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END > SEC Filings for END > Form 10-K on 18-Mar-2013All Recent SEC Filings

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Annual Report

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 Annual Report on Form 10-K contain forward-looking statements that involve risks and uncertainties. All forward-looking statements included in this Annual Report on Form 10-K are based on information available to us 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 Annual Report on Form 10-K. The following should be read in conjunction with the audited financial statements and the notes thereto included in "Item 8. Financial Statements and Supplementary Data." 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 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 our U.S. operations are spending minimal capital, primarily on strategic positioning, while we monitor U.S. gas prices. During 2012 and 2011, our primary focus has been on completing the acquisition of additional interests in both the Bacchus and Alba fields and then moving the Bacchus and Rochelle fields from development to first production. By the end of 2012, we had made progress toward those goals. We closed on the Bacchus and Alba acquisitions in 2011 and 2012, respectively, and achieved first production at Bacchus during the second quarter of 2012. Our goal for 2012 was to increase production, cash flows and proved reserves as we believe that longer-term this creates value for our shareholders. During 2012, and as a result of the above events, we:

increased production year over year by 231%;

increased proved reserves year over year in the UK by 186% and overall by 113%; and

increased production cash flows to $160.6 million.

During the third quarter of 2012, we began drilling the first of two planned development wells at Rochelle. 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 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.

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During 2010, we 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 slowing 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 Bacchus and Rochelle projects and increased debt service costs required to financing 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.

Strategic Alternatives

As discussed previously, 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 expired 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 UK North Sea production;

entered into a sale and purchase agreement (the "Sale and Purchase Agreement") for $107.5 million providing for the sale and purchase of a monetary production payment; and

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extended the maturity of approximately $100 million of the commitments under our revolving credit facility (" Revolving Credit Facility") from October 12, 2013 to June 30, 2014.

Each of these transactions are discussed in Note 24 to our consolidated financial statements in "Item 8. Financial Statements and Supplementary Data."

2013 Liquidity and Capital Resources

During 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 December 31, 2012, we had $815.0 million in outstanding indebtedness, net of $59.2 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 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

Our revenues and cash flows from operating activities are very sensitive to changes in the prices we receive for the oil and natural gas we produce. Our production is sold at prevailing market prices, which may be volatile and subject to numerous factors which are outside of our control. Further, the current tightly balanced supply and demand market means a small variation in supply or demand can significantly impact the market prices for these commodities. Our realized price per BOE, before derivatives, increased from $48.67 per BOE in 2011 to $76.07 per BOE in 2012. Our revenues increased from $60.1 million for the year ended December 31, 2011 to $219.1 million for 2012, primarily as a result of higher production volumes related to first production from Bacchus in the second quarter of 2012 and our purchase of the additional interest in Alba. Our revenues decreased from $71.7 million for the year ended December 31, 2010 to $60.1 million for 2011 primarily as a result of lower production volumes from our producing assets partially offset by higher commodity prices.

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In October 2010, we sold our interests in the Cygnus reserves in the Southern Gas Basin of the North Sea for $110 million (the "Cygnus Sale"). Upon the closing of that transaction, we recognized a gain of $87 million. The cash proceeds were not burdened by any taxes payable and were primarily used to accelerate our development projects and fund our acquisition of an additional 20% interest in the Bacchus field, which closed in February 2011.

For 2012, net loss to common stockholders was $(128.0) million, or $(3.01) per diluted share. This net loss includes a $53.1 impairment related to our U.S. properties, increased interest expense resulting from borrowings under existing debt agreements and issuances of new debt obligations and a loss on the early extinguishment of debt of $21.7 million. Net loss to common stockholders was $(133.0) million for 2011, or $(3.70) per diluted share. Net income to common stockholders for 2010 was $54.3 million, or $1.95 per diluted share, including a gain on the Cygnus Sale of $87 million.

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 $38.6 million in 2012 versus $(39.3) million in 2011 and $17.0 million in 2010. Adjusted EBITDA (as defined below) was $129.9 million in 2012, as compared to $25.1 million in 2011 and $124.8 million in 2010. These fluctuations in Adjusted EBITDA are primarily due to the changes in our production volumes, interest expense and operating costs. In addition, Adjusted EBITDA for 2010 includes the gain on the Cygnus Sale.

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 our 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, adjusted earnings before interest, taxes, depreciation, depletion and amortization ("Adjusted EBITDA") and net income as adjusted.

Net loss as adjusted for 2012 was $(54.2) million. Net loss as adjusted for 2011 was $(49.7) million, as compared to net income as adjusted of $57.4 million in 2010.

For definitions of net income as adjusted and Adjusted EBITDA, and a reconciliation of these non-GAAP measures to the appropriate GAAP measure, please see "Non-GAAP Financial Measures and Reconciliations."


Our revenues and sales volumes have fluctuated significantly during the last three years primarily due to the following:

Our revenues increased from $60.1 million for the year ended December 31, 2011 to $219.1 million for the year ended December 31, 2012, primarily due to increases in U.K. oil production from our increased interest in the Alba field and initial production from the Bacchus field.

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As a result of substantially decreased U.K. gas production from the Goldeneye field and decreases in U.S. natural gas prices, partially offset by increased oil prices, our revenues decreased from $71.7 million for the year ended December 31, 2010 to $60.1 million for the year ended December 31, 2011.

U.S. production increased from 2010 to 2011 primarily due to the results of our successful drilling and completion of wells during 2010.

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The following table shows our annual average sales volumes, sales prices and
average production costs.

                                                         Year Ended December 31,
                                                      2012         2011        2010
    Sales volume (1)
    Oil and condensate sales (Mbbls):
    United Kingdom                                     1,994          373         545
    United States                                          3            7           6

    Total                                              1,997          380         551

    Gas sales (MMcf):
    United Kingdom                                        91           94       3,071
    United States                                      5,207        5,033       2,636

    Total                                              5,298        5,127       5,707

    Oil equivalent sales (MBOE)
    United Kingdom                                     2,009          388       1,057
    United States                                        871          846         445

    Total                                              2,880        1,234       1,502

    Total BOE per day                                  7,868        3,382       4,115

    Physical production volume (BOE per day) (1):
    United Kingdom                                     5,494        1,095       2,904
    United States                                      2,379        2,319       1,221

    Total                                              7,873        3,414       4,125

    Realized Price, before and after derivatives:
    Oil and condensate price ($ per Bbl)              103.56       109.20       76.39

    Gas price ($ per Mcf)                               2.32         3.63        5.18

    Equivalent oil price ($ per BOE)                $  76.07     $  48.67     $ 47.72

    Operating Costs ($ per BOE) (2)                 $  20.33     $  14.31     $ 10.22

(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.

(2) Operating costs 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 production and production related general and administrative costs.

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

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largely impacted by local supply and demand conditions as the global transportation infrastructure for natural gas is still developing. As such, the oil we produce and sell is typically sold at prices in line with global prices, whereas our natural gas is to a large extent impacted by regional supply and demand issues and to a lesser extent by global fuel prices, including oil and coal. The 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.

Operating Expenses

For 2012, operating expenses increased to $58.5 million as compared to $17.7 million for 2011, 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 to $20.33 per BOE for 2012 from $14.31 per BOE for 2011 primarily due to the increasing portion of U.K. operations to our total expenses. In addition, 2012 operating expenses increased as a result of the sale of $9.7 million of oil inventory purchased in the Alba Acquisition. 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.

For 2011, operating expenses increased to $17.7 million as compared to $15.3 million for 2010, primarily due to increased U.S. workover expense and increases in transportation expense and production taxes as a result of increased U.S. sales volumes. Operating costs per BOE increased to $14.31 per BOE for 2011 from $10.22 per BOE for 2010. The increase in operating costs per BOE is due to the impact of both the increases in the dollar levels of operating expenses and the decreased volumes discussed above.

DD&A and Impairment of Oil and Gas Properties

Depreciation, depletion and amortization ("DD&A") expense increased from 2011 to 2012 primarily due to increased production due to our acquisition of additional interest in Alba and initial production from Bacchus. DD&A expense decreased from 2010 to 2011 as a result of impairments in oil and gas properties. DD&A per BOE was $23.11, $21.45 and $19.24 for the years ended December 31, 2012, 2011 and 2010, respectively.

In 2012, 2011 and 2010, we recorded $53.1 million, $65.7 million and $7.7 million, respectively, in impairment of oil and gas properties, pre-tax, through the application of the full cost ceiling test at the end of each quarter. The 2012 impairment was primarily related to the declines in U.S. gas prices. The 2011 impairment was primarily related to declines in U.S. gas prices and the impact of our determination that the likely economic returns in the future would not warrant further investment in our test wells in the Alabama area. Our decision to discontinue activities in that area resulted in the reclassification of related amounts as being evaluated for full cost accounting purposes.

The impairment during 2010 was also related to our U.S. oil and gas properties, pre-tax, and was primarily due to the declaration of two wells as dry holes during the first quarter of 2010.

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General and Administrative ("G&A") Expenses

Our G&A expenses increased from $17.9 million in 2011 to $21.1 million for 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 as operator and our expanding U.K. operations. The decrease in G&A expense from $18.4 million in 2010 to $17.9 million in 2011 was a result of a decrease in employee compensation expense, partially offset by an increase in consulting costs.

Non-cash stock-based compensation is comprised of expense related to grants of restricted stock and performance awards, which were granted for the first time in 2012. The restricted stock awards were valued based on the closing price of our common stock on the measurement date, typically the date of grant. The performance awards are valued on the date of grant using a Monte Carlo simulation model. In January 2012, certain of our executive officers were granted a target number of performance shares that will be earned as the relative total shareholder return ranking is measured among a designated peer group at the end of a three-year performance period. Payouts will be based on a predetermined schedule at the end of the performance period and may range from 0% to 200% of the number of performance units. See Note 13 to our consolidated financial statements in "Item 8. Financial Statements and Supplementary Data."

Components of G&A expenses for these periods are as follows:

                                                     Year Ended December 31,
     (Amounts in thousands)                    2012           2011           2010
     Compensation                            $  20,520      $  17,363      $  18,110
     Consulting, legal and accounting fees       9,160          6,461          5,843
     Other expenses                              3,299          3,600          3,888

     Total gross cash G&A expenses              32,979         27,424         27,841
     Non-cash stock-based compensation           6,036          3,697          3,692

     Gross G&A expenses                         39,015         31,121         31,533
     Less: capitalized G&A expenses            (17,930 )      (13,268 )      (13,118 )

     Net G&A expenses                        $  21,085      $  17,853      $  18,415

Interest Expense and Other

The increase in interest expense from $44.9 million in 2011 to $84.1 million in 2012 reflects the increases in interest expense that occurred as we completed several financing transactions during 2012 and 2011 that have had a significant impact on our interest expense, including the issuance of new debt facilities and the repayment of extinguished debt. Components of interest expense are as follows:

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                                                     Year Ended December 31,
    (Amounts in thousands)                      2012           2011           2010
    Interest expense on debt outstanding      $  77,128      $  10,706      $  8,461
    Interest expense on retired debt             19,701         36,664        19,794
    Amortization of loan costs and discount      14,179         12,234        10,262

    Gross interest expense                      111,008         59,604        38,517
    Less: capitalized interest                  (26,886 )      (14,711 )      (3,925 )

    Net interest expense                      $  84,122      $  44,893      $ 34,592

Each of our debt instruments and transactions are discussed in Note 9 to our consolidated financial statements in "Item 8. Financial Statements and Supplementary Data."

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Income Taxes

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

(Amounts in thousands)                         U.K.            U.S.           Other           Total
Year Ended December 31, 2012:
Net income (loss) before taxes               $ (22,959 )     $ (91,383 )     $  2,344       $ (111,998 )
Current tax expense                             31,796              -              26           31,822
Deferred tax benefit                           (26,181 )            -              -           (26,181 )
Deferred tax expense related to U.K. tax
law change                                       8,587              -              -             8,587

Total tax expense                               14,202              -              26           14,228

Net income (loss) after taxes                $ (37,161 )     $ (91,383 )     $  2,318       $ (126,226 )

Year Ended December 31, 2011:
Net income (loss) before taxes               $  (9,806 )     $ (99,409 )     $  5,281       $ (103,934 )
Current tax (benefit) expense                    5,926               4             15            5,945
Deferred tax benefit                            (4,308 )            -              -            (4,308 )
Deferred tax expense related to U.K. tax
law change                                      25,424              -              -            25,424

Total tax expense                               27,042               4             15           27,061

Net income (loss) after taxes                $ (36,848 )     $ (99,413 )     $  5,266       $ (130,995 )

Year Ended December 31, 2010:
Net income (loss) before taxes               $  90,160       $ (30,978 )     $ (3,439 )     $   55,743
Current tax (benefit) expense                    2,734              -            (154 )          2,580
Deferred tax (benefit) expense                  (2,388 )            -            (929 )         (3,317 )
Foreign currency losses on deferred tax
liabilities                                         -               -             (51 )            (51 )

Total tax (benefit) expense                        346              -          (1,134 )           (788 )

Net income (loss) after taxes                $  89,814       $ (30,978 )     $ (2,305 )     $   56,531

We currently do not record tax benefits for losses in the U.S. as there was no assurance that we could generate any U.S. taxable earnings, resulting in a full valuation allowance of all deferred tax assets generated. Therefore, our income tax expense relates primarily to our operations in the U.K. During 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%. This resulted in total tax relief available for decommissioning at 50%. As a result of this enactment, we incurred additional income tax expense of $8.6 million.

During 2011, $25.4 million of the tax expense is attributable to the increase in the supplemental corporate tax rate due to a tax law change, enacted by the U.K. . . .

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