United States
Securities and Exchange Commission
Washington, D.C. 20549
Form 10-K
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Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the Fiscal Year Ended
December 31, 2010 |
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Transition Report Under Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from
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Commission file number: 001-32212
Endeavour International Corporation
(Exact name of registrant as specified in its charter)
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Nevada
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88-0448389 |
(State or other jurisdiction of incorporation or organization)
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(I.R.S. Employer Identification No.) |
1001 Fannin Street, Suite 1600, Houston, Texas 77002
(Address of principal executive offices) (Zip code)
(713) 307-8700
(Registrants telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
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Title of Each Class of Stock
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Name of Each Exchange on Which Registered |
Common Stock $0.001 par value per share
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NYSE-Amex |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer as defined in Rule 405 of the Securities Act. o Yes þ No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. o Yes þ No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. þ Yes o No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data
File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 2 months (or for
such shorter period that the registrant was required to submit and post such files). o Yes o No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of registrants knowledge, in definitive proxy or information statements incorporated by reference in Part III of this
Form 10-K or any amendment to this Form 10-K. þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting
company. See definition of large accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act:
Large accelerated filer o |
Accelerated filer
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Non-accelerated filer o (Do not check if a smaller reporting company) | Smaller reporting company
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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). o Yes þ No
The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant was $152.0 million computed by
reference to the closing sale price of the registrants common stock on the NYSE-Amex on June 30, 2010, the last business day of the registrants
most recently completed second fiscal quarter. Shares of common stock held by executive officers and directors of the registrant are not included
in the computation.
As of February 28, 2011, 24,882,292 shares of the registrants common stock were outstanding.
Documents
Incorporated By Reference:
Portions of the registrants definitive proxy statement relating to the 2011 Annual Meeting of Stockholders, which will be filed within 120 days
of December 31, 2010, are incorporated by reference into Part III of this Annual Report on Form 10-K.
Table of Contents
Quantities of natural gas are expressed in this Annual Report on Form 10-K in terms of
thousand cubic feet (Mcf) and million cubic feet (MMcf). Oil is quantified in terms of barrels
(Bbls) and thousands of barrels (Mbbls). Natural gas is compared to oil in terms of barrels of oil
equivalent (BOE), thousand barrels of oil equivalent (MBOE) or million barrels of oil equivalent
(MMBOE). One barrel of oil is the approximate energy equivalent of six Mcf of natural gas. This
is a physical correlation and does not reflect a value or price relationship between the
commodities. With respect to information relating to our working interest in wells or acreage,
net oil and gas wells or acreage is determined by multiplying gross wells or acreage by our
working interest therein. References to number of potential well locations are gross, unless
otherwise indicated.
References to GAAP refer to U.S. generally accepted accounting principles.
Endeavour International Corporation
Part I
Item 1. Business
Unless the context otherwise requires, references to Endeavour, we, us or our mean
Endeavour International Corporation and its consolidated subsidiaries.
Our Company
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.S. and the North Sea. Our strategy is to
expand and exploit our balanced portfolio of exploration and development assets using conventional
and unconventional technologies in basins that have historically generated and produced substantial
quantities of oil and gas and that we believe will yield commercial quantities of reserves through
improved drilling and completion technologies. Finding, developing and producing oil and gas
reserves in the North Sea require both significant capital and time. Recognizing this, we have
sought to balance our North Sea assets, which have large potential reserves but long
production-cycles, with a portfolio of assets in the U.S. that have lower costs and shorter
production-cycles. We also seek to achieve a balance of oil and gas reserves in our portfolio of
assets, believing that both commodities present attractive opportunities for capital returns in the
future.
Our North Sea activities and assets remain a key source of value that we are actively developing to
increase our overall reserves and production. Our major development projects in the U.K. sector of
the North Sea Bacchus, Greater Rochelle, and Columbus have the potential to significantly
expand our total proved reserves and production levels. These projects are in various stages of
development, with Bacchus currently expected to commence oil production in the second half of 2011.
Additionally, we expect that production from our two-phase development of the Greater Rochelle
area will commence with first production from East Rochelle in the second half of 2012 and from
West Rochelle shortly thereafter. Finally, Columbus could commence production as early as 2012.
We intend to continue to actively manage our North Sea assets in a manner that maximizes value and
enables us to allocate resources to effectively pursue our growth strategy.
Currently, our primary focus in the U.S. is unconventional gas shale developments targeting reserve
and production growth in the Haynesville area, including the East Texas Cotton Valley gas sands,
and the Marcellus area. In the Haynesville area, we have approximately 7,500 net acres with
acreage located in Red River, DeSoto, Bienville and Caddo Parishes in Louisiana and in Harrison and
Gregg Counties in Texas. Our Marcellus acreage is comprised of approximately 18,600 net acres in
Pennsylvania located between two of the most active parts of the Marcellus play. We also have
exploratory plans in emerging gas and oil plays in Alabama and Montana where early well results
will determine the pace and scope of our subsequent exploration and development initiatives.
In 2011, we intend to expand upon our foundation of producing assets and undeveloped acreage in
both established and emerging U.S. onshore resource plays, including the development of our
leasehold positions in the Haynesville and Marcellus areas, while continuing to develop our
existing assets in the North Sea. Specifically, during 2011 we intend to focus on achieving
initial production from the Bacchus oil field in the North Sea.
As of December 31, 2010, our estimated proved reserves were 18.4 MMBOE, up 1.1% from 18.2 MMBOE as
of December 31, 2009, of which approximately 70% were located in the U.K.
and approximately 30% were located in the U.S., and 19.4% of which were proved developed reserves.
Our 1.7 MMBOE of net reserve additions before production in 2010 replaced 111% of our production
during the year. We also achieved average sales volume of 4,115 BOE/d for the year ended December
31, 2010, a 7.7% increase from 2009, implying a reserve life index of approximately 12.2 years
based on our reserves as of December 31, 2010.
Our Business Strategy
We pursue a strategy of exploiting a balanced portfolio of exploration and development assets
that has evolved over the last several years. When we commenced operations in 2004, our focus was
exclusively in the North Sea. By 2009, we had built a portfolio of production and development
assets in the U.K. and Norway sectors of the North Sea. In May 2009, we sold our assets and
operations in the Norwegian sector of the North Sea for $150 million, and we used the proceeds from
that sale to complete acquisitions of U.S. onshore interests, providing us with acreage positions
and production in the Haynesville and Marcellus areas and our two emerging plays in Alabama and
Montana. We believe the resource-rich plays in the U.S., with lower costs and shorter
production-cycles, help provide a stable platform upon which to execute our strategy. We intend to
continue developing our existing assets in the North Sea, while simultaneously pursuing the
development of our domestic positions in the Haynesville and Marcellus areas and our positions in
the emerging Alabama and Montana plays.
We believe this strategy will best enable us to provide an attractive return on capital for our
stockholders. Several of the key elements of our business strategy include:
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Efficiently develop and commence production from our North Sea development assets. We
currently have three large development projects in the North Sea the Bacchus, Greater
Rochelle and Columbus fields which have the potential to significantly increase our
current production levels over the next several years. We intend to efficiently manage our
interests in each of these prospects in order to commence production in a timely and
cost-effective manner. We expect to achieve first production from the Bacchus field in the
second half of 2011. We expect that production from our two-phase development of the
Greater Rochelle area will commence with first production from East Rochelle in the second
half of 2012 and from West Rochelle shortly thereafter. Finally, Columbus is expected to
commence production as early as 2012. |
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Develop and exploit existing acreage in resource-rich plays. We have established a mix
of U.S. producing assets and undeveloped acreage in both established and emerging resource
plays, including the Haynesville and Marcellus areas and our emerging plays in Alabama and
Montana. We have the ability to adjust our domestic drilling activities in accordance with
current and future commodity prices and our operating results. |
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Maintain a balanced portfolio of production, development and exploration assets. We
intend to actively manage our assets in a manner that maximizes value and enables us to
allocate resources to effectively pursue our balanced growth strategy. Recognizing this,
we have established a portfolio that balances assets that are characterized by shorter
production-cycles with assets that have larger potential reserves with longer
production-cycles. |
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Exploit potential growth opportunities in our emerging domestic plays. We have
approximately 73,000 and 61,000 net acres, respectively, in exploratory plays in central
Montana and western Alabama, which give us exposure to emerging oil and natural gas shale
plays, respectively. We believe that the relatively modest capital investment required to
drill pilot wells in each of these two areas helps to mitigate the inherent risk in
attempting to develop assets in emerging plays. We may seek to explore these emerging
plays following a review of the projected return on capital from these plays based on early
well results. |
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Reduce leverage and simplify our capital structure. To fund our growth over the last
several years, we relied primarily on financing structures available to small and
developing companies, some of which were considered relatively complicated. These
financial instruments include several series of convertible notes and our senior term loan.
We are currently exploring our options to replace these instruments with more traditional
financing arrangements. We plan to continue strengthening our balance sheet and lowering
our overall cost of capital, which we believe will give us access to a wider variety of
more favorable financing options on a long-term basis. |
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Endeavour International Corporation
Our Competitive Strengths
We believe the following competitive strengths will help us achieve our business strategy:
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Significant North Sea development assets and attractive positions in resource-rich shale
plays. We believe that successful development of our three primary development
assets in the North Sea could have the potential to significantly increase our production
levels over the next several years. Moreover, our assets in the U.S. cover a broad
spectrum of resource plays, from established areas, such as Haynesville and Marcellus, to
emerging plays, in Alabama and Montana. This combination should allow us to balance the
capital intensive, long lead-time nature of our North Sea assets with the shorter
development times and lower capital requirements of our U.S. properties. |
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Balanced producing and development and exploration assets. We have taken important
steps to balance our asset portfolio in several dimensions: U.S. versus U.K. properties;
oil versus natural gas; and short-term versus long-term realizations. We have constructed
our asset portfolio in this manner in an attempt to mitigate the risks of over-emphasizing
any one of these variables. Specifically, we believe that the resource-rich plays in the
U.S., with less capital-intensive and shorter production-cycles relative to our North Sea
development projects, will provide a stable platform for the successful execution of our
strategy by helping to provide cash flows from operations as we develop our longer-term,
more capital-intensive North Sea development projects. |
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Improving exposure to liquids. With the expected first production from our Bacchus
asset in the second half of 2011, we expect that our liquids production will increase
significantly. In addition, our current portfolio of assets includes other liquids-rich
opportunities in the North Sea as well as upside development acreage in the Heath oil shale
play in Montana. These assets and prospects should provide us with both near- and
long-term liquids exposure. |
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Experienced and skilled management team with proven track records. We were co-founded
in 2004 by William L. Transier, our President and Chief Executive Officer, and John N.
Seitz, one of our directors. Our management team has extensive technical expertise and
industry experience across the full cycle of development of oil and gas assets and
operations. The members of our management team, including our senior geoscience and
engineering professionals, average more than 24 years of experience in the oil and gas
industry. Under this management team, we have executed several significant transactions,
including the sale of our Norwegian subsidiary, the sale of our Cygnus reserves in the North
Sea, our recent Bacchus acquisition and several acquisitions of U.S. onshore properties.
Substantially all of the members of the team have previously worked for a major oil company
or a large independent producer. |
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Our President and Chief Executive Officer, William L. Transier, was the
former Chief Financial Officer of Ocean Energy, which merged with Devon Energy in
2003, and has over 35 years of experience in the oil and gas industry. |
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Our Chief Financial Officer, J. Michael Kirksey, has an extensive
background in both operational and financial management in the energy industry,
having served in various executive roles for Metals USA, Input Output, Inc. and
Keystone International, Inc. |
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Carl D. Grenz, our Executive Vice President International, has 33
years of experience in the oil and gas industry, having spent a majority of his
career working for BHP Billiton and Hamilton Oil, focused in the North Sea. |
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Our Executive Vice President North America, James J. Emme, has 30
years of experience in the oil and gas industry, with an extensive background in
unconventional hydrocarbon exploration and development while working for Anadarko
Petroleum Corporation and Source Exploration, LLC. |
Our Areas of Operation
North Sea
The North Sea is a proven resource area where we have several significant development projects,
producing properties and additional exploration licenses. Although production costs are higher
than conventional developments in the U.S., the quality of the oil, the political stability of the
region, and the proximity of important markets with strong demand in Western Europe has made the
North Sea an important oil and natural gas producing region. We believe our assets in the U.K.
sector of the North Sea possess significant value that can continue to be realized in a manner that
will provide us with an attractive return on invested capital.
Our development assets in the Bacchus, Greater Rochelle, and Columbus fields comprise the primary
components of our U.K. North Sea portfolio, and we currently have development plans under way in
each of these fields. When these projects are fully producing, they have the potential to
significantly increase our current production levels over the next several years. We also have
producing properties the Alba, Bittern, Enoch and Goldeneye fields and certain other fields
where we have suspended production. We anticipate re-developing production from
our suspended fields, if commercially attractive and practicable, once additional production
commences from the nearby East Rochelle field.
We believe that constraints on available capital and consolidation have reduced the number of
companies operating in the North Sea, which in turn has reduced competition and given us an
increased ability to pursue opportunities consistent with our balanced strategy.
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Endeavour International Corporation
Primary Development Fields
Bacchus
At December 31, 2010, we held a 10% working interest in our Bacchus field asset, which is operated
by Apache Corporation, who owns a 50% working interest. On February 23, 2011, we closed our
acquisition of an additional 20% working interest in the Bacchus development for approximately $9.2
million in cash payable at closing and approximately $6.2 million in cash payable three months
after first oil is produced. In addition, we paid capital costs previously incurred by the seller
of $9.4 million. Following the acquisition, we hold an aggregate working interest of 30%. As of
December 31, 2010, our 0.2 MMBOE of estimated proved reserves in the Bacchus area were 95% oil.
The development of the Bacchus field was sanctioned in the second quarter of 2010 by the Department
of Energy and Climate Change (DECC). The discovery well was drilled in 2005, followed by a
down-dip sidetrack appraisal well that tested the upper part of the reservoir. The field
development plan (FDP) for the Bacchus field calls for a subsea development with three wells to
be drilled and linked to production facilities at the nearby Forties field. The 6.5 kilometer
subsea bundled pipeline launched from Wick on the east coast of Scotland in early March 2011, and
first production is expected to commence in the second half of 2011.
Greater Rochelle
The Greater Rochelle area is comprised of three blocks in the North Sea, including our interests in
blocks 15/27 and 15/26c. We refer to these blocks as our East Rochelle field and our West Rochelle
field, respectively. In the East Rochelle field in block 15/27, we hold a 55.6% working interest
and are the operator, while our partner Nexen Petroleum U.K. Limited (Nexen) holds the remaining
working interest. In the West Rochelle field in block 15/26c, we hold a 50% working interest and
are the operator. Nexen and Premier Oil plc (Premier) have each farmed into block 15/26c for a
25% working interest. In the third block of the Greater Rochelle area, block 15/26b, Nexen and
Premier are partners, each with a 50% working interest.
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Endeavour International Corporation
East Rochelle
Our reserves at the East Rochelle field are a gas/condensate mix and account for 7.5 MMBOE of our
proved reserves at December 31, 2010. On February 28, 2011, the DECC approved the Rochelle FDP for
Block 15/27 in the Central North Sea, now known as East Rochelle. This approval represents phase
one of the development of the Greater Rochelle area. The current East Rochelle FDP calls for the
subsea development to be linked, by a 30 kilometer pipeline, to production facilities on the Scott Platform. First production is planned for the second half of
2012.
West Rochelle
Nexen operated the first well in block 15/26b, which was drilled in September 2010 and encountered
natural gas with an oil rim in a reservoir similar to that discovered at East Rochelle. The well
was sidetracked to the north and encountered hydrocarbons that extend the Greater Rochelle area.
This well confirmed the reserves on our interest in block 15/26c.
Columbus
We hold a 25% working interest in the Columbus field, which is operated by Serica Energy plc.
Columbus is a gas/condensate field in the Central Graben region of the North Sea. During 2010, we,
along with our partners in Columbus, agreed to study an option of producing the field using a new
bridge-linked platform connected to the Lomand Platform. We expect to file an updated FDP later in
2011 with project sanction by the DECC anticipated later in the year. We believe that first
production from this field could occur as early as 2012.
Producing Fields
Our four producing fields in the U.K. Alba, Bittern, Enoch and Goldeneye held a combined 1.6
MMBOE of proved reserves as of December 31, 2010. Sales from these fields totaled 1,057 MBOE for
the year ended December 31, 2010. In addition, we hold interests in the Ivanhoe, Rob Roy, Hamish
(collectively, IVRRH), Renee and Rubie fields, each of which is currently shut in.
In 2010, the Goldeneye field represented nearly all of our gas production in the U.K. The field
was shut-in in early December 2010 due to flow assurance issues resulting from increased water
production. The Goldeneye field is a mature gas field, nearing the end of its production life.
When we acquired the Goldeneye field in October 2006, it contained estimated proved reserves of
approximately 2,237 MBOE. From our acquisition through December 31, 2010, the Goldeneye field has
produced approximately 4,571 MBOE.
In February 2011, production from the Goldeneye field was re-started to commence flow trials to
study pipeline hydraulic performance. These trials are continuing and we are monitoring progress
along with the field operator. The trials, when concluded, should help us determine how much more
production may be expected from the Goldeneye field. In addition, the operator is evaluating
options to use the Goldeneye reservoir as a carbon-capture facility, which may reduce our
abandonment obligations for the field.
Production from each of our IVRRH, Renee and Rubie fields is currently suspended. Previously, each
of these fields produced to a single floating production facility that experienced significant
increases in operating costs. As a result, production was suspended in the first quarter of 2009
and will remain suspended until the development activities at East Rochelle are operational,
which we currently anticipate to be during 2012. After the start of East Rochelle production, we
expect to re-develop these fields if commercially attractive and practicable.
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Endeavour International Corporation
United States
During 2009, we began acquiring acreage in U.S. onshore resource plays. Our U.S. assets held 5.4
MMBOE of proved reserves as of December 31, 2010. We believe that our U.S. acreage provides us
with development projects with shorter timeframes to first production at lower costs than our North
Sea assets. In addition, our U.S. acreage covers a broad spectrum of resource plays, from
established areas such as Haynesville and Marcellus areas, to emerging plays in Alabama and
Montana.
Our strategy for our U.S. operations has been to employ a measured approach that seeks to balance
U.S. natural gas prices with drilling costs. We plan to continue this disciplined approach, which
includes:
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a one to two rig drilling program in Louisiana and East Texas for our interests in the
Haynesville area and Cotton Valley trend; |
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a measured drilling program to delineate our position in the Marcellus area while
pipeline infrastructure issues are resolved; and |
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a thorough analysis of test well results in Alabama and Montana before finalizing any
development plans in these exploratory areas. |
We believe this approach in the U.S. should provide flexibility to adjust our drilling activity in
accordance with current and future commodity prices and our operating results, while still allowing
our U.S. operations to grow and provide near-term return on capital to balance our longer
production-cycle U.K. projects.
Haynesville Area
The Haynesville area has become one of the most active natural gas plays in the U.S. This area is
defined by a Jurassic shale formation located approximately 1,000 to 1,500 feet below the base of
the Cotton Valley formation at depths ranging from approximately 10,500 feet to 13,000 feet. The
formation is 125 to 250 feet thick and is composed of organic-rich, black shale. It is located
across numerous parishes in Northwest Louisiana, primarily in Caddo, Bossier, Red River, DeSoto,
Webster and Bienville parishes, and also in East Texas. Numerous shallower secondary objectives
exist in the Haynesville area, including the overlying Jurassic Cotton Valley Sandstone and Bossier
Shale intervals.
Through several transactions, we have acquired non-operated interests in both producing wells and
prospective acreage in the Haynesville area. In October 2009, we purchased interests in 24 wells
and certain proved undeveloped locations in North Louisiana and East Texas for $15 million in cash.
These 24 wells produce primarily from the Cotton Valley trend. In 2010, we acquired additional
acreage in the Haynesville and Marcellus areas for a combined $22.5 million.
In the Haynesville area, we have had drilling activity in the Woodardville, Jamestown, Bull Bayou,
Metcalf and Grand Cane fields in Louisiana, and the Willow Springs field in East Texas. During
2010, we drilled 12 Haynesville Shale wells, all of which were successful.
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Endeavour International Corporation
Marcellus Area
The Marcellus area is a Middle Devonian-aged shale that underlies much of Pennsylvania, New York,
Ohio, West Virginia and adjacent states. Within the past few years, advances in two technologies,
fracture stimulation and horizontal drilling, have produced promising results in the Marcellus
area. These developments have resulted in significantly increased leasing and drilling activity in
the area. We have acquired interests in the Marcellus area in several project areas, including
portions of Cameron, Elk, Potter, McKean, Jefferson, Clarion and Clearfield counties, Pennsylvania.
During 2010, we successfully completed one well, which is now on production, and commenced drilling
the first of two planned horizontal tests to further evaluate the Daniel Field in Cameron County.
The first horizontal test well was successfully drilled and is waiting on completion. We are
currently drilling the second test well and may drill additional wells to delineate the area. In
parallel, we are working on expanding pipeline infrastructure, including options to connect with
one of three major pipelines in Cameron County.
Alabama
We hold non-operating interests in approximately 61,000 net acres with exposure to emerging gas
shale plays in western Alabama. We believe that our position allows us to target multiple gas
shale intervals, with a primary focus on the Devonian shale. We drilled two vertical pilot wells
during 2010 and are evaluating the results of these wells for future horizontal re-entries and/or
completion tests before formulating an appropriate completion and development plan.
Central Montana
We own non-operating interests in approximately 73,000 net acres in central Montana, with exposure
to the Mississippian Heath oil-prone source shale. This region has historically produced a
significant amount of oil from the Cretaceous through the Mississippian reservoirs. We currently
plan to participate in the drilling of three vertical pilot wells during 2011. We intend to
monitor the results of these wells before determining further appraisal or development plans.
Reserves
Our proved oil and gas reserves at December 31, 2010, 2009 and 2008 included the following:
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Endeavour International Corporation
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Oil |
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Gas |
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Oil Equivalents |
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(MBbls) |
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(MMcf) |
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(MBOE) |
2010: |
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United Kingdom |
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3,664 |
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56,177 |
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13,027 |
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United States |
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59 |
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31,777 |
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5,355 |
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3,723 |
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87,954 |
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18,382 |
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2009: |
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United Kingdom |
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3,348 |
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78,316 |
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16,401 |
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United States |
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18 |
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10,784 |
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1,815 |
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3,366 |
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89,100 |
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18,216 |
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2008: |
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United Kingdom |
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2,131 |
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27,130 |
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6,653 |
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United States |
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18 |
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690 |
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133 |
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Discontinued operations Norway |
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1,406 |
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4,977 |
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2,236 |
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3,555 |
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32,797 |
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9,022 |
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Our proved undeveloped reserves are primarily related to our development projects in the UK
and the results of successful exploration drilling during 2010 in the U.S. We expect our proved
undeveloped reserves in the UK to become proved developed reserves over the next three years as
development plans are completed and production commences on existing development projects at
Bacchus, Rochelle and Columbus. In the U.S., we have four wells that are either being completed or
awaiting completion at December 31, 2010. Once completed, the proved undeveloped reserves
associated with these wells will transfer to proved developed reserves. See Note 5 to our
consolidated financial statements in this Annual Report on Form 10-K for additional information on
the costs associated with our proved developed reserves and unproved properties. Our proved
developed and undeveloped oil and gas reserves at December 31, 2010, 2009 and 2008 included the
following:
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Endeavour International Corporation
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Proved |
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Proved |
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Developed |
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Undeveloped |
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Total Proved |
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Reserves |
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Reserves |
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Reserves |
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|
(MBOE) |
|
(MBOE) |
|
(MBOE) |
2010: |
|
|
|
|
|
|
|
|
|
|
|
|
United Kingdom |
|
|
1,333 |
|
|
|
11,694 |
|
|
|
13,027 |
|
United States |
|
|
2,227 |
|
|
|
3,128 |
|
|
|
5,355 |
|
|
|
|
|
3,560 |
|
|
|
14,822 |
|
|
|
18,382 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009: |
|
|
|
|
|
|
|
|
|
|
|
|
United Kingdom |
|
|
2,103 |
|
|
|
14,298 |
|
|
|
16,401 |
|
United States |
|
|
792 |
|
|
|
1,023 |
|
|
|
1,815 |
|
|
|
|
|
2,895 |
|
|
|
15,321 |
|
|
|
18,216 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008: |
|
|
|
|
|
|
|
|
|
|
|
|
United Kingdom |
|
|
2,595 |
|
|
|
4,058 |
|
|
|
6,653 |
|
United States |
|
|
46 |
|
|
|
87 |
|
|
|
133 |
|
Discontinued
Operations Norway |
|
|
2,122 |
|
|
|
114 |
|
|
|
2,236 |
|
|
|
|
|
4,763 |
|
|
|
4,259 |
|
|
|
9,022 |
|
|
Preparation of Oil and Gas Reserve Information
We have established internal controls over reserve estimation processes and procedures to
support the accurate and timely preparation and disclosure of reserve estimations in accordance
with SEC and GAAP requirements. These controls include oversight of the reserves estimation
reporting processes by our technical staff, annual external audits of all of our proved reserves by
independent reserve engineers and secured access to reservoir databases and systems. Proved
reserve estimates are prepared by our technical staff and reviewed and approved by our executive
team, including our Executive Vice-President International and Executive Vice President North
America. In the third quarter of 2010, we established a new Technology and Reserves committee of
the board of directors. The committee supports the board by providing increased focus on emerging
technologies in the upstream industry and oversight of our reserve evaluation and reporting
processes. Reserves are reviewed internally with senior management quarterly and presented to the
Technology and Reserves Committee and our Board of Directors on an annual basis for their review.
For 2010 and 2009, our oil and gas reserve estimates were prepared by our internal reservoir
engineers and audited by independent reserve engineers, Netherland, Sewell & Associates, Inc.
(NSAI). For 2008, our proved oil and gas reserves were estimated by NSAI.
Each year, our internal technical staff evaluates all technical data available on each field,
including production data, wells logs, pressure data, petrophysical analysis, fluid properties,
seismic data, seismic interpretations and well control along with offset well data. We estimate
8
Endeavour International Corporation
the quantity of oil and gas reserves and provide our estimates, analysis and data to our
independent reserve engineers.
For 2008, we provided our analysis and data to NSAI for their independent estimates using the
Securities and Exchange Commission (SEC), or SEC, definitions of proved reserves. The
independent engineers then performed their own analysis of the same raw data including analysis of
all production data, pressure data, well logs, petrophysical analysis, fluid analysis, seismic data
and mapping based on that seismic data to determine their own estimate of the quantity of proved
oil and gas reserves attributable to a specific property.
Qualification of Reserves Preparers and Auditors
We employ oil and gas technical professionals, including geophysicists, petrophysicists,
geologists, and reservoir engineers, who have 10 to 35 years of experience in their technical
fields. Our Director of Reservoir Engineering, who has over 25 years of experience and a masters
degree in petroleum engineering, supervises our technical professionals in the evaluation and
estimation of our oil and gas reserves. In addition, we engage experienced and qualified
consultants to perform various comprehensive seismic acquisitions, processing, reprocessing,
interpretation, and other related services.
NSAI provides worldwide petroleum property analysis services for energy clients, financial
organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum
engineering services under Texas Board of Professional Engineers Registration No. F-002699. The
technical persons responsible for conducting this audit for NSAI meet the requirements regarding
qualifications, independence, objectivity, and confidentiality set forth in the Standards
Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the
Society of Petroleum Engineers. NSAI opined that the overall proved reserves for the reviewed
properties as estimated by us are, in the aggregate, reasonable, prepared in accordance with
generally accepted petroleum engineering and evaluation principles and conform to the SECs
definition of proved reserves as set forth in Rule 210.4-10(a) of Regulation S-X. NSAI has
informed us that the tests and procedures used during its reserves audit conform to the Standards
Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the
Society of Petroleum Engineers. Paragraph 2.2(f) of the Standards Pertaining to the Estimating and
Auditing of Oil and Gas Reserves Information defines a reserves audit as the process of reviewing
certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate
of reserves prepared by others and the rendering of an opinion about (1) the appropriateness of the
methodologies employed, (2) the adequacy and quality of the data relied upon, (3) the depth and
thoroughness of the reserves estimation process, (4) the classification of reserves appropriate to
the relevant definitions used, and (5) the reasonableness of the estimated reserve quantities. A
reserve audit is not the same as
a financial audit and is less rigorous in nature than an independent reserve report where the
independent reserve engineer determines the reserves on his or her own.
9
Endeavour International Corporation
2011 Planned Capital Expenditures
We anticipate spending approximately $150 million during 2011 to fund our oil and gas activities in
the U.S. and U.K., with approximately 60% of those expenditures anticipated to be focused on our
U.K. assets. In the U.K., our activity during 2011 will be primarily concentrated on the Bacchus
and Greater Rochelle development projects. At the Bacchus project, we plan to drill three
production wells and install the infrastructure to allow first production in the second half of
2011. At the Greater Rochelle project, our focus will be completing engineering and procuring long
lead-time equipment to prepare Greater Rochelle for a 2012 first production date from the East
Rochelle area. We also intend to begin actual construction of the subsea
infrastructure and modifications to the Scott platform to prepare it for production from the
Greater Rochelle area. Additionally, we expect to continue to further our development program at
our Columbus project, including ongoing engineering assessments for future production and
commercial off-take solutions.
Our primary focus during 2011 in the U.S. will be in the Haynesville and Marcellus areas as we
believe this acreage contains near-term production potential. The ongoing U.S. program and
expenditures will be tailored based on early drilling results and U.S. gas prices in 2011. During
2011, we expect to further evaluate our two existing frontier plays in Alabama and Montana through
the drilling of additional test wells.
We intend to fund our capital expenditures through cash on hand and cash flow generated from
operations. The majority of our cash on hand was acquired through our capital raising activities
in 2010, including our 15.0% senior term loan due 2013 (the Senior Term Loan) and the sale of our
Cygnus reserves. The timing, completion and progress of our 2011 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 technical work.
Based on these and other factors, we may increase or decrease our planned capital program or
prioritize certain projects over others.
For a complete discussion of our available sources of liquidity and our expected financing needs,
please see Item 7. Managements Discussion and Analysis of Financial Condition and Results of
Operations Liquidity and Financial Resources.
Company History
Endeavour International Corporation (a Nevada corporation formed in 2000) is an independent
oil and gas company engaged in the acquisition, exploration and development of energy reserves and
resources.
On October 31, 2006, we purchased producing properties in the U.K. (the Talisman Acquisition)
through the purchase of all the outstanding shares of Talisman Expro Limited for $366 million,
after purchase price adjustments and expenses. As a result of the Talisman
Acquisition, we acquired interests in eight fields in the United Kingdom sector of the North Sea
and over seven million BOE of proved reserves as of the closing date.
In the second quarter of 2006, we purchased an eight percent interest in the Enoch Field in the
North Sea for approximately $11.7 million. The field is one of the first discoveries to be
developed along the median line between the United Kingdom and Norway after the ratification of the
U.K./Norway Framework Treaty concerning cross-boundary petroleum cooperation.
10
Endeavour International Corporation
While working to complete and integrate these acquisitions, we also moved forward in our
drilling program. We have also pursued various farm-in and license transfer opportunities to build
acreage and exploration potential and spread the risk of exploration drilling among multiple
prospects. Most notably, we have three significant development projects ongoing in the U.K.
Bacchus, Columbus, and Rochelle.
In 2008, we initiated operations in the U.S. and announced our first production there in January
2009.
On May 14, 2009, we completed the divestiture of our Norwegian subsidiary, Endeavour Energy Norge
AS, to VerbundnetzGas AG, a German utility company, for cash
consideration of $150 million (the Norway Sale). We
used the proceeds from this divestiture primarily to pay down our outstanding debt and streamline
our capital structure, acquire new properties in the U.S. and support our ongoing drilling program.
This divestiture allowed us to focus our efforts on our acquired positions in our U.S. resource
plays, as wells as develop our significant North Sea assets.
In the fourth quarter of 2009, we purchased producing properties and exploration acreage in the
U.S. We purchased additional exploration acreage in the U.S. in January 2010. This accumulation
of acreage in the U.S. signified our expansion into resource plays in the onshore U.S.
In October 2010, we sold our interests in the Cygnus reserves in the Southern Gas Basin of the
North Sea for $110 million (the Cygnus Sale).
Also in October 2010, our Board of Directors authorized a consolidation of our common stock, in the
form of a one-for-seven share reverse stock split. This consolidation was effective at the opening
of trading on November 18, 2010. As a result of the share consolidation, every seven shares of our
common stock outstanding were automatically combined into one share of our common stock.
In November 2010, we signed a definitive agreement to acquire an additional 20% working interest in
the Bacchus development, for a cash consideration at closing of $9.6 million and $6.4 million three
months after first oil production. Closing was completed February 2011.
Our activities have been funded through various debt and equity offerings since our inception.
During the year ended December 31, 2010, we had the following debt and equity outstanding in
addition to our common stock:
|
|
|
6% Senior Convertible Notes During 2005, we issued in a private offering $81.25
million aggregate principal amount of convertible senior notes due in January 2012. |
|
|
|
|
11.5% Convertible Senior Bonds In January 2008, we issued 11.5% Convertible Bonds due
2014 for gross proceeds of $40 million pursuant to a private offering to a sophisticated
investor in Norway. |
|
|
|
|
Senior Term Loan In August 2010, we entered into a credit agreement with Cyan
Partners, LP, as administrative agent, and various lenders for a senior, secured term loan,
in the aggregate amount of $150 million, which was subsequently increased to $160 million. |
11
Endeavour International Corporation
|
|
|
Senior Bank Facility In 2006, we issued a $225 million senior bank facility,
which was subject to a borrowing base limitation with interest of LIBOR plus 1.3%. We
terminated the Senior Bank Facility and repaid the outstanding indebtedness in its entirety
on August 16, 2010 |
|
|
|
|
Junior Facility In the first quarter of 2010, we entered into the $25 million junior
facility, which had a maturity date of February 5, 2011, and bore interest at LIBOR plus
8%. We terminated the Junior Facility and repaid the outstanding indebtedness in its
entirety on August 16, 2010. |
|
|
|
|
$50 million Subordinated Notes In November 2009, we issued an aggregate $50 million
of subordinated notes due 2014. |
|
|
|
|
Series C Preferred Stock In 2006, we issued $125 million of convertible preferred
stock. In November 2009, we redeemed 60% of the outstanding shares of Series C Preferred
Stock and amended the terms of the remaining shares of Series C Preferred Stock. The
redemption price consisted of a $25 million cash payment and the issuance of $50 million of
Subordinated Notes. |
Each of these debt and equity offerings is explained more fully in Note 9 and Note 12 to the
Consolidated Financial Statements herein for.
Geographical Data
We operate in one industry segment, that being oil and gas exploration and production, in two
geographical areas. See Note 24 to our consolidated financial statements in Item 8, Financial
Statements and Supplementary Data for geographic operating segment information, including results
of operations and segment assets.
Competition
We encounter intense competition from other oil and gas companies in all areas of our
operations, including the acquisition of producing properties and undeveloped acreage. Our
competitors include major integrated oil and gas companies, numerous independent oil and gas
companies and individuals. Many of our competitors are large, well-established companies with
substantially larger operating staffs and greater capital resources and have been engaged in the
oil and gas business for a much longer time than our company.
Petroleum and natural gas producers also compete with other suppliers of energy and fuel to
industrial, commercial and individual customers. Competitive conditions may be substantially
affected by various forms of energy legislation and/or regulation considered from time to time by
the governments and/or agencies thereof and other factors out of our control including,
international political conditions, overall levels of supply and demand for oil and gas, and the
markets for synthetic fuels and alternative energy sources.
Significant Customers
Our sales in the U.K. are to a limited number of customers, each of which accounts for more
than 10% of revenue: Chevron North Sea Ltd, Shell U.K. Limited, and Esso Exploration and
12
Endeavour International Corporation
Production. Our sales in the U.S. are sold through our arrangements with the operators of the
fields, with the majority of the sales being to Cohort Energy.
Employees
As of March 4, 2011, we have 46 full-time employees and 12 consultants, primarily in the
operations area. We believe that we maintain good relationships with our employees, none of whom
are covered by a collective bargaining agreement.
Environmental Matters and Regulation
Endeavour was established on a commitment to find and develop energy resources in a manner
that protects the health and safety of people and preserves the quality of the environment.
Adhering to high performance standards in the areas of health, safety and the environment (HSE)
is a primary goal of our operations and an integral part in our efforts to end each day injury and
incident free.
North Sea
Our operations in the U.K. portions of the North Sea are subject to numerous U.K. and European
Union laws and regulations relating to environmental matters, health and safety. Environmental
matters are addressed before oil and gas production activities commence and during the exploration
and production activities. Before a U.K. licensing round begins, the DECC will consult with
various public bodies that have responsibility for the environment. Applicants for production
licenses are required to submit a summary of its management systems and how those systems will be
applied to the proposed work program. Additionally, the Offshore Petroleum Production and
Pipelines (Assessment of Environmental Effects) Regulations 1999 require the Secretary of State to
exercise his licensing powers under the U.K. Petroleum Act in such a way to ensure that an
environmental assessment is undertaken and considered before consent is given to certain projects.
There are a number of new and forthcoming rules that may impact our North Sea operations. In
response to the Deepwater Horizon Incident, the DECC has announced plans to increase rig
inspections. In addition, early this year the European Commission intends to impose new rules for
offshore platforms that will require spill response plans; increase regulatory requirements for
equipment, such as blowout preventers; and require operators to pay for any environmental damage
within 200 miles of a blowout. Our operations in the North Sea will also be subject to the
European Unions REACH program, which requires the registration and ultimate phase out of certain
hazardous chemicals. In order to implement the requirements of the REACH program in the offshore
production sector, the DECC has issued amendments to the Offshore Chemicals Regulations that will
enter into force in early 2011. These regulations will control all operational and non-operational
discharges from offshore production platforms. Finally, depending on the scale of our operations,
our offshore production facilities may be subject to compliance obligations under the EU Emissions
trading system or impacted by carbon tax proposals under consideration in the U.K. Compliance with
the above regulations may cause us to incur additional costs in our North Sea operations.
13
Endeavour International Corporation
United States
Our U.S. operations are subject to stringent federal, state and local laws and regulations relating
to environmental protection, as well as controlling the manner in which various substances,
including wastes generated in connection with oil and gas industry operations, are released into
the environment. Compliance with these laws and regulations require the acquisition of permits
authorizing air emissions and wastewater discharge from operations and can affect the location or
size of wells and facilities, limit or prohibit the extent to which exploration and development may
be allowed, and require proper closure of wells and restoration of properties that are being
abandoned. Failure to comply with these laws and regulations may result in the assessment of
administrative, civil or criminal penalties, imposition of remedial obligations, incurrence of
capital costs to comply with governmental standards, and even injunctions that limit or prohibit
exploration and production operations or the disposal of substances generated in connection with
our operations.
We currently lease a number of properties that for many years have been used for the exploration
and production of oil and gas. Although we have utilized operating and disposal practices that
were standard in the industry at the time, hydrocarbons or wastes may have been disposed of or
released on or under the properties operated or leased by us or on or under other locations where
such hydrocarbons or wastes have been taken for recycling or disposal. In addition, many of these
properties have been operated by third parties whose treatment and disposal or release of
hydrocarbons or wastes was not under our control. These properties and the hydrocarbons and wastes
disposed thereon may be subject to laws and regulations imposing joint and several, strict
liability, without regard to fault or the legality of the original conduct, that could require us
to remove or remediate previously disposed wastes or environmental contamination, or to perform
remedial well plugging or pit closure to prevent future contamination.
Hydraulic fracturing is an important and common practice that is used to stimulate production of
hydrocarbons, particularly natural gas, from tight formations. We routinely utilize hydraulic
fracturing techniques in many of our natural gas well drilling and completion programs. The
process involves the injection of water, sand and chemicals under pressure into the formation to
fracture the surrounding rock and stimulate production. The process is typically regulated by
state oil and gas commissions. However, the EPA recently asserted federal regulatory authority
over hydraulic fracturing involving diesel additives under the Safe Drinking Water Acts
Underground Injection Control Program. While the EPA has yet to take any action to enforce or
implement this newly asserted regulatory authority, industry groups have filed suit challenging the
EPAs recent decision. At the same time, the EPA has commenced a study of the potential
environmental impacts of hydraulic fracturing activities, and a committee of the U.S. House of
Representatives is also conducting an investigation of hydraulic fracturing practices. Legislation
has been introduced before Congress to provide for federal regulation of hydraulic fracturing and
to require disclosure of the chemicals used in the fracturing process. In addition, some states
have adopted, and other states are considering adopting, regulations that could impose more
stringent permitting, disclosure and well construction requirements on hydraulic fracturing
operations. For example, Pennsylvania, Colorado, and Wyoming have each adopted a variety of well
construction, set back, and disclosure regulations limiting how fracturing can be performed
14
Endeavour International Corporation
and requiring various degrees of chemical disclosure. If new laws or regulations that
significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or
costly for us to perform fracturing to stimulate production from tight formations. In addition, if
hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or
regulatory initiatives by the EPA, our fracturing activities could become subject to additional
permitting requirements, and also to attendant permitting delays and potential increases in costs.
Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we
are ultimately able to produce from our reserves.
Climate Change
Globally, our operations may be impacted by various international, national, and local efforts to
respond to climate change by controlling greenhouse gas (GHG) emissions. With the first
commitment period of the Kyoto Protocol due to expire in 2012, there is substantial uncertainty as
to the structure of a future international climate change regime. However, any new international
agreements and domestic laws to implement them may adversely impact our operations by imposing GHG
emission limits on our activities and potentially reducing demand for our products. Within Europe,
the European Union has announced its plans for the next phase of the emissions trading system,
running from 2013 to 2020, and therefore our activities in the North Sea are still potentially
subject to the impacts of GHG limitations. Many other countries, including the United States, are
weighing a variety of legislative and regulatory strategies that may impose controls on GHG
emissions.
Beginning in 2009, the United States Environmental Protection Agency (EPA) took a series of steps
to begin regulating GHG emissions under the Clean Air Act. As of January 2, 2011, the EPAs rules
impose limitations on GHG emissions from motor vehicles and certain large stationary sources. In
addition, the EPA has issued regulations requiring certain sectors to
monitor and report their greenhouse gas emissions. Petroleum refineries must report their
emissions for the 2010 calendar year in 2011. On January 1, 2011, our exploration and production
activities also became subject to the monitoring and reporting requirements, and we will incur
costs related to compliance with these regulations.
In addition, the United States Congress has from time to time considered adopting legislation to
reduce emissions of greenhouse gases and almost one-half of the states have already taken legal
measures to reduce emissions of greenhouse gases primarily through the planned development of
greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of
these cap and trade programs work by requiring major sources of emissions, such as electric power
plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and
surrender emission allowances. The number of allowances available for purchase is reduced each year
in an effort to achieve the overall greenhouse gas emission reduction goal.
The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases in areas
where we operate could require us to incur increased operating costs, such as costs to purchase and
operate emissions control systems, to acquire emissions allowances or comply with new regulatory or
reporting requirements. Any such legislation or regulatory programs could also increase the cost of
consuming, and thereby reduce demand for, the oil and natural gas we
15
Endeavour International Corporation
produced. Consequently, legislation and regulatory programs to reduce emissions of greenhouse
gases could have an adverse effect on our business, financial condition and results of operations.
Finally, it should be noted that some scientists have concluded that increasing concentrations of
greenhouse gases in the Earths atmosphere may produce climate changes that have significant
physical effects, such as increased frequency and severity of storms, droughts, and floods and
other climatic events. If any such effects were to occur, they could have an adverse effect on our
financial condition and results of operations.
We have made, and will continue to make, expenditures in connection with our effort to comply with
environmental laws and regulations. We believe that we are in compliance with applicable
environmental laws and regulations currently in effect and that continued compliance with existing
requirements will not have a material adverse impact on us. However, we also believe that it is
reasonably likely that the trend in environmental legislation and regulation will continue toward
stricter standards and, thus, we cannot give any assurance that we will not be adversely affected
in the future.
We have established internal guidelines to be followed in order to comply with environmental laws
and regulations in the U.S. We employ a safety department whose responsibilities include providing
assurance that our operations are carried out in accordance with applicable environmental
guidelines and safety precautions. Although we maintain pollution insurance to cover a portion of
the potential costs of cleanup obligations, public liability and physical damage, there is no
assurance that such insurance will be adequate to cover all such costs or that such insurance will
continue to be available in the future. To date, we believe that compliance with existing
requirements of such governmental bodies has not had a material effect on our operations.
Other Regulation of the Oil and Gas Industry
The oil and gas industry is extensively regulated by numerous federal, state and local authorities.
Legislation affecting the oil and gas industry is under constant review for amendment or
expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies,
both federal and state, are authorized by statute to issue rules and regulations binding on the oil
and gas industry and its individual members, some of which carry substantial penalties for failure
to comply. Although the regulatory burden on the oil and gas industry increases our cost of doing
business and, consequently, affects our profitability, these burdens generally do not affect us any
differently or to any greater or lesser extent than they affect other companies in the industry
with similar types, quantities and locations of production.
Legislation continues to be introduced in Congress and development of regulations continues in the
Department of Homeland Security and other agencies concerning the security of industrial
facilities, including oil and gas facilities. Our operations may be subject to such laws and
regulations. Presently, it is not possible to accurately estimate the costs we could incur to
comply with any such facility security laws or regulations, but such expenditures could be
substantial.
16
Endeavour International Corporation
Production Regulation
Our operations are subject to various types of regulation at federal, state and local levels.
These types of regulation include requiring permits for the drilling of wells, drilling bonds and
reports concerning operations. Most states, and some counties and municipalities, in which we
operate, also regulate one or more of the following:
|
|
|
the location of wells; |
|
|
|
|
the method of drilling and casing wells; |
|
|
|
|
the surface use and restoration of properties upon which wells are drilled; |
|
|
|
|
the plugging and abandoning of wells; and |
|
|
|
|
notice to surface owners and other third parties. |
The various states regulate the drilling for, and the production of, oil and natural gas, including
imposing severance taxes and requirements for obtaining drilling permits. States also regulate the
method of developing new fields, the spacing and operation of wells and the prevention of waste of
oil and natural gas resources. States may regulate rates of production and may establish maximum
daily production allowable from oil and gas wells based on market demand or resource conservation,
or both. States do not regulate wellhead prices or engage in other similar direct economic
regulation, but there can be no assurance that they will not do so in the future. The effect of
these regulations may be to limit the amounts of oil and natural gas that may be produced from our
wells, and to limit the number of wells or locations we can drill.
Regulation
The exploration, production and sale of oil and gas are extensively regulated by governmental
bodies. Applicable legislation is under constant review for amendment or expansion. Oil and gas
mineral rights may be held by individuals, corporations or governments having jurisdiction over the
area in which such mineral rights are located. As a general rule, parties holding such mineral
rights grant licenses or leases to third parties to facilitate the exploration and development of
these mineral rights. The terms of the leases and licenses are generally established to require
timely development. Notwithstanding the ownership of mineral rights, the government of the
jurisdiction in which mineral rights are located generally retains authority over the manner of
development of those rights.
Title to Properties
We believe that our title to the various interests set forth above is satisfactory and
consistent with generally accepted industry standards, subject to exceptions that would not
materially detract from the value of the interests or materially interfere with their use in our
operations. Individual properties may be subject to burdens such as royalty, overriding royalty
and other outstanding interests customary in the industry. In addition, interests may be subject
to obligations or duties under applicable laws or burdens such as production payments, net profits
interest, liens incident to operating agreements and for current taxes, development obligations
under crude oil and natural gas leases or capital commitments under production sharing contracts or
exploration licenses.
17
Endeavour International Corporation
Offices
Our principal executive offices are located at 1001 Fannin Street, Suite 1600, Houston, Texas
77002, and our telephone number is (713) 307-8700. Certain of our executive officers are also
located in our offices at 114 St. Martins Lane, London WC2N 4BE England and 1125 17th Street,
Suite 1525, Denver, Colorado 80202. We also have an office in Aberdeen, United Kingdom.
Available Information
We file annual and quarterly financial reports, as well as interim updates of a material
nature to investors, with the SEC. The public may read and copy any materials that we file with
the SEC at the SECs Public Reference Room at 100 F Street, NE, Washington, DC 20549. The public
may obtain information on the operation of the Public Reference Room by calling the SEC at
1-800-SEC-0330. Also, the SEC maintains a website that contains reports, proxy and information
statements and other information regarding issuers, including Endeavour, that file electronically
with the SEC. The public can obtain any document we file at the SEC web page, http://www.sec.gov.
Our website is available at http://www.endeavourcorp.com. We make available, free of charge, on
our website, the Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on
Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such
reports to the SEC. Also, our Governance Guidelines, the charters of the Audit Committee, the
Compensation Committee and the Governance, Nominating Committee and Technology & Reserves
Committee, and the Code of Conduct and Code of Ethics for Senior Officers are available on our
website and in print to any stockholder who provides a written request to the Corporate Secretary
at 1001 Fannin Street, Suite 1600, Houston, Texas 77002. Our Code of Conduct applies to all
directors, officers and employees, including the chief executive officer and chief financial
officer.
Information contained on or connected to our website is not incorporated by reference into this
Annual Report on Form 10-K and should not be considered part of this report or any other filing
that we make with the SEC.
Financial Information about Segment and Geographical Areas
Our revenues and long-lived assets by geographic area is included in Note 21 to our
consolidated financial statements in Item 8 and incorporated herein by reference.
Average Sales Prices and Production Costs by Geographical Area
Information on average sales prices and production costs by geographic area is included in
Item 7 and incorporated herein by reference.
18
Endeavour International Corporation
Item 1A. Risk Factors
Cautionary Statement Concerning Forward-Looking Statements
Certain matters discussed in this Annual Report on Form 10-K are forward-looking statements
intended to qualify for the safe harbors from liability established by the Private Securities
Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, as amended, or the
Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange
Act. These forward-looking statements include statements that express a belief, expectation, or
intention, as well as those that are not statements of historical fact, and may include projections
and estimates concerning the timing and success of specific projects and our future production,
revenues, income and capital spending. Our forward-looking statements are generally accompanied by
words such as estimate, project, predict, believe, expect, anticipate, potential,
plan, goal or other words that convey the uncertainty of future events or outcomes. We caution
you not to rely on them unduly. In particular, this Annual Report on Form 10-K contains
forward-looking statements pertaining to the following:
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our future financial position; |
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our business strategy; |
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budgets; |
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projected costs, savings and plans; |
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objectives of management for future operations; |
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legal strategies; and |
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legal proceedings. |
We have based these forward-looking statements on our current expectations and assumptions about
future events. While our management considers these expectations and assumptions to be reasonable,
they are inherently subject to significant business, economic, competitive, regulatory and other
risks, contingencies and uncertainties, most of which are difficult to predict and many of which
are beyond our control. These risks, contingencies and uncertainties, which may not be exhaustive,
relate to, among other matters, the following:
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discovery, estimation, development and replacement of oil and gas reserves; |
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decreases in proved reserves due to technical or economic factors; |
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drilling of wells and other planned exploitation activities; |
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timing and amount of future production of oil and gas; |
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the volatility of oil and gas prices; |
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availability and terms of capital; |
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operating costs such as lease operating expenses, administrative costs and other
expenses; |
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our future operating or financial results; |
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amount, nature and timing of capital expenditures, including future development costs; |
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cash flow and anticipated liquidity; |
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availability of drilling and production equipment; |
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uncertainties related to drilling and production operations in a new region; |
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cost and access to natural gas gathering, treatment and pipeline facilities; |
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business strategy and the availability of acquisition opportunities; and |
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Endeavour International Corporation
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factors not known to us at this time. |
Any of these factors, or a combination of these factors, could materially affect our future
financial condition or results of operations and the ultimate accuracy of the forward-looking
statements. The forward-looking statements are not guarantees of our future performance, and our
actual results and future developments may differ materially from those projected in the
forward-looking statements. In addition, any or all of our forward-looking statements in this
Annual Report on Form 10-K may turn out to be incorrect. They can be affected by inaccurate
assumptions we might make or by known or unknown risks and uncertainties, including those mentioned
in Item 1A. Risk Factors and elsewhere in this Annual Report on Form 10-K. Except as required by
law, we undertake no obligation to update publicly or release any revisions to these
forward-looking statements to reflect events or circumstances after the date of this Annual Report
on Form 10-K. These cautionary statements qualify all forward-looking statements attributable to us
or persons acting on our behalf.
Risks related to our business
We operate internationally and are subject to political, economic and other uncertainties.
We currently have operations in the U.S. and U.K. and may expand our operations to other countries
or regions. International operations are subject to political, economic and other uncertainties,
including:
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the risk of war, acts of terrorism, revolution, border disputes, expropriation,
renegotiation or modification of existing contracts, and import, export and transportation
regulations and tariffs; |
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taxation policies, including royalty and tax increases and retroactive tax claims; |
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exchange controls, currency fluctuations and other uncertainties arising out of foreign
government sovereignty over our international operations; |
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laws and policies of the U.S. affecting foreign trade, taxation and investment; and |
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the possibility of being subject to the exclusive jurisdiction of foreign courts in
connection with legal disputes and the possible inability to subject foreign persons to the
jurisdiction of courts in the U.S. |
The exploration, production and sale of oil and gas are extensively regulated by governmental
bodies, which subjects us to increased costs in order to comply with applicable laws and
regulations as well as significant uncertainties due to the potential for such laws and regulations
to change and evolve. Applicable legislation and regulations are under constant review for
amendment or expansion. These efforts frequently result in an increase in the regulatory burden on
companies in our industry and consequently an increase in the cost of doing business and
decrease in profitability. Numerous governmental departments and agencies are authorized to,
and have, issued rules and regulations imposing additional burdens on the oil and gas industry that
often are costly to comply with and carry substantial penalties for failure to comply. Production
operations are affected by changing tax and other laws relating to the petroleum industry, by
constantly changing administrative regulations and possible interruptions or termination by
government authorities.
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Endeavour International Corporation
Oil and gas mineral rights may be held by individuals, corporations or governments having
jurisdiction over the area in which such mineral rights are located. As a general rule, parties
holding such mineral rights grant licenses or leases to third parties to facilitate the exploration
and development of these mineral rights. The terms of the leases and licenses are generally
established to require timely development. Notwithstanding the ownership of mineral rights, the
government of the jurisdiction in which mineral rights are located generally retains authority over
the manner of development of those rights. As such, we may become subject to certain requirements,
obligations and timelines as established or demanded by the holder of the oil and gas mineral
rights and such requirements or obligations may adversely impact our operations, cash flow and
capital plans.
Economic conditions in the U.S. and key international markets may materially adversely impact our
operating results, which could hinder or prevent us from meeting our future capital needs.
The U.S., U.K. and other world economies are slowly recovering from a recession which began in 2008
and extended into 2009. Growth has resumed, but remains modest. There are likely to be
significant long-term effects resulting from the recession and credit market crisis, including a
future global economic growth rate that is slower than what was experienced in recent years. In
addition, more volatility may occur before a sustainable, yet lower, growth rate is achieved.
Because global economic growth drives demand for energy from all sources, including fossil fuels, a
lower future economic growth rate will result in decreased demand growth for our crude oil and
natural gas production as well as lower commodity prices, which will reduce our cash flows from
operations and our profitability and may adversely affect our ability to obtain funding for our
projects.
Due to these and other factors, we cannot be certain that funding will be available if needed, and
to the extent required, on acceptable terms or at all. If funding is not available as needed, or
is available only on unfavorable terms, we may be unable to (i) meet our obligations as they come
due, (ii) refinance or extend the maturity of our outstanding 6% Senior Convertible Notes which
would result in the Senior Term Loan maturing and becoming due and payable in full on October 14,
2011, or (iii) implement our capital program, enhance our existing business, complete acquisitions
or otherwise take advantage of business opportunities or respond to competitive
pressures, any of which could have a material adverse effect on our production, revenues,
results of operations and prospects.
Oil and gas prices are volatile, and a decline in oil and gas prices would reduce our revenues,
profitability and cash flow and impede our growth.
Our revenues, profitability and cash flow depend substantially upon the prices and demand for oil
and gas. The markets for these commodities are volatile, and even relatively modest drops in
prices can significantly affect our financial results and impede our growth. Oil and gas prices
increased to, and then declined significantly from, historical highs in 2008 and may fluctuate and
decline significantly in the near future. Prices for oil and gas fluctuate in response to
relatively
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Endeavour International Corporation
minor changes in the supply and demand for oil and gas, market uncertainty and a variety
of additional factors beyond our control, such as:
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global supply of oil and gas; |
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level of consumer product demand; |
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technological advances affecting oil and gas consumption; |
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global economic conditions; |
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price and availability of alternative fuels; |
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actions of the Organization of Petroleum Exporting Countries and other state-controlled
oil companies relating to oil price and production controls; |
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governmental regulations and taxation; |
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political conditions in or affecting other oil-producing and gas-producing countries; |
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weather conditions; |
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the proximity, capacity, cost and availability of pipeline and other transportation
facilities; and |
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the impact of energy conservation efforts. |
Lower oil and gas prices may not only decrease our revenues on a per unit basis, but significant or
extended price declines may also reduce the amount of oil and gas that we can produce economically.
A reduction in production could result in a shortfall in expected cash flows and require us to
reduce capital spending or borrow funds to cover any such shortfall. Any of these factors could
negatively impact our future rate of growth and ability to replace our production.
In addition, we may, from time to time, enter into long-term contracts based upon our reasoned
expectations for commodity price levels. If commodity prices subsequently decrease significantly
for a sustained period, we may be unable to perform our obligations or otherwise breach the
contract and be liable for damages.
Competition for oil and gas properties and prospects is intense and some of our competitors
have larger financial, technical and personnel resources that give them an advantage in evaluating,
obtaining and developing properties and prospects.
We operate in a highly competitive environment for reviewing prospects, acquiring properties,
marketing oil and gas and securing trained personnel. Many of our competitors are major or
independent oil and gas companies that have longer operating histories in our areas of operation
and employ superior financial resources which allow them to obtain substantially greater technical
and personnel resources and which better enable them to acquire and develop the prospects that they
have identified. We also actively compete with other companies when acquiring new licenses or oil
and gas properties. Specifically, competitors with greater resources than our own have certain
advantages that are particularly important in reviewing prospects and purchasing properties.
Competitors may be able to evaluate, bid for and purchase a greater number of properties and
prospects than our financial or personnel resources permit. Competitors may also be able to pay
more for producing oil and gas properties and exploratory prospects than we are able or willing to
pay. If we are unable to compete successfully in these areas in the future, our future revenues
and growth may be diminished or restricted.
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Endeavour International Corporation
These competitors may also be better able to withstand sustained periods of unsuccessful drilling
or downturns in the economy, including decreases in the price of commodities as experienced in 2008
and 2009. Larger competitors may also be able to absorb the burden of any changes in laws and
regulations more easily than we can, which would also adversely affect our competitive position.
In addition, most of our competitors have been operating for a much longer time and have
demonstrated the ability to operate through industry cycles.
Our use of derivative transactions may limit future revenues from price increases and involves the
risk that our counterparties may be unable to satisfy their obligations to us.
To manage our exposure to price or interest rate risk with our production, we routinely enter into
commodity derivative contracts. The goal of these derivative contracts is to limit volatility and
increase the predictability of cash flow. Although the use of derivative contracts limits the
downside risk of price declines, their use also may limit future revenues from price increases. In
addition, derivative contracts may expose us to the risk of financial loss in certain
circumstances, including instances in which our production is less than expected or a sudden,
unexpected event materially impacts oil or gas prices.
Derivative contracts also involve the risk that counterparties, which generally are financial
institutions, may be unable to satisfy their obligations to us. If any one of our counterparties
were to default on its obligations to us under the derivative contracts or seek bankruptcy
protection it could have a material adverse effect on our expected cash flows and our ability to
fund our planned activities and could result in a larger percentage of our future production
being subject to commodity price changes. In addition, in the current economic environment and
tight financial markets, the risk of a counterparty default is heightened and it is possible that
fewer counterparties will participate in future derivative transactions, which could result in
greater concentration of our exposure to any one counterparty or a larger percentage of our future
production being subject to commodity price changes.
We are dependent on our executive officers and need to attract and retain additional qualified
personnel.
Our future success depends in large part on the service of our executive officers. The loss of
these executives could have a material adverse effect on our business. Although we have employment
agreements with certain of our executive officers, there can be no assurance that we will have the
ability to retain their services. Further, we do not maintain key-person life insurance on any
executive officers.
Our future success also depends upon our ability to attract, assimilate and retain highly qualified
technical and other management personnel who are essential for the identification and development
of our prospects. There can be no assurance that we will be able to attract, integrate and retain
key personnel, and our failure to do so would have a material adverse effect on our business.
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Endeavour International Corporation
Our operations are sensitive to currency rate fluctuations.
Our operations are sensitive to fluctuations in foreign currency exchange rates, particularly
between the U.S. dollar and the British pound. Our financial statements, presented in U.S.
dollars, are affected by foreign currency fluctuations through both translation risk and
transaction risk. Volatility in exchange rates may adversely affect our results of operation,
particularly through the weakening of the U.S. dollar relative to other currencies.
Risks related to executing our strategy and operations
To maintain and grow our production and cash flow, we must continue to develop and produce
existing reserves and discover or acquire new oil and gas reserves to develop and produce.
Our future oil and gas production is highly dependent upon our level of success in finding or
acquiring additional reserves. Producing oil and gas reserves are generally characterized by
declining production rates that vary depending on reservoir characteristics and other factors. Our
reserves will decline unless we acquire properties with proved reserves or conduct successful
development and exploration drilling activities. We accomplish this through successful drilling
programs and the acquisition of properties. However, we may be unable to find, develop or
acquire additional reserves or production at an acceptable cost or at all. Acquisition
opportunities in the oil and gas industry are very competitive, which can increase the cost of, or
cause us to refrain from, completing acquisitions.
If we are unable to find, develop or acquire additional reserves to replace our current and future
production, our production rates will decline even if we drill the undeveloped locations that were
included in our estimated proved reserves. Our future oil and gas reserves and production, and
therefore our cash flow and income, are dependent on our success in economically finding or
acquiring new reserves and efficiently developing our existing reserves.
We may be unable to make attractive acquisitions, and any acquisition we complete is subject to
substantial risks that could impact our business.
As part of our growth strategy, we intend to continue to pursue strategic acquisitions of new
properties or businesses that expand our current asset base and potentially offer unexploited
reserve potential. Our growth strategy could be impeded if we are unable to acquire additional
interests in oil and gas prospects on a profitable basis. Acquisition opportunities in the oil and
gas industry are very competitive, which can increase the cost of, or cause us to refrain from,
completing acquisitions. The success of any acquisition will depend on a number of factors and
involves potential risks, including among other things:
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the inability to estimate accurately the costs to develop the interests in oil and gas
prospects, the recoverable volumes of reserves, rates of future production and future net
cash flows attainable from the reserves; |
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the assumption of unknown liabilities, losses or costs for which we are not indemnified
or for which the indemnity we receive is inadequate; |
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Endeavour International Corporation
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the validity of assumptions about costs, including synergies; |
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the impact on our liquidity or financial leverage of using available cash or debt to
finance acquisitions; |
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the diversion of managements attention from other business concerns; and |
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an inability to hire, train or retain qualified personnel to manage and operate our
growing business and assets. |
All of these factors affect whether an acquisition will ultimately generate cash flows sufficient
to provide a suitable return on investment. Consistent with industry practices, we typically are
only able to perform limited reviews of the properties we seek to acquire. As a result, among
other risks, our initial estimates of reserves, and the costs associated with developing those
estimated reserves, may be subject to revision following an acquisition, which may materially and
adversely impact the desired benefits of the acquisition.
Our expectations for future drilling and development activities will be realized over several
years, making them susceptible to uncertainties that could materially alter the occurrence or
timing of such activities.
We have identified drilling locations, prospects for future drilling opportunities and development
plans for our commercial discoveries, including development, exploratory and other drilling and
enhanced recovery activities. These drilling and development locations and prospects represent a
significant part of our future drilling and development plans. Our ability to drill and develop
these locations depends on a number of factors, including the availability of capital, seasonal
conditions, third-party operators, regulatory approvals, negotiation of agreements with third
parties, commodity prices, costs and drilling results. In particular, delays in obtaining
regulatory approvals relating to our field development programs for our North Sea discoveries can
materially impact our ability to commence production at these discoveries which would materially
impact our reserves, cash flow and results of operations. Furthermore, because of these
uncertainties, we cannot give any assurance as to the timing of these activities or that they will
ultimately result in the realization of proved reserves or meet our expectations for success. As
such, our actual drilling and enhanced recovery activities may materially differ from our current
expectations, which could have a significant adverse effect on our financial condition and results
of operations.
Our drilling projects are based in part on seismic and other technical data, which cannot ensure
the commercial success of a prospect.
Our decisions to purchase, explore, develop and exploit prospects or properties depend in part on
data obtained through geophysical and geological analyses, production data and engineering studies,
the results of which are often uncertain. Seismic data and visualization techniques only assist
geoscientists and geologists in identifying subsurface structures and hydrocarbon indicators and do
not enable an interpreter to conclusively determine whether hydrocarbons are present or producible
economically. In addition, the use of seismic and other advanced technologies may require greater
predrilling expenditures than other drilling strategies. Because of these factors and the inherent
uncertainties surrounding the evaluation of exploration prospects, we could incur losses as a
result of exploratory drilling expenditures. Poor results
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Endeavour International Corporation
from drilling activities would have a
material adverse effect on our future cash flows, ability to replace reserves and results of
operations.
Reserve estimates depend on many assumptions that may turn out to be inaccurate and any
material inaccuracies in the reserve estimates or underlying assumptions of our assets will
materially affect the quantities and present value of those reserves.
Estimating oil and gas reserves is complex and inherently imprecise. It requires interpretation of
the available technical data and making many assumptions about future conditions, including price
and other economic factors. In preparing such estimates, projection of production rates, timing of
development expenditures and available geological, geophysical, production and engineering data are
analyzed. The extent, quality and reliability of these data can vary. This process also requires
economic assumptions about matters such as oil and gas prices, drilling and operating expenses,
capital expenditures, taxes and availability of funds. If our interpretations or assumptions used
in arriving at our reserve estimates prove to be inaccurate, the amount of oil and gas that will
ultimately be recovered may differ materially and adversely from the estimated quantities and net
present value of reserves owned by us.
A significant portion of our total estimated net proved reserves at December 31, 2010 were
undeveloped, and those reserves may not ultimately be developed.
At December 31, 2010, approximately 81% of our total estimated net proved reserves were
undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and
successful drilling. Our reserve data assumes that we can and will make these expenditures and
conduct these operations successfully. These assumptions, however, may not prove correct. If we
choose not to spend the capital to develop these reserves or if we are not otherwise able to
successfully develop these reserves we may be required to write-off these reserves. Any such
write-offs of our reserves could materially reduce our ability to borrow money and the value of our
securities.
Our offshore operations involve special risks that could increase our cost of operations and
adversely affect our ability to produce oil and gas.
Offshore operations are subject to a variety of operating risks specific to the marine environment,
such as capsizing, collisions and damage or loss from hurricanes or other adverse weather
conditions. These conditions can cause substantial damage to facilities and interrupt production.
As a result, we could incur substantial liabilities that could reduce or eliminate the funds
available for exploration, development or leasehold acquisitions, or result in loss of equipment
and properties. Offshore drilling in the North Sea generally requires more time and more advanced
drilling technologies, involving a higher risk of technological failure and usually higher drilling
costs. Moreover, offshore projects often lack proximity to the physical and oilfield service
infrastructure, necessitating significant capital investment in subsea flow line infrastructure.
Subsea tieback production systems require substantial time and the use of advanced and very
sophisticated installation equipment supported by remotely operated vehicles.These operations may encounter mechanical difficulties and equipment failures that could
result in significant cost overruns. As a result, a significant amount of time and capital must be
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Endeavour International Corporation
invested before we can market the associated oil or gas, increasing both the financial and
operational risk involved with these operations. Because of the lack and high cost of
infrastructure, some offshore reserve discoveries may never be produced economically.
We have commenced exploration, production and development operations in the United States, and as a
result, our ability to successfully achieve our goals is subject to greater risk and uncertainty.
In 2008, we began to pursue exploration, production and development activities in the U.S.
Moreover, we did not have a significant U.S. presence in our assets and operations until late 2009.
Because we have limited production history in the U.S. and do not have extensive experience in
unconventional resource plays, we are less able to use past operational results to help predict
future results. Our lack of operational experience in the U.S. may result in our not being able to
fully execute our expected drilling programs in this region, and the return on investment from our
United States operations may not be as attractive as expected. We cannot assure you that our
efforts in the U.S. will be successful, or if successful will achieve the resource potential levels
that we currently anticipate or achieve the anticipated economic returns based on our current
financial models.
We are not the operator of our producing fields and will not be the operator of all of the
interests we own or acquire, and therefore we may not be in a position to control the timing of
development efforts, the associated costs, or the rate of production of the reserves in respect of
such interests.
A significant number of our interests, including all of our producing fields, are currently
operated by third parties. As a result, we may have limited ability to exercise influence over the
operations of these interests or their associated costs. Dependence on the operator and other
working interest owners for these projects, and limited ability to influence operations and
associated costs could prevent the realization of expected returns on capital in drilling or
acquisition activities. The success and timing of development and exploitation activities on
properties operated by others depend upon a number of factors that will be largely outside our
control, including:
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the operators expertise and financial resources; |
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the timing and amount of their capital expenditures; |
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the rate of production of the reserves; |
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approval of other participants to drill wells and implement other work programs; |
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the availability of suitable drilling rigs, drilling equipment, support vessels,
production and transportation infrastructure and qualified operating personnel; and |
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selection of technology. |
Our inability to control the development efforts, costs and timing on the interests where we are
not the operator could have a material adverse effect on our financial conditions, results of
operations and business prospects.
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Actual production could differ significantly from forecasts.
From time to time we provide forecasts of expected quantities of future oil and gas production.
These forecasts are based on a number of estimates, including expectations of production decline
rates from existing wells, outcomes from future drilling activity and assumptions relating to
ongoing operations and maintenance of producing wells. Should these estimates prove inaccurate,
actual production could be adversely impacted. Furthermore, downturns in commodity prices could
make certain drilling activities or production uneconomical, which would also adversely impact
production. We may also adjust estimates of proved reserves to reflect production history, results
of exploration and development, prevailing oil and gas prices and other factors, many of which are
beyond our control.
Our insurance may not protect us against business and operating risks, including an operator of a
prospect in which we participate failing to maintain or obtain adequate insurance.
Oil and gas operations are subject to particular hazards incident to the drilling and production of
oil and gas, such as blowouts, cratering, explosions, uncontrollable flows of oil, gas or well
fluids, fires and pollution and other environmental risks. These hazards can cause personal injury
and loss of life, severe damage to and destruction of property and equipment, pollution or
environmental damage and suspension of operations. We maintain insurance for some, but not all, of
the potential risks and liabilities associated with our business. If a significant accident or
other event resulting in damage to our operations, including severe weather, terrorist acts, war,
civil disturbances, pollution or environmental damage, occurs and is not fully covered by
insurance, it could adversely affect our financial condition and results of operations. We do not
currently operate all of our oil and gas properties. In the projects in which we own non-operating
interests, the operator may maintain insurance of various types to cover our operations with policy
limits and retention liability customary in the industry. The occurrence of a significant adverse
event that is not fully covered by insurance could result in the loss of our total investment in a
particular prospect and additional liability for us, which could have a material adverse effect on
our financial condition and results of operations and prospects.
The cost of decommissioning is uncertain.
We expect to incur obligations to abandon and decommission certain structures associated with our
producing properties. To date, the industry has little experience of removing oil and gas
structures from the North Sea, because few of the structures in the North Sea have been removed.
Because experience in limited, we cannot precisely predict the costs of any future decommissions
for which we might become obligated. Furthermore, we are required to post collateral as security
over certain of our decommissioning liabilities in the North Sea. If actual decommission or
abandonment costs exceed our estimates or reserves to satisfy such obligations, or we are required
to provide a significant amount of collateral in cash or other security for these future costs, our
financial condition, results of operations and prospects could be materially adversely affected.
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Endeavour International Corporation
Risks related to access to capital and financing
Our development and exploration operations require substantial capital, and we may be unable
to obtain needed capital or financing on satisfactory terms, which could lead to a loss of
properties and a decline in our oil and gas reserves.
The oil and gas industry is capital intensive. We make and expect to continue to make substantial
capital expenditures in our business and operations for the exploration, development, production
and acquisition of oil and gas reserves, including expenditures relating to the development of our
discoveries in the North Sea and our acreage position in the Haynesville Shale and other U.S.
plays. We intend to finance our future capital expenditures primarily with cash flow from
operations and borrowings under our Senior Term Loan. Our cash flow from operations and access to
capital is subject to a number of variables, including:
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our oil and gas reserves; |
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the level of natural gas and crude oil we are able to produce from existing wells; |
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the prices at which natural gas and crude oil are sold; and |
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our ability to acquire, locate and produce new reserves. |
If our revenues decrease as a result of lower oil and gas prices, operating difficulties, declines
in reserves or for any other reason, we may have limited ability to obtain the capital necessary to
sustain our operations at current levels or to further develop and exploit our current properties,
or for exploratory activity. In order to fund our capital expenditures, we may need to seek
additional financing. Our credit agreements contain covenants restricting our ability to incur
additional indebtedness without the consent of the lenders. Our lenders may withhold this consent
in their sole discretion.
Furthermore, we may not be able to obtain debt or equity financing on terms favorable to us,
or at all. In particular, the cost of raising money in the debt and equity capital markets has
increased substantially while the availability of funds from those markets generally has diminished
significantly. Also, as a result of concerns about the stability of financial markets generally
and the solvency of counterparties specifically, the cost of obtaining money from the credit
markets generally has increased as many lenders and institutional investors have increased interest
rates, enacted tighter lending standards, refused to refinance existing debt at maturity on terms
that are similar to existing debt, and reduced, or in some cases ceased, to provide funding to
borrowers. The failure to obtain additional financing could result in a curtailment of our
operations relating to exploration and development of our prospects, which in turn could lead to a
possible loss of properties and a decline in our natural gas, crude oil and natural gas liquids
reserves.
Our debt levels could negatively impact our financial condition, results of operations and business
prospects.
As of December 31, 2010, we had $349.6 million in outstanding indebtedness. Our level of
indebtedness could have important consequences on our operations, including:
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placing restrictions on certain operating activities; |
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making it more difficult for us to satisfy our obligations under our indentures or the
terms of our other debt instruments and increasing the risk that we may default on our debt
obligations; |
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requiring us to dedicate a substantial portion of our cash flow from operating
activities to required payments on debt, thereby reducing the availability of cash flow for
working capital, capital expenditures and other general business activities; |
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limiting our ability to obtain additional financing in the future for working capital,
capital expenditures, acquisitions and other general business activities; |
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decreasing our ability to withstand a downturn in our business or the economy
generally; and |
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placing us at a competitive disadvantage against other less leveraged competitors. |
We may not have sufficient funds to repay our outstanding debt. If we are unable to repay our debt
out of cash on hand, we could attempt to refinance such debt, sell assets or repay such debt with
the proceeds from an equity offering. In addition, we cannot assure you that we will be able to
generate sufficient cash flow from operating activities to pay the interest on our debt or that
future borrowings, equity financings or proceeds from the sale of assets will be available to repay
or refinance such debt. Furthermore, some of our existing debt instruments contain certain
restrictions on our ability to repay other debt. For example, our Senior Term Loan prohibits cash
on hand from being used to repay any debt other than that extended pursuant to the related
Credit Agreement.
Factors that will affect our ability to raise cash through an offering of our capital stock, a
refinancing of our debt or a sale of assets include financial market conditions, our market value,
our reserve levels and our operating performance at the time of such offering or other financing.
We cannot assure you that any such offering, refinancing or sale of assets can be successfully
completed. The inability to repay or refinance our debt could have a material adverse effect on
our operations and negatively impact our capital program.
Failure to satisfy certain covenants in our Senior Term Loan could cause this debt to come due
prematurely.
Unless we are able to successfully refinance or extinguish our outstanding 6% Convertible Senior
Notes due 2012 and extend the ability of the holders of our 11.5% Convertible Senior Bonds due 2014
to require us to repurchase such notes, our Senior Term Loan will mature and become payable in full
on October 14, 2011. If required to repay our Senior Term Loan in full on that date, our available
cash would be severely impacted. We would also need to find alternative sources of liquidity to
fund the repayment of the Senior Term Loan and our ongoing
development and exploration operations. Therefore, our failure to
repay the Senior Term Loan when due would be an event of default with
respect to our other outstanding indebtedness, which could cause all
$349.6 million of our debt outstanding at December 31, 2010 to become
immediately due and payable.
We can provide no assurance that we would be able to find alternative sources of liquidity on
commercially reasonable terms, or at all, if required.
30
Endeavour International Corporation
A change of control may adversely affect our liquidity and require refinancing of certain debt
instruments.
Upon certain specified change of control events, each lender under our debt agreements may cancel
the facility and declare as due and payable any outstanding loans plus accrued and unpaid interest,
outstanding letters of credit and other outstanding fees. We cannot assure you we would have
sufficient financial resources to purchase the notes for cash or repay the lenders under our debt
agreements upon the occurrence of a change of control. If a change of control occurs, we may be
required to refinance our indebtedness. There can be no assurance that we would be able to
refinance our indebtedness or, if a refinancing were to occur, that the refinancing would be on
terms favorable to us.
If we are unable to fulfill commitments under any of our oil and gas interests, we will lose our
interest, and our entire investment, in such interest.
Our ability to retain oil and gas interests will depend on our ability to fulfill the commitments
made with respect to each interest. We cannot assure you that we or the other participants in the
projects will have the financial ability to fund these potential commitments. If we are unable to
fulfill commitments under any of our interests, we will lose our interest, and our entire
investment, in such interest.
Risks related to environmental and other regulations
We are subject to environmental regulations that can have a significant impact on our
operations.
Our operations are subject to a variety of national, state, local and international laws and
regulations governing the discharge of materials into the environment or otherwise relating to
environmental protection. Failure to comply with these laws and regulations can result in the
imposition of substantial fines and penalties as well as potential orders suspending or terminating
our rights to operate. Some environmental laws to which we are subject to provide for strict
liability for pollution damages and cleanup costs, rendering a person liable without regard to
negligence or fault on the part of such person. In addition, we may be subject to claims alleging
personal injury or property damage as a result of alleged exposure to hazardous substances such as
oil and gas related products. Aquatic environments in which we operate are often particularly
sensitive to environmental impacts, which may expose us to greater potential liability than that
associated with exploration, development and production at many onshore locations.
Changes in environmental laws and regulations occur frequently, and any changes that result in more
stringent or costly requirements for oil and gas exploration and production activities could
require us, as well as others in our industry, to make significant expenditures to attain and
maintain compliance which could have a corresponding material adverse effect on our competitive
position, financial condition or results of operations. We cannot provide assurance that we will
be able to comply with future laws and regulations to the same extent that we have complied in the
past. Similarly, we cannot always precisely predict the potential impact of
31
Endeavour International Corporation
environmental laws and
regulations which may be adopted in the future, including whether any such laws or regulations
would restrict our operations in any area.
Current and future environmental regulations, including restrictions on emissions of greenhouse
gases due to concerns about climate change, could reduce the demand for our products. Our
business, financial condition and results of operations could be materially and adversely affected
if this were to occur.
Under certain environmental laws and regulations, we could be subject to liability arising out of
the conduct of operations or conditions caused by others, or for activities that were in compliance
with all applicable laws at the time they were performed. Such liabilities can be significant, and
if imposed could have a material adverse effect on our financial condition or results of
operations.
Governmental regulations to which we are subject could expose us to significant fines and/or
penalties and our cost of compliance with such regulations could be substantial.
Oil and gas exploration, development and production are subject to various types of regulation by
local, state and national agencies. Regulations and laws affecting the oil and gas industry are
comprehensive and under constant review for amendment and expansion. These regulations and laws
carry substantial penalties for failure to comply. The regulatory burden on the oil and gas
industry increases our cost of doing business and, consequently, adversely affects our
profitability. In addition, competitive conditions may be substantially affected by various forms
of energy legislation and/or regulation considered from time to time by the governments and/or
agencies thereof.
Federal and state legislative regulatory initiatives relating to hydraulic fracturing could result
in increased costs and additional operating restrictions or delays.
Hydraulic fracturing is an important and common practice that is used to stimulate production of
hydrocarbons, particularly natural gas, from tight formations. We routinely utilize hydraulic
fracturing techniques in many of our natural gas well drilling and completion programs. The
process involves the injection of water, sand and chemicals under pressure into the formation to
fracture the surrounding rock and stimulate production. The process is typically regulated by
state oil and gas commissions. However, the EPA recently asserted federal regulatory authority
over hydraulic fracturing involving diesel additives under the Safe Drinking Water Acts
Underground Injection Control Program. While the EPA has yet to take any action to enforce or
implement this newly asserted regulatory authority, industry groups have filed suit challenging the
EPAs recent decision. At the same time, the EPA has commenced a study of the potential
environmental impacts of hydraulic fracturing activities. Legislation has been introduced before
Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the
chemicals used in the fracturing process. In addition, some states have adopted, and other states
are considering adopting, regulations that could impose more stringent permitting, disclosure and
well construction requirements on hydraulic fracturing operations. For example, Pennsylvania,
Colorado, and Wyoming have each adopted a variety of well construction, set back, and disclosure
regulations limiting how fracturing can be performed and requiring various degrees of
32
Endeavour International Corporation
chemical disclosure. If new laws or regulations that significantly restrict hydraulic fracturing are
adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate
production from tight formations. In addition, if hydraulic fracturing becomes regulated at the
federal level as a result of federal legislation or regulatory initiatives by the EPA, our
fracturing activities could become subject to additional permitting requirements, and also to
attendant permitting delays and potential increases in costs. Restrictions on hydraulic fracturing
could also reduce the amount of oil and natural gas that we are ultimately able to produce from our
reserves.
Climate change legislation or regulations restricting emissions of greenhouse gases could
result in increased operating costs and reduced demand for the crude oil and natural gas that we
produce.
There are a number of programs at the international, national, and local levels that aim to reduce
greenhouse gas emissions. Changes to the existing laws or the enactment of new laws and
regulations could increase our operating costs and reduce demand for our products. At this time,
there is substantial uncertainty about the future of GHG emission limitations in the areas where we
operate. For example, the first commitment period of the Kyoto Protocol is due to expire in 2012.
Because the Cancun negotiations failed to reach a binding global agreement on climate change, we
face uncertainty regarding the structure of a future international regime and potential
implementing national laws addressing GHGs.
Rapidly evolving domestic legal and regulatory structures governing GHG emissions may increase the
costs imposed upon our operations. For example, since December 2009, the United States
Environmental Protection Agency has declared that GHGs threaten the environment, imposed
limitations on GHGs from mobile sources and certain large stationary sources, and required certain
industries to monitor and report their GHG emissions. These rules are all currently subject to
legal challenges, but to this point, federal courts have refused to prevent EPA from implementing
them. In addition, by the end of 2012, the EPA intends to impose New Source Performance Standards
under the Clean Air Act that will apply to all fossil-fuel fired power plants and petroleum
refineries. To the extent we or our customers are subject to any of these regulations, we may face
increased costs and decreased demand for our product.
The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could
require us to incur increased operating costs, such as costs to purchase and operate emissions
control systems, to acquire emissions allowances or comply with new regulatory or reporting
requirements. Any such legislation or regulatory programs could also increase the cost of
consuming, and thereby reduce demand for, the oil and natural gas we produced. Consequently,
legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse
effect on our business, financial condition and results of operations.
The recent adoption of derivatives legislation by the United States Congress could have an adverse
effect on our ability to use derivative instruments to reduce the effect of commodity price,
interest rate and other risks associated with our business.
The United States Congress adopted comprehensive financial reform legislation that establishes
federal oversight and regulation of the over-the-counter derivatives market and entities, such as
us, that participate in that market. The new legislation, known as the Dodd-Frank Wall Street
33
Endeavour International Corporation
Reform and Consumer Protection Act (the Act), was signed into law by the President on July 21,
2010 and requires the Commodities Futures Trading Commission (the CFTC) and the SEC
to promulgate rules and regulations implementing the new legislation within 360 days from the
date of enactment. In its rulemaking under the Act, the CFTC has proposed regulations to set
position limits for certain futures and option contracts in the major energy markets and for swaps
that are their economic equivalents. Certain bona fide hedging transactions or positions would be
exempt from these position limits. It is not possible at this time to predict when the CFTC will
finalize these regulations. The financial reform legislation may also require us to comply with
margin requirements and with certain clearing and trade-execution requirements in connection with
our derivative activities, although the application of those provisions to us is uncertain at this
time. The financial reform legislation may also require the counterparties to our derivative
instruments to spin off some of their derivatives activities to a separate entity, which may not be
as creditworthy as the current counterparty. The new legislation and any new regulations could
significantly increase the cost of derivative contracts (including through requirements to post
collateral which could adversely affect our available liquidity), materially alter the terms of
derivative contracts, reduce the availability of derivatives to protect against risks that we
encounter, reduce our ability to monetize or restructure our existing derivative contracts, and
increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as
a result of the legislation and regulations, our results of operations may become more volatile and
our cash flows may be less predictable, which could adversely affect our ability to plan for and
fund capital expenditures. Finally, the legislation was intended, in part, to reduce the
volatility of oil and natural gas prices, which some legislators attributed to speculative trading
in derivatives and commodity instruments related to oil and natural gas. Our revenues could
therefore be adversely affected if a consequence of the legislation and regulations is to lower
commodity prices. Any of these consequences could have a material, adverse effect on us, our
financial condition, and our results of operations.
Certain federal income tax deductions currently available with respect to oil and natural gas
exploration and development may be eliminated as a result of proposed legislation.
Legislation has been proposed that would, if enacted into law, make significant changes to U.S.
federal income tax laws, including the elimination of certain key U.S. federal income tax
incentives currently available to oil and natural gas exploration and production companies. These
changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for
oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling
and development costs, (iii) the elimination of the deduction for certain domestic production
activities, and (iv) an extension of the amortization period for certain geological and geophysical
expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how
soon any such changes could become effective. The passage of this legislation or any other similar
changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are
currently available with respect to oil and natural gas exploration and
development, and any such change could negatively impact the value of an investment in our
common stock.
34
Endeavour International Corporation
Risks related to potential impairments
Our financial results could be adversely affected by goodwill impairments.
As a result of mergers, acquisitions and dispositions, at December 31, 2010 we had $211.9 million
of goodwill on our balance sheet. Goodwill is not amortized, but instead must be tested at least
annually for impairment by applying a fair-value-based test. Goodwill is deemed impaired to the
extent that its carrying amount exceeds the fair value of the reporting unit. Although our latest
tests indicate that no goodwill impairment is currently required, future deterioration in market
conditions could lead to goodwill impairments that could have a substantial negative effect on our
profitability.
Lower oil and gas prices and other factors may result in ceiling test write-downs or other
impairments.
We capitalize the costs to acquire, find and develop our oil and gas properties under the full cost
accounting method. The net capitalized costs of our oil and gas properties may not exceed the
present value of estimated future net cash flows from proved reserves, plus the lower of cost or
fair market value for unproved properties. This quarterly test is called a ceiling test. If net
capitalized costs of our oil and gas properties exceed this ceiling test, we must charge the amount
of the excess to earnings. Although a ceiling test write-down does not impact cash flow from
operating activities, it does reduce net income and our shareholders equity. Once recorded, a
ceiling test write-down is not reversible at a later date even if oil and gas prices increase.
We review the net capitalized costs of our properties quarterly, based on prices in effect
(excluding the effect of our hedging contracts that are not designated for hedge accounting) as of
the end of each quarter or as of the time of reporting our results. We also assess investments in
unproved properties periodically to determine whether impairment has occurred.
The risk that we will be required to further write down the carrying value of our oil and gas
properties increases when oil and gas prices are low or volatile. In addition, write-downs may
occur if we experience substantial downward adjustments to our estimated proved reserves or our
unproved property values, or if estimated future development costs increase. We may experience
further ceiling test write-downs or other impairments in the future. In addition, any future
ceiling test cushion would be subject to fluctuation as a result of acquisition or divestiture
activity.
Risks relating to our common stock
An active liquid trading market for our common stock may not be maintained and the trading
price of our common stock may be volatile.
Liquid and active trading markets usually result in less price volatility and more efficiency in
carrying out stockholders purchase and sale orders. Smaller capitalized companies like ours often
experience substantial fluctuations in the trading price of their securities. An active and liquid
trading market for our common stock may not be maintained. In 2010, we undertook a
35
Endeavour International Corporation
one-for-seven
share consolidation which significantly reduced the number of shares outstanding and eligible for
trading. The trading price of our common stock has fluctuated significantly and may be subject to
similar fluctuations in the future. The market price of our common stock could vary significantly
as a result of a number of factors, some of which are beyond our control.
If we, our existing stockholders or holders of our securities that are convertible into shares
of our common stock sell any shares of our common stock, the market price of our common stock could
significantly decline.
The market price of our common stock could decline as a result of sales of a large number of shares
of common stock in the public market or the perception that such sales could occur. These sales,
or the possibility that these sales may occur, might make it more difficult for us to sell equity
securities in the future at a time and at a price that we deem appropriate.
As of February 28, 2011, we had approximately 24.9 million shares of common stock outstanding. Of
those shares, approximately 0.9 million shares are restricted shares subject to vesting periods of
up to three years. The remainder of these shares is freely tradable.
In addition, 0.3 million shares are issuable upon the exercise of presently outstanding stock
options under our employee incentive plans and 0.1 million shares are issuable upon the exercise of
presently outstanding options and warrants outside our employee incentive plans. Also 2.3 million
shares are issuable upon the conversion of our 6% Convertible Senior
Notes and 5.1 million shares
are issuable upon conversion of our Series C Preferred Stock, based upon the conversion price of
$8.75 per share, and 3.4 million shares are issuable upon conversion of our 11.5% Convertible
Bonds, based on a conversion price of $16.52.
Provisions in our articles of incorporation, bylaws and the Nevada Revised Statutes may
discourage a change of control.
Certain provisions of our amended and restated articles of incorporation and amended and restated
bylaws and the Nevada Revised Statutes (NRS) could delay or make more difficult a change of
control transaction or other business combination that may be beneficial to stockholders. These
provisions include, but are not limited to, the ability of our board of directors to issue a series
of preferred stock, classification of our board of directors into three classes and limiting the
ability of our stockholders to call a special meeting.
We are subject to the Combinations With Interested Stockholders Statute and the Control Share
Acquisition Statute of the NRS. The Combinations Statute provides that specified persons who,
together with affiliates and associates, own, or within three years did own, 10% or more of the
outstanding voting stock of a corporation cannot engage in specified business combinations with the
corporation for a period of three years after the date on which the person became an interested
stockholder, unless the combination or the transaction by which the person first became an
interested stockholder is approved by the corporations board of directors before the person first
became an interested stockholder.
36
Endeavour International Corporation
The Control Share Acquisition Statute provides that persons who acquire a controlling
interest as defined by the statute, in a company may only be given full voting rights in their
shares if such rights are conferred by the stockholders of the company at an annual or special
meeting. However, any stockholder that does not vote in favor of granting such voting rights is
entitled to demand that the company pay fair value for their shares if the acquiring person has
acquired at least a majority of all of the voting power of the company. As such, persons acquiring
a controlling interest may not be able to vote their shares.
Item 1B. Unresolved Staff Comments
None.
37
Endeavour International Corporation
Item 2. Properties
Drilling Statistics
A well is considered productive for purposes of the following table if it justifies the
installation of permanent equipment for the production of oil or gas. The information contained in
the table should not be considered indicative of future performance, nor should it be assumed that
there is necessarily any correlation between the number of productive wells drilled, quantities of
reserves found or economic value. The following table shows the results of the oil and gas wells
in which we participated, drilled and tested during 2010, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive Wells |
|
|
Dry Holes |
|
|
In Progress Wells |
|
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
|
Exploration |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United Kingdom |
|
|
3 |
|
|
|
0.38 |
|
|
|
1 |
|
|
|
0.10 |
|
|
|
|
|
|
|
|
|
United States |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
1.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United Kingdom |
|
|
3 |
|
|
|
0.82 |
|
|
|
2 |
|
|
|
0.52 |
|
|
|
1 |
|
|
|
0.10 |
|
United States |
|
|
3 |
|
|
|
1.32 |
|
|
|
1 |
|
|
|
0.22 |
|
|
|
3 |
|
|
|
1.04 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United Kingdom |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
0.68 |
|
United States |
|
|
1 |
|
|
|
0.20 |
|
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
0.10 |
|
Discontinued Operations Norway |
|
|
5 |
|
|
|
0.14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United Kingdom |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
0.05 |
|
United States |
|
|
13 |
|
|
|
3.00 |
|
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
1.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United Kingdom |
|
|
2 |
|
|
|
0.05 |
|
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
0.02 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United Kingdom |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
0.02 |
|
Discontinued Operations Norway |
|
|
3 |
|
|
|
0.08 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We do not own any drilling rigs, and all of our drilling activities are conducted by
independent drilling contractors.
38
Endeavour International Corporation
Productive Well Summary
At December 31, 2010, our productive wells included the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
Gas |
|
|
Gross |
|
Net |
|
Gross |
|
Net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United Kingdom |
|
|
44 |
|
|
|
4.74 |
|
|
|
5 |
|
|
|
0.35 |
|
United States |
|
|
2 |
|
|
|
1.12 |
|
|
|
42 |
|
|
|
12.15 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
46 |
|
|
|
5.86 |
|
|
|
47 |
|
|
|
12.50 |
|
|
Acreage
The following table sets forth certain information regarding our developed and undeveloped
acreage as of December 31, 2010, in the areas indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed |
|
Undeveloped |
|
|
Gross |
|
Net |
|
Gross |
|
Net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United Kingdom |
|
|
31,790 |
|
|
|
8,108 |
|
|
|
252,052 |
|
|
|
70,047 |
|
United States |
|
|
12,425 |
|
|
|
5,561 |
|
|
|
574,871 |
|
|
|
165,065 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
44,215 |
|
|
|
13,669 |
|
|
|
826,923 |
|
|
|
235,112 |
|
|
As of
December 31, 2010, we had approximately 45,912, 25,123 and 51,423 net acres that are
scheduled to expire by December 31, 2011, 2012 and 2013, respectively, if we take no action to
continue the term of the underlying license through operational or administrative actions. This
includes all of our acreage in Alabama and Montana, where we have 134,420 net acres. We intend to
monitor the results of test wells and continue to evaluate our current drilling before determining
further appraisal or development plans in these two states. For our other acreage in the U.S. and
U.K., we currently have plans to continue the terms of various licenses through operational or
administrative actions and do not expect a significant portion of our net acreage position to
expire before such actions occur.
Sales Volumes and Prices
Information regarding our annual average sales volumes, sales prices and average production
costs is contained in Item 7 of this Annual Report Form 10-K. Additional detail of production
costs is contained in Note 24 to our consolidated financial statements under Item 8 of this
Annual Report on Form 10-K.
39
Endeavour International Corporation
Reserves
Our estimates of proved reserves, proved developed reserves and proved undeveloped reserves at
December 31, 2010, 2009 and 2008 and changes in proved reserves during the last three years are
contained in Note 24 to our consolidated financial statements under Item 8 of this Form 10-K.
Item 3. Legal Proceedings
We are a party to various lawsuits, claims, and proceedings from time to time in the ordinary
course of business. These proceedings are subject to uncertainties inherent in any litigation, and
the outcome of these matters is inherently difficult to predict with any certainty. We believe
that the amount of any potential loss associated with these proceedings would not be material to
our consolidated financial position; however, in the event of an unfavorable outcome, the potential
loss could have an adverse effect on our results of operations and cash flow in the reporting
periods in which any such actions are resolved.
Part II
Item 5. Market for Registrants Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities
Our common stock currently trades on the NYSE-Amex, formerly the American Stock Exchange,
under the symbol END and on the London Stock Exchange under the symbol ENDV.
Reverse Stock Split
In October 2010, our Board of Directors authorized a share consolidation of our common stock,
in the form of a one-for-seven reverse stock split. This consolidation was effective at the
opening of trading on November 18, 2010. As a result of the share consolidation, every seven
shares of our common stock outstanding were automatically combined into one share of our common
stock. Each shareholder continues to hold the same percentage of our outstanding common shares.
The shares were rounded up to the next whole share for those holders who would have otherwise
received fractional shares. The share consolidation was intended to make
our common stock available to a broader range of investors and reposition the companys
trading metrics.
All share information and prices per share discussed in this Annual Report have been restated to
reflect the share consolidation.
40
Endeavour International Corporation
Historical Stock Prices
The following table sets forth the range of high and low prices per share of our common stock
for each of the calendar quarters identified below as reported by the NYSE-Amex. These quotations
represent inter-dealer prices, without retail mark-up, markdown or commission, and may not
represent actual transactions.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
2009 |
|
|
High |
|
Low |
|
High |
|
Low |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter |
|
$ |
10.36 |
|
|
$ |
5.60 |
|
|
$ |
7.21 |
|
|
$ |
3.22 |
|
Second Quarter |
|
|
12.18 |
|
|
|
8.68 |
|
|
|
15.47 |
|
|
|
5.81 |
|
Third Quarter |
|
|
10.22 |
|
|
|
6.72 |
|
|
|
10.50 |
|
|
|
7.14 |
|
Fourth Quarter |
|
|
14.16 |
|
|
|
8.12 |
|
|
|
9.10 |
|
|
|
5.74 |
|
Holders
As of February 28, 2011, the number of holders of record of our common stock was 199. We
believe that there are a number of additional beneficial owners of our common stock who hold such
shares in street name.
Dividends
We have not paid any cash dividends on our common stock to date and have no intention of
declaring or paying any cash dividends on our common stock in the foreseeable future. The
declaration and payment of dividends is subject to the discretion of our Board of Directors and to
certain limitations imposed under Nevada corporate laws and the agreements governing our debt
obligations. The timing, amount and form of dividends, if any, will depend on, among other things,
our results of operations, financial condition, cash requirements and other factors deemed relevant
by our Board of Directors.
Our Series B Preferred Stock is subject to a cumulative 8% dividend. Unless the full amount of the
foregoing dividends accrued for the Series B Preferred Stock is paid in full, we cannot declare or
pay any dividend on our common stock. In addition, certain of our debt facilities contain
restrictions on the payment of dividends to the holders of our common stock.
In 2006, we issued the Series C Preferred Stock. Dividends on the Series C Preferred Stock
are:
|
|
|
cumulative; |
|
|
|
|
compounded quarterly based on the original issue price; |
|
|
|
|
payable in cash or common stock, at 4.5% or 4.92%, respectively, since November 2009
and at 8.5% or 8.92%, respectively, in prior periods; and |
|
|
|
|
payable to the preferred stock investors prior to payment of any other dividend on any
other shares of our capital stock. |
41
Endeavour International Corporation
The Series C Preferred Stock will participate in any dividends paid on our common stock. Since
2007, we have paid the Series C Preferred Stock dividends in cash.
Item 6. Selected Financial Data
The following table sets forth some of our historical consolidated financial data for each of
the five years ended December 31, 2010. Significant property acquisitions and dispositions during
these periods have materially affected the comparability of our year-to-year financial data. We
completed the divestiture of our Norwegian subsidiary on May 14, 2009. The results of operations
and financial position of this subsidiary are classified as discontinued operations for all periods
presented.
The following data should be read in conjunction with Item 7. Managements Discussion and Analysis
of Financial Condition and Results of Operations and the Consolidated Financial Statements and
Notes thereto included in Item 8. Financial Statements and Supplementary Data. The selected
consolidated financial data provided below are not necessarily indicative of our future results of
operations or financial performance.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Summary Financial Data (1) |
|
|
Year Ended December 31, |
(Amounts in thousands, except per share data) |
|
2010 |
|
2009 |
|
2008 |
|
2007 |
|
2006 |
|
Summary Income Statement Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
71,675 |
|
|
$ |
62,293 |
|
|
$ |
170,781 |
|
|
$ |
135,876 |
|
|
$ |
24,881 |
|
Operating Profit (Loss) |
|
|
1,327 |
|
|
|
(50,398 |
) |
|
|
18,236 |
|
|
|
23,778 |
|
|
|
(11,516 |
) |
Net Income (Loss) to
Common Shareholders |
|
|
54,304 |
|
|
|
(62,206 |
) |
|
|
45,681 |
|
|
|
(60,315 |
) |
|
|
(8,829 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) Per |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Share Basic: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing Operations |
|
$ |
2.34 |
|
|
$ |
(5.84 |
) |
|
$ |
0.82 |
|
|
$ |
(3.50 |
) |
|
$ |
(0.56 |
) |
Discontinued Operations |
|
|
|
|
|
|
2.50 |
|
|
|
1.67 |
|
|
|
0.07 |
|
|
|
(0.14 |
) |
|
Total |
|
$ |
2.34 |
|
|
$ |
(3.34 |
) |
|
$ |
2.49 |
|
|
$ |
(3.43 |
) |
|
$ |
(0.70 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) Per Common Share Diluted: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing Operations |
|
$ |
1.95 |
|
|
$ |
(4.70 |
) |
|
$ |
0.59 |
|
|
$ |
(3.50 |
) |
|
$ |
(0.56 |
) |
Discontinued Operations |
|
|
|
|
|
|
2.50 |
|
|
|
1.20 |
|
|
|
0.07 |
|
|
|
(0.14 |
) |
|
Total |
|
$ |
1.95 |
|
|
$ |
(2.20 |
) |
|
$ |
1.79 |
|
|
$ |
(3.43 |
) |
|
$ |
(0.70 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Summary Balance Sheet Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Working Capital |
|
$ |
71,145 |
|
|
$ |
24,885 |
|
|
$ |
22,902 |
|
|
$ |
37,198 |
|
|
$ |
47,431 |
|
Total Assets |
|
|
750,287 |
|
|
|
538,879 |
|
|
|
737,470 |
|
|
|
747,623 |
|
|
|
774,470 |
|
Debt |
|
|
345,306 |
|
|
|
223,385 |
|
|
|
227,855 |
|
|
|
266,250 |
|
|
|
306,250 |
|
Convertible Preferred Stock |
|
|
53,152 |
|
|
|
59,058 |
|
|
|
125,000 |
|
|
|
125,000 |
|
|
|
125,000 |
|
Equity |
|
|
154,618 |
|
|
|
60,133 |
|
|
|
117,971 |
|
|
|
70,149 |
|
|
|
116,828 |
|
42
Endeavour International Corporation
|
|
|
(1) |
|
Includes the following: |
|
|
|
acquisition of producing properties and exploration acreage in the U.S. in 2009 and
2010; |
|
|
|
disposition of our interests in the Cygnus reserves in 2010 for a gain of $87.2
million; |
|
|
|
acquisition of Talisman Expro Limited in November 2006; |
|
|
|
acquisition of working interests in the Enoch and Bacchus prospects in 2006; and |
|
|
|
unrealized gains (losses) on derivatives of $12.3 million, $(55.6) million, $76.7
million, $(89.1) million and $34.5 million in 2010, 2009, 2008, 2007 and 2006,
respectively. |
Information regarding each of these transactions is included in the notes to the Consolidated
Financial Statements included elsewhere in this report.
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 Annual Report on Form 10-K contain forward-looking statements that involve
risks and uncertainties. All forward-looking statements included in this Annual Report on Form
10-K are based on information available to us on the date hereof, and we assume no obligation to
update any such forward-looking statements. Our actual results could differ materially from those
anticipated in these forward-looking statements as a result of a number of factors, including those
set forth in the section captioned Risk Factors in Item 1A and elsewhere in this Annual Report on
Form 10-K. The following should be read in conjunction with the audited financial statements and
the notes thereto included in Item 8. Financial Statements and Supplementary Data. The
following discussion also includes non-GAAP financial measures, which may not be comparable to
similarly titled measures presented by other companies. Accordingly, we strongly encourage
investors to review our financial statements in their entirety and not rely on any single financial
measure.
Overview
We are an international oil and gas exploration and production company focused on the
acquisition, exploration and development of energy reserves and resources. Historically, we have
focused our operations in the North Sea, but have expanded our focus to target U.S. onshore
resource plays with shorter production-cycle times and compelling risk/return profiles.
Implementing this shift in strategy over the last several years has required measured and specific
steps. From inception in 2004 through the end of 2007, we built a portfolio of production and
development assets in the UK and Norway through acquisition, exploration and development
activities. During 2008, these assets generated sufficient cash flow to repay $32 million of debt
while continuing to support our capital program. We sought to identify opportunities that would
shorten production-cycle times and provide cash flow while still fitting into our balanced,
43
Endeavour International Corporation
disciplined approach. To strike that new balance in our portfolio, the 2008 capital program
included participation in our first two U.S. exploration wells.
In May 2009, we sold our assets and operations in the Norwegian sector of the North Sea for $150
million. We then looked to further balance the capital intensive, long lead-time nature of our
North Sea assets with entry into the onshore U.S. in active hydrocarbon producing areas. We
targeted U.S. onshore petroleum systems that we believe have shorter production-cycle times and
compelling risk/return profiles. Proceeds from the sale of our Norwegian operations enabled us to
complete acquisitions of U.S. onshore interests, providing us with acreage positions and production
in the Haynesville and Marcellus areas. We also purchased additional acreage, providing exposure
to emerging resource plays in Alabama and Montana.
On October 19, 2010 we completed the Cygnus Sale for $110 million. Upon the closing of this
transaction, we recognized a gain of $87.2 million. The cash proceeds were not burdened by any
taxes payable and are primarily being used to accelerate our development projects and fund our
purchase of an additional 20% in the Bacchus field, which we closed this acquisition in February
2011.
Our North Sea activities and assets represented the majority of our activity in 2008. During 2009,
our North Sea assets continued to represent the primary focus of our activities, but we also began
pursuing activity in the U.S. and sold our Norwegian assets and operations. Our major development
projects Bacchus, Columbus, Cygnus and Rochelle continued to move toward development
throughout the year with appraisal wells drilled at Cygnus and Rochelle in early 2009. In the
U.S., we expanded our operations primarily by completing the acquisitions of exploration acreage
and producing properties in 2009. During 2010, we expanded our U.S. production and operations and
sold Cygnus, while advancing our remaining development projects in the U.K.
Our realized price per BOE, before derivatives, increased from $44.44 per BOE in 2009 to $47.72 per
BOE in 2010. Our revenues have increased from $62.3 million for the year ended December 31, 2009
to $71.7 million for 2010 primarily as a result of higher commodity prices before the effect of our
hedging activities, and higher production volumes from our producing assets. Increases in prices
in the first half of 2008, largely as a result of oil prices climbing to record levels in the
summer of 2008 and gas prices in our markets improving, helped our revenue grow to $170.8 million
in 2008, however the subsequent decrease in commodity prices and normal declines in our production
during 2009 let to a substantial reduction in our revenues to $62.3 million for the year. In
addition, we had revenues from our Norwegian assets included in discontinued operations of $17.6
million and $89.7 million for the years ended December 31, 2009 and 2008, respectively. We sold
our Norwegian assets in May 2009.
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 $17.0 million in 2010 versus $55.7 million in 2009
and $133.2 million in 2008. Discretionary Cash Flow was $21.1 million in 2010 compared to $71.4
million in 2009 and $121.1 million in 2008. The decreases in cash flow provided by operations and
Discretionary Cash Flow primarily reflect our declines in realized prices and
44
Endeavour International Corporation
increasing interest
costs, partially offset by lower operating expenses. Adjusted EBITDA
was $124.8 million in 2010, as
compared to $64.6 million in 2009 and $176.6 million in 2008. These fluctuations in Adjusted
EBITDA are also primarily due to the changes in our realized prices, interest expense and operating
costs. In addition, Adjusted EBITDA for 2010 includes the gain on the Cygnus Sale.
For 2010, net income to common stockholders was $54.3 million for 2010, representing $1.95 per
diluted share, including the gain on the Cygnus Sale of $87.2 million. Net loss to common
stockholders was $(62.2) million for 2009, or $(2.20) per diluted share, including a gain on the
sale of our discontinued operations, an impairment of oil and gas properties, significant
unrealized losses on the mark-to-market of commodity derivatives and a non-cash preferred
stock dividend upon the valuation of the redemption and modification of a portion of our
Series C Preferred Stock. Net income to common stockholders for 2008 was $45.7 million, or $1.79
per diluted share, including impairment of oil and gas properties and significant unrealized gains on the
mark-to-market of commodity derivatives.
Net income as adjusted for 2010 would have been $57.4 million without the effect of impairments,
derivative transactions and currency impacts of deferred taxes. Net income as adjusted for 2009
would have been $41.1 million, as compared to net income as adjusted of $16.5 million in 2008.
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 net income as adjusted, Adjusted EBITDA and Discretionary Cash Flow, and a
reconciliation of these non-GAAP measures to the appropriate GAAP measure, please see
Reconciliation of Non-GAAP Accounting Measures.
Results of Operations
Our revenues and sales volumes have fluctuated significantly during the last three years
primarily due to the following:
|
|
|
As a result of substantially increased oil prices and increased sales from our U.S.
operations, partially offset by decreases in natural gas prices, our revenues have
increased from $62.3 million for the period ended December 31, 2009 to $71.7 million as of
December 31, 2010. |
|
|
|
|
U.S. production reflects the results of our purchase of producing assets in October 2009
and ongoing drilling in 2010, primarily in the Haynesville area. |
45
Endeavour International Corporation
|
|
|
In the first quarter of 2009, we suspended production at the IVRRH, Renee and Rubie
fields due to high operating costs. |
|
|
|
|
In the U.K., natural production declines at certain of our fields have not been offset
by infield drilling resulting in production decreases at certain fields, particularly in
2010 and 2009 at our largest producing gas field Goldeneye. |
|
|
|
|
Sale of our discontinued operations in Norway in May 2009. |
The following table shows our annual average sales volumes, sales prices and average
production costs. None of our current producing fields represent more than 15% of our total proved
reserves during 2009 or 2008. At December 31, 2010, the Woodardville field, in the Haynesville
area, represented more than 15% of our proved reserves. Woodardville, which was part of our U.S.
acquisitions in 2009, is a gas field and represented 1,865 MMcf and 204 MMcf of our gas sales in
2010 and 2009, respectively.
At December 31, 2009, the Goldeneye field, in the UK, represented more than 15% of our proved
reserves. The Goldeneye field in the U.K. had gas sales volumes of 2,990 MMcf, 3,670 MMcf and
6,400 MMcf of in 2010, 2009 and 2008, respectively. The Goldeneye field also had oil sales volumes
of 85 Mbbls, 108 Mbbls and 205 Mbbls in 2010, 2009 and 2008, respectively.
Certain of our non-producing North Sea development assets each represent more than 15% of our
proved reserves during the last three years, specifically the East Rochelle field in 2010 and 2009
and the Columbus field in 2009. As these fields do not have any current sales or production, they
have not been separately identified.
46
Endeavour International Corporation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2010 |
|
2009 |
|
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales volume (1) |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate sales (Mbbls): |
|
|
|
|
|
|
|
|
|
|
|
|
United Kingdom |
|
|
545 |
|
|
|
690 |
|
|
|
1,032 |
|
United States |
|
|
6 |
|
|
|
4 |
|
|
|
|
|
|
Continuing operations |
|
|
551 |
|
|
|
694 |
|
|
|
1,032 |
|
Discontinued operations Norway |
|
|
|
|
|
|
310 |
|
|
|
726 |
|
|
Total |
|
|
551 |
|
|
|
1,004 |
|
|
|
1,758 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas sales (MMcf): |
|
|
|
|
|
|
|
|
|
|
|
|
United Kingdom |
|
|
3,071 |
|
|
|
3,743 |
|
|
|
6,532 |
|
United States |
|
|
2,636 |
|
|
|
320 |
|
|
|
|
|
|
Continuing operations |
|
|
5,707 |
|
|
|
4,063 |
|
|
|
6,532 |
|
Discontinued operations Norway |
|
|
|
|
|
|
686 |
|
|
|
2,322 |
|
|
Total |
|
|
5,707 |
|
|
|
4,749 |
|
|
|
8,854 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil equivalent sales (MBOE) |
|
|
|
|
|
|
|
|
|
|
|
|
United Kingdom |
|
|
1,057 |
|
|
|
1,314 |
|
|
|
2,121 |
|
United States |
|
|
445 |
|
|
|
58 |
|
|
|
|
|
|
Continuing operations |
|
|
1,502 |
|
|
|
1,372 |
|
|
|
2,121 |
|
Discontinued operations Norway |
|
|
|
|
|
|
425 |
|
|
|
1,113 |
|
|
Total |
|
|
1,502 |
|
|
|
1,797 |
|
|
|
3,234 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total BOE per day |
|
|
4,115 |
|
|
|
4,923 |
|
|
|
8,835 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Physical production volume (BOE per day) (2): |
|
|
|
|
|
|
|
|
|
|
|
|
United Kingdom |
|
|
2,904 |
|
|
|
3,669 |
|
|
|
5,804 |
|
United States |
|
|
1,221 |
|
|
|
162 |
|
|
|
|
|
|
Continuing operations |
|
|
4,125 |
|
|
|
3,831 |
|
|
|
5,804 |
|
Discontinued operations Norway |
|
|
|
|
|
|
1,156 |
|
|
|
3,033 |
|
|
Total |
|
|
4,125 |
|
|
|
4,987 |
|
|
|
8,837 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized Prices (3) |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and
condensate price ($ per Bbl): |
|
|
|
|
|
|
|
|
|
|
|
|
Before commodity derivatives |
|
$ |
76.39 |
|
|
$ |
52.15 |
|
|
$ |
90.53 |
|
Effect of commodity derivatives |
|
|
(5.61 |
) |
|
|
22.51 |
|
|
|
(14.50 |
) |
|
Realized prices including commodity derivatives |
|
$ |
70.78 |
|
|
$ |
74.66 |
|
|
$ |
76.03 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas price ($ per Mcf): |
|
|
|
|
|
|
|
|
|
|
|
|
Before commodity derivatives |
|
$ |
5.18 |
|
|
$ |
5.77 |
|
|
$ |
11.44 |
|
Effect of commodity derivatives |
|
|
0.27 |
|
|
|
2.69 |
|
|
|
(0.35 |
) |
|
Realized prices including commodity derivatives |
|
$ |
5.45 |
|
|
$ |
8.46 |
|
|
$ |
11.09 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equivalent oil price ($ per BOE): |
|
|
|
|
|
|
|
|
|
|
|
|
Before commodity derivatives |
|
$ |
47.72 |
|
|
$ |
44.44 |
|
|
$ |
80.54 |
|
Effect of commodity derivatives |
|
|
(1.03 |
) |
|
|
19.71 |
|
|
|
(8.84 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized prices including commodity derivatives |
|
$ |
46.69 |
|
|
$ |
64.15 |
|
|
$ |
71.70 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Costs ($ per BOE)(4) |
|
$ |
10.22 |
|
|
$ |
12.97 |
|
|
$ |
14.40 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
47
Endeavour International Corporation
(1) |
|
We record oil revenues on the sales method, i.e. when delivery has occurred. We use
the entitlements method to account for sales of gas production. |
|
(2) |
|
Physical production may differ from sales volumes based on the timing of tanker
liftings for our international sales. |
|
(3) |
|
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. |
|
(4) |
|
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. |
Our revenues and cash flows from operating activities are very sensitive to changes in the prices
we receive for the oil and natural gas we produce. Our production is sold at prevailing market
prices which may be volatile and subject to numerous factors which are outside of our control.
Further, the current tightly balanced supply and demand market allows a small variation in supply
or demand to significantly impact the market prices for these commodities.
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 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. Specifically, we sold
a majority of our gas in 2009 and 2008 into the U.K. market, which is very sensitive to and
impacted by tighter European gas supplies and gas deliveries from Russia. Therefore, the price for
natural gas in the U.K. market is typically higher than the price for natural gas in other
geographic regions and markets, including the U.S.
We utilize various oil and gas derivative instruments to achieve a more predictable cash flow by
reducing our exposure to price fluctuations. 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. The derivative instruments cover a portion of our production through
2012. The significant volatility in commodity prices and the multi-year nature of the derivative
instruments leads to large fluctuations in the fair market value of the derivative instruments at
the end of each year. This non-cash change in the fair market value is recorded in unrealized
gains (losses) on derivatives in the income statement. The realized prices above show the effect
of the cash settlements for our derivative instruments each year. We expect to continue to have
fluctuations in net earnings for the change in the fair market value each period as commodity
prices fluctuate based on all remaining unsettled contracts. See Note 18 to our consolidated
financial statements in this Annual Report on Form 10-K for additional information on these
derivatives.
48
Endeavour International Corporation
Operating Expenses
For 2010, operating expenses decreased to $15.3 million as compared to $17.8 million for 2009.
Operating costs per BOE decreased to $10.22 per BOE for 2010 from $12.97 per BOE for 2009.
Beginning with the fourth quarter of 2009, our U.S. operations began to be an increasing portion of
our total expenses. On average, our U.S. operations have lower operating costs per BOE than our
U.K. operations, thereby lowering our overall operating costs and operating costs per BOE.
For 2009, operating expenses decreased to $17.8 million as compared to $32.3 million for 2008.
Operating costs per BOE decreased to $12.97 per BOE for 2009 from $14.40 per BOE for 2008. In
general, the changes in operating costs from 2008 to 2009 reflect the higher fuel costs in 2008 at
a non-operated facility which gathered production from our IVRRH, Renee and Rubie fields and then
the absence of those costs when we suspended production from those fields in 2009.
DD&A and Impairment of Oil and Gas Properties
Decreased depreciation, depletion and amortization (DD&A) expense from 2009 to 2010 reflects
lower DD&A rates that result from impairments in oil and gas properties in early 2009 and during
2010 and the increasing proportion of U.S. sales volumes to total sales volumes. Our U.S. assets
have a lower DD&A rate due to their lower cost structure. As a consequence, as U.S. sales become a
larger portion of our total sales, the lower DD&A rate related to our U.S. properties drives our
average DD&A rate lower.
In 2010, we recorded $7.7 million in impairment of oil and gas properties in the U.S., pre-tax,
through the application of the full cost ceiling test due to lower U.S. gas prices in the first
quarter. At December 31, 2010, the prices used to determine the estimates of future cash inflows
were $79.37 per Bbl for oil and $6.58 per Mcf for gas.
In 2009, we recorded $43.9 million in impairment of oil and gas properties, pre-tax, through the
application of the full cost ceiling test. At December 31, 2009, the prices used to determine the
estimates of future cash inflows were $60.40 per Bbl for oil and $4.96 per Mcf for gas.
General and Administrative (G&A) Expenses
Our G&A expenses increased from $17.0 million in 2009 to $18.4 million for 2010 as a result of
an increase in employee compensation expense due to expanding U.S. operations and increased
consulting costs and related employee costs, that pertain to our expanding U.S. operations. The
increase in G&A expense from $15.9 million in 2008 to $17.0 million in 2009 was a result of an
increase in employee compensation and consulting fees associated with the additional staff to
pursue our expanding development projects in the U.K. Much of this increase in staff costs was
offset by recoveries from our partner on the development project we operate.
Components of G&A expenses for these periods are as follows:
49
Endeavour International Corporation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
(Amounts in thousands) |
|
2010 |
|
2009 |
|
2008 |
|
Compensation |
|
$ |
18,110 |
|
|
$ |
14,659 |
|
|
$ |
11,203 |
|
Consulting, legal and accounting fees |
|
|
5,843 |
|
|
|
5,118 |
|
|
|
4,679 |
|
Occupancy costs |
|
|
1,158 |
|
|
|
982 |
|
|
|
1,130 |
|
Other expenses |
|
|
2,730 |
|
|
|
1,364 |
|
|
|
4,005 |
|
|
Total gross cash G&A expenses |
|
|
27,841 |
|
|
|
22,123 |
|
|
|
21,017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash stock-based compensation |
|
|
3,692 |
|
|
|
2,612 |
|
|
|
2,928 |
|
|
Gross G&A expenses |
|
|
31,533 |
|
|
|
24,735 |
|
|
|
23,945 |
|
Less: capitalized G&A expenses |
|
|
(13,118 |
) |
|
|
(7,769 |
) |
|
|
(8,013 |
) |
|
Net G&A expenses |
|
$ |
18,415 |
|
|
$ |
16,966 |
|
|
$ |
15,932 |
|
|
Interest Expense and Other
The increase in interest expense from $16.6 million in 2009 to $34.6 million in 2010 reflects
the increases in interest expense that occurred as a result of several changes in our outstanding
debt obligations, beginning in the fourth quarter of 2009 and continuing through 2010.
In the fourth quarter of 2009, we issued $50 million of Subordinated Notes in connection with the
redemption and modification of our Series C Preferred Stock. During the first quarter of 2010, we
borrowed $25 million under the Junior Facility. In August 2010, we borrowed $150 million under the
Senior Term Loan and repaid all outstanding balances under the Senior Bank Facility and the Junior
Facility. In connection with the repayment of the Senior Bank and Junior Facilities, we expensed
the remaining deferred financing costs of $1.2 million related to these instruments. In October
2010 we borrowed an additional $10 million under the Senior Term Loan. At December 31, 2010, we
recorded $28.2 million in interest expense related to our debt and $10.3 million in deferred
financing expense; offset by $3.9 million in capitalized interest.
The decrease in interest expense from $23.0 million in 2008 to $16.6 million in 2009 reflects the
partial repayment of outstanding balances under our Senior Bank Facility with a portion of the
proceeds from the sale of our Norwegian operations and lower interest rates.
Income Taxes
The following summarizes the components of tax expense (benefit):
50
Endeavour International Corporation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
Discontinued |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing |
|
Operations |
|
|
(Amounts in thousands) |
|
U.K. |
|
U.S. |
|
Other |
|
Operations |
|
Norway |
|
Total |
|
Year Ended December 31, 2010: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) before taxes |
|
$ |
90,160 |
|
|
$ |
(30,978 |
) |
|
$ |
(3,439 |
) |
|
$ |
55,743 |
|
|
$ |
|
|
|
$ |
55,743 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current tax (benefit) expense |
|
|
2,734 |
|
|
|
|
|
|
|
(154 |
) |
|
|
2,580 |
|
|
|
|
|
|
|
2,580 |
|
Deferred tax (benefit) expense |
|
|
(2,388 |
) |
|
|
|
|
|
|
(929 |
) |
|
|
(3,317 |
) |
|
|
|
|
|
|
(3,317 |
) |
Foreign currency losses on
deferred tax liabilities |
|
|
|
|
|
|
|
|
|
|
(51 |
) |
|
|
(51 |
) |
|
|
|
|
|
|
(51 |
) |
|
Total tax (benefit) expense |
|
|
346 |
|
|
|
|
|
|
|
(1,134 |
) |
|
|
(788 |
) |
|
|
|
|
|
|
(788 |
) |
|
Net income (loss) after taxes |
|
$ |
89,814 |
|
|
$ |
(30,978 |
) |
|
$ |
(2,305 |
) |
|
$ |
56,531 |
|
|
$ |
|
|
|
$ |
56,531 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2009: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) before taxes |
|
$ |
(52,041 |
) |
|
$ |
(31,167 |
) |
|
$ |
(11,479 |
) |
|
$ |
(94,687 |
) |
|
$ |
51,963 |
|
|
$ |
(42,724 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current tax expense |
|
|
(5,739 |
) |
|
|
40 |
|
|
|
(26 |
) |
|
|
(5,725 |
) |
|
|
(603 |
) |
|
|
(6,328 |
) |
Deferred tax expense |
|
|
(20,260 |
) |
|
|
(20 |
) |
|
|
(35 |
) |
|
|
(20,315 |
) |
|
|
4,791 |
|
|
|
(15,524 |
) |
Foreign currency gains on
deferred tax liabilities |
|
|
18,882 |
|
|
|
|
|
|
|
|
|
|
|
18,882 |
|
|
|
1,241 |
|
|
|
20,123 |
|
|
Total tax expense |
|
|
(7,117 |
) |
|
|
20 |
|
|
|
(61 |
) |
|
|
(7,158 |
) |
|
|
5,429 |
|
|
|
(1,729 |
) |
|
Net income (loss) after taxes |
|
$ |
(44,924 |
) |
|
$ |
(31,187 |
) |
|
$ |
(11,418 |
) |
|
$ |
(87,529 |
) |
|
$ |
46,534 |
|
|
$ |
(40,995 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2008: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) before taxes |
|
$ |
66,129 |
|
|
$ |
(11,969 |
) |
|
$ |
(4,185 |
) |
|
$ |
49,975 |
|
|
$ |
63,244 |
|
|
$ |
113,219 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current tax (benefit) expense |
|
|
11,158 |
|
|
|
|
|
|
|
10 |
|
|
|
11,168 |
|
|
|
27,879 |
|
|
|
39,047 |
|
Deferred tax (benefit) expense |
|
|
22,673 |
|
|
|
|
|
|
|
303 |
|
|
|
22,976 |
|
|
|
15,415 |
|
|
|
38,391 |
|
Foreign currency losses on
deferred tax liabilities |
|
|
(10,028 |
) |
|
|
|
|
|
|
|
|
|
|
(10,028 |
) |
|
|
(10,681 |
) |
|
|
(20,709 |
) |
|
Total tax (benefit) 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 |
|
|
We currently do not record tax benefits due to losses in the U.S. as there was no assurance
that we could generate any U.S. taxable earnings, resulting in a full valuation allowance of all
deferred tax assets generated. Therefore, our income tax expense relates primarily to our
operations in the U.K. and our discontinued operations in Norway. Income tax benefit decreased in
2010 as a result of the decrease in U.K. revenues due primarily to lower sales volumes, partially
offset by the increase in production revenue taxes (PRT) in the U.K. as our allowances for oil
production at PRT eligible fields expired. In addition, the gain on the Cygnus sales was
non-taxable.
Income taxes decreased in 2009 from 2008 to a benefit of $7.2 million reflecting the decrease in
revenues and the weakening of the U.S. dollar versus the U.K. pound. 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 U.K. pound and the shift in anticipated capital
expenditures from late 2008 to early 2009.
51
Endeavour International Corporation
Liquidity and Capital Resources
Capital Expenditures
We spent $106.3 million, $88.6 million and $88.5 million on our oil and gas capital program,
excluding acquisitions, in 2010, 2009 and 2008, respectively. We spent $23.9 million in 2010,
$16.5 million in 2009 and $25.6 million in 2008 on development activities in both the U.S. and UK.
We also spent $82.4 million, $72.1 million and $62.9 million in 2010, 2009 and 2008, respectively,
on exploration and appraisal activities, primarily related to our new operations in the U.S. In
addition, we incurred $43.7 million, $32.2 million and $2.2 million during 2010, 2009 and 2008,
respectively, related to our acquisitions, primarily located in the U.S.
Capital Resources
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
(Amounts in thousands) |
|
2010 |
|
2009 |
|
Cash |
|
$ |
99,267 |
|
|
$ |
27,287 |
|
Restricted Cash |
|
$ |
31,776 |
|
|
$ |
2,879 |
|
Debt, including current maturities |
|
$ |
(345,306 |
) |
|
$ |
(223,385 |
) |
|
|
|
|
|
|
|
|
|
|
Debt, net of Cash |
|
$ |
(214,263 |
) |
|
$ |
(193,219 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2010 |
|
2009 |
|
Net cash provided by operating activities |
|
$ |
17,019 |
|
|
$ |
55,711 |
|
|
Net cash provided by (used in) investing activities |
|
$ |
(56,314 |
) |
|
$ |
31,120 |
|
|
Net cash provided by (used in) financing activities |
|
$ |
111,275 |
|
|
$ |
(97,700 |
) |
|
Our primary sources of financial resources and liquidity are cash on hand, internally
generated cash flows from operations and access to the credit and capital markets, to the extent
available. Significant issuances and repayments of debt and equity, as well as the uses of the net
proceeds, in 2010, 2009, and 2008 were as follows:
|
|
|
completed the Cygnus Sale for $110 million in cash in October 2010; |
|
|
|
|
entered into a $160 million Senior Term Loan during 2010 Loan in August 2010; |
|
|
|
|
repaid and terminated the Senior Bank Facility and the $25 million Junior Facility; |
|
|
|
|
completed a registered direct offering of common stock, in connection with the Senior
Term Loan, to sell 1.3 million shares of our common stock for aggregate cash consideration
of approximately $10.1 million, after expenses; |
|
|
|
|
completed a private placement of our common stock, pursuant to a Common Stock Purchase
Agreement, selling 3.4 million shares for aggregate net cash consideration of approximately
$20.5 million in February 2010; |
52
Endeavour International Corporation
|
|
|
repaid $63.1 million of net debt in 2009; |
|
|
|
|
redeemed $75 million of the Series C Convertible Preferred Stock in the fourth quarter
of 2009 with $25 million in cash and $50 million subordinated notes; |
|
|
|
|
repaid the $75 million second lien term loan in the first quarter of 2008; and |
|
|
|
|
issued $40 million of 11.5% Convertible Bonds in the first quarter of 2008. |
Cash flow from operations decreased to $17.0 million for 2010 from $55.7 million for 2009 primarily
due to a $10.2 million loss related to the early termination of commodity derivatives, lower gas
prices in the U.S., lower realizations from our commodity derivatives as higher priced oil collars
expired at the end of 2009 and increased interest expense following our issuance of the Senior Term
Loan in third quarter of 2010 and our issuance of the Subordinated Notes in fourth quarter of 2009.
Cash flow from operations decreased to $55.7 million for 2009 from $133.2 million for 2008
primarily due to lower realized commodity prices and lower sales volumes, particularly the
reduction in gas sales as a result of production declines at Goldeneye.
In 2010, we utilized our cash flow from operations, equity issuances and debt issuances to fund our
capital needs and repay a portion of outstanding debt. The proceeds from the Cygnus Sale in the
fourth quarter of 2010 are intended to partially fund our capital needs in 2011. During 2009, we
principally relied on cash flow from operations and proceeds from our sale of Norwegian assets to
fund our capital needs and repay a portion of outstanding debt and preferred stock.
In August 2010, we entered into the Senior Term Loan in the aggregate amount of $150 million, which
was subsequently increased to $160 million. We used $66 million of the proceeds from this loan to
repay in full the outstanding borrowings under the Senior Bank Facility and the Junior Facility.
Following these repayments, both the Senior Bank Facility and the Junior Facility terminated in
accordance with their terms.
In February 2010, we issued 3.4 shares of common stock in a private placement for aggregate net
proceeds of $20.5 million. We also entered into a $25 million Junior Lending Facility, which had a
maturity date of February 5, 2011, and interest at LIBOR plus 8%. The net proceeds from the
private placement and the borrowing under the Junior Facility were used to partially fund our 2010
capital budget. We terminated the Junior Facility and repaid the outstanding indebtedness in its
entirety on August 16, 2010, in connection with our entry into the Senior Term Loan, discussed
above.
In connection with the repayment of the Senior Bank Facility in August 2010, we also terminated all
of our outstanding commodity derivative positions for a realized loss of $10.2 million. Under the
Senior Term Loan, we are required to re-establish our commodity derivatives to manage our cash
flows from operations. In November 2010, we executed six natural gas and ten oil option contracts
with three major counterparties. For additional information regarding our derivative contracts,
see Note 18 to our consolidated financial statements in this Annual Report.
On November 17, 2009, we redeemed 60% of the outstanding shares of Series C Preferred Stock, for
face value of $75 million, and amended the terms of the remaining shares of Series C Preferred
Stock. The redemption price consisted of a $25 million cash payment and the issuance of $50
million Subordinated Notes.
53
Endeavour International Corporation
The redemption and modification of the Series C Preferred Stock required the modified Series C
Preferred Stock to be recorded at fair market value at the redemption date. As there was not a
market observable price for the Series C Preferred Stock, we utilized a valuation approach to
estimate the price that would be paid to transfer the Series C Preferred Stock in an orderly
transaction between market participants. The fair value of the modified Series C Preferred Stock
was greater than the carrying value by $11.5 million. This excess of fair value over carrying
value was recorded as a non-cash charge to preferred stock dividends and increased the carrying
value of the Series C Preferred Stock. As holders convert the Series C Preferred Stock, the $11.5
million non-cash charge will be transferred to equity on a ratio of shares converted to shares of
Series C Preferred Stock outstanding.
In the redemption and modification of the Series C Preferred Stock, we also reduced the annual
dividend rate to 4.5% (from 8.5%), adjust the conversion price to $8.75 per share (from $17.50) and
remove certain anti-dilution provisions.
See Note 9 and Note 12 to the Consolidated Financial Statements herein for additional discussion of
our recent issuance of debt and equity. As more fully described in Note 9 to our audited
consolidated financial statements herein, our outstanding bank facilities contain certain financial
ratio covenants. We were in compliance with all financial and restrictive covenants of our debt
obligations as of December 31, 2010 and 2009.
Operating, Investing and Financing Activities include the net cash flows from our discontinued
operations which were sold in May 2009. For the years ended December 31, 2009 and 2008, our
discontinued operations had net cash flows provided by (used in) operating activities of
approximately $9.0 million and $38.8 million, respectively. These net cash flows were
substantially offset by net cash used by investing activities of approximately $9.0 million and
$34.7 million during 2009 and 2008, respectively.
Outlook
2011 Planned Capital Expenditures
We anticipate spending approximately $150 million during 2011 to fund our oil and gas activities in
the U.S. and U.K., with approximately 60% of those expenditures anticipated to be focused on our
U.K. assets. In the U.K., our activity during 2011 will be primarily concentrated on the Bacchus
and Greater Rochelle development projects. At the Bacchus project, we plan to drill three
production wells and install the infrastructure to allow first production in the second half of
2011. At the Greater Rochelle project, our focus will be completing engineering and procuring long
lead-time equipment to prepare Greater Rochelle for a 2012 first production date from the East
Rochelle area. We also intend to begin actual construction of the subsea
infrastructure and modifications to the Scott platform to prepare it for production from the
Greater Rochelle area. Additionally, we expect to continue to further our development program at
our Columbus project, including ongoing engineering assessments for future production and
commercial off-take solutions.
Our primary focus during 2011 in the U.S. will be in the Haynesville and Marcellus areas as we
believe this acreage contains near-term production potential. The ongoing U.S. program and
expenditures will be tailored based on early drilling results and U.S. gas prices in 2011. During
2011, we expect to further evaluate our two existing frontier plays in Alabama and Montana through
the drilling of additional test wells.
We intend to fund our capital expenditures through cash on hand and cash flow generated from
operations. The majority of our cash on hand was acquired through our capital raising activities
in 2010, including our Senior Term Loan and the sale of our
Cygnus asset. The timing, completion and progress of our 2011 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 technical work.
Based on these and other factors, we may increase or decrease our planned capital program or
prioritize certain projects over others.
54
Endeavour International Corporation
2011 Liquidity and Capital Resources
Our primary sources of financial resources and liquidity are cash on hand, internally
generated cash flows from operations and access to the credit and capital markets, to the extent
available. We strive to synchronize our capital expenditures with our cash flow and cash on hand.
We believe the combination of our available cash on hand and cash flow from operations will fund
our capital expenditure program for 2011. In turn, our capital program should allow additional
cash flows to be generated as Bacchus and additional U.S. wells begin production.
Our cash flows will be significantly impacted by the amount of oil and gas we produce and the price
we obtain for our produced commodities. While we expect our 2011 production to increase over our
2010 production, that increase will not occur evenly throughout the year. Instead, the anticipated
production increase will be deferred to the latter half of the year. We expect our production in
2011 will be significantly similar to the fourth quarter of 2010 until Bacchus reaches production
and our U.S. drilling program begins produce from new wells. Each of these operational activities
will have an impact on our 2011 production as follows:
|
|
|
Initial production date of the Bacchus field We expect first production of the
Bacchus field to commence in mid 2011. The
precise initial production date and how long it may take for Bacchus to reach full
production are key variables to our overall 2011 production. |
|
|
|
|
U.S. drilling program results We are continuing our drilling operations in the U.S.
and expect to have additional production as new successful wells are completed. Currently,
we have seven wells in the US that are either being completed or awaiting completion. |
|
|
|
|
Flow testing at the Goldeneye field In early December 2010, the Goldeneye field was
shut-in due to flow assurance issues resulting from increased water production. As
discussed earlier, the Goldeneye field is a mature gas field, nearing the end of its
production life. In February 2011, production was re-started to commence flow trials
which, when concluded, should help us determine how much more production may be expected
from the Goldeneye field. |
Our future revenues and cash flows from operating activities will continue to be 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.
55
Endeavour International Corporation
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. U.S. gas prices have been impacted by increases in gas production from shale and other
resources play drilling activities, thereby depressing U.S. gas prices in 2010.
Oil prices continue to be impacted by supply and demand on a worldwide basis. Although oil and gas
prices have remained volatile, 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, 2010,
our outstanding commodity derivates covered 50% of our estimated 2011 production from our proved
developed reserves.
2011 and 2012 Debt Maturities
Our 6% Convertible Notes mature in January 2012 and have an outstanding balance of $81.3
million as of December 31, 2010. In addition, our 11.5% Convertible Bonds have a conditional
redemption right in 2012 and have an outstanding balance of $55.8 million as of December 31, 2010.
Under the Senior Term Loan, the 6% Convertible Notes must be refinanced, extinguished or extended
and the holders conditional redemption right on Endeavours 11.5% Convertible Bonds due 2014 must
be terminated or extended prior to October 14, 2011. If these conditions are not met, the $160
million Senior Term Loan is payable in full on October 14, 2011. We are currently in discussions
with several parties concerning this process and expect to extend, refinance or terminate the 6%
Convertible Notes and the holders conditional redemption right on Endeavours 11.5% Convertible
Bonds by mid-2011. However, there can be no assurance that efforts to refinance, terminate or
extend will be successful, and covenants in our senior Term Loan place restrictions on our ability
to use cash on hand to repay other debt, including the 6% Convertible Notes.
Non-GAAP Measures
Net income can be significantly affected by various non-cash items, such as unrealized gains
and losses on our commodity derivatives, currency impact of long-term liabilities and deferred
taxes. Given the significant impact that non-cash items may have on our net income, we use various
measures in addition to net income and net cash provided by operating activities, including
non-financial performance indicators and non-GAAP measures as key metrics to manage our business.
These metrics demonstrate our ability to maintain or grow production levels and reserves,
internally fund capital expenditures and service debt as well as provide comparisons to other oil
and gas exploration and production companies. Net Income (Loss) as Adjusted,
earnings before interest, taxes, depreciation, depletion and amortization adjusted for the early termination of commodity derivatives and income (loss) from discontinued operations (Adjusted
EBITDA) and Discretionary Cash Flow are internal, supplemental measures of our performance that
are not required by, or presented in accordance with GAAP. The calculations of these non-GAAP
measures and the reconciliation of net income (loss) to these non-GAAP measures are provided below.
56
Endeavour International Corporation
We view these non-GAAP measures, and we believe that others in the oil and gas industry, securities
analysts, investors, and other interested parties view these, or similar, non-GAAP measures, as
commonly used analytic indicators to compare performance among companies in our industry and in the
evaluation of issuers.
Because Net Income (Loss) as Adjusted, Adjusted EBITDA and Discretionary Cash Flow are not measures
determined in accordance with GAAP and thus are susceptible to varying calculations, our non-GAAP
measures as presented may not be comparable to similarly titled measures of other companies. Net
Income (Loss) as Adjusted, Adjusted EBITDA and Discretionary Cash Flow have limitations as
analytical tools, 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.
57
Endeavour International Corporation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
(Amounts in thousands) |
|
2010 |
|
2009 |
|
2008 |
|
Net income (loss) |
|
$ |
56,531 |
|
|
$ |
(40,995 |
) |
|
$ |
56,490 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
28,894 |
|
|
|
38,701 |
|
|
|
81,734 |
|
Impairment of oil and gas properties |
|
|
7,692 |
|
|
|
43,929 |
|
|
|
36,970 |
|
Deferred tax expense (benefit) |
|
|
(3,367 |
) |
|
|
4,599 |
|
|
|
17,682 |
|
Gain on sales |
|
|
(87,171 |
) |
|
|
(47,308 |
) |
|
|
(258 |
) |
Unrealized (gain) loss on derivatives |
|
|
(12,291 |
) |
|
|
55,598 |
|
|
|
(76,666 |
) |
Early termination of commodity derivatives |
|
|
10,201 |
|
|
|
|
|
|
|
|
|
Other |
|
|
20,632 |
|
|
|
16,835 |
|
|
|
5,114 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discretionary Cash Flow (1) |
|
$ |
21,121 |
|
|
$ |
71,359 |
|
|
$ |
121,066 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
56,531 |
|
|
$ |
(40,995 |
) |
|
$ |
56,490 |
|
Impairment of oil and gas properties (net of
tax) (2) |
|
|
7,692 |
|
|
|
28,263 |
|
|
|
18,485 |
|
Unrealized (gain) loss on derivatives (net of
tax) (3) |
|
|
(6,820 |
) |
|
|
33,702 |
|
|
|
(37,743 |
) |
Currency impact on deferred taxes |
|
|
(51 |
) |
|
|
20,123 |
|
|
|
(20,709 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income as Adjusted |
|
$ |
57,352 |
|
|
$ |
41,093 |
|
|
$ |
16,523 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
56,531 |
|
|
$ |
(40,995 |
) |
|
$ |
56,490 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized (gain) loss on derivatives |
|
|
(12,291 |
) |
|
|
55,598 |
|
|
|
(76,666 |
) |
Net interest expense |
|
|
34,517 |
|
|
|
16,420 |
|
|
|
21,301 |
|
Depreciation, depletion and amortization |
|
|
28,894 |
|
|
|
38,701 |
|
|
|
81,734 |
|
Impairment of oil and gas properties |
|
|
7,692 |
|
|
|
43,929 |
|
|
|
36,970 |
|
Income tax expense (benefit) |
|
|
(788 |
) |
|
|
(1,729 |
) |
|
|
56,729 |
|
Early termination of commodity derivatives |
|
|
10,201 |
|
|
|
|
|
|
|
|
|
Gain on sale of discontinued operations |
|
|
|
|
|
|
(47,308 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA |
|
$ |
124,756 |
|
|
$ |
64,616 |
|
|
$ |
176,558 |
|
|
|
|
|
(1) |
|
Discretionary Cash Flow is equal to cash flow from operating activities
before the changes in operating assets and liabilities, excluding the early termination of
commodity derivatives. |
|
(2) |
|
Net of tax benefits of none, $(15,666) and $(18,485) in 2010,
2009 and 2008, respectively. |
|
(3) |
|
Net of tax expense (benefit) of $5,471, $(21,896) and $38,923 in 2010,
2009 and 2008, respectively. |
58
Endeavour International Corporation
Disclosures about Contractual Obligations and Commercial Commitments
The following table sets forth our obligations and commitments to make future payments under
our lease agreements and other long-term obligations as of December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments due by Period |
|
|
|
|
|
|
Less |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
than 1 |
|
1-3 |
|
|
|
|
|
After 5 |
(Amounts in thousands) |
|
Total |
|
Year |
|
Years |
|
3-5 Years |
|
Years |
|
Long-term debt |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Principal |
|
$ |
349,575 |
|
|
$ |
21,600 |
|
|
$ |
261,021 |
|
|
$ |
66,954 |
|
|
$ |
|
|
Interest (1) |
|
|
106,598 |
|
|
|
34,817 |
|
|
|
47,531 |
|
|
|
24,250 |
|
|
|
|
|
Asset retirement obligations |
|
|
42,996 |
|
|
|
5,987 |
|
|
|
18,428 |
|
|
|
1,467 |
|
|
|
17,114 |
|
Operating leases for office
leases and equipment |
|
|
1,085 |
|
|
|
767 |
|
|
|
318 |
|
|
|
|
|
|
|
|
|
|
|
Total Contractual Obligations |
|
$ |
500,254 |
|
|
$ |
63,171 |
|
|
$ |
327,298 |
|
|
$ |
92,671 |
|
|
$ |
17,114 |
|
|
Off-Balance Sheet Arrangements
At December 31, 2010, we did not have any off-balance sheet arrangements.
Rig Commitments
We have previously disclosed a potential commitment on a drilling rig in our North Sea
operations. We are in dispute with the rig operator in relation to this potential commitment and
have also raised potential counterclaims. We will defend our position vigorously, but there can be
no certainty that we will resolve this matter favorably.
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.
59
Endeavour International Corporation
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 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 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; such as the estimated costs of dismantling and abandoning these assets, dry hole costs,
lease acquisition costs, seismic and other geological and geophysical costs, delay rentals, costs
related to such activities, certain directly-related employee costs and a portion of interest
expense. 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). 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. The ceiling test limitation is
calculated as the present value, discounted 10%, of:
|
|
|
the future net cash flows related to estimated production of proved reserves; |
|
|
|
|
the effect of derivative instruments that qualify as cash flow hedges; |
|
|
|
|
the lower of cost or estimated fair value of unproved properties; and |
|
|
|
|
the expected income tax effects of the above items. |
Future net cash flows use the average, first-day-of-the-month price for commodities during 2010 and
2009 and the year-end price for 2008.
We utilize a single cost center for each country where we have operations for amortization
purposes. Any sales or other 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 initially 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.
60
Endeavour International Corporation
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 and 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 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
Assets and liabilities acquired through a business combination are recorded at 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.
Any excess of the acquisition cost of the acquired business over the fair value amounts assigned to
assets and liabilities is recorded as goodwill. Any excess of the amounts assigned to assets and
liabilities over the acquisition of the acquired business is recorded as a gain on acquisition on
the income statement. The amount of goodwill recorded in any particular business combination can
vary significantly depending upon the fair values attributed to assets acquired and liabilities
assumed relative to the total acquisition cost.
61
Endeavour International Corporation
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, 2010, we had $211.9 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 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 2010 annual goodwill impairment test with no impairment indicated as the estimated
fair value of our reporting unit was substantially greater than its book value. We considered our
market capitalization based on average stock prices for 20 days before December 31, 2010.
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.
62
Endeavour International Corporation
Estimating future asset retirement obligations requires us to make estimates and judgments
regarding timing, amount and existence of a liability, as well as what constitutes adequate
restoration. We use the present value of estimated cash flows related to our asset retirement
obligations to determine fair value. Our liability is determined using significant assumptions,
including current estimates of plugging and abandonment costs, inflation factors, the productive
lives of wells and our risk-adjusted interest rate. In addition, there are other external factors
which could significantly affect the ultimate settlement costs for these obligations including
changes in environmental regulations and other statutory requirements, fluctuations in industry
costs and advances in technology.
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 collectability of the
revenue is probable.
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 embedded derivatives related to our debt
instruments and convertible preferred stock.
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.
63
Endeavour International Corporation
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.
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, 2010, we had approximately 1.4 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, the initial measurement of an
asset retirement obligation and the initial measurement of our Series C Preferred Stock upon its
redemption and modification. 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
64
Endeavour International Corporation
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.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Foreign Exchange Risk
The international scope of our business operations exposes us to the risk of fluctuations in
foreign currency markets. As a result, we are subject to foreign currency exchange rate risk due
to effects that foreign exchange rate movements have on our costs and on the cash flows that we
receive from foreign operations. Our oil revenues are received in U.S. dollars while gas revenues
in the U.K. are received in pounds sterling. Capital expenditures, payroll and operating expenses
may be denominated in U.S. dollars or pounds sterling. We operate a centralized currency
management operation to take advantage of potential opportunities to naturally offset exposures
against each other. To date, we have addressed our foreign currency exchange rate risks
principally by maintaining our liquid assets in interest-bearing accounts, until payments in
foreign currency are required. We have not reduced this risk by hedging to date as the timing
expenditures in pounds sterling has been predictable and we have been able to match revenues
received in pounds sterling and foreign currency purchases to minimize our exposure to foreign
currency exchange rate risk.
65
Endeavour International Corporation
Commodity Price Risk
We produce and sell crude oil and natural gas. Realized pricing is primarily driven by the
prevailing worldwide price for crude oil and regional gas spot market prices which have been
volatile and unpredictable for several years. As a result, our financial results can be
significantly impacted as these commodity prices fluctuate widely in response to changing market
forces. We may engage in oil and gas hedging activities to realize commodity prices which we
consider favorable.
At December 31, 2010, we had the following commodity derivative instruments outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2011 |
|
2012 |
|
Total |
|
Oil: |
|
|
|
|
|
|
|
|
|
|
|
|
Fixed Price Puts (Mbbl) |
|
|
144 |
|
|
|
40 |
|
|
|
184 |
|
Weighted Average Price ($/Barrel) |
|
$ |
90.18 |
|
|
$ |
91.85 |
|
|
|
90.55 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas: (1) |
|
|
|
|
|
|
|
|
|
|
|
|
Fixed Price Puts (MMcf) |
|
|
118 |
|
|
|
55 |
|
|
|
173 |
|
Weighted Average Price ($/Mcf) |
|
$ |
7.48 |
|
|
$ |
8.20 |
|
|
|
7.71 |
|
|
|
|
(1) |
|
Gas derivative contracts are designated in therms and have been converted to
Mcf at a rate of 10 therm to 1 Mcf. The exchange rate at December 31, 2010 was $1.54 to
£1.00. |
The fair value of our commodity derivatives was $2.0 million at December 31, 2010.
Interest Rate Risk
Our exposure to changes in interest rates is not significant as all of our borrowings are
subject to fixed interest rates. Changes in interest rates only affect the interest earned on cash
and cash equivalents.
66
Endeavour International Corporation
Item 8. Financial Statements and Supplementary Data
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Endeavour International Corporation:
We have audited the accompanying consolidated balance sheets of Endeavour International Corporation
and subsidiaries as of December 31, 2010 and 2009, and the related consolidated statements of
operations, stockholders equity and comprehensive income, and cash flows for each of the years in
the three-year period ended December 31, 2010. These consolidated financial statements are the
responsibility of the Companys management. Our responsibility is to express an opinion on these
consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all
material respects, the financial position of Endeavour International Corporation and subsidiaries
as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each
of the years in the three-year period ended December 31, 2010, in conformity with U.S. generally
accepted accounting principles.
As discussed in note 2 to the consolidated financial statements, effective December 31, 2009, the
Company has changed it reserve estimates and related disclosures as a result of adopting new oil
and gas reserve estimation and disclosure requirements.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), Endeavour International Corporations internal control over financial
reporting as of December 31, 2010, based on criteria established in Internal Control Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO),
and our report dated March 10, 2011, expressed an unqualified opinion on the effectiveness of the
Companys internal control over financial reporting.
/S/ KPMG LLP
Houston, Texas
March 10, 2011
67
Endeavour International Corporation
Consolidated Balance Sheets
(Amounts in thousands)
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
|
|
|
|
|
|
|
|
|
Assets
|
Current Assets: |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
99,267 |
|
|
$ |
27,287 |
|
Restricted cash |
|
|
31,776 |
|
|
|
2,879 |
|
Accounts receivable |
|
|
8,068 |
|
|
|
14,800 |
|
Prepaid expenses and other current assets |
|
|
8,718 |
|
|
|
10,118 |
|
|
Total Current Assets |
|
|
147,829 |
|
|
|
55,084 |
|
|
|
|
|
|
|
|
|
|
Property and Equipment, Net ($161,430 and $154,553 not subject
to amortization at 2010 and 2009, respectively) |
|
|
364,677 |
|
|
|
266,587 |
|
Goodwill |
|
|
211,886 |
|
|
|
211,886 |
|
Other Assets |
|
|
25,895 |
|
|
|
5,322 |
|
|
|
|
|
|
|
|
|
|
|
Total Assets |
|
$ |
750,287 |
|
|
$ |
538,879 |
|
|
See accompanying notes to condensed consolidated financial statements.
68
Endeavour International Corporation
Consolidated Balance Sheets
(Amounts in thousands)
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2010 |
|
2009 |
|
|
|
|
|
|
|
|
|
|
Liabilities and Stockholders Equity
|
Current Liabilities: |
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
32,442 |
|
|
$ |
12,401 |
|
Current maturities of debt |
|
|
21,600 |
|
|
|
|
|
Accrued expenses and other |
|
|
22,642 |
|
|
|
17,798 |
|
|
Total Current Liabilities |
|
|
76,684 |
|
|
|
30,199 |
|
|
|
|
|
|
|
|
|
|
Long-Term Debt |
|
|
323,706 |
|
|
|
223,385 |
|
Deferred Taxes |
|
|
77,200 |
|
|
|
80,692 |
|
Other Liabilities |
|
|
64,927 |
|
|
|
85,412 |
|
|
Total Liabilities |
|
|
542,517 |
|
|
|
419,688 |
|
|
|
|
|
|
|
|
|
|
Commitments and Contingencies |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Series C Convertible Preferred Stock: |
|
|
|
|
|
|
|
|
Face value (liquidation preference) |
|
|
45,000 |
|
|
|
50,000 |
|
Net non-cash premiums under fair value accounting on redemption |
|
|
8,152 |
|
|
|
9,058 |
|
|
Total Series C Convertible Preferred Stock |
|
|
53,152 |
|
|
|
59,058 |
|
|
|
|
|
|
|
|
|
|
Stockholders Equity: |
|
|
|
|
|
|
|
|
Series B preferred stock (Liquidation preference: $3,273
and $3,115 at 2010 and 2009, respectively) |
|
|
|
|
|
|
|
|
Common stock; shares issued and outstanding (24,784 and
18,803 shares at 2010 and 2009, respectively) |
|
|
25 |
|
|
|
19 |
|
Additional paid-in capital |
|
|
287,995 |
|
|
|
247,820 |
|
Treasury stock, at cost (72 and 72 shares at 2010
and 2009, respectively) |
|
|
(587 |
) |
|
|
(587 |
) |
Accumulated deficit |
|
|
(132,815 |
) |
|
|
(187,119 |
) |
|
Total Stockholders Equity |
|
|
154,618 |
|
|
|
60,133 |
|
|
|
|
|
|
|
|
|
|
|
Total Liabilities and Stockholders Equity |
|
$ |
750,287 |
|
|
$ |
538,879 |
|
|
See accompanying notes to condensed consolidated financial statements.
69
Endeavour International Corporation
Consolidated Statement of Operations
(Amounts in thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
|
Revenues |
|
$ |
71,675 |
|
|
$ |
62,293 |
|
|
$ |
170,781 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of Operations: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses |
|
|
15,347 |
|
|
|
17,776 |
|
|
|
32,317 |
|
Depreciation, depletion and amortization |
|
|
28,894 |
|
|
|
34,020 |
|
|
|
67,326 |
|
Impairment of oil and gas properties |
|
|
7,692 |
|
|
|
43,929 |
|
|
|
36,970 |
|
General and administrative |
|
|
18,415 |
|
|
|
16,966 |
|
|
|
15,932 |
|
|
Total Expenses |
|
|
70,348 |
|
|
|
112,691 |
|
|
|
152,545 |
|
|
Income (Loss) From Operations |
|
|
1,327 |
|
|
|
(50,398 |
) |
|
|
18,236 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income (Expense): |
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
Realized gains (losses) |
|
|
(11,753 |
) |
|
|
35,422 |
|
|
|
(28,578 |
) |
Unrealized gains (losses) |
|
|
12,291 |
|
|
|
(55,598 |
) |
|
|
76,666 |
|
Interest expense |
|
|
(34,592 |
) |
|
|
(16,630 |
) |
|
|
(22,975 |
) |
Gain on sale of reserves in place |
|
|
87,171 |
|
|
|
|
|
|
|
|
|
Interest income and other |
|
|
1,299 |
|
|
|
(7,483 |
) |
|
|
6,626 |
|
|
Total Other Income (Expense) |
|
|
54,416 |
|
|
|
(44,289 |
) |
|
|
31,739 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) Before Income Taxes |
|
|
55,743 |
|
|
|
(94,687 |
) |
|
|
49,975 |
|
Income Tax Expense (Benefit) |
|
|
(788 |
) |
|
|
(7,158 |
) |
|
|
24,116 |
|
|
Income (Loss) from Continuing Operations |
|
|
56,531 |
|
|
|
(87,529 |
) |
|
|
25,859 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discontinued Operations, net of tax: |
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from operations |
|
|
|
|
|
|
(774 |
) |
|
|
30,631 |
|
Gain on sale |
|
|
|
|
|
|
47,308 |
|
|
|
|
|
|
Income (Loss) from Discontinued Operations |
|
|
|
|
|
|
46,534 |
|
|
|
30,631 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) |
|
|
56,531 |
|
|
|
(40,995 |
) |
|
|
56,490 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred Stock Dividends: |
|
|
|
|
|
|
|
|
|
|
|
|
Dividends declared |
|
|
2,227 |
|
|
|
9,757 |
|
|
|
10,809 |
|
Non-cash charge under fair value accounting upon
redemption |
|
|
|
|
|
|
11,454 |
|
|
|
|
|
|
Total Preferred Stock Dividends |
|
|
2,227 |
|
|
|
21,211 |
|
|
|
10,809 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) to Common Stockholders |
|
$ |
54,304 |
|
|
$ |
(62,206 |
) |
|
$ |
45,681 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic Net Income (Loss) per Common Share: |
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations |
|
$ |
2.34 |
|
|
$ |
(5.84 |
) |
|
$ |
0.82 |
|
Discontinued operations |
|
|
|
|
|
|
2.50 |
|
|
|
1.67 |
|
|
Total |
|
$ |
2.34 |
|
|
$ |
(3.34 |
) |
|
$ |
2.49 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted Net Income (Loss) per Common Share: |
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations |
|
$ |
1.95 |
|
|
$ |
(4.70 |
) |
|
$ |
0.59 |
|
Discontinued operations |
|
|
|
|
|
|
2.50 |
|
|
|
1.20 |
|
|
Total |
|
$ |
1.95 |
|
|
$ |
(2.20 |
) |
|
$ |
1.79 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Number of Common Shares Outstanding: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
23,252 |
|
|
|
18,613 |
|
|
|
18,330 |
|
|
Diluted |
|
|
28,886 |
|
|
|
18,613 |
|
|
|
25,473 |
|
|
See accompanying notes to condensed consolidated financial statements.
70
Endeavour International Corporation
Consolidated Statement of Cash Flows
(Amounts in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2010 |
|
2009 |
|
2008 |
Cash Flows from Operating Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
56,531 |
|
|
$ |
(40,995 |
) |
|
$ |
56,490 |
|
Adjustments to reconcile net income (loss) to net
cash provided by operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
28,894 |
|
|
|
38,701 |
|
|
|
81,734 |
|
Impairment of oil and gas properties |
|
|
7,692 |
|
|
|
43,929 |
|
|
|
36,970 |
|
Deferred tax expense (benefit) |
|
|
(3,367 |
) |
|
|
4,599 |
|
|
|
17,682 |
|
Unrealized (gains) losses on derivatives |
|
|
(12,291 |
) |
|
|
55,598 |
|
|
|
(76,666 |
) |
Gain on sales |
|
|
(87,171 |
) |
|
|
(47,308 |
) |
|
|
(258 |
) |
Non-cash interest expense |
|
|
8,764 |
|
|
|
5,464 |
|
|
|
4,496 |
|
Amortization of deferred financing costs |
|
|
10,262 |
|
|
|
4,963 |
|
|
|
7,279 |
|
Other |
|
|
1,606 |
|
|
|
6,408 |
|
|
|
(6,920 |
) |
Changes in operating assets and liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
Decrease in receivables |
|
|
6,732 |
|
|
|
3,978 |
|
|
|
9,795 |
|
(Increase) decrease in other current assets |
|
|
(4,668 |
) |
|
|
7,489 |
|
|
|
(3,745 |
) |
Increase (decrease) in liabilities |
|
|
4,035 |
|
|
|
(27,115 |
) |
|
|
6,323 |
|
|
Net Cash Provided by Operating Activities |
|
|
17,019 |
|
|
|
55,711 |
|
|
|
133,180 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows From Investing Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(92,007 |
) |
|
|
(99,241 |
) |
|
|
(64,194 |
) |
Acquisitions |
|
|
(43,726 |
) |
|
|
(32,152 |
) |
|
|
(2,176 |
) |
Proceeds from sales, net of cash |
|
|
108,316 |
|
|
|
144,653 |
|
|
|
259 |
|
(Increase) decrease in restricted cash |
|
|
(28,897 |
) |
|
|
17,860 |
|
|
|
1,260 |
|
|
Net Cash Provided by (Used in) Investing Activities |
|
|
(56,314 |
) |
|
|
31,120 |
|
|
|
(64,851 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows From Financing Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Repayments of borrowings |
|
|
(75,342 |
) |
|
|
(64,458 |
) |
|
|
(120,000 |
) |
Borrowings under debt agreements |
|
|
185,000 |
|
|
|
1,400 |
|
|
|
88,000 |
|
Redemption of preferred stock |
|
|
|
|
|
|
(25,000 |
) |
|
|
|
|
Proceeds from issuance of common stock |
|
|
30,181 |
|
|
|
|
|
|
|
|
|
Dividends paid |
|
|
(2,070 |
) |
|
|
(9,625 |
) |
|
|
(10,625 |
) |
Financing costs paid |
|
|
(26,590 |
) |
|
|
|
|
|
|
(3,538 |
) |
Other financing |
|
|
96 |
|
|
|
(17 |
) |
|
|
(450 |
) |
|
Net Cash Provided by (Used in) Financing Activities |
|
|
111,275 |
|
|
|
(97,700 |
) |
|
|
(46,613 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Increase (Decrease) in Cash and Cash Equivalents |
|
|
71,980 |
|
|
|
(10,869 |
) |
|
|
21,716 |
|
Cash and Cash Equivalents, Beginning of Period |
|
|
27,287 |
|
|
|
38,156 |
|
|
|
16,440 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents, End of Period |
|
$ |
99,267 |
|
|
$ |
27,287 |
|
|
$ |
38,156 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents, End of Period: |
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations |
|
$ |
99,267 |
|
|
$ |
27,287 |
|
|
$ |
31,421 |
|
Discontinued operations |
|
|
|
|
|
|
|
|
|
|
6,735 |
|
|
Total |
|
$ |
99,267 |
|
|
$ |
27,287 |
|
|
$ |
38,156 |
|
|
See accompanying notes to condensed consolidated financial statements.
71
Endeavour International Corporation
Consolidated Statement of Stockholders Equity
(Amounts in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional |
|
Other |
|
|
|
|
|
Total |
|
Total |
|
|
Common |
|
Treasury |
|
Paid-In |
|
Comprehensive |
|
Accumulated |
|
Stockholders |
|
Comprehensive |
|
|
Stock |
|
Stock |
|
Capital |
|
Loss |
|
Deficit |
|
Equity |
|
Income (Loss) |
|
Balance, January 1, 2008 |
|
$ |
19 |
|
|
$ |
|
|
|
$ |
241,647 |
|
|
$ |
(923 |
) |
|
$ |
(170,594 |
) |
|
$ |
70,149 |
|
|
|
|
|
Preferred stock dividend |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(10,809 |
) |
|
|
(10,809 |
) |
|
|
|
|
Amortization of deferred
compensation |
|
|
|
|
|
|
|
|
|
|
3,226 |
|
|
|
|
|
|
|
|
|
|
|
3,226 |
|
|
|
|
|
Treasury stock repurchase |
|
|
|
|
|
|
(450 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(450 |
) |
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
|
(293 |
) |
|
|
|
|
|
|
|
|
|
|
(293 |
) |
|
|
|
|
Comprehensive Income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
56,490 |
|
|
|
56,490 |
|
|
$ |
56,490 |
|
Other comprehensive loss (net of tax): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized loss on derivative
instruments, net of tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(342 |
) |
|
|
|
|
|
|
(342 |
) |
|
|
(342 |
) |
Unrealized gain (loss) on
available-for-sale
securities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
Balance, December 31, 2008 |
|
$ |
19 |
|
|
$ |
(450 |
) |
|
$ |
244,580 |
|
|
$ |
(1,266 |
) |
|
$ |
(124,913 |
) |
|
$ |
117,970 |
|
|
$ |
56,148 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred stock dividend |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(21,211 |
) |
|
|
(21,211 |
) |
|
|
|
|
Amortization of deferred
compensation |
|
|
|
|
|
|
|
|
|
|
3,163 |
|
|
|
|
|
|
|
|
|
|
|
3,163 |
|
|
|
|
|
Treasury stock repurchase |
|
|
|
|
|
|
(137 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(137 |
) |
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
|
77 |
|
|
|
|
|
|
|
|
|
|
|
77 |
|
|
|
|
|
Comprehensive Loss: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(40,995 |
) |
|
|
(40,995 |
) |
|
|
(40,995 |
) |
Other comprehensive income (net of tax): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized loss on derivative
instruments, net of tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,194 |
|
|
|
|
|
|
|
1,194 |
|
|
|
1,194 |
|
Unrealized gain (loss) on
available-for-sale
securities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
72 |
|
|
|
|
|
|
|
72 |
|
|
|
72 |
|
|
Balance, December 31, 2009 |
|
$ |
19 |
|
|
$ |
(587 |
) |
|
$ |
247,820 |
|
|
$ |
|
|
|
$ |
(187,119 |
) |
|
$ |
60,133 |
|
|
$ |
(39,729 |
) |
|
See accompanying notes to condensed consolidated financial statements.
72
Endeavour International Corporation
Consolidated Statement of Stockholders Equity
(Amounts in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional |
|
Other |
|
|
|
|
|
Total |
|
Total |
|
|
Common |
|
Treasury |
|
Paid-In |
|
Comprehensive |
|
Accumulated |
|
Stockholders |
|
Comprehensive |
|
|
Stock |
|
Stock |
|
Capital |
|
Loss |
|
Deficit |
|
Equity |
|
Income (Loss) |
|
Balance, December 31, 2009 |
|
$ |
19 |
|
|
$ |
(587 |
) |
|
$ |
247,820 |
|
|
$ |
|
|
|
$ |
(187,119 |
) |
|
$ |
60,133 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred stock dividend |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,227 |
) |
|
|
(2,227 |
) |
|
|
|
|
Common stock issuance |
|
|
5 |
|
|
|
|
|
|
|
30,176 |
|
|
|
|
|
|
|
|
|
|
|
30,181 |
|
|
|
|
|
Series C preferred stock conversion |
|
|
1 |
|
|
|
|
|
|
|
5,906 |
|
|
|
|
|
|
|
|
|
|
|
5,907 |
|
|
|
|
|
Amortization of deferred
compensation |
|
|
|
|
|
|
|
|
|
|
3,660 |
|
|
|
|
|
|
|
|
|
|
|
3,660 |
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
|
433 |
|
|
|
|
|
|
|
|
|
|
|
433 |
|
|
|
|
|
Comprehensive Loss: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
56,531 |
|
|
|
56,531 |
|
|
$ |
56,531 |
|
|
|
Balance, December 31, 2010 |
|
$ |
25 |
|
|
$ |
(587 |
) |
|
$ |
287,995 |
|
|
$ |
|
|
|
$ |
(132,815 |
) |
|
$ |
154,618 |
|
|
$ |
56,531 |
|
|
See accompanying notes to condensed consolidated financial statements.
73
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
Note 1 Description of Business
Endeavour International Corporation is an independent oil and gas company engaged in the
exploration, development, production and acquisition of energy reserves in the U.S. and U.K.
Endeavour was incorporated under the laws of the state of Nevada on January 13, 2000. As used in
these Notes to Consolidated Financial Statements, the terms Endeavour, we, us, our and
similar terms refer to Endeavour International Corporation and, unless the context indicates
otherwise, its consolidated subsidiaries.
Note 2 Summary of Significant Accounting Policies
Basis of Presentation and Use of 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 (US
GAAP) 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. In the opinion of
management, all normal recurring adjustments considered necessary for a fair presentation have been
included in these financial statements. Certain amounts for prior periods have been reclassified
to conform to the current presentation.
These accounting principles require management to use estimates, judgments and assumptions that
affect the amounts of assets, liabilities, revenues and expenses reported herein. While management
reviews its estimates, 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:
|
|
|
estimates of proved oil and gas reserves, |
|
|
|
|
estimates as to the expected future cash flow from proved oil and gas properties, |
|
|
|
|
estimates of future dismantlement and restoration costs, |
|
|
|
|
estimates of fair values used in purchase accounting and |
|
|
|
|
estimates of the fair value of derivative instruments. |
Principles of Consolidation
The accompanying consolidated financial statements include all of the accounts of Endeavour
and our consolidated subsidiaries. All significant intercompany accounts and transactions have
been eliminated. Investments in entities over which we have significant influence, but not
control, are carried at cost adjusted for equity in earnings or (losses) and distributions
received.
74
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
Cash and Cash Equivalents
We consider all highly liquid instruments with an original maturity of 90 days or less at the
time of purchase to be cash equivalents.
Restricted Cash
Restricted cash has included amounts held in escrow for drilling rig commitments, as
collateral for lines of credit, and for acquisitions. At December 31, 2009, restricted cash
primarily represented the escrow for our acquisition of properties from Hillwood Energy and was
released upon closing of the acquisition in January 2010. At December 31, 2010, restricted cash
represented amounts held in escrow as collateral for lines of credit associated abandonment
liabilities related to our U.K. properties. On February 6, 2011, we amended our Senior Term Loan
to increase the security reserved for potential letters of credit from $25 million to $35 million.
Upon receipt of sufficient third party financing, this increase in the security
amount should allow
us to release the $32 million of restricted cash that currently serves as collateral for existing
letters of credit with an alternative letter of credit provider.
Inventories
Materials and supplies and oil inventories are valued at the lower of cost or market value
(net realizable value).
Full Cost Accounting for Oil and Gas Operations
Under the full cost method, all acquisition, exploration and development costs 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; such as the estimated costs of dismantling and abandoning these assets, dry hole costs,
lease acquisition
costs, seismic and other geological and geophysical costs, delay rentals, costs related to such
activities, certain directly-related employee costs and a portion of interest expense. 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). 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. The ceiling test limitation is
calculated as the present value, discounted 10%, of:
|
|
|
the future net cash flows related to estimated production of proved reserves; |
|
|
|
|
the effect of derivative instruments that qualify as cash flow hedges; |
|
|
|
|
the lower of cost or estimated fair value of unproved properties; and |
|
|
|
|
the expected income tax effects of the above items. |
75
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
Future net cash flows use the average, first-day-of-the-month price for commodities during
2010 and 2009 and the year-end price for 2008.
We utilize a single cost center for each country where we have operations for amortization
purposes. Any sales or other 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 initially 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 and 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 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.
Other Property and Equipment
Other oil and gas assets, computer equipment and furniture and fixtures are recorded at cost,
less accumulated depreciation. The assets are depreciated using the straight-line method over
their estimated useful lives of two to five years.
76
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
Capitalized Interest
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.
Marketable Securities
The marketable securities reflected in these financial statements are deemed by management to
be available-for-sale and, accordingly, are reported at fair value, with unrealized gains and
losses reported in other comprehensive income and reflected as a separate component within the
Statement of Stockholders Equity unless we determine that an other-than-temporary impairment has
occurred. Realized gains and losses on securities available-for-sale are included in other
income/expense and, when applicable, are reported as a reclassification adjustment, net of tax, in
other comprehensive income. Gains and losses on the sale of available-for-sale securities are
determined using the specific-identification method.
Business Combinations
Assets and liabilities acquired through a business combination are recorded at 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.
Any excess of the acquisition cost of the acquired business over the fair value amounts assigned to
assets and liabilities is recorded as goodwill. Any excess of the amounts assigned to assets and
liabilities over the acquisition of the acquired business is recorded as a gain on acquisition on
the income statement. The amount of goodwill recorded in any particular business combination can
vary significantly depending upon the fair values attributed to assets acquired and liabilities
assumed relative to the total acquisition cost.
Goodwill and Intangible Assets
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.
77
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
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 collectability of the
revenue is probable.
Significant Customers
Our sales in the U.K. are to a limited number of customers, each of which accounts for more
than 10% of revenue. These customers are Chevron North Sea Ltd, Shell U.K. Limited, and Esso
Exploration and Production. Our sales in the U.S. are sold through our arrangements with the
operators of the fields, with substantially all of the sales being to Cohort Energy.
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 also have embedded derivatives
related to our debt instruments and convertible preferred stock.
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, |
78
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
|
|
|
reduce our exposure to increases in interest rates, and |
|
|
|
|
manage cash flows in support of our annual capital expenditure budget. |
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. At December 31, 2010 and 2009, we have no outstanding derivatives that
are accounted for as a hedge.
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.
Concentrations of Credit and Market Risk
Financial instruments that potentially subject us to concentrations of credit risk consist
principally of cash deposits at financial institutions. At various times during the year, we may
exceed the federally insured limits. To mitigate this risk, we place our cash deposits only with
high credit quality institutions. Management believes the risk of loss is minimal.
Derivative financial instruments that hedge the price of oil and gas, interest rates or currency
exposure will be generally executed with major financial or commodities trading institutions which
expose us to market and credit risks, and may at times be concentrated with certain counterparties
or groups of counterparties. Although notional amounts are used to express the volume of these
contracts, the amounts potentially subject to credit risk, in the event of non-
79
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
performance by the counterparties, are substantially smaller. We review the credit ratings of
our counterparties to derivative contracts on a regular basis and to date we have not experienced
any non-performance by any of our various counterparties, currently BNP Paribas S.A., Bank of
America Merrill Lynch and Commonwealth Bank of Australia. At December 31, 2010, our derivative
instruments do not require either side to maintain collateral or margin accounts.
As an independent oil and gas producer, our revenue, profitability and future rate of growth are
substantially dependent upon prevailing prices for oil and gas, which are dependent upon numerous
factors beyond our control, such as economic, political and regulatory developments and competition
from other sources of energy. The energy markets have historically been very volatile, and there
can be no assurance that oil and gas prices will not be subject to wide fluctuations in the future.
A substantial or extended decline in oil and gas prices could have a material adverse effect on
our financial position, results of operations, cash flows and our access to capital and on the
quantities of oil and gas reserves that may be economically produced.
Foreign Currency Translation
The U.S. dollar is the functional currency for all of our existing operations, as a majority
of all revenue and financing transactions in these operations are denominated in U.S. dollars. For
foreign operations with the U.S. dollar as the functional currency, monetary assets and liabilities
are remeasured into U.S. dollars at the exchange rate on the balance sheet date. Nonmonetary
assets and liabilities are translated into U.S. dollars at historical exchange rates. Income and
expense items are translated at exchange rates prevailing during each period. Adjustments are
recognized currently as a component of foreign currency gain or loss and deferred income taxes. To
the extent that business transactions are not denominated in U.S. dollars, we are exposed to
foreign currency exchange rate risk.
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.
Share-Based Payments
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
80
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
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 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, 2010, we had approximately 1.4 million additional shares available for issuance
pursuant to our existing stock incentive plan.
Adoption of New Accounting Standards
On January 1, 2009, we adopted the following new standards without material effects on our
results of operations or financial position:
|
|
|
Business combinations Guidance related to the measurement of identifiable assets
acquired, liabilities assumed and disclosure of information related to business
combinations and their effect. |
|
|
|
|
Noncontrolling interests Guidance for the noncontrolling interest in a subsidiary and
for the deconsolidation of a subsidiary. Specifically, this standard requires the
recognition of a noncontrolling interest (minority interest) as a component of consolidated
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. |
|
|
|
|
Expanded disclosures of derivatives Expanded and detailed financial statement
disclosures for 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. |
|
|
|
|
Convertible debt Guidance for convertible debt that may be settled in part or in
whole in cash upon conversion requiring issuers of this form of debt to account for its
debt and equity components separately. The new guidance also expands the definition of
mandatorily redeemable convertible preferred shares that should be classified as
liabilities. |
|
|
|
|
Share-based payments Guidance for instruments that are granted in share-based payment
transactions to treat unvested share-based payment awards with non-forfeitable
rights to dividend or dividend equivalents as a separate class of securities in calculating
earnings per share (EPS). The impact of the adoption of this standard on our weighted
average shares outstanding and EPS was not material, therefore, we have not restated prior
periods. |
|
|
|
|
Fair value Framework for measuring fair value and expanded disclosures about fair
value measurements. New fair value measurements are not required; rather, the provisions
apply when fair value measurements are performed under other accounting pronouncements. |
81
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
On June 30, 2009, we adopted the following new standard that did not have a material effect on
our results of operations or financial position:
|
|
|
Subsequent events Standards of accounting for and disclosure of events that occur
after the balance sheet date but before the financial statements are issued. |
On December 31, 2009, we adopted the following new standard that did not have a material effect on
our results of operations or financial position:
|
|
|
Oil and gas modernization Revised oil and gas reserve estimation and disclosure
requirements. The accounting standards update revised the definition of proved oil and gas
reserves to require that the average, first-day-of-the-month price during the 12-month
period before the end of the year rather than the year-end price, must be used when
estimating whether reserve quantities are economical to produce and when calculating the
aggregate amount of (and changes in) future cash inflows related to the standardized
measure of discounted future net cash flows. |
On January 1, 2010, we adopted the following new standards without material effects on
our results of operations or financial position:
|
|
|
Subsequent events Amended standards of accounting for and disclosure of events that
occur after the balance sheet date but before the financial statements are issued. |
|
|
|
|
Fair value New, expanded disclosures are required for recurring or nonrecurring
fair-value measurements and the reconciliation of specific fair value measurements. |
Note 3 Discontinued Operations
On May 14, 2009, we completed the Norway Sale for cash consideration of $150 million. We
recognized a gain upon closing the Norway Sale of $87.0 million, after the allocation of $68
million of goodwill to the assets sold. As a result of the Norway Sale, we have classified the
results of operations and financial position of our Norwegian subsidiary as discontinued operations
for all periods presented. The following table details selected financial data for the assets
included in the Norway Sale:
82
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2010 |
|
2009 |
|
2008 |
|
Sales |
|
$ |
|
|
|
$ |
17,550 |
|
|
$ |
89,660 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before Taxes |
|
$ |
|
|
|
$ |
4,654 |
|
|
$ |
63,244 |
|
Income Tax Expense |
|
|
|
|
|
|
(5,428 |
) |
|
|
(32,613 |
) |
|
Income (Loss) from Operations |
|
|
|
|
|
|
(774 |
) |
|
|
30,631 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain on sale |
|
|
|
|
|
|
47,308 |
|
|
|
|
|
|
Net Income from Discontinued Operations |
|
$ |
|
|
|
$ |
46,534 |
|
|
$ |
30,631 |
|
|
Note 4 Prepaid Expenses and Other Current Assets
Prepaid expenses and other current assets consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2010 |
|
2009 |
|
Fair market value of commodity derivatives current |
|
$ |
709 |
|
|
$ |
2,890 |
|
Prepaid insurance |
|
|
1,039 |
|
|
|
1,506 |
|
Inventory |
|
|
4,617 |
|
|
|
4,450 |
|
Other |
|
|
2,353 |
|
|
|
1,272 |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
8,718 |
|
|
$ |
10,118 |
|
|
83
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
Note 5 Property and Equipment
Property and equipment included the following:
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2010 |
|
2009 |
|
Oil and gas properties under the full cost method: |
|
|
|
|
|
|
|
|
Subject to amortization |
|
$ |
389,575 |
|
|
$ |
275,278 |
|
Not subject to amortization: |
|
|
|
|
|
|
|
|
Acquired in 2010 |
|
|
67,612 |
|
|
|
|
|
Acquired in 2009 |
|
|
31,134 |
|
|
|
51,797 |
|
Acquired in 2008 |
|
|
23,109 |
|
|
|
32,970 |
|
Acquired prior to 2008 |
|
|
39,575 |
|
|
|
69,786 |
|
|
|
|
|
551,005 |
|
|
|
429,831 |
|
|
|
|
|
|
|
|
|
|
Computers, furniture and fixtures |
|
|
4,222 |
|
|
|
3,560 |
|
|
Total property and equipment |
|
|
555,227 |
|
|
|
433,391 |
|
|
|
|
|
|
|
|
|
|
Accumulated depreciation, depletion and amortization |
|
|
(190,550 |
) |
|
|
(166,804 |
) |
|
|
|
|
|
|
|
|
|
|
Net property and equipment |
|
$ |
364,677 |
|
|
$ |
266,587 |
|
|
The costs not subject to amortization include
|
|
|
values assigned to unproved reserves acquired, |
|
|
|
exploration costs such as drilling costs for projects awaiting approved development
plans or the determination of whether or not proved reserves can be assigned, and |
|
|
|
other seismic and geological and geophysical costs. |
These costs are transferred to the amortization base when it is determined whether or not proved
reserves can be assigned to such properties. This analysis is dependent upon well performance,
results of infield drilling, approval of development plans, drilling results and development of
identified projects and periodic assessment of reserves. We expect acquisition costs excluded from
amortization to be transferred to the amortization base over the next five years due to a
combination of well performance and results of infield drilling relating to currently producing
assets and the drilling and development of identified projects acquired, such as the Rochelle
field. We expect exploration costs not subject to amortization to be transferred to the
amortization base over the next three years as development plans are completed and production
commences on existing discoveries including the Rochelle, Bacchus and Columbus projects.
The following is a summary of our oil and gas properties not subject to amortization as of December
31, 2010:
84
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs Incurred in the Year Ended December 31, |
|
|
2010 |
|
2009 |
|
2008 |
|
Prior to 2008 |
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition costs |
|
$ |
32,476 |
|
|
$ |
10,385 |
|
|
$ |
650 |
|
|
$ |
10,345 |
|
|
$ |
53,856 |
|
Exploration costs |
|
|
32,770 |
|
|
|
20,593 |
|
|
|
22,459 |
|
|
|
29,230 |
|
|
|
105,052 |
|
Capitalized interest |
|
|
2,366 |
|
|
|
156 |
|
|
|
|
|
|
|
|
|
|
|
2,522 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil
and gas properties not subject to amortization |
|
$ |
67,612 |
|
|
$ |
31,134 |
|
|
$ |
23,109 |
|
|
$ |
39,575 |
|
|
$ |
161,430 |
|
|
During 2010, 2009 and 2008, we capitalized $13.1 million, $7.8 million and $8.0 million,
respectively, in certain directly related employee costs. During 2010, 2009 and 2008, we
capitalized $3.9 million, $3.1 million and $4.0 million, respectively, in interest.
During 2010, 2009 and 2008, we recorded $7.7 million, $43.9 million and $37.0 million,
respectively, of impairment through the application of the full cost ceiling test. The impairment
during 2010 related to our U.S. oil and gas properties, pre-tax, and was primarily due to the
declaration of two wells as dry holes during the first quarter of 2010; the Alligator Bayou well
which was spud in 2008 and a well under a participation agreement. During 2009, our impairment
related to both our U.S. and UK properties. During 2008, our impairment related to our UK
properties. The impairments in both years resulted from steep declines in commodity prices.
Assets Acquisitions
On January 6, 2010, we acquired positions in several U.S. resource plays as discussed below.
We funded the initial cash contributions for these new focus areas from existing cash reserves.
During 2010, we entered into a participation agreement with a private oil and gas operator, and
acquired interests in certain acreage in North Louisiana/East Texas and Western Pennsylvania,
primarily in the Haynesville and Marcellus areas. Our initial investment was $15 million in cash,
and we will pay a share of that operators drilling and completion expenditures as wells are
drilled over the next few years. Under this agreement, we also acquired additional acreage in the
Marcellus area for approximately $7.5 million during the second quarter of 2010.
During 2010, we also acquired interests in an exploratory gas shale play in Alabama with an initial
net investment of approximately $8.0 million.
85
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
Asset Disposition
On October 19, 2010, we completed the Cygnus Sale for $110 million in cash, and recorded a
gain of $87 million. The cash proceeds were not burdened by any current taxes payable and are
being primarily used to accelerate our development projects.
Note 6 Goodwill
In connection with the several business acquisitions, we recorded goodwill for the excess of
the purchase price over the value assigned to individual assets acquired and liabilities assumed.
With the 2009 settlement of a liability for a metering mis-measurement liability at a purchased
field, the goodwill was reduced by $2.1 million. The following is a reconciliation of the changes
in goodwill for the year ended December 31, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2010 |
|
2009 |
|
Balance at beginning of year |
|
$ |
211,886 |
|
|
$ |
281,943 |
|
Allocation of goodwill to discontinued operations sold |
|
|
|
|
|
|
(67,994 |
) |
Adjustments |
|
|
|
|
|
|
(2,063 |
) |
|
|
|
|
|
|
|
|
|
|
Balance at end of year |
|
$ |
211,886 |
|
|
$ |
211,886 |
|
|
86
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
Note 7 Other Assets
Other long-term assets consisted of the following at December 31:
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
2009 |
|
Intangible assets workforce in place: |
|
|
|
|
|
|
|
|
Gross |
|
$ |
4,800 |
|
|
$ |
4,800 |
|
Accumulated amortization |
|
|
(4,475 |
) |
|
|
(3,919 |
) |
|
Net intangible assets |
|
|
325 |
|
|
|
881 |
|
|
|
|
|
|
|
|
|
|
Debt issuance costs |
|
|
23,702 |
|
|
|
3,875 |
|
Fair market value of long-term portion of derivatives |
|
|
1,611 |
|
|
|
318 |
|
Other |
|
|
257 |
|
|
|
248 |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
25,895 |
|
|
$ |
5,322 |
|
|
Intangible assets represent the purchase price allocated to the assembled workforce as a
result of an acquisition and is being amortized over its estimated life using the straight-line
method. The intangible assets will be fully amortized during 2011.
Debt issuance costs are amortized over the life of the related debt obligation. During 2010, we
incurred $26.6 million
in debt issuance costs related to the issuance of our Junior Credit Facility and
Senior Term Loan. See Note 9 for additional discussion.
Note 8 Accrued Expenses
We had the following accrued expenses outstanding:
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2010 |
|
2009 |
|
Derivative liability |
|
$ |
|
|
|
$ |
6,817 |
|
Foreign taxes payable |
|
|
4,333 |
|
|
|
1,926 |
|
Accrued interest |
|
|
2,234 |
|
|
|
2,432 |
|
Preferred dividends |
|
|
1,301 |
|
|
|
1,143 |
|
Accrued compensation |
|
|
6,681 |
|
|
|
4,311 |
|
Current portion of asset retirement obligations |
|
|
6,405 |
|
|
|
|
|
Other |
|
|
1,688 |
|
|
|
1,169 |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
22,642 |
|
|
$ |
17,798 |
|
|
87
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
Note 9 Debt Obligations
Our debt consisted of the following at December 31:
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
2009 |
|
|
|
|
|
|
|
|
|
|
Senior notes, 6% fixed rate, due 2012 |
|
$ |
81,250 |
|
|
$ |
81,250 |
|
Senior bank facility, variable rate, due 2011 |
|
|
|
|
|
|
49,942 |
|
Convertible bonds, 11.5%, due 2014 |
|
|
55,821 |
|
|
|
49,838 |
|
Subordinated notes, 12.0%,
due 2014 |
|
|
51,132 |
|
|
|
50,122 |
|
Senior term loan, 15%, due 2013 |
|
|
161,371 |
|
|
|
|
|
|
|
|
|
349,574 |
|
|
|
231,152 |
|
Less: debt discount |
|
|
(4,268 |
) |
|
|
(7,767 |
) |
Less: current maturities |
|
|
(21,600 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt |
|
$ |
323,706 |
|
|
$ |
223,385 |
|
|
|
|
|
|
|
|
|
|
|
Standby letters of credit outstanding for
abandonment liabilities |
|
$ |
31,726 |
|
|
$ |
33,388 |
|
|
Principal maturities of debt at December 31, 2010 are as follows:
|
|
|
|
|
2011 |
|
$ |
21,600 |
|
2012 |
|
|
92,850 |
|
2013 |
|
|
168,171 |
|
2014 |
|
|
66,953 |
|
2015 |
|
|
|
|
Thereafter |
|
|
|
|
|
The fair value of our debt obligations was $361 million and $219 million at December 31, 2010
and 2009, respectively. The fair values of long-term debt were determined based upon external
market quotes for our Senior Notes, book value for our Senior Bank Facility and discounted cash
flows for other debt. Book value approximates fair value for our Senior Bank Facility as this
instrument bore interest at a market rate.
Junior Facility
In the first quarter of 2010, we entered into the $25 million Junior Facility, which had a
maturity date of February 5, 2011, and bore interest at LIBOR plus 8%. We terminated the Junior
Facility and repaid the outstanding indebtedness in its entirety on August 16, 2010.
88
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
6% Senior Notes
During 2005, we issued in a private offering $81.25 million aggregate principal amount of
convertible senior notes due in January 2012. The notes bear interest at a rate of 6.00% per
annum, payable in January and July at a conversion price of approximately $35.14 per share, subject
to adjustment. Upon specified change of control events, each holder of those notes may require us
to purchase all or a portion of the holders notes at a price equal to 100% of the principal
amount, plus accrued and unpaid interest, if any, up to but excluding the date of purchase.
Senior Bank Facility
We had a $225 million Senior Bank Facility, which was subject to a borrowing base limitation
with interest of LIBOR plus 1.3%. We terminated the Senior Bank Facility and repaid the
outstanding indebtedness in its entirety on August 16, 2010.
11.5% Convertible Bonds
In January 2008, we issued 11.5% Convertible Bonds due 2014 for gross proceeds of $40 million
pursuant to a private offering to a sophisticated investor in Norway. The net proceeds from the
issuance of the 11.5% Convertible Bonds were used to repay a portion of our outstanding
indebtedness. The 11.5% Convertible Bonds bear interest at a rate of 11.5% per annum, compounded
quarterly. Interest is compounded quarterly and added to the outstanding principal balance each
quarter. The bonds are convertible into shares of our common stock at a conversion price of $16.52
per $1,000 of principal, which represents a conversion rate of approximately 61 shares of our
common stock per $1,000 of principal. The conversion price will be adjusted in accordance with the
terms of the bonds upon occurrence of certain events, including payment of common stock dividends,
common stock splits or issuance of common stock at a price below the then current market price.
In January 2012, the holders have the right to cause us to redeem the 11.5% Convertible Bonds if
the weighted average closing price of our common stock for the preceding 30 days is less than the
conversion price, as adjusted. If the holders do not exercise this right, the right will lapse and
the conversion price will be reset to the then current market price of our common stock if such
price is lower than the conversion price, as adjusted.
If we undergo a change of control as defined, the holders of the bonds have the right,
subject to certain conditions, to redeem the bonds and accrued interest. The bonds may become
immediately due upon the occurrence of certain events of default, as defined.
Two derivatives are associated with the conversion and change in control features of the 11.5%
Convertible Bonds. At December 31, 2010, the combined fair market value of these derivatives
89
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
is
$27.8 million, reflecting a $0.9 million increase during 2010 that was recorded in unrealized gains
(losses) on derivatives.
Subordinated Notes
On November 17, 2009, we entered into Stock Redemption Agreements with each of the holders of
our outstanding shares of Series C Preferred Stock whereby we redeemed 60% of the outstanding
shares of Series C Preferred Stock, for face value of $75 million, and amended the terms of the
remaining shares of Series C Preferred Stock. The redemption price consisted of a $25 million cash
payment and the issuance of $50 million Subordinated Notes.
The Subordinated Notes bear interest at an annual rate of 10%, plus 2% capitalized to the
outstanding principal amount. We will pay interest, in cash, on the unpaid principal amount of the
Subordinated Notes quarterly on March 31, June 30, September 30 and December 31 of each year
commencing on December 31, 2009. The Subordinated Notes are payable over four years commencing in
March 2011, but may be prepaid at any time at face value. The Subordinated Notes are unsecured and
subordinated to our outstanding obligations under our Senior Term Loan and rank on parity with our
other existing debt obligations.
Senior Term Loan
On August 16, 2010, we entered into a credit agreement with Cyan Partners, LP (Cyan), as
administrative agent, and various lenders for the Senior Term Loan, in the aggregate amount of $150
million, which was subsequently increased to $160 million. We paid $25.4 million in financing
costs related to the issuance of the Senior Term Loan.
The Senior Term Loan is a senior obligation of our U.K. subsidiary and guaranteed by Endeavour and
all of our material subsidiaries. In addition, substantially all of our assets are pledged as
collateral to secure the obligations under the Senior Term Loan. Such collateral may also secure
certain hedging obligations and reimbursement obligations in respect of letters of credit that may
be issued for our account.
As discussed above, we used $66 million of the proceeds from the loans to repay in full the
outstanding borrowings under the Senior Bank Facility and the Junior Facility. Following these
repayments, both the Senior Bank Facility and the Junior Facility terminated in accordance with
their terms. We expect to use the remaining net proceeds from the Senior Term Loan to fund our
development program and for general corporate purposes.
The Senior Term Loan obligates us to pay annual cash interest of 12%. In addition, we are
obligated to pay an additional 3% in annual interest in-kind (PIK Interest) through an increase
in the outstanding principal amount of the Senior Term Loan. We have the ability to pay the PIK
Interest in cash at our option. We paid Cyan certain fees in the aggregate amount of $18 million.
Concurrent with the closing of the Senior Term Loan, Cyan purchased nine million
90
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
shares of our
common stock from us. See Note 12 for additional discussion on this purchase of our common stock.
The Senior Term Loan has a three-year term and matures on August 16, 2013, provided that:
|
|
|
our 6% Convertible Notes have been refinanced or extended and |
|
|
|
|
the holders conditional redemption right on our 11.5% Convertible Bonds has been
terminated or extended. Such conditional redemption right exists if our average common
stock price, as defined, is below $16.52 per share on January 18, 2012. |
If these conditions are not met by October 14, 2011, the Senior Term Loan shall mature and will be
due in full on this date. We are currently in discussions with several parties concerning this
process and expect to extend, refinance or terminate the 6% Convertible Notes and the holders
conditional redemption right on Endeavours 11.5% Convertible Bonds by mid 2011.
The Senior Term Loan has quarterly principal prepayments of $400,000 beginning on December 31,
2010. At maturity, the remaining principal balance (including any PIK Interest) is due in full.
The Senior Term Loan is callable by us after one year. Between August 16, 2011 and August 15,
2012, we may voluntarily prepay any portion of or all amounts outstanding under the Senior Term
Loan at 103% of principal. For prepayments on or after August 16, 2012, the additional prepayment
fee will be 1% of the principal amount of the amount outstanding under the Senior Term Loan.
The Senior Term Loan permits certain asset sales and the incurrence of additional indebtedness,
subject to certain conditions and within specified limits. We are obligated to comply with certain
financial covenants, including:
|
|
|
a specified maximum total leverage ratio (consolidated net indebtedness to consolidated
EBITDAX), ranging from 7.85:1.00 at September 30, 2010 to 3.00:1.00 at December 31, 2012
and thereafter; |
|
|
|
|
a specified minimum EBITDAX for each four-quarter period, ranging from $45,000,000 for the
four-quarter period ending September 30, 2010 to $200,000,000 for the four-quarter period ending
June 30, 2013; |
|
|
|
|
a minimum Reserve Coverage Ratio, as defined, of not less than 3.00:1.00; and |
|
|
|
|
a PDP Coverage Ratio, as defined, of not less than 0.25:1.00 on or prior to
September 30, 2011 and not less than 0.50:1.00 after September 30, 2011. |
91
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
The Senior Term Loan contains various covenants that limit our ability, among other things, to:
grant liens; pay dividends; and make investments or loans. We are also obligated to maintain our
traditional hedging policies and program. See Note 18 for additional discussion.
The Senior Term Loan also contains customary events of default. If an event of default exists
under the Senior Term Loan, the administrative agent has the ability to accelerate the maturity of
the loan and exercise other rights and remedies.
92
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
Note 10 Income Taxes
The income (loss) before income taxes and the components of the income tax expense (benefit)
recognized on the Consolidated Statement of Income are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
Discontinued |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing |
|
Operations |
|
|
(Amounts in thousands) |
|
U.K. |
|
U.S. |
|
Other |
|
Operations |
|
Norway |
|
Total |
|
Year Ended December 31, 2010: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) before taxes |
|
$ |
90,160 |
|
|
$ |
(30,978 |
) |
|
$ |
(3,439 |
) |
|
$ |
55,743 |
|
|
$ |
|
|
|
$ |
55,743 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current tax (benefit) expense |
|
|
2,734 |
|
|
|
|
|
|
|
(154 |
) |
|
|
2,580 |
|
|
|
|
|
|
|
2,580 |
|
Deferred tax (benefit) expense |
|
|
(2,388 |
) |
|
|
|
|
|
|
(929 |
) |
|
|
(3,317 |
) |
|
|
|
|
|
|
(3,317 |
) |
Foreign currency losses on
deferred tax liabilities |
|
|
|
|
|
|
|
|
|
|
(51 |
) |
|
|
(51 |
) |
|
|
|
|
|
|
(51 |
) |
|
Total tax (benefit) expense |
|
|
346 |
|
|
|
|
|
|
|
(1,134 |
) |
|
|
(788 |
) |
|
|
|
|
|
|
(788 |
) |
|
Net income (loss) after taxes |
|
$ |
89,814 |
|
|
$ |
(30,978 |
) |
|
$ |
(2,305 |
) |
|
$ |
56,531 |
|
|
$ |
|
|
|
$ |
56,531 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2009: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) before taxes |
|
$ |
(52,041 |
) |
|
$ |
(31,167 |
) |
|
$ |
(11,479 |
) |
|
$ |
(94,687 |
) |
|
$ |
51,963 |
|
|
$ |
(42,724 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current tax expense |
|
|
(5,739 |
) |
|
|
40 |
|
|
|
(26 |
) |
|
|
(5,725 |
) |
|
|
(603 |
) |
|
|
(6,328 |
) |
Deferred tax expense |
|
|
(20,260 |
) |
|
|
(20 |
) |
|
|
(35 |
) |
|
|
(20,315 |
) |
|
|
4,791 |
|
|
|
(15,524 |
) |
Foreign currency gains on
deferred tax liabilities |
|
|
18,882 |
|
|
|
|
|
|
|
|
|
|
|
18,882 |
|
|
|
1,241 |
|
|
|
20,123 |
|
|
Total tax expense |
|
|
(7,117 |
) |
|
|
20 |
|
|
|
(61 |
) |
|
|
(7,158 |
) |
|
|
5,429 |
|
|
|
(1,729 |
) |
|
Net income (loss) after taxes |
|
$ |
(44,924 |
) |
|
$ |
(31,187 |
) |
|
$ |
(11,418 |
) |
|
$ |
(87,529 |
) |
|
$ |
46,534 |
|
|
$ |
(40,995 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2008: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) before taxes |
|
$ |
66,129 |
|
|
$ |
(11,969 |
) |
|
$ |
(4,185 |
) |
|
$ |
49,975 |
|
|
$ |
63,244 |
|
|
$ |
113,219 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current tax (benefit) expense |
|
|
11,158 |
|
|
|
|
|
|
|
10 |
|
|
|
11,168 |
|
|
|
27,879 |
|
|
|
39,047 |
|
Deferred tax (benefit) expense |
|
|
22,673 |
|
|
|
|
|
|
|
303 |
|
|
|
22,976 |
|
|
|
15,415 |
|
|
|
38,391 |
|
Foreign currency losses on
deferred tax liabilities |
|
|
(10,028 |
) |
|
|
|
|
|
|
|
|
|
|
(10,028 |
) |
|
|
(10,681 |
) |
|
|
(20,709 |
) |
|
Total tax (benefit) 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 |
|
|
The following table presents the principal reasons for the difference between our effective
tax rates and the United States federal statutory income tax rate of 35%.
93
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2010 |
|
2009 |
|
2008 |
|
Federal income tax expense (benefit) at statutory rate |
|
$ |
19,500 |
|
|
$ |
(33,141 |
) |
|
$ |
17,491 |
|
Taxation of foreign operations |
|
|
(579 |
) |
|
|
1,572 |
|
|
|
12,464 |
|
Tax-free gain on sale of reserves in place |
|
|
(30,510 |
) |
|
|
|
|
|
|
|
|
Change in valuation allowance U.S. |
|
|
(2,252 |
) |
|
|
10,464 |
|
|
|
4,150 |
|
Foreign tax benefit from foreign currency tax law change |
|
|
|
|
|
|
(5,400 |
) |
|
|
|
|
Foreign currency (gain) loss on deferred taxes |
|
|
(50 |
) |
|
|
18,882 |
|
|
|
(10,028 |
) |
Deemed foreign dividend of wholly owned subsidiaries |
|
|
11,466 |
|
|
|
|
|
|
|
|
|
Disallowed executive compensation |
|
|
765 |
|
|
|
|
|
|
|
|
|
Other |
|
|
872 |
|
|
|
465 |
|
|
|
39 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Tax Expense, continuing operations |
|
|
(788 |
) |
|
|
(7,158 |
) |
|
|
24,116 |
|
Discontinued operations Norway |
|
|
|
|
|
|
5,429 |
|
|
|
32,613 |
|
|
Total Income Tax Expense |
|
$ |
(788 |
) |
|
$ |
(1,729 |
) |
|
$ |
56,729 |
|
|
Effective Income Tax Rate |
|
|
-1 |
% |
|
|
8 |
% |
|
|
45 |
% |
|
During 2010, 2009 and 2008, we incurred taxes primarily related to our operations in the U.K.
and our discontinued operations in Norway. In 2010, 2009 and 2008 we had a loss before taxes of
$31.0 million, $31.2 million and $12.0 million, respectively, in the U.S. and we did not record any
income tax benefits on these losses as there was no assurance that we could generate any future
U.S. taxable earnings. As a result, we recorded a valuation allowance on the full amount of all
deferred tax assets generated in the U.S.
Deferred income taxes result from the net tax effects of temporary timing differences between the
carrying amounts of assets and liabilities reflected on the financial statements and the amounts
recognized for income tax purposes. The tax effects of temporary differences that give rise to
significant portions of deferred tax assets and liabilities are as follows at December 31:
94
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
2009 |
|
Deferred tax asset: |
|
|
|
|
|
|
|
|
Deferred compensation |
|
$ |
6,129 |
|
|
$ |
6,236 |
|
Unrealized loss on commodity derivative instruments |
|
|
936 |
|
|
|
16,560 |
|
Asset retirement obligation |
|
|
1,324 |
|
|
|
7,026 |
|
Net operating loss and capital loss carryforward |
|
|
57,548 |
|
|
|
34,635 |
|
Unrealized loss on embedded derivative instruments |
|
|
8,343 |
|
|
|
621 |
|
|
|
|
|
|
|
|
|
|
|
Total deferred tax assets |
|
|
74,280 |
|
|
|
65,078 |
|
Less valuation allowance |
|
|
(37,807 |
) |
|
|
(38,771 |
) |
|
Total deferred tax assets after valuation allowance |
|
|
36,473 |
|
|
|
26,307 |
|
|
|
|
|
|
|
|
|
|
Deferred tax liability: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment |
|
|
(104,672 |
) |
|
|
(97,111 |
) |
Unrealized gain on derivative instruments |
|
|
(825 |
) |
|
|
|
|
Petroleum revenue tax, net of tax benefit |
|
|
(488 |
) |
|
|
(1,264 |
) |
Debt discount |
|
|
(1,281 |
) |
|
|
(2,330 |
) |
Other |
|
|
(6,407 |
) |
|
|
(6,294 |
) |
|
|
|
|
|
|
|
|
|
|
Total deferred tax liabilities |
|
|
(113,673 |
) |
|
|
(106,999 |
) |
|
|
|
|
|
|
|
|
|
|
Net deferred tax liability |
|
$ |
(77,200 |
) |
|
$ |
(80,692 |
) |
|
At December 31, 2010, we had the following carryforwards available to reduce future income
taxes:
|
|
|
|
|
|
|
|
|
|
|
Years of |
|
Carryforward |
Types of Carryforward |
|
Expiration |
|
Amounts |
|
U.S. Net operating loss |
|
|
2023 - 2030 |
|
|
$ |
69,392 |
|
U.S. Capital loss |
|
|
2015 |
|
|
|
1,848 |
|
U.K. Corporate tax net operating loss |
|
Indefinite |
|
|
81,767 |
|
U.K. Supplemental Corporate tax net operating loss |
|
Indefinite |
|
|
40,305 |
|
With the exception of $69.4 million of net operating loss carryforward and a $1.8 million
capital loss carryforward attributable to our U.S. operations for which a valuation allowance has
been established, the remaining carryforward amounts shown above have been recognized for financial
statement reporting purposes to reduce deferred tax liability.
95
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
Recognition of the benefits of the deferred tax assets will require that we generate future
taxable income. There can be no assurance that we will generate any earnings or any specific level
of earnings in future years. Therefore, we have established a valuation allowance for deferred tax
assets of approximately $37.8 million, $38.8 million and $23.7 million as of December 31, 2010,
2009 and 2008, respectively. During 2010, the valuation allowance in the U.S. decreased $2.2
million due to net revisions of the net operating loss and increased $1.3 million for net operating
losses in other juridictions. During 2009, the valuation allowance in the U.S. increased $10.5
million due to net operating losses and increased $4.6 million in other jurisdictions. During
2008, the valuation allowance in the U.S. increased $2.9 million due to net operating losses and
increased $1.1 million for net operating losses in other jurisdictions.
For U.S. federal income tax purposes, certain limitations are imposed on an entitys ability to
utilize its NOLs in future periods if a change of control, as defined for federal income tax
purposes, has taken place. In general terms, the limitation on utilization of NOLs and other tax
attributes during any one year is determined by the value of an acquired entity at the date of the
change of control multiplied by the then-existing long-term, tax-exempt interest rate. The manner
of determining an acquired entitys value has not yet been addressed by the Internal Revenue
Service. We have determined that, for federal income tax purposes, a change of control occurred
during 2004 and 2007, however, we do not believe such limitations will significantly impact our
ability to utilize the NOL. The timing of NOL utilization will be determined by our future net
income.
At December 2007, we provided for a liability of $1.7 million for unrecognized tax benefits
relating to various U.K. matters. The statute of limitations for assessing tax for these benefits
expired during 2008, thus allowing the full recognition of these benefits. The benefit was
recorded as a reduction to goodwill. A reconciliation of the beginning and ending amount of
unrecognized tax benefits is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended |
|
|
December 31, |
|
|
2010 |
|
2009 |
|
2008 |
|
Balance at the beginning of the year |
|
$ |
|
|
|
$ |
|
|
|
$ |
1,727 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease in unrecognized tax
benefits from current period tax
position |
|
|
|
|
|
|
|
|
|
|
(1,727 |
) |
|
Balance at the end of the year |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
As of December 31, 2010, we believe that no current tax positions that have resulted in
unrecognized tax benefits will significantly increase or decrease within the next year.
As of December 31, 2010, we had unremitted earnings in our foreign subsidiaries. If these
unremitted earnings had been dividend to the U.S., the U.S. NOLs not subject to the limitations
96
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
mentioned above would be fully available to offset any incremental U.S. federal income tax.
Further, the foreign tax credits associated with the unremitted earnings would be sufficient to
offset any incremental U.S. tax liabilities associated with the dividend.
Note 11 Other Liabilities
Other liabilities included the following:
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2010 |
|
2009 |
|
Asset retirement obligations |
|
$ |
36,592 |
|
|
$ |
47,362 |
|
Long-term derivative liabilities |
|
|
27,810 |
|
|
|
38,050 |
|
Other |
|
|
525 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Other Liabilities |
|
$ |
64,927 |
|
|
$ |
85,412 |
|
|
Our asset retirement obligations relate to obligation of the plugging and abandonment of oil
and gas properties. 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. The following table provides a
rollforward of the asset retirement obligations for the year ended December 31, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
Year Ended |
|
|
December 31, |
|
|
2010 |
|
2009 |
|
Asset retirement obligations, beginning of year |
|
$ |
47,362 |
|
|
$ |
38,776 |
|
Increase due to revised estimates |
|
|
2,949 |
|
|
|
7,762 |
|
Accretion expense |
|
|
4,591 |
|
|
|
4,117 |
|
Impact of foreign currency exchange rate changes |
|
|
(2,397 |
) |
|
|
4,280 |
|
Payments |
|
|
(9,508 |
) |
|
|
(7,325 |
) |
Sale of assets |
|
|
|
|
|
|
(248 |
) |
|
Asset retirement obligations, end of year |
|
|
42,997 |
|
|
|
47,362 |
|
|
|
|
|
|
|
|
|
|
Less: current portion of asset retirement obligations |
|
|
(6,405 |
) |
|
|
|
|
|
Long-term asset retirement obligations |
|
$ |
36,592 |
|
|
$ |
47,362 |
|
|
97
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
Note 12 Equity
The activity in shares of our common and preferred stock during 2010, 2009 and 2008 included
the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2010 |
|
2009 |
|
2008 |
|
Common Stock: |
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at the beginning of the year |
|
|
18,803 |
|
|
|
18,368 |
|
|
|
18,144 |
|
Issuance of common stock |
|
|
4,638 |
|
|
|
|
|
|
|
|
|
Exercise of stock options |
|
|
23 |
|
|
|
24 |
|
|
|
|
|
Conversion of preferred stock |
|
|
572 |
|
|
|
|
|
|
|
|
|
Issuance of stock based compensation |
|
|
748 |
|
|
|
411 |
|
|
|
224 |
|
|
Outstanding at the end of the year |
|
|
24,784 |
|
|
|
18,803 |
|
|
|
18,368 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Series B Preferred Stock: |
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at the end of the year |
|
|
20 |
|
|
|
20 |
|
|
|
20 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Convertible Preferred Stock: |
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at the beginning of the year |
|
|
50 |
|
|
|
125 |
|
|
|
|
|
Conversion to common stock |
|
|
(5 |
) |
|
|
|
|
|
|
|
|
Redemptions |
|
|
|
|
|
|
(75 |
) |
|
|
|
|
Issuance of preferred stock |
|
|
|
|
|
|
|
|
|
|
125 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at the end of the year |
|
|
45 |
|
|
|
50 |
|
|
|
125 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Treasury Stock: |
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at the beginning of the year |
|
|
(72 |
) |
|
|
(47 |
) |
|
|
|
|
Purchase of treasury shares for stock vesting |
|
|
|
|
|
|
(25 |
) |
|
|
(47 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at the end of the year |
|
|
(72 |
) |
|
|
(72 |
) |
|
|
(47 |
) |
|
Common Stock
The Common Stock is $0.001 par value common stock, 64,285,714 shares authorized.
In October 2010, our Board of Directors authorized a one-for-seven share consolidation of our
common stock, in the form of a reverse stock split. This consolidation was effective at the
opening of trading on November 18, 2010. As a result of the share consolidation, every seven
98
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
shares of our common stock outstanding were automatically combined into one share of our
common stock. Each shareholder continues to hold the same percentage of our outstanding common
shares. The shares were rounded up to the next whole share for those holders who would have
otherwise received fractional shares. The share consolidation was intended to make our common
stock available to a broader range of investors and reposition the companys trading metrics.
On August 16, 2010, in connection with the issuance of the Senior Term Loan, we completed a
registered direct offering of common stock pursuant to a Common Stock Purchase Agreement with Cyan
to sell 1.3 million shares of our common stock, par value $0.001 per share, for aggregate net cash
consideration of approximately $10.1 million, after deducting expenses. The purchase price per
share was $7.91, the closing price of our common stock on the NYSE Amex on August 13, 2010. We
intend to use the net proceeds from this offering for general corporate purposes.
On February 4, 2010, we completed a private placement of our common stock pursuant to a Common
Stock Purchase Agreement with existing stockholders, certain directors and other third-party
investors, thereby selling 3.4 million shares of our common stock, for aggregate net cash
consideration of approximately $20.5 million. The purchase price per share was $6.30, the closing
price of our common stock on the NYSE Amex on February 3, 2010. The net proceeds from this private
placement were used to partially fund our 2010 capital budget.
In 2010, we issued inducement grants of 85,715 shares of our restricted common stock, upon
commencement of employment of one executive officer. In 2008, we issued inducement grants of
42,858 shares of our restricted common stock, and options to purchase 35,715 shares of our common
stock at an exercise price of $5.25 per share upon commencement of employment of one executive
officer.
Series C Convertible Preferred Stock
In 2006, we issued the Series C Preferred Stock. Dividends on the Series C Preferred Stock
are:
|
|
|
cumulative; |
|
|
|
|
compounded quarterly based on the original issue price; |
|
|
|
|
payable in cash or common stock, at 4.5% or 4.92%, respectively, since November 2009
and at 8.5% or 8.92%, respectively, in prior periods; and |
|
|
|
|
payable to the preferred stock investors prior to payment of any other dividend on any
other shares of our capital stock. |
The Series C Preferred Stock ranks senior to any of our other existing or future shares of capital
stock. Dividends will be paid to the preferred stock investors prior to payment of any other
dividend on any other shares of our capital stock. The Series C Preferred Stock also participates
on an as-converted basis with respect to any dividends paid on the common stock.
99
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
On November 17, 2009, we redeemed 60% of the outstanding shares of Series C Preferred Stock, for
face value of $75 million, and amended the terms of the remaining shares of Series C Preferred
Stock. The redemption price consisted of a $25 million cash payment and the issuance of $50
million of Subordinated Notes.
The redemption and modification of the Series C Preferred Stock required the modified Series C
Preferred Stock to be recorded at fair market value at the redemption date. The fair value of the
modified Series C Preferred Stock was greater than the carrying value by $11.5 million. This
excess of fair value over carrying value was recorded as a non-cash charge to preferred stock
dividends and increased the carrying value of the Series C Preferred Stock. As holders convert the
Series C Preferred Stock, the $11.5 million non-cash charge will be transferred to equity on a
ratio of shares converted to shares of Series C Preferred Stock outstanding.
In addition to the modification of the Series C Preferred Stock, we also recorded an embedded
derivative associated with the change in control features of the Series C Preferred Stock of $2.4
million. This embedded derivative was recorded in other liabilities and reduced the premium on the
Series C Preferred Stock at the date of issuance. At December 31, 2010 the fair market value of
this derivative was an asset of $0.3 million, reflecting a $2.3 million gain during 2010 that was
recorded in unrealized gains (losses) on derivatives.
The Series C Preferred Stock is convertible into common stock at any time at the option of the
preferred stock investors, at (i) a conversion price of $8.75 (the Conversion Price) and (ii) in
an amount of common stock equal to the quotient of the liquidation preference of $1,000 per share
plus accrued but unpaid dividends (the Liquidation Preference) divided by the Conversion Price.
In the November 2009 amendment, we amended terms of the Series C Preferred Stock to reduce the
annual dividend rate to 4.5% (from 8.5%), adjust the conversion price to $8.75 per share (from
$17.50) and remove certain anti-dilution provisions.
Issuance of dividends in the form of common stock are subject to the following equity conditions
(the Equity Conditions), which are waivable by two-thirds of the holders of the Series C
Preferred Stock: (i) such common stock is listed on the NYSE AMEX, the New York Stock Exchange or
the Nasdaq Stock Market, and not subject to any trading suspension; (ii) we are not then subject to
any bankruptcy event; and (iii) such common stock will be immediately re-saleable by the holders
pursuant to an effective registration statement and otherwise in compliance with all applicable
laws. If we have not maintained the effectiveness of the registration statement pursuant to the
registration rights section below, then the dividend rate on the Series C Preferred Stock will be
increased by the product of 2.5% (if the dividend is paid in cash) or 2.63% (if the dividend is
paid in stock) times the number of quarters (or portions thereof) in which the failure occurs or we
fail to cure such failure.
100
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
After the fourth anniversary of the initial issuance of the Series C Preferred Stock, we may redeem
all of the Series C Preferred Stock in exchange for a cash payment to the preferred stock investors
of an amount equal to 102% of the sum of the Liquidation Preference. If we call the Series C
Preferred Stock for redemption, the holders thereof will have the right to convert their shares
into a newly issued preferred stock identical in all respects to the Series C Preferred Stock
except that such newly issued preferred stock will not bear a dividend (the Alternate Preferred
Stock). We may not redeem the Convertible Preferred Stock if the Equity Conditions are not then
satisfied with respect to the common stock into which the Alternate Preferred Stock is convertible.
Upon the tenth anniversary of the initial issuance of the Series C Preferred Stock, we must redeem
all of the Series C Preferred Stock for an amount equal to the Liquidation Preference plus accrued
and unpaid dividends payable by us in cash or common stock at our election. Issuance by us of
common stock for such redemption is subject to the Equity Conditions and to the market value of the
outstanding shares of common stock immediately prior to such redemption equaling at least $500
million.
In the event of a change of control of Endeavour, we will be required to offer to redeem all of the
Series C Preferred Stock for the greater of: (i) the amount equal to which such holder would be
entitled to receive had the holder converted such Series C Preferred Stock into common stock; (ii)
115% of the sum of the Liquidation Preference plus accrued and unpaid dividends; and (iii) the
amount resulting in an internal rate of return to such holder of 15% from the date of issuance of
such Series C Preferred Stock through the date that Endeavour pays the redemption price for such
shares.
On January 29, 2010, we and the holders of our outstanding Series C Convertible Preferred Stock
corrected a technical oversight in the Subscription and Registration Rights Agreement for our
Series C Preferred Stock. The amendment aligns the number of common shares reserved for the
potential conversion of the Series C Preferred Stock to the terms of the Series C Convertible
Preferred Stock after our partial redemption in November 2009. On March 10, 2010, we also amended
the Certificate of Designation for the Series C Preferred Stock and the $50 million subordinated
notes issued to the holders of the Series C Preferred Stock to make certain technical changes that
align certain definitions and provisions relating to potential repurchases of securities by us.
In 2010, a combined 5,000 shares of our Series C Preferred Stock were converted into 0.6 million
shares of our common stock.
Series B Preferred Stock
In September 2002, we authorized and designated 500,000 shares of Preferred Stock, as Series B
Preferred Stock par value $.001 per share.
101
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
The Series B Preferred Stock is entitled to dividends of 8% of the original issuing price per share
per annum, which are cumulative prior to any dividends on the common stock and on parity with the
payment of any dividend or other distribution on any other series of preferred stock that has
similar characteristics. The holders of each share of Series B Preferred Stock are entitled to be
paid out of available funds prior to any distributions to holders of common stock in the amount of
$100.00 per outstanding share plus all accrued dividends. We may, upon approval of our Board,
redeem all or a portion of the outstanding shares of Series B preferred stock at a cost of the
liquidation preference and all accrued and unpaid dividends.
Note 13 Comprehensive Income (Loss)
The following summarizes the components of comprehensive loss:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2010 |
|
2009 |
|
2008 |
|
Net income (loss) |
|
$ |
56,531 |
|
|
$ |
(40,995 |
) |
|
$ |
56,490 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Related to derivative instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized gain |
|
|
|
|
|
|
|
|
|
|
428 |
|
Reclassification adjustment for gain realized in net
income (loss) above |
|
|
|
|
|
|
1,194 |
|
|
|
(770 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Related to marketable securities: |
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized loss |
|
|
|
|
|
|
|
|
|
|
(1 |
) |
Reclassification adjustment for loss realized in net
income (loss) above |
|
|
|
|
|
|
72 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net impact on comprehensive income (loss) |
|
|
|
|
|
|
1,266 |
|
|
|
(343 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income (loss) |
|
$ |
56,531 |
|
|
$ |
(39,729 |
) |
|
$ |
56,147 |
|
|
The components of accumulated other comprehensive income (loss) are:
102
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2010 |
|
2009 |
|
2008 |
|
Related to derivative instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
Balance at beginning of year |
|
$ |
|
|
|
$ |
(1,194 |
) |
|
$ |
(852 |
) |
Change during the year |
|
|
|
|
|
|
1,194 |
|
|
|
(342 |
) |
|
Balance at end of year |
|
|
|
|
|
|
|
|
|
|
(1,194 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Related to marketable securities: |
|
|
|
|
|
|
|
|
|
|
|
|
Balance at beginning of year |
|
|
|
|
|
|
(72 |
) |
|
|
(71 |
) |
Change during the year |
|
|
|
|
|
|
72 |
|
|
|
(1 |
) |
|
Balance at end of year |
|
|
|
|
|
|
|
|
|
|
(72 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive loss |
|
$ |
|
|
|
$ |
|
|
|
$ |
(1,266 |
) |
|
Note 14 Stock-Based Compensation Arrangements
We grant restricted stock and stock options to employees and directors as incentive
compensation. The restricted stock and options generally vest over three years. The vesting of
these shares and options is dependent upon the continued service of the grantees with Endeavour.
Upon the occurrence of a change in control, each outstanding share of restricted stock and stock
option will immediately vest.
The fair value of each option award is estimated on the date of grant using the Black-Scholes
option-pricing model. The following summarizes the weighted average of the assumptions used in the
option-pricing model and the method for determining the assumptions:
103
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31, |
|
|
|
|
2010 |
|
2009 |
|
2008 |
|
Method of Determining Assumptions |
|
Risk-free rate |
|
|
|
|
|
|
1.5 |
% |
|
|
3.1 |
% |
|
U.S. treasury yield curve in effect at the time of grant for the duration of estimated term |
Expected years until
exercise |
|
|
|
|
|
|
4.25 |
|
|
|
4.00 |
|
|
Historical data regarding option exercises and employee terminations |
Expected stock volatility |
|
|
|
|
|
|
56 |
% |
|
|
46 |
% |
|
Historical Endeavour volatility for the length of the expected term |
|
Dividend yield |
|
|
|
|
|
|
|
|
|
|
|
|
|
Historical |
|
At December 31, 2010, total compensation cost related to nonvested awards not yet recognized
was approximately $4.0 million and is expected to be recognized over a weighted average period of
less than two years. For the year ended December 31, 2010, we included approximately $0.9 million
of stock-based compensation in capitalized G&A in property and equipment.
Stock Options
Information relating to stock options, including notional stock options, is summarized as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
Weighted |
|
|
|
|
Number of |
|
Average |
|
Average |
|
|
|
|
Shares |
|
Exercise |
|
Contractual |
|
Aggregate |
|
|
Underlying |
|
Price per |
|
Life in |
|
Intrinsic |
|
|
Options |
|
Share |
|
Years |
|
Value |
|
Balance outstanding January 1, 2010 |
|
|
601 |
|
|
$ |
13.10 |
|
|
|
|
|
|
|
|
|
Exercised |
|
|
(23 |
) |
|
|
4.22 |
|
|
|
|
|
|
|
|
|
Forfeited |
|
|
(10 |
) |
|
|
11.37 |
|
|
|
|
|
|
|
|
|
Expired |
|
|
(104 |
) |
|
|
29.01 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance outstanding December 31, 2010 |
|
|
464 |
|
|
$ |
10.04 |
|
|
|
5.5 |
|
|
$ |
2,366 |
|
|
|
Currently exercisable December 31, 2010 |
|
|
338 |
|
|
$ |
11.79 |
|
|
|
5.0 |
|
|
$ |
1,301 |
|
|
We did not grant any options during 2010. The weighted average grant-date fair value of
options granted during 2009 and 2008 was $0.25 and $0.50, respectively.
104
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
Of options granted during 2009 and 2008, 0.2 million and 0.2 million options, respectively, were
granted pursuant to incentive plans which have been approved by our stockholders. All other stock
options have been granted pursuant to stock option plans that were not subject to stockholder
approval.
Information relating to stock options outstanding at December 31, 2010 is summarized as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options Outstanding |
|
|
|
|
|
Options Exercisable |
|
|
|
|
|
|
Weighted |
|
Weighted |
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Average |
|
Average |
|
|
|
|
|
Average |
|
|
Number of |
|
Remaining |
|
Exercise |
|
|
|
|
|
Exercise |
Range of Exercise |
|
Options |
|
Contractual |
|
Price Per |
|
Number |
|
Price Per |
Prices |
|
Outstanding |
|
Life |
|
Share |
|
Exercisable |
|
Share |
|
Less than $10.00 |
|
|
327 |
|
|
|
6.3 |
|
|
$ |
6.55 |
|
|
|
201 |
|
|
$ |
7.30 |
|
$10.00 - $20.00 |
|
|
91 |
|
|
|
5.5 |
|
|
|
15.10 |
|
|
|
91 |
|
|
|
15.10 |
|
Greater than $20.00 |
|
|
46 |
|
|
|
0.1 |
|
|
|
24.66 |
|
|
|
46 |
|
|
|
24.66 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
464 |
|
|
|
5.5 |
|
|
$ |
10.04 |
|
|
|
338 |
|
|
$ |
11.79 |
|
|
Restricted Stock
At December 31, 2010, our employees and directors held 0.8 million restricted shares of our
common stock that vest over the service period of up to three years. The restricted stock awards
were valued based on the closing price of our common stock on the measurement date, typically the
date of grant, and compensation expense is recorded on a straight-line basis over the restricted
share vesting period.
Status of the restricted shares as of December 31, 2010 and the changes during the year ended
December 31, 2010 are presented below:
105
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Average Grant |
|
|
|
|
|
|
Date Fair |
|
|
Number of |
|
Value per |
|
|
Shares |
|
Share |
|
Balance outstanding January 1, 2010 |
|
|
489 |
|
|
$ |
6.99 |
|
Granted |
|
|
784 |
|
|
|
7.90 |
|
Vested |
|
|
(422 |
) |
|
|
7.95 |
|
Forfeited |
|
|
(35 |
) |
|
|
7.28 |
|
|
|
|
|
|
|
|
|
|
|
Balance outstanding December 31, 2010 |
|
|
816 |
|
|
$ |
7.36 |
|
|
|
|
|
|
|
|
|
|
|
Total grant date fair value of shares vesting during the period |
|
$ |
3,353 |
|
|
|
|
|
|
Non-Cash stock-based compensation is recorded in G&A expenses or capitalized G&A as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended |
|
|
December 31, |
|
|
2010 |
|
2009 |
|
2008 |
|
G&A Expenses |
|
$ |
3,191 |
|
|
$ |
2,464 |
|
|
$ |
2,467 |
|
Capitalized G&A |
|
|
988 |
|
|
|
573 |
|
|
|
759 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total non-cash stock-based compensation |
|
$ |
4,179 |
|
|
$ |
3,037 |
|
|
$ |
3,226 |
|
|
Note 15 Earnings per Share
Basic income (loss) per common share is computed by dividing net income (loss) to common
stockholders by the weighted average number of common shares outstanding for the period. Diluted
income (loss) per share includes the effect of our outstanding stock options, warrants and shares
issuable pursuant to convertible debt, convertible preferred stock and certain stock incentive
plans under the treasury stock method, if including such instruments is dilutive.
106
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2010 |
|
2009 |
|
2008 |
|
Net income (loss) to common shareholders |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
54,304 |
|
|
$ |
(62,206 |
) |
|
$ |
45,681 |
|
Add Effect of: |
|
|
|
|
|
|
|
|
|
|
|
|
Preferred dividends |
|
|
2,070 |
|
|
|
|
|
|
|
10,625 |
|
|
Diluted |
|
$ |
56,374 |
|
|
$ |
(62,206 |
) |
|
$ |
56,306 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Number of Common
Shares Outstanding: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
23,252 |
|
|
|
18,613 |
|
|
|
18,330 |
|
Add Effect of: |
|
|
|
|
|
|
|
|
|
|
|
|
Stock compensation grants and warrants |
|
|
380 |
|
|
|
|
|
|
|
|
|
Preferred stock |
|
|
5,254 |
|
|
|
|
|
|
|
7,143 |
|
|
Diluted |
|
|
28,886 |
|
|
|
18,613 |
|
|
|
25,473 |
|
|
For each of the periods presented, shares associated with stock options, warrants, convertible
debt, convertible preferred stock and certain stock incentive plans are not included when their
inclusion would be antidilutive (i.e., reduce the net loss per share). The common shares
potentially issuable arising from these instruments excluded from weighted average diluted shares
outstanding consisted of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31, |
|
|
2010 |
|
2009 |
|
2008 |
|
Options, warrants and stock-based compensation |
|
|
|
|
|
|
273 |
|
|
|
|
|
Convertible debt |
|
|
5,691 |
|
|
|
5,329 |
|
|
|
4,675 |
|
Convertible preferred stock |
|
|
|
|
|
|
5,714 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common shares potentially issuable |
|
|
5,691 |
|
|
|
11,316 |
|
|
|
4,675 |
|
|
107
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
Note 16 Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
December 31, |
|
|
2010 |
|
2009 |
|
|
|
|
|
|
Carrying |
|
|
|
|
|
Carrying |
|
|
Fair Value |
|
Value |
|
Fair Value |
|
Value |
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative instruments |
|
$ |
2,320 |
|
|
$ |
2,320 |
|
|
$ |
3,208 |
|
|
$ |
3,208 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt |
|
|
360,844 |
|
|
|
323,706 |
|
|
|
219,959 |
|
|
|
223,385 |
|
Derivative instruments |
|
|
(27,810 |
) |
|
|
(27,810 |
) |
|
|
(44,866 |
) |
|
|
(44,866 |
) |
The carrying amounts reflected in the consolidated balance sheets for cash and equivalents,
short-term receivables and short-term payables approximate their fair value due to the short
maturity of the instruments. The fair values of commodity derivative instruments and interest rate
swaps were determined based upon quotes obtained from brokers. The fair values of long-term debt
were determined based upon quotes obtained from brokers for our senior notes, discounted cash flows
for our other debt. Book value approximates fair value for our Senior Bank Facility and as this
instrument bears interest at a market rate.
Note 17 Fair Value Measurements
We measure the fair value of financial assets and liabilities on a recurring basis, defining
fair value as the price that would be received to sell an asset or paid to transfer a liability in
an orderly transaction between market participants at the measurement date. The fair value is
based on assumptions that market participants would use when pricing an asset or liability,
including assumptions about risk and the risks inherent in valuation techniques and the inputs to
valuations. This includes not only the credit standing of counterparties involved and the impact
of credit enhancements but also the impact of our own nonperformance risk on our liabilities. Fair
value measurements are classified and disclosed in one of the following categories:
|
|
|
Level 1:
|
|
Fair value is based on actively-quoted market prices, if available. |
|
|
|
Level 2:
|
|
In the absence of actively-quoted market prices, we seek price information from external sources, including broker
quotes and industry publications. Substantially all of these inputs are observable in the marketplace during the
entire term of the instrument, can be derived from observable data, or supported by observable levels at which
transactions are executed in the marketplace. |
108
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
|
|
|
Level 3:
|
|
If valuations require inputs that are both significant to the fair value measurement
and less observable from objective sources, we must estimate prices based on available
historical and near-term future price information and certain statistical methods that reflect
our market assumptions. |
We apply fair value measurements to certain assets and liabilities including commodity and interest
rate derivative instruments, marketable securities and embedded derivatives relating to conversion
and change in control features in certain of our debt instruments. We seek to maximize the use of
observable inputs and minimize the use of unobservable inputs when measuring fair value.
Financial assets and liabilities are classified based on the lowest level of input that is
significant to the fair value measurement. The following table summarizes the valuation of our
investments and financial instruments by pricing levels as of December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quoted Market Prices |
|
Significant Other |
|
Significant |
|
|
|
|
in Active Markets |
|
Observable Inputs |
|
Unobservable Inputs |
|
Total |
|
|
Level 1 |
|
Level 2 |
|
Level 3 |
|
Fair Value |
|
Oil and gas derivative contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas puts |
|
$ |
|
|
|
$ |
1,213 |
|
|
$ |
792 |
|
|
$ |
2,005 |
|
Embedded derivatives |
|
|
|
|
|
|
|
|
|
|
(27,495 |
) |
|
|
(27,495 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative liabilities |
|
$ |
|
|
|
$ |
1,213 |
|
|
$ |
(26,703 |
) |
|
$ |
(25,490 |
) |
|
Our commodity and interest rate derivative contracts were measured based on quotes from our
counterparties, which are major financial institutions or commodities trading institutions. Such
quotes have been derived using models that consider various inputs including current market and
contractual prices for the underlying instruments, quoted forward prices for natural gas and crude
oil, volatility factors and interest rates, such as a LIBOR curve for a similar length of time as
the derivative contract term. The inputs for the fair value models for our swaps and Brent oil
collars and puts were all observable market data and these instruments have been classified as
Level 2.
Although we utilized the same option pricing models to assess the reasonableness of the fair values
of our gas collars and puts, an active futures market does not exist for our U.K. gas derivatives.
We based the inputs to the option models for our U.K. gas derivatives on observable market data in
other markets to verify the reasonableness of the counterparty quotes. These U.K. gas derivatives
are classified as Level 3.
The following is a reconciliation of changes in fair value of net derivative assets and liabilities
classified as Level 3:
109
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
|
|
|
|
|
|
|
|
|
|
|
Year Ended |
|
|
December 31, |
|
|
2010 |
|
2009 |
|
Balance at beginning of period |
|
$ |
(28,843 |
) |
|
$ |
(12,057 |
) |
Total gains or losses (realized/unrealized) |
|
|
|
|
|
|
|
|
Included in earnings |
|
|
1,348 |
|
|
|
(14,390 |
) |
Purchases, issuance and settlements |
|
|
792 |
|
|
|
(2,396 |
) |
|
Balance at end of period |
|
$ |
(26,703 |
) |
|
$ |
(28,843 |
) |
|
|
|
|
|
|
|
|
|
|
Changes in unrealized gains (losses) relating to derivatives assets and liabilities
still held at December 31, 2010 |
|
$ |
1,348 |
|
|
$ |
(9,713 |
) |
|
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Certain assets and liabilities are reported at fair value on a nonrecurring basis in our
consolidated balance sheets. The following methods and assumptions were used to estimate the fair
values:
Goodwill Goodwill is tested annually at year end for impairment. 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. Significant Level 3 inputs may be used
in the determination of the fair value of the reporting unit, including present values of expected
cash flows from operations.
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.
Note 18 Derivative Instruments
As discussed in Note 2 Accounting Policies, we have oil and gas commodity derivatives and
embedded derivatives related to debt instruments. The fair market value of these derivative
instruments is included in our balance sheet as follows:
110
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2010 |
|
2009 |
|
Derivatives not designated as hedges: |
|
|
|
|
|
|
|
|
Oil and gas commodity derivatives: |
|
|
|
|
|
|
|
|
Assets: |
|
|
|
|
|
|
|
|
Prepaid expenses and other current assets |
|
$ |
709 |
|
|
$ |
2,890 |
|
Other assets long term |
|
|
1,296 |
|
|
|
318 |
|
Liabilities: |
|
|
|
|
|
|
|
|
Accrued expenses and other |
|
|
|
|
|
|
(6,817 |
) |
Other liabilities long-term |
|
|
|
|
|
|
(9,207 |
) |
|
|
|
$ |
2,005 |
|
|
$ |
(12,816 |
) |
|
|
|
|
|
|
|
|
|
Embedded derivatives related to debt instrument: |
|
|
|
|
|
|
|
|
Assets: |
|
|
|
|
|
|
|
|
Other assets long term |
|
$ |
315 |
|
|
$ |
|
|
Liabilities: |
|
|
|
|
|
|
|
|
Other liabilities long-term |
|
|
(27,810 |
) |
|
|
(28,843 |
) |
|
If all counterparties failed to perform, our maximum loss would be $2.0 million as of December
31, 2010.
The effect of the derivatives not designated as hedges on our results of operations was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2010 |
|
2009 |
|
2008 |
|
Derivatives not designated as hedges: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas commodity derivatives |
|
|
|
|
|
|
|
|
|
|
|
|
Realized gains (losses) |
|
$ |
(11,753 |
) |
|
$ |
35,422 |
|
|
$ |
(28,578 |
) |
Unrealized gains (losses) |
|
|
10,943 |
|
|
|
(43,791 |
) |
|
|
77,846 |
|
|
|
|
|
(810 |
) |
|
|
(8,369 |
) |
|
|
49,268 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Embedded derivatives related to debt instrument |
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized gains (losses) |
|
$ |
1,348 |
|
|
$ |
(11,807 |
) |
|
$ |
(1,180 |
) |
|
The effect of derivatives designated as cash flow hedges on our results of operations and
other comprehensive income was as follows:
111
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
Location of |
|
|
|
|
|
|
|
|
Reclassification |
|
|
|
|
into Income |
|
2010 |
|
2009 |
|
2008 |
|
Interest rate swap |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Gain) loss recognized in other
comprehensive income, net of tax |
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
428 |
|
(Gain) loss reclassified from
accumulated other comprehensive
income into income |
|
Interest expense |
|
|
|
|
|
|
1,194 |
|
|
|
(770 |
) |
|
We did not exclude any component of the hedging instruments gain or loss when assessing
effectiveness. The ineffective portion of the hedges is not material for the periods presented and
is included in other income (expense).
As of December 31, 2010, our outstanding commodity derivatives covered approximately 184 Mbbl of
oil and 173 MMcf of gas cumulative through 2012 and consist of fixed price puts.
During 2007, we entered into an interest rate swap with for a notional amount of $37.5 million
whereby we paid a fixed rate of 5.05% and received three-month LIBOR through November 2009.
Note 19 Supplementary Cash Flow Disclosures
Cash paid during the period for interest and income taxes was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2010 |
|
2009 |
|
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest paid |
|
$ |
18,668 |
|
|
$ |
7,074 |
|
|
$ |
15,966 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income taxes paid (refunded) |
|
$ |
(172 |
) |
|
$ |
4,738 |
|
|
$ |
20,088 |
|
|
Non-Cash Investing and Financing Transactions
As discussed in Note 12, in 2010, a combined 5,000 shares of our Series C Preferred Stock were
converted into 0.6 million shares of our common stock. In addition, during 2009, we redeemed 60%
of the outstanding shares of Series C Preferred Stock, for face value of $75 million with a $25
million cash payment and the issuance of $50 million Subordinated Notes.
112
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
We recorded $11.4 million in preferred stock dividends in 2009 for a non-cash valuation under
fair value accounting relating to the redemption and modification of our Series C Preferred Stock.
In 2010, 2009 and 2008, we recorded $8.8 million, $5.5 million and $4.5 million, respectively, in
non-cash interest expense that was added to the principal balance of the 11.5% Convertible Bonds,
the $50 million Subordinated Notes and the Senior Term Loan.
Note 20 Commitments and Contingencies
General
The oil and gas industry is subject to regulation by federal, state and local authorities. In
particular, oil and gas production operations and economics are affected by environmental
protection statutes, tax statutes and other laws and regulations relating to the petroleum
industry. We believe we are in compliance with all federal, state and local laws, regulations
applicable to Endeavour and its properties and operations, the violation of which would have a
material adverse effect on us or our financial condition.
Operating Leases
We have leases for office space and equipment with lease payments of $0.8 million, $0.2
million and $0.1 million for the years ended December 31, 2011, 2012 and 2013, respectively.
Rig Commitments
We have previously disclosed a potential commitment on a drilling rig in our North Sea
operations. We are in dispute with the rig operator in relation to this potential commitment and
have also raised potential counterclaims. We will defend our position vigorously, but there can be
no certainty that we will resolve this matter favorably.
Participation Agreement
In April 2009, we executed an agreement with Caza Petroleum Inc., a subsidiary of Caza Oil and
Gas, Inc., (Caza) to participate in a jointly established exploration and development program
covering Cazas onshore acreage position and opportunity portfolio in the United States. We had
the option, but not the obligation, to participate in the acquisition, exploration and appraisal
activities of selected assets. Caza provided economic and engineering analysis on projects
113
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
submitted for our selection. We received 75% of Cazas interest in exchange for $250,000 per
month and payment of our share of all external costs on any projects we selected. We elected to
terminate the agreement effective April 2010.
Note 21 Segment and Geographic Information
We have determined we have one reportable operating segment being the acquisition, exploration
and development of oil and gas properties. Our operations are conducted in geographic areas as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
2009 |
|
2008 |
|
|
|
|
|
|
Long- |
|
|
|
|
|
Long- |
|
|
|
|
|
Long- |
|
|
|
|
|
|
lived |
|
|
|
|
|
lived |
|
|
|
|
|
lived |
|
|
Revenue |
|
Assets |
|
Revenue |
|
Assets |
|
Revenue |
|
Assets |
|
United States |
|
$ |
11,174 |
|
|
$ |
115,114 |
|
|
$ |
1,627 |
|
|
$ |
46,172 |
|
|
$ |
|
|
|
$ |
12,125 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United Kingdom |
|
|
60,501 |
|
|
|
486,467 |
|
|
|
60,666 |
|
|
|
436,016 |
|
|
|
170,781 |
|
|
|
441,195 |
|
Other |
|
|
|
|
|
|
877 |
|
|
|
|
|
|
|
1,607 |
|
|
|
|
|
|
|
2,140 |
|
|
Continuing Operations |
|
|
71,675 |
|
|
|
602,458 |
|
|
|
62,293 |
|
|
|
483,795 |
|
|
|
170,781 |
|
|
|
455,460 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discontinued
operations
Norway |
|
|
|
|
|
|
|
|
|
|
17,550 |
|
|
|
|
|
|
|
89,660 |
|
|
|
148,605 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
71,675 |
|
|
$ |
602,458 |
|
|
$ |
79,843 |
|
|
$ |
483,795 |
|
|
$ |
260,441 |
|
|
$ |
604,065 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total International |
|
$ |
60,501 |
|
|
$ |
487,344 |
|
|
$ |
78,216 |
|
|
$ |
437,623 |
|
|
$ |
260,441 |
|
|
$ |
591,940 |
|
|
114
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
Note 22 Quarterly Financial Data (Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second |
|
Third |
|
Fourth |
|
|
First Quarter |
|
Quarter |
|
Quarter |
|
Quarter |
|
|
|
2010
|
Revenues from continuing operations |
|
$ |
13,721 |
|
|
$ |
21,532 |
|
|
$ |
19,849 |
|
|
$ |
16,573 |
|
Operating expenses from continuing operations |
|
|
20,625 |
|
|
|
15,582 |
|
|
|
16,529 |
|
|
|
17,613 |
|
Operating profit (loss) from continuing operations |
|
|
(6,904 |
) |
|
|
5,950 |
|
|
|
3,320 |
|
|
|
(1,040 |
) |
Net income (loss) to common stockholders |
|
|
(15,779 |
) |
|
|
58 |
|
|
|
(12,238 |
) |
|
|
82,263 |
|
Net income (loss) per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
(0.11 |
) |
|
|
|
|
|
|
(0.07 |
) |
|
|
3.34 |
|
Diluted |
|
|
(0.11 |
) |
|
|
|
|
|
|
(0.07 |
) |
|
|
2.37 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
Revenues from continuing operations |
|
$ |
16,338 |
|
|
$ |
18,082 |
|
|
$ |
7,759 |
|
|
$ |
20,113 |
|
Operating expenses from continuing operations |
|
|
50,743 |
|
|
|
17,614 |
|
|
|
13,613 |
|
|
|
30,722 |
|
Operating profit (loss) from continuing operations |
|
|
(34,405 |
) |
|
|
468 |
|
|
|
(5,854 |
) |
|
|
(10,609 |
) |
Net income (loss) to common stockholders |
|
|
(19,532 |
) |
|
|
7,124 |
|
|
|
(7,179 |
) |
|
|
(42,618 |
) |
Net income (loss) from
continuing operations per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
(0.15 |
) |
|
|
(0.31 |
) |
|
|
0.06 |
|
|
|
0.33 |
|
Diluted |
|
|
(0.15 |
) |
|
|
(0.31 |
) |
|
|
0.06 |
|
|
|
0.33 |
|
Net income (loss) from
discontinued operations per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
|
|
|
|
0.36 |
|
|
|
|
|
|
|
|
|
Diluted |
|
|
|
|
|
|
0.36 |
|
|
|
|
|
|
|
|
|
Note 23 Subsequent Events
On February 6, 2011, we amended our Senior Term Loan to increase the security reserved for
potential letters of credit from $25 million to $35 million. Upon receipt of sufficient third
party financing, this increase in the security amount should
allow us to release the $32 million of
restricted cash that currently serves as collateral for existing letters of credit with an
alternative letter of credit provider.
On February 23, 2011, we closed on our previously announced acquisition of an additional 20%
working interest in the Bacchus development for approximately $9.2 million at closing and $6.2
million three months after first oil. In addition, we paid capital costs previously incurred by
the seller of $9.4 million.
115
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
Note 24 Supplemental Oil and Gas Disclosures (Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
Capitalized Costs Relating to Oil and Gas Producing Activities |
|
|
United |
|
United |
|
|
|
|
Kingdom |
|
States |
|
Total |
|
December 31, 2010: |
|
|
|
|
|
|
|
|
|
|
|
|
Proved |
|
$ |
346,915 |
|
|
$ |
42,659 |
|
|
$ |
389,574 |
|
Unproved |
|
|
85,019 |
|
|
|
76,412 |
|
|
|
161,431 |
|
|
Total capitalized costs |
|
|
431,934 |
|
|
|
119,071 |
|
|
|
551,005 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated depreciation, depletion and amortization |
|
|
(182,158 |
) |
|
|
(6,058 |
) |
|
|
(188,216 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net capitalized costs |
|
$ |
249,776 |
|
|
$ |
113,013 |
|
|
$ |
362,789 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009: |
|
|
|
|
|
|
|
|
|
|
|
|
Proved |
|
$ |
266,893 |
|
|
$ |
8,385 |
|
|
$ |
275,278 |
|
Unproved |
|
|
127,736 |
|
|
|
26,817 |
|
|
|
154,553 |
|
|
Total capitalized costs |
|
|
394,629 |
|
|
|
35,202 |
|
|
|
429,831 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated depreciation, depletion and amortization |
|
|
(164,703 |
) |
|
|
(810 |
) |
|
|
(165,513 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net capitalized costs |
|
$ |
229,926 |
|
|
$ |
34,392 |
|
|
$ |
264,318 |
|
|
116
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
Discontinued |
|
|
|
|
United |
|
United |
|
|
|
|
|
Continuing |
|
Operations |
|
|
|
|
Kingdom |
|
States |
|
Other |
|
Operations |
|
Norway (1) |
|
Total |
|
Year Ended December 31, 2010: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition costs: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved |
|
$ |
|
|
|
$ |
2,386 |
|
|
$ |
|
|
|
$ |
2,386 |
|
|
$ |
|
|
|
$ |
2,386 |
|
Unproved |
|
|
1,184 |
|
|
|
40,155 |
|
|
|
|
|
|
|
41,339 |
|
|
|
|
|
|
|
41,339 |
|
Exploration costs |
|
|
50,328 |
|
|
|
32,027 |
|
|
|
|
|
|
|
82,355 |
|
|
|
|
|
|
|
82,355 |
|
Development costs |
|
|
22,047 |
|
|
|
1,884 |
|
|
|
|
|
|
|
23,931 |
|
|
|
|
|
|
|
23,931 |
|
|
|
Total costs incurred |
|
$ |
73,559 |
|
|
$ |
76,452 |
|
|
$ |
|
|
|
$ |
150,011 |
|
|
$ |
|
|
|
$ |
150,011 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2009: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition costs: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved |
|
$ |
7,589 |
|
|
$ |
8,999 |
|
|
$ |
|
|
|
$ |
16,588 |
|
|
$ |
|
|
|
$ |
16,588 |
|
Unproved |
|
|
1,450 |
|
|
|
14,091 |
|
|
|
23 |
|
|
|
15,564 |
|
|
|
|
|
|
|
15,564 |
|
Exploration costs |
|
|
49,937 |
|
|
|
17,757 |
|
|
|
(382 |
) |
|
|
67,312 |
|
|
|
4,776 |
|
|
|
72,088 |
|
Development costs |
|
|
11,443 |
|
|
|
|
|
|
|
|
|
|
|
11,443 |
|
|
|
5,067 |
|
|
|
16,510 |
|
|
|
Total costs incurred |
|
$ |
70,419 |
|
|
$ |
40,847 |
|
|
$ |
(359 |
) |
|
$ |
110,907 |
|
|
$ |
9,843 |
|
|
$ |
120,750 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2008: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition costs: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved |
|
$ |
1,178 |
|
|
$ |
971 |
|
|
$ |
27 |
|
|
$ |
2,176 |
|
|
$ |
|
|
|
$ |
2,176 |
|
Exploration costs |
|
|
34,641 |
|
|
|
5,515 |
|
|
|
(62 |
) |
|
|
40,094 |
|
|
|
22,796 |
|
|
|
62,890 |
|
Development costs |
|
|
16,752 |
|
|
|
19 |
|
|
|
|
|
|
|
16,771 |
|
|
|
8,808 |
|
|
|
25,579 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs incurred |
|
$ |
52,571 |
|
|
$ |
6,505 |
|
|
$ |
(35 |
) |
|
$ |
59,041 |
|
|
$ |
31,604 |
|
|
$ |
90,645 |
|
|
117
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of Operations for Oil and Gas Producing Activities |
|
|
|
|
|
|
|
|
|
|
Total |
|
Discontinued |
|
|
|
|
United |
|
United |
|
Continuing |
|
Operations |
|
|
|
|
Kingdom |
|
States |
|
Operations |
|
Norway (1) |
|
Total |
|
Year Ended December 31, 2010: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
60,501 |
|
|
$ |
11,174 |
|
|
$ |
71,675 |
|
|
$ |
|
|
|
$ |
71,675 |
|
Production expenses |
|
|
11,086 |
|
|
|
4,261 |
|
|
|
15,347 |
|
|
|
|
|
|
|
15,347 |
|
DD&A |
|
|
22,020 |
|
|
|
5,273 |
|
|
|
27,293 |
|
|
|
|
|
|
|
27,293 |
|
Impairment of oil and
gas properties |
|
|
|
|
|
|
7,692 |
|
|
|
7,692 |
|
|
|
|
|
|
|
7,692 |
|
Income tax expense (benefit) |
|
|
13,698 |
|
|
|
(2,118 |
) |
|
|
11,580 |
|
|
|
|
|
|
|
11,580 |
|
|
|
Results of activities |
|
$ |
13,697 |
|
|
$ |
(3,934 |
) |
|
$ |
9,763 |
|
|
$ |
|
|
|
$ |
9,763 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2009: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
60,666 |
|
|
$ |
1,627 |
|
|
$ |
62,293 |
|
|
$ |
17,550 |
|
|
$ |
79,843 |
|
Production expenses |
|
|
16,911 |
|
|
|
865 |
|
|
|
17,776 |
|
|
|
5,536 |
|
|
|
23,312 |
|
DD&A |
|
|
31,915 |
|
|
|
817 |
|
|
|
32,732 |
|
|
|
4,595 |
|
|
|
37,327 |
|
Impairment of oil and
gas properties |
|
|
31,332 |
|
|
|
12,597 |
|
|
|
43,929 |
|
|
|
|
|
|
|
43,929 |
|
Income tax expense (benefit) |
|
|
(9,746 |
) |
|
|
(4,428 |
) |
|
|
(14,174 |
) |
|
|
5,787 |
|
|
|
(8,387 |
) |
|
|
Results of activities |
|
$ |
(9,746 |
) |
|
$ |
(8,224 |
) |
|
$ |
(17,970 |
) |
|
$ |
1,632 |
|
|
$ |
(16,338 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2008: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
170,781 |
|
|
$ |
|
|
|
$ |
170,781 |
|
|
$ |
89,660 |
|
|
$ |
260,441 |
|
Production expenses |
|
|
31,489 |
|
|
|
828 |
|
|
|
32,317 |
|
|
|
14,259 |
|
|
|
46,576 |
|
DD&A |
|
|
65,764 |
|
|
|
|
|
|
|
65,764 |
|
|
|
14,078 |
|
|
|
79,842 |
|
Impairment of oil and
gas properties |
|
|
36,970 |
|
|
|
|
|
|
|
36,970 |
|
|
|
|
|
|
|
36,970 |
|
Income tax expense (benefit) |
|
|
18,279 |
|
|
|
(290 |
) |
|
|
17,989 |
|
|
|
47,832 |
|
|
|
65,821 |
|
|
|
Results of activities |
|
$ |
18,279 |
|
|
$ |
(538 |
) |
|
$ |
17,741 |
|
|
$ |
13,491 |
|
|
$ |
31,232 |
|
|
|
|
|
(1) |
|
We completed the divestiture of our Norwegian subsidiary on May 14,
2009. The results of operations and financial position of this subsidiary are classified
as discontinued operations for all periods presented. |
118
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
Oil and Gas Reserves
Proved reserves are estimated quantities of oil, gas and natural gas liquids that geological
and engineering data demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions. Proved developed reserves are
proved reserves that can reasonably be expected to be recovered through existing wells with
existing equipment and operating methods. The reserve volumes presented are estimates only and
should not be construed as being exact quantities. These reserves may or may not be recovered and
may increase or decrease as a result of our future operations and changes in economic conditions.
During 2010 and 2009, our oil and gas reserves were audited by independent reserve engineers. Our
oil and gas reserves were prepared by independent reserve engineers at December 31, 2008.
In the fourth quarter of 2009, we adopted revised oil and gas reserve estimation and disclosure
requirements. The primary impact of the new disclosures is to conform the definition of proved
reserves to the SEC Modernization of Oil and Gas Reporting rules, which were issued by the SEC at
the end of 2008. The accounting standards update revised the definition of proved oil and gas
reserves to require that the average, first-day-of-the-month price during the 12-month period
before the end of the year rather than the year-end price, must be used when estimating whether
reserve quantities are economical to produce. This same 12-month average price is also used in
calculating the aggregate amount of (and changes in) future cash inflows related to the
standardized measure of discounted future net cash flows. The rules also allow for the use of
reliable technology to estimate proved oil and gas reserves if those technologies have been
demonstrated to result in reliable conclusions about reserve volumes. The unaudited supplemental
information on oil and gas exploration and production activities for 2010 and 2009 have been
presented in accordance with the new reserve estimation and disclosure rules, which may not be
applied retrospectively. The 2008 data is presented in accordance with FASB oil and gas disclosure
requirements effective during those periods.
119
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
Discontinued |
|
|
|
|
|
|
United |
|
|
United |
|
|
Continuing |
|
|
Operations - |
|
|
|
|
|
|
Kingdom |
|
|
States |
|
|
Operations |
|
|
Norway (1) |
|
|
Total |
|
|
Proved Oil Reserves (MBbls): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved reserves at January 1, 2008 |
|
|
3,284 |
|
|
|
|
|
|
|
3,284 |
|
|
|
2,056 |
|
|
|
5,340 |
|
Production |
|
|
(1,032 |
) |
|
|
|
|
|
|
(1,032 |
) |
|
|
(726 |
) |
|
|
(1,758 |
) |
Extensions and discoveries |
|
|
522 |
|
|
|
18 |
|
|
|
540 |
|
|
|
121 |
|
|
|
661 |
|
Revisions of previous estimates |
|
|
(643 |
) |
|
|
|
|
|
|
(643 |
) |
|
|
(45 |
) |
|
|
(688 |
) |
|
Proved reserves at December 31, 2008 |
|
|
2,131 |
|
|
|
18 |
|
|
|
2,149 |
|
|
|
1,406 |
|
|
|
3,555 |
|
Production |
|
|
(690 |
) |
|
|
(4 |
) |
|
|
(694 |
) |
|
|
(310 |
) |
|
|
(1,004 |
) |
Purchases of reserves |
|
|
|
|
|
|
2 |
|
|
|
2 |
|
|
|
|
|
|
|
2 |
|
Sales of reserves in place |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,107 |
) |
|
|
(1,107 |
) |
Extensions and discoveries |
|
|
1,209 |
|
|
|
3 |
|
|
|
1,212 |
|
|
|
|
|
|
|
1,212 |
|
Revisions of previous estimates |
|
|
698 |
|
|
|
(1 |
) |
|
|
697 |
|
|
|
11 |
|
|
|
708 |
|
|
Proved reserves at December 31, 2009 |
|
|
3,348 |
|
|
|
18 |
|
|
|
3,366 |
|
|
|
|
|
|
|
3,366 |
|
Production |
|
|
(545 |
) |
|
|
(6 |
) |
|
|
(551 |
) |
|
|
|
|
|
|
(551 |
) |
Extensions and discoveries |
|
|
457 |
|
|
|
34 |
|
|
|
491 |
|
|
|
|
|
|
|
491 |
|
Revisions of previous estimates |
|
|
404 |
|
|
|
13 |
|
|
|
417 |
|
|
|
|
|
|
|
417 |
|
|
Proved reserves at December 31,
2010 |
|
|
3,664 |
|
|
|
59 |
|
|
|
3,723 |
|
|
|
|
|
|
|
3,723 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Oil Reserves (MBbls): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2008 |
|
|
1,468 |
|
|
|
7 |
|
|
|
1,475 |
|
|
|
1,302 |
|
|
|
2,777 |
|
|
At December 31, 2009 |
|
|
1,381 |
|
|
|
8 |
|
|
|
1,389 |
|
|
|
|
|
|
|
1,389 |
|
|
At December 31, 2010 |
|
|
1,240 |
|
|
|
14 |
|
|
|
1,254 |
|
|
|
|
|
|
|
1,254 |
|
|
120
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
Discontinued |
|
|
|
|
|
|
United |
|
|
United |
|
|
Continuing |
|
|
Operations |
|
|
|
|
|
|
Kingdom |
|
|
States |
|
|
Operations |
|
|
Norway(1) |
|
|
Total |
|
|
Proved Gas Reserves (MMcf): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved reserves at January 1, 2008 |
|
|
11,812 |
|
|
|
|
|
|
|
11,812 |
|
|
|
8,434 |
|
|
|
20,246 |
|
Production |
|
|
(6,532 |
) |
|
|
|
|
|
|
(6,532 |
) |
|
|
(2,322 |
) |
|
|
(8,854 |
) |
Extensions and discoveries |
|
|
20,370 |
|
|
|
690 |
|
|
|
21,060 |
|
|
|
52 |
|
|
|
21,112 |
|
Revisions of previous estimates |
|
|
1,480 |
|
|
|
|
|
|
|
1,480 |
|
|
|
(1,187 |
) |
|
|
293 |
|
|
Proved reserves at December 31, 2008 |
|
|
27,130 |
|
|
|
690 |
|
|
|
27,820 |
|
|
|
4,977 |
|
|
|
32,797 |
|
Production |
|
|
(3,743 |
) |
|
|
(320 |
) |
|
|
(4,063 |
) |
|
|
(686 |
) |
|
|
(4,749 |
) |
Purchases of reserves |
|
|
|
|
|
|
10,037 |
|
|
|
10,037 |
|
|
|
|
|
|
|
10,037 |
|
Sales of reserves in place |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,241 |
) |
|
|
(4,241 |
) |
Extensions and discoveries |
|
|
52,895 |
|
|
|
6 |
|
|
|
52,901 |
|
|
|
|
|
|
|
52,901 |
|
Revisions of previous estimates |
|
|
2,034 |
|
|
|
371 |
|
|
|
2,405 |
|
|
|
(50 |
) |
|
|
2,355 |
|
|
Proved reserves at December 31, 2009 |
|
|
78,316 |
|
|
|
10,784 |
|
|
|
89,100 |
|
|
|
|
|
|
|
89,100 |
|
Production |
|
|
(3,071 |
) |
|
|
(2,636 |
) |
|
|
(5,707 |
) |
|
|
|
|
|
|
(5,707 |
) |
Purchases of reserves |
|
|
|
|
|
|
2,657 |
|
|
|
2,657 |
|
|
|
|
|
|
|
2,657 |
|
Sales of reserves in place |
|
|
(51,522 |
) |
|
|
|
|
|
|
(51,522 |
) |
|
|
|
|
|
|
(51,522 |
) |
Extensions and discoveries |
|
|
26,692 |
|
|
|
24,181 |
|
|
|
50,873 |
|
|
|
|
|
|
|
50,873 |
|
Revisions of previous estimates |
|
|
5,762 |
|
|
|
(3,209 |
) |
|
|
2,553 |
|
|
|
|
|
|
|
2,553 |
|
|
Proved reserves at December 31, 2010 |
|
|
56,177 |
|
|
|
31,777 |
|
|
|
87,954 |
|
|
|
|
|
|
|
87,954 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Gas Reserves (MMcf): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2008 |
|
|
6,761 |
|
|
|
234 |
|
|
|
6,995 |
|
|
|
4,917 |
|
|
|
11,912 |
|
|
At December 31, 2009 |
|
|
4,329 |
|
|
|
4,707 |
|
|
|
9,036 |
|
|
|
|
|
|
|
9,036 |
|
|
At December 31, 2010 |
|
|
555 |
|
|
|
13,281 |
|
|
|
13,836 |
|
|
|
|
|
|
|
13,836 |
|
|
121
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
Discontinued |
|
|
|
|
|
|
United |
|
|
United |
|
|
Continuing |
|
|
Operations |
|
|
|
|
|
|
Kingdom |
|
|
States |
|
|
Operations |
|
|
Norway |
|
|
Total |
|
|
Proved Reserves (MBOE): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved reserves at December 31, 2007 |
|
|
5,252 |
|
|
|
|
|
|
|
5,252 |
|
|
|
3,461 |
|
|
|
8,713 |
|
Extensions and discoveries |
|
|
3,917 |
|
|
|
133 |
|
|
|
4,050 |
|
|
|
130 |
|
|
|
4,180 |
|
Production |
|
|
(2,121 |
) |
|
|
|
|
|
|
(2,121 |
) |
|
|
(1,113 |
) |
|
|
(3,234 |
) |
Revisions of previous estimates |
|
|
(395 |
) |
|
|
|
|
|
|
(395 |
) |
|
|
(242 |
) |
|
|
(637 |
) |
|
Proved reserves at December 31, 2008 |
|
|
6,653 |
|
|
|
133 |
|
|
|
6,786 |
|
|
|
2,236 |
|
|
|
9,022 |
|
Production |
|
|
(1,314 |
) |
|
|
(57 |
) |
|
|
(1,371 |
) |
|
|
(424 |
) |
|
|
(1,795 |
) |
Extensions and discoveries |
|
|
10,025 |
|
|
|
4 |
|
|
|
10,029 |
|
|
|
|
|
|
|
10,029 |
|
Purchase of proved reserves, in place |
|
|
|
|
|
|
1,675 |
|
|
|
1,675 |
|
|
|
|
|
|
|
1,675 |
|
Sales of reserves |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,815 |
) |
|
|
(1,815 |
) |
Revisions of previous estimates |
|
|
1,037 |
|
|
|
60 |
|
|
|
1,097 |
|
|
|
3 |
|
|
|
1,100 |
|
|
Proved reserves at December 31, 2009 |
|
|
16,401 |
|
|
|
1,815 |
|
|
|
18,216 |
|
|
|
|
|
|
|
18,216 |
|
Production |
|
|
(1,057 |
) |
|
|
(445 |
) |
|
|
(1,502 |
) |
|
|
|
|
|
|
(1,502 |
) |
Extensions and discoveries |
|
|
4,906 |
|
|
|
4,064 |
|
|
|
8,970 |
|
|
|
|
|
|
|
8,970 |
|
Purchase of proved reserves, in place |
|
|
|
|
|
|
443 |
|
|
|
443 |
|
|
|
|
|
|
|
443 |
|
Sales of reserves |
|
|
(8,587 |
) |
|
|
|
|
|
|
(8,587 |
) |
|
|
|
|
|
|
(8,587 |
) |
Revisions of previous estimates |
|
|
1,364 |
|
|
|
(522 |
) |
|
|
842 |
|
|
|
|
|
|
|
842 |
|
|
Proved reserves at December 31, 2010 |
|
|
13,027 |
|
|
|
5,355 |
|
|
|
18,382 |
|
|
|
|
|
|
|
18,382 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Reserves (MBOE): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2008 |
|
|
2,595 |
|
|
|
46 |
|
|
|
2,641 |
|
|
|
2,122 |
|
|
|
4,763 |
|
|
At December 31, 2009 |
|
|
2,103 |
|
|
|
792 |
|
|
|
2,895 |
|
|
|
|
|
|
|
2,895 |
|
|
At December 31, 2010 |
|
|
1,333 |
|
|
|
2,227 |
|
|
|
3,560 |
|
|
|
|
|
|
|
3,560 |
|
|
Standardized Measure of Discounted Future Net Cash Flows
Future cash inflows and future production and development costs are determined by applying
average 12-month pricing for 2010 and 2009 and year-end prices for 2008 and year-end costs to the
estimated quantities of oil and gas to be produced. Oil, gas and condensate prices are
escalated only for fixed and determinable amounts under provisions in some contracts.
Estimated future income taxes are computed using current statutory income tax rates where
production occurs. The resulting future net cash flows are reduced to present value amounts by
applying a 10% annual discount factor.
At December 31, 2010 and 2009, the prices used to determine the estimates of future cash inflows
were as follows:
122
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
Estimated future cash inflows are reduced by estimated future development, production, abandonment
and dismantlement costs based on year-end cost levels, assuming continuation of existing economic
conditions, and by estimated future income tax expense. Income tax expense, both U.S. and foreign,
is calculated by applying the existing statutory tax rates, including any known future changes, to
the pretax net cash flows giving effect to any permanent differences and reduced by the applicable
tax basis. The effect of tax credits is considered in determining the income tax expense.
The standardized measure of discounted future net cash flows is not intended to present the fair
market value of our oil and gas reserves. An estimate of fair value would also take into account,
among other things, the recovery of reserves in excess of proved reserves, anticipated future
changes in prices and costs, an allowance for return on investment and the risks inherent in
reserve estimates.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
|
Oil |
|
|
Gas |
|
|
Oil |
|
|
Gas |
|
|
|
United Kingdom ($/Barrel) |
|
|
79.37 |
|
|
|
6.58 |
|
|
|
60.40 |
|
|
|
4.96 |
|
United States ($/Mcf) |
|
|
79.81 |
|
|
|
4.40 |
|
|
|
61.08 |
|
|
|
3.86 |
|
|
123
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized Measure of Discounted Future Net Cash Flows |
|
|
United |
|
United |
|
|
|
|
Kingdom |
|
States |
|
Total |
|
December 31, 2010: |
|
|
|
|
|
|
|
|
|
|
|
|
Future cash inflows |
|
$ |
704,073 |
|
|
$ |
129,007 |
|
|
$ |
833,080 |
|
Future production costs |
|
|
(101,660 |
) |
|
|
(26,110 |
) |
|
|
(127,770 |
) |
Future development costs |
|
|
(374,380 |
) |
|
|
(33,433 |
) |
|
|
(407,813 |
) |
Future income tax expense |
|
|
(72,870 |
) |
|
|
|
|
|
|
(72,870 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows (undiscounted) |
|
|
155,163 |
|
|
|
69,464 |
|
|
|
224,627 |
|
Annual discount of 10% for estimated timing |
|
|
81,613 |
|
|
|
31,717 |
|
|
|
113,330 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of future net cash flows |
|
$ |
73,550 |
|
|
$ |
37,747 |
|
|
$ |
111,297 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009: |
|
|
|
|
|
|
|
|
|
|
|
|
Future cash inflows |
|
$ |
424,007 |
|
|
$ |
36,799 |
|
|
$ |
460,806 |
|
Future production costs |
|
|
(89,696 |
) |
|
|
(9,893 |
) |
|
|
(99,589 |
) |
Future development costs |
|
|
(274,456 |
) |
|
|
(12,602 |
) |
|
|
(287,058 |
) |
Future income tax expense |
|
|
(17,433 |
) |
|
|
|
|
|
|
(17,433 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows (undiscounted) |
|
|
42,422 |
|
|
|
14,304 |
|
|
|
56,726 |
|
Annual discount of 10% for estimated timing |
|
|
(6,770 |
) |
|
|
7,798 |
|
|
|
1,028 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of future net cash flows |
|
$ |
49,192 |
|
|
$ |
6,506 |
|
|
$ |
55,698 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Principal Sources of Change in the Standardized Measure of Discounted Future Net Cash Flows |
|
|
2010 |
|
2009 |
|
2008 |
|
Standardized measure, beginning of period |
|
$ |
55,698 |
|
|
$ |
49,662 |
|
|
$ |
191,920 |
|
Net changes in prices and production costs |
|
|
86,915 |
|
|
|
(30,155 |
) |
|
|
(144,547 |
) |
Future development costs incurred |
|
|
21,112 |
|
|
|
16,511 |
|
|
|
8,912 |
|
Net changes in estimated future development costs |
|
|
(48,356 |
) |
|
|
(81,864 |
) |
|
|
(105,784 |
) |
Revisions of previous quantity estimates |
|
|
16,375 |
|
|
|
22,318 |
|
|
|
(19,381 |
) |
Extensions and discoveries |
|
|
110,059 |
|
|
|
128,090 |
|
|
|
127,182 |
|
Acretion of discount |
|
|
2,630 |
|
|
|
8,139 |
|
|
|
39,734 |
|
Changes in income taxes, net |
|
|
(35,306 |
) |
|
|
(1,054 |
) |
|
|
163,445 |
|
Sale of oil and gas produced, net of production costs |
|
|
(56,327 |
) |
|
|
(56,531 |
) |
|
|
(213,865 |
) |
Purchased reserves |
|
|
2,386 |
|
|
|
8,827 |
|
|
|
|
|
Sales of reserves in place |
|
|
(48,310 |
) |
|
|
(11,514 |
) |
|
|
|
|
Change in production, timing and other |
|
|
4,421 |
|
|
|
3,269 |
|
|
|
2,046 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure, end of period |
|
$ |
111,297 |
|
|
$ |
55,698 |
|
|
$ |
49,662 |
|
|
124
Endeavour International Corporation
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
Under the supervision and with the participation of our management, including our chief
executive officer, chief financial officer and chief accounting officer, we evaluated the
effectiveness of our disclosure controls and procedures as of the end of the period covered by this
Annual Report on Form 10-K, December 31, 2010. Based on that evaluation, our chief executive
officer, chief financial officer and chief accounting officer concluded that our disclosure
controls and procedures are effective to ensure that information we are required to disclose in our
reports filed or submitted under the Securities Exchange Act of 1934, as amended, is accumulated
and communicated to management as appropriate to allow timely decisions regarding required
disclosures.
Managements Report on Internal Control Over Financial Reporting
Management of the Company is responsible for establishing and maintaining adequate internal
controls over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Securities
Exchange Act of 1934, as amended. Our internal controls were designed to provide reasonable
assurance as to the reliability of our financial reporting and the preparation and presentation of
the consolidated financial statements for external purposes in accordance with accounting
principles generally accepted in the United States.
Because of its inherent limitations, internal control over financial reporting may not detect or
prevent misstatements. Projections of any evaluation of the effectiveness to future periods are
subject to the risk that controls may become inadequate because of changes in conditions, or that
the degree of compliance with the policies or procedures may deteriorate.
Our management assessed the effectiveness of our internal control over financial reporting as of
December 31, 2010. In making this assessment, our management used the criteria established in
Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO). Based on our assessment, our internal control over financial reporting
was effective as of December 31, 2010.
125
Endeavour International Corporation
KPMG LLP, an independent registered public accounting firm, audited managements assessment of
the effectiveness of the Companys internal control over financial reporting as of December 31,
2010 and issued their attestation report set forth in this Item 9A.
Changes in Internal Control over Financial Reporting
There were no changes in our internal controls over financial reporting during the quarterly
period ended December 31, 2010 that have materially affected, or are reasonably likely to
materially affect, our internal control over financial reporting.
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Endeavour International Corporation:
We have audited Endeavour International Corporations internal control over financial reporting as
of December 31, 2010, based on criteria established in Internal Control Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Endeavour
International Corporations management is responsible for maintaining effective internal control
over financial reporting and for its assessment of the effectiveness of internal control over
financial reporting included in the accompanying Managements Report on Internal Control over
Financial Reporting. Our responsibility is to express an opinion on the Companys internal control
over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control over financial reporting was
maintained in all material respects. Our audit included obtaining an understanding of internal
control over financial reporting, assessing the risk that a material weakness exists, and testing
and evaluating the design and operating effectiveness of internal control based on the assessed
risk. Our audit also included performing such other procedures as we considered necessary in the
circumstances. We believe that our audit provides a reasonable basis for our opinion.
A companys internal control over financial reporting is a process designed to provide reasonable
assurance regarding the reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with generally accepted accounting principles. A
companys internal control over financial reporting includes those policies and procedures that (1)
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the
transactions and dispositions of the assets of the company; (2) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of financial statements in accordance
with generally accepted accounting principles, and that receipts and expenditures of the company
are being made only in accordance with authorizations of management and directors of the company;
and (3) provide reasonable assurance regarding prevention or timely
126
Endeavour International Corporation
detection of unauthorized acquisition, use, or disposition of the companys assets that could
have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or
detect misstatements. Also, projections of any evaluation of effectiveness to future periods are
subject to the risk that controls may become inadequate because of changes in conditions, or that
the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Endeavour International Corporation maintained, in all material respects, effective
internal control over financial reporting as of December 31, 2010, based on criteria established in
Internal Control Integrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), the consolidated balance sheets of Endeavour International Corporation and
subsidiaries as of December 31, 2010 and 2009, and the related consolidated statements of
operations, stockholders equity and comprehensive income, and cash flows for each of the years in
the three-year period ended December 31, 2010, and our report dated March 10, 2011 expressed an
unqualified opinion on those consolidated financial statements.
Houston, Texas
March 10, 2011
127
Endeavour International Corporation
Item 9B. Other Information
None.
Item 10. Directors, Executive Officers and Corporate Governance of the Registrant
Our Definitive Proxy Statement for our 2011 Annual Meeting of Stockholders, when filed
pursuant to Regulation 14A under the Securities Exchange Act of 1934, will be incorporated by
reference into this Annual Report on Form 10-K pursuant to General Instruction G(3) of Form 10-K
and will provide the information required under Part III, Item 10.
Our Code of Business Conduct and the Code of Ethics for Senior Officers can be found on our
internet located at www.endeavourcorp.com. Any stockholder may request a printed copy of these
codes by submitting a written request to our Corporate Secretary.
Item 11. Executive Compensation
Our Definitive Proxy Statement for our 2011 Annual Meeting of Stockholders, when filed
pursuant to Regulation 14A under the Securities Exchange Act of 1934, will be incorporated by
reference into this Annual Report on Form 10-K pursuant to General Instruction G(3) of Form 10-K
and will provide the information required under Part III, Item 11.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related
Stockholders Matters
Our Definitive Proxy Statement for our 2011 Annual Meeting of Stockholders, when filed
pursuant to Regulation 14A under the Securities Exchange Act of 1934, will be incorporated by
reference into this Annual Report on Form 10-K pursuant to General Instruction G(3) of Form 10-K
and will provide the information required under Part III, Item 12.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Our Definitive Proxy Statement for our 2011 Annual Meeting of Stockholders, when filed
pursuant to Regulation 14A under the Securities Exchange Act of 1934, will be incorporated by
reference into this Annual Report on Form 10-K pursuant to General Instruction G(3) of Form 10-K
and will provide the information required under Part III, Item 13.
128
Endeavour International Corporation
Item 14. Principal Accounting Fees and Services
Our Definitive Proxy Statement for our 2011 Annual Meeting of Stockholders, when filed
pursuant to Regulation 14A under the Securities Exchange Act of 1934, will be incorporated by
reference into this Annual Report on Form 10-K pursuant to General Instruction G(3) of Form
10-K and will provide the information required under Part III, Item 14.
Part IV
Item 15. Exhibits and Financial Statement Schedules
(a) (1) and (2) Financial Statements and Financial Statement Schedules.
See our consolidated financial statements included in Item 8 herein.
(a) (3) Exhibits.
See Index of Exhibits herein which lists the documents filed as exhibits with this Annual Report
on Form 10-K.
(b) Exhibits.
See Index of Exhibits herein which lists the documents filed as exhibits with this Annual Report
on Form 10-K.
129
Endeavour International Corporation
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934,
the registrant has duly caused this Annual Report on Form 10-K to be signed on its behalf by the
undersigned, thereunto duly authorized.
|
|
|
|
|
Endeavour International Corporation
|
|
|
By: |
/s/ J. Michael Kirksey
|
|
|
|
J. Michael Kirksey |
|
|
|
Executive Vice President and Chief Financial Officer |
|
|
Date: March 10, 2011
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed
below by the following persons on behalf of the registrant and in the capacities and on the dates
indicated.
|
|
|
|
|
Signature |
|
Title |
|
Date |
|
|
|
|
|
/s/ William L. Transier
William L. Transier
|
|
Chief Executive Officer,
President and Director
(Principal Executive Officer)
|
|
March 10, 2011 |
|
|
|
|
|
/s/ J. Michael Kirksey
J. Michael Kirksey
|
|
Chief Financial Officer
(Principal Financial
Officer)
|
|
March 10, 2011 |
|
|
|
|
|
/s/ Robert L. Thompson
Robert L. Thompson
|
|
Chief Accounting Officer
(Principal Accounting
Officer)
|
|
March 10, 2011 |
|
|
|
|
|
|
|
Director
|
|
March 10, 2011 |
John B. Connally III |
|
|
|
|
|
|
|
|
|
|
|
Director
|
|
March 10, 2011 |
Sheldon Erikson |
|
|
|
|
|
|
|
|
|
|
|
Director
|
|
March 10, 2011 |
Charles Hue Williams |
|
|
|
|
|
|
|
|
|
|
|
Director
|
|
March 10, 2011 |
Leiv L. Nergaard |
|
|
|
|
|
|
|
|
|
|
|
Director
|
|
March 10, 2011 |
Nancy K. Quinn |
|
|
|
|
|
|
|
|
|
|
|
Director
|
|
March 10, 2011 |
John N. Seitz |
|
|
|
|
130
Endeavour International Corporation
Exhibit Index
|
|
|
Exhibit |
|
Description |
*2.1
|
|
Sale and Purchase Agreement
relating to Licence P.255, Block 22/6a North, between Endeavour, Shell U.K. Limited and
Shell EP Offshore Ventures Limited dated November 23, 2010. |
|
|
|
* 2.2
|
|
Sale and Purchase Agreement relating to Licence P.057, Block
21/9,between Endeavour and Shell EP Offshore Ventures Limited dated
November 23, 2010. |
|
|
|
2.3
|
|
Agreement for the Sale and Purchase of the Cygnus Asset dated August
27, 2010. (Incorporated by reference to Exhibit 2.1 of our Quarterly
Report on Form 10-Q (Commission File No. 001-32212) for the quarter
ended September 30, 2010). |
|
|
|
**2.4
|
|
Purchase and Sale and Participation Agreement by and between Endeavour
and Hillwood Energy Alabama LP. Schedules and Exhibits are omitted
pursuant to Section 601(b)(2) of Regulation S-K. Endeavour agrees to
furnish supplementally a copy of any omitted Schedule to the SEC upon
request. (Incorporated by reference to Exhibit 2.1 of our Current
Report on Form 8-K (Commission File No. 001-32212) filed on January
19, 2010). |
|
|
|
**2.5
|
|
Purchase and Sale Agreement between Endeavour and Cohort Energy
Company. Schedules and Exhibits are omitted pursuant to Section
601(b)(2) of Regulation S-K. Endeavour agrees to furnish
supplementally a copy of any omitted Schedule to the SEC upon request.
(Incorporated by reference to Exhibit 2.1 of our Current Report on
Form 8-K (Commission File No. 001-32212) filed on January 19, 2010). |
|
|
|
3.1(a)
|
|
Amended and Restated Articles of Incorporation (Incorporated by
reference to Exhibit 3.2 of our Quarterly Report on Form 10-Q
(Commission File No. 001-32212) for the quarter ended June 30, 2004). |
|
|
|
3.1(b)
|
|
Certificate of Amendment dated June 1, 2006 (Incorporated by reference
to Exhibit 4.2 of our Registration Statement on Form S-3 (Commission
File No. 333-139304) filed on December 13, 2006). |
|
|
|
3.1(c)
|
|
Certificate of Amendment dated June 1, 2010 (Incorporated by reference
to Exhibit 3.1 to our Current Report on Form 8-K (Commission File No.
001-32212) filed on June 3, 2010). |
|
|
|
*3.1(d)
|
|
Amendment to Articles of Incorporation, dated November 17, 2010.
|
|
|
|
3.2(a)
|
|
Amended and Restated Bylaws (Incorporated by reference to Exhibit 3.4
to our Current Report on Form 8-K (Commission File No. 001-32212)
filed on November 6, 2006). |
|
|
|
3.2(b)
|
|
Amendment to Amended and Restated By-laws dated December 12, 2007 by
Endeavour International Corporation (Incorporated by reference to
Exhibit 3.1 to our Current Report on Form 8-K (Commission File No.
001-32212) filed on December 13, 2007). |
131
Endeavour International Corporation
Exhibit Index
|
|
|
Exhibit |
|
Description |
3.3
|
|
Amended and Restated Certificate of Designation of Series B Preferred
Stock filed February 26, 2004 (Incorporated by reference to Exhibit
3.3 of our Quarterly Report on Form 10-Q (Commission File No.
001-32212) for the quarter ended June 30, 2004). |
|
|
|
*3.4
|
|
Specimen of Common Stock Certificate. |
|
|
|
3.5
|
|
Certificate of Designation of Series A Preferred Stock of Endeavour
International Corporation (Incorporated by reference to Exhibit 3.1 to
our Current Report on Form 8-K (Commission File No. 001-32212) filed
on November 6, 2006). |
|
|
|
3.6(a)
|
|
Certificate of Designation of Series C Preferred Stock of Endeavour
International Corporation, (Incorporated by reference to Exhibit 3.2
to our Current Report on Form 8-K (Commission File No. 001-32212)
filed on November 6, 2006). |
|
|
|
3.6(b)
|
|
Amendment to Certificate of Designation of Series C Preferred Stock of
Endeavour International Corporation, dated November 17, 2009
(Incorporated by reference to Exhibit 3.1 to our Current Report on
Form 8-K (Commission File No. 001-32212) filed on November 23, 2009). |
|
|
|
3.6(c)
|
|
Amendment to Certificate of Designation of Series C Preferred Stock of
Endeavour International Corporation, dated March 10, 2010
(Incorporated by reference to Exhibit 3.6(c) of our Annual Report on
Form 10-K for the year ended December 31, 2009). |
|
|
|
3.7
|
|
Certificate of Designation of Series D Preferred Stock of Endeavour
International Corporation (Incorporated by reference to Exhibit 3.3 to
our Current Report on Form 8-K (Commission File No. 001-32212) filed
on November 6, 2006). |
|
|
|
4.1(a)
|
|
Warrants to Purchase Common Stock issued to Trident Growth Fund, LP
dated July 29, 2003 (warrant # 2003-3) (Incorporated by reference to
Exhibit 4.7 of our Annual Report on Form 10-KSB (Commission File No.
000-33439) for the year ended December 31, 2003). |
|
|
|
4.1(b)
|
|
First Amendment to Warrants to Purchase Common Stock dated February
26, 2004 (warrant # 2003-3) (Incorporated by reference to Exhibit 4.7
of our Annual Report on Form 10-KSB (Commission File No. 000-33439)
for the year ended December 31, 2003). |
|
|
|
4.2(a)
|
|
Warrants to Purchase Common Stock issued to Gemini Capital, L.P.
(Warrant #2002-1) (Incorporated by reference to Exhibit 4.6 of our
Quarterly Report on Form 10-QSB (Commission File No. 000-33439) for
the Quarter Ended June 30, 2002). |
132
Endeavour International Corporation
Exhibit Index
|
|
|
Exhibit |
|
Description |
4.2(b)
|
|
First Amendment to Warrants to Purchase Common Stock dated July 29,
2003 (Warrant # 2002-1) (Incorporated by reference to Exhibit 4.5 of
our Annual Report on Form 10-KSB (Commission File No. 000-33439) for
the year ended December 31, 2003). |
|
|
|
4.2(c)
|
|
Second Amendment to Warrants to Purchase Common Stock dated February
26, 2004 (Warrant # 2002-1) (Incorporated by reference to Exhibit 4.5
of our Annual Report on Form 10-KSB (Commission File No. 000-33439)
for the year ended December 31, 2003). |
|
|
|
4.3
|
|
Indenture, dated as of January 20, 2005, between Endeavour
International Corporation and Wells Fargo Bank, National Association,
as Trustee, relating to the 6.00% Convertible Senior Notes due 2012
(Incorporated by reference to our Exhibit 4.1 to our Current Report on
Form 8-K (Commission File No. 001-32212) filed on January 24, 2005). |
|
|
|
4.4
|
|
Registration Rights Agreement dated January 24, 2008 by and between
Endeavour International Corporation and Smedvig QIF Plc (Incorporated
by reference to Exhibit 4.2 to our Current Report on Form 8-K
(Commission File No. 001-32212) filed on January 24, 2008). |
|
|
|
4.5
|
|
Trust Deed dated January 24, 2008 by and among Endeavour International
Corporation, Endeavour Energy Luxembourg S.a.r.l. and BNY Corporate
Trustee Services Limited, as trustee (Incorporated by reference to
Exhibit 4.1 to our Current Report on Form 8-K (Commission File No.
001-32212) filed on January 24, 2008). |
|
|
|
10.1
|
|
2004 Incentive Plan, effective February 26, 2004 (Incorporated by
reference to Exhibit 10.36 of our Annual Report on Form 10-KSB
(Commission File No. 000-33439) for the year ended December 31, 2003). |
|
|
|
10.2
|
|
2007 Incentive Plan (Incorporated by reference to Exhibit 10.1 to our
Quarterly Report (Commission file No. 001-32212) for the quarter ended
June 30, 2007). |
|
|
|
10.3
|
|
2010 Incentive Plan (Incorporated by reference to Exhibit A to our
definitive proxy statement on Schedule 14A filed on April 20, 2010). |
|
|
|
10.4
|
|
Second Amended and Restated Employment Agreement by and between
William L. Transier and the Company (Incorporated by reference to
Exhibit 10.4 to our Annual Report on Form 10-K (Commission File No.
001-32212) for the year ended December 31, 2008). |
|
|
|
10.5
|
|
Employment Offer Letter to Carl Grenz, dated August 15, 2008
(Incorporated by reference to Exhibit 10.1 of our Quarterly Report on
Form 10-Q (Commission File No. 001-32212) for the quarter ended
September 30, 2008). |
|
|
|
10.6
|
|
Form of Change in Control on Termination of Benefits Agreement
(Incorporated by reference to Exhibit 10.1 to our Current Report on
Form 8-K
(Commission File No. 000-32212) filed on February 15, 2008). |
133
Endeavour International Corporation
Exhibit Index
|
|
|
Exhibit |
|
Description |
10.7
|
|
Form of Amended Change in Control Termination Benefits Agreement
between the Company and Kirksey, Grenz, Williams and Stover,
individually (Incorporated by reference to Exhibit 10.8 of our Annual
Report on Form 10-K for the year ended December 31, 2008). |
|
|
|
10.8
|
|
Change in Control and Termination Benefits Agreement dated January 11,
2010, by and between Endeavour International Corporation and James
Joseph Emme (Incorporated by reference to Exhibit 10.7 of our Annual
Report on Form 10-K for the year ended December 31, 2009). |
|
|
|
10.9
|
|
Form of Restricted Stock Agreement under the 2010 Incentive Plan
(Incorporated by reference to Exhibit 10.2 of our Quarterly Report on
Form 10-Q (Commission File No. 001-32212) for the quarter ended
September 31, 2010). |
|
|
|
10.10
|
|
Form of Stock Option Agreement under the 2010 Incentive Plan
(Incorporated by reference to Exhibit 10.3 to our Quarterly Report on
Form 10-Q (Commission File No. 001-32212) for the quarter ended
September 31, 2010). |
|
|
|
10.11(a)
|
|
Form of Stock Option Agreement under the 2010 Incentive Plan
(Incorporated by reference to Exhibit 10.3 to our Quarterly Report on
Form 10-Q (Commission File No. 001-32212) for the quarter ended
September 31, 2010). |
|
|
|
10.11(b)
|
|
Incremental Term Loan Commitment and Amendment Agreement among
Endeavour International Corporation, Endeavour Energy UK Limited,
various lenders and Cyan Partners, LP dated October 21, 2010
(Incorporated by reference to Exhibit 10.4(b) to our Quarterly Report
on Form 10-Q (Commission File No. 001-32212) for the quarter ended
September 31, 2010). |
|
|
|
10.11(c)
|
|
Incremental Fee Letter among Endeavour International Corporation,
Endeavour Energy UK Limited, various lenders and Cyan Partners, LP, as
supplement to the Incremental Term Loan Commitment and Amendment
Agreement, dated October 21, 2010 (Incorporated by reference to
Exhibit 10.4(b) to our Quarterly Report on Form 10-Q (Commission File
No. 001-32212) for the quarter ended September 31, 2010). |
|
|
|
10.11(d)
|
|
First Amendment to Credit Agreement, U.S. Security Agreement and
Subsidiaries Guaranty, dated as of February 3, 2011, by and among
Endeavour International Corporation, Endeavour Energy UK Limited, Cyan
Partners, LP, as administrative agent, and the lenders party thereto
(Incorporated by reference to Exhibit 10.1 to our Current Report on
Form 8-K (Commission File No. 001-32212) filed on February 9, 2011). |
|
|
|
10.12(a)
|
|
Subscription and Registration Rights Agreement, dated October 19,
2006, by and among Endeavour International Corporation and the
Investors party thereto (Incorporated by reference to Exhibit 10.1 to
our Current Report on
Form 8-K (Commission File No. 001-32212) filed on October 25, 2006). |
134
Endeavour International Corporation
Exhibit Index
|
|
|
Exhibit |
|
Description |
10.12(b)
|
|
Amendment No. 1 to Subscription and Registration Rights Agreement,
January 29, 2010, by and among Endeavour International Corporation and
the Investors party thereto (Incorporated by reference to Exhibit 10.1
to our Current Report on Form 8-K (Commission File No. 001-32212)
filed on February 1, 2010). |
|
|
|
**10.13
|
|
Final Participation Agreement between Endeavour and Cohort Energy
Company (Incorporated by reference to Exhibit 10.2 to our Current
Report on Form 8-K (Commission File No. 001-32212) filed on January
19, 2010). |
|
|
|
10.14
|
|
Restricted Stock Award Agreement between Endeavour International
Corporation and J. Michael Kirksey dated September 26, 2007
(Incorporated by reference to Exhibit 10.31 to our Annual Report on
Form 10-K (Commission File No. 001-32212) for the year ended December
31, 2007). |
|
|
|
10.15
|
|
Restricted Stock Award Agreement between Endeavour International
Corporation and John G. Williams dated October 1, 2007 (Incorporated
by reference to Exhibit 10.32 to our Annual Report on Form 10-K
(Commission File No. 001-32212) for the year ended December 31, 2007). |
|
|
|
10.16
|
|
Stock Option Agreement between Endeavour International Corporation and
J. Michael Kirksey dated September 26, 2007 (Incorporated by reference
to Exhibit 10.33 to our Annual Report on Form 10-K (Commission File
No. 001-32212) for the year ended December 31, 2007). |
|
|
|
10.17
|
|
Stock Option Agreement between Endeavour International Corporation and
John G. Williams dated October 1, 2007 (Incorporated by reference to
Exhibit 10.34 to our Annual Report on Form 10-K (Commission File No.
001-32212) for the year ended December 31, 2007). |
|
|
|
10.18
|
|
Stock Option Agreement between Endeavour International Corporation and
Carl D. Grenz dated November 3, 2008 (Incorporated by reference to
Exhibit 10.22 to our Annual Report on Form 10-K (Commission File No.
001-32212) for the year ended December 31, 2008). |
|
|
|
10.19
|
|
Stock Option Agreement between Endeavour International Corporation and
Carl D. Grenz dated November 3, 2008 (Incorporated by reference to
Exhibit 10.23 to our Annual Report on Form 10-K (Commission File No.
001-32212) for the year ended December 31, 2008). |
|
|
|
10.20
|
|
Restricted Stock Award Agreement between Endeavour International
Corporation and Carl D. Grenz dated November 3, 2008 (Incorporated by
reference to Exhibit 10.24 to our Annual Report on Form 10-K
(Commission File No. 001-32212) for the year ended December 31, 2008). |
|
|
|
10.21
|
|
Restricted Stock Award Agreement between Endeavour International
Corporation and Carl D. Grenz dated November 3, 2008 (Incorporated by
reference to Exhibit 10.25 to our Annual Report on Form 10-K
(Commission File No. 001-32212) for the year ended December 31, 2008). |
135
Endeavour International Corporation
Exhibit Index
|
|
|
Exhibit |
|
Description |
*10.22
|
|
Restricted Stock Award Agreement between Endeavour International
Corporation and James J. Emme dated January 10, 2010. |
|
|
|
10.23
|
|
Agreement for the Sale and Purchase of the Endeavour Energy Norge AS
dated April 2, 2009 (Incorporated by reference to Exhibit 4.1 of our
Quarterly Report on Form 10-Q (Commission File No. 001-32212) for the
quarter ended March 31, 2009). |
|
|
|
10.24
|
|
Form of Stock Redemption Agreement dated November 17, 2009 by and
among Endeavour International Corporation and the holders of its
Series C Preferred Stock (Incorporated by reference to Exhibit 10.1 to
our Current Report on Form 8-K (Commission File No. 001-32212) filed
on November 23, 2009). |
|
|
|
10.25(a)
|
|
Form of Note Agreement dated November 17, 2009 by and among Endeavour
International Corporation and the holders of its Series C Preferred
Stock (Incorporated by reference to Exhibit 10.2 to our Current Report
on Form 8-K (Commission File No. 001-32212) filed on November 23,
2009). |
|
|
|
10.25(b)
|
|
Amendment to Note Agreement dated November 17, 2009 by and among
Endeavour International Corporation and the holders of its Series C
Preferred Stock, dated March 10, 2010 (Incorporated by reference to
Exhibit 10.26(b) of our Annual Report on Form 10-K for the year ended
December 31, 2009). |
|
|
|
10.26
|
|
Common Stock Purchase Agreement, dated as of February 4, 2010, by and
between Endeavour International Corporation and the purchasers named
therein ((Incorporated by reference to Exhibit 10.1 to our Current
Report on Form 8-K (Commission File No. 001-32212) filed on February
5, 2010). |
|
|
|
10.27
|
|
Registration Rights Agreement, dated as of February 4, 2010, by and
between Endeavour International Corporation and the purchasers named
therein (Incorporated by reference to Exhibit 10.2 to our Current
Report on Form 8-K (Commission File No. 001-32212) filed on February
5, 2010). |
|
|
|
10.28
|
|
Common Stock Purchase Agreement, dated August 16, 2010, by and between
Endeavour International Corporation and the purchasers named therein
(Incorporated by reference to Exhibit 10.1 to our Current Report on
Form 8-K (Commission File No. 001-32212) filed on August 20, 2010. |
|
|
|
*12.1
|
|
Computation of Ratios of Earnings to Fixed Charges. |
|
|
|
*12.2
|
|
Computation of Ratios of Earnings to Fixed Charges and Preference
Securities Dividends. |
|
|
|
*14.1
|
|
Code of Business Conduct of Endeavour International Corporation. |
|
|
|
*21.1
|
|
List of Subsidiaries. |
136
Endeavour International Corporation
Exhibit Index
|
|
|
Exhibit |
|
Description |
*23.1
|
|
Consent of Independent Registered Public Accounting Firm KPMG LLP. |
|
|
|
*23.2
|
|
Consent of Independent Reserve Engineers Netherland, Sewell &
Associates, Inc. |
|
|
|
*31.1
|
|
Certification of William L. Transier, Chief Executive Officer,
pursuant to Rule 13a-14(a) of the Securities and Exchange Act of 1934,
as amended. |
|
|
|
*31.2
|
|
Certification of J. Michael Kirksey, Chief Financial Officer, pursuant
to Rule 13a-14(a) of the Securities and Exchange Act of 1934, as
amended. |
|
|
|
32.1
|
|
Certification of William L. Transier, Chief Executive Officer,
pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906
of the Sarbanes-Oxley Act of 2002. |
|
|
|
32.2
|
|
Certification of J. Michael Kirksey, Chief Financial Officer, pursuant
to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002. |
|
|
|
99.1
|
|
Report of Netherland, Sewell & Associates, Inc., Independent Petroleum
Engineers and Geologists. |
|
|
|
* |
|
Filed herewith. |
|
|
|
Furnished herewith. |
|
|
|
Identifies management contracts and compensatory plans or arrangements. |
|
** |
|
Portions of this exhibit have been omitted pursuant to a request for
confidential treatment under Rule 24b-2 of the Securities Exchange Act
of 1934, and the omitted material has been separately filed with the
Securities and Exchange Commission. |
137