Attached files
file | filename |
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8-K - FORM 8-K - ENDEAVOUR INTERNATIONAL CORP | h69239e8vk.htm |
EX-23.1 - EX-23.1 - ENDEAVOUR INTERNATIONAL CORP | h69239exv23w1.htm |
EX-99.1 - EX-99.1 - ENDEAVOUR INTERNATIONAL CORP | h69239exv99w1.htm |
EX-99.3 - EX-99.3 - ENDEAVOUR INTERNATIONAL CORP | h69239exv99w3.htm |
Exhibit 99.2
Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations
This Managements Discussion and Analysis of Financial Condition and Results of Operations and
other parts of this report contain forward-looking statements that involve risks and uncertainties.
All forward-looking statements included in this report are based on information available to
Endeavour 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 report. The following should be
read in conjunction with the audited financial statements and the notes thereto included herein.
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 have
reissued this MD&A and filed it under cover of Form 8-K on January 8, 2010 to reflect the disposition of our Norwegian subsidiary and the related reclassification of its results of operation and financial position as discontinued operations as discussed below in detail.
Overview
We are an international oil and gas exploration and production company focused on the
acquisition, exploration and development of energy reserves. To date, we have invested a
significant amount of our resources on various development, acquisition and exploration projects.
Over the last several years, we have principally used acquisitions to build our base of production,
proved reserves and cash flow while continuing our exploration and development programs. Key items
related to our acquisitions, drilling and operations in the last three years include:
| Acquisitions |
o | In late 2006, we completed the acquisition of various fields in the UK North Sea from Talisman. |
o | Enoch Following our acquisition of an interest in this field in 2006, we completed the development program and began initial production in mid 2007. |
| Exploration During the last three years, we have drilled 17 exploration wells with four successes in the UK, seven in Norway and one in the U.S., including: |
o | Cygnus The first of our wells in our 2006 drilling program, the Cygnus prospect, was spud in early February 2006 in the UK sector of the North Sea. In 2008 we submitted a development plan to the UK authorities and began drilling an appraisal well. We announced the success of the appraisal well in 2009. |
o | Columbus In 2006, we drilled the Columbus exploratory prospect in the Central Graben region of the North Sea. We served as operator of the well. In December 2006, we completed successful testing of the well. In 2007, we drilled an appraisal well and its sidetrack effectively confirming the presence of gas/condensate bearing sands. In 2008, we submitted a development plan to the UK authorities and expect to receive approval in 2009. |
o | Rochelle We began appraisal drilling in 2008 and announced successful results in 2009. |
o | United States In 2008, we participated in two exploration wells in the United States. We announced first production from one well in January 2009 while the second well is still undergoing testing and evaluation. |
| Producing assets At the end of 2007, we completed a project that initiated gas production at the Njord field. Production from the Goldeneye field has continued at levels above our expectations, |
Endeavour International Corporation
indicating the quality of this large gas field. Development drilling has been ongoing at Njord, Brage and Alba to maintain production levels. |
Our realized price before derivatives increased 25% from 2007 to 2008 largely as a result of oil
prices climbing to record levels in the summer of 2008 and gas prices in our markets improving.
This substantial increase in prices in the first half of 2008 helped revenue grow from $135.9
million in 2007 to $170.8 million in 2008. With this higher revenue and strong fiscal discipline
over expenses, we repaid $32.0 million in debt, spent $66.4 million in capital expenditures during
2008 and increased cash from year end by $17.6 million. At December 31, 2008, we held $31.4
million in cash and another $20.7 million in cash restricted for drilling rig commitments.
Even with the substantial growth in revenues, 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 $133.2
million in 2008 versus $128.5 million in 2007 and $(14.1) million in 2006. Discretionary cash flow
was $120.8 million in 2008, compared to $113.0 million in 2007 and $5.1 million in 2006, respectively.
This significant increase in our discretionary cash flow in the past two years has allowed us to
repay debt in 2007 and 2008 while continuing to actively invest in our capital programs.
Net income
available to common shareholders was $45.7 million for 2008, or $0.32 per diluted share. Net loss available to common shareholders for 2007 was $60.3
million, or $0.49 per share, reflecting the significant unrealized loss on the mark-to-market of
commodity derivatives. For 2006, net loss was $8.8 million, or $0.10 per share. The net loss for
2006 reflects a significant unrealized gain on the mark-to-market of commodity derivatives.
Net income as adjusted for 2008 would have been $5.7 million without the effect of impairments,
derivative transactions and currency impacts of deferred taxes. Net loss as adjusted for 2007
would have been $10.9 million, as compared to net loss as adjusted of $20.9 million in 2006.
Adjusted EBITDA increased to $176.6 million in 2008, as compared to $124.1 million in 2007 and $9.2
million in 2006.
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 the companys
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, discretionary cash flow, adjusted earnings before interest,
taxes, depreciation, depletion and amortization (Adjusted EBITDA) and adjusted net income.
For definitions of Adjusted EBITDA and Discretionary Cash Flow, and a reconciliation of Adjusted
EBITDA to net income as adjusted, please see Reconciliation of Non-GAAP Accounting Measures.
In connection with the Talisman Acquisition, we entered into various oil and gas derivative
instruments to stabilize cash flows from the acquired assets and satisfy certain obligations under
the financing agreements that funded the acquisition. Hedge accounting has not been elected for
these instruments resulting in the application of mark-to-market accounting effectively pulling
forward into current periods the non-cash gains and losses from commodity price fluctuations
relating to all future delivery periods. When we entered into these contracts, they covered nearly
5.2 million BOE beginning in 2007 and running through 2011 at a weighted average price of $68.35.
As both oil and gas prices fell from the date we entered into the contracts through December 31,
2006, we recorded an unrealized gain of $34.5 million reflecting the decline in future commodity
prices through 2011. However, in 2007, commodity prices reversed their 2006 declines, continuing
to increase to record levels in the case of oil. With oil
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Endeavour International Corporation
prices reaching nearly $100 per barrel and gas prices recovering to levels close to our original
contract prices, we recorded an $89.1 million unrealized loss in 2007 on contract volumes through
2011. As oil prices spiked to record levels in 2008 and then went into an unprecedented decline in
the last half of the year, we recorded $77.8 million in an unrealized gain on contract volumes through
2011. We expect to continue to have fluctuations in net earnings each period as commodity prices
fluctuate based on all remaining unsettled contracts at the end of each period. See Note 16 to the
consolidated financial statements for additional information on these derivatives.
Revenues, Volumes and Operating Costs
Our revenues have increased significantly since 2006 primarily due to the following:
| In November 2006, we completed the Talisman Acquisition and each of 2008 and 2007 reflect a full years contribution of those assets. |
| Similarly, our Enoch field began first production in mid 2007. |
| The last three years have been turbulent times for the global oil market and, to a lesser extent, the North Sea gas markets. 2006 experienced seemingly high commodity prices, only to be followed by lower prices in 2007, new, unprecedented highs in mid 2008 and a precipitous drop by the end of 2008. |
| To soften the extremes of the commodity markets, we have derivative instruments covering a portion of our anticipated sales through 2011. |
| Natural production declines at certain of our fields have not been offset by infield drilling, resulting in small production decreases at certain fields. |
| There was an increase in gas production from our discontinued operations at the end of 2007 with the completion of a gas project at Njord in the fourth quarter of 2007. |
In general total operating costs increased from 2006 through 2008 as a result of production from
the acquisitions discussed above. Operating costs per BOE declined for 2006 and 2007 due to the
lower operating costs per BOE for our acquired UK properties. Operating costs per BOE increased
from 2007 to 2008 primarily due to increased fuel costs at a non-operated facility where several of
our fields deliver production.
The following table shows our annual average sales volumes, sales prices and average production
costs.
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Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
Sales Volume (1): |
||||||||||||
Oil and condensate sales (Mbbl): |
||||||||||||
United Kingdom |
1,032 | 1,274 | 209 | |||||||||
Continuing operations |
1,032 | 1,274 | 209 | |||||||||
Discontinued operations - Norway |
726 | 519 | 508 | |||||||||
Total |
1,758 | 1,793 | 717 | |||||||||
Gas sales (MMcf): |
||||||||||||
United Kingdom |
6,532 | 8,556 | 1,539 | |||||||||
Continuing operations |
6,532 | 8,556 | 1,539 | |||||||||
Discontinued operations - Norway |
2,322 | 328 | 203 | |||||||||
Total |
8,854 | 8,884 | 1,742 | |||||||||
Total sales (MBOE): |
||||||||||||
United Kingdom |
2,121 | 2,700 | 466 | |||||||||
Continuing operations |
2,121 | 2,700 | 466 | |||||||||
Discontinued operations - Norway |
1,113 | 574 | 542 | |||||||||
Total |
3,234 | 3,274 | 1,008 | |||||||||
BOE per day |
8,835 | 8,969 | 2,760 | |||||||||
Physical Production Volume (1): |
||||||||||||
Total production (BOE per day) |
||||||||||||
United Kingdom |
5,804 | 7,660 | 1,334 | |||||||||
Continuing operations |
5,804 | 7,660 | 1,334 | |||||||||
Discontinued operations - Norway |
3,033 | 1,608 | 1,566 | |||||||||
Total |
8,837 | 9,268 | 2,900 | |||||||||
Realized Prices (2): |
||||||||||||
Oil and condensate price ($ per Bbl) |
||||||||||||
Before commodity derivatives |
$ | 90.53 | $ | 67.11 | $ | 60.51 | ||||||
Effect of commodity derivatives |
(14.50 | ) | (2.13 | ) | (7.63 | ) | ||||||
Including commodity derivatives |
$ | 76.03 | $ | 64.98 | $ | 52.88 | ||||||
Gas price ($ per Mcf) |
||||||||||||
Before commodity derivatives |
$ | 11.44 | $ | 6.27 | $ | 9.30 | ||||||
Effect of commodity derivatives |
(0.35 | ) | 1.79 | | ||||||||
Including commodity derivatives |
$ | 11.09 | $ | 8.06 | $ | 9.30 | ||||||
Equivalent oil price ($ per BOE) |
||||||||||||
Before commodity derivatives |
$ | 80.54 | $ | 53.78 | $ | 59.15 | ||||||
Effect of commodity derivatives |
(8.84 | ) | 3.68 | (5.43 | ) | |||||||
Including commodity derivatives |
$ | 71.70 | $ | 57.46 | $ | 53.72 | ||||||
Operating Statistics: |
||||||||||||
Operating costs ($ per BOE) (3) |
$ | 14.40 | $ | 12.56 | $ | 15.45 | ||||||
G&A costs ($ per BOE) |
$ | 6.07 | $ | 6.07 | $ | 21.76 | ||||||
Sales volume per employee (MBOE/employee) |
52 | 54 | 17 | |||||||||
(1) | We record oil revenues on the sales method, i.e. when delivery has occurred. Actual production may differ based on the timing of tanker liftings. We use the entitlements method to account for sales of gas production. |
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Endeavour International Corporation
(2) | The average sales prices reflect both our continuing and discontinued operations and include realized gains and losses for derivative contracts we utilize to manage price risk related to our future cash flows. | |
(3) | Operating costs reflect both our continuing and discontinued operations and 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 product and production related general and administrative costs. |
DD&A and Impairment of Oil and Gas Properties
Decreased DD&A expense from 2007 to 2008 reflects the impact of a decrease in production from 2007
to 2008 partially offset by an increase in the DD&A rate. DD&A expense increased from 2006 to 2007
as a result of the acquisitions discussed above. In addition, DD&A for 2006 includes $1.2 million
related to the impairment of our intangible asset.
In 2008, we recorded $37.0 million in impairment of oil and gas properties, pre-tax, through the
application of the full cost ceiling test at year-end. The prices used to determine the impairment
were $36.55 per barrel for oil and $8.70 per Mcf for gas. While our commodity derivatives had a
fair value of $31.0 million at December 31, 2008, these derivatives were not included in the
calculation of the full cost ceiling test as the derivatives are not accounted for as cash flow
hedges.
During 2006, we recorded $0.8 million in impairment of oil and gas properties related to the
abandonment costs of a well impaired in 2005.
General and Administrative Expenses
Our net G&A expenses have decreased since 2006 as we have been able to absorb our expanded
operations without a corresponding increase in the number of employees. We had 62 employees at
December 31, 2008, 61 employees at December 31, 2007, and 58 employees at December 31, 2006. Gross
cash G&A expense increases since 2006 reflect increased foreign currency exchange rates, additional
payroll taxes and salary expense related to the changes in staffing, occupancy costs and fees.
Occupancy costs increased due to additional office leases at our four locations. Accounting, legal
and tax consulting fees fluctuated with our acquisition and financing activity. Non-cash
stock-based compensation decreased as a result of the final vesting of grants given in prior years,
current year forfeitures and declining fair values on each years grants. Components of G&A
expenses for these periods are as follows:
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Endeavour International Corporation
(Amounts in thousands) | Year Ended December 31, | |||||||||||
2008 | 2007 | 2006 | ||||||||||
Compensation |
$ | 11,203 | $ | 10,181 | $ | 9,214 | ||||||
Consulting, legal and accounting fees |
4,679 | 5,045 | 3,387 | |||||||||
Occupancy costs |
1,130 | 994 | 507 | |||||||||
Other expenses |
4,004 | 2,352 | 3,040 | |||||||||
Total gross cash G&A expenses |
21,016 | 18,572 | 16,148 | |||||||||
Non-cash stock-based compensation |
2,928 | 4,487 | 10,819 | |||||||||
Gross G&A expenses |
23,944 | 23,059 | 26,967 | |||||||||
Less: capitalized G&A expenses |
(8,012 | ) | (7,206 | ) | (9,322 | ) | ||||||
Net G&A expenses |
$ | 15,932 | $ | 15,853 | $ | 17,645 | ||||||
Interest Expense and Other
Interest expense increased to $23.0 million in 2008 primarily as a result of $4.3 million in
expenses, including $2.1 million in cash, related to the early repayment of the second lien term
loan. Interest expense increased to $19.3 million for 2007 versus only $8.6 million in 2006,
reflecting the various debt instruments issued to fund the Talisman Acquisition. Interest income
results from our investments of excess cash in short-term commercial paper and money market
accounts.
Other income (expense) for 2006 includes $3.8 million in financing costs paid in connection with
the Talisman Acquisition and $1.8 million impairment of long-term marketable securities with the
remainder primarily representing foreign currency exchange losses.
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Endeavour International Corporation
Income Taxes
The following summarizes the components of tax expense (benefit):
Total | Discontinued | |||||||||||||||||||||||
Continuing | Operations - | |||||||||||||||||||||||
(Amounts in thousands) | UK | U.S. | Other | Operations | Norway | Total | ||||||||||||||||||
Year Ended December 31, 2008 |
||||||||||||||||||||||||
Net income (loss) before
taxes |
$ | 66,129 | $ | (11,969 | ) | $ | (4,185 | ) | $ | 49,975 | $ | 63,244 | $ | 113,219 | ||||||||||
Current tax expense |
11,158 | | 10 | 11,168 | 27,879 | 39,047 | ||||||||||||||||||
Deferred tax expense |
22,673 | | 303 | 22,976 | 15,415 | 38,391 | ||||||||||||||||||
Foreign currency gains on deferred tax liabilities |
(10,028 | ) | | | (10,028 | ) | (10,681 | ) | (20,709 | ) | ||||||||||||||
Total tax expense |
23,803 | | 313 | 24,116 | 32,613 | 56,729 | ||||||||||||||||||
Net income (loss) after taxes |
$ | 42,326 | $ | (11,969 | ) | $ | (4,498 | ) | $ | 25,859 | $ | 30,631 | $ | 56,490 | ||||||||||
Year Ended December 31, 2007 |
||||||||||||||||||||||||
Net income (loss) before
taxes |
$ | (68,704 | ) | $ | (10,233 | ) | $ | 6,584 | $ | (72,353 | ) | $ | 14,095 | $ | (58,258 | ) | ||||||||
Current tax (benefit) expense |
2,898 | (3 | ) | 289 | 3,184 | 562 | 3,746 | |||||||||||||||||
Deferred tax (benefit)
expense |
(27,430 | ) | | 711 | (26,719 | ) | 8,951 | (17,768 | ) | |||||||||||||||
Foreign currency losses on
deferred tax liabilities |
1,327 | | | 1,327 | 3,514 | 4,841 | ||||||||||||||||||
Total tax (benefit) expense |
(23,205 | ) | (3 | ) | 1,000 | (22,208 | ) | 13,027 | (9,181 | ) | ||||||||||||||
Net income (loss) after taxes |
$ | (45,499 | ) | $ | (10,230 | ) | $ | 5,584 | $ | (50,145 | ) | $ | 1,068 | $ | (49,077 | ) | ||||||||
Year Ended December 31, 2006 |
||||||||||||||||||||||||
Net income (loss) before
taxes |
$ | 33,275 | $ | (23,463 | ) | $ | 13 | $ | 9,825 | $ | 7,250 | $ | 17,075 | |||||||||||
Current tax (benefit) expense |
1,837 | (45 | ) | 69 | 1,861 | 9,014 | 10,875 | |||||||||||||||||
Deferred tax (benefit)
expense |
10,105 | | | 10,105 | (1,840 | ) | 8,265 | |||||||||||||||||
Foreign currency losses on
deferred tax liabilities |
2,904 | | | 2,904 | 1,869 | 4,773 | ||||||||||||||||||
Total tax (benefit) expense |
14,846 | (45 | ) | 69 | 14,870 | 9,043 | 23,913 | |||||||||||||||||
Net income (loss) after taxes |
$ | 18,429 | $ | (23,418 | ) | $ | (56 | ) | $ | (5,045 | ) | $ | (1,793 | ) | $ | (6,838 | ) | |||||||
Our income tax expense relates primarily to operations in the UK and our discontinued
operations in Norway. Income tax expense in 2008 represents the significant increase in revenues
as a result of higher realized prices, the strengthening of the U.S. dollar versus the UK pound and
Norwegian kroner and the shift in anticipated capital expenditures from late 2008 to early 2009.
During 2007, we incurred taxes in all of the jurisdictions in which we do business, except for the
U.S., whereas in 2006, we incurred taxes only on our discontinued Norwegian operations. After
closing the Talisman Acquisition in 2006, we began recording tax expense (benefit) for our UK
operations and removed the valuation allowances previously recorded. The change in income taxes
from an expense of $23.9 million in 2006 to a benefit of $9.2 million in 2007 resulted from the
impact of the mark-to-market changes on our derivatives and the activity of our UK operations. At
December 31, 2008, we had net operating loss carryforwards of $61.6 million in the U.S.
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Endeavour International Corporation
In 2008, 2007 and 2006, we have not recorded 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
of deferred tax assets generated.
As our deferred tax liabilities in the UK and the Netherlands are denominated in their respective
currencies, we revalue those deferred tax liabilities to the applicable foreign currency exchange
rate at the end of each period. Those foreign currency gains and losses are included in income tax
expense.
Capital Program
We originally anticipated spending approximately $90 million during 2008 to fund oil and gas
exploration and development in the North Sea. With delays in timing for delivery of the necessary
drilling rigs, certain projects were delayed or rescheduled until 2009. We spent $88.5 million,
$87.9 million and $56.6 million on oil and gas capital, excluding acquisitions, in 2008, 2007 and
2006, respectively. We spent $15 million to $20 million each year on development activities at our
producing properties. The remaining costs were spent on exploration and appraisal activities,
including $5.5 million in 2008 related to our new operations in the United States.
Liquidity and Capital Resources
(Amounts in thousands) | December 31, 2008 | December 31, 2007 | ||||||
Cash |
$ | 31,421 | $ | 13,810 | ||||
Restricted cash, related to rig commitments |
20,739 | 22,000 | ||||||
Debt, including current maturities |
(227,855 | ) | (266,250 | ) | ||||
Debt, net of cash |
$ | (175,695 | ) | $ | (230,440 | ) | ||
Year Ended December 31, | ||||||||||||
(Amounts in thousands) | 2008 | 2007 | 2006 | |||||||||
Net cash provided by (used in): |
||||||||||||
Operating activities |
$ | 133,180 | $ | 128,506 | $ | (14,100 | ) | |||||
Investing activities |
$ | (64,851 | ) | $ | (108,140 | ) | $ | (427,118 | ) | |||
Financing activities |
$ | (46,613 | ) | $ | (43,740 | ) | $ | 403,369 | ||||
Operating, Investing and
Financing Activities include the net cash flows from our discontinued operations. For
the years ended December 31, 2008, 2007 and 2006, our discontinued operations had net
cash flows provided by (used in) operating activities of approximately $38.8 million,
$26.3 million and $(1.4) million, respectively. These net cash flows were substantially
offset by net cash used by investing activities of approximately $34.7 million, $25.5
million and $10.7 million during 2008, 2007 and 2006, respectively. We do not expect the
sale of our discontinued operations to have a material effect on cash flows in 2009, excluding
the proceeds from the sale.
In addition to cash flows from operations, we have utilized issuances of debt and equity
securities to enhance our liquidity and support the execution of our strategic objectives.
Significant issuances and repayments of debt and equity, as well as the uses of the net proceeds,
in 2008, 2007 and 2006 were as follows:
| repaid the outstanding balance of the second lien term loan in the first quarter of 2008; |
| issued $40 million of the 11.5% convertible bonds in the first quarter of 2008; |
| in the fourth quarter of 2006 in conjunction with the Talisman Acquisition, we issued |
| 37.8 million shares of common stock for $89 million in gross proceeds, |
| 125,000 shares of Series C Convertible Preferred Stock for $125 million in gross proceeds, |
| $150 million in a senior bank debt facility, before financing costs of $3.2 million, and |
| $75 million in a second lien term loan, before financing costs of $2.6 million. |
See Note 9 to the Consolidated Financial Statements for additional discussion of our debt.
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Endeavour International Corporation
Cash flow from operations increased to $133.2 million for 2008 primarily due to higher realized
commodity prices that were substantially offset by increased current taxes. The increased revenues
generated by a full year of operations of our acquired assets were primarily responsible for the
cash flows provided by operations of $128.5 million for 2007 versus the $13.2 million used by
operations in 2006.
Our revenues and cash flows from operating activities are sensitive to changes in prices received
for our products. Our production is sold at prevailing market prices which fluctuate in response
to many factors that are outside of our control. Given the current tightly balanced supply-demand
market, small variations in either supply or demand, or both, can have dramatic effects on prices
we receive for our oil and natural gas production. While the market price received for oil and
natural gas varies among geographic areas, oil trades in a worldwide market, whereas natural gas,
which is still developing a global transportation system, is more subject to local supply and
demand conditions. Consequently, price movements for all types and grades of crude oil generally
move in the same direction. Natural gas prices in the North Sea have been influenced by fuel
prices around the world, including crude oil and coal. These prices are also impacted by European
gas supplies, particularly deliveries from Russian gas supplies. In addition, regional supply and
demand issues affect gas prices. The majority of our natural gas is sold in the UK market. Market
prices for both oil and natural gas were at historically high levels during 2006 and oil prices
continued their high levels throughout much of 2007 and 2008. North Sea gas prices declined in the
first quarter of 2007 but recovered in the second half of the year and remained strong during 2008.
Both crude oil and natural gas prices have declined in 2009 as a result of the global economic
decline.
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, including non-financial performance indicators and non-GAAP
measures as key metrics to manage our business. These key metrics demonstrate the companys
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, discretionary cash flow, adjusted earnings before interest,
taxes, depreciation, depletion and amortization (Adjusted EBITDA) and adjusted net income.
Net Income (Loss) as Adjusted, Adjusted EBITDA and Discretionary Cash Flow are internal,
supplemental measures of our performance that are not required by, or presented in accordance with,
GAAP. We use these non-GAAP measures as internal measures of performance and to aid in our
budgeting and forecasting processes. We view these non-GAAP measures, and we believe that others
in the oil and gas industry view these, or similar, non-GAAP measures, as commonly used analytic
indicators to compare performance among companies. We further believe that these non-GAAP measures
are frequently used by securities analysts, investors, and other interested parties in the
evaluation of issuers, many of which present these measures when reporting their results. We
believe these non-GAAP measures provide useful information to both management and investors to gain
an overall understanding of our current financial performance and provide investors with financial
measures that most closely align to our internal measurement processes. Since the application of
mark-to-market accounting has the effect of pulling forward into current periods non-cash gains and
losses related to commodity derivatives relating to future delivery periods, analysis of results of
operations from one period to another can be difficult. We believe that excluding these unrealized
non-cash gains and losses related to commodity derivatives and currency exchange changes provides a
more meaningful representation of our economic performance in the reporting period and is therefore
useful to us, investors, analysts and others in
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Endeavour International Corporation
facilitating the analysis of our results of operations from one period to another. These measures
should not be considered as measures of financial performance under GAAP, and the items excluded
from these measures are significant components in understanding and assessing financial
performance.
These non-GAAP measures should not be considered in isolation or as an alternative to net income,
operating income or any other performance measures derived in accordance with GAAP or as
alternatives to cash flows generated by operating, investing or financing activities as a measure
of our liquidity. Because Net Income (Loss) as Adjusted, Adjusted EBITDA and Discretionary Cash
Flow are not measurements determined in accordance with GAAP and thus susceptible to varying
calculations, Net Income (Loss) as Adjusted, Adjusted EBITDA and Discretionary Cash Flow as
presented may not be comparable to other similarly titled measures of other companies.
Net Income (Loss) as Adjusted, Adjusted EBITDA and Discretionary Cash Flow have limitations as an
analytical tool, and you should not consider these measures in isolation, or as a substitute for
analysis of our financial statement data presented in the consolidated financial statements as
reported under GAAP. For example, Net Income (Loss) as Adjusted, Adjusted EBITDA and Discretionary
Cash Flow may not reflect:
| our cash expenditures, or future requirements, for capital expenditures or contractual commitments; |
| changes in, or cash requirements for, our working capital needs; |
| unrealized gains (losses) on derivatives; |
| non-cash foreign currency gains (losses); |
| our interest expense, or the cash requirements necessary to service interest and principal payments on our debts; |
| our preferred stock dividend requirements; and |
| depreciation, depletion and amortization. |
Because of these limitations, Net Income (Loss) as Adjusted, Adjusted EBITDA and Discretionary Cash
Flow should not be considered as measures of cash available to us to invest in the growth of our
business. We compensate for these limitations by relying primarily on our GAAP results and by
using Net Income (Loss) as Adjusted, Adjusted EBITDA and Discretionary Cash Flow only
supplementally.
As required under Regulation G of the Securities Exchange Act of 1934, provided below are
reconciliations of net income (loss) to the following non-GAAP financial measures: net income as
adjusted, Adjusted EBITDA and discretionary cash flow.
(in thousands, except per share) | December 31, | |||||||||||
2008 | 2007 | 2006 | ||||||||||
Net income (loss) |
$ | 56,490 | $ | (49,077 | ) | $ | (6,838 | ) | ||||
Depreciation, depletion and amortization |
81,734 | 76,850 | 20,164 | |||||||||
Impairment of oil and gas properties |
36,970 | | 849 | |||||||||
Deferred tax expense (benefit) |
17,682 | (12,926 | ) | 13,038 | ||||||||
Unrealized (gain) loss on derivative instruments |
(76,666 | ) | 89,132 | (34,531 | ) | |||||||
Amortization of non-cash compensation |
3,226 | 4,968 | 11,573 | |||||||||
Amortization of loan costs and discount |
7,279 | 1,655 | 731 | |||||||||
Other |
(5,940 | ) | 2,373 | 154 | ||||||||
Discretionary cash flow |
$ | 120,775 | $ | 112,975 | $ | 5,140 | ||||||
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Endeavour International Corporation
(in thousands, except per share) | December 31, | |||||||||||
2008 | 2007 | 2006 | ||||||||||
Net income (loss) to common shareholders, as reported |
$ | 45,681 | $ | (60,315 | ) | $ | (8,829 | ) | ||||
Impairment of oil and gas properties (net of 50% tax) |
18,485 | | 424 | |||||||||
Unrealized (gains) losses on commodity derivatives
(net of 50% tax) |
(38,923 | ) | 44,566 | (17,266 | ) | |||||||
Unrealized (gains) losses on embedded derivatives |
1,180 | | | |||||||||
Currency impact of deferred taxes |
(20,709 | ) | 4,842 | 4,773 | ||||||||
Net income (loss) to common shareholders as adjusted |
$ | 5,714 | $ | (10,907 | ) | $ | (20,898 | ) | ||||
Net income (loss) to common shareholders, as reported |
$ | 45,681 | $ | (60,315 | ) | $ | (8,829 | ) | ||||
Unrealized (gains) losses on derivatives |
(76,666 | ) | 89,132 | (34,531 | ) | |||||||
Net interest expense |
21,301 | 16,430 | 5,676 | |||||||||
Depreciation, depletion and amortization |
81,734 | 76,850 | 20,164 | |||||||||
Impairment of oil and gas properties |
36,970 | | 849 | |||||||||
Income tax expense (benefit) |
56,729 | (9,180 | ) | 23,913 | ||||||||
Preferred stock dividends |
10,809 | 11,238 | 1,991 | |||||||||
Adjusted EBITDA |
$ | 176,558 | $ | 124,155 | $ | 9,233 | ||||||
Discretionary cash flow is equal to cash flow from operating activities before the changes in
operating assets and liabilities.
Outlook
2009 Capital Program
We currently anticipate spending approximately $50 - $60 million during 2009 to fund oil and gas
exploration, production and development activities in our core areas of operation in the North Sea
and the U.S., excluding our discontinued operations. As in 2008, we intend to finance this capital
program through our cash flow generated from operations. To the extent our cash flow from
operations is unable to completely finance our capital program, we will postpone certain proposed
capital projects until our capital spending does not exceed our available resources. However, we
believe our existing production base, combined with our commodity derivatives in place, should
generate sufficient cash flows to fund our ongoing operations and capital program.
A significant portion of our 2009 capital program will be directed towards developing our three
major projects in the UK sector of the North Sea, the Rochelle, Cygnus and Columbus prospects. In
addition, we expect to spend approximately $12 million to $15 million on infield drilling and
facilities improvements to maintain production levels on our producing properties. Lastly, we also
intend to continue our exploration activities in both the North Sea and the US, subject to the
availability of sufficient capital.
The timing, completion and process of our 2009 capital program is subject to a number of factors,
including availability of capital, drilling results, drilling and production costs, availability of
drilling services and equipment, partner approvals and
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Endeavour International Corporation
technical work. Based on these and other factors, we may increase or decrease our planned capital
program or prioritize certain projects over others.
Revenues and Production
We expect production for 2009 to range from 4,000 to 5,000 BOE per day, with approximately 50% of
that production as gas. We anticipate this decline in production from 2008 due to normal
production declines and the suspension of production at three of our fields as discussed below.
With development programs for Columbus, Cygnus and Rochelle, we expect significant increases in
production beginning in the fourth quarter of 2010 when we anticipate the start of production at
Rochelle. We anticipate Columbus and Cygnus to begin production in 2011. When all three projects
are fully producing, they have the potential to equal our 2008 production levels from all other
fields.
Our IVRRH, Renee and Rubie fields all produce to a single floating production facility that has
experienced significant increases in operating costs in recent periods. With the decline in oil
prices and the rising operating costs, the operator has decided to cease operations and begin
removal and salvage procedures at that floating production facility. As a result, we expect to
suspend production at these fields by the end of the first quarter 2009. The production from these
fields will be suspended until the development activities at Rochelle are operational which we
currently anticipate to be late 2010. After the start of Rochelle production, we expect to
re-develop IVRRH, Renee and Rubie if economically feasible. We also expect to incur approximately
$10 million of abandonment costs for the facility, before salvage value, by mid 2010.
Oil prices continued to be impacted by supply and demand on a worldwide basis, while natural gas
prices are more impacted by regional economic and weather patterns. Oil prices continue to
decrease since year-end 2008 and natural gas prices in the UK, the market for the majority of our
gas production, have recovered due primarily to return to normal weather conditions. For 2009, we
expect realized prices before derivatives to be $0.10 - $0.20 per Mcf less than the National
Balance Point price for gas and $5.50 - $6.50 per Bbl less than the Dated Brent price for oil. We
have commodity derivative instruments to secure our realized prices for a portion of our oil and
gas production through 2011. See Note 16 to the Consolidated Financial Statements herein for more
discussion of our commodity derivative instruments.
We expect operating costs per BOE to be in the range of $9.50 to $12.00 per BOE for 2009.
Commodity prices can also affect our operating cash flow through an indirect effect on operating
expenses. Significant commodity price volatility, as experienced in recent years, can lead to
fluctuations in drilling and development activities. As a result, the demand and cost for people,
services, equipment and materials may also increase or decrease following worldwide drilling
levels, causing an impact on our cash flow.
Liquidity and Financial Resources
Our primary sources of financial resources and liquidity are internally generated cash flows from
operations and access to the credit and capital markets, to the extent available. We believe the
combination of our available cash on hand, cash flow from operations, our ability to time capital
expenditures and our flexible 2009 capital program and related obligations will allow us to manage
volatile markets while enabling us to further our strategic objectives.
We expect to fund our 2009 capital requirements through internally generated cash flow from
operations. These cash flows will be significantly impacted by the amount of hydrocarbons we
produce, and to a lesser extent, the price we obtain for our produced commodities. Oil prices
continue to be impacted by supply and demand on a worldwide basis, while natural gas prices are
more impacted by regional
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Endeavour International Corporation
economic and weather patterns. Although oil prices have declined significantly since the record
high prices in the summer of 2008, natural gas prices in the UK and Norway have not experienced as
steep of a decline. While we expect revenues to decline from 2008 to 2009 as a result of the sharp
decline in oil prices, the full impact on our cash flows will be partially mitigated by our balance
of gas to oil production and our commodity derivative positions. As of December 31, 2008, our
outstanding commodity derivatives covered 55% to 65% of expected 2009 production.
We have historically utilized a combination of borrowings under our bank facility and accessing the
capital markets to fund our operations, capital projects or strategic acquisitions. The worldwide
credit and capital markets have recently experience significant disruptions and exhibited adverse
conditions. Continued volatility in the credit and capital markets may substantially restrict our
ability to access these markets or increase costs associated with issuing debt instruments due to,
among other things, increased spreads over relevant interest rate benchmarks and affect our ability
to access those markets. We do not believe our liquidity has been materially affected by the
recent events in the global financial markets as we have not required these financing alternatives.
Further, we do not expect our liquidity to be materially impacted in the near future as we intend
to exercise strict fiscal discipline in matching our future expenditures with cash flow from
operations. Nevertheless, we will continue to monitor our capital requirements, the credit and
capital markets and circumstances surrounding each of the lenders in our senior bank facility. To
date we have experienced no disruptions in our ability to access additional funding through our
senior facility. However, we cannot predict with any certainty the impact to us of any further
disruption in the credit environment.
At December 31, 2008, we had $113 million outstanding under our senior bank facility. The senior
bank facility has a current borrowing base capacity of $126 million, which is secured by our oil
and gas assets. The borrowing base is subject to redetermination every six months (on April 1 and
October 1), and we are required to provide our lenders with an independent reserve report every 12
months. Based on our reserve report at December 31 and June 30 each year, commodity prices set by
our lenders and terms set forth in the credit agreement, the maximum capacity of our borrowing base
is set, and any amounts outstanding over the redetermined borrowing base must be repaid within 45
days of the redetermination date. The senior bank facility is also subject to maximum commitment
levels by the participating lenders that change over time.
We have reflected $13 million in current maturities of long-term debt at December 31, 2008 due to
the borrowing base capacity and maximum commitment levels. The next scheduled redetermination of
our borrowing base will occur on April 1, 2009. We are currently undergoing the redetermination
process based on our reserve report as of December 31, 2008. We cannot estimate the level of the
borrowing base capacity that will be in effect as of April 1, 2009 although we do expect the
borrowing base capacity to decrease given the decline in commodity prices during 2008. We expect
to repay amounts outstanding in excess of the redetermined borrowing base with cash on hand. This
will reduce the amount of cash on hand that is immediately available for our capital program.
Consistent with our strict financial discipline, we continue to manage our capital expenditures to
stay within generated cash flows while anticipating additional debt repayments.
The terms of our credit agreement provide that the borrowing base capacity may be increased as
projects are approved by the applicable authority. We currently have submitted development plans
for approval for both our Cygnus and Columbus projects and anticipate submitting a plan for the
Rochelle development during 2009. As these development plans are approved, we expect to include
the new projects in the borrowing base assets and believe that this will result in an increase of
our borrowing base capacity.
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Endeavour International Corporation
The senior bank facility also provides for issuances of letters of credit of up to an aggregate $60
million. While all letters of credit issued under the senior bank facility will reduce the total
amount available for drawing under the senior bank facility, letters of credit issued to secure
abandonment liabilities in respect of borrowing base assets will not reduce the amount available
under the borrowing base. As of December 31, 2008, we have $30.1 million of outstanding letters of
credit related to abandonment liabilities on certain of our oil and gas properties.
In January 2008, we completed the refinancing of certain debt utilizing a strategic investment by
the Smedvig Family Office in Norway. Included in this refinancing were: the repayment of our
Second Lien Term Loan, plus accrued interest; issuance of $40 million under a private offering of
11.5% guaranteed convertible bonds due 2014; and borrowing of $25 million under a Junior Credit
Facility. Amounts borrowed under the Junior Facility were repaid in full during 2008. The Smedvig
Family also committed an additional $60 million for future investments with us.
Our income tax expense relates primarily to our operations in the UK (statutory income tax rate of
50%) and to our operations in Norway (statutory income tax rate of 78%). We are currently not able
to record income tax benefits on our U.S. loss as there is no assurance that we can generate any
U.S. taxable earnings. As operations commence in the U.S. during 2009, we will be able to record
income tax benefits in the U.S. and do not anticipate paying current taxes in the U.S.
Off-Balance Sheet Arrangements
At December 31, 2008, we did not have any off-balance sheet arrangements.
Rig Commitments
Our rig commitments reflect two commitments for the use of drilling rigs in our North Sea
operations. Our continuing operations include one commitment for the drilling rig that
commenced drilling at the Rochelle field in December 2008. We have $21 million in escrow toward
this commitment, included in Restricted cash on our Condensed Consolidated Balance Sheet. The
reserved amounts in escrow will be released as payments are made for this drilling activity.
Our discontinued operations included a commitment for a semi-submersible rig in Norway through a
consortium with several other operators in the Norwegian Continental Shelf. The contract committed
us to 100 days (for two wells) for drilling services for $38 million. We estimated the rig to be
initially delivered in the third quarter of 2009 and again in 2010.
Critical Accounting Policies and Estimates
The accompanying financial statements have been prepared on the accrual basis of accounting in
accordance with accounting principles generally accepted in the United States of America and have
been presented on a going concern basis, which contemplates the realization of assets and
satisfaction of liabilities in the normal course of business. These accounting principles require
management to use estimates, judgments and assumptions that affect the reported amounts of assets
and liabilities as of the date of the financial statements, and revenues and expenses during the
reporting period. Management reviews its estimates, including those related to the determination
of proved reserves, estimates of future dismantlement costs, income taxes and litigation. Actual
results could differ from those estimates.
Management believes it is reasonably possible that the following material estimates affecting the
financial statements could change in the coming year: (1) estimates of proved oil and gas reserves,
(2) estimates as
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Endeavour International Corporation
to the expected future cash flow from proved oil and gas properties, (3) estimates of future
dismantlement and restoration costs, (4) estimates of fair values used in purchase accounting and
(5) estimates of the fair value of derivative instruments. In addition, alternatives may exist
among various accounting methods. In such cases, the choice of accounting method may also have a
significant impact on reported amounts.
Our critical accounting policies are as follows:
Full Cost Accounting
Under the full cost method, all acquisition, exploration and development costs, including certain
directly related employee costs and a portion of interest expense, incurred for the purpose of
finding oil and gas are capitalized and accumulated in pools on a country-by-country basis.
Capitalized costs include the cost of drilling and equipping productive wells, including the
estimated costs of dismantling and abandoning these assets, dry hole costs, lease acquisition
costs, seismic and other geological and geophysical costs, delay rentals and costs related to such
activities. Employee costs associated with production and other operating activities and general
corporate activities are expensed in the period incurred.
Capitalized costs are limited on a country-by-country basis (the ceiling test). The ceiling test
limitation is calculated as the sum of the present value of future net cash flows related to
estimated production of proved reserves, using end-of-the-current-period prices including the
effect of derivative instruments that qualify as cash flow hedges, discounted at 10%, plus the
lower of cost or estimated fair value of unproved properties, all net of expected income tax
effects. Under the ceiling test, if the capitalized cost of the full cost pool, net of deferred
taxes, exceeds the ceiling limitation, the excess is charged as an impairment expense.
We utilize a single cost center for each country where we have operations for amortization
purposes. Any conveyances of properties are treated as adjustments to the cost of oil and gas
properties with no gain or loss recognized unless the operations are suspended in the entire cost
center or the conveyance is significant in nature.
Unproved property costs include the costs associated with unevaluated properties and properties
under development and are not included in the full cost amortization base (where proved reserves
exist) until the project is evaluated. These costs include unproved leasehold acreage, seismic
data, wells and production facilities in progress and wells pending determination, together with
interest costs capitalized for these projects. Seismic data costs are associated with specific
unevaluated properties where the seismic data is acquired for the purpose of evaluating acreage or
trends covered by a leasehold interest owned by us. Significant unproved properties are assessed
periodically for possible impairment or reduction in value. If a reduction in value has occurred,
these property costs are considered impaired and are transferred to the related full cost pool.
Geological and geophysical costs included in unproved properties are transferred to the full cost
amortization base along with the associated leasehold costs on a specific project basis. Costs
associated with wells in progress and wells pending determination are transferred to the
amortization base once a determination is made whether or not proved reserves can be assigned to
the property. Costs of dry holes are transferred to the amortization base immediately upon
determination that the well is unsuccessful. Unproved properties whose acquisition costs are not
individually significant are aggregated, the portion of such costs estimated to be ultimately
nonproductive, based on experience, are amortized to the full cost pool over an average holding
period.
In countries where the existence of proved reserves has not yet been determined, unevaluated
property costs remain capitalized in unproved property cost centers until proved reserves have been
established, exploration activities cease or impairment and reduction in value occurs. If
exploration activities result in
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Endeavour International Corporation
the establishment of a proved reserve base, amounts in the unproved property cost center are
reclassified as proved properties and become subject to amortization and the application of the
ceiling test. When it is determined that the value of unproved property costs have been permanently
diminished (in part or in whole) based on the impairment evaluation and future exploration plans,
the unproved property cost centers related to the area of interest are impaired, and accumulated
costs charged against earnings.
We capitalize interest on expenditures for significant exploration and development projects while
activities are in progress to bring the assets to their intended use. Capitalized interest is
calculated by multiplying our weighted-average interest rate on debt by the amount of qualifying
costs and is limited to gross interest expense. As costs are transferred to the full cost pool,
the associated capitalized interest is also transferred to the full cost pool.
Business Combinations
Accounting for the acquisition of a business requires the allocation of the purchase price to the
various assets and liabilities of the acquired business and recording deferred taxes for any
differences between the allocated values and tax basis of assets and liabilities. Any excess of
the purchase price over the amounts assigned to assets and liabilities is recorded as goodwill. In
connection with the several acquisitions, we recorded goodwill for the excess of the purchase price
over the value assigned to individual assets acquired and liabilities assumed. Our fair value
estimates for the acquisition are subject to change as additional information becomes available and
is assessed.
Purchase Price Allocation
The purchase price allocation is accomplished by recording the asset or liability at its estimated
fair value. We use all available information to make these fair value determinations, including
information commonly considered by our engineers in valuing individual oil and gas properties and
sales prices for similar assets. Estimated deferred taxes are based on available information
concerning the tax basis of the acquired companys assets and liabilities and carryforwards at the
merger date, although such estimates may change in the future as additional information becomes
known. The amount of goodwill recorded in any particular business combination can vary
significantly depending upon the values attributed to assets acquired and liabilities assumed
relative to the total acquisition cost.
Goodwill and Intangible Assets
Goodwill represents the excess of the purchase price over the estimated fair value of the assets
acquired and liabilities assumed in an acquisition. Intangible assets represent the purchase price
allocation to the assembled workforce as a result of the acquisition of NSNV, Inc. We assess the
carrying amount of goodwill and other indefinite-lived intangible assets by testing the asset for
impairment annually at year-end, or more frequently if events or changes in circumstances indicate
that the asset might be impaired. The impairment test requires allocating goodwill and all other
assets and liabilities to reporting units. The fair value of each reporting unit is determined and
compared to the book value of the reporting unit. An impairment loss is recognized to the extent
that the carrying amount exceeds the assets fair value.
At December 31, 2008, we had $282 million of goodwill recorded related to past business
combinations. This goodwill is not amortized, but is required to be assessed for impairment
annually, or more often as facts and circumstances warrant. The first step of that process is to
compare the fair value of the reporting unit to which goodwill has been assigned to the carrying
amount of the associated net assets and goodwill. The reporting units used to evaluate and measure
goodwill for impairment are determined from the manner in which the business is managed. We have
determined we have a single reporting unit. Goodwill is tested annually at year end. Although we
cannot predict when or if goodwill will be
16
Endeavour International Corporation
impaired, impairment charges may occur if we are unable to replace the value of our depleting asset
base or if other adverse events (for example, lower sustained oil and gas prices) reduce the fair
value of the reporting unit.
We completed our 2008 annual goodwill impairment test with no impairment indicated. To determine
the fair value of the company, we worked with a valuation consulting firm and used all available
information, such as market multiples, the present values of expected cash flows and the effect of
the announcement of drilling results (where such drilling had begun.)
In the determination of the present value of expected cash flows, we assumed production profiles
consistent with our year-end estimation of reserves that are disclosed in our supplemental oil and
gas disclosures, market prices considering the forward price curve for oil and gas, adjusted for
location and quality differentials that we currently receive, as well as capital and operating
costs consistent with year-end pricing, adjusted for managements view that such costs should
decline in the near term to realign with lower commodity prices, and discount rates that management
believes a market participant would utilize to consider the risks inherent in our operations.
We also considered our market capitalization based on average stock prices for 20 days around
December 31, 2008 and any premium a buyer might pay to obtain control of Endeavour. As part of
this analysis, we considered the relatively few transactions in the market, trading multiples for
peers to determine an appropriate multiple to apply against our projected EBITDA, cash flows and
reserves and the material results of our drilling program that were not publicly available at
December 31, 2008. In the first quarter of 2009, we announced the successful drilling results of
wells at our Cygnus and Rochelle projects and the expansion of operations into the US. While these
activities were initiated in 2008, the public markets were unaware of the positive outcomes until
2009. From December 31, 2008 through February 10, 2009 (the date of the last of these three
announcements), our common stock price increased 50%, from $0.50 per share to $0.74 per share,
respectively.
A lower fair value estimate in the future could result in impairment. Examples of factors that
could cause a lower fair value estimate could be sustained declines in prices, increases in costs,
and changes in discount rate assumptions due to market conditions.
Dismantlement, Restoration and Environmental Costs
We recognize liabilities for asset retirement obligations associated with tangible long-lived
assets, such as producing well sites, offshore production platforms, and natural gas processing
plants, with a corresponding increase in the related long-lived asset. The asset retirement cost
is depreciated along with the property and equipment in the full cost pool. The asset retirement
obligation is recorded at fair value and accretion expense, recognized over the life of the
property, increases the liability to its expected settlement value. If the fair value of the
estimated asset retirement obligation changes, an adjustment is recorded for both the asset
retirement obligation and the asset retirement cost.
Revenue Recognition
We use the entitlements method to account for sales of gas production. We may receive more or less
than our entitled share of production. Under the entitlements method, if we receive more than our
entitled share of production, the imbalance is treated as a liability at the market price at the
time the imbalance occurred. If we receive less than our entitled share, the imbalance is recorded
as an asset at the lower of the current market price or the market price at the time the imbalance
occurred. Oil revenues are recognized when production is sold to a purchaser at a fixed or
determinable price, when delivery has occurred, title has transferred and collectibility of the
revenue is probable.
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Endeavour International Corporation
Derivative Instruments and Hedging Activities
From time to time, we may utilize derivative financial instruments to hedge cash flows from
operations or to hedge the fair value of financial instruments. We may use derivative financial
instruments with respect to a portion of our oil and gas production or a portion of our variable
rate debt to achieve a more predictable cash flow by reducing our exposure to price fluctuations.
These transactions are likely to be swaps, collars or options and to be entered into with major
financial institutions or commodities trading institutions. Derivative financial instruments are
intended to reduce our exposure to declines in the market prices of crude oil and natural gas that
we produce and sell, to increases in interest rates and to manage cash flows in support of our
annual capital expenditure budget. We also have two embedded derivatives related to our debt
instruments.
We record all derivatives at fair market value in our Consolidated Balance Sheets at the end of
each period. The accounting for the fair market value, and the changes from period to period,
depends on the intended use of the derivative and the resulting designation. This evaluation is
determined at each derivatives inception and begins with the decision to account for the
derivative as a hedge, if applicable. The accounting for changes in the fair value of a derivative
instrument that is not accounted for as a hedge is included in other (income) expense as an
unrealized gain or loss. Where we intend to account for a derivative as a hedge, we document, at
its inception, the hedging relationship, the risk management objective and the strategy for
undertaking the hedge. The documentation includes the identification of the hedging instrument,
the hedged item or transaction, the nature of the risk being hedged, and the method that will be
used to assess effectiveness of derivative instruments that receive hedge accounting treatment.
Changes in fair value to hedge instruments, to the extent the hedge is effective, are recognized in
other comprehensive income until the forecasted transaction occurs. Hedge effectiveness is
assessed at least quarterly based on total changes in the derivatives fair value. Any ineffective
portion of the derivative instruments change in fair value is recognized immediately in other
(income) expense.
We discontinue hedge accounting prospectively when (1) we determine that the derivative is no
longer effective in offsetting changes in the fair value or cash flows of a hedged item (including
hedged items such as firm commitments or forecasted transactions); (2) the derivative expires; (3)
it is no longer probable that the forecasted transaction will occur; (4) a hedged firm commitment
no longer meets the definition of a firm commitment; or (5) management determines that designating
the derivative as a hedging instrument is no longer appropriate.
Income Taxes
We use the liability method of accounting for income taxes under which deferred tax assets and
liabilities are recognized for the estimated future tax consequences attributable to differences
between the financial statement carrying amounts of existing assets and liabilities, and their
respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates in
effect for the year in which those temporary differences are expected to be recovered or settled.
The effect on deferred tax assets and liabilities of a change in tax rates is recognized as part of
the provision for income taxes in the period that includes the enactment date. Deferred tax assets
are reduced by a valuation allowance when, in the opinion of management, it is more likely than not
that some portion of, or all of, the deferred tax assets will not be realized.
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Endeavour International Corporation
Stock-Based Compensation Arrangements
We recognize all share-based payments to employees, including grants of employee stock options,
based on their fair values. The share-based compensation cost is measured at the grant date, based
on the calculated fair value of the award, and is recognized as general and administrative expense
over the employees requisite service period (generally the vesting period of the equity award).
We apply the fair value method in accounting for stock option grants to non-employees using the
Black-Scholes Method.
It is our policy to use authorized but unissued shares of stock when stock options are exercised.
At December 31, 2008, we had approximately 7.7 million additional shares available for issuance
pursuant to our existing stock incentive plan.
Fair Value
We estimate fair value for the measurement of derivatives, long-lived assets during certain
impairment tests, reporting units for goodwill impairment testing and the initial measurement of an
asset retirement obligation. When we are required to measure fair value, and there is not a market
observable price for the asset or liability, or a market observable price for a similar asset or
liability, we generally utilize an income valuation approach. This approach utilizes managements
best assumptions regarding expectations of projected cash flows, and discounts the expected cash
flows using a commensurate risk adjusted discount rate. Such evaluations involve a significant
amount of judgment since the results are based on expected future events or conditions, such as
sales prices; estimates of future oil and gas production; development and operating costs and the
timing thereof; economic and regulatory climates and other factors. Our estimates of future net
cash flows are inherently imprecise because they reflect managements expectation of future
conditions that are often outside of managements control. However, assumptions used reflect a
market participants view of long-term prices, costs and other factors, and are consistent with
assumptions used in our business plans and investment decisions.
Recent Accounting Pronouncements
In December 2007, the FASB issued enhanced guidance related to the measurement of identifiable
assets acquired, liabilities assumed and disclosure of information related to business combinations
and their effect. The standard applies prospectively to business combinations in 2009 and is not
subject to early adoption. We are currently evaluating the potential impact of this new guidance
on business combinations and related valuations.
In December 2007, the FASB issued a new standard for the noncontrolling interest in a subsidiary
and for the deconsolidation of a subsidiary. Specifically, this statement requires the recognition
of a noncontrolling interest (minority interest) as a component of consolidated equity. This is a
change from the current practice to present noncontrolling interests in liabilities or between
liabilities and stockholders equity. Similarly, the new standard requires consolidated net income
and comprehensive income to be reported at amounts that include the amounts attributable to both
the parent and the noncontrolling interests. The standard is effective prospectively with respect
to transactions involving noncontrolling financial interests that occur on or after January 1,
2009. We are currently evaluating the potential impact, if any, of this new guidance.
In March 2008, the FASB issued a new standard that requires entities to present expanded and
detailed financial statement disclosures for their derivatives and hedged financial instruments.
This standard applies to all derivatives and non-derivative instruments designated and qualifying
as hedges, including bifurcated derivative instruments and related hedged items. The new standard
is effective for interim
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Endeavour International Corporation
periods and fiscal years beginning after November 15, 2008. We do not expect the adoption of this
pronouncement to have a material impact on our financial position or results of operations.
In May 2008, the FASB posted a new staff position that applies to convertible debt that may be
settled in part or in whole in cash upon conversion. The new staff position requires required
issuers of this form of debt to account for its debt and equity components separately. The new
position also expands the definition of convertible preferred shares of an entitys stock that are
mandatorily redeemable financial instruments classified as liabilities. The new FASB staff
position is effective for financial statements issued for fiscal years after December 15, 2008 and
interim period within those fiscal years. It must be applied retroactively to all presented
periods. We are currently evaluating the potential impact, if any, of this new guidance.
In June 2008, the FASB issued a new staff position that addresses whether instruments that are
granted in share-based payment transactions are participating securities prior to vesting; and
therefore are required to be included in the earnings allocation in the calculation of earnings per
share (EPS) under the two-class method as described in a prior FASB standard. The new staff
position requires entities to treat unvested share-based payment awards with non-forfeitable rights
to dividend or dividend equivalents as a separate class of securities in calculating EPS. The new
staff position is effective for fiscal years beginning after December 15, 2008. We are currently
evaluating the potential impact, if any, of this new guidance.
Disclosures about Contractual Obligations and Commercial Commitments
The following table sets forth our obligations and commitments for continuing operations to make future payments under
its lease agreements and other long-term obligations as of December 31, 2008:
(Amounts in thousands) | Payments due by Period | |||||||||||||||||||
Less than 1 | ||||||||||||||||||||
Contractual Obligations | Total | Year | 1-3 Years | 3-5 Years | After 5 Years | |||||||||||||||
Long-term debt |
||||||||||||||||||||
Principal (1) |
$ | 238,746 | $ | 13,000 | $ | 100,000 | $ | 81,250 | $ | 44,496 | ||||||||||
Interest (2) |
55,839 | 7,766 | 13,125 | 406 | 34,542 | |||||||||||||||
Asset retirement obligations |
38,776 | 9,680 | 160 | 160 | 28,776 | |||||||||||||||
Operating leases for office
leases and equipment |
2,743 | 1,157 | 1,349 | 237 | | |||||||||||||||
Rig commitments (3) |
20,739 | 20,739 | | | | |||||||||||||||
Total Contractual Obligations |
$ | 356,843 | $ | 52,342 | $ | 114,634 | $ | 82,053 | $ | 107,814 | ||||||||||
(1) | Repayment of the initial borrowing base on the senior bank facility is based on reserve estimates, which are reassessed every six months. | |
(2) | Assumes a 1.5% LIBOR rate. In addition, interest on our 11.5% convertible debt is added to the outstanding principal balance each quarter and reflected as due upon maturity. | |
(3) | As is common in the oil and gas industry, we operate in many instances through joint ventures under joint operating or similar agreements. Typically, the operator under a joint operating agreement enters into contracts, such as rig commitment contracts, for the benefit of all joint venture partners. Through the joint operating agreement, the non-operators reimburse, and in some cases advance, the funds necessary to meet the contractual obligations entered into by the operator. These obligations are typically shared on a working interest basis. The joint operating agreement provides remedies to the operator in the event that the non-operator does not satisfy its share of the contractual obligations. Occasionally, the operator is permitted by the joint operating agreement to enter into lease obligations and other contractual commitments that are |
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Endeavour International Corporation
then passed on to the non-operating joint interest owners as lease operating expenses, frequently without any identification as to the long-term nature of any commitments underlying such expenses. |
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