Unless the context otherwise requires, references to "Endeavour," "we," "us" or "our" mean Endeavour International Corporation or any of our consolidated subsidiaries or partnership interests. 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.

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.

As oil prices continue to climb to record levels and gas prices in our markets have recovered from last year, our realized price before derivatives increased over 60% from the first quarter of 2007 to the first quarter of 2008. This substantial increase in prices helped revenue grow from $42.8 million in the first three months of 2007 to $61.3 million in the same period of 2008. By keeping cash expenses reasonably flat from 2007 to 2008, the cash flow from this higher revenue allowed us to pay down an additional $2.0 million in debt while spending $19.6 million in capital expenditures during the first quarter of 2008 and increasing cash from year end by $4.0 million. At March 31, 2008, we held $20.5 million in cash and another $22.0 million in cash restricted for drilling rig commitments.

Even with the substantial growth in revenue, 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. Net loss to common shareholders for the first three months of 2008 was $19.5 million, or $0.15 per share, reflecting the significant unrealized loss on the mark-to-market of commodity derivatives. For the first three months of 2007, net loss to common shareholders was $6.0 million, or $0.05 per share. The net loss for 2007 reflects a smaller unrealized loss on the mark-to-market of commodity derivatives. Net loss as adjusted for 2008 would have been $2.0 million, or $0.02 per share without the effect of derivative transactions and currency impacts of deferred taxes as compared to net income as adjusted of $3.0 million, or $0.03 per share, in 2007. Net loss and net loss as adjusted for 2008 include $4.3 million in interest expense, including $2.1 million in cash, related to the early repayment of the Second Lien Term Loan. Adjusted EBITDA increased to $42.6 million in 2008 from $37.2 million in 2007.

Discretionary cash flow was $36.3 million for the first three months of 2008 compared to $34.4 million for the same period in 2007, reflecting the increase in revenues over the periods. Cash flows provided by operating activities decreased to $29.1 million for the three months ended

March 31, 2008 as compared to $46.3 million for the three months ended March 31, 2007 primarily due to decreases in net cash provided by changes in operating assets and liabilities partially offset by higher commodity prices.

Results of Operations

Our revenues are sensitive to changes in prices received for our products. Our production is sold at prevailing market prices that 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 has a limited global transportation system, is subject to local supply and demand conditions. Consequently, price movements for all types and grades of crude oil generally move in the same direction, while natural gas price movements have historically followed local market conditions. The majority of our natural gas is sold in the UK market. UK natural gas prices are influenced by European natural gas markets, liquefied natural gas ("LNG") supply and new Norwegian gas supply. With the advent of more LNG facilities, natural gas price movements will also become more global in nature with a likely convergence between European and North American markets.

For the first quarter of 2008 and 2007, we had sales volume of 8,800 BOE per day and 10,150 BOE per day, respectively. Our physical daily production was approximately 10,100 BOE and 9,800 BOE for 2008 and 2007, respectively. The decrease in sales volume is primarily attributable to timing of tanker liftings partially offset by production from Enoch (which recorded first sales in the third quarter of 2007) and the contribution of the gas from the completion of the gas project at Njord in the fourth quarter of 2007. Even with the delay in tanker liftings for the first quarter of 2008, we still expect full year 2008 production to range from 8,600 to 9,000 BOE per day.

The following table shows our average sales volumes, sales prices and average production costs for the periods presented.

                                    Quarter Ended March 31,
                                      2008           2007

Sales volume (1):
Oil and condensate sales (Mbbl):
United Kingdom                            265             397
Norway                                     96             131
Total                                     361             528

Gas sales (MMcf):
United Kingdom                          2,035           2,259
Norway                                    599              54
Total                                   2,634           2,313

Total sales (MBOE):
United Kingdom                            604             773
Norway                                    196             140
Total                                     800             913

BOE per day                             8,796          10,148




Realized Prices (2):
Oil and condensate price ($per Bbl):
Before commodity derivatives                      $  89.84   $ 53.54
Effect of commodity derivatives                   $ (17.57 ) $  5.96
Realized prices including commodity derivatives   $  72.27   $ 59.50

Gas price ($per Mcf):
Before commodity derivatives                      $  10.93   $  6.28
Effect of commodity derivatives                   $   1.22   $  3.43
Realized prices including commodity derivatives   $  12.15   $  9.71

Equivalent oil price ($per BOE):
Before commodity derivatives                      $  76.53   $ 46.85
Effect of commodity derivatives                   $  (3.94 ) $ 12.12
Realized prices including commodity derivatives   $  72.59   $ 58.97

method to account for sales of gas production. Our physical daily production was approximately 10,100 BOE and 9,800 BOE for 2008 and 2007, respectively.

(2) The average sales prices include gains and losses for derivative contracts we utilize to manage price risk related to our future cash flows.

During the three months ended March 31, 2008, we realized $3 million in losses on the settlement of commodity derivatives, compared to $11 million in gains for the same period in 2007. In the first quarter of 2008, we also recognized $30 million in losses on the mark-to-market of our commodity derivatives versus a loss of $16 million for the same period in 2007.

Expenses

Operating expenses decreased to $10.0 million during the first quarter of 2008 as compared to $10.7 million in the first quarter of 2007. Operating costs per BOE decreased from $11.73 per BOE in the first quarter of 2007 to $12.52 per BOE in the first quarter of 2008.

G&A expenses decreased to $4.8 million during the first quarter of 2008 as compared to $5.4 million for the corresponding period in 2007. This decrease resulted from changes in non-cash stock-based compensation as a result of current year forfeitures and lower consulting fees. The decreases were partially offset by increases resulting from compensation expense, and occupancy costs. The compensation expense increase reflects salary expense related to increases in staffing and $0.2 million related to retiring employees. Components of G&A expenses for these periods are as follows:

                                           Three Months Ended March 31,
(Amounts in thousands)                       2008                2007

Compensation                            $         4,937     $         4,188
Consulting, legal and accounting fees             1,111               1,400
Other expenses                                      198                 149
Total gross cash G&A expenses                     6,246               5,737

Non-cash stock-based compensation                   544               1,877
Gross G&A expenses                                6,790               7,614
Less: capitalized G&A expenses                   (2,039 )            (2,247 )
Net G&A expenses                        $         4,751     $         5,367

Interest expense increased to $8.2 million for the three months ended March 31, 2008 as compared to $4.8 million for the corresponding period in 2007 and is primarily associated with our early retirement of the Second Lien Term Loan of $4.3 million.

Income Taxes



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



(Amounts in thousands)              UK         Norway       U.S.       Other        Total
Three Months Ended March 31,
2008
Net income (loss) before
taxes                            $ (19,565 )  $  7,925    $ (2,312 )  $ (2,370 )  $ (16,322 )

Current tax expense                  1,470       2,144           -           -        3,614
Deferred tax expense
(benefit)                          (10,230 )     4,323           -         122       (5,785 )
Foreign currency losses on
deferred tax liabilities                11       2,630           -           -        2,641
Total tax expense (benefit)         (8,749 )     9,097           -         122          470

Net income (loss) after taxes    $ (10,816 )  $ (1,172 )  $ (2,312 )  $ (2,492 )  $ (16,792 )

Three Months Ended March 31,
2007
Net income (loss) before
taxes                            $    (468 )  $    887    $ (2,616 )  $    344    $  (1,853 )

Current tax expense (benefit)        1,653        (620 )        (3 )         -        1,030
Deferred tax expense
(benefit)                           (2,307 )     1,330           -           -         (977 )
Foreign currency losses on
deferred tax liabilities               660         577           -           -        1,237
Total tax expense                        6       1,287          (3 )         -        1,290

Net income (loss) after taxes    $    (474 )  $   (400 )  $ (2,613 )  $    344    $  (3,143 )

The change in income tax expense from a $1.3 million to $0.5 million for the first three months of 2007 and 2008, respectively, is primarily the result of higher deferred tax benefits on increased unrealized losses on derivatives, partially offset by increased income resulting from higher commodity prices and the effect of foreign currency changes on the deferred tax liabilities as a result of the strengthening of the Norwegian kroner versus the U.S. dollar.

In the first quarter of 2008 and 2007, 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 of deferred tax assets generated.

As our deferred tax liabilities 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 as shown above.

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, 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, generally accepted accounting principles (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 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.

                                                               Three Months Ended March 31,
(in thousands, except per share)                                  2008               2007
Net loss                                                    $        (16,792 )  $       (3,143 )

Depreciation, depletion and amortization                              21,403            19,213
Deferred tax expense (benefit)                                        (3,144 )             261
Unrealized (gain) loss on instruments                                 29,642            15,696
Amortization of non-cash compensation                                    544             1,884
Amortization of loan costs and discount                                3,156               427
Non-cash interest expense                                                869                 -
Other                                                                    632                15

Discretionary cash flow                                     $         36,310    $       34,353

Net income (loss) to common shareholders, as reported       $        (19,487 )  $       (5,987 )
Unrealized (gains) losses on derivatives (net of 50%
tax)                                                                  14,821             7,848
Currency impact of deferred taxes                                      2,641             1,237

Net income (loss), as adjusted                              $         (2,025 )  $        3,098

Weighted average number of common shares outstanding -
basic and diluted                                                    125,537           120,304

Earnings per share, as adjusted                             $          (0.02 )  $         0.03

                                                               Three Months Ended March 31,
(in thousands, except per share)                                  2008               2007

Net income (loss) to common shareholders, as reported       $        (19,487 )  $       (5,987 )

Unrealized (gains) losses on derivatives                              29,642            15,696
Net interest expense                                                   7,841             4,169
Depreciation, depletion and amortization                              21,403            19,213
Income tax expense (benefit)                                             470             1,290
Preferred stock dividends                                              2,695             2,844

Adjusted EBITDA                                             $         42,564    $       37,225

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.

                                              For the Quarter Ended March 30,
(Amounts in thousands)                            2008                2007

Net cash provided by Operating Activities   $         29,140    $         46,311
Net cash used in Investing Activities       $        (19,581 )  $        (33,576 )
Net cash provided by Financing Activities   $         (5,540 )  $        (30,110 )

The net cash flows provided by (used in) operating activities are primarily impacted by the earnings from our business activities. The cash flows provided by operating activities decreased to $29.1 million for the three months ended March 31, 2008 as compared to $46.3 million for the three months ended March 31, 2007 primarily due to decreases in cash flows used by changes in net operating assets and liabilities partially offset by higher commodity prices.

The cash used in investing activities represents expenditures for capital projects and asset purchases, as discussed in "Drilling Program" below, and increases to restricted cash under escrow for our rig commitments for 2007. The cash provided by (used in) financing activities generally consists of borrowings and repayments of debt, proceeds from the issuance of equity securities and payment of financing costs.

In January 2008, we completed the refinancing of certain debt with the following:

† Repayment of the outstanding balance of $75 million under our Second Lien Term Loan, plus accrued interest;
† Issuance of $40 million under a private offering of 11.5% guaranteed convertible bonds to a company controlled by the Smedvig Family Office of Norway; and

† Issuance of $25 million under a junior credit facility.

The $40 million Convertible Bonds due 2014 bear interest at a rate of 11.5% per annum, compounded quarterly, and are unconditionally guaranteed by us on a senior unsecured basis. Interest is compounded quarterly and added to the outstanding principal balance each quarter. Interest is not payable in cash, but is instead payable in kind upon maturity of the bonds.

We also borrowed $25 million under the Junior Facility. Indebtedness under the Junior Facility bears interest at LIBOR plus 3.5% (plus 5.5% after the first year). Amounts borrowed under the Junior Facility will be repaid in semi-annual payments beginning December 31, 2009 and must be repaid in full in October 2011.

Outstanding loans under the Junior Facility may be prepaid at our option without penalty after the earlier of (i) the day after the period extending from January 22, 2008 to and including one month after the Effective Date (as defined in the Junior Facility) or (ii) the day on which the lenders' available commitments are reduced to zero. Once repaid, amounts under the Junior Facility may not be re-borrowed. The Junior Facility contains customary covenants, which limit our ability to incur indebtedness, except for permitted hedging arrangements; create certain liens; dispose of our assets and make dividend or other distribution with respect to equity securities. In addition, the Junior Facility contains various financial and technical covenants.

The amounts outstanding under the Junior Facility may become immediately due upon the occurrence of a change of control, failure to pay obligations under other financial indebtedness when due, certain events of default, breach of financial covenants and other events as defined in the agreement.

Simultaneously with entering into the Junior Facility and issuing the Convertible Bonds, discussed above, we terminated the Second Lien Term Loan and repaid all of the $78.6 million in outstanding indebtedness including accrued interest, related fees and expenses of approximately $4.3 million. The amount outstanding under the Second Lien Term Loan was scheduled to mature in 2011.

Drilling Program

We anticipate spending approximately $90 million during 2008 to fund oil and gas exploration and development in the North Sea. An estimated $40 million will be allocated to drilling at least five exploration prospects in the North Sea. Approximately 60 percent of this exploration budget will be spent in Norway with the balance dedicated to drilling in the UK.

In Norway, the Galtvort well began drilling in April 2008 and is a near-field prospect operated by StatoilHydro Petroleum AS in which we have a 7.5 percent interest in the well. We will also participate in the drilling of three other exploration wells on the Norwegian Continental Shelf as part of our 2008 drilling campaign. We will operate our first well in Norway with the drilling of the Jade well, in which Endeavour holds a 65 percent interest. The area is the site of the two Agat natural gas discoveries and the test will set out to identify additional reserves in support of commercial development. The other two wells include the Noatun C, a prospect in north of the

Njord field, and the Brage North, an exploration target in the Brage field. We hold a 2.5 and 4.44 percent interest, respectively, in the blocks.

We plan to drill three exploration and appraisal wells and one development well in the United Kingdom sector of the North Sea during the second half of this year. The Tesla exploration well on Block 22/24c will test for hydrocarbons in one of our primary areas of focus. We hold a 25 percent interest in the license. We also plan to drill a well to further appraise the Cygnus discovery, in which we hold a 12.5 percent interest. Another appraisal well is planned on the Rochelle discovery in which we hold a 55.6% interest. We are scheduled to drill and operate a development well on one of the two R blocks, Renee and Rubie, later this year.

The timing and order of this program will be determined by the completion of ongoing technical work, partner approvals and rig scheduling for individual prospects. We may increase or decrease our planned activities for 2008 or high grade our exploratory prospects, depending upon drilling results, potential acquisition candidates, product prices, the availability of capital resources and other factors affecting the economic viability of such activities. We believe we have a production base that generates significant cash flow to fund our future growth plans and ongoing operations.

In March, we were awarded interests in two production licenses on the Norwegian Continental Shelf, a 25 percent interest in PL453S and a 20 percent interest in PL457. Total acreage for the two awards approximates 538,000 acres, which . . .