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END > SEC Filings for END > Form 10-Q on 10-May-2013All Recent SEC Filings

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Form 10-Q for ENDEAVOUR INTERNATIONAL CORP


10-May-2013

Quarterly Report


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

The following discussion should be read in conjunction with our unaudited Condensed Consolidated Financial Statements and related notes thereto included elsewhere in this report. The following discussion also includes non-GAAP financial measures, which may not be comparable to similarly titled measures presented by other companies. Accordingly, we strongly encourage investors to review our financial statements in their entirety and not rely on any single financial measure.

Overview

We are an independent oil and gas company engaged in the production, exploration, development and acquisition of crude oil and natural gas in the U.K. North Sea and U.S. onshore. Our U.K. operations have been focused on development projects and acquisition, while we are spending minimal capital on our U.S. operations, primarily on strategic positioning, as we monitor U.S. gas prices. In 2012 and 2013, our primary focus has been on completing the acquisition of additional interests in the Alba field and then moving the Bacchus and Rochelle fields from development to first production. We achieved first production from Bacchus and completed the Alba acquisition during the second quarter of 2012.

We began drilling the first of two planned development wells at Rochelle in mid-2012. We completed the hook-up of the pipelines and flow-lines to the subsea manifolds for the field but encountered operational difficulties following severe weather in early 2013. As a result, we have suspended drilling operations on the East Rochelle well and moved the rig to the second well site at West Rochelle. While we had originally anticipated that first production at Rochelle would occur in the fourth quarter of 2012, delays in receiving the drilling rig, the operational difficulties at East Rochelle and the further estimated time to drill West Rochelle have delayed our anticipated first production until mid-2013 at the earliest.

We have acquired both producing and exploration acreage in U.S. onshore unconventional oil and gas shale developments targeting reserve and production growth. Our ongoing U.S. program and expenditures have been tailored based on drilling results and the decline in U.S. gas prices over the last several years. We have limited capital expenditures to those necessary to fulfill drilling commitments and maintain acreage positions.

In the last two years, we have incurred substantial capital expenditures and acquisition costs as we advanced development projects at Bacchus and Rochelle and completed acquisitions. We also experienced delays in the timing of first production from our Bacchus and Rochelle developments, a decline of production from our U.S. drilling operations as we curtailed the U.S. drilling program in response to declining U.S. gas prices, increased capital costs due to the production delays at the Bacchus and Rochelle projects and increased debt service costs required to finance the drilling and acquisition program. The production delays and increased capital costs and debt service costs placed a strain on our cash flow from operations and our ability to reduce our debt leverage.


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Strategic Alternatives

In February 2013, we initiated a review of strategic alternatives and will announce the results of the effort once a course of action is chosen. The primary objective of the strategic review is to accelerate the deleveraging of the balance sheet and unlock the value of our underlying assets. The Board of Directors will consider a full range of options, including:

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

a sale of specific assets;

a sale or merger of the Company; or

continuing to execute on our operational plan.

Tudor, Pickering, Holt & Co. and Lambert Energy Advisory Ltd. have been engaged as our financial advisors in this process. There is no assurance that this strategic alternatives review will result in a change to our current business plan, pursuing a particular transaction or completing any such transaction.

Since year-end 2012, we have also completed several transactions to improve our liquidity position and extended the maturities of some of our debt and other obligations. The completion of these recent financing activities are designed to provide sufficient liquidity to bring the Rochelle development on line, drill a third well at Bacchus and allow sufficient time for a thoughtful and disciplined strategic review process. These transactions include:

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

entered into a forward sale agreement for a payment of approximately $22.5 million in return for a specified volume of crude oil in excess of 200,000 barrels to be delivered over a six month delivery period from our U.K. North Sea production;

entered into a monetary production payment for $107.5 million; and

extended the maturity of the commitments under our revolving credit facility ("Revolving Credit Facility") from October 12, 2013 to June 30, 2014.

These transactions are discussed in the Notes to our condensed consolidated financial statements.

2013 Liquidity and Capital Resources

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

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

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

As of March 31, 2013, we had $795.4 million in outstanding indebtedness, net of $80.8 million in cash. Being highly leveraged, servicing our debt and other long-term obligations will continue to require a significant portion of our cash flow from operations and available cash on hand. The combination of these debt servicing requirements, capital expenditures and the delay in cash flow


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resulting from the mechanical issues experienced at the Rochelle field may exceed the cash flow from our current operations. Ultimately, our primary uses and sources of financial resources will be impacted by the outcome of our strategic review.

If we are unable to meet any short-term liquidity needs out of cash on hand, we would attempt to refinance debt, sell forward our production, sell assets, issue debt or equity, delay discretionary capital expenditures, decline to participate in non-operated drilling or perform any other alternatives resulting from our strategic review. No assurance can be given however that we could successfully consummate any of these alternatives.

Results of Operations

Net loss to common stockholders for the three months ended March 31, 2013 was $14.5 million, or $0.31 per share, compared to $35.7 million, or $0.94 per share, for the same period in 2012. The change in the net loss to common stockholders for these periods is primarily due to increased revenues related to our Bacchus field and increased unrealized gains on derivatives, partially offset by impairments of oil and gas properties, increased interest expenses, expenses related to our reimbursement agreements covering certain of our abandonment liabilities and increased tax expense.

In addition to our operations, our net income can be significantly affected by various non-cash items, such as unrealized gains and losses on our derivatives, impairment of oil and gas properties, and foreign currency impact of long-term liabilities. Excluding these non-cash items, Net Loss as Adjusted for the first quarter 2013 was $12.1 million as compared to Net Loss as Adjusted of $15.4 million for the same period in 2012. The decrease in Net Loss as Adjusted is primarily due to increased revenues, partially offset by increased interest expense and expenses related to our reimbursement agreements covering certain of our abandonment liabilities. These impacts on Net Loss as Adjusted were primarily attributable to increased sales volumes at Bacchus and the purchase of our additional interest in the Alba field.

Adjusted EBITDA increased to $44.6 million for the first quarter of 2013 from $2.2 million for the same period in 2012 due to increased revenue from the initial production at Bacchus and our additional interest in Alba, partially offset by foreign currency losses on long-term liabilities and expenses related to our reimbursement agreements covering certain of our abandonment liabilities. For definitions of Net Loss as Adjusted and Adjusted EBITDA, and a reconciliation of each to the nearest comparable GAAP measure, please see "Reconciliation of Non-GAAP Measures."

Our cash flows provided by operating activities increased to $47.6 million for the three months ended March 31, 2013 as compared to cash flows used in operating activities of $21.2 million for the same period in 2012. The change was primarily due to increased revenue from the initial production at Bacchus and our additional interest in Alba and the proceeds of the Forward Sale, partially offset by increased interest expense related to our outstanding indebtedness.


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Revenue and Sales Volume

Our physical daily production was approximately 9,385 BOE and 3,974 BOE for the three months ended March 31, 2013 and 2012, respectively, reflecting the impact of the initial production from Bacchus and our increased interest in Alba.

For the first quarter of 2013 and 2012, we had sales volume of 7,186 BOE per day and 4,174 BOE per day, respectively. The increases in sales volume are primarily attributable to the initial production from Bacchus and our increased interest in Alba.

Our revenues increased from $15.2 million during the first quarter of 2012 to $57.7 million in the same period of 2013. These increases are primarily a result of the initial production from Bacchus, partially offset by lower commodity prices in both the U.S. and U.K. and less than expected production at Alba. During the first quarter of 2013, production at the Alba field was impacted by an unplanned five-day shutdown and lower than expected production levels due to continuing processing problems.

We may utilize financial commodity derivatives and negotiated pricing in our marketing contracts to achieve a more predictable cash flow by reducing our exposure to price fluctuations. At March 31, 2013, we had the following floors and ceilings embedded within our marketing contracts:

                                              Second       Third        Fourth
                                             Quarter      Quarter      Quarter       Total
 Oil:
 Volumes (Mbbl)                                    91          276          276          643
 Weighted Average Ceiling Price ($/Barrel)   $ 105.15     $ 107.56     $ 105.30     $ 106.25
 Weighted Average Floor Price ($/Barrel)     $  90.00     $  96.01     $  95.00     $  94.73

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


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                                                         Three Months Ended
                                                              March 31,
                                                          2013          2012
        Sales volume (1)
        Oil and condensate sales (Mbbls):
        United Kingdom                                        508           96
        United States                                          -             1

        Total                                                 508           97

        Gas sales (MMcf):
        United Kingdom                                         11           21
        United States                                         821        1,677

        Total                                                 832        1,698

        Oil equivalent sales (MBOE)
        United Kingdom                                        510          100
        United States                                         137          280

        Total                                                 647          380

        Total BOE per day                                   7,186        4,174

        Physical production volume (BOE per day) (1)
        United Kingdom                                      7,862          893
        United States                                       1,523        3,081

        Total                                               9,385        3,974

        Realized Price, before and after derivatives
        Oil and condensate price ($ per Bbl)           $   108.40     $ 116.99

        Gas price ($ per Mcf)                          $     3.13     $   2.25

        Equivalent oil price ($ per BOE)               $    89.17     $  39.92

(1) We record oil revenues on the sales method and use the entitlements method to account for sales of gas production. Physical production may differ from sales volumes based on the timing of tanker liftings for our international sales.

Our revenues, profitability and cash flow depend substantially upon the prices and demand for oil and gas and are subject to numerous operational and financial risks, some of which are beyond our control. The markets for these commodities are volatile, and even relatively modest drops in prices can significantly affect our financial results and impede our growth.

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


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regional supply and demand issues and to a lesser extent by global fuel prices, including oil and coal. The U.S. gas market is heavily impacted by the increased supply from shale drilling, which has served to depress natural gas prices relative to the U.K. market.

Expenses

For the first quarter of 2013, operating expenses increased to $17.5 million as compared to $4.9 million for the same period in 2012 primarily due to costs related to our increased interest in the Alba field and initial production from the Bacchus field.

Operating costs per BOE increased from $12.89 per BOE for the first quarter of 2012 to $27.04 per BOE for the same period in 2013 primarily due to the increasing portion of U.K. operations to our total expenses and the lesser sales volumes resulting from the lack of liftings at Alba during the first quarter of 2013. On average, our U.K. operations have higher operating costs per BOE than our U.S. operations, thereby increasing our overall operating costs per BOE as more of our production comes from the U.K.

Depreciation, depletion and amortization ("DD&A") expense increased to $22.9 million from $7.9 million for the first quarter of 2013 and 2012, respectively. These increases were primarily a result of the increased sales volumes discussed previously and additional accretion expense related to the increased abandonment liabilities assumed upon the closing of the Alba field acquisition.

For the first quarter of 2013, the prices used in the full cost ceiling test for our U.S. properties were $92.63 per barrel for oil and $2.97 per Mcf for gas. We recorded an impairment of $3.5 million during the first quarter of 2013 for our U.S. properties. For the first quarter of 2013, the prices used in the full cost ceiling test for our U.K. properties were $110.49 per barrel for oil and $9.71 per Mcf for gas. We have not recorded any impairment related to our U.K. properties. The risk that we will be required to record additional impairments of our oil and gas properties, through the application of the full cost ceiling test in subsequent periods, increases when oil and gas prices are low or volatile. If U.S. gas prices continue to face the adverse effects of high gas supply or other factors, we may experience further ceiling test write-downs or other impairments in the future.

General and administrative ("G&A") expenses increased slightly to $5.5 million during the first quarter of 2013 as compared to $5.3 million for the corresponding period in 2012 as a result of an increase in employee compensation expense and an increase in consulting costs associated with the additional staff to pursue the Rochelle development. Components of G&A expenses for these periods are as follows:


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                                                     Three Months Ended
           (Amounts in thousands)                         March 31,
                                                     2013           2012
           Compensation                            $   6,391      $  5,198
           Consulting, legal and accounting fees       2,569         1,773
           Other expenses                               (113 )       1,073

           Total gross cash G&A expenses               8,847         8,044
           Non-cash stock-based compensation           1,690         1,559

           Gross G&A expenses                         10,537         9,603
           Less: capitalized G&A expenses             (5,055 )      (4,280 )

           Net G&A expenses                        $   5,482      $  5,323

Interest expense increased by $1.7 million to $21.4 million for the first quarter of 2013 as compared to $19.7 million for the corresponding period in 2012. For the period ending March 31, 2013 and 2012, we had non-cash interest expense, including amortization of loan costs and discount, of $5.7 million and $7.2 million, respectively.

As discussed in "Liquidity and Capital Resources," we have completed several financing transactions during 2013 and 2012 that have had a significant impact on our interest expense. Interest expense has increased with the issuance and subsequent borrowings from the April 2012 Revolving Credit Facility, and the 2018 Notes in February 2012. This increase has been partially offset by our repayment of the Senior Term Loan in May 2012 and the Subordinated Notes in October 2012. In addition, we capitalize a portion of interest as a result of our increased drilling activity at Bacchus and Rochelle. The components of interest expense are as follows:

                                                             Three Months Ended
  (Amounts in thousands)                                          March 31,
                                                             2013           2012
  Interest expense on debt outstanding at March 31, 2013   $  24,172      $  9,977
  Interest expense on retired debt                                -         11,586
  Amortization of loan costs and discount                      3,439         3,669

  Gross interest expense                                      27,611        25,232
  Less: capitalized interest                                  (6,173 )      (5,525 )

  Net interest expense                                     $  21,438      $ 19,707

Other income (expense) increased to $9.9 million during the first quarter of 2013 as compared to $(2.7) million for the corresponding period in 2012. The changes in other income (expense) are primarily attributable to the effects of foreign currency fluctuations on our abandonment liabilities.

Income Taxes

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


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 (amounts in thousands)                 U.K.           U.S.          Other          Total
 Three Months Ended March 31, 2013:
 Net income (loss) before taxes       $   1,341      $ (14,874 )    $    396      $ (13,137 )
 Current tax expense                        781             -             -             781
 Deferred tax expense                       128             -             -             128

 Income tax expense                         909             -             -             909

 Net income (loss)                    $     432      $ (14,874 )    $    396      $ (14,046 )

 Three Months Ended March 31, 2012:
 Net loss before taxes                $ (14,659 )    $ (24,681 )    $ (6,515 )    $ (45,855 )
 Current tax benefit                     (1,579 )           -             -          (1,579 )
 Deferred tax benefit                    (9,014 )           -             -          (9,014 )

 Income tax benefit                     (10,593 )           -             -         (10,593 )

 Net loss                             $  (4,066 )    $ (24,681 )    $ (6,515 )    $ (35,262 )

During July 2012, the U.K. government enacted legislation (retroactive to March 2012) to restrict decommissioning expenditures to 20% for supplemental corporate tax, in addition to the U.K. corporate tax of 30%, resulting in total tax relief available for decommissioning at 50%.

The change in income tax expense (benefit) from $(10.6) million to $0.9 million for the three months ended March 31, 2012 and 2013, respectively, was primarily the result of increased income in the U.K. due to the initial production from Bacchus and our increased interest in Alba. The current tax expense (benefit) in both 2013 and 2012 is related to Petroleum Revenue Tax on our Alba field in the U.K.

In 2013 and 2012, we did not record any income tax benefits in the U.S. as there was no assurance that we could generate any U.S. taxable earnings, resulting in a full valuation allowance against the deferred tax assets generated.

Reconciliation of Non-GAAP Measures

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


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

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

                                                             Three Months Ended
  (amounts in thousands)                                         March 31,
                                                            2013           2012
  Net loss                                                $ (14,046 )    $ (35,262 )
  Impairment of oil and gas properties (net of tax) (1)       3,534         15,740
  Unrealized loss on derivatives (net of tax) (2)            (1,580 )        4,148

  Net Loss as Adjusted                                    $ (12,092 )    $ (15,374 )

  Net loss                                                $ (14,046 )    $ (35,262 )
  Unrealized loss on derivatives                             (1,580 )        4,779
  Net interest expense                                       21,422         19,651
  Letter of credit fees                                      11,380             -
  Depreciation, depletion and amortization                   22,947          7,906
  Impairment of oil and gas properties                        3,534         15,740
  Income tax expense (benefit)                                  909        (10,593 )

  Adjusted EBITDA                                         $  44,566      $   2,221

(1) Since the impairments related to U.S. oil and gas properties, we recognized no tax benefits as there was no assurance that we could generate any U.S. taxable earnings.

(2) Net of tax (benefit) expense of none and $631, respectively.

Liquidity and Capital Resources

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


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(amounts in thousands)                                      Three Months Ended March 31,
                                                            2013                   2012
Net cash provided by (used in) operating activities     $      47,605         $       (21,153 )

Net cash used in investing activities                   $     (59,074 )       $      (524,693 )
. . .
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