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END > SEC Filings for END > Form 10-Q on 8-Aug-2014All Recent SEC Filings

Show all filings for ENDEAVOUR INTERNATIONAL CORP

Form 10-Q for ENDEAVOUR INTERNATIONAL CORP


8-Aug-2014

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 capital spending by our U.S. operations is primarily related to strategic positioning and proof-of-concept in the Marcellus and Niobrara play areas as we monitor U.S. gas prices.

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 market conditions and increased debt service costs required to finance our 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.

2014 Liquidity and Capital Resources

During 2014, our primary focus for our financial resources is expected to be:

our capital expenditures, primarily related to our drilling activities in the U.K.;

payments for abandonment obligations;

payments due under our production payments; and

interest payments on outstanding indebtedness and payments in support of our reimbursement agreement covering our abandonment obligations.

As of June 30, 2014, we had $913.2 million in outstanding debt and $83.2 million in cash, totaling $830.0 million in outstanding indebtedness with a fair value of $648.6 million, net of cash. We anticipate that we will rely on our existing cash balances and cash generated from operations to satisfy our liquidity needs. We are primarily dependent upon our three fields in the U.K. - Alba, Bacchus and Rochelle - for our cash flows from operations. If we incur delays in production, such as those resulting from the mechanical issues experienced at the Rochelle field and the subsequent unplanned shutdown at the Scott platform discussed in "Liquidity and Capital


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Resources," it will negatively impact our cash flows, results of operations and financial condition.

During 2014, we completed several transactions to improve our liquidity position and reduce our costs. These transactions include:

replacing certain credit facilities which would have expired in June 2014;

replacing reimbursement agreements covering certain of our abandonment liabilities in the U.K. which would have expired in June and July 2014;

entering into a forward sale for $22.5 million;

issuing $12.5 million in common stock and warrants; and

issuing $17.5 million in 6.5% convertible debt.

In addition, we have reduced our gross general and administrative expenses as a result of the previously announced consolidation of our U.K. offices, headcount reductions and other cost-reduction initiatives. During the second quarter, we also settled an insurance claim for the Rochelle E1Y well, which resulted in proceeds of $12.6 million paid to us from the insurance carrier.

We remain highly leveraged and continue to focus on our liquidity position. We continue to be challenged by unexpected downtime and lower production efficiency rates which are directly attributable to production facilities we do not control. For example, we expect to experience production delays during the third quarter associated with planned shutdowns at the Rochelle, Bacchus and Alba fields. Financial obligations coming due in the near term include interest payments our 12% Senior Notes due each September and March, anticipated decommissioning charges of $29 million during the second half 2014 and principal payments on our monetary production payments totaling $115 million from July 2014 through April 2015.

If we are unable to meet any short-term liquidity needs out of cash on hand or if we undertake a longer term solution to our leverage situation, we would attempt to refinance or extend our debt or the monetary production payments. We may also be forced to pursue other alternatives, such as a sale of assets, issuances of equity, a delay in discretionary capital expenditures or declining to participate in non-operated drilling prospects. No assurance can be given, however, that we could successfully consummate any of these transactions.

During 2013, we also completed several transactions to improve our liquidity, extend the maturities of some of our debt and reimbursement agreements and effectively hedge a portion of production from our U.K. North Sea assets by locking in pricing. These transactions included:

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

entered into two forward sale agreements for a payment of approximately $22.5 million each 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 monetary production payments for $175 million; and


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entered into a purchase and sale agreement for the joint exploration, development, and operation of certain oil and gas properties in Pennsylvania.

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

Results of Operations

Our revenues, net loss and cash flows from operating activities are sensitive to changes in the prices we receive for the oil and natural gas produced. 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 revenues decreased from $126.2 million for the quarter ended June 30, 2013 to $44.9 million for 2014 and from $183.8 million for six months ended June 30, 2013 to $139.0 million for the same period in 2014, primarily as a result of timing of liftings at our Alba field, partially offset by initial production from the Rochelle field. Sales volumes, revenues and net loss were significantly affected by the lifting schedule at the Alba field which did not have a lifting in the second quarter of 2014. Given the level of production at Alba and the size of its tanker liftings, we estimate three to four liftings per year. Physical production for the quarter produced, but not lifted, is recorded into deferred revenues. Alba's most recent lifting occurred on July 4, 2014, as a result, sales, revenues and income for the July lifting will be reflected in the third quarter. A similar situation occurred in the third quarter of 2013 when there was no Alba lifting.

Net loss to common stockholders for the six months ended months ended June 30, 2014 was $82.5 million, or $1.63 per share, compared to $28.8 million, or $0.61 per share, for the same period in 2013. The change in the net loss to common stockholders for these periods was primarily due to the timing of liftings at the Alba field, higher gains on unrealized foreign currency exchange in 2013, increased depreciation, depletion and amortization ("DD&A") related to the increased U.K. accretion expense, the litigation settlement expense in 2014, and an increase in interest expense from our debt agreements and Monetary Production Payment; partially offset by initial production from Rochelle, lower impairments of oil and gas properties and decreased expenses related to reimbursement agreements covering certain of our abandonment liabilities.

Net loss to common shareholders for the second quarter of 2014 increased to $37.1 million, or $0.72 per share, compared to $14.3 million or $0.30 per share for the same period in 2013 primarily due to the timing of liftings at the Alba field and increased interest expense related to the Monetary Production Payment.

In addition to our operations, our net income can be affected by various non-cash items, such as impairments, derivative transactions, and loss on extinguishment of debt. Net loss, as adjusted, which excludes these non-cash items, for the second quarter 2014 was $38.7 million as compared to net loss, as adjusted of $12.6 million for the same period in 2013. The increase in net loss, as adjusted is primarily due to the lack of liftings at the Alba field and increased interest expense.


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Adjusted EBITDA decreased to $26.9 for the six months ended June 30, 2014 from $82.2 million for the same period in 2013. The decrease in Adjusted EBITDA was due to decreased revenues related to the Alba field's lifting schedule, partially offset by increased production from the Rochelle field and decreased expenses related to reimbursement agreements covering certain of our abandonment liabilities.

Our cash flows provided by operating activities decreased to $59.9 million for the six months ended June 30, 2014 as compared to cash flows provided by operating activities of $71.6 million for the same period in 2013. The change was primarily due to increased payments for abandonment obligations and the timing of receipts related to increased revenues partially offset by increased operating expenses and interest expense.

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."

Revenue and Sales Volume

Our physical daily production was 12,879 boe and 9,498 boe for the second quarter of 2014 and 2013, respectively, and 11,169 boe and 9,427 boe for the six months ended June 30, 2014 and 2013, respectively. Physical production for the quarter exceeded the revised guidance range of 10,500 - 11,500 boed we had previously announced on June 10, 2014.

For the second quarter of 2014 and 2013, we had sales volume of 7,424 boed and 14,497 boed, respectively and 9,269 boed and 10,862 boed for the six months ended June 30, 2014 and 2013, respectively. Our revenues decreased from $126.2 million during the three months ended June 30, 2013 to $44.9 million in the same period in 2014. For the six months ended June 30, 2014, our revenues decreased to $139.0 million, compared to $183.8 for the same period in 2013. The decrease in sales volumes and revenue is primarily a result of the timing of 2014 liftings at the Alba field discussed previously, partially offset by initial production at the Rochelle field.

The Rochelle field produces natural gas and liquids (including standardized crude oil) through the Scott platform, in which we have no ownership interest. In late March 2014, Rochelle production was shut-in due to an unplanned shutdown of the Scott platform. Rochelle production resumed during April 2014, but this unanticipated downtime negatively affected our production rates, revenue and results of operations for the first and second quarter of 2014, as well as our near-term liquidity. The W1 well was returned to production during May 2014 and for the first time at Rochelle, both the E1 and W1 development wells were producing simultaneously. As a result, the field has subsequently produced at rates of greater than a 100 mcfed for 32 days during the second quarter.

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


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the Alba field and liquids at the Rochelle 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 delivered out of our storage tanks. While the timing of tanker liftings affect when we record revenue, 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 June 30, 2014, we had the following floors and ceilings embedded within our marketing contracts and forward sales:

                                          Third    Fourth
                                         Quarter   Quarter
Oil:                                      2014      2014
Volumes (mbbl)                              481       449
Weighted Average Ceiling Price ($/bbl) $ 106.77  $ 106.06
Weighted Average Floor Price ($/bbl)     101.79    101.96


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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           Six Months Ended
                                              June 30,                    June 30,
                                          2014         2013          2014          2013
Sales volume: (1)
Oil and condensate sales (mbbls):
United Kingdom                              255        1,205         1,087         1,713
United States                                  -           1              -            1
Total                                       255        1,206         1,087         1,714

Gas sales (mmcf):
United Kingdom                            2,109           15         2,694            26
United States                               415          667           846         1,489
Total                                     2,524          682         3,540         1,515

Oil equivalent sales (mboe):
United Kingdom                              606        1,207         1,536         1,717
United States                                70          112           141           249
Total                                       676        1,319         1,677         1,966

Total boed                                7,424       14,497         9,269        10,862

Physical production volume (boed):
(1)
United Kingdom                           12,079        8,083        10,351         7,973
United States                               800        1,415           818         1,454
Total                                    12,879        9,498        11,169         9,427

Realized Price, before and after
derivatives :
United Kingdom:
Oil and condensate price ($ per bbl)  $  106.34     $ 102.68      $ 104.19      $ 104.37
Gas price ($ per mcf)                 $    7.62     $   8.19      $   8.19      $   8.06
Equivalent oil price ($ per boe)      $   71.17     $ 102.57      $  88.10      $ 104.23

United States:
Oil and condensate price ($ per bbl)  $   97.33     $  85.46      $  98.67      $  88.19
Gas price ($ per mcf)                 $    4.07     $   3.40      $   4.30      $   3.22
Equivalent oil price ($ per boe)      $   24.85     $  20.72      $  26.01      $  19.49

Total:
Oil and condensate price ($ per bbl)  $  106.32     $ 102.67      $ 104.19     $  104.37
Gas price ($ per mcf)                 $    7.03     $   3.50      $   7.26     $    3.30
Equivalent oil price ($ per boe)      $   66.40     $  95.64      $  82.87     $   93.51

(1) We record oil revenues when production is transported by pipeline or production is shipped out of our storage tanks and legal ownership has passed to the purchaser. We use the entitlements method to account for sales of gas production. Physical production may


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differ from sales volumes based on the timing of tanker liftings for our international sales.

Our revenues, profitability and cash flow depend upon production efficiencies of facilities we do not control and 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 2014, operating expenses decreased to $6.8 million as compared to $38.1 million for the same period in 2013. For the six months ended June 30, 2014 and 2013, operating expenses were $34.0 million and $55.6 million, respectively. This decrease was primarily the result of reduced operating expenses associated with lack of lifting volumes at Alba. Due to the decrease in operating expenses, operating costs per boe decreased from $28.88 per boe for the second quarter of 2013 to $10.14 per boe for the same period in 2014.

DD&A expense decreased to $32.3 million from $51.9 million for the second quarter of 2014 and 2013, respectively. This decrease was due to decreased sales volumes primarily offset by increased accretion expense related to our decommissioning obligations and an increase in the DD&A rate on our U.K. properties. DD&A expense increased to $77.2 million from $74.9 million for the six months ended June 30, 2014 and 2013, respectively. Accretion expense increased to $6.5 million from $5.8 million for the second quarter of 2014 and 2013, respectively, and $12.6 million from $11.4 million for the six months ended June 30, 2014 and 2013, respectively.

For the second quarter of 2014, the prices used in the full cost ceiling test for our U.S. properties were $100.27 per barrel for oil and $4.09 per mcf for gas. We did not record an impairment related to our U.S. properties for the second quarter of 2014. Prices used for the same period in 2013 were $91.60 per barrel for oil and $3.46 per mcf for gas and no impairment was recorded.

For the second quarter of 2014, the prices used in the full cost ceiling test for our U.K. properties were $108.64 per barrel for oil and $9.65 per mcf for gas. We have not recorded any impairment


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related to our U.K. properties. Prices used in 2013 for the same period were $107.58 per barrel for oil and $10.24 per mcf for gas.

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 to $5.2 million for the second quarter of 2014 as compared to $4.9 million for the same period in 2013 as a result of lower amounts recovered from our joint interest partners, partially offset by a decrease in employee compensation expense resulting from the organizational changes and closure of our London offices that occurred in late 2013. For the six months ended June 30, 2013, G&A expenses decreased from $10.1 million at June 30, 2014, compared to $10.4 for the same period in 2013. Components of G&A expenses for these periods are as follows:

(Amounts in thousands)                      Three Months Ended          Six Months Ended
                                                 June 30,                   June 30,
                                            2014           2013        2014          2013
Compensation                            $   3,338       $  4,597    $  7,250      $ 10,988
Consulting, legal and accounting fees       2,289          2,369       4,703         4,938
Amounts recovered from joint interest
partners                                     (172)        (3,967)       (156)       (5,054)
Other expenses                              1,132          2,149       1,615         3,122
Total gross cash G&A expenses               6,587          5,148      13,412        13,994

Non-cash stock-based compensation           1,611          1,517       2,745         3,207
Gross G&A expenses                          8,198          6,665      16,157        17,201
Less: capitalized G&A expenses             (2,958)        (1,783)     (6,068)       (6,837)
Net G&A expenses                        $   5,240       $  4,882    $ 10,089      $ 10,364

As discussed in "Liquidity and Capital Resources," we completed several financing transactions during the first quarter that have had a significant impact on our interest expense. Interest expense increased to $31.4 million for the second quarter of 2014 as compared to $24.4 million for the corresponding period in 2013, primarily due to additional interest resulting from the issuance of the Monetary Production Payment in mid-2013 and lower capitalized interest in 2014 as our significant development projects have been completed, partially offset by the lower interest rate from the Term Loan Facility versus the Revolving Credit Facility. For the six months ended June 30, 2014, interest expense increased to $62.9 as compared to $45.9 for the corresponding period in 2013. This increase was primarily due to the additional interest expense discussed above. We capitalize a portion of interest as a result of our drilling activity. As the development work at Bacchus and Rochelle has been completed, the amount of interest we capitalize related to these projects has decreased. The components of interest expense are as follows:


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(Amounts in thousands)                      Three Months Ended        Six Months Ended
                                                 June 30,                 June 30,
                                             2014        2013        2014         2013

Interest expense on debt outstanding       $ 27,172    $ 26,781    $ 54,502    $  50,954
Amortization of loan costs and discount       6,671       5,257      13,376        8,695
Gross interest expense                       33,843      32,038      67,878       59,649

Less: capitalized interest                   (2,412)     (7,591)     (4,970)     (13,764)

Interest expense                           $ 31,431    $ 24,447    $ 62,908    $  45,885

For the six months ended June 30, 2014 and 2013, we had non-cash interest expense, including amortization of loan costs and discount, of $17.2 million and $12.1 million, respectively.

Letter of credit fees were $2.3 million, $7.1 million for the second quarter of 2014 and 2013, $6.1 million and $18.5 million, for the six months ended June 30, 2014 and 2013, respectively. The letter of credit fees are expenses related to our reimbursement agreements covering certain of our abandonment liabilities.
The decrease in the letter of credit fees was primarily due to the lower rates and financing costs of our Combined Procurement Agreement versus the previous agreements.

As part of the repayment of the Revolving Credit Facility, we paid an early termination fee of approximately $2.5 million and wrote off the remaining deferred financing costs of $2.1 million.

The unrealized gains (losses) on foreign currency exchange are primarily attributable to the effects of foreign currency fluctuations on our abandonment liabilities which are predominantly denominated in pounds sterling.

We recorded $19.0 million in total settlement expense in connection with the settlement, including a $6 million deposit that was paid to SM Energy prior to the execution of the agreements in 2011. See Note 15 for additional discussion.

Other income (expense) decreased to $(1.4) million during the six months ended June 30, 2014 as compared to $(2.1) million for the corresponding period in 2013. For the six months ended June 30, 2014, other income (expense) increased to $(3.4) million compared to $(2.0) million in 2013. The changes in other income (expense) are primarily attributable to transaction costs related to our litigation with SM Energy.

Income Taxes

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


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(amounts in thousands)             U.K.         U.S.        Other       Total
Six Months Ended June 30, 2014:
Net loss before taxes           $ (37,089)   $ (37,966)   $ (3,332)   $ (78,387)

PRT tax current expense            11,234             -           -      11,234
. . .
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