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Table of Contents

 

 

 

Quantities of natural gas are expressed in this Annual Report on Form 10-K in terms of thousand cubic feet (“Mcf”) and million cubic feet (“MMcf”).  Oil, which includes natural gas liquids, is quantified in terms of barrels (“Bbls”) and thousands of barrels (“Mbbls”).  Natural gas is compared to oil in terms of barrels of oil equivalent (“BOE”), thousand barrels of oil equivalent (“MBOE’) or million barrels of oil equivalent (“MMBOE”).  One barrel of oil is the approximate energy equivalent of six Mcf of natural gas.  This is a physical correlation and does not reflect a value or price relationship between the commodities.  With respect to information relating to our working interest in wells or acreage, “net” oil and gas wells or acreage is determined by multiplying gross wells or acreage by our working interest therein.  References to number of potential well locations are gross, unless otherwise indicated.  References to “GAAP” refer to U.S. generally accepted accounting principles.

 

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Part I

 

Item 1.  Business

 

Unless the context otherwise requires, references to “Endeavour,” the “Company,” “we,” “us” or “our” mean Endeavour International Corporation and its consolidated subsidiaries.

 

Our Company

 

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 in the United Kingdom (“U.K.”) North Sea and United States (“U.S.”) onshore.  We began our operations focused on the U.K. and Norwegian sectors of the North Sea.  In 2009, we sold our Norwegian operations, utilizing the proceeds to expand our U.S. position in the fourth quarter of 2009 and early 2010, purchasing both producing properties and exploration acreage.  Since 2010, our focus has been on the acquisition of additional interests and advancement of our primary development projects in our U.K. fields – Bacchus in 2011, Alba in 2012, and Rochelle in 2013.

 

Our Areas of Operation

 

Our operations are organized into two main geographic regions: the U.K. North Sea and U.S. onshore.  As of December 31, 2013, our estimated proved reserves were 23.5 MMBOE, compared to 25.7 MMBOE as of December 31, 2012, of which approximately 92% were located in the U.K. and approximately 8% were located in the U.S. 

 

 

 

 

 

U.K. North Sea

 

The North Sea is a proven resource area where we have producing properties and exploration licenses.  Although capital and production costs are higher than conventional developments in the U.S., the quality of the oil, the political stability of the region, and the proximity of important markets with strong demand in Western Europe has made the North Sea an important oil and  

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natural gas producing region.  Our recent focus in the North Sea has been on our three largest fields – Alba, Bacchus and Rochelle.  While Alba and Rochelle each represent nearly 40% of our proved reserves at December 31, 2013, the fields are in very different stages.  Alba is a mature oil field and our 2013 activity has involved infill drilling and operational activities.  Rochelle is primarily a liquids-rich gas field that started production in October 2013.  The Bacchus field is an oil field that began production in May 2012, reached payout after 15 months and completed its development operations during 2013.

 

Alba

 

In May 2012, we acquired an additional 23.43% interest in the Alba field, which increased our total working interest in the field to 25.68%.  In April 2013, operations commenced on a three-well infill drilling program.  The first two development wells were completed by August 2013, just prior to the shutdown for the planned maintenance program from mid-August to mid-September 2013.  Following the shutdown, the operator identified that the water injection pipeline supplying pressure to the southern area of the field had ruptured, causing a portion of the southern region to be shut-in.  The Alba 2013 exit rate was 18,500 barrels per day gross, below the levels expected from the field.  Remedial action is currently being taken to reinstate partial water injection to offset some of the reduced production, and the permanent replacement of the pipeline is expected in late 2014.  The 2013 infill drilling campaign recommenced in November 2013 with an additional well that began producing during the first quarter of 2014.  We expect production to increase upon initial production from this development well.  An additional two development wells are scheduled to be drilled during 2014.

 

Bacchus

 

At December 31, 2013, we held a 30% working interest in our Bacchus field asset.  In 2012, we achieved production from the first two development wells and the third well was completed in July 2013.  The 2013 production exit rate at the field was over 10,000 barrels per day gross.  During the third quarter of 2013, a new 3D seismic survey was shot over the Bacchus field to gain additional understanding of field performance and identify additional Bacchus development opportunities.  Consistent with the original development plans, the first well drilled is expected to be turned into a water injector during the second quarter of 2014.  This will provide pressure support to help sustain the field’s production rate and increase its overall recovery.  Production from the field is expected to continue to decline in line with our field estimates until additional development opportunities can be undertaken.

 

Rochelle

 

Our working interest in the Rochelle field, a gas-condensate field, is 44%.  Development drilling and subsea tie-ins have been underway since 2012.  In February 2013, following a severe storm lasting several days, we performed a routine inspection of the conductor, wellhead and blow out preventer systems which revealed that a non-uniform hole had been formed around the conductor.  As a result of this finding, the E1 well was plugged and abandoned.  We have made an insurance claim to recover certain abandonment and redrill costs; however, no assurance can be given that we can successfully recover any costs.

 

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By January 2014, both the E2 and W1 development wells at Rochelle were fully completed and tied-in to the production manifolds.  As part of the final installation and start-up of the E2 well, the W1 well was shut-in.    During the restart of production, a valve was discovered stuck in the ‘shut’ position on the outlet side of the Rochelle production manifold. An attempt to open the valve manually was unsuccessful and the operator secured an intervention vessel to open the valve.  The valve was successfully opened in February 2014.   The E2 well commenced production on February 28, 2014.  The E2 production is ramping up and the W1 well is anticipated to restart production in March 2014.  This unanticipated downtime will negatively affect our daily production rates and associated revenue for the first quarter of 2014, as well as our near-term liquidity.  When both E2 and W1 wells are on production, we expect the production from the Rochelle field to be able to exceed the available production capacity at the Scott platform.

 

U.S. Onshore

 

During 2009, we began acquiring acreage in U.S. onshore resource plays. Our primary focus in the U.S. has been onshore unconventional oil and gas developments.  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. Our U.S. activity has targeted reserve and production growth in proven shale gas plays, including the Louisiana Haynesville and Pennsylvania Marcellus areas.  We are also targeting emerging oil-prone and liquids-rich plays, including the Montana Heath oil play and our new interests in the Colorado Niobrara play area.  With U.S. gas prices remaining relatively depressed during 2013, we limited our capital expenditures to primarily those expenditures necessary to maintain our acreage positions and fulfill minor drilling commitments.

 

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:

 

 

Marcellus Area

 

On November 8, 2013, we closed on a purchase and sale agreement and formed a joint venture partnership with Samson Exploration LLC (“Samson”), which included a sale of 50% of our upstream and midstream assets in the Pennsylvania Marcellus area to Samson.  The agreement provides for the joint development of the Marcellus assets and includes a financing component.  This joint venture provides the necessary capital for the next development phase in the core Daniel Field in Cameron County, Pennsylvania.  The partnership has plans underway to complete three previously drilled and cased horizontal Marcellus wells.  These wells will be tied

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to a new third-party pipeline being constructed by EQT Corporation that will allow firm capacity up to 10 MMcf per day, with potential for future expansion.  Endeavour will operate this initial phase of activity, which we expect to complete by mid-2014.  At December 31, 2013, we had approximately 27,200 gross acres and 13,400 net acres in the Pennsylvania Marcellus area.

 

We currently have five producing wells and three wells awaiting completion.  No new drilling is required until late 2014 to hold key leasehold acreage in Cameron County.

 

Haynesville Area

 

We have working interests in three Haynesville producing project areas in Louisiana totaling approximately 7,250 gross acres and 3,300 net acres.  We have working interests in 19 Haynesville units which are currently held by production with an estimated 80 or more remaining gross locations yet to be developed, depending on ultimate development well spacing.  No new drilling is currently required in the Haynesville area to maintain our acreage position.

 

Heath Shale Oil Play

 

We have interests in approximately 60,050 net acres in the emerging Heath Shale oil play in Montana, primarily in Rosebud and Garfield Counties.  We have two vertical pilot test wells where we continue to evaluate potential horizontal targets penetrated within the Heath Shale and Tyler Formation.  We are also evaluating offset well results in the surrounding area and will consider that information as we determine our next operational steps.  Until we have completed our evaluation, we do not expect to make significant capital expenditures related our interests in the Heath Shale oil play.

 

Niobrara Play

 

During 2012 and 2013, we acquired leasehold and drilling rights to earn approximately 40,000 gross and 27,000 net acres in the Niobrara play in northwest Colorado, which has liquids-rich potential.  In 2013, we formed a 23,000 acre Federal Unit in Rio Blanco and Moffat Counties and drilled an initial vertical pilot test well in the Wiley Unit to evaluate the liquids-rich potential of the Niobrara and Frontier formations.  The well is being evaluated for a future horizontal re-entry in 2014.  In a separate operation in Mesa County in 2013, we obtained Niobrara cores in a third-party well where we have drill-to-earn options which may be exercised by horizontal drilling in 2014.  We expect to continue building our inventory of prospects in Colorado through leasehold acquisitions and drill-to-earn arrangements.

 

2014 Planned Expenditures

 

We expect that our total capital expenditure budget for 2014 will be approximately $70 million, of which we expect to spend approximately $45 million in the U.K., primarily on maintenance activities and drilling at Alba.  We expect to spend the remainder of our 2014 capital budget in the U.S. to maintain our acreage positions and advance the proof-of-concept in the Marcellus Are and Niobrara Play.  Our 2014 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

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availability of sufficient capital resources, drilling success and other normal factors affecting the oil and gas industry.

 

We intend to fund our 2014 capital expenditures primarily through cash on hand, cash flow generated from operations and our financing activities in early 2014.

 

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 — 2013 Liquidity and Capital Resources.”

 

 

 

 

Decommissioning Expenditures

 

Production from each of our Ivanhoe, Rob Roy, Hamish (collectively, “IVRRH”), Renee, Rubie and Goldeneye fields has ceased and we have performed maintenance and decommissioning activities over the last several years.  We expect to incur approximately $50 million in decommissioning charges during 2014.

 

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 — 2013 Liquidity and Capital Resources.”

 

Geographical Data

 

We operate in one industry segment, that being oil and gas exploration and production, in two geographical areas.  See Notes 23 and 27 to our consolidated financial statements in “Item 8.  Financial Statements and Supplementary Data” for geographic operating segment information, including results of operations and segment assets.

 

Competition

 

We encounter intense competition from other oil and gas companies in all areas of our operations, including the acquisition of producing properties and undeveloped acreage.  Our competitors include major integrated oil and gas companies, numerous independent oil and gas companies and individuals.  Many of our competitors are large, well-established companies with substantially larger operating staffs and greater capital resources and have been engaged in the oil and gas business for a much longer time than our company.

 

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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.  For the year ended December 31, 2013, our sales to Shell U.K. Limited accounted for more than 10% of revenue.  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 J-W Operating Company.

 

Employees

 

As of March 13, 2014, we had 41 full-time employees.  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 (“E.U.”) 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 Department of Energy and Climate Change (the “DECC”) will consult with various public bodies that have responsibility for the environment.  Applicants for production licenses are required to submit a summary of 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 recent and forthcoming rules that may impact our North Sea operations.  In response to the apparent blowout of the Deepwater Horizon drilling rig in the Gulf of Mexico in 2010, the DECC has increased rig inspections over the last several years.  In addition, more rigor has been introduced in the approval process for emergency plans and the provision of

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financial responsibility for well control contingencies.  The E.U. is also proposing to introduce a directive on offshore safety.  We expect these measures to continue, or increase, over the near term.  Our operations in the North Sea are subject to the European Union’s REACH program, which requires the registration and ultimate phase out of certain hazardous chemicals.  Finally, depending on the scale of our operations, our offshore production facilities may be subject to compliance obligations under the E.U. emissions trading system (“E.U. ETS”) for greenhouse gas (“GHG”) emissions.  The E.U. ETS places a cap on GHG emissions from certain sources.  Sources that emit above their applicable caps must purchase allowances in order to comply with the E.U. ETS.  The E.U. has commenced the third phase of the E.U. ETS, running from 2013 to 2020, and therefore our activities in the North Sea are still potentially subject to the impacts of GHG limitations.  While allowance prices on the E.U. ETS remain low, the E.U. has approved a proposal to increase allowances prices by deferring the marketability of allowances by withholding a number of allowances from auction, know as “backloading.” 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 prior to closure and abandonment.  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 such operations  Additionally, a release of hydrocarbons or wastes into the environment could, to the extent the event is not insured, subject us to substantial expenses, including removal and remediation costs, costs to resolve claims by third parties for personal injury or property damage, or by the U.S. federal government or state governments for natural resources damages.

 

The environmental laws we are subject to include:

 

 

 

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In addition, we currently lease a number of properties that for many years have been used for the exploration and production of oil and gas.  Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or wastes may have been disposed of or released on or under the properties operated or leased by us or on or under other locations where such hydrocarbons or wastes have been taken for recycling or disposal.  In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or wastes was not under our control.  These properties and the hydrocarbons and wastes disposed thereon may be subject to laws and regulations imposing strict, joint and several, 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

 

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 (the “EPA”) recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s Underground Injection Control Program.  At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities on water resources.  The EPA’s study includes 18 separate research projects addressing topics such as water acquisition, chemical mixing, well injection, flowback and produced water, and wastewater treatment and disposal.  The EPA has indicated that it expects to issue its study report in late 2014.  From time to time, legislation has been introduced before the United States Congress (“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

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hydraulic fracturing operations.  For example, Pennsylvania, and Colorado, 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

 

In response to findings that emissions of carbon dioxide, methane and other greenhouse gases, or GHGs, present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, establish Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit reviews for certain large stationary sources that are potential major sources of GHG emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA on a case-by-case basis. These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which include certain of our operations.  We are monitoring GHG emissions from our operations in accordance with the GHG emissions reporting rule and believe that our monitoring activities are in substantial compliance with applicable reporting obligations.

 

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years.  In the absence of such federal climate legislation, a number of state and regional efforts have emerged  that are aimed at tracking and/or reducing GHG emission by means of cap and trade programs that typically require major sources of GHG emissions, to acquire and surrender emission allowances in return for emitting those GHGs. If Congress undertakes comprehensive tax reform in the coming year, it is possible that such reform may include a carbon tax, which could impose additional direct costs on operations and reduce demand for the oil and natural gas we produce. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. Substantial limitations on GHG emissions could also adversely affect demand for the oil and natural gas we produce

 

Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic event; if  

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any such effects were to occur, they could have an adverse effect on our exploration and production operations.

 

We have made, and will continue to make, expenditures in connection with our effort to comply with environmental laws and regulations.  We believe that we are in compliance with applicable environmental laws and regulations currently in effect and that continued compliance with existing requirements will not have a material adverse impact on us.  However, we also believe that it is reasonably likely that the trend in environmental legislation and regulation will continue toward stricter standards and, thus, we cannot give any assurance that we will not be adversely affected in the future.

 

We have established internal guidelines to be followed in order to comply with environmental laws and regulations in the U.S.  We employ a safety department whose responsibilities include providing assurance that our operations are carried out in accordance with applicable environmental guidelines and safety precautions.  Although we maintain pollution insurance to cover a portion of the potential costs of cleanup obligations, public liability and physical damage, there is no assurance that such insurance will be adequate to cover all such costs or that such insurance will continue to be available in the future.  To date, we believe that compliance with existing requirements of such governmental bodies has not had a material effect on our operations.

 

Other Regulation of the Oil and Gas Industry

 

The oil and gas industry is extensively regulated by numerous federal, state and local authorities.  Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden.  Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply.  Although the regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

 

Legislation continues to be introduced in Congress and development of regulations continues in the U.S. 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 various states regulate the drilling for, and the production of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits.  States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources.  States may regulate rates of production and may establish maximum daily production allowable from oil and gas wells based on market demand or resource conservation, or both.  States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future.  The effect of these regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, and to limit the number of wells or locations we can drill.

 

Regulation

 

The exploration, production and sale of oil and gas are extensively regulated by governmental bodies.  Applicable legislation is under constant review for amendment or expansion.  Oil and gas mineral rights may be held by individuals, corporations or governments having jurisdiction over the area in which such mineral rights are located.  As a general rule, parties holding such mineral rights grant licenses or leases to third parties to facilitate the exploration and development of these mineral rights.  The terms of the leases and licenses are generally established to require timely development.  Notwithstanding the ownership of mineral rights, the government of the jurisdiction in which mineral rights are located generally retains authority over the manner of development of those rights.

 

Title to Properties

 

We believe that our title to the various interests set forth above is satisfactory and consistent with generally accepted industry standards, subject to exceptions that would not materially detract from the value of the interests or materially interfere with their use in our operations.  Individual properties may be subject to burdens such as royalty, overriding royalty and other outstanding interests customary in the industry.  In addition, interests may be subject to obligations or duties under applicable laws or burdens such as production payments, net profits interest, liens incident to operating agreements and for current taxes, development obligations under crude oil and natural gas leases or capital commitments under production sharing contracts or exploration licenses.

 

Offices

 

Our principal executive offices are located at 811 Main Street, Suite 2100, Houston, Texas 77002, and our telephone number is (713) 307-8700.  We also have offices in Aberdeen, Scotland, United Kingdom and in Denver, Colorado.

 

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Available Information

 

We file annual, quarterly and current reports with the Securities and Exchange Commission (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.

 

Our website is available at www.endeavourcorp.com.  We make available, free of charge, on our website, 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 27 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 23 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.  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 (the

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“Securities Act”),  and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).  These forward-looking statements include statements that express a belief, expectation, or intention, as well as those that are not statements of historical fact, and may include projections and estimates concerning the timing and success of specific projects and our future production, revenues, income and capital spending.  Our forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “plan,” “goal” or other words that convey the uncertainty of future events or outcomes.  We caution you not to rely on them unduly.  In particular, this Annual Report on Form 10-K contains forward-looking statements pertaining to the following:

 

 

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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Any of these factors, or a combination of these factors, could materially affect our financial condition or results of operations and the ultimate accuracy of a forward-looking statement.  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 this “Item 1A. Risk Factors” and elsewhere in this Annual Report on Form 10-K.  Except as required by law, we undertake no obligation to update publicly or release any revisions to these forward-looking statements to reflect events or circumstances after the date of this Annual Report on Form 10-K. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

 

Risks related to access to capital and financing

 

Our debt levels could negatively impact our financial condition, results of operations and business prospects.

 

As of December 31,  2013, we had $882.6 million in outstanding indebtedness.  Our indebtedness and other obligations could have important consequences on our operations, including:

 

 

We may not have sufficient funds to repay our outstanding debt and other obligations.  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 and other obligations 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, such as our term loan issued in January 2014, 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

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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,  require refinancing of certain debt instruments and trigger severance payments or accelerated vesting of equity awards.

 

Upon certain specified change of control events, the lenders under our various debt facilities may cancel the facility and declare as due and payable any outstanding indebtedness, accrued interest and other outstanding fees.  The terms of the indentures governing the 2018 Notes (as defined below) may require us to repurchase all or a portion of the notes if the proceeds from certain dispositions are not applied in a specific manner.  We cannot assure you we would have sufficient financial resources to purchase the debt instruments for cash or repay the lenders upon the occurrence of a change of control or disposition.  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.

 

We provide severance benefits through Mr. Transier’s employment agreement and through change in control agreements with Mr. Emme and Ms. Stubbs.  These agreements provide for severance compensation to be paid if employment is terminated under certain conditions, such as at the executive’s election for “good reason” following a change in control, as defined in the agreements.  Additionally, our long-term incentive grant agreements provide for accelerated vesting of equity awards upon the occurrence of a change in control. 

 

Our development and exploration operations require substantial capital, and we may be unable to generate sufficient cash flow from operations or 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. In the past, we have utilized cash flow from operations and access to the debt and equity markets to fund our capital requirements.  Our cash flow from operations and access to capital is subject to a number of variables, including:

 

 

If our revenues decrease as a result of lower oil and gas prices, operating difficulties, declines in reserves or for any other reason or our capital expenditures increase as a result of operating difficulties, higher drillings costs or for any other reason, we may have limited ability to generate

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sufficient cash flow from operations or 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 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. In addition, our existing debt contains restrictions on the incurrence of new debt.  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.

 

If we are unable to fulfill commitments under any of our oil and gas interests, we will lose our interest, and our entire investment, in such interest.

 

Our ability to retain oil and gas interests will depend on our ability to fulfill the commitments made with respect to each interest.  We cannot assure you that we or the other participants in the projects will have the financial ability to fund these potential commitments.  If we are unable to fulfill commitments under any of our interests, we will lose our interest, and our entire investment, in such interest.

 

Risks related to executing our strategy and operations

 

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 (such as the recent valve issue at Rochelle).  These operating risks may result in a loss or delay of cash flows from production or require additional capital expenditures.  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.

 

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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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 and receive the associated cash flows.   We could also incur substantial losses as a result of:

 

 

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 severe 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.

 

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.  In addition, such mechanical difficulties are more difficult, expensive and time consuming to fix in an offshore environment.  As a result, a significant amount of time and capital must be invested before we can market the associated oil or gas of a

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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.

 

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.

 

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, pursuing 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.

 

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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, approval or other participants to drill wells and implement other work programs, availability of suitable drilling rigs, equipment and qualified operating personnel, 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 and operational issues can materially impact our ability to commence production at these discoveries which would materially impact our reserves, cash flow and results of operations.  Furthermore, because of these uncertainties, we cannot give any assurance as to the timing of these activities or that they will ultimately result in the realization of proved reserves or meet our expectations for success.  As such, our actual drilling and enhanced recovery activities may materially differ from our current expectations, which could have a significant adverse effect on our financial condition and results of operations.

 

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.  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.

 

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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, 2013 were undeveloped, and those reserves may not ultimately be developed.

 

At December 31, 2013, approximately 56% of our total estimated net proved reserves were undeveloped.  Recovery of undeveloped reserves may require significant capital expenditures.  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.

 

Certain of our U.K. oil fields are dependent upon tanker liftings to deliver oil production to buyers, which may result in fluctuations in our revenue and results of operations.

 

We record oil revenues using the sales method (i.e., when delivery has occurred).  While certain of our U.K. fields produce into pipelines (causing revenue to be recorded consistently with such production), certain other fields are dependent upon tanker liftings to deliver oil production to

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buyers.  As a result, our revenues from this oil production will fluctuate in connection with the frequency and volume of tanker liftings, which are factors not entirely within our control.  Accordingly, the revenues from our oil production in the U.K. are expected to be more volatile than the associated physical production, which is expected to remain relatively steady.

 

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.

 

The cost of decommissioning is uncertain.

 

We expect to incur obligations to abandon and decommission certain structures associated with our producing properties.  To date, the industry has little experience of removing oil and gas structures from the North Sea, because few of the structures in the North Sea have been removed.  Because experience 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.

 

We may be unable to make attractive acquisitions, and any acquisition we complete is subject to substantial risks that could impact our business.

 

As part of our growth strategy, we intend to continue to pursue strategic acquisitions of new properties or businesses that expand our current asset base and potentially offer unexploited reserve potential.  Our growth strategy could be impeded if we are unable to acquire additional interests in oil and gas prospects on a profitable basis.  Acquisition opportunities in the oil and gas industry are very competitive, which can increase the cost of, or cause us to refrain from, completing acquisitions.  The success of any acquisition will depend on a number of factors and involves potential risks, including among other things:

 

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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.

 

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:

 

 

The exploration, production and sale of oil and gas are extensively regulated by governmental bodies, which subject 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

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holding such mineral rights grant licenses or leases to third parties to facilitate the exploration and development of these mineral rights.  The terms of the leases and licenses are generally established to require timely development. Notwithstanding the ownership of mineral rights, the government of the jurisdiction in which mineral rights are located generally retains authority over the manner of development of those rights.  As such, we may become subject to certain requirements, obligations and timelines as established or demanded by the holder of the oil and gas mineral rights and such requirements or obligations may adversely impact our operations, cash flow and capital plans.

 

Economic conditions in the U.S. and key international markets may materially adversely impact our operating results, which could hinder or prevent us from meeting our future capital needs.

 

The U.S., U.K. and other world economies are slowly recovering from a recession which began in 2008 and extended into 2009.  Growth has resumed, but remains modest.  There are likely to be significant long-term effects resulting from the recession and credit market crisis, including a future global economic growth rate that is slower than what was experienced 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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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.

 

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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.

 

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 risk with our production, we may enter into commodity derivative contracts.  The goal of these derivative contracts is to limit volatility and increase the predictability of cash flow.  Although the use of derivative contracts limits the downside risk of price declines, their use also may limit future revenues from price increases.  In addition, derivative contracts may expose us to the risk of financial loss in certain circumstances, including instances in which our production is less than expected or a sudden, unexpected event materially impacts oil or gas prices.

 

Derivative contracts also involve the risk that counterparties, which generally are financial institutions, may be unable to satisfy their obligations to us.  If any one of our counterparties were to default on its obligations to us under the derivative contracts or seek bankruptcy protection, it could have a material adverse effect on our expected cash flows and our ability to fund our planned activities and could result in a larger percentage of our future production being subject to commodity price changes.  In addition, in the current economic environment and tight financial markets, the risk of a counterparty default is heightened and it is possible that fewer counterparties will participate in future derivative transactions, which could result in greater concentration of our exposure to any one counterparty or a larger percentage of our future production being subject to commodity price changes.

 

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Risks related to environmental and other regulations

 

We are subject to environmental regulations that can have a significant impact on our operations.

 

Our operations are subject to a variety of national, state, local and international laws and regulations governing the emission and 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.  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. In addition, current and future environmental regulations, including restrictions on GHG emissions of 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.

 

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.

 

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.

 

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We may be exposed to liabilities under the U.S. Foreign Corrupt Practices Act and similar anti-corruption laws, and any determination that we violated such laws could have a material adverse effect on our business.

 

We are subject to the United States Foreign Corrupt Practices Act of 1977 (the “FCPA”), as amended, and may be subject to similar worldwide anti-bribery laws including the UK Bribery Act 2010 that generally prohibit companies and their personnel and intermediaries from offering, authorizing, or making improper payments to government officials and to other persons or entities for the purpose of obtaining or retaining business, or securing some improper advantage in business.  We do business and may do additional business in the future in countries and regions in which we may face, directly or indirectly, corrupt demands by officials, tribal or insurgent organizations, or private entities.  As a result, we face the risk that an unauthorized payment or offer of payment could be made by one of our employees or intermediaries, even if such parties are not always subject to our control or are not themselves subject to the FCPA or other anti-bribery laws to which we may be subject.  It is our policy to implement safeguards to prohibit these practices.  However, existing safeguards and any future improvements may not prevent all such conduct, and it is possible that our employees and intermediaries may engage in conduct for which we might be investigated by U.S., UK, or other authorities, and held responsible.  Violations of the FCPA and other anti-bribery laws (either due to our acts or our inadvertence) may result in criminal and civil sanctions and could subject us to other liabilities in the U.S., UK, and elsewhere.  Even allegations of such violations could disrupt our business and result in a material adverse effect on our business and operations.

 

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.  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.

 

Furthermore, in April 2012, the EPA adopted regulations requiring the reduction of volatile organic compound emissions from oil and natural gas production facilities by mandating the use of “green completions” for hydraulic fracturing activities. These regulations require the operator to recover rather than vent gas and natural gas liquids that return to the surface during well completion operations.  At the same time,  the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities on water resources.  The EPA’s study includes 18 separate research projects addressing topics such as water acquisition, chemical mixing, well injection, flowback and produced water, and wastewater treatment and disposal.  The EPA has indicated that it expects to issue its study report in late 2014. From time to time, legislation has been introduced before the Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process.

 

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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, and Colorado 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 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.

 

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 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 expired on December 31, 2012 and the details of the second commitment period, which began on January 1, 2013, are still being negotiated.   In addition, the Parties to the Framework Convention on Climate Change continue negotiations under 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. In response to findings that emissions of carbon dioxide, methane and GHGs, present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, establish PSD construction and Title V operating permit reviews for certain large stationary sources that are potential major sources of GHG emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA on a case-by-case basis. These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore

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and offshore oil and gas production sources in the United States on an annual basis, which include certain of our operations. While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. If Congress undertakes comprehensive tax reform in the coming year, it is possible that such reform may include a carbon tax, which could impose additional direct costs on operations and reduce demand for the oil and natural gas we produce. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. Substantial limitations on GHG emissions could also adversely affect demand for the oil and natural gas we produce. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our exploration and production operations.

 

The enactment of derivatives legislation 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.

 

On July 21, 2010, new comprehensive financial reform legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”),  was enacted that established federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market.  The Act requires the U.S. Commodity Futures Trading Commission (“CFTC”), the SEC and other regulators to promulgate rules and regulations implementing the new legislation. In its rulemaking under the Act the CFTC has issued final 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 would be exempt from these position limits.  The position limits rule was vacated by the United States District Court for the District of Colombia in September of 2012 although the CFTC has stated that it will appeal the District Court’s decision.  The CFTC also has finalized other regulations, including critical rulemakings on the definition of “swap,” “security-based swap,” “swap dealer” and “major swap participant.”  The Act and CFTC Rules also will require us in connection with certain derivatives activities to comply with clearing and trade-execution requirements (or take steps to qualify for an exemption to such requirements).  In addition new regulations may require us to comply with margin requirements although these regulations are not finalized and their application to us is uncertain at this time.  Other regulations also remain to be finalized, and the CFTC recently has delayed the compliance dates for various regulations already finalized.  As a result, it is not possible at this time to predict with certainty the full effects that  the Act and CFTC rules will have on us and the timing of such effects.  The Act also may require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. 

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The Act and any new regulations could significantly increase the cost of derivative contracts (including from swap recordkeeping and reporting requirements and 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 we encounter, reduce our ability to monetize or restructure our existing derivatives contract, and increase our exposure to less creditworthy counterparties.  If we reduce our use of derivatives as a result of the Act 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 Act 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 Act and regulations is to lower commodity prices.  Any of these consequences could have a material adverse effect on our business, financial condition, and 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, 2013 we had $259.2 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 implied 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.

 

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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 on a country-by-country basis.   This quarterly test is called a “ceiling test.”  If net capitalized costs of our oil and gas properties exceed this ceiling test, we must charge the amount of the excess to earnings.  Although a ceiling test write-down does not impact cash flow from operating activities, it does reduce net income and our 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.  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.

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As of March 13, 2014, we had approximately 50.5 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 are freely tradable.

 

In addition, 0.1 million shares are issuable upon the exercise of presently outstanding stock options under our employee incentive plans and 7.0 million shares are issuable upon the exercise of presently outstanding options and warrants unrelated to 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 (“Series C Preferred Stock”), based upon the conversion price of $8.75 per share; 3.8 million shares are issuable upon conversion of our 6.5% Convertible Notes; and 4.9 million shares are issuable upon conversion of our 11.5% Convertible Bonds (as defined below), based on a conversion price of $16.52 per share.

 

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 with Interested Stockholders 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 two 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.  Unresolved Staff Comments

 

None.

 

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Item 2.  Properties

 

Drilling Statistics

 

A well is considered productive for purposes of the following table if it justifies the installation of permanent equipment for the production of oil or gas.  The information contained in the table should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value.  The following table shows the results of the oil and gas wells in which we participated, drilled and tested during 2013,  2012 and 2011:

 

 

 

 

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, 2013, our productive wells included the following:

 

 

 

 

Reserves

 

Our proved oil and gas reserves at December 31, 2013,  2012 and 2011 included the following: 

 

 

 

 

At December 31, 2013, the Alba field, in the U.K. North Sea, represented more than 40% of our proved reserves, with 9.2 MMBOE, 9.9 MMBOE and 1.2 MMBOE of our proved reserves at December 31, 2013,  2012 and 2011, respectively.

 

The Rochelle field, one of our North Sea development assets, represented more than 38% of our proved reserves at December 31, 2013,  2012, and 2011.  Rochelle had 8.9 MMBOE, 9.0 MMBOE and 8.2 MMBOE of proved reserves at December 31, 2013,  2012 and 2011, respectively.

 

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.

 

 

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.  Our proved developed and undeveloped oil and gas reserves at December 31, 2013,  2012 and 2011 included the following:

 

 

 

 

Proved undeveloped (“PUD”) reserves in the U.K. decreased from 17.4 MMBOE at December 31, 2012 to 13.2 MMBOE at December 31, 2013 primarily due to development drilling at Rochelle and its initial production transferring PUD reserves to proved developed reserves.  PUD reserves in the U.S. increased from none at December 31, 2012 to 0.3 MMBOE at December 31, 2013 primarily due to higher US gas pricing resulting in some undrilled locations becoming economic.  If U.S. market conditions continue to improve sufficiently, it is expected that more undeveloped reserves will be economic to develop and will be restored to proved reserves in the U.S.

 

Proved undeveloped (“PUD”) reserves in the U.K. increased from 11.1 MMBOE at December 31, 2011 to 17.4 MMBOE at December 31, 2012 primarily due to our purchase of additional interests in the Alba field and development drilling in Bacchus discovering additional PUD reserves in previously undrilled fault blocks and development drilling in Rochelle.  PUD reserves in the U.S. decreased from 6.4 MMBOE at December 31, 2011 to none at December 31, 2012 primarily due to lower US gas pricing resulting in all undrilled locations becoming uneconomic.  When market conditions improve sufficiently, it is expected that these undeveloped reserves will be economic to develop and will be restored to proved reserves.    During 2012, we invested approximately $182 million to convert our PUD and probable reserves to proved developed reserves primarily in the following areas:

 

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We have one U.K. field, Columbus, where costs have been excluded from amortization for greater than five years; however, we continue to work on the development planning for the field.  Because of the nature of offshore oil and gas activities, development activities, including sanctioning and regulatory approvals, may take a significant amount of time to implement.

 

See Note 5 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.

 

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 and probable 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 Managing Director - UK and Executive Vice President –North America.  In addition, we have a “Technology and Reserves” committee of our Board of Directors.  The committee supports the board by providing increased focus on emerging technologies in the upstream industry and oversight of our reserve evaluation and reporting processes.  Reserves are reviewed internally with senior management quarterly and presented to the Technology and Reserves Committee and our Board of Directors on an annual basis for their review.

 

Our oil and gas reserve estimates 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, well 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 Managing Director - UK, Mr. Derek Neilson, who has 30 years of experience, supervises our technical professionals in the evaluation and estimation of our oil and gas reserves.  Mr. Neilson graduated from Strathclyde University, Scotland, in 1983 with a Bachelor of Science Degree in Mining Engineering and from Heriot Watt University, Scotland, in 1984 with a Masters in Petroleum Engineering.  In addition, we engage experienced and qualified

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employees to perform various comprehensive seismic acquisitions, processing, reprocessing, interpretation, and other related services.

 

The reserves estimates shown herein have been independently audited by Netherland, Sewell & Associates, Inc. (“NSAI”), a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699.  Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Derek Newton and Mr. David Nice.  Mr. Newton has been practicing consulting petroleum engineering at NSAI since 1997.  Mr. Newton is a Licensed Professional Engineer in the State of Texas (No. 97689) and has over 29 years of practical experience in petroleum engineering, with over 16 years’ experience in the estimation and evaluation of reserves.  He graduated from University College, Cardiff, Wales, in 1983 with a Bachelor of Science Degree in Mechanical Engineering and from Strathclyde University, Scotland, in 1986 with a Master of Science Degree in Petroleum Engineering.  Mr. Nice has been practicing consulting petroleum geology at NSAI since 1998.  Mr. Nice is a Licensed Professional Geoscientist in the State of Texas, Geology (No. 346) and has over 29 years of practical experience in petroleum geosciences, with over 15 years’ experience in the estimation and evaluation of reserves.  He graduated from University of Wyoming in 1982 with a Bachelor of Science Degree in Geology and in 1985 with a Master of Science Degree in Geology.  Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

 

NSAI opined that the overall proved reserves for the reviewed properties as estimated by us are, in the aggregate, reasonable 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:

 

 

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, 2013, in the areas indicated.

 

 

 

 

As of December 31, 2013, we had approximately 19,800, 22,500 and 54,000 net acres in the U.K. and U.S combined that are scheduled to expire by December 2014, 2015 and 2016, 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 8,800 net acres and have suspended operations.  It also includes approximately 9,300 net acres in Montana that will expire in 2014-2015, where we have rights to extend certain leases for an additional five years.  We have a total of 60,100 net acres in Montana.  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 on Form 10-K.  Additional detail of production costs is contained in Note 27 to our consolidated financial statements under Item 8 of this Annual Report on Form 10-K.

 

At December 31, 2013, the Alba field, in the U.K. North Sea, represented more than 15% of our proved reserves.  Alba is an oil field and represented 1,612 Mbbls, 1,263  Mbbls and 191 Mbbls of our oil sales in 2013,  2012 and 2011, respectively.

 

At December 31, 2013, the Rochelle field, in the U.K. North Sea, represented more than 15% of our proved reserves.  Rochelle is predominately  a gas field that began producing in late 2013 and represented 1,157 MMcf of our gas sales and 50 Mbbls of our oil sales in 2013.

 

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 1,066 MMcf, 1,986 MMcf and 336 MMcf of our gas sales in 2013, 2012 and 2011, respectively.

 

 

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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 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; and (ii) the condition of the pipeline was not in compliance with applicable regulatory standards.

 

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.  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.  The case is presently scheduled for trial to commence in the second quarter of 2014.    We intend to contest the case vigorously.

 

 

Item 4.  Mine Safety Disclosures

 

Not applicable.

 

 

Part II

 

Item 5.  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

 

Our common stock is listed on the New York Stock Exchange (“NYSE”) under the symbol “END” and the London Stock Exchange under the symbol “ENDV.”

 

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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.  These quotations represent inter-dealer prices, without retail mark-up, markdown or commission, and may not represent actual transactions.

 

 

 

 

Holders

 

As of March 13, 2014, the number of holders of record of our common stock was 132.  We believe that there are a number of additional beneficial owners of our common stock who hold such shares in street name.

 

Dividends

 

We have not paid any cash dividends on our common stock to date and have no intention of declaring or paying any cash dividends on our common stock in the foreseeable future.  The declaration and payment of dividends is subject to the discretion of our Board of Directors and to certain limitations imposed under Nevada corporate laws and the agreements governing our debt obligations.  The timing, amount and form of dividends, if any, will depend on, among other things, our results of operations, financial condition, cash requirements and other factors deemed relevant by our Board of Directors.

 

Our Series B preferred stock is subject to a cumulative 8% dividend (the “Series B Preferred Stock”).  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.

 

Our Series C Preferred Stock is subject to a cumulative dividend, payable in cash or common stock at 4.5% or 4.92%, respectively.  Dividends on the Series C Preferred Stock also participate in any dividends paid on our common stock and are payable to the preferred stock investors prior to payment of any other dividend on any other shares of our capital stock.

 

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

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compliance with all applicable laws.  If we do not maintain the effectiveness of the registration statement, 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.

 

 

 

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, 2013.  Significant property acquisitions and dispositions during these periods have materially affected the comparability of our year-to-year financial data.

 

The following data should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial Statements and Notes thereto included in “Item 8.  Financial Statements and Supplementary Data.”  The selected consolidated financial data provided below are not necessarily indicative of our future results of operations or financial performance.

 

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Information regarding each of these transactions is included in the notes to the Consolidated Financial Statements included elsewhere in this report.

 

 

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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 U.K. operations have been focused on development projects and acquisition, while capital spending by our U.S. operations is primarily related to strategic positioning and proof-of-concept in Marcellus and Niobrara as we monitor U.S. gas prices.  During 2013, 2012 and 2011, our primary focus has been on completing the acquisition of additional interests in both the Bacchus and Alba fields and then moving the Bacchus and Rochelle fields from development to first production.  We closed on the Bacchus and Alba acquisitions in 2011 and 2012, respectively, and achieved first production at Bacchus during the second quarter of 2012.  While Rochelle had storm damage that required a replacement well to be drilled, we achieved production during fourth quarter of 2013.

 

We have both producing and exploration acreage in U.S. onshore unconventional oil and gas shale developments targeting reserve and production growth.  Our ongoing U.S. program and expenditures have been tailored based on drilling results and the decline in U.S. gas prices over the last several years.  We have limited capital expenditures to those necessary to fulfill drilling commitments and maintain acreage positions.

 

In the last two years, we have incurred substantial capital expenditures and acquisition costs as we advanced development projects at Bacchus and Rochelle and completed acquisitions.  We also experienced delays in the timing of first production from our Bacchus and Rochelle developments, a slowing of production from our U.S. drilling operations as we curtailed the U.S. drilling program in response to declining U.S. gas prices, increased capital costs due to the production delays at our Bacchus and Rochelle projects and increased debt service costs required to finance our drilling and acquisition program.  The production delays and increased capital costs and debt service costs placed a strain on our cash flow from operations and our ability to reduce our debt leverage.

 

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2014 Liquidity and Capital Resources

 

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

 

 

As of December 31,  2013, we had $847.9 million in outstanding indebtedness, net of $34.7 million in cash.  Being highly leveraged, servicing our debt and other long-term obligations will continue to require a significant portion of our cash flow from operations and available cash on hand.  We are primarily dependent upon our three significant fields in the U.K. – Alba, Bacchus and Rochelle – for our cash flows from operations.  If we incur delays in production, such as those resulting from the mechanical issues experienced at the Rochelle field, it could negatively impact our cash flows, results of operations and financial condition.

 

Since year-end 2013, our liquidity has been an area of concern, although we have met our debt service obligations we have completed several transactions to improve our liquidity position, including extending the maturities of some of our debt and other obligations.    The completion of these recent financing activities are designed to provide sufficient liquidity to replace the loss of cash flows due to the interruption in production at Rochelle.  These transactions include:

 

 

Although these transactions have contributed to our liquidity, we believe that liquidity is likely to remain an area of focus for us during the remainder of 2014.  If we are unable to meet any short-term liquidity needs out of cash on hand, we would attempt to refinance debt, sell forward our production, sell assets, issue equity, delay discretionary capital expenditures, decline to participate in non-operated drilling or pursue other alternatives.  No assurance can be given however that we could successfully consummate any of these alternatives.

 

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Liquidity and Capital Resources

 

Capital Expenditures

 

Our capital expenditures and acquisitions were as follows

 

 

 

 

North Sea Acquisition

 

On December 23, 2011, we entered into a purchase agreement (the “COP Purchase Agreement”), through our 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 (collectively, the “Sellers”), to acquire their interest in three producing U.K. oil fields in the Central North Sea.  On May 31, 2012, we closed the Alba field portion of this acquisition (the “Alba Acquisition”), which consisted of an additional 23.43% interest in the Alba field.  This increased our total working interest in the Alba field to 25.68%.  The Alba Acquisition was closed for aggregate cash consideration of approximately $229.6 million.

 

Concurrently with the closing of the Alba Acquisition, we entered into a reimbursement agreement related to approximately $120 million of abandonment liabilities for the Alba field.  Under the agreement, we agreed to reimburse the issuers of letter of credit covering our abandonment liabilities in the event that the letter of credit is drawn.  We pay a fee of 13% per year, payable quarterly, computed based on the outstanding amount of each letter of credit.  As of December 31, 2013, we do not expect to begin decommissioning activities for the Alba field for many years.  Additional information pertaining to the reimbursement agreement can be found in Note 22 “Commitments and Contingencies.”

 

On January 24, 2014, we also entered into a letter of credit procurement agreement (the “Combined Procurement Agreement”) with an unaffiliated third party (Payee), where we agreed to reimburse the Payee for any expense incurred by it in connection with the posting of cash collateral to secure letters of credit issued for our account in the amount of approximately £78 million (approximately $130 million as of January 24, 2014).  The letters of credit secure decommissioning obligations in connection with certain of our U.K. licences and have been outstanding and unchanged since 2006.  The Combined Procurement Agreement was entered into to replace the Alba Reimbursement Agreement and the LOC Procurement Agreement.

 

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Due to a change in the U.K. tax treatment for decommissioning, we have amended our Decommissioning Securities Agreement for the Alba field.  The new tax law, which allows companies to treat decommissioning on an after-tax basis (including PRT), enables us to reduce our current letter of credit amount on the Alba field from $120 million to approximately $55 million.

 

United Kingdom Capital Program

 

Our capital program in the U.K. for 2013 was focused on two large projects in the North Sea, the Bacchus and Rochelle fields which are now complete, as well as infill drilling at Alba.

 

As previously discussed, in May 2012, we acquired an additional 23.43% interest in the Alba field, which increased our total working interest in the field to 25.68%.  In April 2013, operations commenced on a three-well infill drilling program at the Alba field.  The first two development wells were completed by August 2013, just prior to the shutdown for the planned maintenance program from mid-August to mid-September 2013.  Following the shutdown, the operator identified that the water injection pipeline supplying pressure to the southern area of the field had ruptured, causing a portion of the southern region to be shut-in.  The Alba 2013 exit rate was 18,500 barrels per day gross, below the levels expected from the field.  Remedial action is currently being taken to reinstate partial water injection to offset some of the reduced production, and the permanent replacement of the pipeline is expected in late 2014.  The 2013 infill drilling campaign recommenced in November 2013 with an additional well that began producing during the first quarter of 2014.  We expect production to increase upon initial production from this development well.  An additional two development wells are scheduled to be drilled during 2014.

 

In April and July 2012, we achieved production from the first and second development wells, respectively, on the Bacchus field, where we hold a 30% working interest.  Following completion of the second development well, the Bacchus partners decided to evaluate the positive data gained from the second development well and observe production results before making a final decision on the placement of the third development well to ensure optimization of the entire reservoir.  Drilling of the third well began in April 2013 and was completed in July 2013.  The 2013 production exit rate at the field was over 10,000 barrels per day gross.  During the third quarter of 2013, a new 3D seismic survey was shot over the Bacchus field to gain additional understanding of field performance and identify additional Bacchus development opportunities.  Consistent with the original development plans, the first well drilled is expected to be turned into a water injector during the second quarter of 2014.  This will provide pressure support to help sustain the field’s production rate and increase its overall recovery.  Production from the field is expected to continue to decline in line with our field estimates until additional development opportunities can be undertaken.

 

At the Rochelle field, a gas-condensate field where we hold a 44% working interest, we began drilling the first of the two planned development wells in the latter part of 2012.  With drilling delays, the Rochelle project subsea infrastructure outpaced the drilling operations.  The joint interest partners decided to suspend the first well due to the inability to perform simultaneous pipe-lay and development drilling operations.  In October 2012, the drilling rig moved off location to allow for the hook-up of the pipelines and flow-lines to the subsea manifolds, thereby

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delaying our estimated start of production from the fourth quarter of 2012 to the first quarter of 2013.

 

In January 2013, the rig returned to the East Rochelle site to continue final drilling.  In February 2013, following a severe storm lasting several days, we performed a routine inspection of the conductor, wellhead and blow out preventer systems which revealed that a non-uniform hole had been formed around the conductor.  As a result of this finding, the East Rochelle E1 was plugged and abandoned in August 2013.  We have made an insurance claim to recover certain abandonment and redrill costs; however, no assurance can be given that we can successfully recovery any costs.

 

To mitigate delays while we conducted our analysis of the East Rochelle well, we moved the rig to the West Rochelle area and commenced drilling of the second production well. Drilling began on the West Rochelle W1 well in the first quarter of 2013 and it was completed and flow tested in June 2013.

 

Following the Scott Platform shutdown from July 11 to September 5, 2013, first production from Rochelle started on October 23, 2013 from the West Rochelle W1 well.  Production was ramped up to 65 - 70 MMcf of gas per day with an additional 2,500 - 3,000 barrels per day of liquids, 6,000 – 7,000 BOE net to Endeavour’s working interest in the field.

 

The Transocean Prospect rig returned to the Rochelle field and commenced drilling the second Rochelle development well (E2 well at East Rochelle) on July 25, 2013.  The well was successfully drilled to total depth and was completed in November 2013.  It was tested at a maximum rate of 64 MMcf per day constrained by rig equipment.  The E2 well was tied-in to the East Rochelle manifold in December 2013 but due to continued periods of inclement weather in the U.K. North Sea start-up could not commence until mid-January 2014.

 

By January 2014, both the E2 and W1 development wells at Rochelle were fully completed and tied-in to the production manifolds.  As part of the final installation and start-up of the E2 well, the W1 well was shut-in.  During the well start-up procedure, a valve on the outlet side of the East Rochelle production manifold was stuck in the “shut” position.  An attempt to open the valve manually was unsuccessful and the operator secured an intervention vessel to open the valve.  The valve was successfully opened in February 2014.   The E2 well commenced production on February 28, 2014.  The E2 production is ramping up and the W1 well is anticipated to restart production in March 2014.  This unanticipated downtime will negatively affect our daily production rates and associated revenue for the first quarter of 2014, as well as our near-term liquidity.  When both E2 and W1 wells are on production, we expect the production from the Rochelle field to exceed the available production capacity at the Scott platform.

 

United States Capital Program

 

Our primary focus in the U.S. has been onshore unconventional oil and gas developments.  During 2011, we completed 16 productive wells, and had an additional eight wells, awaiting on completion.  During 2012, we completed two Haynesville gas wells.  With declining U.S. gas

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prices, we have limited our capital expenditures in 2013 to primarily those expenditures necessary to maintain our acreage positions and fulfill minor drilling commitments.

 

Capital Resources

 

 

 

 

Our primary sources of financial resources and liquidity are cash on hand, internally generated cash flows from operations and the credit and capital markets.

 

Cash flow provided by operations increased to $57.4 million for 2013 from $38.6 million for 2012 due to cash flows from our purchase of the additional interest in Alba.  Cash flow provided by (used in) operations increased to $38.6 million for 2012 from ($39.3) million for 2011 primarily 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 additional debt facilities.  Net cash provided by financing activities has provided the necessary funding for our capital expenditures, primarily related to our drilling activities at our Bacchus and Rochelle fields in the U.K., and our acquisitions of additional interests in Bacchus and Alba and U.S. acreage.

 

Our debt facilities, letters of credit, reimbursement agreements and related transactions for 2013,  2012 and 2011 were as follows:

 

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Our equity issuances for 2012 and 2011 were as follows:

 

 

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Strategic Alternatives

 

As discussed previously, in February 2013, we announced that our Board of Directors approved a review of strategic alternatives.  The primary objective of the strategic review was to accelerate the deleveraging of the balance sheet and unlock the value of our underlying assets.  The strategic review was concluded in October 2013.  The Board of Directors determined that it was in the best interest of our shareholders to retain and exploit our existing asset base, while initiating several organizational changes and cost-saving initiatives.  As of December 31, 2013, we had consolidated our U.K. operations in Aberdeen, Scotland, closed our London office, and re-aligned several key personnel internally.

 

Results of Operations

 

Our revenues and cash flows from operating activities are very sensitive to changes in the prices we receive for the oil and natural gas we produce.  Our production is sold at prevailing market prices, which may be volatile and subject to numerous factors which are outside of our control.  Further, the current tightly balanced supply and demand market means a small variation in supply or demand can significantly impact the market prices for these commodities. Our realized price per BOE, before derivatives, increased from $76.08 per BOE in 2012 to $92.36 per BOE in 2013.  Our revenues increased from $219.1 million for the year ended December 31, 2012 to $337.7 million for 2013 primarily as a result of continued production volumes from our Bacchus field and initial production from the Rochelle field.  Our revenues increased from $60.1 million for the year ended December 31, 2011 to $219.1 million for 2012 primarily as a result of higher production volumes related to first production from Bacchus in the second quarter of 2012 and our purchase of the additional interest in Alba.

 

For 2013, net loss to common stockholders was $(97.3) million, or $(2.07) per diluted share.    This net loss includes a $9.6 million impairment related to our U.S. properties, increased interest expense resulting from borrowings under existing debt agreements.  Net loss to common stockholders for 2012 was $(128.0) million, or $(3.01) per diluted share.  The 2012 net loss includes a $53.1 impairment related to our U.S. properties, increased interest expense resulting from borrowings under existing debt agreements, issuances of new debt obligations and a loss on the early extinguishment of debt of $21.7 million.  Net loss to common stockholders for 2011 was $(133.0) million, or $(3.70) per diluted share.  The 2011 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 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 $57.4 million in 2013 versus $38.6 million in 2012 and ($39.3) million in 2011.  Adjusted EBITDA (as defined below) was $203.3 million in 2013, as compared to $129.9 million in 2012 and $25.1 million in 2011.  These fluctuations in Adjusted EBITDA are primarily due to the changes in our production volumes, and operating costs.

 

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-

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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, 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 loss as adjusted.

 

Net loss as adjusted for 2013 was $(84.3) million.  Net loss as adjusted for 2012 was $(54.2) million, as compared to net loss as adjusted of $(49.7) million in 2011.

 

For definitions of net income and loss 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.”

 

Revenues

 

Our revenues and sales volumes have fluctuated significantly during the last three years primarily due to the following:

 

 

 

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The following table shows our annual average sales volumes, sales prices and average production costs.

 

 

 

 

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Our revenues, profitability and cash flow depend substantially upon the prices and demand for oil and gas and are subject to numerous operational and financial risks, some of which are beyond our control.  The markets for these commodities are volatile, and even relatively modest drops in prices can significantly affect our financial results and impede our growth.

 

The markets in which we sell our oil and natural gas also materially impact our revenues and cash flows.  Oil trades on a worldwide market, and, consequently, price movements for all types and grades of crude oil generally trend in the same direction and within a relatively narrow price range.  However, natural gas prices vary among geographic areas as the prices received are largely impacted by local supply and demand conditions as the global transportation infrastructure for natural gas is still developing.  As such, the oil we produce and sell is typically sold at prices in line with global prices, whereas our natural gas is to a large extent impacted by regional supply and demand issues and to a lesser extent by global fuel prices, including oil and coal.  The U.S. gas market is heavily impacted by the increased supply from shale drilling, which has served to depress natural gas prices relative to the U.K. market.

 

Operating Expenses

 

For 2013, operating expenses increased to $105.4 million as compared to $58.5 million for 2012, primarily due to costs related to production from our Alba, Bacchus and Rochelle fields.    Operating costs per BOE increased to $28.84 per BOE for 2013 from $20.33 per BOE for 2012 primarily due to the continued increase in proportion of U.K. operations to our total expenses and workovers in our U.S. fields.  On average, our U.K. operations have higher operating costs per BOE than our U.S. operations, thereby increasing our overall operating costs per BOE.

 

For 2012, operating expenses increased to $58.5 million as compared to $17.7 million for 2011,  primarily due to costs related to our increased interest in the Alba field and initial production from the Bacchus field.  Operating costs per BOE increased to $20.33 per BOE for 2012 from $14.31 per BOE for 2011 due to the increase in proportion of U.K. operations to our total expenses.  In addition, 2012 operating expenses increased as a result of the sale of $9.7 million of oil inventory purchased in the Alba Acquisition (as defined below).

 

DD&A and Impairment of Oil and Gas Properties

 

Depreciation, depletion and amortization (“DD&A”) expense increased from 2012 to 2013 primarily due to increased production from the Alba, Bacchus and Rochelle fields.  DD&A expense increased from 2011 to 2012 primarily due to increased production due to our acquisition of additional interest in Alba and initial production from Bacchus.  DD&A per BOE

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was $39.12,  $23.11 and $21.45 for the years ended December 31, 2013,  2012 and 2011, respectively.  The increase in DD&A per BOE resulted from our increased production through the three year period.

 

In 2013,  2012 and 2011, we recorded $9.6 million,  $53.1 million and $65.7 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 primary reason for the 2013 impairment was the evaluation of certain U.S. assets not subject to amortization which we no longer intend to pursue and accordingly are included in the full cost pool.  The 2012 impairment was primarily related to the declines in U.S. gas prices.  The 2011 impairment was primarily related to the decline 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.

 

General and Administrative (“G&A”) Expenses

 

Our G&A expenses decreased from $21.1 million in 2012 to $19.1 million for 2013 as a result of decreased employee compensation expense, consulting fees, and travel expense primarily resulting from staff realignments and reductions in the U.K resulting from our strategic review.  We expect gross G&A expenses to be lower in 2014 as the majority or our staff realignments and reductions occurred late in 2013.  The increase in G&A expense from $17.9 million in 2011 to $21.1 million in 2012 was a result of an increase in employee compensation expense and an increase in consulting costs associated with the additional staff to pursue the Rochelle development as operator and our expanding U.K. operations.

 

Non-cash stock-based compensation is comprised of expense related to grants of restricted stock and performance awards, which were granted for the first time in 2012.  The restricted stock awards were valued based on the closing price of our common stock on the measurement date, typically the date of grant.  The performance awards are valued on the date of grant using a Monte Carlo simulation model.  In January 2012, certain of our executive officers were granted a target number of performance shares that will be earned as the relative total shareholder return ranking is measured among a designated peer group at the end of a three-year performance period.  Payouts will be based on a predetermined schedule at the end of the performance period and may range from 0% to 200% of the number of performance units.  See Note 13 to our consolidated financial statements in “Item 8. Financial Statements and Supplementary Data.”

 

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Components of G&A expenses for these periods are as follows:

 

 

 

 

Interest Expense and Other

 

The increase in interest expense from $84.1 million in 2012 to $104.5  million in 2013 reflects the increases in interest expense that occurred as we completed several financing transactions during 2013 and 2012 that have had a significant impact on our interest expense, including the issuance of new debt facilities and the repayment of extinguished debt.  Components of interest expense are as follows:

 

 

 

Each of our debt instruments and transactions are discussed in Note 10 to our consolidated financial statements in “Item 8. Financial Statements and Supplementary Data.”

 

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Income Taxes

 

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

 

 

 

 

We currently do not record tax benefits for 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

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tax assets generated.  Therefore, our income tax expense relates primarily to our operations in the U.K.  During 2012, the U.K. government enacted legislation (retroactive to March 2012) to restrict decommissioning expenditures to 20% for supplemental corporate tax, in addition to the U.K. corporate tax of 30%.  This resulted in total tax relief available for decommissioning at 50%.  As a result of this enactment, we incurred additional income tax expense of $8.6 million.

 

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%.

 

Our current tax expense is related to Petroleum Revenue Tax (“PRT”) on our Alba field in the U.K.  The increase in current tax expenses from 2011 to 2012 is primarily due to our acquisition of the additional interest in the Alba field in 2012.

 

Tax Attributes

 

At December 31, 2013, we had the following tax attributes available to reduce future income taxes:

 

 

 

 

As of December 31, 2013, the U.K. tax attributes shown above have been recognized for financial statement reporting purposes to reduce deferred tax liability.  As of December 31, 2013, the U.S. tax attributes shown above have been not recognized for financial statement reporting purposes as we have full valuation allowance for our U.S. net operating and capital loss carry forwards.

 

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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%.

 

 

 

 

2014 Outlook

 

Planned Capital Expenditures

 

We expect that our total capital expenditure budget for 2014 will be approximately $70 million, of which we expect to spend approximately $45 million in the U.K., primarily on drilling at Alba.  We expect to spend the remainder of our 2014 capital budget in the U.S. to maintain our acreage positions and to fulfill minor drilling commitments.  Our 2014 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 2014 capital expenditures primarily through cash on hand, cash flow generated from operations and our financing activities in early 2014.

 

Decommissioning Expenditures

 

Production from each of our Ivanhoe, Rob Roy, Hamish (collectively, “IVRRH”), Renee, Rubie and Goldeneye fields has ceased and we have performed maintenance and decommissioning activities over the last several years.  We expect to incur approximately $50 million in decommissioning charges during 2014.

 

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First Quarter Production Guidance

 

With the unanticipated downtime at the Rochelle field and continued restricted rates at Alba, average daily production volumes are expected to be in the range of 9,000 – 10,000 boepd for the first quarter of 2014.

 

At December 31, 2013, we had the following floors and ceilings embedded within our marketing contracts and forward sales:

 

 

 

 

 

 

Recent Financing Arrangements

 

In February 2014, we entered into a securities purchase agreement relating to the issuance of up to $55 million in common stock, warrants and convertible notes.  We closed on an initial $30 million in late February and early March 2014, comprised of:

 

In January 2014, we and our subsidiaries entered into a credit agreement (“Term Loan Facility”) under which our lenders advanced $125 million.  Concurrent with our entry into this facility, we terminated our Revolving Credit Facility and all outstanding borrowings and accrued interest and fees under such facility were paid in full.  The Term Loan Facility bears quarterly interest at LIBOR plus 7.00% (provided LIBOR equals at least 1.25% annually) and will mature on the earlier of November 30, 2017 or 91 days prior to the maturity of the company’s 5.5% convertible senior notes and 11.5% convertible notes both due 2016.  For additional information regarding the Term Loan Facility, see Note 26 “Subsequent Events.”

 

On January 24, 2014, we also entered into a letter of credit procurement agreement (the “Combined Procurement Agreement”) with an unaffiliated third party (Payee), where we agreed to reimburse the Payee for any expense incurred by it in connection with the posting of cash collateral to secure letters of credit issued for our account in the amount of approximately £78 million (approximately $130 million as of January 24, 2014).  The letters of credit secure decommissioning obligations in connection with certain of our U.K. licences and have been outstanding and unchanged since 2006.  The Combined Procurement Agreement was entered into to replace the Alba Reimbursement Agreement and the LOC Procurement Agreement.

 

Due to a change in the U.K. tax treatment for decommissioning, we have amended our Decommissioning Securities Agreement for the Alba field.  The new tax law, which allows

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companies to treat decommissioning on an after-tax basis (including PRT), enabled us to reduce our letter of credit amount on the Alba field from $120 million to approximately $55 million.  The reduced requirements as a result of the new U.K. decommissioning tax treatment, combined with the refinancing activities completed in January 2014, is expected to generate an annual cash savings of approximately $17 million to the Company.

 

Each of these transactions is discussed in Note 26 to our consolidated financial statements in “Item 8. Financial Statements and Supplementary Data.”

 

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.  These measures 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, they 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.

 

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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, 2013:

 

 

 

 

 

Off-Balance Sheet Arrangements

 

At December 31, 2013, our reimbursement agreements related to abandonment liabilities were off-balance sheet arrangements and covered approximately $153 million of our abandonment liabilities for certain of our U.K. oil and gas properties.  Subsequent to December 31, 2013, we replaced our existing reimbursement agreements and reduced the amount to $88 million.  See Note 26 “Subsequent Event” for additional discussion.  Under these agreements, unaffiliated third parties pledged cash to secure letters of credit covering certain of our abandonment liabilities and we agreed to reimburse the pledged cash in the event that the letters of credit are drawn and pledged cash is utilized to satisfy the commitment.  We have no cash collateral associated with the reimbursement agreements and the commitments under the reimbursement agreements are not recorded as liabilities.  The associated abandonment obligations are recorded in other long-term liabilities as part of our asset retirement obligations.  Fees and expenses related to the reimbursement agreements are included in other expenses on our condensed consolidated statement of operations.  See Note 22 to our consolidated financial statements in “Item 8. Financial Statements and Supplementary Data” for additional discussion.

 

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.  While management regularly reviews its estimates, including those related to the determination of proved reserves, estimates of future dismantlement costs, income taxes and litigation, actual results could differ from those estimates.

 

Management believes it is reasonably possible that the following material estimates affecting the financial statements could change in the coming year: (1) estimates of proved oil and gas reserves, (2) estimates as 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:

 

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Full Cost Accounting

 

Under the full cost method of accounting for oil and gas activities, 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 at 10%, of:

 

 

Future net cash flows use the average, first-day-of-the-month price for commodities during 2013,  2012 and 2011.

 

We utilize a single cost center for each country where we have operations for amortization purposes.  Any sales or other conveyances of properties are treated as adjustments to the cost of oil and gas properties with no gain or loss recognized unless the operations are suspended in the entire cost center or the conveyance is significant in nature.

 

Unproved property costs include the costs associated with unevaluated properties and properties under development and are not initially included in the full cost amortization base (where proved reserves exist) until the project is evaluated.  These costs include unproved leasehold acreage, seismic data, wells and production facilities in progress and wells pending determination, together with interest costs capitalized for these projects. Seismic data costs are associated with specific unevaluated properties where the seismic data is acquired for the purpose of evaluating acreage or trends covered by a leasehold interest owned by us.

 

Significant unproved properties are assessed periodically for possible impairment or reduction in value.  If a reduction in value has occurred, these property costs are considered impaired and are transferred to the related full cost pool.  Geological and geophysical costs included in unproved properties are transferred to the full cost amortization base along with the associated leasehold costs on a specific project basis. Costs associated with wells in progress and wells pending determination are transferred to the amortization base once a determination is made whether or not proved reserves can be assigned to the property.  Costs of dry holes are transferred to the amortization base immediately upon determination that the well is unsuccessful.  Unproved properties whose acquisition costs are not individually significant are aggregated and the portion

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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.

 

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.  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 reporting unit’s fair value.

 

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At December 31, 2013, we had $259.2 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 2013 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, 2013.

 

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, and offshore production platforms, 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.

 

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

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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 recorded when production is transported by pipeline or production is shipped out of our storage tanks.  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.

 

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

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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, 2013, we had approximately 1.8 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 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.  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.  As the timing of expenditures in pounds sterling has been predictable, 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.  At December 31, 2013, we have exposure to exchange rate changes applicable to cash balances in our U.K. pound denominated bank accounts.  A 10% change in the foreign-currency exchange rate would not have a material effect on our financial position or results of operations.

 

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Interest Rate Risk

 

At December 31, 2013, 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.  The Term Loan Facility and the Combined Procurement Agreement issued in January 2014 will be subject to market changes in interest rates.

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Item 8.  Financial Statements and Supplementary Data

 

 

Report of Independent Registered Public Accounting Firm

 

The Board of Directors and Stockholders of

Endeavour International Corporation

 

We have audited the accompanying consolidated balance sheets of Endeavour International Corporation and subsidiaries as of December 31, 2013 and 2012, and the related consolidated statements of operations, stockholders' equity and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

 

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

 

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Endeavour International Corporation and subsidiaries at December 31, 2013 and 2012, and the consolidated results of their operations and their cash flows for the years then ended, in conformity with U.S. generally accepted accounting principles.

 

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Endeavour International Corporation and subsidiaries’ internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) and our report dated March 14, 2013 expressed an unqualified opinion thereon.

 

 

/s/  Ernst & Young LLP

 

Houston, Texas

March 14, 2014

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Endeavour International Corporation:

We have audited the accompanying consolidated statements of income, stockholders’ equity, and cash flows of Endeavour International Corporation and subsidiaries (the Company) for the year 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 audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the results of operations and the cash flows of Endeavour International Corporation and subsidiaries for the year ended December 31, 2011, in conformity with U.S. generally accepted accounting principles.

(signed) KPMG LLP

Houston, Texas
March 7, 2012, except for Note 25, as to which date is March 18, 2013