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.K. North Sea and U.S. onshore. 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, completion and operating 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 development assets, which have large potential reserves but long production-cycles, with current production from the North Sea assets we expect to acquire in the COP Acquisition (described below), our existing U.K. production and a portfolio of assets in the U.S. that have lower development 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.
We recently entered into a definitive agreement with several subsidiaries of ConocoPhillips to purchase certain interests in three North Sea fields which produced an average of approximately 11,000 BOE/d for the year ended December 31, 2011 (the “COP Acquisition”). The proved reserves we expect to acquire in the COP Acquisition total approximately 19.5 MMBOE as of December 31, 2011, comprised of 99% oil and 71% proved developed reserves.
In addition, our major development projects in the U.K. sector of the North Sea - specifically, Bacchus and Rochelle - 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 first quarter of 2012 and first production from the Rochelle area expected in the fourth quarter of 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. We believe our existing portfolio can deliver growth in production and proved reserves over the next several years.
Our primary focus in the U.S. is onshore unconventional oil and gas shale developments targeting reserve and production growth in the Haynesville and Marcellus areas. In the Haynesville area, we have approximately 7,100 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 18,400 net acres in Pennsylvania located between two of the most active parts of the Marcellus play. We also have interests in
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approximately 94,400 net acres in the emerging Heath shale oil play in Montana (the “Heath Shale Oil Play”) where we are evaluating the results of four pilot wells and ongoing technical work. The results from our pilot wells and ongoing technical work will determine the pace and scope of our subsequent exploration and development initiatives in this play.
In 2012, we intend to expand upon our foundation of U.K. assets by moving existing development assets towards their first production and integrating the assets we expect to acquire in the COP Acquisition. We also intend to maintain our interests in both established and emerging U.S. onshore resource plays. Specifically, during 2012, we intend to focus on achieving initial production from the Bacchus oil field and the Rochelle gas field in the North Sea while integrating the assets we expect to acquire in the COP Acquisition and completing the evaluation of our assets in the Heath Shale Oil Play.
Operations
Our operations are organized into two main geographic regions as follows: the U.K. North Sea and U.S. onshore. Proved reserves were as follows for our principal operating areas, including pro forma for the COP Acquisition:
(1) Pro forma includes the acquisition of the three ConocoPhillips assets. The transaction is scheduled to close during the first quarter of 2012.
As of December 31, 2011, our estimated proved reserves were 22.7 MMBOE, up 23% from 18.4 MMBOE as of December 31, 2010, of which approximately 55% were located in the U.K. and approximately 45% were located in the U.S., and 23% of which were proved developed reserves. As of December 31, 2011, the properties that we expect to acquire in the COP Acquisition contained approximately 19.5 MMBOE of proved reserves. On a pro forma basis for the COP Acquisition, our total proved reserves would have been 42.3 MMBOE as of December 31, 2011, of which 45% is proved developed and 55% is oil. On the same pro forma basis, we would have had combined production of approximately 14,400 BOE/d for the year ended December 31, 2011.
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Our Business Strategy
We are pursuing a strategy of building a balanced portfolio of exploration, appraisal and development assets, primarily in the central U.K. North Sea and an evolving set of assets in the onshore North America. We believe our existing producing assets and the producing properties we expect to acquire in the COP Acquisition help provide a stable platform upon which to execute our strategy. We intend to continue developing our existing assets in the U.K. North Sea, while simultaneously pursuing the measured development of our onshore domestic positions in the Haynesville and Marcellus areas as commodity prices dictate. 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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Complete the COP Acquisition. During 2012, we intend to focus on completing the COP Acquisition. We anticipate closing on the acquisition of the interest in the Alba field, which represents 62% and 59% of the acquired assets’ total proved reserves and production as of December 31, 2011 by March 31, 2012. We believe the acquired assets will significantly increase our current production levels, which we expect will have an immediate impact on our cash flows from operations. Specifically, after giving pro forma effect to the COP Acquisition, our production for the year ended December 31, 2011 would have been approximately 14,400 BOE/d. Further, we expect that following the consummation of the COP Acquisition, oil production at Brent crude oil pricing will increase to approximately 84% of our total production.
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Efficiently Develop and Commence Production from Our North Sea Development Assets. We currently have two large development projects in the North Sea - the Bacchus and Rochelle fields - which have the potential to significantly increase our proved reserves and 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 Bacchus before the end of the first quarter of 2012 and from the Rochelle area in the fourth quarter of 2012.
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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 growth in production and cash flow that will enable 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 or current production with assets that have larger potential reserves with longer production-cycles. As with the COP Acquisition, we intend to selectively pursue additional acquisition opportunities, which we believe will continue to arise over the next several years in our core areas of operation.
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Manage Existing Acreage in Resource-Rich Plays. We have established a mix of U.S. onshore producing assets and undeveloped acreage in both established and emerging resource plays, including the Haynesville and Marcellus areas and the Heath Shale. We have the ability to adjust our domestic drilling activities in accordance with current and future commodity prices and our operating results and intend to manage these assets in a measured manner with a focus on enhancing returns on the capital deployed on these assets.
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Our Competitive Strengths
We believe the following competitive strengths will help us achieve our business strategy:
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Cash Flows from Producing and Development Assets. We believe that our producing assets in the U.K. North Sea and U.S. onshore and development assets, together with the assets that we expect to acquire in the COP Acquisition, should provide us with stable cash flows over the next several years without requiring substantial capital expenditures on these assets. In turn, those cash flows should enable us to develop our longer-term, more capital-intensive North Sea development projects. We believe the assets purchased in the COP Acquisition represent significant cash flow generating assets purchased at an attractive price.
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Significant North Sea Development Assets and Attractive Positions in Resource-Rich Shale Plays. We believe that successful development of our two primary development assets in the U.K. North Sea could have the potential to significantly increase our proved reserves and production levels over the next several years. Moreover, our assets in the U.S. cover several onshore resource plays, from established areas, such as Haynesville and Marcellus, to the emerging Heath Shale Oil Play in Montana. This combination should allow us to balance the capital intensive, long lead-time nature of our North Sea development assets with the shorter development times and lower capital requirements of our U.S. properties.
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Increasing Exposure to Oil. Our oil production should increase significantly with existing production from the properties to be acquired in the COP Acquisition and first production from our Bacchus asset. In addition, our current portfolio of assets includes other liquids-rich opportunities, and these assets and prospects could 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 Chief Executive Officer and President, 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 27 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 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 Chief Executive Officer and President, William L. Transier, was formerly the Executive Vice President and Chief Financial Officer of Ocean Energy, which merged with Devon Energy in 2003, and has over 36 years of experience in the oil and gas industry.
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Our Executive Vice President and Chief Financial Officer, J. Michael Kirksey, has an extensive background in both operational and financial management, with 36 years of experience in the energy industry, having served in various executive roles for Metals USA, ION Geophysical Corporation and Keystone International, Inc. after starting his career with Arthur Andersen & Co.
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Our Executive Vice President - International, Carl D. Grenz, has 36 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 Elk Resources, Inc.
Our Areas of Operation
Our operations are organized into two main geographic regions as follows: the U.K. North Sea and U.S. onshore. The following tables set forth information related to our principal operating areas as of the dates and for the periods indicated.
Pro forma for the COP Acquisition, proved reserves would increase to 42.3 MMBOE at year-end 2011.
U.K. 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
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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. Additionally, 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.
We recently entered into a definitive agreement with several subsidiaries of ConocoPhillips to purchase certain interests in three North Sea fields which produced at an average of approximately 11,000 BOE/d for the year ended December 31, 2011. For additional information, see the “Pending Acquisition” discussion, below.
Our three producing fields in the U.K. - Alba, Bittern and Enoch - held a combined 2.0 MMBOE of proved reserves as of December 31, 2011. Sales from these fields totaled 388 MBOE for the year ended December 31, 2011. Our 2.25% working interest in the Alba field will increase to 25.68% upon consummation of the COP Acquisition.
Our development assets in the Bacchus and Rochelle fields comprise the primary components of our current U.K. North Sea portfolio, and we have development plans under way in each of these fields. When these projects are fully producing, they have the potential to significantly increase our proved reserves and current production levels over the next several years.
Bacchus
At December 31, 2011, we held a 30% working interest in our Bacchus field asset, which is operated by Apache Corporation, who owns a 50% working interest. Bacchus is an oil field with 0.5 MMBOE of estimated net proved reserves at December 31, 2011. The development of the Bacchus field was sanctioned in the second quarter of 2010 by the United Kingdom’s 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 is in place, and the rig is currently drilling the first of the three planned development wells. We currently expect to commence production in the first quarter of 2012, and follow with two additional development wells thereafter, which should increase our proved reserves and production attributable to Bacchus. We believe that the Bacchus field may produce up to 4,000 to 5,000 BOE/d net to Endeavour for 12 to 18 months when fully on production.
Rochelle
The Rochelle area accounted for 8.2 MMBOE of our proved reserves at December 31, 2011. Our working interest in the Rochelle area is 44% and we are the operator of the field, which is comprised of Blocks 15/26b, 15/26c and 15/27. In 2011, the DECC approved the necessary
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Rochelle FDPs. In April 2011, we announced agreement of the commercial terms for the processing and transportation of Rochelle production on the Scott Platform in the Central North Sea, and the required modifications to the Scott Platform have commenced. We have also begun construction of the production facilities and contracted for a drilling rig that is expected to commence drilling two planned production wells in the spring of 2012. The Rochelle development continues on schedule for first production in the fourth quarter of 2012 with the contracted drilling rig expected to arrive in the spring to commence drilling of the two planned production wells.
U.S. Onshore
During 2009, we began acquiring acreage in U.S. onshore resource plays. Our U.S. assets held 10.2 MMBOE of proved reserves as of December 31, 2011. We believe that our U.S. acreage provides us with development projects with shorter time frames to first production at lower costs than our North Sea assets. In addition, our U.S. acreage covers several resource plays, from established areas such as the Haynesville and Marcellus areas, to the emerging Heath Shale Oil Play.
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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using our flexibility in the drilling schedule to curtail capital expenditures, where possible, until U.S. natural gas prices improve;
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drilling only three gross Haynesville wells planned in 2012 in order to hold certain acreage;
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drilling only two gross wells in the Marcellus area to maintain acreage positions and fulfill minor drilling commitments; and
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a thorough analysis of test well results in the Heath Shale Oil Play in Montana before finalizing any development plans in this exploratory shale oil play.
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. production to grow and provide near-term return on capital to balance our longer production-cycle U.K. projects.
Pending Acquisition
On December 23, 2011, we entered into a definitive agreement (the “COP Purchase Agreement”) with ConocoPhillips (U.K.) Limited, ConocoPhillips Petroleum Limited and ConocoPhillips (U.K.) Lambda Limited (collectively, “COP”) to acquire certain oil and natural gas interests in the North Sea for approximately $330 million in cash. In addition to customary closing conditions, the purchase is subject to approval of governmental regulatory authorities and partner consents. Pursuant to the COP Purchase Agreement, we will also acquire certain tax assets that are expected to result in a benefit to us of approximately $58 million that will effectively reduce the overall cost of the acquisition to us. The cash consideration is subject to customary purchase
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price adjustments, including adjustments for revenues and expenses from the acquired assets, working capital, capital expenditures, cash calls on joint venture interests and interest on the purchase price, from January 1, 2011 until the closing. Assuming a closing date of March 31, 2012, these adjustments are expected to reduce the cash consideration by approximately $95 million.
As of December 31, 2011, based on evaluations prepared by our internal reserve engineers from data provided by COP (other than with respect to the Alba field), which have been audited by Netherland, Sewell & Associates, Inc., the properties that we expect to acquire contained approximately 19.5 MMBOE of proved reserves as of December 31, 2011, of which 99% was oil. As of that same date, the PV-10 of the proved oil and natural gas reserves was approximately $830 million. In addition, the properties to be acquired produced at an average of approximately 11,000 BOE/d for the year ended December 31, 2011.
The interests to be acquired are composed of a 23.43% interest in the Alba field (in which we already own a 2.25% interest), a 40% interest in the MacCulloch field and an 18% interest in the Nicol field. The interest in the Alba field accounts for approximately 62% and 59% of the acquired assets’ total proved reserves and production as of December 31, 2011. Subject to partner and U.K. regulatory approvals, we expect that we will be the operator of the MacCulloch field following the closing of the COP Acquisition.
The COP Purchase Agreement provides for the possibility that the COP Acquisition may close in multiple stages. Subject to customary exceptions, our acquisition of the interest in the Alba field (the “Alba Acquisition”), which constitutes the majority of the value in the COP Acquisition, is required to close no later than March 31, 2012 unless extended by the parties, and our acquisition of the remaining interests is required to close no later than October 31, 2012. In addition, the COP Purchase Agreement provides that we may close on the interest in the Alba field without subsequently closing on the remaining interests, in certain circumstances. In accordance with the terms of the COP Purchase Agreement, we will not, however, close on the remaining interests without closing on the Alba Acquisition.
There can be no assurance that we will consummate all or any portion of the COP Acquisition by March 31, 2012 or at all.
2012 Planned Capital Expenditures
We expect that our total capital expenditure budget for 2012 will be between $150 million and $175 million. We expect to spend approximately $125 million to $150 million of the total 2012 budget in the U.K., primarily on the advancement of our development projects. The acquisition of the ConocoPhillips assets would add another $20 million-$25 million to Endeavour’s capital budget, upon completion of the transaction. Capital expenditures for Bacchus will be our initial priority, as we plan to reach first production during the first quarter. With our existing cash position, cash flows from existing production and either the start up of production from Bacchus or the completion of the COP Acquisition, we believe we have sufficient cash flows to complete the necessary development program for the Rochelle area to reach first production in the fourth quarter of 2012. We expect to spend the remainder of our 2012 capital budget in the U.S. to
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evaluate our Heath Shale Oil Play pilot wells, to maintain our acreage positions and to fulfill minor drilling commitments. Our 2012 capital expenditure budget is subject to change depending on a number of factors, including the availability and costs of drilling and completion equipment, crews, economic and industry conditions, prevailing and anticipated prices for oil and gas, the availability of sufficient capital resources, drilling success and other normal factors affecting the oil and gas industry.
We intend to fund our 2012 capital expenditures primarily through cash on hand and cash flow generated from operations, including cash flow from new production at Bacchus or the assets to be acquired in the COP Acquisition. The majority of our cash on hand was generated through borrowings under our secured 15.0% senior term loan due 2013 of our principal U.K. subsidiary and the July 2011 offering of our 5.5% Convertible Notes due 2016. The proceeds from the offering of our 5.5% Convertible Notes were originally expected to fund our acquisition of certain Marcellus shale play assets, but the transactions were not consummated and we are currently involved in litigation with the sellers. See “Item 3, Legal Proceedings” for additional information.
For a complete discussion of our available sources of liquidity and our expected financing needs, please see Item 7. “Management’s 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.
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 two significant development projects ongoing in the U.K. Bacchus and Rochelle.
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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, 2011, we had the following debt and equity outstanding in addition to our common stock:
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Letters of Credit: In July 2011, we secured new letters of credit that allowed us to release the $33 million of restricted cash into operations that served as collateral for previous letters of credit.
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5.5% Convertible Notes: In July 2011, we issued $135 million aggregate principal amount of our 5.5% Convertible Notes. We issued the 5.5% Convertible Notes, expecting to utilize the majority of the net proceeds of this offering to fund an acquisition of acreage and related midstream assets in the Marcellus shale play. As we terminated the acquisition agreement in December 2011, these proceeds will be now used for general corporate purposes.
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Common Stock Offering: In March 2011, we closed a public offering of 11.5 million shares of our common stock offering for net proceeds of $118.4 million.
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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,
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in the aggregate amount of $150 million, which was subsequently increased to $160 million. In February 2011, we amended our Senior Term Loan to increase the security reserved for potential letters of credit from $25 million to $35 million. In July 2011, we secured new letters of credit that allowed us to release the $33 million of restricted cash that served as collateral for previous letters of credit. Also in July 2011, we entered into an amendment to our Senior Term Loan providing for an increase of $75 million in the amounts available under the Senior Term Loan. The proceeds will be used for general corporate purposes.
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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. In April 2011, we redeemed all $81.25 million of our outstanding 6% Senior Notes with a portion of the proceeds from our common stock offering completed in March 2011.
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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, Smedvig QIF PLC and the other parties thereto related. In March 2011, we entered into an Amendment to the Trust Deed dated as of January 24, 2008 to our 11.5% Convertible Bonds. The amendment provides for an extension of the maturity date of the 11.5% Convertible Bonds; extends the date on which holders may exercise a put right, and the occurrence of price reset if not exercised; and a reduction in the interest rate payable after March 31, 2014 to 7.5%.
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$50 million Subordinated Notes: In November 2009, we issued an aggregate $50 million of subordinated notes due 2014.
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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. (See above.)
Each of these debt and equity offerings is explained more fully in Note 12 and Note 15 to our consolidated financial statements in “Item 8, Financial Statements and Supplementary Data.”
On February 23, 2012, we closed the private placement of $500 million of 12% notes due 2018. The private placement took place in two parts - $350 million aggregate principal amount of 12% first priority notes due 2018 (the “First Priority Notes”) and $150 million aggregate principal amount of 12% second priority notes due 2018 (the “Second Priority Notes,” and, together with the First Priority Notes, the “2018 Notes”). Each series of 2018 Notes was priced at 96% of par, at a yield to maturity of 12.975% for the First Priority Notes and 12.954% for the Second Priority Notes, respectively. We intend to use the net proceeds from the offering to fund the COP Acquisition, to repay all amounts outstanding under our Senior Term Loan due 2013 and for general corporate purposes. Prior to the closing of the acquisition in the North Sea, the net proceeds of the offering are held in an escrow account. Once we close the COP Acquisition, the proceeds will be released from escrow.
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.
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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 accounted for more than 10% of revenue for the year ended December 31, 2011: Chevron North Sea Ltd, Shell U.K. Limited, and Hess Limited. 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 JW Operating Company.
Employees
As of February 29, 2012 we have 57 full-time employees and 45 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
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consult with various public bodies that have responsibility for the environment. Applicants for production licenses are required to submit a summary of their 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 Union’s 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.
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 requires 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
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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 United States Environmental Protection Agency (“EPA”) recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s 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 EPA’s 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 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 second commitment period of the Kyoto Protocol - due to begin on January 1, 2013 - still under negotiation, there is uncertainty as to the precise nature of commitments that will be made by the parties. The newly agreed to Durban Platform renews the possibility of a broader global climate agreement entering into force by 2020, but substantial uncertainties regarding the ultimate structure of such an agreement remain. 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.
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Beginning in 2009, the EPA took a series of steps to begin regulating GHG emissions under the Clean Air Act. As of January 2, 2011, the EPA’s 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, and requiring the permitting of certain GHG emissions sources under the New Source Review and Title V programs (which are administered by state or local governments in certain jurisdictions). For example, 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 produce. 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 Earth’s 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.
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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.
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:
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the location of wells;
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the method of drilling and casing wells;
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the surface use and restoration of properties upon which wells are drilled;
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the plugging and abandoning of wells; and
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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
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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.
Offices
Our principal executive offices are located at 811 Main Street, Suite 2100, 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. Martin’s 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 SEC’s 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, www.sec.gov.
Endeavour International Corporation
Our website is available at 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, the Governance and Nominating Committee and the 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 811 Main Street, Suite 2100, 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
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. Our revenues and long-lived assets by geographic area are included in Note 21 to our consolidated financial statements in “Item 8, Financial Statements and Supplementary Data” 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.
Item 1A.
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,”
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“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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recent and pending acquisitions;
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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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outcome of legal disputes;
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environmental hazards, such as natural gas leaks, oil spills and discharges of toxic gases;
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business strategy and the availability of acquisition opportunities; and
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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 risks and uncertainties, as mentioned in “Item 1A. Risk Factors” and elsewhere in this Annual Report on Form 10-K. Except as required by law,
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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.
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.
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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 prior to the recession. 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, or (ii) 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. The U.S. gas market is heavily impacted by the increased supply from shale drilling, which has served to depress natural gas prices relative to the U.K. market. Prices for oil and gas fluctuate in response to relatively 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;
Endeavour International Corporation
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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 any such 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.
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. 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
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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.
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 operations, particularly through the weakening of the U.S. dollar relative to other currencies.
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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, including the COP 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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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 management’s 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.
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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.
We are involved in litigation related to a terminated acquisition for Marcellus shale play assets, and such litigation, if resolved adversely to us, could have a material adverse effect on us.
On July 17, 2011, we entered into agreements (the “SM Purchase Agreements”) with SM Energy Company and certain other sellers named therein (collectively, “SM Energy”) for the purchase of oil and gas leases, producing properties, geophysical data, a pipeline and related assets in the Marcellus shale play in Pennsylvania (the “SM Acquisition”). On December 14, 2011, we terminated the SM Purchase Agreements based on our conclusion that (i) the title defects we identified, after analyzing SM Energy’s responses to the notice of defects and valuation of the defects, exceeded the contractual threshold of 15% of the applicable purchase price; and (ii) the condition of the pipeline was not in compliance with applicable regulatory standards, which would constitute a material violation of a representation and warranty contained in the applicable SM Purchase Agreement. Following our termination of each of the SM Purchase Agreements, SM Energy filed a lawsuit against us in Texas state court on December 20, 2011 alleging, among other things, breach of contract for refusing to close on the SM Acquisition. SM Energy is seeking an award of unspecified actual damages, including costs and reasonable attorney’s fees, and specific performance to complete the SM Acquisition. If we are unsuccessful in defending against these claims, we may be subject to a range of potential adverse outcomes, including any one, or a combination of, the following: (i) a requirement to close the SM Acquisition for the full SM Purchase Price; (ii) damages in the event SM Energy divests the assets underlying the SM Acquisition for less than the SM Purchase Price; or (iii) other remedies potentially available to SM Energy. While we intend to contest these claims vigorously, we cannot predict with any certainty the outcome of this litigation, and the lawsuit, if resolved adversely to us, could have a material adverse effect on our business, results of operations or financial condition.
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
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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 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, 2011 were undeveloped, and those reserves may not ultimately be developed.
At December 31, 2011, approximately 77% 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
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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 invested before we can market the associated oil or gas of a commercial discovery, 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 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 current producing fields, are 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 operator’s 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.
Endeavour International Corporation
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.
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.
Our business involves many uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.
Our development activities may be unsuccessful for many reasons, including adverse weather conditions (such as storms in the North Sea), cost overruns, equipment shortages, geological issues and mechanical difficulties. Moreover, the successful drilling of a natural gas or oil well does not assure we will realize a profit on our investment. A variety of factors, both geological and market-related, can cause a well to become uneconomical or only marginally economical. In addition to their costs, unsuccessful wells hinder our efforts to replace reserves.
Endeavour International Corporation
Our oil and natural gas exploration and production activities, including well stimulation and completion activities such as hydraulic fracturing, involve a variety of operating risks, including:
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fires;
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explosions;
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low-outs and surface cratering;
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uncontrollable flows of natural gas, oil and formation water;
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natural disasters, such as tropical storms, hurricanes and other adverse weather conditions;
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inability to obtain insurance at reasonable rates;
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failure to receive payment on insurance claims in a timely manner, or for the full amount claimed;
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pipe, cement, subsea well or pipeline failures;
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casing collapses or failures;
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mechanical difficulties, such as lost or stuck oil field drilling and service tools;
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abnormally pressured formations or rock compaction; and
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environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures, encountering naturally occurring radioactive materials, and discharges of brine, well stimulation and completion fluids, toxic gases, or other pollutants into the surface and subsurface environment.
If we experience any of these problems, well bores, platforms, gathering systems and processing facilities could be affected, which could adversely affect our ability to conduct operations. We could also incur substantial losses as a result of:
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injury or loss of life;
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damage to and destruction of property, natural resources and equipment;
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pollution and other environmental damage;
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clean-up responsibilities;
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regulatory investigation and penalties;
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suspension of our operations;
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repairs required to resume operations; and
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loss of reserves.
Offshore operations are also subject to a variety of operating risks related to the marine environment, such as capsizing, collisions and damage or loss from tropical storms, 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 funds available for exploration, exploitation and acquisitions or result in the loss of property and equipment.
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.
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Because experience is 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.
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 assets in the North Sea and our acreage position in the U.S. We intend to finance our future capital expenditures primarily with cash on hand and cash flow from operations. Our cash flow from operations and access to capital is subject to a number of variables, including:
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the level of natural gas and crude oil we are able to produce from existing wells;
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our oil and gas reserves;
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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. Any future bank indebtedness we incur may contain covenants restricting our ability to incur additional indebtedness without the consent of the lenders.
Furthermore, we may not be able to obtain debt or equity financing in the future on terms favorable to us, or at all. 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.
Endeavour International Corporation
Our debt levels could negatively impact our financial condition, results of operations and business prospects.
As of December 31, 2011, we had $469.9 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, any future debt instruments we enter into may contain certain restrictions on our ability to repay other debt.
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.
A change of control may adversely affect our liquidity and require refinancing of certain debt instruments.
Upon certain specified change of control events, the lender under our letter of credit facility may cancel the facility and declare as due and payable any outstanding letters of credit and other outstanding fees. In addition, the indentures governing our senior notes contain similar covenants requiring repayment in the event of a change of control. We cannot assure you we would have sufficient financial resources to purchase the debt instruments for cash or repay the lenders under upon the occurrence of a change of control. 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.
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If the Alba Acquisition is not consummated on or before June 15, 2012, the notes will be redeemed.
Pending the closing of the Alba Acquisition, the net proceeds from 2018 Notes have been placed in an escrow account. If the Alba Acquisition is not closed on or prior to June 15, 2012, or the COP Purchase Agreement is terminated earlier, the funds in the escrow account, together with additional funds necessary to complete the redemption, will be used to redeem all of the 2018 Notes at a redemption price of 101% of the escrow amount, plus accrued and unpaid interest from the issuance date of the notes to the redemption date. The amount placed into escrow upon the closing of this offering is less than the full amount that will be required to redeem the 2018 Notes, and we will be required to provide such additional cash to use for such redemption. If such an event were to occur, we would utilize commitments under a senior secured bridge facility to fund the COP Acquisition and the repayment of the Senior Term Loan.
Risks related to environmental and other regulations
Increased tax rates contained in the 2011 U.K. Finance Bill may materially and adversely impact our financial condition.
Our free cash flow and financial condition are impacted by the amount of taxes we are required to pay in each of the jurisdictions in which we operate. In July 2011, a tax increase was enacted by the U.K. government that raised the existing supplementary charge on profits from North Sea oil and gas production from 20% to 32%, effective March 24, 2011. This supplementary charge is in addition to the existing corporation tax rate of 30%. Any increase in the taxes we are required to pay, or the recognition of an additional non-cash charge resulting from this tax increase contained in the 2011 U.K. Finance Bill could materially and adversely affect our financial condition and results of operations.
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.
Endeavour International Corporation
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 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 from tight formations. We routinely utilize hydraulic fracturing techniques in many of our 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. In the U.S., 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 Act’s 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 EPA’s recent decision.
Endeavour International Corporation
At the same time, the White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic-fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014. In addition, the U.S. Department of Energy is conducting an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic-fracturing completion methods. Additionally, certain members of the Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, the U.S. Securities and Exchange Commission to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing, and the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. Legislation also has been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act or other regulatory mechanism.
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, Colorado, Pennsylvania, 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 chemical disclosure. In addition, Texas adopted a law in June 2011 requiring disclosure to the Railroad Commission of Texas and the public of certain information regarding chemical ingredients and additives used in the hydraulic fracturing process. The Railroad Commission of Texas has issued regulations to implement these disclosure requirements. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. In the event state, local, or municipal legal restrictions are adopted in areas where we are currently conducting, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling of wells.
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.
Endeavour International Corporation
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 (“GHG”) 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. At the recent Conference of the Parties, an agreement was reached to establish a second commitment period under the Kyoto Protocol beginning on January 1, 2013. While the exact emission reduction commitments that will be made by the Parties are not yet known, commitments to further emission reductions could negatively impact demand for our products. In addition, the Parties to the Framework Convention on Climate Change agreed to the Durban Platform, an approach to develop a new legally binding agreement on climate change by 2015 that will enter into force by 2020. While this agreement will not impact our operations in the near term, a new agreement on global climate change could further reduce demand for the oil and natural gas that we produce.
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. Entities involved in the production and distribution of oil and natural gas currently subject to the requirements of Subpart W of the Mandatory Reporting of Greenhouse Gases Rule, and must report 2011 GHG emissions to the EPA. These reports are in addition to those required under Subpart Y for petroleum refineries. In addition, 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. At the state level, California has adopted regulations to implement the cap and trade program called for in the Global Warming Solutions Act, and beginning in 2015, distributors of transportation, natural gas, and other fuels will be subject to the requirements of the program. 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.
Endeavour International Corporation
Recently proposed rules regulating air emissions from oil and gas operations could cause us to incur increased capital expenditures and operating costs.
On July 28, 2011, the EPA proposed rules that would establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s proposed rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The EPA’s proposal would require the reduction of VOC emissions from oil and natural gas production facilities by mandating the use of “green completions” for hydraulic fracturing, which requires the operator to recover rather than vent the gas and natural gas liquids that come to the surface during completion of the fracturing process. The proposed rules also would establish specific requirements regarding emissions from compressors, dehydrators, storage tanks, and other production equipment. In addition, the rules would establish new leak detection requirements for natural gas processing plants. The EPA will receive public comment and hold hearings regarding the proposed rules and must take final action on them by April 3, 2012. If finalized, these rules could require a number of modifications to our operations, including the installation of new equipment. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.
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 Reform and Consumer Protection Act (the “Act”), was signed into law by the President on July 21, 2010 and requires the Commodity 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
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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 have a material, adverse effect on us, our financial condition and results of operations.
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, 2011 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
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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 stockholders’ 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 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 29, 2012, we had approximately 38.2 million shares of common stock outstanding. Of those shares, approximately 0.8 million shares are restricted shares subject to vesting periods of up to three years. The remainder of these shares is freely tradable.
In addition, 0.2 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
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of presently outstanding options and warrants outside our employee incentive plans. Also 7.3 million shares are issuable upon the conversion of our 5.5% Convertible Notes, based upon the conversion price of $18.51 per share; 4.2 million shares are issuable upon conversion of our Series C Preferred Stock, based upon the conversion price of $8.75 per share; and 5.1 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 corporation’s board of directors before the person first became an interested stockholder.
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.
Item 1B. Unresolved Staff Comments
None.
Item 2.
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
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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 2011, 2010 and 2009:
We do not own any drilling rigs, and all of our drilling activities are conducted by independent drilling contractors.
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Productive Well Summary
At December 31, 2011, our productive wells included the following:
Reserves
Our proved oil and gas reserves at December 31, 2011, 2010 and 2009 included the following:
At December 31, 2011, the Grand Cane field, a gas field in the Haynesville area, represented more than 15% of our proved reserves, with 3.8 MMBOE of proved reserves. At December 31, 2009, the Woodardville field, a gas field in the Haynesville area, represented more than 15% of our proved reserves, with 2.2 MMBOE of proved reserves.
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 Rochelle field in 2011, 2010 and 2009 and the Columbus field in 2009. Rochelle had 8.2 MMBOE, 9.4 MMBOE and 6.3 MMBOE of proved reserves at December 31, 2011, 2010 and 2009. The Columbus field had 1.8 MMBOE of proved reserves at December 31, 2009.
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Our proved undeveloped reserves are primarily related to our development projects in the U.K. and the results of successful exploration drilling in the U.S. We expect our proved undeveloped reserves in the U.K. to become proved developed reserves over the next two years as development plans are completed and production commences on existing development projects at Bacchus and Rochelle. In the U.S., we have 8 wells that are either being completed or awaiting completion at December 31, 2011, including our four vertical pilot tests in Montana that may or may not be completed. If completed, the proved undeveloped reserves associated with these wells will transfer to proved developed reserves. See Note 8 to our consolidated financial statements in “Item 8, Financial Statements and Supplementary Data” 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, 2011, 2010 and 2009 included the following:
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 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
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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.
Our oil and gas reserve estimates (and the estimates of the oil and gas reserves that we expect to acquire in the COP Acquisition) were prepared by our internal reservoir engineers and audited by independent reserve engineers, Netherland, Sewell & Associates, Inc. (“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 the quantity of oil and gas reserves and provide our estimates, analysis and data to our independent reserve engineers.
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.. 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 SEC’s 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.
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Acreage
The following table sets forth certain information regarding our developed and undeveloped acreage as of December 31, 2011, in the areas indicated.
As of December 31, 2011, we had approximately 26,410, 36,933 and 30,686 net acres in the U.K. and U.S combined that are scheduled to expire by December 31, 2012, 2013 and 2014, 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, where we have 29,628 net acres and have suspended operations. It also includes approximately 40,000 net acres in Montana that will expire in 2012-2014, where we have rights to extend certain leases for additional five years. We have a total of 94,353 net acres in Montana. Together with our partners, we are completing core and log data analysis from our four vertical pilot wells in Montana and plan to define possible horizontal re-entry target zones for testing during 2012. 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 on 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.
At December 31, 2011, the Grand Cane field, in the Haynesville area, represented more than 15% of our proved reserves. Grand Cane is a gas field and represented 662 MMcf and 48 MMcf of our gas sales in 2011 and 2010, respectively. At December 31, 2009, the Woodardville field, in the Haynesville area, represented more than 15% of our proved reserves. Woodardville is a gas field and represented 2,508 MMcf, 1,865 MMcf and 204 MMcf of our gas sales in 2011, 2010 and 2009, respectively.
At December 31, 2009, the Goldeneye field, in the U.K., represented more than 15% of our proved reserves. The Goldeneye field in the U.K. had gas sales volumes of 8 MMcf, 2,990 MMcf, and 3,670 MMcf in 2011, 2010 and 2009, respectively. The Goldeneye field also had oil sales volumes of 85 Mbbls and 108 Mbbls in 2010 and 2009, respectively.
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Item 3.
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.
Terminated Acquisition of Marcellus Assets
On July 17, 2011, we entered into agreements with SM Energy Company and certain other sellers named therein for the purchase of oil and gas leases, producing properties, geophysical data, a pipeline and related assets in the Marcellus shale play in Pennsylvania for aggregate consideration of approximately $110 million (the “SM Purchase Price”). We terminated the agreements on December 14, 2011, based on our conclusion that (i) the title defects we identified, after analyzing SM Energy’s responses to the notice of defects and valuation of the defects, exceeded the contractual threshold of 15% of the purchase price for the applicable asset group ($85 million); and (ii) the condition of the pipeline was not in compliance with applicable regulatory standards, which would constitute a material violation of a representation and warranty contained in the applicable SM Purchase Agreement.
SM Energy filed a lawsuit against us in Texas state court on December 20, 2011 alleging that we breached the SM Purchase Agreements by terminating them and refusing to close on the transactions. Specifically, SM Energy has alleged, among other things, that most of our asserted title defects are without merit and, in any event, would not exceed 15% of the applicable purchase price. SM Energy seeks the award of unspecified actual damages, including costs and reasonable attorney’s fees, and specific performance. On January 17, 2012, we filed an answer and counterclaim denying the allegations and seeking the return of our $6 million deposit, which we believe we are entitled to recover pursuant to the terms of the SM Purchase Agreements, and for the damages that we suffered as a result of SM Energy’s misrepresentations. We intend to contest the case vigorously.
Item 4.
Item 4. Mine Safety Disclosures
Not applicable.
Endeavour International Corporation
Part II
Item 5.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
On March 15, 2011, we completed the transfer of the primary listing for our common stock from the NYSE-Amex to the New York Stock Exchange (“NYSE”) under the symbol “END.” Our common stock is also listed 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, 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 continued 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 company’s trading metrics.
All share information and prices per share discussed in this Annual Report have been restated to reflect the share consolidation.
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, and prior to March 15, 2011, the NYSE-Amex. These quotations represent inter-dealer prices, without retail mark-up, markdown or commission, and may not represent actual transactions.
Holders
As of February 29, 2011, the number of holders of record of our common stock was 144. We believe that there are a number of additional beneficial owners of our common stock who hold such shares in street name.
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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
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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 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.
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, 2011. 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 of this subsidiary are classified as discontinued operations for all periods presented.
The following data should be read in conjunction with “Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
This Management’s 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 independent oil and gas company engaged in the production, exploration, development and acquisition of crude oil and natural gas in the U.K. North Sea and U.S. Onshore. Our 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 oil and gas reserves through improved drilling, completion and operating 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 development assets, which have large potential reserves but long production-cycles, with current production from the North Sea assets we expect to acquire in the COP Acquisition and a portfolio of onshore assets in the U.S. that have lower development 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 major development projects in the U.K. sector of the North Sea - specifically, Bacchus and Rochelle - 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 first quarter of 2012 and first production from the Rochelle area expected in the fourth quarter of 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.
Our primary focus in the U.S. is onshore unconventional oil and gas shale developments targeting reserve and production growth in the Haynesville and Marcellus areas. In the Haynesville area, we have approximately 7,100 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 18,400 net acres in Pennsylvania
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located between two of the most active parts of the Marcellus play. We also have interests in approximately 94,400 net acres in the emerging Heath Shale Oil Play in Montana where we are evaluating the results of four pilot wells and ongoing technical work. The results from our pilot wells and ongoing technical work will determine the pace and scope of our subsequent exploration and development initiatives in this play.
As of December 31, 2011, our estimated proved reserves were 22.7 MMBOE, up 23% from 18.4 MMBOE as of December 31, 2010, of which approximately 55% were located in the U.K. and approximately 45% were located in the U.S., and 23% of which were proved developed reserves. As of December 31, 2011, the properties that we expect to acquire in the COP Acquisition contained approximately 19.5 MMBOE of proved reserves.
In 2012, we intend to expand upon our foundation of U.K. assets by moving existing development assets towards their first production and integrating the assets we expect to acquire in the COP Acquisition. We also intend to maintain our interests in both established and emerging U.S. onshore resource plays. Specifically, during 2012, we intend to focus on achieving initial production from the Bacchus oil field and the Rochelle gas field in the North Sea while integrating the assets we expect to acquire in the COP Acquisition and completing the evaluation of our assets in the Heath Shale Oil Play.
Our realized price per BOE, before derivatives, increased from $47.72 per BOE in 2010 to $48.67 per BOE in 2011. Our revenues have decreased from $71.7 million for the year ended December 31, 2010 to $60.1 million for 2011 primarily as a result of lower production volumes from our producing assets partially offset by higher commodity prices. Increases in prices in the first half of 2010, largely as a result of oil prices climbing to record levels in the summer of 2010 and gas prices in our markets improving, helped our revenue grow to $71.7 million in 2010, however the subsequent decrease in commodity prices and normal declines in our production led to a substantial reduction in our revenues for the year ended December 31, 2011.
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 and exposure to emerging resource plays in 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 were primarily used to accelerate our development projects and fund our acquisition of an additional 20% interest in the Bacchus field, which closed in February 2011.
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 $(39.3) million in 2011 versus $17.0 million in
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2010 and $55.7 million in 2009. Adjusted EBITDA was $24.7 million in 2011, as compared to $124.8 million in 2010 and $64.6 million in 2009. These fluctuations in Adjusted EBITDA are primarily due to the changes in our realized prices, production volumes, interest expense and operating costs. In addition, Adjusted EBITDA for 2010 includes the gain on the sale of our Cygnus asset.
For 2011, net loss to common stockholders was $(133.0) million, or $(3.70) per diluted share. This net loss includes a $65.7 impairment related to our U.S. properties and increased interest expense resulting from borrowings under existing debt agreements and issuances of new debt obligations. Net income to common stockholders was $54.3 million for 2010, or $1.95 per diluted share, including a gain on the Cygnus sale of $87.2 million. Net loss to common stockholders for 2009 was $(62.2) million, 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 loss as adjusted for 2011 was $(75.6) million. Net income as adjusted for 2010 was $57.4 million, as compared to net income as adjusted of $38.3 million in 2009.
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 our company’s 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, adjusted earnings before interest, taxes, depreciation, depletion and amortization (“Adjusted EBITDA”) and net income as adjusted.
For definitions of net income as adjusted and Adjusted EBITDA, and a reconciliation of these non-GAAP measures to the appropriate GAAP measure, please see “Non-GAAP Financial Measures and Reconciliations.”
Results of Operations
Our revenues and sales volumes have fluctuated significantly during the last three years primarily due to the following:
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Our revenues have decreased from $71.7 million for the period ended December 31, 2010 to $60.1 million as of December 31, 2011, primarily due to decreases in U.K. gas production at our largest producing gas field - Goldeneye - and decreases in U.S. natural gas prices, partially offset by increased oil prices.
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As a result of substantially increased oil prices and 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.
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•
U.S. production reflects the results of our purchase of producing assets in October 2009 and ongoing drilling in 2010 and 2011, primarily in the Haynesville area.
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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.
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(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, net income 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, a small variation in supply or demand may significantly impact the market prices for these commodities. As a result, we utilize various oil and gas derivative instruments to achieve more predictable cash flows by reducing our exposure to price fluctuations. In addition, our net income can be significantly affected by various non-cash items, such as unrealized gains and losses on our derivatives, impairment of oil and gas properties, currency impact of long-term liabilities and deferred taxes.
The markets in which we sell our oil and natural gas also materially impact our revenues and cash flows. Oil trades on a worldwide market, and, consequently, price movements for all types and grades of crude oil generally trend in the same direction and within a relatively narrow price range. However, natural gas prices vary among geographic areas as the prices received are largely impacted by local supply and demand conditions as the global transportation infrastructure for natural gas is still developing. As such, the oil we produce and sell is typically sold at prices in line with global prices, whereas our natural gas is to a large extent impacted by regional supply and demand issues and to a lesser extent by global fuel prices, including oil and coal. With the increase in our U.S. operations and the shut-in of the Goldeneye field, the majority of our gas sales are in the U.S. The U.S. gas market is heavily impacted by the increased supply from shale drilling, which has served to depress natural gas prices relative to the U.K. market.
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 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. These measures include, among others, Adjusted EBITDA and net income (loss), as adjusted.
For definitions of net income (loss), as adjusted and Adjusted EBITDA, and a reconciliation of these non-GAAP measures to the appropriate GAAP measure, please read “Non-GAAP Financial Measures and Reconciliations.”
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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 19 to our consolidated financial statements in this Annual Report on Form 10-K for additional information on these derivatives.
Operating Expenses
For 2011, operating expenses increased to $17.7 million as compared to $15.3 million for 2010, primarily due to increased U.S. workover expense and increases in transportation expense and production taxes as a result of increased U.S. sales volumes. Operating costs per BOE increased to $14.31 per BOE for 2011 from $10.22 per BOE for 2010. The increase in operating costs per BOE is due to the impact of both the increases in the dollar levels of operating expenses and the decreased volumes discussed above.
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.
DD&A and Impairment of Oil and Gas Properties
Decreased depreciation, depletion and amortization (“DD&A”) expense from 2009 to 2010 and again in 2011 reflects the result from impairments in oil and gas properties in early 2010 and during 2011 and decreasing production volumes.
In 2011, 2010 and 2009, we recorded $65.7 million, $7.7 million and $43.9 million, respectively, in impairment of oil and gas properties, pre-tax, through the application of the full cost ceiling test at the end of each quarter. The 2011 impairment was primarily related to declines in U.S. gas prices and the impact of our determination that the likely economic returns in the future would not warrant further investment in our test wells in the Alabama area. Our decision to discontinue activities in that area resulted in the reclassification of related amounts as being evaluated for full cost accounting purposes.
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The impairment during 2010 was also 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 U.K. properties as a result of steep declines in commodity prices.
General and Administrative (“G&A”) Expenses
Our G&A expenses decreased from $18.4 million in 2010 to $17.9 million for 2011 as a result of a decrease in employee compensation expense, partially offset by an increase in consulting costs. The increase in G&A expense from $17.0 million in 2009 to $18.4 million in 2010 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:
Interest Expense and Other
The increase in interest expense from $34.6 million in 2010 to $45.3 million in 2011 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 with the issuance of our Subordinated Notes and continuing through 2011 with amendments to our Senior Term Loan and issuance of our 5.5% Convertible Senior Notes.
In July 2011, we issued $135 million aggregate principal amount of our 5.5% Convertible Senior Notes due 2016. Also, in July 2011, we amended our Senior Term Loan to provide for an increase of $75 million in the borrowings available under the Senior Term Loan. In connection with the increase, we drew down the full additional amounts available and our quarterly scheduled amortization payments on the Senior Term Loan increased. During 2010, we borrowed $25 million under the Junior Facility and $160 million under the Senior Term Loan. The proceeds from the Senior Term Loan were utilized to repay all outstanding balances under
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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 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 2011, the interest expense from our outstanding debt was primarily related to increased borrowing under our Senior Term Loan and the 5.5% Convertible Senior Notes issued July 2011. The Senior Term Loan was amended in July 2011 to provide for an increase of $75 million in available borrowings. In connection with the increase, we drew down the full additional amounts available and our quarterly scheduled amortization payments increased.
During 2011, we recorded $47.4 million in interest expense related to our debt and $12.6 million in deferred financing expense; offset by $14.7 million in capitalized interest. 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.
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Income Taxes
The following summarizes the components of tax expense (benefit):
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. During 2011, $25.4 million of the tax expense is attributable to the increase in the supplemental corporate tax rate due to a tax law change, enacted by the U.K. government, in July 2011, that raised the existing supplementary charge on profits from North Sea oil and gas production from 20% to 32%. Income tax benefit decreased in 2010 as a result of the increase in U.K. income due primarily to an absence of an impairment in oil and gas properties 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.
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The current tax expense (benefit) in both 2011 and 2010 is related to Petroleum Revenue Tax on our Alba field in the U.K.
Liquidity and Capital Resources
Capital Expenditures
We spent $218.2 million, $106.3 million and $88.6 million on our oil and gas capital program, excluding acquisitions, in 2011, 2010 and 2009, respectively. We spent $90.5 million in 2011, $23.9 million in 2010 and $16.5 million in 2009 on development activities in both the U.S. and U.K. We also spent $127.7 million, $82.4 million and $72.1 million in 2011, 2010 and 2009, respectively, on exploration and appraisal activities, primarily related to our Bacchus project and new operations in the U.S. In addition, we incurred $51.5 million, $43.7 million and $32.2 million during 2011, 2010 and 2009, respectively, related to our acquisition of additional interest in Bacchus during 2011 and various acquisitions of U.S. properties in 2010 and 2009.
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, including production from the assets to be acquired in the COP Acquisition, will fund our capital expenditure program for 2012. In turn, our capital program should allow additional cash flows to be generated as Bacchus begins production.
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
Endeavour International Corporation
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 lead 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 include 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.
Cash flow from operations decreased to $(39.3) million for 2011 from $17.0 million for 2010 due to lower oil and gas revenue resulting from lower production, and working capital changes, lower gas prices in the U.S. and increased interest expense following our issuance of the Senior Term Loan in third quarter of 2010, which was increased in the third quarter of 2011, and the issuance of the 5.5% Convertible Senior Notes in 2011. Cash flow from operations decreased to $17.0 million for 2010 from $55.7 million for 2009 primarily due to lower production, lower gas prices in the U.S., 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, and lower realizations from our commodity derivatives as higher priced oil collars expired at the end of 2009, partially offset by higher oil prices.
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.
Operating, Investing and Financing Activities include the net cash flows from our discontinued operations which were sold in May 2009. For the year ended December 31, 2009, our discontinued operations had net cash flows provided by (used in) operating activities of approximately $ 9.0 million. These net cash flows were substantially offset by net cash used by investing activities of approximately $ 9.0 million during 2009.
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 were utilized to partially fund our capital needs in 2011.
See Note 12 and Note 15 to the Consolidated Financial Statements herein for discussion of our recent issuance of debt and equity. At December 31, 2011, we had $469.9 million in outstanding debt. As more fully described in Note 12 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.
On January 18, 2012, we and our wholly owned subsidiary, Endeavour Energy UK Limited (“EEUK”), entered into a Consent and Fourth Amendment to Credit Agreement, U.S. Security Agreement and Subsidiaries Guaranty (the “Amendment”) with Cyan Partners, LP, as administrative agent, and certain lenders party thereto (the “Senior Term Loan”). The primary provisions of the Amendment include the (i) consent and approval for the Company to issue up
Endeavour International Corporation
to $500 million of senior unsecured notes, (ii) exclusion of up to $500 million of senior unsecured notes, if any, from certain financial covenants and (iii) amendments to certain existing financial covenants, including a reduction in the minimum consolidated EBITDAX requirement to $20,000,000 for each of the test periods ended December 31, 2011 and March 31, 2012 and an extension of the increase in the minimum PDP coverage ratio from 0.25:1.00 to 0.50:100 after March 31, 2012.
After considering this amendment, we were in compliance with all financial and restrictive covenants of our debt obligations as of December 31, 2011.
On February 23, 2012, we closed the private placement of $350 million aggregate principal amount of 12% first priority notes due 2018 (the “First Priority Notes”) and $150 million aggregate principal amount of 12% second priority notes due 2018 (the “Second Priority Notes,” and, together with the First Priority Notes, the “2018 Notes”). Each series of 2018 Notes was priced at 96% of par, at a yield to maturity of 12.975% for the First Priority Notes and 12.954% for the Second Priority Notes, respectively. We intend to use the net proceeds from the 2018 Notes to fund the COP Acquisition, to repay all amounts outstanding under our Senior Term Loan due 2013 and for general corporate purposes. Prior to the closing of the acquisition in the North Sea, the net proceeds of the offering are held in an escrow account. The COP Purchase Agreement provides for the possibility that the COP Acquisition may close in multiple stages. If we close the Alba Acquisition, which constitutes the majority of the value in the COP Acquisition, the full amount of proceeds will be released from escrow.
We have also received a commitment for a senior secured bridge facility; however, we would only expect to draw on the facility to the extent we are otherwise unable to fund the COP Acquisition and the repayment of the Senior Term Loan, including with the proceeds of the 2018 Notes and cash on hand.
Outlook
2012 Planned Capital Expenditures
We expect that our total capital expenditure budget for 2012 will be between $150 million and $175 million. We expect to spend approximately $125 million to $150 million of the total 2012 budget in the U.K., primarily on the advancement of our development projects. The acquisition of the ConocoPhillips assets would add another $20 million-$25 million to Endeavour’s capital budget, upon completion of the transaction. Capital expenditures for Bacchus will be our initial priority, as we plan to reach first production during the first quarter. With our existing cash position, cash flows from existing production and either the start up of production from Bacchus or the completion of the COP Acquisition, we believe we have sufficient cash flows to complete the necessary development program for the Rochelle area to reach first production in the fourth quarter of 2012. We expect to spend the remainder of our 2012 capital budget in the U.S. to evaluate our Heath Shale Oil Play pilot wells, to maintain our acreage positions and to fulfill minor drilling commitments. Our 2012 capital expenditure budget is subject to change depending on a number of factors, including the availability and costs of drilling and completion equipment, crews, economic and industry conditions, prevailing and anticipated prices for oil and gas, the availability of sufficient capital resources, drilling success and other normal factors affecting the oil and gas industry.
Endeavour International Corporation
We intend to fund our 2012 capital expenditures primarily through cash on hand and cash flow generated from operations, including cash flow from the assets to be acquired in the COP Acquisition. The majority of our cash on hand was generated through borrowings under our secured 15.0% senior term loan due 2013 of our principal U.K. subsidiary and the July 2011 offering of our 5.5% Convertible Senior Notes due 2016. The proceeds from the offering of our 5.5% Convertible Notes were originally expected to fund our acquisition of certain Marcellus shale play assets, but the transactions were not consummated and we are currently involved in litigation with the sellers.
2012 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 necessary. We strive to synchronize our capital expenditures with our cash flow and cash on hand. The combination of our available cash on hand and cash flow from operations funded our capital expenditure program in 2011. During the first quarter of 2012, we expect to complete the COP Acquisition, conserve capital and focus on two development projects in the U.K. - Bacchus and Rochelle. Capital expenditures for Bacchus currently have our highest priority as we plan to reach first production early next year. Once Bacchus begins producing, we expect to earmark a substantial portion of the cash flows from its production to complete the necessary development program for the Rochelle area to allow first production during the second half of 2012. Remaining capital will be divided among our smaller commitments, including evaluation of our Montana vertical pilot wells and complete drilling in the Marcellus and Haynesville areas. The full extent of our U.S. drilling program will be determined by our anticipated available cash and any changes in the U.S. natural gas markets and prices.
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 and oil production and our commodity derivative positions.
As we pushed our U.K. and U.S. capital programs forward in 2011, we reviewed opportunities to add resources that fit within our strategic plan at reasonable rates of return for our shareholders, including the COP Acquisition. We expect our production will grow from 2011 levels once we consummate the COP Acquisition, achieve first production from Bacchus and commence production from Rochelle. Each of these operational activities will have an impact on our production as follows:
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Initial Production Date of the Bacchus Field - Drilling at the first of three planned production wells has reached total depth. The liner for the well has been cemented in place and preparations are being made to run the production string. The operator has announced that production is expected to begin in the first quarter of 2012. The precise initial production date, rate of production and how long it may take for Bacchus to reach full production from all three wells are key variables to our overall production levels.
Endeavour International Corporation
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Closing Date of the COP Acquisition - The assets to be acquired in the COP Acquisition produced at an average of approximately 11,000 BOE/d for the year ended December 31, 2011. After giving pro forma effect to the COP Acquisition, our production for the year ended December 31, 2011 would have been approximately 14,400 BOE/d. Further, we expect that following the consummation of the COP Acquisition, oil production will increase to approximately 84% of our total production. We expect to close the Alba Acquisition in the first quarter of 2012.
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Initial Production Date of the Rochelle Field - We are working to complete engineering and procure long-lead time equipment in the Rochelle field. We have contracted for a drilling rig which is expected to arrive in the spring of 2012 to commence drilling of the two planned production wells. The operator of the Scott platform, Rochelle’s off-take solution, has commenced the required modifications to prepare it for production from the Rochelle area in 2012. First production from Rochelle is planned for the fourth quarter of 2012.
Non-GAAP Financial Measures and Reconciliations
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, such as income (loss) as adjusted and Adjusted EBITDA, 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. We define “net income (loss), as adjusted” as net income (loss), without the effect of impairments, derivative transactions and currency impacts of deferred taxes. We define “Adjusted EBITDA” as net income (loss) before interest, taxes, depreciation, depletion and amortization adjusted for the early termination of commodity derivatives and income (loss) from discontinued operations (“Adjusted EBITDA”) 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.
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 and Adjusted EBITDA 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 and Adjusted EBITDA 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.
Endeavour International Corporation
(1) Net of tax benefits of none, none and $(15,666) in 2011, 2010 and 2009, respectively.
(2) Net of tax (expense) benefit of $(1,891), $5,471 and $(21,896) in 2011, 2010 and 2009, respectively.
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, 2011:
Endeavour International Corporation
(1) Interest on our 11.5% convertible bonds and subordinated notes is added to the outstanding principal balance each quarter and reflected as due upon maturity.
See Note 23 “Subsequent Events” to our consolidated financial statements under “Item 8, Financial Statements and Supplementary Data” for discussion of our plans to repay the Senior Term Loan in its entirety with proceeds from a senior note offering.
Off-Balance Sheet Arrangements
At December 31, 2011, 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 relating to a dispute with the rig operator. On June 6, 2011, we entered into a settlement agreement with the rig operator whereby the parties were mutually released from all future claims. We incurred costs of $14 million related to the settlement, which are included in capital expenditures
We also have a rig commitment for the drilling of the two Rochelle production wells in the spring of 2012.
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.
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:
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the future net cash flows related to estimated production of proved reserves;
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the effect of derivative instruments that qualify as cash flow hedges;
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the lower of cost or estimated fair value of unproved properties; and
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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 2011 and 2010 and the year-end price for 2009.
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.
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 company’s 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.
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 asset’s fair value.
At December 31, 2011, 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 2011 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, 2011.
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.
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 derivative’s 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.
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 derivative’s fair value. Any ineffective portion of the derivative instrument’s 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 employee’s 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, 2011, we had approximately 1.2 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
Endeavour International Corporation
or liability, we generally utilize an income valuation approach. This approach utilizes management’s 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 management’s expectation of future conditions that are often outside of management’s control. However, assumptions used reflect a market participant’s view of long-term prices, costs and other factors, and are consistent with assumptions used in our business plans and investment decisions.
Item 7A.
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.
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, 2011, we had the following commodity derivative instruments outstanding:
(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, 2011 was $1.54 to £1.00.
The fair value of our commodity derivatives was $1.2 million at December 31, 2011.
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.
Endeavour International Corporation
Item 8.
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 (the Company) as of December 31, 2011 and 2010, and the related consolidated statements of operations, stockholders’ equity and comprehensive income (loss), and cash flows for each of the years in the three-year period ended December 31, 2011. These consolidated financial statements are the responsibility of the Company’s 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 consolidated 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, 2011 and 2010, and the results of their operations and their cash flows for each of the years in the three- year period ended December 31, 2011, 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 its reserves estimates and related disclosures as a result of adopting the new oil and gas reserve estimation and disclosure requirements.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Endeavour International Corporation’s internal control over financial reporting as of December 31, 2011, 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 7, 2012 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
/s/ KPMG LLP
Houston, Texas
March 7, 2012
Endeavour International Corporation
Consolidated Balance Sheets
(Amounts in thousands)
See accompanying notes to condensed consolidated financial statements.
Endeavour International Corporation
Consolidated Balance Sheets
(Amounts in thousands)
See accompanying notes to condensed consolidated financial statements.
Endeavour International Corporation
Consolidated Statement of Operations
(Amounts in thousands, except per share data)
See accompanying notes to condensed consolidated financial statements.
Endeavour International Corporation
Consolidated Statement of Cash Flows
(Amounts in thousands)
See accompanying notes to condensed consolidated financial statements.
Endeavour International Corporation
Consolidated Statement of Stockholders’ Equity
(Amounts in thousands)
See accompanying notes to condensed consolidated financial statements.
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:
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estimates of proved oil and gas reserves,
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estimates as to the expected future cash flow from proved oil and gas properties,
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estimates of future dismantlement and restoration costs,
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estimates of fair values used in purchase accounting and
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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.
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, 2010, restricted cash represented amounts held in escrow as collateral for lines of credit associated abandonment liabilities related to our U.K. properties.
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:
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the future net cash flows related to estimated production of proved reserves;
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the effect of derivative instruments that qualify as cash flow hedges;
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the lower of cost or estimated fair value of unproved properties; and
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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 2011 and 2010 and the year-end price for 2009.
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.
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
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.
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.
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
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 company’s 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 asset’s fair value.
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
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
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 accounted for more than 10% of revenue for the year ended December 31, 2011: Chevron North Sea Ltd, Shell U.K. Limited, and Hess Limited. 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 JW Operating Company.
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
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reduce our exposure to declines in the market prices of crude oil and natural gas that we produce and sell,
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reduce our exposure to increases in interest rates, and
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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,
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
depends on the intended use of the derivative and the resulting designation. This evaluation is determined at each derivative’s 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, 2011 and 2010, 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 derivative’s fair value. Any ineffective portion of the derivative instrument’s 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-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, 2011, our derivative instruments do not require either side to maintain collateral or margin accounts.
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
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 date, based on the calculated fair value of the award, and is recognized as general and administrative expense over the employee’s 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.
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
It is our policy to use authorized but unissued shares of stock when stock options are exercised. At December 31, 2011, we had approximately 1.2 million additional shares available for issuance pursuant to our existing stock incentive plan.
Adoption of New Accounting Standards
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:
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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:
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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:
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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.
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Fair value-New, expanded disclosures are required for recurring or nonrecurring fair-value measurements and the reconciliation of specific fair value measurements.
We are currently reviewing the following new 2011 standards to determine their effects on our results of operations or financial position:
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Fair Value-In May 2011, the Financial Accounting Standards Board (“FASB”) issued a new accounting standard on fair value measurements that clarifies the application of existing guidance and disclosure requirements, changes certain fair value measurement principles and requires additional disclosures about fair value measurements. The standard is effective for interim and annual periods beginning after December 15, 2011. Early adoption is not permitted. We do not expect the adoption of this accounting guidance to have a material impact on our consolidated financial statements and related disclosures.
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
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Comprehensive Income-In June 2011, the FASB issued guidance impacting the presentation of comprehensive income. The guidance eliminates the current option to report components of other comprehensive income in the statement of changes in equity or in a footnote to the financial statements. The guidance is intended to provide a more consistent method of presenting non-owner transactions that affect an entity’s equity. The guidance is effective for interim and annual periods beginning on or after December 15, 2011. We do not expect adoption of the comprehensive income presentation to have an impact on our financial position or results of operations.
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Goodwill-In September 2011, the FASB amended the previously issued guidance on testing goodwill for impairment. The revised guidance provides entities with an option of performing a qualitative assessment prior to calculating the fair value of the reporting unit. The amended guidance is effective for annual and interim goodwill impairment tests that will be performed for fiscal years beginning after December 15, 2011. We do not expect the adoption of this amended guidance for goodwill impairment testing to have an impact on our financial position or on our consolidated financial statements and related disclosures.
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 $47.0 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 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:
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
Note 4 - Comprehensive Income (Loss)
The following summarizes the components of comprehensive loss:
The components of accumulated other comprehensive income (loss) are:
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
Note 5 - 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.
At December 31, 2011, total compensation cost related to nonvested awards not yet recognized was approximately $ 5.1 million and is expected to be recognized over a weighted average period of less than two years. For the year ended December 31, 2011, we included approximately $ 1.1 million of stock-based compensation in capitalized G&A in property and equipment.
The fair value of each option award is estimated on the date of grant using the Black-Scholes option-pricing model. We did not grant any options during 2011 and 2010. The weighted average grant-date fair value of options granted during 2009 was $0.25. The following summarizes the weighted average of the assumptions used in the option-pricing model and the method for determining the assumptions:
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
Stock Options
Information relating to stock options, including notional stock options, is summarized as follows:
Of options granted during 2009, 0.2 million options 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, 2011 is summarized as follows:
Restricted Stock
At December 31, 2011, 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.
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
Status of the restricted shares as of December 31, 2011 and the changes during the year ended December 31, 2011 are presented below:
Non-Cash stock-based compensation is recorded in G&A expenses or capitalized G&A as follows:
Note 6 - 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.
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
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:
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
Note 7 - Prepaid Expenses and Other Current Assets
Prepaid expenses and other current assets consisted of the following:
Note 8 - Property and Equipment
Property and equipment included the following:
The costs not subject to amortization include
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values assigned to unproved reserves acquired,
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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
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other seismic and geological and geophysical costs.
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
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 and Bacchus projects.
The following is a summary of our oil and gas properties not subject to amortization as of December 31, 2011:
During 2011, 2010 and 2009, we capitalized $13.3 million, $13.1 million and $7.8 million, respectively, in certain directly related employee costs. During 2011, 2010 and 2009, we capitalized $14.7 million, $3.9 million and $3.1 million, respectively, in interest.
During 2011, 2010 and 2009, we recorded $65.7 million, $7.7 million and $43.9 million, respectively, of impairment through the application of the full cost ceiling test. The 2011 impairment was primarily related to declines in U.S. gas prices and the impact of our determination that the likely economic returns in the future would not warrant further investment in our test wells in the Alabama area. Our decision to discontinue activities in that area resulted in the reclassification of related amounts as being evaluated for full cost accounting purposes.
The impairment during 2010 was also 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 U.K. properties as a result of steep declines in commodity prices.
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
Assets Acquisitions
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 operator’s 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. During the third quarter of 2011, we completed our analysis of our test wells in the Alabama area and determined that the likely economic returns in the future would not warrant further investment and therefore reclassified these amounts as evaluated for full cost accounting purposes.
On February 23, 2011, we closed our acquisition of an additional 20% working interest in the Bacchus field for approximately $9.2 million in cash paid at closing and approximately $6.2 million in cash paid in 2012. In addition, we paid capital costs incurred by the seller of $9.4 million. Following the acquisition, we hold an aggregate 30% working interest in the Bacchus field.
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.
Pending Acquisition
On December 23, 2011, we entered into a Sale and Purchase Agreement, through its wholly owned subsidiary Endeavour Energy UK Limited (“EEUK”), with ConocoPhillips (U.K.) Limited, ConocoPhillips Petroleum Limited and ConocoPhillips (U.K.) Lambda Limited, subsidiaries of ConocoPhillips to acquire their interest in three producing U.K. oil fields in the Central North Sea for $330 million (the “COP Acquisition”).
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
The producing assets to be purchased include the following net working interests:
(1) We currently have a 2.25% working interest in the Alba field which will increase to 25.68% upon consummation of the COP Acquisition.
The Purchase Agreement provides for the possibility that completion of this acquisition may occur individually for each field and we expect to close the Alba field portion by March 31, 2012. In addition to customary closing conditions, the purchase is subject to approval of governmental regulatory authorities and partner consents. The consideration for the acquisition is $330 million, including approximately $94 million of tax attributes, and may be adjusted for customary purchase price adjustments.
Note 9 - 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. There have been no changes in goodwill during the year ended December 31, 2011 or 2010.
Note 10 - Other Assets
Other long-term assets consisted of the following at December 31:
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
Intangible assets represented the purchase price allocated to the assembled workforce as a result of an acquisition and was amortized over its estimated life using the straight-line method. The intangible assets were fully amortized during 2011.
Debt issuance costs are amortized over the life of the related debt obligation. During 2011, we incurred $11.4 million in debt issuance costs related to the issuance of our Senior Term Loan. See Note 12 for additional discussion.
Note 11 - Accrued Expenses
We had the following accrued expenses and other current liabilities outstanding:
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
Note 12 - Debt Obligations
Our debt consisted of the following at December 31:
Principal maturities of debt at December 31, 2011 are as follows:
Senior Term Loan
In August 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 $235 million. We paid $25.4 million in financing costs related to the issuance of the Senior Term Loan. The Senior Term Loan has a three-year term and matures on August 16, 2013.
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.
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
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 shares of our common stock from us. See Note 15 for additional discussion on this purchase of our common stock.
Before 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:
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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;
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a specified minimum EBITDAX for each four-quarter period, ranging from $20,000,000 for the four-quarter period ending December 31, 2011 to $200,000,000 for the four-quarter period ending June 30, 2013;
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a minimum Reserve Coverage Ratio, as defined, of not less than 3.00:1.00; and
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a PDP Coverage Ratio, as defined, of not less than 0.25:1.00 on or prior to March 31, 2012 and not less than 0.50:1.00 after March 31, 2012.
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 19 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.
In February 2011, we amended our Senior Term Loan due 2013 to increase the security reserved for potential letters of credit from $25 million to $35 million. In July 2011, we secured new letters of credit that allowed us to release the $33 million of restricted cash that served as collateral for previous letters of credit.
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
In July 2011, we amended our Senior Term Loan to provide for an increase of $75 million in the borrowings available under the Senior Term Loan. In connection with the increase, we drew down the full additional amounts available and our quarterly scheduled amortization payments on the Senior Term Loan increased from $400,000 to $587,500. The other primary provisions of the amendment include:
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consent and approval by the lenders of the issuance of the 5.5% Convertible Senior Notes and certain conforming amendments with respect to the issuance of those notes, including an increase in the basket available for the issuance of junior debt from $100 million to $135 million;
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an amendment to the negative pledge provision to allow us to provide up to $10 million of cash margin to secure hedging obligations; and
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an extension by one additional quarter to the scheduled step up in the minimum secured debt coverage ratio.
See Note 23 “Subsequent Events, for discussion of an amendment to the Senior Term Loan made subsequent to December 31, 2011 and our plans to repay the Senior Term Loan in its entirety with proceeds from a senior note offering.
5.5% Convertible Senior Notes
In July 2011, we issued $135 million aggregate principal amount of our 5.5% Convertible Senior Notes due July 15, 2016. Interest on these notes will be payable semiannually at a rate of 5.5% per annum, commencing on January 15, 2012. The 5.5% Convertible Senior Notes are convertible into shares of our common stock at an initial conversion rate of 54.019 shares (equivalent to $18.51 per share) of common stock per $1,000 principal amount of the notes, subject to certain anti-dilution adjustments. In addition, following certain Make-Whole Fundamental Changes, as defined, we will increase the conversion rate for a holder who elects to convert its 5.5% Convertible Senior Notes.
The 5.5% Convertible Senior Notes are unsecured but guaranteed by our existing material domestic subsidiaries. We may not redeem the 5.5% Convertible Senior Notes prior to their maturity, and we do not intend to file a shelf registration statement for the resale of the 5.5% Convertible Senior Notes or the shares of our common stock issuable upon conversion of the 5.5% Convertible Senior Notes, if any. The indenture governing the 5.5% Convertible Senior Notes provides for customary events of default.
If we undergo a “fundamental change” as defined, the holders of the 5.5% Convertible Senior Notes have the right, subject to certain conditions, to redeem the 5.5% Convertible Senior Notes and accrued interest. The 5.5% Convertible Senior Notes may become immediately due upon the occurrence of certain events of default, as defined.
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Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
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.
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, 2011, the combined fair market value of these derivatives is $13.7 million, reflecting a $14.1 million decrease during 2011 that was recorded in unrealized gains (losses) on derivatives.
On March 11, 2011, we entered into an amendment to the Trust Deed related to our 11.5% Convertible Bonds due 2014. The amendment provided for:
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the amendment of the maturity date of the 11.5% Convertible Bonds from January 24, 2014 to January 24, 2016;
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the amendment of the date upon which the holders of the 11.5% Convertible Bonds may first exercise a put right, and the occurrence of the conversion price reset if such put right is not exercised, from January 24, 2012 to January 24, 2016; and
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a reduction in the interest rate payable from 11.5% to 7.5% on and after March 31, 2014.
We recorded a loss of $0.8 million in other expenses related to this amendment, representing the difference between the fair value of the debt and the book value of the debt at March 11, 2011.
Subordinated Notes
In November 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.
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Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
The Subordinated Notes bear interest at an annual rate of 10%, plus 2% capitalized to the outstanding principal amount. We 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. 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.
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, bearing interest at a rate of 6.00% per annum. On April 20, 2011, we redeemed all $81.25 million of the outstanding 6% Senior Notes due 2012 with a portion of the proceeds from our common stock offering completed in March 2011. The redemption was made at a price of 100% of the Senior Notes’ principal amount, plus accrued and unpaid interest to the redemption date.
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.
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.
Fair Value
The fair value of our outstanding debt obligations was $419.8 million and $361 million at 2011 and 2010, respectively. The fair values of long-term debt were determined based upon external market quotes for our Senior Notes and Convertible Senior Notes and discounted cash flows for other debt.
Letter of Credit Agreement
On July 25, 2011, we entered into a letter of credit facility agreement (the “LC Agreement”) with Commonwealth Bank of Australia (“CBA”), pursuant to which CBA issued letters of credit to us in the amount of £20.6 million (approximately $35 million as of July 25, 2011). Concurrent with
Endeavour International Corporation
Notes to Consolidated Financial Statements
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the issuance of the letters of credit, the restrictions on £20.6 million of our restricted cash were removed and the cash returned for general corporate purposes. The letters of credit secure decommissioning obligations in connection with certain of our United Kingdom Continental Shelf Petroleum Production Licences. The LC Agreement provides that we pay a quarterly fee computed at a rate of 4.5% per year on the outstanding amount of each letter of credit issued under the LC Agreement. The LC Agreement contains similar financial covenants and other covenants as the credit agreement governing our Senior Term Loan. The CBA letters of credit are renewable at our option on October 31, 2012 and through the expiration of the LC Agreement on October 31, 2013.
See Note 23 “Subsequent Events, for discussion of waivers and amendments to the LC Agreement made subsequent to December 31, 2011.
Senior Note Offering
See Note 23 “Subsequent Events, for discussion of a senior note offering made subsequent to December 31, 2011.
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Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
Note 13 - 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:
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
Effective Tax Rate Reconciliation
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%.
During 2011, 2010 and 2009, we incurred taxes primarily related to our operations in the U.K. and our discontinued operations in Norway during 2009. In 2011, 2010 and 2009 we had a loss before taxes of $99.4 million, $31.0 million and $31.2 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 Tax Assets and Liabilities
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:
Endeavour International Corporation
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Tax Attributes
At December 31, 2011, we had the following tax attributes available to reduce future income taxes:
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As of December 31, 2011, the U.K. tax attributes shown above have been recognized for financial statement reporting purposes to reduce deferred tax liability.
Valuation Allowances and Unrecognized Tax Benefits
Recognition of the benefits of the deferred tax assets requires that we generate future taxable income. In the U.S., 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 $58.5 million, $37.8 million and $38.8 million as of December 31, 2011, 2010 and 2009, respectively, primarily related to our U.S. operations. During 2011, the valuation allowance in the U.S. increased $24.6 million due to net operating losses and decreased $3.9 million in other jurisdictions. 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 jurisdictions. 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.
For U.S. federal income tax purposes, certain limitations are imposed on an entity’s 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 entity’s 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.
As of December 31, 2011, we believe that no current tax positions that have resulted in unrecognized tax benefits will significantly increase or decrease within the next year.
The following tax years remain subject to examination:
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Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
Foreign Earnings and Credits
As of December 31, 2011, we had unremitted earnings in our foreign subsidiaries. If these unremitted earnings had been dividend to the U.S., the U.S. NOL’s not subject to the limitations 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 14 - Other Liabilities
Other liabilities included the following:
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, 2011 and 2010:
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Note 15 - Equity
The activity in shares of our common and preferred stock during 2011, 2010 and 2009 included the following:
Common Stock
The Common Stock is $0.001 par value common stock, 64,285,714 shares authorized.
In March 2011, we completed an underwritten public offering of 11.5 million shares of common stock at a price of $11.00 per common share ($10.34 per common share, net of underwriting discounts) for net proceeds of $118.4 million. In April 2011, we used a portion of the offering proceeds to redeem all $81.25 million of our outstanding 6% Senior Notes.
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 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
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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 company’s trading metrics.
In August 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.
In February 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.
During 2010, we issued inducement grants of 85,715 shares of our restricted common stock, upon commencement of employment of one executive officer.
New York Stock Exchange Listing of Common Stock
On March 15, 2011, we completed the transfer of the primary listing for our common stock from the NYSE Amex to the New York Stock Exchange under the symbol “END.”
Series C Convertible Preferred Stock
In 2006, we issued the Series C Preferred Stock. At December 31,2011 we had 37,000 shares of Series C Convertible Preferred Stock outstanding, convertible into 4.2 million shares of common stock. The Series C Preferred Stock is convertible into common stock at any time at the option of the preferred stock investors, at a conversion price of $8.75. Dividends on the Series C Preferred Stock are:
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cumulative;
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compounded quarterly based on the original issue price;
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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
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payable to the preferred stock investors prior to payment of any other dividend on any other shares of our capital stock.
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Notes to Consolidated Financial Statements
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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.
In November 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.
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.
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
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.
In January 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. In March 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.
During 2011, holders of a portion of our Series C Convertible Preferred Stock converted 8,000 preferred shares, with a face value of $8 million, into 0.9 million shares of our common stock. In 2010, a combined 5,000 shares of our Series C Preferred Stock were converted into 0.6 million shares of our common stock.
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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.
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 16 - Supplementary Cash Flow Disclosures
Cash paid during the period for interest and income taxes was as follows:
Non-Cash Investing and Financing Transactions
As discussed in Note 15, in 2011, a combined 8,000 shares of our Series C Preferred Stock were converted into 0.9 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.
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 2011, 2010 and 2009, we recorded $12.8 million, $8.8 million and $5.5 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.
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Note 17 - Financial Instruments
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.
Note 18 - 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.
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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 derivative instruments 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, 2011:
Our commodity derivative contracts were measured 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 oil 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 the fair values of our gas 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.
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(Amounts in thousands, except per unit data)
The following is a reconciliation of changes in fair value of net derivative assets and liabilities classified as Level 3:
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.
In September 2011, the FASB amended the previously issued guidance on testing goodwill for impairment. The revised guidance provides entities with an option of performing a qualitative assessment prior to calculating the fair value of the reporting unit. The amended guidance is effective for annual and interim goodwill impairment tests that will be performed for fiscal years beginning after December 15, 2011. We do not expect the adoption of this amended guidance for goodwill impairment testing to have an impact on our financial position or on our consolidated financial statements and related disclosures.
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 management’s 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 management’s expectation of future conditions that are often outside of management’s control. However, assumptions used reflect a market participant’s view of long-term prices, costs and other factors, and are consistent with assumptions used in our business plans and investment decisions.
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Note 19 - Derivative Instruments
We have oil and gas commodity derivatives and embedded derivatives related to debt instruments at December 31, 2011 and 2010. The fair market value of these derivative instruments is included in our balance sheet as follows:
As of December 31, 2011, our outstanding commodity derivatives covered approximately 304 Mbbl of oil and 548 MMcf of gas cumulative through 2010 and consist of fixed price puts. If all counterparties failed to perform, our maximum loss would be $1.2 million as of December 31, 2011.
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Notes to Consolidated Financial Statements
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The effect of the derivatives not designated as hedges on our results of operations was as follows:
The effect of derivatives designated as cash flow hedges on our results of operations and other comprehensive income was as follows:
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).
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 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.
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Terminated Acquisition of Marcellus Assets
On July 17, 2011, we entered into agreements with SM Energy Company and certain other sellers named therein for the purchase of oil and gas leases, producing properties, geophysical data, a pipeline and related assets in the Marcellus shale play in Pennsylvania for aggregate consideration of approximately $110 million. We terminated the agreements on December 14, 2011, based on our conclusion that (i) the title defects we identified, after analyzing SM Energy’s responses to the notice of defects and valuation of the defects, exceeded the contractual threshold of 15% of the purchase price for the applicable asset group ($85 million); and (ii) the condition of the pipeline was not in compliance with applicable regulatory standards, which would constitute a material violation of a representation and warranty contained in the applicable SM Purchase Agreement.
SM Energy filed a lawsuit against us in Texas state court on December 20, 2011 alleging that we breached the SM Purchase Agreements by terminating them and refusing to close on the transactions. Specifically, SM Energy has alleged, among other things, that most of our asserted title defects are without merit and, in any event, would not exceed 15% of the applicable purchase price. SM Energy seeks the award of unspecified actual damages, including costs and reasonable attorney’s fees, and specific performance. On January 17, 2012, we filed an answer and counterclaim denying the allegations and seeking the return of our $6 million deposit, which we believe we are entitled to recover pursuant to the terms of the SM Purchase Agreements, and for the damages that we suffered as a result of SM Energy’s misrepresentations. We intend to contest the case vigorously.
Rig Commitments
We have previously disclosed a potential commitment on a drilling rig in our North Sea operations relating to a dispute with the rig operator. On June 6, 2011, we entered into a settlement agreement with the rig operator whereby the parties were mutually released from all future claims. We incurred costs of $14 million related to the settlement, which are included in capital expenditures.
We also have a rig commitment for the drilling of the two Rochelle production wells in the spring of 2012.
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Operating Leases
At December 31, 2011, we have leases for office space and equipment with lease payments as follows:
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:
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Note 22 - Quarterly Financial Data (Unaudited)
(1) Includes impairments of oil and gas properties of $28.8 million and $36.9 million, for the third and fourth quarter of 2011, respectively.
(2) Includes impairments of oil and gas properties of $7.7 million, for the first quarter of 2010 and gain on sale of reserves in place of $87.2 million in the fourth quarter of 2010.
Note 23 - Subsequent Events
Senior Note Offering
On February 23, 2012, we closed the private placement of $350 million aggregate principal amount of 12% first priority notes due 2018 (the “First Priority Notes”) and $150 million aggregate principal amount of 12% second priority notes due 2018 (the “Second Priority Notes,” and, together with the First Priority Notes, the “2018 Notes”). Each series of 2018 Notes was priced at 96% of par, at a yield to maturity of 12.975% for the First Priority Notes and 12.954% for the Second Priority Notes, respectively. We intend to use the net proceeds from the 2018 Notes to fund the COP Acquisition, to repay all amounts outstanding under our Senior Term Loan due 2013 and for general corporate purposes. Prior to the closing of the acquisition in the North Sea, the net proceeds of the offering are held in an escrow account. The COP Purchase
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Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
Agreement provides for the possibility that the COP Acquisition may close in multiple stages. If we close the Alba Acquisition, which constitutes the majority of the value in the COP Acquisition, the full amount of proceeds will be released from escrow.
We have also received a commitment for a senior secured bridge facility; however, we would only expect to draw on the facility to the extent we are otherwise unable to fund the COP Acquisition and the repayment of the Senior Term Loan, including with the proceeds of the 2018 Notes and cash on hand.
Amendment to Senior Term Loan
On January 18, 2012, we and our wholly owned subsidiary, Endeavour Energy UK Limited (“EEUK”), entered into a Consent and Fourth Amendment to Credit Agreement, U.S. Security Agreement and Subsidiaries Guaranty (the “Amendment”) with Cyan Partners, LP, as administrative agent, and certain lenders party thereto (the “Senior Term Loan”).
The primary provisions of the Amendment include the (i) consent and approval for the Company to issue up to $500 million of senior unsecured notes, (ii) exclusion of up to $500 million of senior unsecured notes, if any, from certain financial covenants and (iii) amendments to certain existing financial covenants, including a reduction in the minimum consolidated EBITDAX requirement to $20,000,000 for each of the test periods ended December 31, 2011 and March 31, 2012 and an extension of the increase in the minimum PDP coverage ratio from 0.25:1.00 to 0.50:100 after March 31, 2012.
Letter of Credit Agreement
Subsequent to December 31, 2011, we entered into waivers and amendments for our letter of credit facility agreement with Commonwealth Bank of Australia (“CBA”). The primary provisions include (i) an amendment and waiver for certain existing financial covenants, including the minimum EBITDAX covenant and (ii) CBA’s consent to the issuance of up to $525 million of senior unsecured notes, and the escrow of the proceeds therefrom, including the exclusion of such proceeds from any requirement to grant a security interest in favor of CBA and the exclusion of the notes from the financial covenant calculations while the proceeds are held in escrow. The waiver includes express provisions to enable us to complete our previously disclosed acquisition of North Sea assets from several subsidiaries of ConocoPhillips.
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
Note 24 - Supplemental Oil and Gas Disclosures (Unaudited)
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
Note 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.
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. Our oil and gas reserves were audited by independent reserve engineers at December 31, 2011, 2010 and 2009.
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 2011, 2010 and 2009 have been presented in accordance with the new reserve estimation and disclosure rules, which may not be applied retrospectively.
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
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 2011, 2010 and 2009. 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.
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
At December 31, 2011 and 2010, the prices used to determine the estimates of future cash inflows were as follows:
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.
Endeavour International Corporation
Notes to Consolidated Financial Statements
(Amounts in thousands, except per unit data)
Endeavour International Corporation
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A.
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, 2011. 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.
Management’s 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, 2011. 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, 2011.
Endeavour International Corporation
KPMG LLP, an independent registered public accounting firm, audited management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2011 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, 2011 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 Shareholders
Endeavour International Corporation:
We have audited Endeavour International Corporation’s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control- Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Endeavour International Corporation’s 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 Management’s Assessment of Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We have 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 company’s 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 company’s 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 detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Endeavour International Corporation
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, 2011, 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, 2011 and 2010, and the related consolidated statements of operations, stockholders’ equity and comprehensive income (loss), and cash flows for each of the years in the three-year period ended December 31, 2011, and our report dated March 7, 2012 expressed an unqualified opinion on these consolidated financial statements.
/s/ KPMG LLP
Houston, Texas
March 7, 2012
Item 9B.
Item 9B. Other Information
None.
Part III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance of the Registrant
Our Definitive Proxy Statement for our 2012 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.
Endeavour International Corporation
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.
Item 11. Executive Compensation
Our Definitive Proxy Statement for our 2012 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.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholders Matters
Our Definitive Proxy Statement for our 2012 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.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Our Definitive Proxy Statement for our 2012 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.
Item 14.
Item 14. Principal Accounting Fees and Services
Our Definitive Proxy Statement for our 2012 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.
Endeavour International Corporation
Part IV
Item 15.
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.
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 7, 2012
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.
Endeavour International Corporation
Endeavour International Corporation
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