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END > SEC Filings for END > Form 10-Q on 9-Aug-2013All Recent SEC Filings

Show all filings for ENDEAVOUR INTERNATIONAL CORP

Form 10-Q for ENDEAVOUR INTERNATIONAL CORP


9-Aug-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 our U.S. operations have focused primarily on strategic positioning and new reservoir plays. 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 suspended drilling operations on the East Rochelle well and moved the rig to the second well site at West Rochelle. The West Rochelle well was completed and flow tested at the end of June 2013. During a 56-hour flow test, the well flowed up to 60 million standard cubic feet per day, which was the limit of the well test equipment on the drilling rig. Final installation of the subsea pipeline infrastructure has been completed and the well is connected back to the Scott Platform. First production from the West Rochelle well is expected in September 2013 following the completion of the annual maintenance period at the Scott Platform.

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 Bacchus and Rochelle developments, a decline of production from our U.S. drilling operations as we curtailed U.S. capital expenditures 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


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costs and debt service costs placed a strain on our cash flow from operations and our ability to reduce our debt leverage.

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 is considering 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 from our U.K. North Sea production, which was fully delivered by June 30, 2013;

entered into a monetary production payment for $125 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.


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As of June 30, 2013, we had $747.5 million in outstanding indebtedness, net of $130.8 million in cash. Being highly leveraged, required development capital expenditures, debt service 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.

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 six months ended June 30, 2013 was $28.8 million, or $0.61 per share, compared to $87.0 million, or $2.26 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 the purchase of our additional interest in the Alba field, lower impairments of oil and gas properties and the loss on early extinguishment of debt in 2012, partially offset by increased income tax expense and expenses related to 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 second quarter 2013 was $12.6 million as compared to Net Loss as Adjusted of $17.4 million for the same period in 2012. The decrease in Net Loss as Adjusted is primarily due to increased revenues, partially offset by increased income tax 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 $82.2 million for the second quarter of 2013 from $11.5 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 $71.6 million for the six months ended June 30, 2013 as compared to cash flows used in operating activities of $(28.1) million for the same period in 2012. The change was primarily due to increased revenue from the initial


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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.

Revenue and Sales Volume

Our physical daily production was 9,498 BOE and 6,437 BOE for the second quarter of 2013 and 2012, respectively, and 9,427 BOE and 5,205 BOE for the six months ended June 30, 2013 and 2012, respectively, reflecting the impact of the initial production from Bacchus and our increased interest in Alba.

For the second quarter of 2013 and 2012, we had sales volume of 14,497 BOE per day and 4,677 BOE per day, respectively. For the six months ended June 30, 2013 and 2012, we had sales volume of 10,862 BOE per day and 4,426 BOE per day, respectively. The increases in sales volume were primarily attributable to the initial production from Bacchus and our increased interest in Alba.

Our revenues increased from $23.0 million during the second quarter of 2012 to $126.2 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.

We record oil revenues when deliveries have occurred and legal ownership of the oil transfers to the customer. While certain of our U.K. oil fields produce into pipelines and thereby allow us to record revenue each month, the remaining fields, including the Alba field, are dependent upon tanker liftings to deliver oil production to the buyers. For certain of our U.K. fields, including the Alba field, we sell production on a monthly basis, although the production remains in the field's storage tanks until the tanker lifting. The inventory associated with these sales remains on our balance sheet and the revenue is deferred until the production is shipped out of our storage tanks. 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. The lower production levels during the first quarter of 2013 delayed the tanker lifting until the second quarter. As a result, we had two tanker liftings at Alba during the second quarter of 2013. The May 31, 2012 closing of the Alba field portion of the COP Acquisition did not allow sufficient time for our production at the field to satisfy a full tanker lifting. While the timing of tanker liftings affect when we record revenue from Alba, physical production and cash receipts are unaffected.

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 June 30, 2013, we had the following floors and ceilings embedded within our marketing contracts:


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Endeavour International Corporation

Third Quarter Fourth Quarter Total
Oil:
Volumes (Mbbl) 276 276 552 $ $ $ Weighted Average Ceiling Price ($/Barrel) 107.56 105.30 106.43 $ $ $ Weighted Average Floor Price ($/Barrel) 96.01 95.00 95.51

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

                                      Three Months Ended           Six Months Ended
                                           June 30,                    June 30,
                                       2013         2012          2013          2012
Sales volume (1)
Oil and condensate sales (Mbbls):
United Kingdom                         1,205          191         1,713           287
United States                              1            1             1             2
Total                                  1,206          192         1,714           289

Gas sales (MMcf):
United Kingdom                            15           30            26            51
United States  (2)                       667        1,375         1,489         3,052
Total                                    682        1,405         1,515         3,103

Oil equivalent sales (MBOE)
United Kingdom                         1,207          196         1,717           295
United States  (2)                       112          230           249           510
Total                                  1,319          426         1,966           805

Total BOE per day                     14,497        4,677        10,862         4,426

Physical production volume (BOE
per day) (1)
United Kingdom                         8,083        3,910         7,973         2,401
United States  (2)                     1,415        2,527         1,454         2,804
Total                                  9,498        6,437         9,427         5,205

Realized Price, before and after
derivatives
Oil and condensate price ($ per
Bbl)                               $  102.67     $ 104.46      $ 104.37     $  108.67
Gas price ($ per Mcf)              $    3.50     $   2.14      $   3.30      $   2.20
Equivalent oil price ($ per BOE)   $   95.64     $  54.05      $  93.51     $   47.39

(1) We record oil revenues when deliveries have occurred and legal ownership of the oil transfers to the customer. Physical production may differ based on the timing of tanker liftings for international sales.

(2) In October 2012, we completed an exchange with domestic co-venturer, J-W Operating Company ("J-W"), whereby we exchanged our Bull Bayou Haynesville and Willow


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Springs Cotton Valley properties for all of J-W's upstream and midstream interests in the Pennsylvania Marcellus area. The transaction added 15,500 net acres to our position in the Marcellus area, bringing the total to 31,000 net acres, and decreased our position in the Haynesville area by 2,100 net acres and approximately 3.2 MMcf equivalent per day (530 BOE per day) of declining net production.

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 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 second quarter of 2013, operating expenses increased to $38.1 million as compared to $5.7 million for the same period in 2012. For the six months ended June 30, 2013 and 2012, operating expenses were $55.6 million and $10.6 million, respectively. These increases were 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 $13.49 per BOE for the second quarter of 2012 to $28.88 per BOE for the same period in 2013 primarily due to the increasing portion of U.K. operations contributing to our total expenses. 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 $51.9 million from $10.6 million for the second quarter of 2013 and 2012, respectively, and to $74.9 million from $18.5 million for the six months ended June 30, 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.

We did not record an impairment during the second quarter of 2013. For the second quarter of 2013, the prices used in the full cost ceiling test for our U.S. properties were $91.60 per barrel for oil and $3.46 per Mcf for gas. For the second quarter of 2013, the prices used in the full cost


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ceiling test for our U.K. properties were $107.58 per barrel for oil and $10.24 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 decreased slightly to $4.9 million during the second quarter of 2013 as compared to $5.0 million for the corresponding period in 2012 as a result of a decrease in employee compensation expense. Components of G&A expenses for these periods are as follows:

(Amounts in thousands)                      Three Months Ended           Six Months Ended
                                                 June 30,                    June 30,
                                            2013           2012         2013          2012
Compensation                            $   4,597       $  5,308     $ 10,988      $ 10,506
Consulting, legal and accounting fees       2,369          2,331        4,938         4,105
Amounts recovered from joint interest
partners                                   (3,967)        (1,043)      (5,054)       (1,733)
Other expenses                              2,149          1,738        3,122         3,501
Total gross cash G&A expenses               5,148          8,334       13,994        16,379

Non-cash stock-based compensation           1,517          1,556        3,207         3,114
Gross G&A expenses                          6,665          9,890       17,201        19,493
Less: capitalized G&A expenses             (1,783)        (4,860)      (6,837)       (9,140)
Net G&A expenses                        $   4,882       $  5,030     $ 10,364      $ 10,353

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 as a result of borrowings under the Revolving Credit Facility, and the issuance of 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:

(Amounts in thousands)                      Three Months Ended        Six Months Ended
                                                 June 30,                 June 30,
                                             2013        2012         2013         2012
Interest expense on debt outstanding
at June 30, 2013                           $ 26,781    $ 20,820    $  50,954    $  30,796
Interest expense on retired debt                   -      7,120             -      18,707
Amortization of loan costs and discount       5,257       3,642        8,695        7,311
Gross interest expense                       32,038      31,582       59,649       56,814

Less: capitalized interest                   (7,591)     (6,326)     (13,764)     (11,851)

Net interest expense                       $ 24,447    $ 25,256    $  45,885    $  44,963


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Interest expense decreased slightly to $24.4 million for the second quarter of 2013 as compared to $25.3 million for the corresponding period in 2012, primarily due to increased capitalized interest associated with our drilling activities at Rochelle. For the three months ending June 30, 2013 and 2012, we had non-cash interest expense, including amortization of loan costs and discount, of $12.1 million and $12.5 million, respectively.

Letter of credit fees were $7.1 million, $3.1 million, $18.5 million and $3.1 million for the second quarter of 2013 and 2012 and the six months ended June 30, 2013 and 2012, respectively. The letter of credit fees are expenses related to our reimbursement agreements covering certain of our abandonment liabilities. The increases in letter of credit fees were primarily due to the reimbursement agreement issued upon our acquisition of additional interest in Alba.

Other income (expense) increased to $8.9 million during the six months ended June 30, 2013 as compared to $(3.3) 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):

(amounts in thousands)             U.K.         U.S.        Other        Total
Six Months Ended June 30, 2013:
Net income (loss) before taxes  $  10,139    $ (22,761)   $ (3,121)   $  (15,743)

Current tax expense (1)            14,646             -           -       14,646
Deferred tax benefit               (2,457)            -           -       (2,457)
Income tax expense                 12,189             -           -       12,189

Net loss                        $  (2,050)   $ (22,761)   $ (3,121)   $  (27,932)

Six Months Ended June 30, 2012:
Net loss before taxes           $ (52,449)   $ (56,462)   $ (2,089)   $ (111,000)

Current tax benefit (1)              (921)            -           -         (921)
Deferred tax benefit              (24,008)            -           -      (24,008)
Income tax benefit                (24,929)            -           -      (24,929)

Net loss                        $ (27,520)   $ (56,462)   $ (2,089)   $  (86,071)

(1) The current tax expense (benefit) in both 2013 and 2012 is related to Petroleum Revenue Tax on our Alba field in the U.K.


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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 $(24.9) million to $12.2 million for the six months ended June 30, 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.

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.

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 . . .

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