilling the second of three planned development wells on Bacchus field on April 20, 2012. It is expected that this well will be on production early in the third quarter of 2012.

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. The required modifications to the Scott Platform are progressing with various items of large equipment already installed. The Rochelle development continues on schedule for first production in the fourth quarter of 2012 with the contracted drilling rig expected to arrive in the spring to commence drilling of the two planned production wells.

United States Capital Program

Our strategy for our U.S. operations has been to employ a measured approach that seeks to balance U.S. natural gas prices with drilling costs. We have 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. 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.

We believe this approach in the U.S. should provide flexibility to adjust our drilling activity in accordance with current and future commodity prices and our operating results, while still allowing our U.S. production to grow and provide near-term return on capital to balance our longer production-cycle U.K. projects.

In the Haynesville area, during the first quarter, we completed one minority-interest well and drilled a second joint interest well. We have deferred the completion of that well and suspended drilling operations due to low gas prices.

In the Marcellus area, we will drill as many as two wells to maintain our leasehold in the Daniel Field in Cameron County during 2012. In parallel, 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 have obtained rights-of-way, and are currently in the process of obtaining permits and conducting a habitat study. Upon completion of these items, we expect to begin construction of a gathering line to tie our production to an existing pipeline. We will defer any well completion operations until that pipeline work is completed.

 

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In Montana, we drilled four vertical pilot wells during 2011 to evaluate the potential of our acreage in the Heath Shale tight oil play and are currently evaluating the results to define possible horizontal re-entry target zones for 2012.

Outlook

2012 Planned Capital Expenditures

We expect that our total capital expenditure budget for 2012 will be between $150 million and $175 million. We expect to spend approximately $125 million to $150 million of the total 2012 budget in the U.K., primarily on the advancement of our development projects. The acquisition of the ConocoPhillips assets is expected to add another $20 million—$25 million to Endeavour’s capital budget, upon completion of the transaction. 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 normal factors affecting the oil and gas industry.

We intend to fund our 2012 capital expenditures and acquisitions primarily through cash on hand, cash flow generated from operations, including cash flow from the assets to be acquired in the COP Acquisition, and debt issuances under the 2018 Notes and Revolving Credit Facility. The majority of our cash on hand has been generated through borrowings under our secured 15.0% senior term loan due 2013 of our principal U.K. subsidiary and the July 2011 offering of our 5.5% Convertible Senior Notes due 2016.

Our primary sources of financial resources and liquidity are cash on hand, internally generated cash flows from operations and access to the credit and capital markets, to the extent available. We strive to synchronize our capital expenditures with our cash flow and cash on hand. We believe the combination of our available cash on hand and cash flow from operations, including production from the assets to be acquired in the COP Acquisition, will fund our capital expenditure program for 2012. In turn, our capital program should allow additional cash flows to be generated as Bacchus continues to produce.

 

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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 March 31, 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

   $ 973,077      $ 14,850      $ 258,906      $ 199,321      $ 500,000  

Interest

     481,510        105,630        151,897        159,483        64,500  

Asset retirement obligations

     48,495        2,157        3,891        28,964        13,483  

Operating leases for office leases and equipment

     6,845        905        2,591        2,447        902  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Contractual Obligations

   $ 1,509,927      $ 123,542      $ 417,285      $ 390,215      $ 578,885  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) Interest on our 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;

 

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projected costs, savings and plans;

 

   

objectives of management for future operations;

 

   

legal strategies; and

 

   

legal proceedings.

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

 

   

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

 

   

decreases in proved reserves due to technical or economic factors;

 

   

drilling of wells and other planned exploitation activities;

 

   

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 10 to the Condensed Consolidated Financial Statements.

At March 31, 2012, we had the following commodity derivative instruments outstanding:

 

     2012      Total  

Oil:

     

Fixed Price Puts (Mbbl)—Brent

     228        228  

Weighted Average Price ($/Barrel)

   $ 84.29      $ 84.29  

Gas: (1)

     

Fixed Price Puts (MMcf)—Heren National Balancing Point

     398        398  

Weighted Average Price ($/Mcf)

   $ 8.52      $ 8.52  

 

(1) 

Gas derivative contracts are designated in therms and have been converted to Mcf at a rate of 10 therm to 1 Mcf. The exchange rate at March 31, 2012 was $1.60 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 March 31, 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.

If the Alba field portion of the COP Acquisition is not consummated or other alternatives arranged, we will be required to redeem the 2018 Notes and repay the amounts outstanding under our new revolving credit facility.

Completion of the Alba field transfer, one of the fields under the COP Acquisition, has been delayed due to the efforts of certain of the co-venturers who seek an agreement on the handling of future decommissioning costs, which was neither under discussion by the co-venturers at the execution of the purchase and sale agreement, nor is it required as a condition of closing. ConocoPhillips and Endeavour have proposed a solution to the Alba co-venturers who are considering the proposal. At this time, the resolution of this process is not clear.

In accordance with the terms of the 2018 Notes, if the COP acquisition does not close by June 15, 2012, or other alternatives are not arranged, we would be required to redeem the 2018 Notes, including penalties and interest, which is more than the net proceeds from the offering now in escrow. In addition, we would be required to repay the $40 million of outstanding borrowings under our new revolving credit facility. There can be no assurance that we will have the necessary cash or will be able to obtain the necessary financing to fund these repayments.

Item 6: Exhibits

The exhibits marked with the asterisk symbol (*) are filed or furnished (in the case of Exhibits 32.1, 32.2 and 101) with this

Form 10-Q.

 

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Endeavour International Corporation

 

3.1(a)   Amended and Restated Articles of Incorporation (Incorporated by reference to Exhibit 3.2 of our Quarterly Report on Form 10-Q (Commission File No. 001-32212) for the quarter ended June 30, 2004).
3.1(b)   Certificate of Amendment dated June 1, 2006 (Incorporated by reference to Exhibit 4.2 of our Registration Statement on Form S-3 (Commission File No. 333-139304) filed on December 13, 2006).
3.1(c)   Certificate of Amendment dated June 1, 2010 (Incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on June 3, 2010).
3.1(d)   Amendment to Articles of Incorporation, dated November 17, 2010 (Incorporated by reference to Exhibit 3.1(d) of our Annual Report on Form 10-K (Commission File No. 001-32212) for the year ended December 31, 2010).
3.2(a)   Amended and Restated Bylaws (Incorporated by reference to Exhibit 3.4 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on November 6, 2006).
3.2(b)   Amendment to Amended and Restated 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   First Priority Indenture, dated February 23, 2012, among Endeavour International Corporation, the subsidiary guarantors party thereto, and Wells Fargo Bank, National Association, as trustee and collateral agent (Incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on February 29, 2012).
4.2   Form of First Priority 12% Senior Notes due 2018 (included in Exhibit 4.1).
4.3   Second Priority Indenture, dated February 23, 2012, among Endeavour International Corporation, the subsidiary guarantors party thereto, Wilmington Trust, National Association, as trustee and Wells Fargo Bank, National Association, as collateral agent (Incorporated by reference to Exhibit 4.3 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on February 29, 2012).
4.4   Form of Second Priority 12% Senior Notes due 2018 (included in Exhibit 4.3).
4.5   First Priority Registration Rights Agreement, dated February 23, 2012, among Endeavour International Corporation, the subsidiary guarantors party thereto and Citigroup Global Markets Inc., as representative of the initial purchasers named therein (Incorporated by reference to Exhibit 4.5 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on February 29, 2012).
4.6   Second Priority Registration Rights Agreement, dated February 23, 2012, among Endeavour International Corporation, the subsidiary guarantors party thereto and Citigroup Global Markets Inc. (Incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on February 29, 2012).

 

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10.1    *    Consent and Fourth Amendment to Credit Agreement, U.S. Security Agreement and Subsidiaries Guaranty dated as of January 18, 2012, among Endeavour International Corporation, Endeavour Energy UK Limited. Cyan Partners, LP, as administrative agent, and certain lenders party thereto.
10.2       Purchase Agreement dated as of February 13, 2012, among Endeavour International Corporation, the guarantors named therein and Citigroup Global Markets Inc., as representative of the Initial Purchasers named therein (Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K (Commission File No. 001-32212) filed on February 17, 2012).
10.3    *    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.
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.
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.

 

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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: May 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)

XNYS:END Endeavour International Corp Quarterly Report 10-Q Filling

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