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8-K - FORM 8-K - ENDEAVOUR INTERNATIONAL CORPh69239e8vk.htm
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EX-99.1 - EX-99.1 - ENDEAVOUR INTERNATIONAL CORPh69239exv99w1.htm
EX-99.3 - EX-99.3 - ENDEAVOUR INTERNATIONAL CORPh69239exv99w3.htm
Exhibit 99.2
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
This Management’s Discussion and Analysis of Financial Condition and Results of Operations and other parts of this report contain forward-looking statements that involve risks and uncertainties. All forward-looking statements included in this report are based on information available to Endeavour on the date hereof, and we assume no obligation to update any such forward-looking statements. Our actual results could differ materially from those anticipated in these forward-looking statements as a result of a number of factors, including those set forth in the section captioned “Risk Factors” in Item 1A and elsewhere in this report. The following should be read in conjunction with the audited financial statements and the notes thereto included herein. 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.
We have reissued this MD&A and filed it under cover of Form 8-K on January 8, 2010 to reflect the disposition of our Norwegian subsidiary and the related reclassification of its results of operation and financial position as discontinued operations as discussed below in detail.
Overview
We are an international oil and gas exploration and production company focused on the acquisition, exploration and development of energy reserves. To date, we have invested a significant amount of our resources on various development, acquisition and exploration projects. Over the last several years, we have principally used acquisitions to build our base of production, proved reserves and cash flow while continuing our exploration and development programs. Key items related to our acquisitions, drilling and operations in the last three years include:
    Acquisitions
  o   In late 2006, we completed the acquisition of various fields in the UK North Sea from Talisman.
  o   Enoch — Following our acquisition of an interest in this field in 2006, we completed the development program and began initial production in mid 2007.
    Exploration — During the last three years, we have drilled 17 exploration wells with four successes in the UK, seven in Norway and one in the U.S., including:
  o   Cygnus — The first of our wells in our 2006 drilling program, the Cygnus prospect, was spud in early February 2006 in the UK sector of the North Sea. In 2008 we submitted a development plan to the UK authorities and began drilling an appraisal well. We announced the success of the appraisal well in 2009.
  o   Columbus — In 2006, we drilled the Columbus exploratory prospect in the Central Graben region of the North Sea. We served as operator of the well. In December 2006, we completed successful testing of the well. In 2007, we drilled an appraisal well and its sidetrack effectively confirming the presence of gas/condensate bearing sands. In 2008, we submitted a development plan to the UK authorities and expect to receive approval in 2009.
  o   Rochelle — We began appraisal drilling in 2008 and announced successful results in 2009.
  o   United States — In 2008, we participated in two exploration wells in the United States. We announced first production from one well in January 2009 while the second well is still undergoing testing and evaluation.
    Producing assets — At the end of 2007, we completed a project that initiated gas production at the Njord field. Production from the Goldeneye field has continued at levels above our expectations,

 


 

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      indicating the quality of this large gas field. Development drilling has been ongoing at Njord, Brage and Alba to maintain production levels.
Our realized price before derivatives increased 25% from 2007 to 2008 largely as a result of oil prices climbing to record levels in the summer of 2008 and gas prices in our markets improving. This substantial increase in prices in the first half of 2008 helped revenue grow from $135.9 million in 2007 to $170.8 million in 2008. With this higher revenue and strong fiscal discipline over expenses, we repaid $32.0 million in debt, spent $66.4 million in capital expenditures during 2008 and increased cash from year end by $17.6 million. At December 31, 2008, we held $31.4 million in cash and another $20.7 million in cash restricted for drilling rig commitments.
Even with the substantial growth in revenues, net income can be significantly affected by various non-cash items, such as unrealized gains and losses on our commodity derivatives, currency impact of long-term liabilities and deferred taxes. Cash flow provided by (used in) operations was $133.2 million in 2008 versus $128.5 million in 2007 and $(14.1) million in 2006. Discretionary cash flow was $120.8 million in 2008, compared to $113.0 million in 2007 and $5.1 million in 2006, respectively. This significant increase in our discretionary cash flow in the past two years has allowed us to repay debt in 2007 and 2008 while continuing to actively invest in our capital programs.
Net income available to common shareholders was $45.7 million for 2008, or $0.32 per diluted share. Net loss available to common shareholders for 2007 was $60.3 million, or $0.49 per share, reflecting the significant unrealized loss on the mark-to-market of commodity derivatives. For 2006, net loss was $8.8 million, or $0.10 per share. The net loss for 2006 reflects a significant unrealized gain on the mark-to-market of commodity derivatives.
Net income as adjusted for 2008 would have been $5.7 million without the effect of impairments, derivative transactions and currency impacts of deferred taxes. Net loss as adjusted for 2007 would have been $10.9 million, as compared to net loss as adjusted of $20.9 million in 2006. Adjusted EBITDA increased to $176.6 million in 2008, as compared to $124.1 million in 2007 and $9.2 million in 2006.
Given the significant impact that non-cash items may have on our net income, we use various measures in addition to net income, including non-financial performance indicators and non-GAAP measures as key metrics to manage our business. These key metrics demonstrate the company’s ability to maintain or grow production levels and reserves, internally fund capital expenditures and service debt as well as provide comparisons to other oil and gas exploration and production companies. These measures include, among others, debt and cash balances, production levels, oil and gas reserves, drilling results, discretionary cash flow, adjusted earnings before interest, taxes, depreciation, depletion and amortization (“Adjusted EBITDA”) and adjusted net income.
For definitions of Adjusted EBITDA and Discretionary Cash Flow, and a reconciliation of Adjusted EBITDA to net income as adjusted, please see “Reconciliation of Non-GAAP Accounting Measures.”
In connection with the Talisman Acquisition, we entered into various oil and gas derivative instruments to stabilize cash flows from the acquired assets and satisfy certain obligations under the financing agreements that funded the acquisition. Hedge accounting has not been elected for these instruments resulting in the application of mark-to-market accounting — effectively pulling forward into current periods the non-cash gains and losses from commodity price fluctuations relating to all future delivery periods. When we entered into these contracts, they covered nearly 5.2 million BOE beginning in 2007 and running through 2011 at a weighted average price of $68.35. As both oil and gas prices fell from the date we entered into the contracts through December 31, 2006, we recorded an unrealized gain of $34.5 million reflecting the decline in future commodity prices through 2011. However, in 2007, commodity prices reversed their 2006 declines, continuing to increase to record levels in the case of oil. With oil

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prices reaching nearly $100 per barrel and gas prices recovering to levels close to our original contract prices, we recorded an $89.1 million unrealized loss in 2007 on contract volumes through 2011. As oil prices spiked to record levels in 2008 and then went into an unprecedented decline in the last half of the year, we recorded $77.8 million in an unrealized gain on contract volumes through 2011. We expect to continue to have fluctuations in net earnings each period as commodity prices fluctuate based on all remaining unsettled contracts at the end of each period. See Note 16 to the consolidated financial statements for additional information on these derivatives.
Revenues, Volumes and Operating Costs
Our revenues have increased significantly since 2006 primarily due to the following:
    In November 2006, we completed the Talisman Acquisition and each of 2008 and 2007 reflect a full year’s contribution of those assets.
    Similarly, our Enoch field began first production in mid 2007.
    The last three years have been turbulent times for the global oil market and, to a lesser extent, the North Sea gas markets. 2006 experienced seemingly high commodity prices, only to be followed by lower prices in 2007, new, unprecedented highs in mid 2008 and a precipitous drop by the end of 2008.
    To soften the extremes of the commodity markets, we have derivative instruments covering a portion of our anticipated sales through 2011.
    Natural production declines at certain of our fields have not been offset by infield drilling, resulting in small production decreases at certain fields.
    There was an increase in gas production from our discontinued operations at the end of 2007 with the completion of a gas project at Njord in the fourth quarter of 2007.
In general total operating costs increased from 2006 through 2008 as a result of production from the acquisitions discussed above. Operating costs per BOE declined for 2006 and 2007 due to the lower operating costs per BOE for our acquired UK properties. Operating costs per BOE increased from 2007 to 2008 primarily due to increased fuel costs at a non-operated facility where several of our fields deliver production.
The following table shows our annual average sales volumes, sales prices and average production costs.

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    Year Ended December 31,
    2008   2007   2006
 
Sales Volume (1):
                       
Oil and condensate sales (Mbbl):
                       
United Kingdom
    1,032       1,274       209  
 
Continuing operations
    1,032       1,274       209  
Discontinued operations - Norway
    726       519       508  
 
Total
    1,758       1,793       717  
 
                       
Gas sales (MMcf):
                       
United Kingdom
    6,532       8,556       1,539  
 
Continuing operations
    6,532       8,556       1,539  
Discontinued operations - Norway
    2,322       328       203  
 
Total
    8,854       8,884       1,742  
 
                       
Total sales (MBOE):
                       
United Kingdom
    2,121       2,700       466  
 
Continuing operations
    2,121       2,700       466  
Discontinued operations - Norway
    1,113       574       542  
 
Total
    3,234       3,274       1,008  
 
                       
BOE per day
    8,835       8,969       2,760  
 
                       
Physical Production Volume (1):
                       
Total production (BOE per day)
                       
United Kingdom
    5,804       7,660       1,334  
 
Continuing operations
    5,804       7,660       1,334  
Discontinued operations - Norway
    3,033       1,608       1,566  
 
Total
    8,837       9,268       2,900  
 
                       
Realized Prices (2):
                       
Oil and condensate price ($  per Bbl)
                       
Before commodity derivatives
  $ 90.53     $ 67.11     $ 60.51  
Effect of commodity derivatives
    (14.50 )     (2.13 )     (7.63 )
 
Including commodity derivatives
  $ 76.03     $ 64.98     $ 52.88  
 
                       
Gas price ($  per Mcf)
                       
Before commodity derivatives
  $ 11.44     $ 6.27     $ 9.30  
Effect of commodity derivatives
    (0.35 )     1.79        
 
Including commodity derivatives
  $ 11.09     $ 8.06     $ 9.30  
 
                       
Equivalent oil price ($  per BOE)
                       
Before commodity derivatives
  $ 80.54     $ 53.78     $ 59.15  
Effect of commodity derivatives
    (8.84 )     3.68       (5.43 )
 
Including commodity derivatives
  $ 71.70     $ 57.46     $ 53.72  
 
                       
Operating Statistics:
                       
Operating costs ($  per BOE) (3)
  $ 14.40     $ 12.56     $ 15.45  
G&A costs ($  per BOE)
  $ 6.07     $ 6.07     $ 21.76  
Sales volume per employee (MBOE/employee)
    52       54       17  
 
(1)   We record oil revenues on the sales method, i.e. when delivery has occurred. Actual production may differ based on the timing of tanker liftings. We use the entitlements method to account for sales of gas production.

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(2)   The average sales prices reflect both our continuing and discontinued operations and include realized gains and losses for derivative contracts we utilize to manage price risk related to our future cash flows.
 
(3)   Operating costs reflect both our continuing and discontinued operations and are costs incurred to operate and maintain our wells and related equipment and include cost of labor, well service and repair, location maintenance, power and fuel, transportation, cost of product and production related general and administrative costs.
DD&A and Impairment of Oil and Gas Properties
Decreased DD&A expense from 2007 to 2008 reflects the impact of a decrease in production from 2007 to 2008 partially offset by an increase in the DD&A rate. DD&A expense increased from 2006 to 2007 as a result of the acquisitions discussed above. In addition, DD&A for 2006 includes $1.2 million related to the impairment of our intangible asset.
In 2008, we recorded $37.0 million in impairment of oil and gas properties, pre-tax, through the application of the full cost ceiling test at year-end. The prices used to determine the impairment were $36.55 per barrel for oil and $8.70 per Mcf for gas. While our commodity derivatives had a fair value of $31.0 million at December 31, 2008, these derivatives were not included in the calculation of the full cost ceiling test as the derivatives are not accounted for as cash flow hedges.
During 2006, we recorded $0.8 million in impairment of oil and gas properties related to the abandonment costs of a well impaired in 2005.
General and Administrative Expenses
Our net G&A expenses have decreased since 2006 as we have been able to absorb our expanded operations without a corresponding increase in the number of employees. We had 62 employees at December 31, 2008, 61 employees at December 31, 2007, and 58 employees at December 31, 2006. Gross cash G&A expense increases since 2006 reflect increased foreign currency exchange rates, additional payroll taxes and salary expense related to the changes in staffing, occupancy costs and fees. Occupancy costs increased due to additional office leases at our four locations. Accounting, legal and tax consulting fees fluctuated with our acquisition and financing activity. Non-cash stock-based compensation decreased as a result of the final vesting of grants given in prior years, current year forfeitures and declining fair values on each year’s grants. Components of G&A expenses for these periods are as follows:

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(Amounts in thousands)   Year Ended December 31,
    2008   2007   2006
 
Compensation
  $ 11,203     $ 10,181     $ 9,214  
Consulting, legal and accounting fees
    4,679       5,045       3,387  
Occupancy costs
    1,130       994       507  
Other expenses
    4,004       2,352       3,040  
 
 
                       
Total gross cash G&A expenses
    21,016       18,572       16,148  
 
                       
Non-cash stock-based compensation
    2,928       4,487       10,819  
 
 
                       
Gross G&A expenses
    23,944       23,059       26,967  
 
                       
Less: capitalized G&A expenses
    (8,012 )     (7,206 )     (9,322 )
 
 
                       
Net G&A expenses
  $ 15,932     $ 15,853     $ 17,645  
 
Interest Expense and Other
Interest expense increased to $23.0 million in 2008 primarily as a result of $4.3 million in expenses, including $2.1 million in cash, related to the early repayment of the second lien term loan. Interest expense increased to $19.3 million for 2007 versus only $8.6 million in 2006, reflecting the various debt instruments issued to fund the Talisman Acquisition. Interest income results from our investments of excess cash in short-term commercial paper and money market accounts.
Other income (expense) for 2006 includes $3.8 million in financing costs paid in connection with the Talisman Acquisition and $1.8 million impairment of long-term marketable securities with the remainder primarily representing foreign currency exchange losses.

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Income Taxes
The following summarizes the components of tax expense (benefit):
                                                 
                            Total   Discontinued    
                            Continuing   Operations -    
(Amounts in thousands)   UK   U.S.   Other   Operations   Norway   Total
 
Year Ended December 31, 2008
                                               
Net income (loss) before taxes
  $ 66,129     $ (11,969 )   $ (4,185 )   $ 49,975     $ 63,244     $ 113,219  
 
                                               
Current tax expense
    11,158             10       11,168       27,879       39,047  
Deferred tax expense
    22,673             303       22,976       15,415       38,391  
Foreign currency gains on
deferred tax liabilities
    (10,028 )                 (10,028 )     (10,681 )     (20,709 )
 
Total tax expense
    23,803             313       24,116       32,613       56,729  
 
 
                                               
Net income (loss) after taxes
  $ 42,326     $ (11,969 )   $ (4,498 )   $ 25,859     $ 30,631     $ 56,490  
 
 
                                               
Year Ended December 31, 2007
                                               
Net income (loss) before taxes
  $ (68,704 )   $ (10,233 )   $ 6,584     $ (72,353 )   $ 14,095     $ (58,258 )
 
                                               
Current tax (benefit) expense
    2,898       (3 )     289       3,184       562       3,746  
Deferred tax (benefit) expense
    (27,430 )           711       (26,719 )     8,951       (17,768 )
Foreign currency losses on deferred tax liabilities
    1,327                   1,327       3,514       4,841  
 
Total tax (benefit) expense
    (23,205 )     (3 )     1,000       (22,208 )     13,027       (9,181 )
 
 
                                               
Net income (loss) after taxes
  $ (45,499 )   $ (10,230 )   $ 5,584     $ (50,145 )   $ 1,068   $ (49,077 )
 
 
                                               
Year Ended December 31, 2006
                                               
Net income (loss) before taxes
  $ 33,275     $ (23,463 )   $ 13     $ 9,825     $ 7,250     $ 17,075  
 
                                               
Current tax (benefit) expense
    1,837       (45 )     69       1,861       9,014       10,875  
Deferred tax (benefit) expense
    10,105                   10,105       (1,840 )     8,265  
Foreign currency losses on deferred tax liabilities
    2,904                   2,904       1,869       4,773  
 
Total tax (benefit) expense
    14,846       (45 )     69       14,870       9,043       23,913  
 
 
                                               
Net income (loss) after taxes
  $ 18,429     $ (23,418 )   $ (56 )   $ (5,045 )   $ (1,793 )   $ (6,838 )
 
Our income tax expense relates primarily to operations in the UK and our discontinued operations in Norway. Income tax expense in 2008 represents the significant increase in revenues as a result of higher realized prices, the strengthening of the U.S. dollar versus the UK pound and Norwegian kroner and the shift in anticipated capital expenditures from late 2008 to early 2009.
During 2007, we incurred taxes in all of the jurisdictions in which we do business, except for the U.S., whereas in 2006, we incurred taxes only on our discontinued Norwegian operations. After closing the Talisman Acquisition in 2006, we began recording tax expense (benefit) for our UK operations and removed the valuation allowances previously recorded. The change in income taxes from an expense of $23.9 million in 2006 to a benefit of $9.2 million in 2007 resulted from the impact of the mark-to-market changes on our derivatives and the activity of our UK operations. At December 31, 2008, we had net operating loss carryforwards of $61.6 million in the U.S.

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In 2008, 2007 and 2006, we have not recorded any income tax benefits in the U.S. as there was no assurance that we could generate any U.S. taxable earnings, resulting in a full valuation allowance of deferred tax assets generated.
As our deferred tax liabilities in the UK and the Netherlands are denominated in their respective currencies, we revalue those deferred tax liabilities to the applicable foreign currency exchange rate at the end of each period. Those foreign currency gains and losses are included in income tax expense.
Capital Program
We originally anticipated spending approximately $90 million during 2008 to fund oil and gas exploration and development in the North Sea. With delays in timing for delivery of the necessary drilling rigs, certain projects were delayed or rescheduled until 2009. We spent $88.5 million, $87.9 million and $56.6 million on oil and gas capital, excluding acquisitions, in 2008, 2007 and 2006, respectively. We spent $15 million to $20 million each year on development activities at our producing properties. The remaining costs were spent on exploration and appraisal activities, including $5.5 million in 2008 related to our new operations in the United States.
Liquidity and Capital Resources
                 
(Amounts in thousands)   December 31, 2008   December 31, 2007
 
Cash
  $ 31,421     $ 13,810  
Restricted cash, related to rig commitments
    20,739       22,000  
Debt, including current maturities
    (227,855 )     (266,250 )
 
Debt, net of cash
  $ (175,695 )   $ (230,440 )
 
                         
    Year Ended December 31,
(Amounts in thousands)   2008   2007   2006
 
Net cash provided by (used in):
                       
Operating activities
  $ 133,180     $ 128,506     $ (14,100 )
Investing activities
  $ (64,851 )   $ (108,140 )   $ (427,118 )
Financing activities
  $ (46,613 )   $ (43,740 )   $ 403,369  
 
Operating, Investing and Financing Activities include the net cash flows from our discontinued operations. For the years ended December 31, 2008, 2007 and 2006, our discontinued operations had net cash flows provided by (used in) operating activities of approximately $38.8 million, $26.3 million and $(1.4) million, respectively. These net cash flows were substantially offset by net cash used by investing activities of approximately $34.7 million, $25.5 million and $10.7 million during 2008, 2007 and 2006, respectively. We do not expect the sale of our discontinued operations to have a material effect on cash flows in 2009, excluding the proceeds from the sale.
In addition to cash flows from operations, we have utilized issuances of debt and equity securities to enhance our liquidity and support the execution of our strategic objectives. Significant issuances and repayments of debt and equity, as well as the uses of the net proceeds, in 2008, 2007 and 2006 were as follows:
    repaid the outstanding balance of the second lien term loan in the first quarter of 2008;
    issued $40 million of the 11.5% convertible bonds in the first quarter of 2008;
    in the fourth quarter of 2006 in conjunction with the Talisman Acquisition, we issued
    37.8 million shares of common stock for $89 million in gross proceeds,
    125,000 shares of Series C Convertible Preferred Stock for $125 million in gross proceeds,
    $150 million in a senior bank debt facility, before financing costs of $3.2 million, and
    $75 million in a second lien term loan, before financing costs of $2.6 million.
See Note 9 to the Consolidated Financial Statements for additional discussion of our debt.

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Cash flow from operations increased to $133.2 million for 2008 primarily due to higher realized commodity prices that were substantially offset by increased current taxes. The increased revenues generated by a full year of operations of our acquired assets were primarily responsible for the cash flows provided by operations of $128.5 million for 2007 versus the $13.2 million used by operations in 2006.
Our revenues and cash flows from operating activities are sensitive to changes in prices received for our products. Our production is sold at prevailing market prices which fluctuate in response to many factors that are outside of our control. Given the current tightly balanced supply-demand market, small variations in either supply or demand, or both, can have dramatic effects on prices we receive for our oil and natural gas production. While the market price received for oil and natural gas varies among geographic areas, oil trades in a worldwide market, whereas natural gas, which is still developing a global transportation system, is more subject to local supply and demand conditions. Consequently, price movements for all types and grades of crude oil generally move in the same direction. Natural gas prices in the North Sea have been influenced by fuel prices around the world, including crude oil and coal. These prices are also impacted by European gas supplies, particularly deliveries from Russian gas supplies. In addition, regional supply and demand issues affect gas prices. The majority of our natural gas is sold in the UK market. Market prices for both oil and natural gas were at historically high levels during 2006 and oil prices continued their high levels throughout much of 2007 and 2008. North Sea gas prices declined in the first quarter of 2007 but recovered in the second half of the year and remained strong during 2008. Both crude oil and natural gas prices have declined in 2009 as a result of the global economic decline.
Non-GAAP Measures
Net income can be significantly affected by various non-cash items, such as unrealized gains and losses on our commodity derivatives, currency impact of long-term liabilities and deferred taxes. Given the significant impact that non-cash items may have on our net income, we use various measures in addition to net income, including non-financial performance indicators and non-GAAP measures as key metrics to manage our business. These key metrics demonstrate the company’s ability to maintain or grow production levels and reserves, internally fund capital expenditures and service debt as well as provide comparisons to other oil and gas exploration and production companies. These measures include, among others, debt and cash balances, production levels, oil and gas reserves, drilling results, discretionary cash flow, adjusted earnings before interest, taxes, depreciation, depletion and amortization (“Adjusted EBITDA”) and adjusted net income.
Net Income (Loss) as Adjusted, Adjusted EBITDA and Discretionary Cash Flow are internal, supplemental measures of our performance that are not required by, or presented in accordance with, GAAP. We use these non-GAAP measures as internal measures of performance and to aid in our budgeting and forecasting processes. We view these non-GAAP measures, and we believe that others in the oil and gas industry view these, or similar, non-GAAP measures, as commonly used analytic indicators to compare performance among companies. We further believe that these non-GAAP measures are frequently used by securities analysts, investors, and other interested parties in the evaluation of issuers, many of which present these measures when reporting their results. We believe these non-GAAP measures provide useful information to both management and investors to gain an overall understanding of our current financial performance and provide investors with financial measures that most closely align to our internal measurement processes. Since the application of mark-to-market accounting has the effect of pulling forward into current periods non-cash gains and losses related to commodity derivatives relating to future delivery periods, analysis of results of operations from one period to another can be difficult. We believe that excluding these unrealized non-cash gains and losses related to commodity derivatives and currency exchange changes provides a more meaningful representation of our economic performance in the reporting period and is therefore useful to us, investors, analysts and others in

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facilitating the analysis of our results of operations from one period to another. These measures should not be considered as measures of financial performance under GAAP, and the items excluded from these measures are significant components in understanding and assessing financial performance.
These non-GAAP measures should not be considered in isolation or as an alternative to net income, operating income or any other performance measures derived in accordance with GAAP or as alternatives to cash flows generated by operating, investing or financing activities as a measure of our liquidity. Because Net Income (Loss) as Adjusted, Adjusted EBITDA and Discretionary Cash Flow are not measurements determined in accordance with GAAP and thus susceptible to varying calculations, Net Income (Loss) as Adjusted, Adjusted EBITDA and Discretionary Cash Flow as presented may not be comparable to other similarly titled measures of other companies.
Net Income (Loss) as Adjusted, Adjusted EBITDA and Discretionary Cash Flow have limitations as an analytical tool, and you should not consider these measures in isolation, or as a substitute for analysis of our financial statement data presented in the consolidated financial statements as reported under GAAP. For example, Net Income (Loss) as Adjusted, Adjusted EBITDA and Discretionary Cash Flow may not reflect:
    our cash expenditures, or future requirements, for capital expenditures or contractual commitments;
    changes in, or cash requirements for, our working capital needs;
    unrealized gains (losses) on derivatives;
    non-cash foreign currency gains (losses);
    our interest expense, or the cash requirements necessary to service interest and principal payments on our debts;
    our preferred stock dividend requirements; and
    depreciation, depletion and amortization.
Because of these limitations, Net Income (Loss) as Adjusted, Adjusted EBITDA and Discretionary Cash Flow should not be considered as measures of cash available to us to invest in the growth of our business. We compensate for these limitations by relying primarily on our GAAP results and by using Net Income (Loss) as Adjusted, Adjusted EBITDA and Discretionary Cash Flow only supplementally.
As required under Regulation G of the Securities Exchange Act of 1934, provided below are reconciliations of net income (loss) to the following non-GAAP financial measures: net income as adjusted, Adjusted EBITDA and discretionary cash flow.
                         
(in thousands, except per share)   December 31,
    2008   2007   2006
 
Net income (loss)
  $ 56,490     $ (49,077 )   $ (6,838 )
 
Depreciation, depletion and amortization
    81,734       76,850       20,164  
Impairment of oil and gas properties
    36,970             849  
Deferred tax expense (benefit)
    17,682       (12,926 )     13,038  
Unrealized (gain) loss on derivative instruments
    (76,666 )     89,132       (34,531 )
Amortization of non-cash compensation
    3,226       4,968       11,573  
Amortization of loan costs and discount
    7,279       1,655       731  
Other
    (5,940 )     2,373       154  
 
 
                       
Discretionary cash flow
  $ 120,775     $ 112,975     $ 5,140  
 

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(in thousands, except per share)   December 31,
    2008   2007   2006
 
Net income (loss) to common shareholders, as reported
  $ 45,681     $ (60,315 )   $ (8,829 )
Impairment of oil and gas properties (net of 50% tax)
    18,485             424  
Unrealized (gains) losses on commodity derivatives (net of 50% tax)
    (38,923 )     44,566       (17,266 )
Unrealized (gains) losses on embedded derivatives
    1,180              
Currency impact of deferred taxes
    (20,709 )     4,842       4,773  
 
 
                       
Net income (loss) to common shareholders as adjusted
  $ 5,714     $ (10,907 )   $ (20,898 )
 
 
                       
Net income (loss) to common shareholders, as reported
  $ 45,681     $ (60,315 )   $ (8,829 )
Unrealized (gains) losses on derivatives
    (76,666 )     89,132       (34,531 )
Net interest expense
    21,301       16,430       5,676  
Depreciation, depletion and amortization
    81,734       76,850       20,164  
Impairment of oil and gas properties
    36,970             849  
Income tax expense (benefit)
    56,729       (9,180 )     23,913  
Preferred stock dividends
    10,809       11,238       1,991  
 
 
                       
Adjusted EBITDA
  $ 176,558     $ 124,155     $ 9,233  
 
Discretionary cash flow is equal to cash flow from operating activities before the changes in operating assets and liabilities.
Outlook
2009 Capital Program
We currently anticipate spending approximately $50 - $60 million during 2009 to fund oil and gas exploration, production and development activities in our core areas of operation in the North Sea and the U.S., excluding our discontinued operations. As in 2008, we intend to finance this capital program through our cash flow generated from operations. To the extent our cash flow from operations is unable to completely finance our capital program, we will postpone certain proposed capital projects until our capital spending does not exceed our available resources. However, we believe our existing production base, combined with our commodity derivatives in place, should generate sufficient cash flows to fund our ongoing operations and capital program.
A significant portion of our 2009 capital program will be directed towards developing our three major projects in the UK sector of the North Sea, the Rochelle, Cygnus and Columbus prospects. In addition, we expect to spend approximately $12 million to $15 million on infield drilling and facilities improvements to maintain production levels on our producing properties. Lastly, we also intend to continue our exploration activities in both the North Sea and the US, subject to the availability of sufficient capital.
The timing, completion and process of our 2009 capital program is subject to a number of factors, including availability of capital, drilling results, drilling and production costs, availability of drilling services and equipment, partner approvals and

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technical work. Based on these and other factors, we may increase or decrease our planned capital program or prioritize certain projects over others.
Revenues and Production
We expect production for 2009 to range from 4,000 to 5,000 BOE per day, with approximately 50% of that production as gas. We anticipate this decline in production from 2008 due to normal production declines and the suspension of production at three of our fields as discussed below. With development programs for Columbus, Cygnus and Rochelle, we expect significant increases in production beginning in the fourth quarter of 2010 when we anticipate the start of production at Rochelle. We anticipate Columbus and Cygnus to begin production in 2011. When all three projects are fully producing, they have the potential to equal our 2008 production levels from all other fields.
Our IVRRH, Renee and Rubie fields all produce to a single floating production facility that has experienced significant increases in operating costs in recent periods. With the decline in oil prices and the rising operating costs, the operator has decided to cease operations and begin removal and salvage procedures at that floating production facility. As a result, we expect to suspend production at these fields by the end of the first quarter 2009. The production from these fields will be suspended until the development activities at Rochelle are operational which we currently anticipate to be late 2010. After the start of Rochelle production, we expect to re-develop IVRRH, Renee and Rubie if economically feasible. We also expect to incur approximately $10 million of abandonment costs for the facility, before salvage value, by mid 2010.
Oil prices continued to be impacted by supply and demand on a worldwide basis, while natural gas prices are more impacted by regional economic and weather patterns. Oil prices continue to decrease since year-end 2008 and natural gas prices in the UK, the market for the majority of our gas production, have recovered due primarily to return to normal weather conditions. For 2009, we expect realized prices before derivatives to be $0.10 - $0.20 per Mcf less than the National Balance Point price for gas and $5.50 - $6.50 per Bbl less than the Dated Brent price for oil. We have commodity derivative instruments to secure our realized prices for a portion of our oil and gas production through 2011. See Note 16 to the Consolidated Financial Statements herein for more discussion of our commodity derivative instruments.
We expect operating costs per BOE to be in the range of $9.50 to $12.00 per BOE for 2009. Commodity prices can also affect our operating cash flow through an indirect effect on operating expenses. Significant commodity price volatility, as experienced in recent years, can lead to fluctuations in drilling and development activities. As a result, the demand and cost for people, services, equipment and materials may also increase or decrease following worldwide drilling levels, causing an impact on our cash flow.
Liquidity and Financial Resources
Our primary sources of financial resources and liquidity are internally generated cash flows from operations and access to the credit and capital markets, to the extent available. We believe the combination of our available cash on hand, cash flow from operations, our ability to time capital expenditures and our flexible 2009 capital program and related obligations will allow us to manage volatile markets while enabling us to further our strategic objectives.
We expect to fund our 2009 capital requirements through internally generated cash flow from operations. These cash flows will be significantly impacted by the amount of hydrocarbons we produce, and to a lesser extent, the price we obtain for our produced commodities. Oil prices continue to be impacted by supply and demand on a worldwide basis, while natural gas prices are more impacted by regional

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economic and weather patterns. Although oil prices have declined significantly since the record high prices in the summer of 2008, natural gas prices in the UK and Norway have not experienced as steep of a decline. While we expect revenues to decline from 2008 to 2009 as a result of the sharp decline in oil prices, the full impact on our cash flows will be partially mitigated by our balance of gas to oil production and our commodity derivative positions. As of December 31, 2008, our outstanding commodity derivatives covered 55% to 65% of expected 2009 production.
We have historically utilized a combination of borrowings under our bank facility and accessing the capital markets to fund our operations, capital projects or strategic acquisitions. The worldwide credit and capital markets have recently experience significant disruptions and exhibited adverse conditions. Continued volatility in the credit and capital markets may substantially restrict our ability to access these markets or increase costs associated with issuing debt instruments due to, among other things, increased spreads over relevant interest rate benchmarks and affect our ability to access those markets. We do not believe our liquidity has been materially affected by the recent events in the global financial markets as we have not required these financing alternatives. Further, we do not expect our liquidity to be materially impacted in the near future as we intend to exercise strict fiscal discipline in matching our future expenditures with cash flow from operations. Nevertheless, we will continue to monitor our capital requirements, the credit and capital markets and circumstances surrounding each of the lenders in our senior bank facility. To date we have experienced no disruptions in our ability to access additional funding through our senior facility. However, we cannot predict with any certainty the impact to us of any further disruption in the credit environment.
At December 31, 2008, we had $113 million outstanding under our senior bank facility. The senior bank facility has a current borrowing base capacity of $126 million, which is secured by our oil and gas assets. The borrowing base is subject to redetermination every six months (on April 1 and October 1), and we are required to provide our lenders with an independent reserve report every 12 months. Based on our reserve report at December 31 and June 30 each year, commodity prices set by our lenders and terms set forth in the credit agreement, the maximum capacity of our borrowing base is set, and any amounts outstanding over the redetermined borrowing base must be repaid within 45 days of the redetermination date. The senior bank facility is also subject to maximum commitment levels by the participating lenders that change over time.
We have reflected $13 million in current maturities of long-term debt at December 31, 2008 due to the borrowing base capacity and maximum commitment levels. The next scheduled redetermination of our borrowing base will occur on April 1, 2009. We are currently undergoing the redetermination process based on our reserve report as of December 31, 2008. We cannot estimate the level of the borrowing base capacity that will be in effect as of April 1, 2009 although we do expect the borrowing base capacity to decrease given the decline in commodity prices during 2008. We expect to repay amounts outstanding in excess of the redetermined borrowing base with cash on hand. This will reduce the amount of cash on hand that is immediately available for our capital program. Consistent with our strict financial discipline, we continue to manage our capital expenditures to stay within generated cash flows while anticipating additional debt repayments.
The terms of our credit agreement provide that the borrowing base capacity may be increased as projects are approved by the applicable authority. We currently have submitted development plans for approval for both our Cygnus and Columbus projects and anticipate submitting a plan for the Rochelle development during 2009. As these development plans are approved, we expect to include the new projects in the borrowing base assets and believe that this will result in an increase of our borrowing base capacity.

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The senior bank facility also provides for issuances of letters of credit of up to an aggregate $60 million. While all letters of credit issued under the senior bank facility will reduce the total amount available for drawing under the senior bank facility, letters of credit issued to secure abandonment liabilities in respect of borrowing base assets will not reduce the amount available under the borrowing base. As of December 31, 2008, we have $30.1 million of outstanding letters of credit related to abandonment liabilities on certain of our oil and gas properties.
In January 2008, we completed the refinancing of certain debt utilizing a strategic investment by the Smedvig Family Office in Norway. Included in this refinancing were: the repayment of our Second Lien Term Loan, plus accrued interest; issuance of $40 million under a private offering of 11.5% guaranteed convertible bonds due 2014; and borrowing of $25 million under a Junior Credit Facility. Amounts borrowed under the Junior Facility were repaid in full during 2008. The Smedvig Family also committed an additional $60 million for future investments with us.
Our income tax expense relates primarily to our operations in the UK (statutory income tax rate of 50%) and to our operations in Norway (statutory income tax rate of 78%). We are currently not able to record income tax benefits on our U.S. loss as there is no assurance that we can generate any U.S. taxable earnings. As operations commence in the U.S. during 2009, we will be able to record income tax benefits in the U.S. and do not anticipate paying current taxes in the U.S.
Off-Balance Sheet Arrangements
At December 31, 2008, we did not have any off-balance sheet arrangements.
Rig Commitments
Our rig commitments reflect two commitments for the use of drilling rigs in our North Sea operations. Our continuing operations include one commitment for the drilling rig that commenced drilling at the Rochelle field in December 2008. We have $21 million in escrow toward this commitment, included in “Restricted cash” on our Condensed Consolidated Balance Sheet. The reserved amounts in escrow will be released as payments are made for this drilling activity.
Our discontinued operations included a commitment for a semi-submersible rig in Norway through a consortium with several other operators in the Norwegian Continental Shelf. The contract committed us to 100 days (for two wells) for drilling services for $38 million. We estimated the rig to be initially delivered in the third quarter of 2009 and again in 2010.
Critical Accounting Policies and Estimates
The accompanying financial statements have been prepared on the accrual basis of accounting in accordance with accounting principles generally accepted in the United States of America and have been presented on a going concern basis, which contemplates the realization of assets and satisfaction of liabilities in the normal course of business. These accounting principles require management to use estimates, judgments and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements, and revenues and expenses during the reporting period. Management reviews its estimates, including those related to the determination of proved reserves, estimates of future dismantlement costs, income taxes and litigation. Actual results could differ from those estimates.
Management believes it is reasonably possible that the following material estimates affecting the financial statements could change in the coming year: (1) estimates of proved oil and gas reserves, (2) estimates as

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to the expected future cash flow from proved oil and gas properties, (3) estimates of future dismantlement and restoration costs, (4) estimates of fair values used in purchase accounting and (5) estimates of the fair value of derivative instruments. In addition, alternatives may exist among various accounting methods. In such cases, the choice of accounting method may also have a significant impact on reported amounts.
Our critical accounting policies are as follows:
Full Cost Accounting
Under the full cost method, all acquisition, exploration and development costs, including certain directly related employee costs and a portion of interest expense, incurred for the purpose of finding oil and gas are capitalized and accumulated in pools on a country-by-country basis. Capitalized costs include the cost of drilling and equipping productive wells, including the estimated costs of dismantling and abandoning these assets, dry hole costs, lease acquisition costs, seismic and other geological and geophysical costs, delay rentals and costs related to such activities. Employee costs associated with production and other operating activities and general corporate activities are expensed in the period incurred.
Capitalized costs are limited on a country-by-country basis (the ceiling test). The ceiling test limitation is calculated as the sum of the present value of future net cash flows related to estimated production of proved reserves, using end-of-the-current-period prices including the effect of derivative instruments that qualify as cash flow hedges, discounted at 10%, plus the lower of cost or estimated fair value of unproved properties, all net of expected income tax effects. Under the ceiling test, if the capitalized cost of the full cost pool, net of deferred taxes, exceeds the ceiling limitation, the excess is charged as an impairment expense.
We utilize a single cost center for each country where we have operations for amortization purposes. Any conveyances of properties are treated as adjustments to the cost of oil and gas properties with no gain or loss recognized unless the operations are suspended in the entire cost center or the conveyance is significant in nature.
Unproved property costs include the costs associated with unevaluated properties and properties under development and are not included in the full cost amortization base (where proved reserves exist) until the project is evaluated. These costs include unproved leasehold acreage, seismic data, wells and production facilities in progress and wells pending determination, together with interest costs capitalized for these projects. Seismic data costs are associated with specific unevaluated properties where the seismic data is acquired for the purpose of evaluating acreage or trends covered by a leasehold interest owned by us. Significant unproved properties are assessed periodically for possible impairment or reduction in value. If a reduction in value has occurred, these property costs are considered impaired and are transferred to the related full cost pool. Geological and geophysical costs included in unproved properties are transferred to the full cost amortization base along with the associated leasehold costs on a specific project basis. Costs associated with wells in progress and wells pending determination are transferred to the amortization base once a determination is made whether or not proved reserves can be assigned to the property. Costs of dry holes are transferred to the amortization base immediately upon determination that the well is unsuccessful. Unproved properties whose acquisition costs are not individually significant are aggregated, the portion of such costs estimated to be ultimately nonproductive, based on experience, are amortized to the full cost pool over an average holding period.
In countries where the existence of proved reserves has not yet been determined, unevaluated property costs remain capitalized in unproved property cost centers until proved reserves have been established, exploration activities cease or impairment and reduction in value occurs. If exploration activities result in

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the establishment of a proved reserve base, amounts in the unproved property cost center are reclassified as proved properties and become subject to amortization and the application of the ceiling test. When it is determined that the value of unproved property costs have been permanently diminished (in part or in whole) based on the impairment evaluation and future exploration plans, the unproved property cost centers related to the area of interest are impaired, and accumulated costs charged against earnings.
We capitalize interest on expenditures for significant exploration and development projects while activities are in progress to bring the assets to their intended use. Capitalized interest is calculated by multiplying our weighted-average interest rate on debt by the amount of qualifying costs and is limited to gross interest expense. As costs are transferred to the full cost pool, the associated capitalized interest is also transferred to the full cost pool.
Business Combinations
Accounting for the acquisition of a business requires the allocation of the purchase price to the various assets and liabilities of the acquired business and recording deferred taxes for any differences between the allocated values and tax basis of assets and liabilities. Any excess of the purchase price over the amounts assigned to assets and liabilities is recorded as goodwill. In connection with the several acquisitions, we recorded goodwill for the excess of the purchase price over the value assigned to individual assets acquired and liabilities assumed. Our fair value estimates for the acquisition are subject to change as additional information becomes available and is assessed.
Purchase Price Allocation
The purchase price allocation is accomplished by recording the asset or liability at its estimated fair value. We use all available information to make these fair value determinations, including information commonly considered by our engineers in valuing individual oil and gas properties and sales prices for similar assets. Estimated deferred taxes are based on available information concerning the tax basis of the acquired company’s assets and liabilities and carryforwards at the merger date, although such estimates may change in the future as additional information becomes known. The amount of goodwill recorded in any particular business combination can vary significantly depending upon the values attributed to assets acquired and liabilities assumed relative to the total acquisition cost.
Goodwill and Intangible Assets
Goodwill represents the excess of the purchase price over the estimated fair value of the assets acquired and liabilities assumed in an acquisition. Intangible assets represent the purchase price allocation to the assembled workforce as a result of the acquisition of NSNV, Inc. We assess the carrying amount of goodwill and other indefinite-lived intangible assets by testing the asset for impairment annually at year-end, or more frequently if events or changes in circumstances indicate that the asset might be impaired. The impairment test requires allocating goodwill and all other assets and liabilities to reporting units. The fair value of each reporting unit is determined and compared to the book value of the reporting unit. An impairment loss is recognized to the extent that the carrying amount exceeds the asset’s fair value.
At December 31, 2008, we had $282 million of goodwill recorded related to past business combinations. This goodwill is not amortized, but is required to be assessed for impairment annually, or more often as facts and circumstances warrant. The first step of that process is to compare the fair value of the reporting unit to which goodwill has been assigned to the carrying amount of the associated net assets and goodwill. The reporting units used to evaluate and measure goodwill for impairment are determined from the manner in which the business is managed. We have determined we have a single reporting unit. Goodwill is tested annually at year end. Although we cannot predict when or if goodwill will be

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impaired, impairment charges may occur if we are unable to replace the value of our depleting asset base or if other adverse events (for example, lower sustained oil and gas prices) reduce the fair value of the reporting unit.
We completed our 2008 annual goodwill impairment test with no impairment indicated. To determine the fair value of the company, we worked with a valuation consulting firm and used all available information, such as market multiples, the present values of expected cash flows and the effect of the announcement of drilling results (where such drilling had begun.)
In the determination of the present value of expected cash flows, we assumed production profiles consistent with our year-end estimation of reserves that are disclosed in our supplemental oil and gas disclosures, market prices considering the forward price curve for oil and gas, adjusted for location and quality differentials that we currently receive, as well as capital and operating costs consistent with year-end pricing, adjusted for management’s view that such costs should decline in the near term to realign with lower commodity prices, and discount rates that management believes a market participant would utilize to consider the risks inherent in our operations.
We also considered our market capitalization based on average stock prices for 20 days around December 31, 2008 and any premium a buyer might pay to obtain control of Endeavour. As part of this analysis, we considered the relatively few transactions in the market, trading multiples for peers to determine an appropriate multiple to apply against our projected EBITDA, cash flows and reserves and the material results of our drilling program that were not publicly available at December 31, 2008. In the first quarter of 2009, we announced the successful drilling results of wells at our Cygnus and Rochelle projects and the expansion of operations into the US. While these activities were initiated in 2008, the public markets were unaware of the positive outcomes until 2009. From December 31, 2008 through February 10, 2009 (the date of the last of these three announcements), our common stock price increased 50%, from $0.50 per share to $0.74 per share, respectively.
A lower fair value estimate in the future could result in impairment. Examples of factors that could cause a lower fair value estimate could be sustained declines in prices, increases in costs, and changes in discount rate assumptions due to market conditions.
Dismantlement, Restoration and Environmental Costs
We recognize liabilities for asset retirement obligations associated with tangible long-lived assets, such as producing well sites, offshore production platforms, and natural gas processing plants, with a corresponding increase in the related long-lived asset. The asset retirement cost is depreciated along with the property and equipment in the full cost pool. The asset retirement obligation is recorded at fair value and accretion expense, recognized over the life of the property, increases the liability to its expected settlement value. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded for both the asset retirement obligation and the asset retirement cost.
Revenue Recognition
We use the entitlements method to account for sales of gas production. We may receive more or less than our entitled share of production. Under the entitlements method, if we receive more than our entitled share of production, the imbalance is treated as a liability at the market price at the time the imbalance occurred. If we receive less than our entitled share, the imbalance is recorded as an asset at the lower of the current market price or the market price at the time the imbalance occurred. Oil revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred, title has transferred and collectibility of the revenue is probable.

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Derivative Instruments and Hedging Activities
From time to time, we may utilize derivative financial instruments to hedge cash flows from operations or to hedge the fair value of financial instruments. We may use derivative financial instruments with respect to a portion of our oil and gas production or a portion of our variable rate debt to achieve a more predictable cash flow by reducing our exposure to price fluctuations. These transactions are likely to be swaps, collars or options and to be entered into with major financial institutions or commodities trading institutions. Derivative financial instruments are intended to reduce our exposure to declines in the market prices of crude oil and natural gas that we produce and sell, to increases in interest rates and to manage cash flows in support of our annual capital expenditure budget. We also have two embedded derivatives related to our debt instruments.
We record all derivatives at fair market value in our Consolidated Balance Sheets at the end of each period. The accounting for the fair market value, and the changes from period to period, depends on the intended use of the derivative and the resulting designation. This evaluation is determined at each derivative’s inception and begins with the decision to account for the derivative as a hedge, if applicable. The accounting for changes in the fair value of a derivative instrument that is not accounted for as a hedge is included in other (income) expense as an unrealized gain or loss. Where we intend to account for a derivative as a hedge, we document, at its inception, the hedging relationship, the risk management objective and the strategy for undertaking the hedge. The documentation includes the identification of the hedging instrument, the hedged item or transaction, the nature of the risk being hedged, and the method that will be used to assess effectiveness of derivative instruments that receive hedge accounting treatment.
Changes in fair value to hedge instruments, to the extent the hedge is effective, are recognized in other comprehensive income until the forecasted transaction occurs. Hedge effectiveness is assessed at least quarterly based on total changes in the derivative’s fair value. Any ineffective portion of the derivative instrument’s change in fair value is recognized immediately in other (income) expense.
We discontinue hedge accounting prospectively when (1) we determine that the derivative is no longer effective in offsetting changes in the fair value or cash flows of a hedged item (including hedged items such as firm commitments or forecasted transactions); (2) the derivative expires; (3) it is no longer probable that the forecasted transaction will occur; (4) a hedged firm commitment no longer meets the definition of a firm commitment; or (5) management determines that designating the derivative as a hedging instrument is no longer appropriate.
Income Taxes
We use the liability method of accounting for income taxes under which deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities, and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized as part of the provision for income taxes in the period that includes the enactment date. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion of, or all of, the deferred tax assets will not be realized.

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Stock-Based Compensation Arrangements
We recognize all share-based payments to employees, including grants of employee stock options, based on their fair values. The share-based compensation cost is measured at the grant date, based on the calculated fair value of the award, and is recognized as general and administrative expense over the employee’s requisite service period (generally the vesting period of the equity award). We apply the fair value method in accounting for stock option grants to non-employees using the Black-Scholes Method.
It is our policy to use authorized but unissued shares of stock when stock options are exercised. At December 31, 2008, we had approximately 7.7 million additional shares available for issuance pursuant to our existing stock incentive plan.
Fair Value
We estimate fair value for the measurement of derivatives, long-lived assets during certain impairment tests, reporting units for goodwill impairment testing and the initial measurement of an asset retirement obligation. When we are required to measure fair value, and there is not a market observable price for the asset or liability, or a market observable price for a similar asset or liability, we generally utilize an income valuation approach. This approach utilizes management’s best assumptions regarding expectations of projected cash flows, and discounts the expected cash flows using a commensurate risk adjusted discount rate. Such evaluations involve a significant amount of judgment since the results are based on expected future events or conditions, such as sales prices; estimates of future oil and gas production; development and operating costs and the timing thereof; economic and regulatory climates and other factors. Our estimates of future net cash flows are inherently imprecise because they reflect management’s expectation of future conditions that are often outside of management’s control. However, assumptions used reflect a market participant’s view of long-term prices, costs and other factors, and are consistent with assumptions used in our business plans and investment decisions.
Recent Accounting Pronouncements
In December 2007, the FASB issued enhanced guidance related to the measurement of identifiable assets acquired, liabilities assumed and disclosure of information related to business combinations and their effect. The standard applies prospectively to business combinations in 2009 and is not subject to early adoption. We are currently evaluating the potential impact of this new guidance on business combinations and related valuations.
In December 2007, the FASB issued a new standard for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. Specifically, this statement requires the recognition of a noncontrolling interest (minority interest) as a component of consolidated equity. This is a change from the current practice to present noncontrolling interests in liabilities or between liabilities and stockholders’ equity. Similarly, the new standard requires consolidated net income and comprehensive income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interests. The standard is effective prospectively with respect to transactions involving noncontrolling financial interests that occur on or after January 1, 2009. We are currently evaluating the potential impact, if any, of this new guidance.
In March 2008, the FASB issued a new standard that requires entities to present expanded and detailed financial statement disclosures for their derivatives and hedged financial instruments. This standard applies to all derivatives and non-derivative instruments designated and qualifying as hedges, including bifurcated derivative instruments and related hedged items. The new standard is effective for interim

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periods and fiscal years beginning after November 15, 2008. We do not expect the adoption of this pronouncement to have a material impact on our financial position or results of operations.
In May 2008, the FASB posted a new staff position that applies to convertible debt that may be settled in part or in whole in cash upon conversion. The new staff position requires required issuers of this form of debt to account for its debt and equity components separately. The new position also expands the definition of convertible preferred shares of an entity’s stock that are mandatorily redeemable financial instruments classified as liabilities. The new FASB staff position is effective for financial statements issued for fiscal years after December 15, 2008 and interim period within those fiscal years. It must be applied retroactively to all presented periods. We are currently evaluating the potential impact, if any, of this new guidance.
In June 2008, the FASB issued a new staff position that addresses whether instruments that are granted in share-based payment transactions are participating securities prior to vesting; and therefore are required to be included in the earnings allocation in the calculation of earnings per share (EPS) under the two-class method as described in a prior FASB standard. The new staff position requires entities to treat unvested share-based payment awards with non-forfeitable rights to dividend or dividend equivalents as a separate class of securities in calculating EPS. The new staff position is effective for fiscal years beginning after December 15, 2008. We are currently evaluating the potential impact, if any, of this new guidance.
Disclosures about Contractual Obligations and Commercial Commitments
The following table sets forth our obligations and commitments for continuing operations to make future payments under its lease agreements and other long-term obligations as of December 31, 2008:
                                         
(Amounts in thousands)   Payments due by Period
            Less than 1            
Contractual Obligations   Total   Year   1-3 Years   3-5 Years   After 5 Years
 
Long-term debt
                                       
Principal (1)
  $ 238,746     $ 13,000     $ 100,000     $ 81,250     $ 44,496  
Interest (2)
    55,839       7,766       13,125       406       34,542  
Asset retirement obligations
    38,776       9,680       160       160       28,776  
Operating leases for office leases and equipment
    2,743       1,157       1,349       237        
Rig commitments (3)
    20,739       20,739                    
 
Total Contractual Obligations
  $ 356,843     $ 52,342     $ 114,634     $ 82,053     $ 107,814  
 
(1)   Repayment of the initial borrowing base on the senior bank facility is based on reserve estimates, which are reassessed every six months.
 
(2)   Assumes a 1.5% LIBOR rate. In addition, interest on our 11.5% convertible debt is added to the outstanding principal balance each quarter and reflected as due upon maturity.
 
(3)   As is common in the oil and gas industry, we operate in many instances through joint ventures under joint operating or similar agreements. Typically, the operator under a joint operating agreement enters into contracts, such as rig commitment contracts, for the benefit of all joint venture partners. Through the joint operating agreement, the non-operators reimburse, and in some cases advance, the funds necessary to meet the contractual obligations entered into by the operator. These obligations are typically shared on a “working interest” basis. The joint operating agreement provides remedies to the operator in the event that the non-operator does not satisfy its share of the contractual obligations. Occasionally, the operator is permitted by the joint operating agreement to enter into lease obligations and other contractual commitments that are

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Endeavour International Corporation
    then passed on to the non-operating joint interest owners as lease operating expenses, frequently without any identification as to the long-term nature of any commitments underlying such expenses.

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