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END > SEC Filings for END > Form 10-Q on 12-Nov-2013All Recent SEC Filings

Show all filings for ENDEAVOUR INTERNATIONAL CORP

Form 10-Q for ENDEAVOUR INTERNATIONAL CORP


12-Nov-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. In October 2013, we achieved first production from the Rochelle field.

In the U.S., we have acquired both producing and exploration acreage in 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 as we prioritized capital to complete our U.K. projects.

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 our drilling program and acquisitions.

Strategic Alternative Process

In February 2013, we initiated a review of strategic alternatives. The primary objective of the strategic review was to accelerate the deleveraging of the balance sheet and unlock the value of our underlying assets. The strategic review was concluded in October 2013. The Board of Directors determined that it was in the best interest of our shareholders to retain and exploit our existing asset base, while initiating several organizational changes and cost-saving initiatives.


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Our U.K. operations will be consolidated in Aberdeen, Scotland; our London office closed; and several key personnel will be re-aligned internally.

Since year-end 2012, we have also completed several transactions to improve our liquidity 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, and drill a third well at Bacchus. 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 first 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 each from our U.K. North Sea production, that was fully delivered by June 30, 2013;

entered into a second 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, to be delivered over a six month delivery period;

entered into a monetary production payment for $150 million;

entered into a purchase and sale agreement for the joint exploration, development, and operation of certain oil and gas properties in Pennsylvania; 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 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 September 30, 2013, we had $820.1 million in outstanding indebtedness, net of $60.4 million in cash. Because we are 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 cause our cash needs to 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.


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Results of Operations

Net loss to common stockholders for the nine months ended September 30, 2013 was $69.2 million, or $1.47 per share, compared to $121.1 million, or $2.94 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 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 expenses related to reimbursement agreements covering certain of our abandonment liabilities and depreciation, depletion and amortization ("DD&A") related to the increased volumes at Alba and Bacchus.

Net loss to common shareholders for the third quarter of 2013 increased to $40.3 million compared to $34.2 million for the same period in 2012 primarily due to reduced revenue as a result of maintenance shutdowns on our North Sea assets, foreign currency losses on long-term liabilities and increased interest expense, partially offset by reduced operating costs, impairments of oil and gas properties and expense related to our reimbursement agreements covering certain of our abandonment liabilities.

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 third quarter 2013 was $34.7 million as compared to Net Loss as Adjusted of $13.6 million for the same period in 2012. The increase in Net Loss as Adjusted is primarily due to reduced revenue as a result of maintenance shutdowns on our North Sea assets, foreign currency losses on long-term liabilities and increased interest expense, partially offset by reduced operating costs, and expense related to our reimbursement agreements covering certain of our abandonment liabilities.

Adjusted EBITDA increased to $130.0 for the nine months ended September 30, 2013 from $65.3 million for the same period in 2012. The increase in Adjusted EBITDA was due to increased revenues related to our Bacchus field and the purchase of our additional interest in the Alba field and the loss on early extinguishment of debt in 2012, partially offset by increased expenses related to reimbursement agreements covering certain of our abandonment liabilities.

Adjusted EBITDA decreased to $3.3 million for the third quarter of 2013 from $51.6 million for the same period in 2012 due to decreased revenue as a result of maintenance shutdowns on our North Sea assets and foreign currency losses on long-term liabilities, partially offset by 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 $54.8 million for the nine months ended September 30, 2013 as compared to cash flows provided by operating activities of $1.3 million for the same period in 2012. The change was primarily due to increased revenue from


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the initial production at Bacchus and our additional interest in Alba and the proceeds of Forward Sales, partially offset by increased interest expense related to our outstanding indebtedness.

Revenue and Sales Volume

Our physical daily production was 7,980 BOE and 10,724 BOE for the third quarter of 2013 and 2012, respectively, reflecting the decreased volumes related to planned maintenance periods at certain of our U.K. properties. During the third quarter of 2013, the Alba field completed its maintenance, thereby providing no liftings for the period. For the third quarter of 2013 and 2012, we had sales volume of 4,725 BOE per day and 11,006 BOE per day, respectively.

Our physical daily production was 8,940 BOE and 7,059 BOE for the nine months ended September 30, 2013 and 2012, respectively, reflecting the impact of the production from Bacchus and our increased interest in Alba. For the nine months ended September 30, 2013 and 2012, we had sales volume of 8,794 BOE per day and 6,635 BOE per day, respectively. The increases in sales volume were primarily attributable to the production from Bacchus and our increased interest in Alba.

Our revenues increased from $121.4 million during the nine months ended September 30, 2012 to $220.7 million in the same period in 2013. The increase in revenue is a result of the production from the Bacchus and Alba fields. Our revenues decreased from $83.3 million during the third quarter of 2012 to $36.9 million in the same period of 2013. These decreases are primarily a result of production losses due to the maintenance shutdown of the Alba field during the third quarter of 2013.

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 of 2013. As a result, we had two tanker liftings at Alba during the second quarter of 2013. Because Alba was shutdown for the planned maintenance program from mid-August to mid-September 2013, there were no liftings during the third quarter. Drilling at the Alba field is scheduled to recommence in November 2013 with an additional well. 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, negotiated pricing in our marketing contracts and forward sales to achieve a more predictable cash flow by reducing our exposure to price fluctuations. At September 30, 2013, we had the following floors and ceilings embedded within our marketing contracts and forward sales:


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                                  Fourth Quarter   First Quarter    Second Quarter
                                       2013            2014              2014
Oil:
Volumes (Mbbl)                               387              472              360
Weighted Average Ceiling Price                  $                $                $
($/Barrel)                                103.96           109.81           109.75
Weighted Average Floor Price                    $                $                $
($/Barrel)                                 96.63           103.97           102.50


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

                                         Three Months Ended           Nine Months Ended
                                            September 30,               September 30,
                                          2013         2012           2013          2012
Sales volume: (1)
Oil and condensate sales (Mbbls):
United Kingdom                              327          812          2,039         1,099
United States                                  -           1              1             2
Total                                       327          813          2,040         1,101

Gas sales (MMcf):
United Kingdom                                9           19             35            69
United States  (2)                          638        1,182          2,127         4,234
Total                                       647        1,201          2,162         4,303

Oil equivalent sales (MBOE):
United Kingdom                              328          815          2,045         1,110
United States  (2)                          107          198            356           708
Total                                       435        1,013          2,401         1,818

Total BOE per day                         4,725       11,006          8,794         6,635

Physical production volume (BOE per
day): (1)
United Kingdom                            6,824        8,573          7,586         4,474
United States                             1,156        2,151          1,354         2,585
Total                                     7,980       10,724          8,940         7,059

Realized Price, before and after
derivatives :
United Kingdom:
Oil and condensate price ($ per Bbl)  $  106.82     $  99.32      $  104.77      $ 101.78
Gas price ($ per Mcf)                 $    7.92     $   6.80      $    8.03      $   7.18
Equivalent oil price ($ per BOE)      $  106.55     $  99.09      $  104.60      $ 101.16

United States:
Oil and condensate price ($ per Bbl)     106.78     $  92.93          94.84         96.19
Gas price ($ per Mcf)                 $    2.99     $   2.09      $    3.15      $   2.11
Equivalent oil price ($ per BOE)      $   18.29     $  12.88      $   19.13      $  12.95

Realized Price, before and after
derivatives:
Oil and condensate price ($ per Bbl)  $  106.82     $  99.31      $  104.76     $  101.76
Gas price ($ per Mcf)                 $    3.06     $   2.16      $    3.23      $   2.19
Equivalent oil price ($ per BOE)      $   84.89     $  82.24      $   91.95     $   66.80

(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.


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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 third quarter of 2013, operating expenses decreased to $16.4 million as compared to $24.0 million for the same period in 2012. This decrease was primarily the result of the shutdown of the Alba field for routine maintenance from mid-August to September 2013 and drilling delays at the Rochelle field. For the nine months ended September 30, 2013 and 2012, operating expenses were $72.0 million and $34.6 million, respectively. These increases for the nine month period were primarily due to costs related to our increased interest in the Alba field, initial production from the Bacchus field and operating expenses of approximately $9.7 million for the third quarter of 2012 and nine months ended September 30, 2012 related to the initial purchase price value allocation of inventory at Alba as of the acquisition date.

Operating costs per BOE increased from $23.68 per BOE for the third quarter of 2012 to $37.63 per BOE for the same period in 2013 primarily due to the effect of lower sales volumes resulting from the lack of tanker liftings at Alba during the third quarter of 2013. In addition, certain of our operating expenses are fixed costs and do not vary with the amount of sales volumes each quarter. With the lower sales volumes at Alba, this fixed cost component of operating expenses increased the operating expense per BOE for the third quarter of 2013.

DD&A expense decreased to $18.6 million from $23.8 million for the third quarter of 2013 and 2012, respectively, primarily due to the decreased sales volumes for the third quarter as previously discussed. DD&A expense increased to $93.5 million from $42.3 million for the nine months ended September 30, 2013 and 2012, respectively. The increased sales volumes related to our increased interest in the Alba field, production from the Bacchus field and additional accretion expense related to the increased abandonment liabilities assumed upon the closing of the Alba field acquisition contributed to the increase over the comparative period.

We recorded an impairment of $6.0 million during the third quarter of 2013. For the third quarter of 2013, the prices used in the full cost ceiling test for our U.S. properties were $95.06


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per barrel for oil and $3.61 per Mcf for gas. For the nine months ended September 30, 2013, we recorded a pre-tax impairment of $9.6 million for our U.S. oil and gas properties. The primary reason for the U.S. impairment was the evaluation of assets not subject to amortization where we no longer intend to pursue and accordingly are included in the full cost pool. For the third quarter of 2012, we recorded a pre-tax impairment of $11.4 million related to our U.S. oil and gas properties through the application of the full cost ceiling test at the end of the quarter. For the nine months ended September 30, 2012, we recorded a pre-tax impairment of $47.1 million related to our U.S. oil and gas properties. The impairment was primarily due to the decline in U.S. gas prices. The prices used to determine the impairment for our U.S. properties for the third quarter of 2012 were $94.84 per barrel for oil and $2.78 per Mcf for gas.

For the third quarter of 2013, the prices used in the full cost ceiling test for our U.K. properties were $108.67 per barrel for oil and $10.51 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 to $3.9 million for the third 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 and lower travel expenses. Components of G&A expenses for these periods are as follows:

(Amounts in thousands)                      Three Months Ended           Nine Months Ended
                                               September 30,               September 30,
                                            2013           2012         2013           2012
Compensation                            $   4,000       $  4,814     $ 14,988      $  15,320
Consulting, legal and accounting fees       2,278          2,211        7,217          6,316
Amounts recovered from joint interest
partners                                   (1,241)          (806)      (6,295)        (2,539)
Other expenses                                525          1,549        3,644          5,050
Total gross cash G&A expenses               5,562          7,768       19,554         24,147

Non-cash stock-based compensation           1,464          1,758        4,672          4,872
Gross G&A expenses                          7,026          9,526       24,226         29,019
Less: capitalized G&A expenses             (3,113)        (4,500)      (9,950)       (13,640)
Net G&A expenses                        $   3,913       $  5,026     $ 14,276      $  15,379

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.


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In addition, we capitalize a portion of interest as a result of our increased drilling activity at Alba, Bacchus and Rochelle. The components of interest expense are as follows:

(Amounts in thousands)                      Three Months Ended        Nine Months Ended
                                              September 30,             September 30,
                                             2013        2012         2013         2012
Interest expense on debt outstanding
at September 30, 2013                      $ 27,309    $ 22,275    $  78,264    $  53,072
Interest expense on retired debt                   -        820             -      19,526
Amortization of loan costs and discount       6,635       3,225       15,330       10,536
Gross interest expense                       33,944      26,320       93,594       83,134

Less: capitalized interest                   (7,483)     (8,267)     (21,248)     (20,118)

Net interest expense                       $ 26,461    $ 18,053    $  72,346    $  63,016

Interest expense increased to $26.5 million for the third quarter of 2013 as compared to $18.1 million for the corresponding period in 2012, primarily due to increased outstanding debt. For the nine months ending September 30, 2013 and 2012, we had non-cash interest expense, including amortization of loan costs and discount, of $20.6 million and $17.6 million, respectively.

Letter of credit fees were $7.3 million and $9.4 million for the third quarter of 2013 and 2012, respectively. The letter of credit fees are expenses related to our reimbursement agreements covering certain of our abandonment liabilities. Letter of credit fees were $25.8 million and $12.4 million for the nine months ended September 30, 2013 and 2012, respectively. The increases in letter of credit fees for the nine months ended September 30, 2013 and 2012 were primarily due to the reimbursement agreement issued upon our acquisition of additional interest in Alba.

Other income (expense) increased to $(4.5) million during the nine months ended September 30, 2013 as compared to $(1.8) 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
Nine Months Ended September 30, 2013:
Net loss before taxes                 $ (30,152)   $ (35,459)   $ (4,347)   $  (69,958)

Current tax expense (1)                  15,121             -           -       15,121
Deferred tax benefit                    (17,262)            -           -      (17,262)
Income tax benefit                       (2,141)            -           -       (2,141)
. . .
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