Item 1. Business
General
We believe we are a leading, highly diversified provider of specialized oilfield services and equipment. We focus on serving the drilling-related needs of oil and gas companies primarily through our drilling products and services segment, and the production-related needs of oil and gas companies through our subsea and well enhancement, drilling products and services and marine segments. We believe that we are one of the few companies capable of providing the services and tools necessary to maintain, enhance and extend the life of producing wells, as well as plug and abandonment services at the end of their life cycle. We also own oil and gas properties in the Gulf of Mexico. We believe that our ability to provide our customers with multiple services and to coordinate and integrate their delivery, particularly offshore through the use of our liftboats, allows us to maximize efficiency, reduce lead time and provide cost effective solutions for our customers. We have expanded geographically and now have a significant presence in both domestic and international market areas. Excluding the continental United States, we currently have physical locations in the following geographic regions: Latin America (Brazil, Colombia, Ecuador, Trinidad and Tobago and Venezuela), North America (Canada), North Sea and Europe (Norway, Netherlands, Germany and the United Kingdom), Middle East (Kazakhstan and United Arab Emirates), West Africa (Angola and Nigeria) and Asia Pacific (Australia, Indonesia, Malaysia and Singapore).
Operations
Our operations are organized into the following business segments:
Subsea and Well Enhancement. We provide subsea and well enhancement services that are used to build out oil and gas production infrastructure, stimulate oil and gas production, plug and abandon uneconomic or non-producing wells and decommission offshore oil and gas platforms. Our subsea and well enhancement services include integrated subsea and engineering services, coiled tubing, electric line, pumping and stimulation, gas lift, well control, hydraulic workover and snubbing, mechanical wireline, recompletion, stimulation and sand control equipment and services, well evaluation, offshore oil and gas tank and vessel cleaning, decommissioning and plug and abandonment. In connection with our acquisition of the Bullwinkle platform and its related assets, production
handling arrangements, as well as the production and sale of oil and gas from our properties in the Gulf of Mexico are included in this segment. Additionally, we manufacture and sell specialized drilling rig instrumentation equipment. Our subsea and well enhancement segment conducts operations in over 50 countries within Latin America, North America, the North Sea region, Continental Europe, the Middle East, Central Asia, West Africa and the Asia Pacific region.
We believe we are the leading provider of wireline services in the Gulf of Mexico. We service this market area with approximately 135 offshore wireline units, 25 offshore electric line units and ten dedicated liftboats configured specifically for wireline services. We also own and operate 47 land wireline units, 67 land electric line units, 33 land coiled tubing units and six offshore coiled tubing units. Additionally, we own two derrick barges each equipped with an 800 metric ton crane, two dynamically positioned vessels suited for subsea intervention projects, three saturation diving systems and 25 remotely operated vehicles used for inspection, repair and maintenance work. We are also a lessee of a third dynamically positioned subsea vessel under a capital lease that expires in 2019.
Drilling Products and Services. We believe we are a leading provider of drilling products and services. We manufacture, sell and rent specialized equipment for use with offshore and onshore oil and gas well drilling, completion, production and workover activities. Through internal growth and acquisitions, we have increased the size and breadth of our drilling products inventory and geographic scope of operations so that we now conduct operations offshore in the Gulf of Mexico, onshore in the United States and in select international market areas. We currently have locations in all of the major staging points in Louisiana and Texas for oil and gas activities in the Gulf of Mexico, and in North Louisiana, Texas, Arkansas, Oklahoma, Colorado, Pennsylvania, North Dakota and Wyoming. Our drilling products and services segment conducts operations in over 35 countries within Latin America, North America, the North Sea region, Continental Europe, the Middle East, Central Asia, West Africa and the Asia Pacific region. Our drilling products and services include pressure control equipment, specialty tubular goods including drill pipe and landing strings, connecting iron, handling tools, stabilizers, drill collars and on-site accommodations.
Marine Services. We own and operate a fleet of liftboats that is highly complementary to our subsea and well enhancement services. A liftboat is a self-propelled, self-elevating work platform with legs, cranes and living accommodations. Our fleet consists of 25 liftboats with leg lengths ranging from 145 feet to 265 feet. Our liftboat fleet has leg lengths and deck spaces that are suited to deliver our production-related bundled services and support customers in their construction, maintenance and other production enhancement projects. All of our liftboats are currently located either in the Gulf of Mexico or the Atlantic Ocean.
Equity-Method Investments. Our equity-method investments in SPN Resources, LLC (SPN Resources) and DBH, LLC (DBH), the successor company of Beryl Oil and Gas, LP, provide us additional opportunities for our subsea and well enhancement, decommissioning and platform management services. SPN Resources and DBH utilize our production-related assets and services to maintain, enhance and extend existing production of these properties. At the end of a property’s economic life, we offer services to plug and abandon the wells and decommission and abandon the facilities.
For additional industry segment financial information, see note 14 to our consolidated financial statements included in Item 8 of this Form 10-K.
Customers
Our customers are the major and independent oil and gas companies that are active in the geographic areas in which we operate. In 2010, no single customer accounted for more than 10% of our total revenue. Of our 2009 and 2008 total revenue, Chevron accounted for approximately 15% and 12%, respectively, Apache accounted for approximately 13% and 11%, respectively, and BP accounted for approximately 11% for each year. Our inability to continue to perform services for a number of our large existing customers, if not offset by sales to new or other existing customers, could have a material adverse effect on our business and operations.
Competition
We operate in highly competitive areas of the oilfield services industry. The products and services of each of our operating segments are sold in highly competitive markets, and our revenues and earnings can be affected by the following factors:
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changes in competitive prices;
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oil and gas prices and industry perceptions of future prices;
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fluctuations in the level of activity by oil and gas producers;
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changes in the number of liftboats operating in the Gulf of Mexico;
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the ability of oil and gas producers to generate capital;
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general economic conditions; and
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governmental regulation.
We compete with the oil and gas industry’s largest integrated oilfield service providers in the production-related services provided by our subsea and well enhancement segment. The rental tool divisions of these companies, as well as several smaller companies that are single source providers of rental tools, are our competitors in the drilling products and services market. In the marine services segment, we compete with other companies that provide liftboat services. We believe the principal competitive factors in the market areas that we serve are price, product and service quality, safety record, equipment availability and technical proficiency.
Our operations may be adversely affected if our current competitors or new market entrants introduce products or services with better features, performance, prices or other characteristics than our products and services. Further, if our competitors construct additional liftboats, it could affect vessel utilization and resulting day rates. Competitive pressures or other factors also may result in significant price competition that could reduce our operating cash flow and earnings. In addition, competition among oilfield service and equipment providers is affected by each provider’s reputation for safety and quality.
Potential Liabilities and Insurance
Our operations involve a high degree of operational risk and expose us to significant liabilities. Failure or loss of our equipment could result in personal injury, damage or loss of property and equipment, environmental accidents and pollution and other damages for which we could be liable. Litigation arising from a catastrophic occurrence, such as a sinking of a marine vessel or a fire, explosion or well blowout at a location we lease or where our equipment and services are used may result in substantial claims for damages. We also may have limited exposure to liability for economic losses sustained by third parties due to catastrophic occurrences.
In addition to liability exposure for our own actions, we may also be liable for damages caused by the fault of third parties, including our customers. This is due to indemnification rights contained in most of our customer contracts, pursuant to which we agree to indemnify our customers for any personal injuries or property damages sustained by our personnel or equipment, regardless of who is at fault for such injuries or damages.
We maintain insurance against risks that we believe is consistent in types and amounts with industry standards and is required by our customers, including coverage for our contractual indemnification obligations. Changes in the insurance industry in the past few years have led to higher insurance costs and deductibles as well as lower coverage limits, causing us to rely on self insurance against many risks associated with our business. The availability of insurance covering risks we typically insure against may continue to decrease, and the costs of such insurance and
deductibles may continue to increase, forcing us to self insure against more business risks, including the risks associated with hurricanes. The insurance that we are able to obtain may have higher deductibles, higher premiums, lower limits and more restrictive policy terms.
Health, Safety and Environmental Assurance
We have established health, safety and environmental performance as a corporate priority. Our goal is to be an industry leader in this area by focusing on the belief that all safety and environmental incidents are preventable and an injury-free workplace is achievable by emphasizing correct behavior. We have a company-wide effort to enhance our behavioral safety process and training program to make safety a constant area of focus through open communication with all of our offshore, onshore and yard employees. In addition, we investigate all incidents with a priority of identifying and implementing the corrective measures necessary to reduce the chance of reoccurrence.
Government Regulation
Our business is significantly affected by the following:
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federal, state and international laws and other regulations relating to the oil and gas industry;
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changes in such laws and regulations; and
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the level of enforcement thereof.
We cannot predict the level of enforcement of existing laws and regulations or how such laws and regulations may be interpreted by enforcement agencies or court rulings in the future. A change in the level of industry compliance with or enforcement of these laws and regulations in the future may adversely affect the demand for our services. Additionally, the denial or delay of, or any other changes in the procedures and timing for, issuing permits necessary to our and our customers’ operations could significantly affect our business. We also cannot predict whether additional laws and regulations will be adopted, including changes in regulatory oversight, increase of inspection costs or removal of applicable liability caps, or the effect such changes may have on us, our businesses or our financial condition. The demand for our services from the oil and gas industry would be affected by changes in applicable laws and regulations. The adoption of new laws and regulations curtailing drilling for oil and gas in our operating areas for economic, environmental or other policy reasons could also adversely affect our operations by limiting demand for our services.
Environmental Regulations
General. Our operations are subject to extensive federal, state and local laws and regulations relating to the generation, storage, handling, emission, transportation and discharge of materials into the environment. Permits are required for the conduct of our business and operation of our various marine vessels. These permits can be revoked, modified or renewed by issuing authorities. Governmental authorities enforce compliance with their regulations through administrative or civil penalties, corrective action orders, injunctions or criminal prosecution. Although we believe that compliance with environmental regulations will not have a material adverse effect on us, risks of substantial costs and liabilities related to environmental compliance issues are part of our operations. No assurance can be given that significant costs and liabilities will not be incurred.
Federal laws and regulations applicable to our operations include those controlling the discharge of materials into the environment, requiring removal and cleanup of materials that may harm the environment, requiring consistency with applicable coastal zone management plans, or otherwise relating to the protection of the environment.
Our insurance policies provide liability coverage for sudden and accidental occurrences of pollution or clean up and containment in amounts that we believe are prudent and comparable to policy limits carried by others in our industry.
Outer Continental Shelf Lands Act. The Outer Continental Shelf Lands Act (OCSLA) and regulations promulgated pursuant thereto impose a variety of regulations relating to safety and environmental protection applicable to lessees, permittees and other parties operating on the Outer Continental Shelf. Specific design and operational standards may apply to Outer Continental Shelf vessels, rigs, platforms, vehicles and structures. Violations of lease conditions or regulations issued pursuant to OCSLA can result in substantial civil and criminal penalties as well as potential
court injunctions curtailing operations and the cancellation of leases. Enforcement liabilities under OCSLA can result from either governmental or citizen prosecution. We believe that we substantially comply with OCSLA and its regulations.
Solid and Hazardous Waste. We own and lease numerous properties that have been used in connection with the production of oil and gas for many years. Although we believe we utilize operating and disposal practices that are standard in the industry, it is possible that hydrocarbons or other solid wastes may have been disposed of or released on or under the properties owned and leased by us. Federal and state laws applicable to oil and gas wastes and properties continue to be stricter over time. Under these increasingly stringent requirements, we could be required to remove or remediate previously disposed wastes (including wastes disposed or released by prior owners and operators) or clean up property contamination (including groundwater contamination by prior owners or operators) or to perform plugging operations to prevent future contamination. We generate some hazardous wastes that are already subject to the Federal Resource Conservation and Recovery Act (RCRA) and comparable state statutes. The Environmental Protection Agency (EPA) has limited the disposal options for certain hazardous wastes. It is possible that certain wastes currently exempt from treatment as hazardous wastes may in the future be designated as hazardous wastes under RCRA or other applicable statutes. We could, therefore, be subject to more rigorous and costly disposal requirements in the future than we encounter today.
Superfund. The Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on certain persons with respect to the release of hazardous substances into the environment. These persons include the owner and operator of a site and any party that disposed of or arranged for the disposal of hazardous substances found at a site. CERCLA also authorizes the EPA, and in some cases, private parties, to undertake actions to clean up such hazardous substances, or to recover the costs of such actions from the responsible parties. In the course of business, we have generated and will continue to generate wastes that may fall within CERCLA’s definition of hazardous substances. We may also be an operator of sites on which hazardous substances have been released. As a result, we may be responsible under CERCLA for all or part of the costs to clean up sites where such wastes have been disposed.
Oil Pollution Act. The Federal Oil Pollution Act of 1990 (OPA) and resulting regulations impose a variety of obligations on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills in waters of the United States. The term “waters of the United States” has been broadly defined to include inland water bodies, including wetlands and intermittent streams. OPA assigns liability to each responsible party for oil removal costs and a variety of public and private damages. We believe that we substantially comply with OPA and related federal regulations.
Clean Water Act. The Federal Water Pollution Control Act (Clean Water Act) and resulting regulations, which are implemented through a system of permits, also govern the discharge of certain contaminants into waters of the United States. Sanctions for failure to comply strictly with the Clean Water Act are generally resolved by payment of fines and correction of any identified deficiencies. However, regulatory agencies could require us to cease operation of our marine vessels that are the source of water discharges. We believe that we substantially comply with the Clean Water Act and related federal and state regulations.
Clean Air Act. Our operations are subject to local, state and federal laws and regulations to control emissions from sources of air pollution. Payment of fines and correction of any identified deficiencies generally resolve penalties for failure to comply strictly with air regulations or permits. Regulatory agencies could also require us to cease operation of certain marine vessels that are air emission sources. We believe that we substantially comply with the emission standards under local, state, and federal laws and regulations.
Maritime Employees
Certain of our employees who perform services on offshore platforms and marine vessels are covered by the provisions of the Jones Act, the Death on the High Seas Act and general maritime law. These laws operate to make the liability limits established under state workers’ compensation laws inapplicable to these employees. Instead, these employees or their representatives are permitted to pursue actions against us for damages resulting from job related injuries, with generally no limitations on our potential liability.
Employees
As of January 31, 2011, we had approximately 5,700 employees. None of our employees are represented by a union or covered by a collective bargaining agreement. We believe that our relationship with our employees is good.
Facilities
Our principal executive offices are located at 601 Poydras Street, Suite 2400, New Orleans, Louisiana 70130. We own an operating facility on a 17-acre tract in Harvey, Louisiana, which we use to support our subsea and well enhancement, drilling products and services, and marine operations. Our other principal operating facility is located on a 32-acre tract in Broussard, Louisiana, which we use to support our drilling products and services and subsea and well enhancement operations in the Gulf of Mexico. We also own an operating facility on a 23-acre tract in Houston, Texas, which serves as a manufacturing, testing and research and design center. In addition, we own certain facilities and lease other office, service and assembly facilities under various operating leases. We have a total of approximately 150 owned or leased operating facilities located throughout the world. We believe that all of our leases are at competitive or market rates and do not anticipate any difficulty in leasing suitable additional space as may be needed or extending terms when our current leases expire.
Intellectual Property
We own numerous patents that we use in our operations, many of which we acquired from Baker Hughes Incorporated in August 2010 (see note 4 to our consolidated financial statements included in Item 8 of this Form 10-K). We protect these patents by registering them with the U.S. Patent and Trademark Office and with governmental agencies in foreign countries, particularly where our products and services are offered. We intend to vigorously enforce and protect our patents and other intellectual properties. In addition, we rely to a great extent on the technical expertise and know-how of our personnel to maintain our competitive position.
Other Information
We have our principal executive offices at 601 Poydras Street, Suite 2400, New Orleans, Louisiana 70130. Our telephone number is (504) 587-7374. We also have a website at http://www.superiorenergy.com. Copies of the annual, quarterly and current reports we file with the SEC, and any amendments to those reports, are available on our website free of charge soon after such reports are filed with or furnished to the SEC. The information posted on our website is not incorporated into this Annual Report on Form 10-K. Alternatively, you may access these reports at the SEC’s internet website: http://www.sec.gov/.
We have a Code of Business Ethics and Conduct, which applies to all of our directors, officers and employees. The Code of Business Ethics and Conduct is publicly available on our website at http://www.superiorenergy.com. Any waivers to the Code of Business Ethics and Conduct by directors or executive officers and any material amendment to the Code of Business Ethics and Conduct will be posted promptly on our website and/or disclosed in a current report on Form 8-K.
Item 1A.
Item 1A. Risk Factors
You should carefully consider the following factors in addition to the other information contained in this Annual Report. The risks described below are the material risks that we have identified. In addition, they may not be the only material risks that we face. There are many factors that affect our business and the results of our operations, many of which are beyond our control. Additional risks and uncertainties not currently known to us or that we currently view as immaterial may also impair our business operations. If any of these risks develop into actual events, it could materially and adversely affect our business, financial condition, results of operations and cash flows. If that occurred, the trading price of our common stock could decline and you could lose part or all of your investment.
The Deepwater Horizon incident could have a lingering significant impact on exploration and production activities in United States coastal waters that could adversely affect demand for our services and equipment.
As an oil and gas service company, the success and profitability of our operations in the United States are influenced by the level of drilling and exploration activity in the Gulf of Mexico. Revenue generated from our Gulf of Mexico market area was approximately $675.8 million, $804.9 million and $1,204.6 million for the years ended December 31, 2010, 2009 and 2008, respectively.
The April 2010 catastrophic explosion of the Deepwater Horizon, the related oil spill in the Gulf of Mexico and the U.S. Government’s response to these events has significantly and adversely disrupted oil and gas exploration activities in the Gulf of Mexico. Shortly after the explosion, the United States government imposed a moratorium effectively suspending all deepwater drilling activity in the Gulf of Mexico which was subsequently lifted. Although the moratorium did not suspend drilling activity in the shallow waters of the Gulf of Mexico, new safety and permitting requirements have been imposed on shallow water operators, resulting in fewer drilling permits being issued to shallow water operators since the Deepwater Horizon explosion. Additionally, the commission appointed by the President of the United States to study the causes of the catastrophe released its report and has recommended certain legislative and regulatory measures that should be taken with the stated goal to minimize the possibility of a reoccurrence of a disastrous spill. Various bills are being considered by Congress which, if enacted, could either significantly increase the costs of conducting drilling and exploration activities in the Gulf of Mexico, particularly in deep waters, or possibly drive a substantial portion of drilling and operation activity out of the Gulf of Mexico.
There are a number of uncertainties affecting the oil and gas industry that continue to exist in the aftermath of the Deepwater Horizon events and the release of the commission report, including whether Congress will repeal the $75 million cap for non-reclamation liabilities under the Oil Pollution Act of 1990, whether insurance will continue to be available at a reasonable cost and with reasonable policy limits to support drilling and exploration activity in the Gulf of Mexico, whether permits for drilling and other oilfield service activities will be issued and at what rate, and whether the overall legislative and regulatory response to the disaster will discourage investment in oil and gas exploration in the Gulf of Mexico. Although the eventual outcome of these uncertainties is currently unknown, any one or more of them could constrict the return of demand for our products and services to historical levels or further reduce demand for our products and services, which could adversely affect our operations in the Gulf of Mexico. However, until the ultimate regulatory response to these events becomes more certain, we cannot accurately predict the extent of the impact those responses could have on our customers and similarly, the long term impact on our business and operations. Any regulatory response that has the effect of materially curtailing drilling and exploration activity in the Gulf of Mexico will ultimately adversely affect our operations in the Gulf of Mexico.
Adverse macroeconomic and business conditions may significantly and negatively affect our results of operations.
Economic conditions in the United States and international markets in which we operate could substantially affect our revenue and profitability. The lingering domestic and global financial crises, the associated fluctuating oil and gas prices, and the disruption in the credit markets have had an adverse effect on our operating results and financial condition, and if sustained or worsened, such adverse effects could continue or worsen. Additionally, if the disruption in the credit markets continues, some of our suppliers and customers may be unable to recover from, or could face additional credit issues, cash flow problems and other financial hardships.
Changes in governmental banking, monetary and fiscal policies to restore the domestic and global financial markets and increase credit availability may not be effective. It is difficult to determine the breadth and duration of the domestic and global financial crises and the many ways in which they may affect our suppliers, customers and our business in general. The continuation or further deterioration of these difficult financial and macroeconomic conditions could have a significant adverse effect on our results of operations and cash flows.
Our borrowing capacity could be affected by the uncertainty impacting credit markets generally.
Lingering disruptions in the credit and financial markets could adversely affect financial institutions, inhibit lending and limit access to capital and credit for many companies. Although we believe that the banks participating in our
credit facility have adequate capital and resources, we can provide no assurance that all of those banks will continue to operate as a going concern in the future. If any of the banks in our lending group were to fail, it is possible that the borrowing capacity under our credit facility would be reduced. In the event that the availability under our credit facility was reduced significantly, we could be required to obtain capital from alternate sources in order to finance our capital needs. Our options for addressing such capital constraints would include, but not be limited to, (1) obtaining commitments from the remaining banks in the lending group or from new banks to fund increased amounts under the terms of our credit facility, (2) accessing the public capital markets, or (3) delaying certain projects. If it became necessary to access additional capital, any such alternatives could have terms less favorable than those terms under our existing credit facility, which could have a material effect on our consolidated financial position, results of operations and cash flows.
If future financing is not available to us when required, as a result of limited access to the credit markets or otherwise, or is not available to us on acceptable terms, we may be unable take advantage of business opportunities or respond to competitive pressures, either of which could have a material adverse effect on our consolidated financial position, results of operations and cash flows.
We are subject to the cyclical nature of the oil and gas industry.
Demand for most of our oilfield services is substantially dependent on the level of expenditures by the oil and gas industry. This level of activity has traditionally been volatile as a result of sensitivities to oil and gas prices and generally dependent on the industry’s view of future oil and gas prices. The purchases of the products and services we provide are, to a substantial extent, deferrable in the event oil and gas companies reduce expenditures. Therefore, the willingness of our customers to make expenditures is critical to our operations. Oil and gas prices are very volatile and could be affected by many factors, including the following:
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the level of worldwide oil and gas exploration and production;
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the cost of exploring for, producing and delivering oil and gas;
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demand for energy, which is affected by worldwide economic activity and population growth;
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the ability of the Organization of Petroleum Exporting Countries, or OPEC, to set and maintain production levels for oil;
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the discovery rate of new oil and gas reserves;
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domestic and global political and economic uncertainty, socio-political unrest and instability or hostilities;
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demand for and availability of alternative, competing sources of energy; and
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technological advances affecting energy exploration, production and consumption.
Although the effects of changing prices on activity levels in production and development sectors of the oil and gas industry are less immediate and as a result, less volatile than the exploration sector, producers generally react to declining oil and gas prices by reducing expenditures. This has, in the past, adversely affected and may in the future adversely affect our business. We are unable to predict future oil and gas prices or the level of oil and gas industry activity. A prolonged low level of activity in the oil and gas industry will adversely affect the demand for our products and services and our financial condition, results of operations and cash flows.
Our industry is highly competitive.
We operate in highly competitive areas of the oilfield services industry. The products and services of each of our principal industry segments are sold in highly competitive markets, and our revenues and earnings may be affected by the following factors:
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changes in competitive prices;
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fluctuations in the level of activity in major markets;
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an increased number of liftboats in the Gulf of Mexico;
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general economic conditions; and
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governmental regulation.
We compete with the oil and gas industry’s largest integrated and independent oilfield service providers. We believe that the principal competitive factors in the market areas that we serve are price, product and service quality, safety record, equipment availability and technical proficiency.
Our operations may be adversely affected if our current competitors or new market entrants introduce new products or services with better features, performance, prices or other characteristics than our products and services. Further, additional liftboat capacity in the Gulf of Mexico would increase competition for that service, likely resulting in lower day rates and utilization. Competitive pressures or other factors also may result in significant price competition that could have a material adverse effect on our results of operations and financial condition. Finally, competition among oilfield service and equipment providers is also affected by each provider’s reputation for safety and quality.
A significant portion of our revenue is derived from our international operations, which exposes us to additional political, economic and other uncertainties.
Our international revenues accounted for approximately 28%, 22%, and 17% of our total revenues in 2010, 2009, and 2008, respectively. Our international operations are subject to a number of risks inherent in any business operating in foreign countries, including, but not limited to, the following:
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political, social and economic instability;
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potential expropriation, seizure or nationalization of assets;
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increased operating costs;
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civil unrest and protests, strikes, acts of terrorism, war or other armed conflict;
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renegotiating, cancellation or forced modification of contracts;
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import-export quotas;
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confiscatory taxation or other adverse tax policies;
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currency fluctuations;
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restrictions on the repatriation of funds;
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submission to the jurisdiction of a foreign court or arbitration panel or having to enforce the judgment of a foreign court or arbitration panel against a sovereign nation within its own territory; and
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other forms of government regulation which are beyond our control.
Additionally, our competitiveness in international market areas may be adversely affected by regulations, including, but not limited to, the following:
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the awarding of contracts to local contractors;
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the employment of local citizens; and
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the establishment of foreign subsidiaries with significant ownership positions reserved by the foreign government for local citizens.
The occurrence of any of the risks described above could adversely affect our results of operations and cash flows.
We are susceptible to adverse weather conditions in the Gulf of Mexico.
Certain areas in and near the Gulf of Mexico experience hurricanes and other extreme weather conditions on a relatively frequent basis. Substantially all of our assets offshore and along the Gulf of Mexico are susceptible to damage or total loss by these storms. Although we maintain insurance on our properties, due to the significant losses incurred as a consequence of the hurricanes that occurred in the Gulf of Mexico in recent years these coverages are not comparable with that of prior years. For instance, since 2006, our insurance policies now have an annual aggregate limit, rather than an occurrence limit. Also, our deductible for wind damage versus non-wind damage events is between five and ten times higher. Thus, we are at greater risk of loss due to severe weather conditions. Any significant uninsured losses could have a material adverse effect on our financial position, results of operations and cash flows.
Damage to our equipment caused by high winds and turbulent seas could cause us to curtail or suspend service operations for significant periods of time until damage can be assessed and repaired. Moreover, even if we do not experience direct damage from any of these storms, we may experience disruptions in our operations because
customers may curtail or suspend their development activities due to damage to their platforms, pipelines and other related facilities. We do not maintain business interruption insurance that could protect us from these events.
We depend on key personnel.
Our success depends to a great degree on the abilities of our key management personnel, particularly our chief executive officer and other high-ranking executives. The loss of the services of one or more of these key employees could adversely affect us.
We might be unable to employ a sufficient number of skilled workers.
The delivery of our products and services require personnel with specialized skills and experience. As a result, our ability to remain productive and profitable will depend upon our ability to employ and retain skilled workers. In addition, our ability to expand our operations depends in part on our ability to increase the size of our skilled labor force. The demand for skilled workers in our industry is high, and the supply is limited. We could be faced with severe shortages of experienced personnel as we expand our operations and enter new markets. In developed countries, many senior engineers, managers and other professionals are reaching retirement age, with no assurance that enough college graduates and younger workers will be ready to replace them.
In addition, although our employees are not covered by a collective bargaining agreement, the marine services industry has in the past been targeted by maritime labor unions in an effort to organize Gulf of Mexico employees. A significant increase in the wages paid by competing employers or the unionization of our Gulf of Mexico employees could result in a reduction of our skilled labor force, increases in the wage rates that we must pay or both. If either of these events were to occur, our capacity and profitability could be diminished and our growth potential could be impaired.
We depend on significant customers.
We derive a significant amount of our revenue from a small number of major and independent oil and gas companies. In 2010, no single customer accounted for more than 10% of our total revenue. Of our 2009 and 2008 total revenue, Chevron accounted for approximately 15% and 12%, respectively, Apache accounted for approximately 13% and 11%, respectively, and BP accounted for approximately 11% for each year. Our inability to continue to perform services for a number of our large existing customers, if not offset by sales to new or other existing customers, could have a material adverse effect on our business and operations.
The terms of our contracts could expose us to unforeseen costs and costs not within our control.
Under fixed-price contracts, turnkey or modified turnkey contracts, we agree to perform a defined scope of work for a fixed price. Extra work, which is subject to customer approval, is billed separately. As a result, we can improve our expected profit by superior contract performance, productivity, worker safety and other factors resulting in cost savings. However, we could incur cost overruns above the approved contract price, which may not be recoverable. Prices for these contracts are established based largely upon estimates and assumptions relating to project scope and specifications, personnel and material needs. These estimates and assumptions may prove inaccurate or conditions may change due to factors out of our control, resulting in cost overruns, which we may be required to absorb and could have a material adverse effect on our business, financial condition and results of operations. In addition, our profits from these contracts could decrease and we could experience losses if we incur difficulties in performing the contracts or are unable to secure suitable commitments from our subcontractors and other suppliers. Many of these contracts require us to satisfy specified progress milestones or performance standards in order to receive payment. Under these types of arrangements, we may incur significant costs for equipment, labor and supplies prior to receipt of payment. If the customer fails or refuses to pay us for any reason, there is no assurance we will be able to collect amounts due to us for costs previously incurred. In some cases, we may find it necessary to terminate subcontracts and we may incur costs or penalties for canceling our commitments to them. If we are unable to collect amounts owed to us under these contracts, we may be required to record a charge against previously recognized earnings related to the project, and our liquidity, financial condition and results of operations could be adversely affected.
Percentage-of-completion accounting for contract revenue may result in material adjustments.
A portion of our revenue is recognized using the percentage-of-completion method of accounting. The percentage-of-completion accounting practices that we use result in our recognizing contract revenue and earnings ratably over the contract term based on the proportion of actual costs incurred to our estimated total contract costs. The earnings or losses recognized on individual contracts are based on estimates of contract revenue and costs. We review our estimates of contract revenue, costs and profitability on a monthly basis. Prior to contract completion, we may adjust our estimates on one or more occasions as a result of changes in cost estimates, change orders to the original contract, collection disputes with the customer on amounts invoiced or claims against the customer for extra work or increased cost due to customer-induced delays and other factors. Contract losses are recognized in the fiscal period in which the loss is determined. Contract profit estimates are also adjusted in the fiscal period in which it is determined that an adjustment is required. No restatements are made to prior periods for changes in these estimates. As a result of the requirements of the percentage-of-completion method of accounting, the possibility exists, for example, that we could have estimated and reported a profit on a contract over several prior periods and later determine that all or a portion of such previously estimated and reported profits were overstated or understated. If this occurs, the cumulative impact of the change will be reported in the period in which such determination is made, thereby eliminating all or a portion of any profits related to long-term contracts that would have otherwise been reported in such period or even resulting in a loss being reported for such period.
The dangers inherent in our operations and the limits on insurance coverage could expose us to potentially significant liability costs and materially interfere with the performance of our operations.
Our operations are subject to numerous operating risks inherent in the oil and gas industry that could result in substantial losses. These risks include the following:
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fires;
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explosions, blowouts and cratering;
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hurricanes and other extreme weather conditions;
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mechanical problems, including pipe failure;
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abnormally pressured formations; and
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environmental accidents, including oil spills, gas leaks or ruptures, uncontrollable flows of oil, gas, brine or well fluids, or other discharges of toxic gases or other pollutants.
These risks affect our provision of oilfield services and equipment, as well as our oil and gas operations. Our liftboats and marine vessels are also subject to operating risks such as catastrophic marine disasters, adverse weather conditions, collisions and navigation errors.
The realization of these risks could result in catastrophic events causing personal injury, loss of life, damage to or destruction of wells, production facilities or other property or equipment, or damages to the environment, which could lead to claims against us for substantial damages. In addition, certain of our employees who perform services on offshore platforms and marine vessels are covered by provisions of the Jones Act, the Death on the High Seas Act and general maritime law. These laws make the liability limits established by federal and state workers’ compensation laws inapplicable to these employees and instead permit them or their representatives to pursue actions against us for damages for job related injuries. Realization of any of the foregoing by our equity-method investments engaged in oil and gas production could result in significant impairment to our equity-method investment balances.
As a result of indemnification obligations contained in most of our customer contracts, we may also be required to indemnify our customers for any damages sustained by our employees or equipment, regardless of whether those damages were caused by us.
We maintain several types of insurance to cover liabilities arising from our operations. These policies include primary and excess umbrella liability policies with limits of $200 million dollars per occurrence, including sudden and accidental pollution incidents. We also maintain property insurance on our physical assets, including marine vessels and operating equipment and platforms and wells. The cost of many of the types of insurance coverage maintained for our oil and gas operations has increased significantly due to losses as a result of hurricanes that
occurred in the Gulf of Mexico in recent years and resulted in the retention of significant additional risk by us and our equity-method investments, primarily through higher insurance deductibles. Also, most of these property insurance policies now have annual aggregate limits, rather than occurrence-based limits, for named storm damages and significantly higher deductibles for wind damage. Very few insurance underwriters offer certain types of insurance coverage maintained by us, and there can be no assurance that any particular type of insurance coverage will continue to be available in the future, that we will not accept retention of additional risk through higher insurance deductibles or otherwise, or that we will be able to purchase our desired level of insurance coverage at commercially feasible rates.
The frequency and severity of incidents related to our operating risks affect our operating costs, insurability, revenue derived from our equity-method investments, and relationships with customers, employees and regulators. Any increase in the frequency or severity of such incidents, or the general level of compensation and damage awards with respect to such incidents, could adversely affect our ability to obtain insurance or projects from oil and gas companies. Also, any significant uninsured losses could have a material adverse effect on our financial position, results of operations and cash flows.
We are vulnerable to the potential difficulties associated with rapid expansion.
We have grown rapidly over the last several years through internal growth and acquisitions of other companies. We believe that our future success depends on our ability to manage the rapid growth that we have experienced and the demands from increased responsibility on our management personnel. The following factors could present difficulties to us:
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lack of experienced management-level personnel;
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increased administrative burden; and
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increased logistical problems common to large, expansive operations.
If we do not manage these potential difficulties successfully, our operating results could be adversely affected.
Our inability to control the inherent risks of acquiring businesses could adversely affect our operations.
Acquisitions have been and we believe will continue to be a key element of our business strategy. We cannot assure that we will be able to identify and acquire acceptable acquisition candidates on terms favorable to us in the future. We may be required to incur substantial indebtedness to finance future acquisitions. Such additional debt service requirements may impose a significant burden on our results of operations and financial condition. We cannot assure you that we will be able to successfully consolidate the operations and assets of any acquired business with our own business. Acquisitions may not perform as expected when the transaction was consummated and may be dilutive to our overall operating results. In addition, our management may not be able to effectively manage our increased size or operate a new line of business.
The nature of our industry subjects us to compliance with regulatory and environmental laws.
Our business is significantly affected by a wide range of local, state and federal statutes, rules, orders and regulations, as well as international laws in the other countries in which we operate, relating to the oil and gas industry in general, and more specifically with respect to the environment, health and safety, waste management and the manufacture, storage, handling and transportation of hazardous wastes. The failure to comply with these rules and regulations can result in the revocation of permits, corrective action orders, administrative or civil penalties and criminal prosecution. Further, laws and regulations in this area are complex and change frequently. Changes in laws or regulations, or their enforcement, could subject us to material costs.
Our operations are also subject to certain requirements under OPA. Under OPA and its implementing regulations, “responsible parties,” including owners and operators of certain vessels, are strictly liable for damages resulting from spills of oil and other related substances in the United States waters, subject to certain limitations. OPA also requires a responsible party to submit proof of its financial ability to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. Further, OPA imposes other requirements, such as the preparation of oil spill response plans. In the event of a substantial oil spill, we could be required to expend
potentially significant amounts of capital which could have a material adverse effect on our future operations and financial results.
We have compliance costs and potential environmental liabilities with respect to our offshore and onshore operations, including our environmental cleaning services. Certain environmental laws provide for joint and several liabilities for remediation of spills and releases of hazardous substances. These environmental statutes may impose liability without regard to negligence or fault. In addition, we may be subject to claims alleging personal injury or property damage as a result of alleged exposure to hazardous substances. We believe that our present operations substantially comply with applicable federal and state pollution control and environmental protection laws and regulations. We also believe that compliance with such laws has not had a material adverse effect on our operations. However, we are unable to predict whether environmental laws and regulations will have a material adverse effect on our future operations and financial results. Sanctions for noncompliance may include revocation of permits, corrective action orders, administrative or civil penalties and criminal prosecution.
Federal, state and local statutes and regulations require permits for plugging and abandonment and reports concerning operations. A decrease in the level of enforcement of such laws and regulations in the future would adversely affect the demand for our services and products. In addition, demand for our services is affected by changing taxes, price controls and other laws and regulations relating to the oil and gas industry generally. The adoption of laws and regulations curtailing exploration and development drilling for oil and gas in our areas of operations for economic, environmental or other policy reasons could also adversely affect our operations by limiting demand for our services.
The regulatory burden on our business increases our costs and, consequently, affects our profitability. We are unable to predict the level of enforcement of existing laws and regulations, how such laws and regulations may be interpreted by enforcement agencies or court rulings, or whether additional laws and regulations will be adopted. We are also unable to predict the effect that any such events may have on us, our business or our financial condition.
A terrorist attack or armed conflict could harm our business.
Terrorist activities, anti-terrorist efforts and other armed conflicts may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our services and causing a reduction in our revenues. Oil and gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to customers’ operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.
Regulation of greenhouse gas emissions effects and climate change issues may adversely affect our operations and markets.
The impact and implication of greenhouse gas emissions has received increasing attention, especially in the form of proposals to regulate the emissions. Regulation of emissions has been proposed on an international, national, regional, state and local level. These proposals include an international protocol, which has gone into effect but is not binding on the United States, and numerous bills introduced to the U.S. Congress relating to climate change.
In June 2009, a bill to control and reduce emissions of greenhouse gasses in the United States, was approved by the U.S. House of Representatives. The legislation, often referred to as a “cap-and-trade” system, would limit greenhouse gas emissions while creating a corresponding market for the purchase and sale of emission permits. Although not passed by the U.S. Senate, and therefore not law, the Senate has initiated drafting its own legislation for the control and reduction of greenhouse emissions.
It is not currently feasible to predict whether, or which of, the current greenhouse gas emission proposals will be adopted. In addition, there may be subsequent international treaties, protocols or accords that the United States joins in the future. The potential passage of climate change regulation may impact our operations, however, since it may limit demand and production of fossil fuels by our customers. The impact on our customers, in turn, may adversely affect demand for our products and services, which could adversely impact our operations.
Estimates of our oil and gas reserves and potential liabilities relating to our oil and gas properties may be incorrect.
We acquire mature oil and gas properties in the Gulf of Mexico on an “as is” basis and assume all plugging, abandonment, restoration and environmental liability with limited remedies for breaches of representations and warranties. Acquisitions of these properties require an assessment of a number of factors beyond our control, including estimates of recoverable reserves, future oil and gas prices, operating costs and potential environmental and plugging and abandonment liabilities. These assessments are complex and inherently imprecise, and, with respect to estimates of oil and gas reserves, require significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. In addition, since these properties are typically mature, our facilities and operations may be more susceptible to hurricane damage, equipment failure or mechanical problems. In connection with these assessments, we perform due diligence reviews that we believe are generally consistent with industry practices. However, our reviews may not reveal all existing or potential problems. In addition, our reviews may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We may not always discover structural, subsurface, environmental or other problems that may exist or arise.
Actual future production, cash flows, development expenditures, operating and abandonment expenses and quantities of recoverable oil and gas reserves may vary substantially from those estimated by us and any significant variance in these assumptions could materially affect the estimated quantity and value of our proved reserves. Therefore, the risk is that we may overestimate the value of economically recoverable reserves and/or underestimate the cost of plugging wells and abandoning production facilities. If costs of abandonment are materially greater or actual reserves are materially lower than our estimates, they could have an adverse effect on earnings.
Item 1B.
Item 1B. Unresolved Staff Comments
None.
Item 2.
Item 2. Properties
Information on properties is contained in Part I, Item 1 of this Form 10-K and in note 16 to our consolidated financial statements included in Part II, Item 8.
Item 3.
Item 3. Legal Proceedings
We are involved in various legal and other proceedings and claims that are incidental to the conduct of our business. Our management does not believe that the outcome of any ongoing proceedings, individually or collectively, would have a material adverse affect on our financial condition, results of operations or cash flows.
Item 4A. Executive Officers of Registrant
David D. Dunlap, age 49, was appointed as our Chief Executive Officer in April 2010 and President in February 2011. Prior to joining us, he was employed by BJ Services Company as its Executive Vice President and Chief Operating Officer since 2007. Mr. Dunlap joined BJ Services in 1984 and held numerous positions during his tenure including President of the International Division, Vice President for the Coastal Division of North America and U.S. Sales and Marketing Manager.
Robert S. Taylor, age 56, has served as our Chief Financial Officer since January 1996, as one of our Executive Vice Presidents since September 2004, and as our Treasurer since July 1999. He also served as one of our Vice Presidents from July 1999 to September 2004.
A. Patrick Bernard, age 53, has served as our Senior Executive Vice President since July 2006 and as one of our Executive Vice Presidents since September 2004. He served as one of our Vice Presidents from June 2003 until September 2004. From July 1999 until June 2003, Mr. Bernard served as the Chief Financial Officer of our wholly-owned subsidiary International Snubbing Services, L.L.C. and its predecessor company.
Patrick J. Campbell, age 66, has served as one of our Executive Vice Presidents since April 2009. Prior to this position, he served as President and Chief Operating Officer of our wholly-owned subsidiary, Wild Well Control, Inc., since 2000. Mr. Campbell joined Wild Well Control in 1990 and served as its Executive Vice President until 2000.
L. Guy Cook, III, age 42, has served as one of our Executive Vice Presidents since September 2004. He has also served as an Executive Vice President of our wholly-owned subsidiary Superior Energy Services, L.L.C., and previously as a Vice President of this subsidiary and its predecessor company since August 2000.
Charles M. Hardy, age 65, has served as one of our Executive Vice Presidents since January 2008. Prior to this position, he served as Vice President and General Manager of our Marine Services division since May 2005, and previously as Vice President of Sales for this same division since August 2004. From July 2000 to July 2004, Mr. Hardy served as Vice President of Operations of Trico Marine Operators, Inc.
Samuel Hardy Jr., age 58, was appointed as one of our Executive Vice Presidents in February 2011. He joined the Company with the acquisition of Warrior Energy Services Corporation in December 2006. Mr. Hardy has served as the Chief Operating Officer of Warrior Energy Services Corporation since August 2000.
William B. Masters, age 53, has served as our General Counsel and one of our Executive Vice Presidents since March 2008. He was previously a partner in the law firm Jones, Walker, Waechter, Poitevent, Carrère & Denègre L.L.P. for more than 20 years.
Danny R. Young, age 55, has served as one of our Executive Vice Presidents since September 2004. Mr. Young has also served as an Executive Vice President of Superior Energy Services, L.L.C. from January 2002 to May 2005, he served as Vice President of Health, Safety and Environment and Corporate Services of Superior Energy Services, L.L.C.
Patrick J. Zuber, age 50, has served as one of our Executive Vice Presidents since January 2008. Prior to joining us, he was employed by Weatherford International, Ltd. from June 1999 to December 2007 and held numerous positions during his tenure including Vice President for the Middle East region, Vice President for the Asia Pacific region and General Manager for the Underbalanced Drilling Division for the Middle East and North Africa region.
PART II
Item 5.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Common Stock Information
Our common stock trades on the New York Stock Exchange under the symbol “SPN.” The following table sets forth the high and low sales prices per share of common stock as reported for each fiscal quarter during the periods indicated.
As of February 18, 2011, there were 78,892,650 shares of our common stock outstanding, which were held by 163 record holders.
Dividend Information
We have never paid cash dividends on our common stock. We currently expect to retain all of the cash our business generates to fund the operation and expansion of our business and repurchase stock. In addition, the terms of our credit facility and the indenture governing our 6 7/8% unsecured senior notes due 2014 restrict our ability to pay dividends.
Equity Compensation Plan Information
Information required by this item with respect to compensation plans under which our equity securities are authorized for issuance is incorporated by reference from Part III, Item 12.
Issuer Purchases of Equity Securities
In December 2009, our Board of Directors approved a $350 million share repurchase program that will expire on December 31, 2011. The following table provides information about our common stock repurchased and retired during each month for the three months ended December 31, 2010:
Performance Graph
The following performance graph and related information shall not be deemed “solicitating material” or “filed” with the Securities and Exchange Commission, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933 or Securities Exchange Act of 1934, except to the extent that we specifically incorporate it by reference into such filing.
The following graph compares the total stockholder return on our common stock for the last five years with the total return on the S&P 500 Stock Index and a Self-Determined Peer Group for the same period. The information in the graph is based on the assumption of a $100 investment on January 1, 2006 at closing prices on December 31, 2005. The comparisons in the graph are required by the Securities and Exchange Commission and are not intended to be a forecast or be indicative of possible future performance of our common stock.
NOTES:
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The lines represent monthly index levels derived from compounded daily returns that include all dividends.
•
The indexes are reweighted daily, using the market capitalization on the previous trading day.
•
If the monthly interval, based on the fiscal year-end, is not a trading day, the preceding trading day is used.
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The index level for all series was set to $100.00 on December 31, 2005.
During 2010, we amended our Self-Determined Peer Group as there was a reduction in the number of peer companies due to merger activity. We believe our current Self-Determined Peer Group better reflects our current size as well as our potential for growth. Our current Self-Determined Peer Group consists of the peer group of 14 companies whose average stockholder return levels comprise part of the performance criteria established by the Compensation Committee under our long-term incentive compensation program: Baker Hughes, Inc., Basic Energy Services, Inc., Cameron International Corp., Complete Production Services, Inc., Global Industries, Ltd., Helix Energy Solutions Group, Inc., Hercules Offshore, Inc., Key Energy Services, Inc., National Oilwell Varco, Inc., Oceaneering International, Inc., Oil States International, Inc., RPC, Inc., Tetra Technologies, Inc. and Weatherford International, Ltd. Our prior Self-Determined Peer Group included Helix Energy Solutions Group, Inc., Helmerich & Payne, Inc., Oceaneering International, Inc., Oil States International, Inc., Pride International, Inc., RPC, Inc., Seacor Holdings Inc., Tetra Technologies, Inc., and Weatherford International, Ltd.
Item 6.
Item 6. Selected Financial Data
We present below our selected consolidated financial data for the periods indicated. We derived the historical data from our audited consolidated financial statements.
The data presented below should be read together with, and are qualified in their entirety by reference to, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements included elsewhere in this Annual Report on Form 10-K. The financial data is in thousands, except per share amounts.
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with our consolidated financial statements and applicable notes to our consolidated financial statements and other information included elsewhere in this Annual Report on Form 10-K, including risk factors disclosed in Part I, Item 1A. The following information contains forward-looking statements, which are subject to risks and uncertainties. Should one or more of these risks or uncertainties materialize, our actual results may differ from those expressed or implied by the forward-looking statements. See “Forward-Looking Statements” at the beginning of this Annual Report on Form 10-K.
Executive Summary
We believe we are a leading provider of oilfield services and equipment focused on serving the drilling-related needs of oil and gas companies primarily through our drilling products and services segment, and the production-related needs of oil and gas companies through our subsea and well enhancement, drilling products and services and marine segments. We have expanded geographically into select domestic land and international market areas. Through our subsidiary, Wild Well Control, Inc. (Wild Well), and our equity-method investments, we also own oil and gas properties in the Gulf of Mexico.
The financial performance of our various products and services are reported in three operating segments - subsea and well enhancement, drilling products and services, and marine.
Overview of our business segments
The subsea and well enhancement segment consists of specialized down-hole services, which are both labor and equipment intensive. We offer a wide variety of services used to maintain, enhance and extend oil and gas production from mature wells. In 2010, approximately 40% of this segment’s revenue was derived from work performed for customers in the Gulf of Mexico market area (down from 59% in 2009), while approximately 34% of segment revenue was from the domestic land market area (up from 23% in 2009) and approximately 26% of segment revenue was from international market areas (up from 18% in 2009). While our income from operations as a percentage of segment revenue tends to be fairly consistent, special projects such as well control can directly increase our profitability.
The drilling products and services segment is capital intensive with higher operating margins as a result of relatively low operating expenses. The largest fixed cost is depreciation as there is little labor associated with our drilling products and services businesses. The financial performance is primarily a function of changes in volume rather than pricing. In 2010, approximately 32% of segment revenue was derived from the Gulf of Mexico market area (down from 40% in 2009), while approximately 35% of segment revenue was from the domestic land market area (up from 25% in 2009) and approximately 33% of segment revenue was from international market areas (down from 35% in 2009). Three rental products and their ancillary equipment (accommodations, drill pipe and stabilization tools) each accounted for more than 20% of this segment’s revenue in 2010.
The marine segment is comprised of our 25 rental liftboats. Operating costs of our liftboats are relatively fixed, and therefore, income from operations as a percentage of revenue can vary significantly from quarter to quarter and year to year based on changes in dayrates and utilization levels. With most of our liftboats currently operating in the Gulf of Mexico, our activity levels can be impacted by harsh weather, especially tropical systems that occur during hurricane season.
Market drivers and conditions
The oil and gas industry remains highly cyclical and seasonal. Activity levels are driven primarily by traditional energy industry activity indicators, which include current and expected commodity prices, drilling rig counts, well completions and workover activity, geological characteristics of producing wells which determine the number of services required per well, oil and gas production levels, and customers’ spending allocated for drilling and production work, which is reflected in our customers’ operating expenses or capital expenditures.
Historical market indicators are listed below:
(1)
Estimate of drilling activity as measured by average active drilling rigs based on Baker Hughes Inc. rig count information.
(2)
Excludes Canadian Rig Count.
As indicated by the table above, the major activity drivers improved in 2010. The average number of drilling rigs working in the United States, which is more weighted toward natural gas drilling than oil drilling, increased 42%, while the international rig count, which is more weighted toward oil drilling than natural gas drilling, increased 10%. The average price of West Texas Intermediate crude oil increased 27% while the average price of natural gas at Henry Hub increased 3% from 2009.
The following table compares our revenues generated from major geographic regions for the years ended December 31, 2010 and 2009 (in thousands). We attribute revenue to countries based on the location where services are performed or the destination of the sale of products.
Higher oil prices, the increase in drilling rig counts (particularly the number of horizontal drilling rigs in the domestic land market area) and higher overall industry activity increased pricing and utilization for our products and services in all segments, where our domestic land revenue increased 68% to $540.5 million. In this market area, we experienced a 75% increase in revenue from our subsea and well enhancement segment and a 54% increase in revenue from our drilling products and services segment. Within individual product and service lines, the largest increases in the domestic land market area were in coiled tubing, cased hole wireline, pressure control tools, rentals of accommodations and rentals and sales of stabilizers and related equipment.
Our Gulf of Mexico revenue declined 16% to $675.8 million due primarily to the deepwater drilling moratorium and lack of new deepwater drilling permits issued following the Deepwater Horizon incident in April 2010, which curtailed demand for our drilling products and services. In addition, we generated less revenue from special projects as a result of the conclusion of field work on our large-scale decommissioning project. Finally, our Gulf of Mexico liftboat revenue declined as a result of downtime for our two 265-foot class liftboats, which did not return to service until October and November 2010. These liftboats typically generate dayrates of approximately $40,000.
Our international revenue increased 44% to $465.3 million due primarily to the acquisition of Hallin Marine Subsea International Plc (Hallin) in January 2010, and increases in demand for down-hole drilling products in Latin America and hydraulic workover and snubbing services in Europe.
Industry Outlook
We believe drivers of industry demand, commodity prices and drilling rig counts should remain favorable in most geographic market area, with the exception of the Gulf of Mexico. We believe domestic land market areas with high concentrations of horizontal drilling remain underserved for products and services such as coiled tubing, premium drill pipe and ancillary products. Internationally, we will continue to build out market areas, such as Brazil, that provide us the best opportunities to provide as many products and services as possible. As a result, we anticipate that we will continue to grow revenue and earnings from international market areas, but at a slower, more measured pace than the domestic land market area. Accordingly, a significant portion of our capital expenditures in 2011 will be allocated to these areas.
Our Gulf of Mexico operations generally focus on three areas: drilling support, production enhancement and decommissioning (or end of life) services. Our exposure to drilling activity is primarily in the drilling products and services segment. We anticipate that our financial performance from the Gulf of Mexico in this segment will continue to be curtailed due to the lack of drilling in the deepwater Gulf of Mexico market area as a result of the aftermath of the Deepwater Horizon incident. The industry continues in its efforts to interpret and comply with new government regulations to obtain new drilling permits. The pace at which new permits are issued and rigs resume drilling will drive demand for our drilling products and services. Operations in our subsea and well enhancement and marine segments are primarily focused on production enhancement and end of life activities in the shallow water Gulf of Mexico. A new regulatory initiative aimed at removing idle iron in the Gulf of Mexico may increase long-term demand for our plug and abandonment and decommissioning services.
Critical Accounting Policies and Estimates
Our discussion and analysis of our financial condition and results of operations are based on our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes. Note 1 to our consolidated financial statements contains a description of the significant accounting policies used in the preparation of our financial statements. We evaluate our estimates on an ongoing basis, including those related to long-lived assets and goodwill, income taxes, allowance for doubtful accounts, long-term construction accounting, self insurance and oil and gas properties. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances. Actual amounts could differ significantly from these estimates under different assumptions and conditions.
We define a critical accounting policy or estimate as one that is both important to our financial condition and results of operations and requires us to make difficult, subjective or complex judgments or estimates about matters that are uncertain. We believe that the following are the critical accounting policies and estimates used in the preparation of our consolidated financial statements. In addition, there are other items within our consolidated financial statements that require estimates but are not deemed critical as defined in this paragraph.
Long-Lived Assets. We review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of any such asset may not be recoverable. We record impairment losses on long-lived assets used in operations when the fair value of those assets is less than their respective carrying amount. Fair value is measured, in part, by the estimated cash flows to be generated by those assets. Our cash flow estimates are based upon, among other things, historical results adjusted to reflect our best estimate of future market rates, utilization levels and operating performance. Our estimates of cash flows may differ from actual cash flows due to, among other things, changes in economic conditions or changes in an asset’s operating performance. Assets are grouped by subsidiary or division for the impairment testing, except for liftboats, which are grouped together by leg length. These groupings represent the lowest level of identifiable cash flows. We have long-lived assets, such as facilities, utilized by multiple operating divisions that do not have identifiable cash flows. Impairment testing for these long-lived assets is based on the consolidated entity. Assets to be disposed of are reported at the lower of the carrying amount or fair value less estimated costs to sell. Our estimate of fair value represents our best estimate based on industry trends and reference to market transactions and is subject to variability. The oil and gas industry is cyclical and our estimates of the period over which future cash flows will be generated, as well as the
predictability of these cash flows, can have a significant impact on the carrying value of these assets and, in periods of prolonged down cycles, may result in impairment charges.
During the fourth quarter of 2010, after a thorough and comprehensive evaluation of liftboat components primarily related to two partially constructed 265-foot class liftboats, we determined that it was impractical to finish the construction of these two vessels. As such, we recorded approximately $32.0 million of a reduction in the value of these tangible assets (property, plant and equipment) within the marine segment (see note 3 to our consolidated financial statements included in Part II, Item 8). We will utilize the remaining components of these vessels as spares for our existing fleet.
During the second quarter of 2009, we recorded approximately $92.7 million of impairment expense in connection with our intangible assets within our subsea and well enhancement segment. This reduction in value of intangible assets was primarily due to the decline in demand for services in the domestic land market area. During the fourth quarter of 2009, the domestic land market area remained depressed and our forecast of this market did not suggest a timely recovery sufficient to support our current carrying values. As such, we recorded approximately $119.8 million of impairment expense related to our tangible assets (property, plant and equipment) within the same segment (see note 3 to our consolidated financial statements included in Part II, Item 8).
Goodwill. In assessing the recoverability of goodwill, we must make assumptions regarding estimated future cash flows and other factors to determine the fair value of the respective assets. We test goodwill for impairment in accordance with authoritative guidance related to goodwill and other intangibles, which requires that goodwill as well as other intangible assets with indefinite lives not be amortized, but instead tested annually for impairment. Our annual testing of goodwill is based on carrying value and our estimate of fair value at December 31. We estimate the fair value of each of our reporting units (which are consistent with our business segments) using various cash flow and earnings projections discounted at a rate estimated to approximate the reporting units’ weighted average cost of capital. We then compare these fair value estimates to the carrying value of our reporting units. If the fair value of the reporting units exceeds the carrying amount, no impairment loss is recognized. Our estimates of the fair value of these reporting units represent our best estimates based on industry trends and reference to market transactions. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events.
Based on business conditions and market values that existed at December 31, 2010, we concluded that no goodwill impairment loss was required. Even though we recognized a $32.0 million reduction in the value of liftboat components within the marine segment in 2010, the estimated future cash flows used in the fair value calculation of this segment from the remainder of the fleet was more than sufficient to support the carrying value of this reporting unit.
Income Taxes. We use the asset and liability method of accounting for income taxes. This method takes into account the differences between financial statement treatment and tax treatment of certain transactions. Deferred tax assets and liabilities are recognized for the 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 expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. Our deferred tax calculation requires us to make certain estimates about our future operations. Changes in state, federal and foreign tax laws, as well as changes in our financial condition or the carrying value of existing assets and liabilities, could affect these estimates. The effect of a change in tax rates is recognized as income or expense in the period that the rate is enacted.
Allowance for Doubtful Accounts. We maintain an allowance for doubtful accounts for estimated losses resulting from the inability of some of our customers to make required payments. These estimated allowances are periodically reviewed on a case by case basis, analyzing the customer’s payment history and information regarding the customer’s creditworthiness known to us. In addition, we record a reserve based on the size and age of all receivable balances against those balances that do not have specific reserves. If the financial condition of our customers deteriorates, resulting in their inability to make payments, additional allowances may be required.
Revenue Recognition. Our products and services are generally sold based upon purchase orders or contracts with customers that include fixed or determinable prices. We recognize revenue when services or equipment are
provided and collectability is reasonably assured. We contract for marine, subsea and well enhancement and environmental projects either on a day rate or turnkey basis, with a majority of our projects conducted on a day rate basis. The products we rent within our drilling products and services segment are rented on a day rate basis, and revenue from the sale of equipment is recognized when the equipment is shipped.
Long-Term Construction Accounting for Revenue and Profit (Loss) Recognition. A portion of our revenue is derived from long-term contracts. For contracts that meet the criteria under the authoritative guidance related to construction-type and production-type contracts, we recognize revenues on the percentage-of-completion method, primarily based on costs incurred to date compared with total estimated contract costs. It is possible there will be future and currently unforeseeable significant adjustments to our estimated contract revenues, costs and profitability for contracts currently in process. These adjustments could, depending on the magnitude of the adjustments, materially, positively or negatively, affect our operating results in an annual or quarterly reporting period. To the extent that an adjustment in the estimated total contract cost impacts estimated profit of the contract, the cumulative change to revenue and profitability is reflected in the period in which this adjustment in estimate is identified. The accuracy of the revenue and estimated earnings we report for fixed-price contracts is dependent upon the judgments we make in estimating our contract performance and contract revenue and costs.
We use the percentage-of-completion method for recognizing our revenues and related costs on our contract to decommission seven downed oil and gas platforms and related well facilities located in the Gulf of Mexico. During the fourth quarter of 2009, as the project to decommission seven downed oil and gas platforms and well facilities neared completion, we determined it was necessary to increase the total cost estimate due to various well conditions and other technical issues associated with this complex and challenging project (see note 5 to our consolidated financial statements included in Part II, Item 8).
Self Insurance. We self insure, through deductibles and retentions, up to certain levels for losses related to workers’ compensation, third party liability insurances, property damage, and group medical. With our growth, we have elected to retain more risk by increasing our self insurance. We accrue for these liabilities based on estimates of the ultimate cost of claims incurred as of the balance sheet date. We regularly review our estimates of reported and unreported claims and provide for losses through reserves. We also have actuarial reviews of our estimates for losses related to workers’ compensation and group medical on an annual basis. While we believe these estimates are reasonable based on the information available, our financial results could be impacted if litigation trends, claims settlement patterns and future inflation rates are different from our estimates. Although we believe adequate reserves have been provided for expected liabilities arising from our self insured obligations, and we believe that we maintain adequate insurance coverage, we cannot assure that such coverage will adequately protect us against liability from all potential consequences.
Oil and Gas Properties. Our subsidiary, Wild Well, and our equity-method investments, SPN Resources and DBH, acquire mature oil and gas properties and assume the related well abandonment and decommissioning liabilities. Each of these entities follows the successful efforts method of accounting for their investment in oil and natural gas properties. Under the successful efforts method, the costs of successful exploratory wells and leases containing productive reserves are capitalized. Costs incurred to drill and equip developmental wells, including unsuccessful developmental wells, are capitalized. Other costs such as geological and geophysical costs and the drilling costs of unsuccessful exploratory wells are expensed. Wild Well’s property purchase was recorded at the value exchanged at closing, combined with an estimate of its proportionate share of the decommissioning liability assumed in the purchase. All capitalized costs are accumulated and recorded separately for each field and allocated to leasehold costs and well costs. Leasehold costs and well costs are depleted on a units-of-production basis based on the estimated remaining equivalent proved developed oil and gas reserves of each field.
We estimate the third party market price to plug and abandon wells, abandon the pipelines, decommission and remove the platforms and clear the sites, and use that estimate to record our proportionate share of the decommissioning liability. In estimating the decommissioning liabilities, we perform detailed estimating procedures, analysis and engineering studies. Whenever practical, we will utilize the services of our subsidiaries to perform well abandonment and decommissioning work. When these services are performed by our subsidiaries, all recorded intercompany revenues and expenses are eliminated in the consolidated financial statements. The recorded decommissioning liability associated with a specific property is fully extinguished when the property is completely abandoned. The liability is first reduced by all cash expenses incurred to abandon and decommission the property.
If the liability exceeds (or is less than) our incurred costs, the difference is reported as income (or loss) in the period in which the work is performed. We review the adequacy of our decommissioning liability whenever indicators suggest that the estimated cash flows underlying the liability have changed materially. The timing and amounts of these cash flows are subject to changes in the energy industry environment and may result in additional liabilities recorded, which in turn would increase the carrying values of the related properties.
Oil and gas properties are assessed for impairment in value on a field-by-field basis whenever indicators become evident. We use our current estimate of future revenues and operating expenses to test the capitalized costs for impairment. In the event net undiscounted cash flows are less than the carrying value, an impairment loss is recorded based on the present value of expected future net cash flows over the economic lives of the reserves.
Proved Reserve Estimates. Our reserve information is prepared by independent reserve engineers in accordance with guidelines established by the Securities and Exchange Commission. There are a number of uncertainties inherent in estimating quantities of proved reserves, including many factors beyond our control such as commodity pricing. Reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. In accordance with the Securities and Exchange Commission’s guidelines, we use twelve month average prices, year end costs and a 10% discount rate to determine the present value of future net cash flow. Actual prices and costs may vary significantly, and the discount rate may or may not be appropriate based on outside economic conditions.
Comparison of the Results of Operations for the Years Ended December 31, 2010 and 2009
For the year ended December 31, 2010, our revenue was $1,681.6 million and our net income was $81.8 million, or $1.03 diluted earnings per share. Included in the results for the year ended December 31, 2010 were pre-tax management transition expenses of approximately $35.0 million, as well as non-cash pre-tax charges of $32.0 million for the reduction in value of assets within our marine segment. For the year ended December 31, 2009, our revenue was $1,449.3 million and net loss was $102.3 million, or $1.31 loss per share. Net loss for the year ended December 31, 2009 included a non-cash, pre-tax charge of $212.5 million for the reduction in value of assets within our subsea and well enhancement segment and $36.5 million for the reduction in value of our remaining equity-method investment in Beryl Oil and Gas L.P. (BOG). Also included in the results for the year ended December 31, 2009 were losses of $18.0 million from our share of equity-method investments and $4.6 million of other non-cash charges related to SPN Resources.
The following table compares our operating results for the years ended December 31, 2010 and 2009 (in thousands). Cost of services, rentals and sales excludes depreciation, depletion, amortization and accretion for each of our business segments.
The following discussion analyzes our results on a segment basis.
Subsea and Well Enhancement Segment
Revenue for our subsea and well enhancement segment was $1,112.7 million for the year ended December 31, 2010, as compared to $919.3 million for 2009. Our increase in revenue and profitability is primarily due to demand increases in the domestic land and international market areas. Revenue from our domestic land market area increased approximately 75% due to demand for coiled tubing, cased hole wireline, well control services and hydraulic workover and snubbing services. Additionally, revenue from our international market areas increased approximately 77% primarily due to our acquisition of Hallin along with increased revenue from our well control services and hydraulic workover and snubbing services. Revenue from our Gulf of Mexico market area decreased approximately 18% primarily based on a decline in revenue from work associated with our large-scale decommissioning project. This decrease was partially offset by increased well control work and plug and abandonment activity, as well as our acquisitions of Superior Completion Services and the Bullwinkle platform.
Cost of services decreased to 61% of segment revenue in 2010, as compared to 67% of segment revenue in 2009. Similar to revenue, our profitability increased due to increased demand for coiled tubing, cased hole wireline, well control services and hydraulic workover and snubbing services. Additionally, cost of services as a percentage of revenue for 2009 was impacted due to the adjustment related to our large-scale decommissioning project. During the fourth quarter of 2009 as we neared completion of this project, we determined it was necessary to increase our total cost estimate due to various well conditions and other technical issues associated with this complex and challenging project. As the revenue related to this long-term contract is recorded on the percentage-of-completion method utilizing costs incurred as a percentage of total estimated costs, the cumulative effect of changes to estimated total contract costs was recognized in the period in which revisions were identified.
Drilling Products and Services Segment
Revenue for our drilling products and services segment was $474.7 million for the year ended December 31, 2010, an approximate 11% increase from 2009. Cost of services increased to 37% of segment revenue in 2010 from 34% in 2009. The increase in revenue for this segment is primarily related to rentals of our accommodation units and specialty tubulars, specifically in our domestic land market area. Revenue in our domestic land market area increased approximately 54% for the year ended December 31, 2010 over the same period in 2009. Revenue generated from our international market areas increased approximately 5%. Revenue from our Gulf of Mexico market area decreased approximately 11% due to decreased demand for specialty tubulars and stabilization equipment as a result of the lingering effects of the deepwater drilling moratorium. The decrease in demand for specialty tubulars was partially offset by an increase in demand for accommodation rentals, which benefited from oil spill cleanup efforts. Cost of services as a percentage of revenue increased 4% as rentals from high-margin drill pipe, specialty tubulars and stabilization equipment fell significantly in the Gulf of Mexico due to the deepwater drilling moratorium.
Marine Segment
Our marine segment revenue for the year ended December 31, 2010 decreased 9% from 2009 to $94.3 million. Our cost of services percentage increased to 71% of segment revenue for the year ended December 31, 2010 from 62% in 2009 primarily due to increased liftboat inspections and maintenance costs coupled with decreased revenue. Due to the high fixed cost nature of this segment, cost of services does not fluctuate proportionately with revenue. The fleet’s average utilization increased to approximately 67% in 2010 from 52% in 2009. However, the fleet’s average dayrate decreased to approximately $13,600 in 2010 from $16,800 in 2009. The average dayrate decreased as several of our larger liftboats were not available for work due to inspections and repairs. Both of our 250-foot class liftboats were out of service for an extended period of time for U.S. Coast Guard inspections. Additionally, our two completed 265-foot class liftboats recently returned to service in October and November of 2010 after being out of service for repairs since November 2009. In December 2010, we also sold one of our 175-foot class liftboats for $5.4 million and recorded a gain of approximately $1.1 million.
Depreciation, Depletion, Amortization and Accretion
Depreciation, depletion, amortization and accretion increased to $220.8 million for the year ended December 31, 2010 from $207.1 million in 2009. Depreciation, depletion, amortization and accretion expense related to our subsea and well enhancement segment increased $5.3 million, or 6%, in 2010 from the same period in 2009. Increases in depreciation, depletion, amortization and accretion related to the acquisitions of Superior Completion Services, Hallin and the Bullwinkle platform, along with 2009 and 2010 capital expenditures, were offset by the decrease in depreciation and amortization as a result of the $212.5 million reduction in value of assets related to our domestic land market area recorded in 2009. Depreciation and amortization expense increased within our drilling products and services segment by $9.1 million, or 9%, due to 2009 and 2010 capital expenditures. Depreciation expense related to the marine segment decreased $0.7 million, or 6%. The decrease in depreciation expense in our marine segment is attributable to the fact that our 250-foot class liftboats were out of service for an extended period of time for U.S. Coast Guard inspections and our two completed 265-foot class liftboats returned to service in the October and November of 2010 after being out of the service for repairs since November 2009.
General and Administrative Expenses
General and administrative expenses increased to $342.9 million for the year ended December 31, 2010 from $259.1 million in 2009. Included in this increase is approximately $35.0 million of management transition expenses. Additional increases in general and administrative expenses include the acquisitions of Superior Completion Services and Hallin, as well as increased bonus and compensation expense due to our improved performance, and additional infrastructure to enhance our growth.
Reduction in Value of Assets
During the fourth quarter of 2010, we recorded a reduction in the value of assets totaling $32.0 million in connection with liftboat components primarily related to our two partially completed 265-foot class liftboats. After a detailed evaluation, we concluded in December that it was impractical to complete these vessels. As such, we reduced our carrying value in these assets to their respective net realizable value and will utilize the remaining components as spares for our existing fleet.
During the second quarter of 2009, we recorded an expense of approximately $92.7 million in connection with intangible assets within our subsea and well enhancement segment. This reduction in value of intangible assets was primarily due to the decline in demand for services in the domestic land market area. During the fourth quarter of 2009, the domestic land market area remained depressed and our forecast of this market did not suggest a timely recovery sufficient to support our current carrying values. As such, we recorded an expense of approximately $119.8 million related to our tangible assets (property, plant and equipment) within the same segment.
Additionally in 2009, we recorded a $36.5 million expense to write off our remaining investment in BOG, an equity-method investment in which we owned a 40% interest. In April 2009, BOG defaulted under its loan agreements due primarily to the impact of production curtailments from Hurricanes Gustav and Ike in 2008 and the decline of natural gas and oil prices. As a result of continued negative BOG operating results, lack of viable interested buyers and unsuccessful attempts to renegotiate the terms and conditions of BOG’s loan agreements, we wrote off the remaining carrying value of our investment in BOG.
Comparison of the Results of Operations for the Years Ended December 31, 2009 and 2008
For the year ended December 31, 2009, our revenue was $1,449.3 million and our net loss was $102.3 million, or $1.31 loss per share. Included in the results for the year ended December 31, 2009 were non-cash, pre-tax charges of $212.5 million for the reduction in value of assets within our subsea and well enhancement segment and $36.5 million for the reduction in value of our remaining equity-method investment in BOG. Also included in the results for the year ended December 31, 2009 were losses of $18.0 million from our share of equity-method investments and $4.6 million of other non-cash charges related to SPN Resources. For the year ended December 31, 2008, revenue was $1,881.1 million, and net income was $351.5 million or $4.33 diluted earnings per share. Net income for the year ended December 31, 2008 included a $40.9 million gain from the sale of businesses. Revenue across all segments was lower in 2009 as compared to 2008 as a result of the significant downturn in commodity prices, the drilling rig count and overall industry activity. Revenue in our oil and gas segment decreased due the fact that we sold 75% of our interest in SPN Resources in March 2008. SPN Resources represented substantially all of our operating oil and gas segment. Subsequent to the sale of our interest on March 14, 2008, we account for our remaining interest in SPN Resources using the equity-method.
The following table compares our operating results for the years ended December 31, 2009 and 2008 (in thousands). Cost of services, rentals and sales excludes depreciation, depletion, amortization and accretion for each of our business segments. Oil and gas eliminations represent products and services provided to the oil and gas segment by our other segments.
The following discussion analyzes our results on a segment basis.
Subsea and Well Enhancement Segment
Revenue for our subsea and well enhancement segment was $919.3 million for the year ended December 31, 2009, as compared to $1,155.2 million for 2008. Cost of services increased to 67% of segment revenue in 2009, as compared to 55% of segment revenue in 2008. Our revenue decreased 20% due to a $139.5 million decrease in our domestic land business as a result of the significant downturn in commodity prices, the drilling rig count and overall industry activity in North America. Additionally, our revenue from a large-scale platform decommissioning project decreased approximately 29% due to the combination of less work being performed coupled with an increase in the estimated total cost of this project. During the fourth quarter of 2009 as we neared completion of this project, we determined it was necessary to increase our total cost estimate due to various well conditions and other technical issues associated with this complex and challenging project. As the revenue related to this long-term contract is recorded on the percentage-of-completion method utilizing costs incurred as a percentage of total estimated costs, the cumulative effect of changes to estimated total contract costs was recognized in the period in which revisions were identified. Revenue from international market areas grew 11% in 2009 due to an increase in emergency well control work and the commencement of three projects off the coast of Angola.
Drilling Products and Services Segment
Revenue for our drilling products and services segment was $426.9 million for the year ended December 31, 2009, an approximate 23% decrease from 2008. Cost of services increased to 34% of segment revenue in 2009 from 32% in 2008. The decrease in drilling products and services revenue is primarily related to a decrease in the rentals of our on-site accommodation units and stabilization equipment, specifically in the domestic land market area, and rentals of our drill pipe and stabilization equipment in international market areas. Drilling products and services revenue in our domestic land market area decreased 42% to approximately $108.4 million in 2009 from 2008. Additionally, drilling products and services revenue generated from the Gulf of Mexico and international market areas decreased by 14% and 10%, respectively, in 2009 from 2008.
Marine Segment
Our marine segment revenue for the year ended December 31, 2009 decreased 15% from 2008 to $103.1 million. Cost of services as a percentage of revenue remained constant at 62% in 2009 and 2008. The fleet’s average utilization decreased to approximately 52% in 2009 from 66% in 2008. The utilization decrease was offset by an increase in the fleet’s average dayrate, which increased 8% to approximately $16,800 in 2009 from $15,600 in 2008. The increase in average dayrate was primarily due to the addition of two 265-foot class vessels in the second quarter of 2009. Generally, cost of services does not fluctuate proportionately with revenue due to the high fixed costs associated with this segment; thus, a decrease in revenue would typically result in higher cost of service as a percentage of revenue. However, during 2008, we incurred substantial costs for maintenance to our liftboat fleet. Additionally, we benefited from a decrease in insurance expense in 2009 as a result of our favorable loss history and more competitive marine insurance markets.
In the fourth quarter of 2009, our two 265-foot class liftboats were removed from service following damage to one of the vessels during Hurricane Ida. Both vessels returned to service in the fourth quarter of 2010. Additionally, we sold four liftboats from our 145 - 155-foot class for approximately $7.7 million and recorded a gain of approximately $2.1 million.
Oil and Gas Segment
In March 2008, we sold 75% of our interest in SPN Resources for approximately $167.2 million and recorded a pre-tax gain on sale of this business of approximately $37.1 million. SPN Resources represented substantially all of our oil and gas segment. Subsequent to the sale of our interest on March 14, 2008, we account for our remaining interest in SPN Resources using the equity-method.
Depreciation, Depletion, Amortization and Accretion
Depreciation, depletion, amortization and accretion increased to $207.1 million for the year ended December 31, 2009 from $175.5 million in 2008. Depreciation and amortization expense related to our subsea and well enhancement segment increased $17.8 million, or 25%, in 2009 from the same period in 2008. The increase in depreciation and amortization expense for this segment is primarily attributable to our 2009 and 2008 capital expenditures partially offset by a decrease in the amortization expense as a result of a $92.7 million reduction in the value of amortizable intangible assets in the second quarter of 2009. Depreciation and amortization expense related to our drilling products and services segment increased $15.2 million, or 17%, in 2009 from the same period in 2008 primarily due to our 2009 and 2008 capital expenditures. Depreciation expense related to the marine segment in 2009 increased approximately $1.4 million, or 14%, from 2008. The increase in depreciation expense for the marine segment is primarily attributable to the delivery of two new vessels, which was partially offset by lower utilization.
General and Administrative Expenses
General and administrative expenses decreased to $259.1 million for the year ended December 31, 2009 from $282.6 million in 2008. General and administrative expenses related to our subsea and well enhancement and drilling products and services segments decreased $21.8 million, or 8%, from 2008 to 2009. The decrease in general and administrative expense within these two segments is primarily related to decreased incentive compensation expenses. General and administrative expenses related to our marine segment increased $7.1 million primarily due to the expense incurred as a result of the write-down of components from one of our 265-foot class liftboats in the fourth quarter of 2009.
Reduction in Value of Assets
During the second quarter of 2009, we recorded an expense of approximately $92.7 million in connection with intangible assets within our subsea and well enhancement segment. This reduction in value of intangible assets was primarily due to the decline in demand for services in the domestic land market area. During the fourth quarter of 2009, the domestic land market area remained depressed and our forecast of this market did not suggest a timely
recovery sufficient to support our current carrying values. As such, we recorded an expense of approximately $119.8 million related to our tangible assets (property, plant and equipment) within the same segment.
Additionally, we recorded a $36.5 million expense to write off our remaining investment in BOG, an equity-method investment in which we owned a 40% interest. In April 2009, BOG defaulted under its loan agreements due primarily to the impact of production curtailments from Hurricanes Gustav and Ike in 2008 and the decline of natural gas and oil prices. As a result of continued negative BOG operating results, lack of viable interested buyers and unsuccessful attempts to renegotiate the terms and conditions of BOG’s loan agreements, we wrote off the remaining carrying value of our investment in BOG.
Liquidity and Capital Resources
In the year ended December 31, 2010, we generated net cash from operating activities of $456.0 million as compared to $276.1 million in 2009. This increase is primarily attributable to the billings and receipt of payments related to the large-scale decommissioning contract in the Gulf of Mexico. Included in other current assets is approximately $144.5 million and $209.5 million at December 31, 2010 and 2009, respectively, of costs and estimated earnings in excess of billings related to this project. Billings, and subsequent receipts, are based on the completion of milestones.
Our primary liquidity needs are for working capital, and to fund capital expenditures, debt service and acquisitions. Our primary sources of liquidity are cash flows from operations and available borrowings under our revolving credit facility. We had cash and cash equivalents of $50.7 million and $206.5 million at December 31, 2010 and 2009, respectively. At December 31, 2009, $167.1 million was held in a foreign account in anticipation of the January 2010 acquisition of Hallin.
We spent $323.2 million of cash on capital expenditures during the year ended December 31, 2010. Approximately $142.9 million was used to expand and maintain our drilling products and services equipment inventory, approximately $30.0 million was spent on our marine segment and approximately $150.3 million was used to expand and maintain the asset base of our subsea and well enhancement segment.
In August 2010, we acquired certain assets used in Baker Hughes’ Gulf of Mexico stimulation and sand control business (currently operating as Superior Completion Services), for approximately $54.3 million of cash. Baker Hughes was required to divest this business by the Department of Justice in connection with its acquisition of BJ Services Company. The acquisition of these assets, along with a manufacturing facility and related product line, provides us greater exposure to well completions and intervention projects earlier in the life cycle of the well.
In January 2010, we acquired Hallin for approximately $162.3 million of cash. Additionally, we repaid approximately $55.5 million of Hallin’s debt. Hallin is an international provider of integrated subsea services and engineering solutions, focused on installing, maintaining and extending the life of subsea wells. Hallin operates in international offshore oil and gas markets with offices and facilities located in Singapore, Indonesia, Australia, Scotland and the United States.
In July 2010, we amended our bank revolving credit facility to increase the borrowing capacity to $400 million from $325 million, with the right, at our option, to increase the borrowing capacity of the facility to $550 million. Any amounts outstanding under the revolving credit facility are due on July 20, 2014. At December 31, 2010, we had $175.0 million outstanding under the bank credit facility with a weighted average interest rate of 3.4% per annum. Our borrowings under the revolving credit facility remained essentially constant during 2010. We anticipate collecting $144.5 million late in the first half of 2011 in connection with the large-scale platform decommissioning project in the Gulf of Mexico, pending certain regulatory approvals. At February 18, 2011, we had $161.5 million outstanding under the bank credit facility with a weighted average interest rate of 3.6% per annum. We also had $8.3 million of letters of credit outstanding, which reduces our borrowing capacity under this credit facility. Borrowings under the credit facility bear interest at LIBOR plus margins that depend on our leverage ratio. Indebtedness under the credit facility is secured by substantially all of our assets, including the pledge of the stock of our principal subsidiaries. The credit facility contains customary events of default and requires that we satisfy various financial covenants. It also limits our ability to pay dividends or make other distributions, make acquisitions, create liens or incur additional indebtedness.
At December 31, 2010, we had outstanding $13.4 million in U.S. Government guaranteed long-term financing under Title XI of the Merchant Marine Act of 1936, which is administered by the Maritime Administration (MARAD), for two 245-foot class liftboats. This debt bears an interest rate of 6.45% per annum and is payable in equal semi-annual installments of $405,000 on June 3rd and December 3rd of each year through the maturity date of June 3, 2027. Our obligations are secured by mortgages on the two liftboats. This MARAD financing also requires that we comply with certain covenants and restrictions, including the maintenance of minimum net worth, working capital and debt-to-equity requirements.
We have outstanding $300 million of 6 7/8% unsecured senior notes due 2014. The indenture governing the senior notes requires semi-annual interest payments on June 1st and December 1st of each year through the maturity date of June 1, 2014. The indenture contains certain covenants that, among other things, limit us from incurring additional debt, repurchasing capital stock, paying dividends or making other distributions, incurring liens, selling assets or entering into certain mergers or acquisitions.
The Company’s current long-term issuer credit rating is BB+ by Standard and Poor’s and Ba3 by Moody’s. Our credit rating may be impacted by the rating agencies’ view of the cyclical nature of our industry sector.
We also have outstanding $400 million of 1.50% senior exchangeable notes due 2026. The exchangeable notes bear interest at a rate of 1.50% per annum and decrease to 1.25% per annum on December 15, 2011. Interest on the exchangeable notes is payable semi-annually in arrears on December 15th and June 15th of each year through the maturity date of December 15, 2026. The exchangeable notes do not contain any restrictive financial covenants.
Under certain circumstances, holders may exchange the notes for shares of our common stock. The initial exchange rate is 21.9414 shares of common stock per $1,000 principal amount of notes. This exchange rate is equal to an initial exchange price of $45.58 per share. The exchange price represents a 35% premium over the closing share price at the date of issuance. The notes may be exchanged under the following circumstances:
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during any fiscal quarter (and only during such fiscal quarter), if the last reported sale price of our common stock is greater than or equal to 135% of the applicable exchange price of the notes for at least 20 trading days in the period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter;
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prior to December 15, 2011, during the five business-day period after any ten consecutive trading-day period (the “measurement period”) in which the trading price of $1,000 principal amount of notes for each trading day in the measurement period was less than 95% of the product of the last reported sale price of our common stock and the exchange rate on such trading day;
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if the notes have been called for redemption;
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upon the occurrence of specified corporate transactions; or
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at any time beginning on September 15, 2026, and ending at the close of business on the second business day immediately preceding the maturity date of December 15, 2026.
Holders of the senior exchangeable notes may also require us to purchase all or a portion of their notes on December 15, 2011, December 15, 2016 and December 15, 2021 subject to certain administrative formalities. In each case, the purchase price payable will be equal to 100% of the principal amount of the notes to be purchased plus any accrued and unpaid interest with all amounts payable in cash.
As the holders of the senior exchangeable notes have the ability to require us to purchase all of their notes on December 15, 2011, these notes are deemed to be a current liability as of December 31, 2010. In accordance with authoritative guidance related to the classification of short-term debt that is expected to be refinanced, we utilized the amount available under our current bank revolving credit facility of approximately $216.0 million at December 31, 2010 and classified this portion of the senior exchangeable notes as long-term under the assumption that the revolving credit facility could be used to refinance this debt, if required.
We also have the option to redeem for cash the senior exchangeable notes at any time on or after December 15, 2011 at a price equal to 100% of the principal amount to be redeemed plus accrued and unpaid interest. During 2011, we intend to incur additional debt in order to refinance these notes in December 2011 through either the exercise of our redemption right or the note holder purchase option.
In connection with the issuance of the exchangeable notes, we entered into agreements with affiliates of the initial purchasers to purchase call options and sell warrants on our common stock. We may exercise the call options we purchased at any time to acquire approximately 8.8 million shares of our common stock at a strike price of $45.58 per share. The owners of the warrants may exercise the warrants to purchase from us approximately 8.8 million shares of our common stock at a price of $59.42 per share, subject to certain anti-dilution and other customary adjustments. The warrants may be settled in cash, in common stock or in a combination of cash and common stock, at our option. These transactions may potentially reduce the dilution of our common stock from the exchange of the notes by increasing the effective exchange price to $59.42 per share. Lehman Brothers OTC Derivatives, Inc. (LBOTC) is the counterparty to 50% of our call option and warrant transactions. In October 2008, LBOTC filed for bankruptcy protection. We continue to carefully monitor the developments affecting LBOTC. Although we may not retain the benefit of the call option due to LBOTC’s bankruptcy, we do not expect that there will be a material impact, if any, on the financial statements or results of operations. The call option and warrant transactions described above do not affect the terms of the outstanding exchangeable notes.
The following table summarizes our contractual cash obligations and commercial commitments at December 31, 2010 (amounts in thousands). We do not have any other material obligations or commitments.
We currently believe that we will spend approximately $500 million on capital expenditures, excluding acquisitions, during 2011. We believe that our current working capital, cash generated from our operations and availability under our revolving credit facility will provide sufficient funds for our identified capital projects.
In May 2010, we signed a contract for construction of a compact semi-submersible vessel. This vessel is designed for both shallow and deepwater conditions and will be capable of performing subsea construction, inspection, repairs and maintenance work as well as subsea light well intervention and abandonment work.
We intend to continue implementing our growth strategy of increasing our scope of services through both internal growth and strategic acquisitions. We expect to continue to make the capital expenditures required to implement our growth strategy in amounts consistent with the amount of cash generated from operating activities, the availability of additional financing and our credit facility. Depending on the size of any future acquisitions, we may require additional equity or debt financing in excess of our current working capital and amounts available under our revolving credit facility.
Off-Balance Sheet Arrangements
We have no off-balance sheet financing arrangements other than potential additional consideration that may be payable as a result of the future operating performances of certain acquisitions. At December 31, 2010, the maximum additional consideration payable for these acquisitions was approximately $4.0 million. Since these acquisitions occurred before we adopted the revised authoritative guidance for business combinations, these amounts are not classified as liabilities and are not reflected in our financial statements until the amounts are fixed and determinable. When amounts are determined, they are capitalized as part of the purchase price of the related acquisition. We do not have any other financing arrangements that are not required under generally accepted accounting principles to be reflected in our financial statements. During the year ended December 31, 2010, we paid additional consideration of approximately $15.3 million as a result of prior acquisitions.
Hedging Activities
In an effort to achieve a more balanced debt portfolio by targeting an overall desired position of fixed and floating rates, we entered into an interest rate swap in March 2010 whereby we are entitled to receive semi-annual interest payments at a fixed rate of 6 7/8% per annum and are obligated to make quarterly interest payments at a variable rate. Interest rate swap agreements that are effective at hedging the fair value of fixed-rate debt agreements are designated and accounted for as fair value hedges. At December 31, 2010, we had fixed-rate interest on approximately 63% of our long-term debt. As of December 31, 2010, we had a notional amount of $150 million related to this interest rate swap with a variable interest rate, which is adjusted every 90 days, based on LIBOR plus a fixed margin.
From time to time, we enter into forward foreign exchange contracts to mitigate the impact of foreign currency fluctuations. The forward foreign exchange contracts we enter into generally have maturities ranging from one to eighteen months. We do not enter into forward foreign exchange contracts for trading purposes. During the years ended December 31, 2010 and 2009, we held outstanding foreign currency forward contracts in order to hedge exposure to currency fluctuations. These contracts were not accounted for as hedges and were marked to fair market value each period. As of December 31, 2010, we had no outstanding foreign currency forward contracts.
Recently Issued Accounting Pronouncements
In January 2010, the Financial Accounting Standards Board issued Accounting Standards Update 2010-03 (ASU 2010-03), “Oil and Gas Reserve Estimation and Disclosures.” The update provides an amendment to Accounting Standards Codification 932 (ASC 932), “Extractive Activities - Oil and Gas,” that expands the definition of oil- and gas-producing activities and requires disclosures of reserve quantities and standardized measure of cash flows for equity-method investments that have significant oil- and gas-producing activities. ASU 2010-03 is effective for annual reporting periods ending on or after December 31, 2009. ASU 2010-03 allows an entity that becomes subject to the disclosure requirements of ASC 932 due to the change to the definition of significant oil- and gas-producing activities to apply the disclosure provisions of ASC 932 in annual periods beginning after December 31, 2009. As such, we included the disclosures required by ASU 2010-03 for our annual reporting period ended December 31, 2010.
On January 1, 2010, we adopted Accounting Standards Codification 810-10 (ASC 810-10), “Amendments to FASB Interpretation No. 46(R), Consolidation of Variable Interest Entities,” for determining whether an entity is a variable interest entity (VIE) and requires an enterprise to perform an analysis to determine whether the enterprise’s variable interest or interests give it a controlling financial interest in a VIE. ASC 810-10 also requires ongoing assessments of whether an enterprise is the primary beneficiary of a VIE, requires enhanced disclosures and eliminates the scope exclusion for qualifying special-purpose entities. The adoption of ASC 810-10 did not have a significant impact on our results of operations and financial position.
On January 1, 2010, we adopted Accounting Standards Update 2010-06 (ASU 2010-06), “Improving Disclosures about Fair Value Measurements.” The update provides an amendment to ASC 820-10, “Fair Value Measurements and Disclosures,” requiring additional disclosures of significant transfers between Level 1 and Level 2 within the fair value hierarchy, as well as information about purchases, sales, issuances and settlements using unobservable inputs (Level 3). ASU 2010-06 is effective for interim and annual reporting periods beginning after December 15,
2009 for new disclosures and clarifications of existing disclosures, except for disclosures about purchases, sales, issuances and settlements in the rollforward of activity in the Level 3 fair value measurements, which are effective for fiscal years beginning after December 15, 2010. The adoption of ASU 2010-06 did not have a significant impact on our results of operations and financial position.
In October 2009, the Financial Accounting Standards Board issued Accounting Standards Update 2009-13 (ASU 2009-13), “Multiple-Deliverable Revenue Arrangements.” The new standard changes the requirements for establishing separate units of accounting in a multiple element arrangement and requires the allocation of arrangement consideration to each deliverable based on the relative selling price. The selling price for each deliverable is based on vendor-specific objective evidence (VSOE) if available, third-party evidence if VSOE is not available, or estimated selling price if neither VSOE or third-party evidence is available. ASU 2009-13 is effective for revenue arrangements entered into in fiscal years beginning on or after June 15, 2010. We do not expect that the impact the adoption of ASU 2009-13 will have a significant impact on our results of operations and financial position.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
We are exposed to market risks associated with foreign currency fluctuations and changes in interest rates. A discussion of our market risk exposure in financial instruments follows.
Foreign Currency Exchange Rates
Because we operate in a number of countries throughout the world, we conduct a portion of our business in currencies other than the U.S. dollar. The functional currency for our international operations, other than certain operations in the United Kingdom and Europe, is the U.S. dollar, but a portion of the revenues from our foreign operations is paid in foreign currencies. The effects of foreign currency fluctuations are partly mitigated because local expenses of such foreign operations are also generally denominated in the same currency. We continually monitor the currency exchange risks associated with all contracts not denominated in the U.S. dollar.
We do not hold derivatives for trading purposes or use derivatives with complex features. Assets and liabilities of certain subsidiaries in the United Kingdom and Europe are translated at end of period exchange rates, while income and expense are translated at average rates for the period. Translation gains and losses are reported as the foreign currency translation component of accumulated other comprehensive loss in stockholders’ equity.
When we believe prudent, we enter into forward foreign exchange contracts to hedge the impact of foreign currency fluctuations. The forward foreign exchange contracts we enter into generally have maturities ranging from one to eighteen months. We do not enter into forward foreign exchange contracts for trading purposes. As of December 31, 2010, we had no outstanding foreign currency forward contracts.
Interest Rates
At December 31, 2010, our debt (exclusive of discounts), was comprised of the following (in thousands):
(*)
In March 2010, we entered into an interest rate swap agreement for a notional amount of $150 million, whereby we are entitled to receive semi-annual interest payments at a fixed rate of 6 7/8% per annum and are obligated to make quarterly interest payments at a variable rate. The variable interest rate, which is adjusted every 90 days, is based on LIBOR plus a fixed margin.
Based on the amount of this debt outstanding at December 31, 2010, a 10% increase in the variable interest rate would increase our interest expense for the year ended December 31, 2010 by approximately $1.3 million, while a 10% decrease would decrease our interest expense by approximately $1.3 million.
Equity Price Risk
We have $400 million of 1.50% senior exchangeable notes due 2026. The notes are, subject to the occurrence of specified conditions, exchangeable for our common stock initially at an exchange price of $45.58 per share, which would result in an aggregate of approximately 8.8 million shares of common stock being issued upon exchange. We may redeem for cash all or any part of the notes on or after December 15, 2011 for 100% of the principal amount redeemed. The holders may require us to repurchase for cash all or any portion of the notes on December 15, 2011, December 15, 2016 and December 15, 2021 for 100% of the principal amount of notes to be purchased plus any accrued and unpaid interest. The notes do not contain any restrictive financial covenants.
Each $1,000 of principal amount of the notes is initially exchangeable into 21.9414 shares of our common stock, subject to adjustment upon the occurrence of specified events. Holders of the notes may exchange their notes prior to maturity only if (1) the price of our common stock reaches 135% of the applicable exchange rate during certain periods of time specified in the notes; (2) specified corporate transactions occur; (3) the notes have been called for redemption; or (4) the trading price of the notes falls below a certain threshold. In addition, in the event of a fundamental change in our corporate ownership or structure, the holders may require us to repurchase all or any portion of the notes for 100% of the principal amount.
We also have agreements with affiliates of the initial purchasers to purchase call options and sell warrants of our common stock. We may exercise the call options at any time to acquire approximately 8.8 million shares of our common stock at a strike price of $45.58 per share. The owners of the warrants may exercise their warrants to purchase from us approximately 8.8 million shares of our common stock at a price of $59.42 per share, subject to certain anti-dilution and other customary adjustments. The warrants may be settled in cash, in shares or in a combination of cash and shares, at our option. Lehman Brothers OTC Derivatives, Inc. (LBOTC) is the counterparty to 50% of our call option and warrant transactions. We continue to carefully monitor the developments affecting LBOTC. Although we may not be able to retain the benefit of the call option due to LBOTC’s bankruptcy, we do not expect that there will be a material impact, if any, on the financial statements or results of operations. The call option and warrant transactions described above do not affect the terms of the outstanding exchangeable notes.
For additional discussion of the notes, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources” in Part II, Item 7.
Commodity Price Risk
Our revenues, profitability and future rate of growth significantly depend upon the market prices of oil and natural gas. Lower prices may also reduce the amount of oil and gas that can economically be produced.
Item 8.
Item 8. Financial Statements and Supplementary Data
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Superior Energy Services, Inc.:
We have audited the accompanying consolidated balance sheets of Superior Energy Services, Inc. and subsidiaries as of December 31, 2010 and 2009, and the related consolidated statements of operations, changes in stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2010. In connection with our audits of the consolidated financial statements, we also have audited financial statement schedule, Valuation and Qualifying Accounts. These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Superior Energy Services, Inc. and subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
As discussed in note 4 to the consolidated financial statements, the Company changed its method of accounting for business combinations in 2009 due to the adoption of new accounting requirements issued by the Financial Accounting Standards Board.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Superior Energy Services, Inc.’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 25, 2011 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
/s/ KPMG LLP
New Orleans, Louisiana
February 25, 2011
SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Balance Sheets
December 31, 2010 and 2009
(in thousands, except share data)
See accompanying notes to consolidated financial statements.
SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Statements of Operations
Years Ended December 31, 2010, 2009 and 2008
(in thousands, except per share data)
See accompanying notes to consolidated financial statements.
SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Statements of Changes in Stockholders’ Equity
Years Ended December 31, 2010, 2009 and 2008
(in thousands, except share data)
See accompanying notes to consolidated financial statements.
SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Statements of Changes in Stockholders’ Equity (Continued)
Years Ended December 31, 2010, 2009 and 2008
(in thousands, except share data)
See accompanying notes to consolidated financial statements.
SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Statements of Cash Flows
Years Ended December 31, 2010, 2009 and 2008
(in thousands)
See accompanying notes to consolidated financial statements.
SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2010, 2009 and 2008
(1)
Summary of Significant Accounting Policies
(a)
Basis of Presentation
The consolidated financial statements include the accounts of Superior Energy Services, Inc. and subsidiaries (the Company). All significant intercompany accounts and transactions are eliminated in consolidation. Certain previously reported amounts have been reclassified to conform to the 2010 presentation.
(b)
Business
The Company is a leading provider of specialized oilfield services and equipment focusing on serving the production and drilling related needs of oil and gas companies. The Company provides most of the services, tools and liftboats necessary to maintain, enhance and extend producing wells, as well as plug and abandonment services at the end of their life cycle.
(c)
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make significant estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
(d)
Major Customers and Concentration of Credit Risk
The majority of the Company’s business is conducted with major and independent oil and gas exploration companies. The Company evaluates the financial strength of its customers and provides allowances for probable credit losses when deemed necessary.
The market for the Company’s services and products is the offshore and onshore oil and gas industry in the United States and select international market areas. Oil and gas companies make capital expenditures on exploration, drilling and production operations. The level of these expenditures historically has been characterized by significant volatility.
The Company derives a large amount of revenue from a small number of major and independent oil and gas companies. In 2010, no single customer accounted for more than 10% of total revenue. In 2009 and 2008, Chevron accounted for approximately 15% and 12%, respectively, Apache accounted for approximately 13% and 11%, respectively and BP accounted for approximately 11% of total revenue each year primarily related to our subsea and well enhancement segment.
In addition to trade receivables, other financial instruments that potentially subject the Company to concentrations of credit risk consist of cash and derivative instruments used in hedging activities. The Company periodically evaluates the creditworthiness of financial institutions which may serve as a counterparty. The financial institutions in which the Company transacts business are large, investment grade financial institutions which are “well-capitalized” under applicable regulatory capital adequacy guidelines, thereby minimizing its exposure to credit risks for deposits in excess of federally insured amounts and for failure to perform as the counterparty on interest rate swap agreements.
(e)
Cash Equivalents
The Company considers all short-term investments with a maturity of 90 days or less when purchased to be cash equivalents.
(f)
Accounts Receivable and Allowances
Trade accounts receivable are recorded at the invoiced amount or the earned amount but not yet invoiced and do not bear interest. The Company maintains allowances for estimated uncollectible receivables including bad debts and other items. The allowance for doubtful accounts is based on the Company’s best estimate of probable uncollectible amounts in existing accounts receivable. The Company determines the allowance based on historical write-off experience and specific identification.
(g)
Inventory and Other Current Assets
Inventory and other current assets include approximately $70.0 million and $38.4 million of inventory at December 31, 2010 and 2009, respectively. Our inventory balance at December 31, 2010 consisted of $31.4 million of finished goods, $1.4 million of work-in-process, $2.2 million of raw materials and $35.0 million of supplies and consumables. Our inventory balance at December 31, 2009 consisted primarily of supplies and consumables. Inventories are stated at the lower of cost or market. Cost is determined on an average cost basis for finished goods and work-in-process. Supplies and consumables consist principally of products used in our services provided to customers.
Additionally, inventory and other current assets include approximately $146.9 million and $210.0 million of costs incurred and estimated earnings in excess of billings on uncompleted contracts at December 31, 2010 and 2009, respectively. The Company follows the percentage-of-completion method of accounting for applicable contracts. Accordingly, income is recognized in the ratio that costs incurred bears to estimated total costs. Adjustments to cost estimates are made periodically, and losses expected to be incurred on contracts in progress are charged to operations in the period such losses are determined.
(h)
Property, Plant and Equipment
Property, plant and equipment are stated at cost, except for assets acquired using purchase accounting, which are recorded at fair value as of the date of acquisition. With the exception of the Company’s liftboats, derrick barges and dynamically positioned subsea vessels, depreciation is computed using the straight line method over the estimated useful lives of the related assets as follows:
The Company’s liftboats, derrick barges and dynamically positioned subsea vessels are depreciated using the units-of-production method based on the utilization of the vessels and are subject to a minimum amount of annual depreciation. The units-of-production method is used for these assets because depreciation and depletion occur primarily through use rather than through the passage of time.
The Company capitalizes interest on the cost of major capital projects during the active construction period. Capitalized interest is added to the cost of the underlying assets and is amortized over the useful lives of the assets. The Company capitalized approximately $2.7 million, $2.9 million and $3.1 million in 2010, 2009 and 2008, respectively, of interest for various capital projects.
During the fourth quarter of 2010, the Company recorded a reduction in the value of assets totaling $32.0 million in connection with liftboat components primarily related to the two partially completed 265-foot class liftboats. After a thorough and comprehensive evaluation, the Company concluded in December
that it was impractical to complete these vessels. As such, the Company reduced the carrying value in these assets to their respective net realizable value and will utilize the remaining components as spares for the existing fleet.
Long-lived assets and certain identifiable intangibles are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is assessed by a comparison of the carrying amount of assets to their fair value calculated, in part, by the future net cash flows expected to be generated by the assets. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value. Assets are grouped by subsidiary or division for the impairment testing, except for liftboats, which are grouped together by leg length. These groupings represent the lowest level of identifiable cash flows. The Company has long-lived assets, such as facilities, utilized by multiple operating divisions that do not have identifiable cash flows. Impairment testing for these long-lived assets is based on the consolidated entity. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell. For the year ended December 31, 2009, we recorded approximately $119.8 million reduction in the value of property, plant and equipment due to the decline in the North American land market area (see note 3).
(i)
Goodwill
The Company follows authoritative guidance for goodwill and other intangible assets. This guidance requires that goodwill as well as other intangible assets with indefinite lives no longer be amortized, but instead tested annually for impairment. To test for impairment at December 31, 2010, the Company identified its reporting units (which are consistent with the Company’s operating segments) and determined the carrying value of each reporting unit by assigning the assets and liabilities, including goodwill and intangible assets, to the reporting units. The Company then estimated the fair value of each reporting unit and compared it to the reporting unit’s carrying value. Based on this test, the fair values of the reporting units substantially exceeded the carrying amounts. No impairment loss was recognized in the years ended December 31, 2010, 2009 or 2008 under this method. The following table summarizes the activity for the Company’s goodwill for the years ended December 31, 2010 and 2009 (amounts in thousands):
If, among other factors, (1) the Company’s market capitalization declines and remains below its stockholders’ equity, (2) the fair value of the reporting units decline, or (3) the adverse impacts of economic or competitive factors are worse than anticipated, the Company could conclude in future periods that impairment losses are required.
(j)
Notes Receivable
Notes receivable consist of commitments from the seller of oil and gas properties towards the abandonment of the acquired properties. Pursuant to the agreement with the seller, the Company will invoice the seller agreed upon amounts at the completion of certain decommissioning activities. The gross amount of these notes total $115.0 million and is recorded at present value using an effective interest rate of 6.58%. The related discount is amortized to interest income based on the expected timing of the platform’s removal.
(k)
Intangible and Other Long-Term Assets
Intangible and other long-term assets consist of the following at December 31, 2010 and 2009 (amounts in thousands):
Customer relationships, tradenames, and non-compete agreements are amortized using the straight line method over the life of the related asset with weighted average useful lives of 13 years, 18 years, and 3 years, respectively. Debt acquisition costs are amortized primarily using the effective interest method over the life of the related debt agreements with a weighted average useful life of 7 years. Amortization of debt acquisition costs is recorded in interest expense. Amortization expense (exclusive of debt acquisition costs) was approximately $3.3 million, $4.3 million and $9.1 million for the years ended December 31, 2010, 2009 and 2008, respectively. Estimated annual amortization of intangible assets (exclusive of debt acquisition costs) will be approximately $3.1 million for 2011and 2012, $3.0 million for 2013 and 2014 and $2.9 million for 2015, excluding the effects of any acquisitions or dispositions subsequent to December 31, 2010.
In connection with the review for impairment of long-lived assets in accordance with authoritative guidance, the Company recorded approximately $92.7 million as a reduction in the value of intangible assets during the year ended December 31, 2009 (see note 3).
(l)
Decommissioning Liabilities
In connection with the acquisition of the Bullwinkle platform and its related assets, the Company records estimated future decommissioning liabilities in accordance with the authoritative guidance related to asset retirement obligations (decommissioning liabilities), which requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred, with a corresponding increase in the carrying amount of the related long-lived asset. Subsequent to initial measurement, the decommissioning liability is required to be accreted each period to present value. The Company’s decommissioning liabilities associated with the Bullwinkle platform and its related assets consist of costs related to the plugging of wells, the removal of the related facilities and equipment, and site restoration.
Whenever practical, the Company utilizes its own equipment and labor services to perform well abandonment and decommissioning work. When the Company performs these services, all recorded intercompany revenues and related costs of services are eliminated in the consolidated financial statements. The recorded decommissioning liability associated with a specific property is fully extinguished when the property is abandoned. The recorded liability is first reduced by all cash expenses incurred to abandon and decommission the property. If the recorded liability exceeds (or is less than) the Company’s total costs, then the difference is reported as income (or loss) within revenue during the period in which the work is performed. The Company reviews the adequacy of its decommissioning liabilities whenever indicators suggest that the estimated cash flows needed to satisfy the liability have changed materially. The timing and amounts of these expenditures are estimates, and changes to these estimates may result in additional (or decreased) liabilities recorded, which in turn would increase (or decrease) the carrying values of the related assets. The Company reviews its estimates for the timing of these expenditures on a quarterly basis.
In connection with the acquisition of Superior Completion Services, the Company assumed approximately $10.0 million of decommissioning liabilities associated with restoring two chartered vessels to the original condition in which they were received.
The following table summarizes the activity for the Company’s decommissioning liabilities for the year ended December 31, 2010 (amounts in thousands):
(m)
Revenue Recognition
Revenue is recognized when services or equipment are provided. The Company contracts for marine and subsea and well enhancement projects either on a day rate or turnkey basis, with a vast majority of its projects conducted on a day rate basis. The Company’s drilling products and services are rented on a day rate basis, and revenue from the sale of equipment is recognized when the equipment is shipped. Reimbursements from customers for the cost of drilling products and services that are damaged or lost down-hole are reflected as revenue at the time of the incident. The Company is accounting for the revenue and related costs on a large-scale platform decommissioning contract on the percentage-of-completion method utilizing costs incurred as a percentage of total estimated costs (see note 5). Subsequent to the acquisition of Bullwinkle and prior to the sale of 75% of its interest in SPN Resources, the Company recognized oil and gas revenue from its interests in producing wells as oil and natural gas was sold from those wells.
(n)
Taxes Collected from Customers
In connection with authoritative guidance related to taxes collected from customers and remitted to governmental authorities, the Company elected to net taxes collected from customers against those remitted to government authorities in the financial statements consistent with the historical presentation of this information.
(o)
Income Taxes
The Company accounts for income taxes and the related accounts under the asset and liability method. Deferred income taxes reflect the impact of temporary differences between amounts of assets and liabilities for financial reporting purposes and such amounts as measured by tax laws.
(p)
Earnings (Loss) per Share
Basic earnings (loss) per share is computed by dividing income (loss) available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share is computed in the same manner as basic earnings per share except that the denominator is increased to include the number of additional common shares that could have been outstanding assuming the exercise of stock options and restricted stock units and the potential shares that would have a dilutive effect on earnings per share.
Stock options and restricted stock units of approximately 1,650,000, 1,180,000 and 240,000 shares were excluded in the computation of diluted earnings per share for the years ended December 31, 2010, 2009 and 2008, respectively, as the effect would have been anti-dilutive.
In connection with the Company’s outstanding senior exchangeable notes, there could be a dilutive effect on earnings per share if the price of the Company’s common stock exceeds the initial exchange price of $45.58 per share for a specified period of time. In the event the Company’s common stock exceeds $45.58 per share for a specified period of time, the first $1.00 the price exceeds $45.58 would cause a dilutive effect of approximately 188,400 shares. As the share price continues to increase, dilution would continue to occur but at a declining rate. The impact on the calculation of earnings per share varies depending on when during the quarter the $45.58 per share price is reached (see note 8).
(q)
Financial Instruments
The fair value of the Company’s financial instruments of cash equivalents and accounts receivable approximates their carrying amounts. The fair value of the Company’s debt was approximately $902.5 million and $853.2 million at December 31, 2010 and 2009, respectively. The fair value of these debt instruments is determined by reference to the market value of the instrument as quoted in an over-the-counter market.
(r)
Foreign Currency
Results of operations for foreign subsidiaries with functional currencies other than the U.S. dollar are translated using average exchange rates during the period. Assets and liabilities of these foreign subsidiaries are translated using the exchange rates in effect at the balance sheet dates, and the resulting translation adjustments are reported as accumulated other comprehensive income (loss) in the Company’s stockholders’ equity.
For international subsidiaries where the functional currency is the U.S. dollar, financial statements are remeasured into U.S. dollars using the historical exchange rate for most of the long-term assets and liabilities and the balance sheet date exchange rate for most of the current assets and liabilities. An average exchange rate is used for each period for revenues and expenses. These transaction gains and losses, as well as any other transactions in a currency other than the functional currency, are included in general and administrative expenses in the consolidated statements of operations in the period in which the currency exchange rates change. For the years ended December 31, 2010, 2009 and 2008 the Company recorded approximately $1.6 million, $3.5 million and $4.3 million of foreign currency gains, respectively.
(s)
Stock-Based Compensation
In accordance with authoritative guidance related to stock compensation, the Company records compensation costs relating to share based payment transactions within the general and administrative expenses in the financial statements. The cost is measured at the grant date, based on the calculated fair value of the award, and is recognized as an expense over the employee’s requisite service period (generally the vesting period of the equity award).
(t)
Hedging Activities
In an effort to achieve a more balanced debt portfolio by targeting an overall desired position of fixed and floating rates, the Company entered into an interest rate swap in March 2010. Under this agreement, the Company is entitled to receive semi-annual interest payments at a fixed rate of 6 7/8% per annum and is obligated to make quarterly interest payments at a variable rate. Interest rate swap agreements that are effective at hedging the fair value of fixed-rate debt agreements are designated and accounted for as fair value hedges. At December 31, 2010, the Company had fixed-rate interest on approximately 63% of its long-term debt. As of December 31, 2010, the Company had a notional amount of $150 million related to this interest rate swap with a variable interest rate, which is adjusted every 90 days, based on LIBOR plus a fixed margin.
From time to time, the Company enters into forward foreign exchange contracts to hedge the impact of foreign currency fluctuations. The forward foreign exchange contracts generally have maturities ranging from one to eighteen months. The Company does not enter into forward foreign exchange contracts for trading purposes. During the years ended December 31, 2010 and 2008, the Company held foreign currency forward contracts outstanding in order to hedge exposure to currency fluctuations. During the year ended December 31, 2009, the Company did not hold any foreign currency forward contracts. These contracts are not designated as hedges, for hedge accounting treatment, and are marked to fair market value each period. As of December 31, 2010, we had no outstanding foreign currency forward contracts.
(u)
Other Comprehensive Loss
The following table reconciles the change in accumulated other comprehensive loss for the years ended December 31, 2010 and 2009 (amounts in thousands):
(2)
Supplemental Cash Flow Information
The following table includes the Company’s supplemental cash flow information for the years ended December 31, 2010, 2009 and 2008 (amounts in thousands):
(3)
Reduction in Value of Assets
During the fourth quarter of 2010, the Company wrote off liftboat components, primarily related to the two partially completed 265-foot class liftboats, totaling $32.0 million. After a detailed evaluation, the Company concluded in December that it was impractical to complete these vessels. As such, the carrying value of these assets was reduced to their respective net realizable values. These remaining components will be utilized as spares for our existing fleet.
In accordance with authoritative guidance on property, plant and equipment, long-lived assets, such as property, plant and equipment and purchased intangibles subject to amortization are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Recoverability of assets to be held and used is assessed by a comparison of the carrying amount of such assets to their fair value calculated, in part, by the estimated undiscounted future cash flows expected to be generated by the assets. Cash flow estimates are based upon, among other things, historical results adjusted to reflect the best estimate of future market rates, utilization levels, and operating performance. Estimates of cash flows may differ from actual cash flows due to, among other things, changes in economic conditions or changes in an asset’s operating performance. The Company’s assets are grouped by subsidiary or division for the impairment testing, except for liftboats, which are grouped together by leg length. These groupings represent the lowest level of
identifiable cash flows. If the assets’fair value is less than the carrying amount of those items, impairment losses are recorded in the amount by which the carrying amount of such assets exceeds the fair value. Assets to be disposed of are reported at the lower of the carrying amount or fair value less estimated costs to sell. The net carrying value of assets not fully recoverable is reduced to fair value. The estimate of fair value represents the Company’s best estimate based on industry trends and reference to market transactions and is subject to variability. The oil and gas industry is cyclical and these estimates of the period over which future cash flows will be generated, as well as the predictability of these cash flows, can have a significant impact on the carrying values of these assets and, in periods of prolonged down cycles, may result in impairment charges. During the second quarter of 2009, the Company recorded approximately $92.7 million of expense in connection with intangible assets within the subsea and well enhancement segment. This reduction in value of intangible assets was primarily due to the decline in demand for services in the domestic land market area. During the fourth quarter of 2009, the domestic land market remained depressed and the forecast of this market did not suggest a timely recovery sufficient to support the carrying values of these assets. As such, the Company recorded approximately $119.8 million of expense related to tangible assets (property, plant and equipment) within the same segment.
In accordance with authoritative guidance on intangible assets, goodwill and other intangible assets with indefinite lives will not be amortized, but instead tested for impairment annually as of December 31 or on an interim basis if events or circumstances indicate that the fair value of the asset has decreased below its carrying value. In order to estimate the fair value of the reporting units (which is consistent with the reported business segments), the Company used a weighting of the discounted cash flow method and the public company guideline method of determining fair value of each reporting unit. The Company weighted the discounted cash flow method 80% and the public company guideline method 20% due to differences between the Company’s reporting units and the peer companies’ size, profitability and diversity of operations. In order to validate the reasonableness of the estimated fair values obtained for the reporting units, a reconciliation of fair value to market capitalization was performed for each unit on a standalone basis. A control premium, derived from market transaction data, was used in this reconciliation to ensure that fair values were reasonably stated in conjunction with the Company’s capitalization. These fair value estimates were then compared to the carrying value of the reporting units. As the fair value of the reporting unit exceeded the carrying amount, no impairment loss was recognized during the years ended December 31, 2010, 2009 and 2008. A significant amount of judgment was involved in performing these evaluations since the results are based on estimated future events.
Superior Completion Services
On August 30, 2010, the Company acquired certain assets (now operating as Superior Completion Services) from subsidiaries of Baker Hughes Incorporated (Baker Hughes) for approximately $54.3 million of cash. The assets purchased were used in Baker Hughes’ Gulf of Mexico stimulation and sand control business. Superior Completion Services provides the Company greater exposure to well completions and intervention projects earlier in the life cycle of the well.
The following table summarizes the consideration paid for Superior Completion Services and the fair value of the assets acquired and liabilities assumed at the acquisition date (in thousands):
Current assets include inventory consisting of sand control completion tools. Identifiable intangible assets include amortizable intangibles of $1.6 million related to brand names with a useful life of 10 years as well as $0.4 million of customer relationships with a useful life of 15 years. Decommissioning liabilities consist of contractual
obligations to restore two chartered stimulation vessels to their original condition prior to returning to their respective owners.
The Company expensed a total of approximately $0.2 million of acquisition-related costs during the year ended December 31, 2010, which was recorded as general and administrative expenses in the consolidated statements of operations.
Hallin
On January 26, 2010, the Company acquired 100% of the equity interest of Hallin Marine Subsea International Plc (Hallin) for approximately $162.3 million of cash. Additionally, the Company repaid approximately $55.5 million of Hallin’s debt. Hallin is an international provider of integrated subsea services and engineering solutions, focused on installing, maintaining and extending the life of subsea wells. Hallin operates in international offshore oil and gas markets with offices and facilities located in Singapore, Indonesia, Australia, Scotland and the United States. The acquisition of Hallin provides the Company the opportunity to enhance its position in the subsea and well enhancement market through Hallin’s existing subsea assets (remotely operated vehicles, saturation diving systems, chartered and owned vessels) and newbuild vessel program.
The following table summarizes the consideration paid for Hallin and the fair value of the assets acquired and liabilities assumed at the acquisition date (in thousands):
Identifiable intangible assets include goodwill of $93.7 million and amortizable intangibles of $24.5 million. Goodwill consists of assembled workforce, entry into new international markets and business lines, as well as synergistic opportunities created by including the operations of Hallin with the existing services of the Company. All of the goodwill was assigned to the Company’s subsea and well enhancement segment. None of the goodwill recognized is expected to be deductible for income tax purposes. Amortizable intangibles consist of tradenames and customer relationships that have a weighted average useful life of 18 years.
The fair value of the current assets acquired includes trade receivables with a fair value of $19.3 million. The gross amount due from customers was $21.4 million, of which $2.1 million was deemed to be doubtful.
The Company expensed a total of $0.7 million of acquisition-related costs during the year ended December 31, 2010, which was recorded as general and administrative expenses in the consolidated statements of operations. An additional $4.9 million of acquisition-related costs, a portion of which was related to foreign currency exchange loss, was expensed in the year ended December 31, 2009.
Hallin is the lessee of a dynamically positioned subsea vessel under a capital lease expiring in 2019 with a 2 year renewal option. Hallin owns a 5% equity interest in the entity that owns this leased asset. The entity owning this vessel had $31.3 million of debt as of December 31, 2010, all of which was non-recourse to the Company. The amount of the asset and liability under this capital lease is recorded at the present value of the lease payments. This vessel is depreciated using the units-of-production method based on the utilization of the vessel and is subject to a minimum amount of annual depreciation. The units-of-production method is used for this vessel because depreciation occurs primarily through use rather than through the passage of time. Depreciation expense for this asset under the capital lease was approximately $3.8 million from the date of acquisition through December 31, 2010. Included in other long-term liabilities at December 31, 2010 is $33.0 million related to the obligations under this capital lease.
Bullwinkle Platform
On January 31, 2010, Wild Well Control, Inc. (Wild Well), a wholly-owned subsidiary of the Company, acquired 100% ownership of Shell Offshore Inc.’s Gulf of Mexico Bullwinkle platform and its related assets, including 29 wells, and assumed the decommissioning obligation for such assets. Immediately after Wild Well acquired these assets, it conveyed an undivided 49% interest in these assets and the related well plugging and abandonment obligations to Dynamic Offshore Resources, LLC (Dynamic Offshore), which operates these assets. Additionally, Dynamic Offshore will pay Wild Well to extinguish its 49% portion of the well plugging and abandonment obligation (see note 5). In addition to the revenue generated from oil and gas production, the platform also generates revenue from several production handling arrangements for other subsea fields. At the end of their respective economic lives, Wild Well will plug and abandon the wells and decommission the Bullwinkle platform. This body of work will provide additional opportunities for our products and services in the Gulf of Mexico, especially during cyclical and slower seasonal periods.
The following table summarizes the fair value of the assets acquired and liabilities assumed as of the acquisition date (in thousands):
Notes receivable consist of a commitment from the seller of the oil and gas properties to pay Wild Well upon the decommissioning of the platform. The gross amount of these notes total $115.0 million and are recorded at present value using an effective interest rate of 6.58%. The related discount is amortized to interest income based on the expected timing of the platform’s removal.
The Company expensed a total of $0.1 million of acquisition-related costs during the year ended December 31, 2010, which was recorded as general and administrative expenses in the consolidated statements of operations.
The revenue and earnings (losses) related to Superior Completion Services, Hallin and the Bullwinkle platform included in the Company’s consolidated statement of operations for the year ended December 31, 2010, and the revenue and earnings (losses) of the Company on a consolidated basis as if these acquisitions had occurred on January 1, 2009, with pro forma adjustments to give effect to depreciation, interest and certain other adjustments, together with related income tax effects, are as follows (in thousands, except per share amounts):
The 2010 and 2009 supplemental pro forma earnings above were adjusted to exclude $1.0 million and $4.9 million, respectively, of acquisition-related costs incurred in each of these periods.
The Company has no off-balance sheet financing arrangements other than potential additional consideration that may be payable as a result of future operating performances of certain acquisitions. At December 31, 2010, the
maximum additional contingent consideration payable was approximately $4.0 million and will be determined and payable through 2012. Since these acquisitions occurred before the Company adopted the revised authoritative guidance for business combinations, these amounts are not classified as liabilities and are not reflected in the Company’s financial statements until the amounts are fixed and determinable. The Company paid additional consideration of approximately $15.3 million for the year ended December 31, 2010, as a result of prior acquisitions. Of the consideration paid, $15.0 million was capitalized during the year ended December 31, 2010 and $0.3 million had been capitalized and accrued during 2009.
(5)
Long-Term Contracts
In January 2010, Wild Well acquired 100% ownership of Shell Offshore Inc.’s Gulf of Mexico Bullwinkle platform and its related assets, and assumed the decommissioning obligations of such assets. In connection with the conveyance of an undivided 49% interest in these assets and the related well plugging and abandonment obligations, Dynamic Offshore will pay Wild Well to extinguish its portion of the well plugging and abandonment obligations, limited to the current fair value of the obligation at the time of acquisition. As part of the asset purchase agreement with Shell Offshore Inc., Wild Well was required to obtain a $50 million performance bond as well as fund $50 million into an escrow account. This escrow account will be funded $3.0 million monthly through May 2011, with a final payment of $2.0 million in June 2011. Dynamic Offshore will fund a portion of this amount as part of its payment obligation for the well plugging and abandonment. Included in intangible and other long-term assets, net is escrowed cash of $33.0 million as of December 31, 2010. Included in other long-term liabilities is deferred revenue of $16.2 million as of December 31, 2010.
In connection with the sale of 75% of its interest in SPN Resources, the Company retained preferential rights on certain service work and entered into a turnkey contract to perform well abandonment and decommissioning work associated with oil and gas properties owned and operated by SPN Resources. This contract covers only routine end of life well abandonment and pipeline and platform decommissioning for properties owned and operated by SPN Resources at the date of closing and has a remaining fixed price of approximately $134.8 million and $141.1 million as of December 31, 2010 and 2009, respectively. The turnkey contract consists of numerous, separate billable jobs estimated to be performed through 2022. Each job is short-term in duration and will be individually recorded on the percentage-of-completion method utilizing costs incurred as a percentage of total estimated costs.
In December 2007, Wild Well entered into contractual arrangements pursuant to which it is decommissioning seven downed oil and gas platforms and related wells located offshore in the Gulf of Mexico for a fixed sum of $750 million, which is payable in installments upon the completion of specified portions of work. The contract contains certain covenants primarily related to Wild Well’s performance of the work. As of December 31, 2010, all work on this project was complete, pending certain regulatory approvals. The revenue related to the contract for decommissioning these downed platforms and wells is recorded on the percentage-of-completion method utilizing costs incurred as a percentage of total estimated costs. Included in other current assets at December 31, 2010 and 2009 is approximately $144.5 million and $209.5 million, respectively, of costs and estimated earnings in excess of billings related to this contract.
(6) Property, Plant and Equipment
A summary of property, plant and equipment at December 31, 2010 and 2009 (in thousands) is as follows:
During the fourth quarter of 2010, the Company recorded a reduction in the value of assets totaling $32.0 million in connection with liftboat components primarily related to the partially completed 265-foot class liftboats. After a thorough and comprehensive evaluation, the Company concluded in December that it was impractical to complete these vessels. As such, the Company reduced the carrying value in these assets to their respective net realizable value and will utilize the remaining components as spares for the existing fleet.
In connection with the review for impairment of long-lived assets in accordance with authoritative guidance, the Company recorded approximately $119.8 million as a reduction in the value of property, plant and equipment during the year ended December 31, 2009.
The Company had approximately $22.7 million and $22.4 million of leasehold improvements at December 31, 2010 and 2009, respectively. These leasehold improvements are depreciated over the shorter of the life of the asset or the life of the lease using the straight line method. Depreciation expense (excluding depletion, amortization and accretion) was approximately $207.7 million, $202.8 million and $163.6 million for the years ended December 31, 2010, 2009 and 2008, respectively.
Capital Lease
Hallin is the lessee of a dynamically positioned subsea vessel under a capital lease expiring in 2019 with a 2 year renewal option. Hallin owns a 5% equity interest in the entity that owns this leased asset. The entity owning this vessel had $31.3 million of debt as of December 31, 2010, all of which was non-recourse to the Company. The amount of the asset and liability under this capital lease is recorded at the present value of the lease payments. This vessel is depreciated using the units-of-production method based on the utilization of the vessel and is subject to a minimum amount of annual depreciation. The units-of-production method is used for this vessel because depreciation occurs primarily through use rather than through the passage of time. At December 31, 2010, the vessel’s gross asset value under the capital lease was approximately $37.6 million and depreciation expense was approximately $3.8 million from the date of acquisition through December 31, 2010. At December 31, 2010, the Company had approximately $33.0 million included in other long-term liabilities and approximately $3.2 million included in accounts payable related to the obligations under this capital lease. The future minimum lease payments under this capital lease are approximately $3.2 million, $3.6 million, $3.9 million, $4.2 million and $4.6 million in the years ending 2011, 2012, 2013, 2014 and 2015, respectively, exclusive of interest at an annual rate of 8.5%. For the year ended December 31, 2010, the Company recorded interest expense of approximately $3.0 million in connection with this capital lease.
(7) Equity-Method Investments
Investments in entities that are not controlled by the Company, but where the Company has the ability to exercise significant influence over the operations, are accounted for using the equity-method. The Company’s share of the income or losses of these entities is reflected as earnings or losses from equity-method investments in its consolidated statements of operations.
On March 14, 2008, the Company sold 75% of its original interest in SPN Resources. The Company’s equity-method investment balance in SPN Resources was approximately $43.6 million at December 31, 2010 and $52.3 million at December 31, 2009. The Company recorded earnings from its equity-method investment in SPN Resources of approximately $1.2 million for the year ended December 31, 2010 and losses of approximately $7.6 million for the year ended December 31, 2009. From the date of sale through December 31, 2008, the Company recorded earnings from its equity-method investment in SPN Resources of approximately $34.3 million. Additionally, the Company received approximately $9.9 million and $5.9 million of cash distributions from its equity-method investment in SPN Resources for the years ended December 31, 2010 and 2009, respectively. The Company, where possible and at competitive rates, provides its products and services to assist SPN Resources in producing and developing its oil and gas properties. The Company had a receivable from this equity-method investment of approximately $3.2 million and $1.9 million at December 31, 2010 and 2009, respectively. The Company also recorded revenue from this equity-method investment of approximately $11.4 million and $11.0 million for the years ended December 31, 2010 and 2009, respectively and $15.2 million from the date of sale through December 31, 2008. The Company also reduces its revenue and its investment in SPN Resources for its respective ownership interest when products and services are provided to and capitalized by SPN Resources. As these capitalized costs are depleted by SPN Resources, the Company then increases its revenue and investment in SPN Resources. As such, the Company recorded a net increase in revenue and its investment in SPN Resources of approximately $0.6 million for the year ended December 31, 2009. The Company recorded a net decrease in revenue and its investment in SPN Resources of approximately $0.7 million from the date of sale through December 31, 2008.
During the year ended December 31, 2009, the Company wrote off the remaining carrying value of its 40% interest in Beryl Oil and Gas L.P. (BOG), $36.5 million, and suspended recording its share of BOG’s operating results under equity-method accounting as a result of continued negative BOG operating results, lack of viable interested buyers and unsuccessful attempts to renegotiate the terms and conditions of its loan agreements with lenders on terms that would preserve the Company’s investment. The Company’s total cash contribution for this equity-method investment in BOG was approximately $57.8 million. The Company recorded losses from its equity-method investment in BOG of approximately $14.0 million and $9.9 million for the years ended December 31, 2009 and 2008, respectively. The Company also recorded revenue of approximately $7.0 million and $2.1 million from BOG for the years ended December 31, 2009 and 2008, respectively. The Company also recorded a net increase (decrease) in its investment in BOG of approximately ($6.1) million and $10.2 million for the years ended December 31, 2009 and 2008, respectively, for its proportionate share of accumulated other comprehensive income generated from hedging transactions. The Company recorded a net increase in revenue and its investment in BOG for services provided by the Company that were capitalized by BOG of approximately $0.2 million and $0.1 million for the years ended December 31, 2009 and 2008, respectively.
In October 2009, DBH, LLC (DBH) acquired BOG in connection with a restructuring of BOG in which the previously existing debt obligations of BOG were partially extinguished and otherwise renegotiated. Simultaneous with that acquisition, the Company acquired a 24.6% membership interest in DBH for approximately $8.7 million. DBH’s purchase of BOG using the acquisition method of accounting resulted in a difference between the carrying amount of the Company’s investment in DBH and the underlying equity in net assets. The difference is being adjusted against the equity in earnings based on the depletion of DBH’s oil and gas assets and related reserves. The Company’s equity-method investment balance in DBH was approximately $13.8 million and $7.7 million at December 31, 2010 and 2009, respectively. The Company recorded earnings from its equity-method investment in DBH of approximately $7.1 million during the year ended December 31, 2010. From the date of acquisition through December 31, 2009, the Company recorded a loss from its equity-method investment in DBH of approximately $1.0 million. Additionally, the Company received approximately $1.0 million of cash distributions from its equity-method investment in DBH for the year ended December 31, 2010. The Company had a receivable from this equity-
method investment of approximately $1.4 million and $2.3 million at December 31, 2010 and 2009, respectively. The Company also recorded revenue from this equity-method investment of approximately $4.1 million and $2.4 million for the year ended December 31, 2010 and from the date of acquisition through December 31, 2009, respectively.
Combined summarized financial information for all investments that are accounted for using the equity-method of accounting is as follows (in thousands):
(8) Debt
The Company’s long-term debt as of December 31, 2010 and 2009 consisted of the following (in thousands):
The Company has a $400 million bank revolving credit facility. In July 2010, the Company amended its revolving credit facility to increase the borrowing capacity to $400 million from $325 million, with the right, at the company’s option, to increase the borrowing capacity of the facility to $550 million. Any amounts outstanding under the revolving credit facility are due on July 20, 2014. Costs associated with amending the revolving credit facility were
approximately $5.2 million. These costs were capitalized and are being amortized over the remaining term of the credit facility. The weighted average interest rate on amounts outstanding under the revolving credit facility was 3.4% and 3.0% per annum at December 31, 2010 and 2009, respectively.
The Company also had approximately $8.9 million of letters of credit outstanding, which reduce the Company’s borrowing availability under this credit facility. Amounts borrowed under the credit facility bear interest at a LIBOR rate plus margins that depend on the Company’s leverage ratio. Indebtedness under the credit facility is secured by substantially all of the Company’s assets, including the pledge of the stock of the Company’s principal domestic subsidiaries. The credit facility contains customary events of default and requires that the Company satisfy various financial covenants. It also limits the Company’s ability to pay dividends or make other distributions, make acquisitions, make changes to the Company’s capital structure, create liens or incur additional indebtedness. At December 31, 2010, the Company was in compliance with all such covenants.
At December 31, 2010, the Company had outstanding $13.4 million in U.S. Government guaranteed long-term financing under Title XI of the Merchant Marine Act of 1936, which is administered by the Maritime Administration, for two 245-foot class liftboats. The debt bears interest at 6.45% per annum and is payable in equal semi-annual installments of $405,000 on June 3rd and December 3rd of each year through the maturity date of June 3, 2027. The Company’s obligations are secured by mortgages on the two liftboats. In accordance with the agreement, the Company is required to comply with certain covenants and restrictions, including the maintenance of minimum net worth, working capital and debt-to-equity requirements. At December 31, 2010, the Company was in compliance with all such covenants.
The Company also has outstanding $300 million of 6 7/8% unsecured senior notes due 2014. The indenture governing the senior notes requires semi-annual interest payments on June 1st and December 1st of each year through the maturity date of June 1, 2014. The indenture contains certain covenants that, among other things, limit the Company from incurring additional debt, repurchasing capital stock, paying dividends or making other distributions, incurring liens, selling assets or entering into certain mergers or acquisitions. At December 31, 2010, the Company was in compliance with all such covenants.
The Company has outstanding $400 million of 1.50% unsecured senior exchangeable notes due 2026. The exchangeable notes bear interest at a rate of 1.50% per annum that decreases to 1.25% per annum on December 15, 2011. Interest on the exchangeable notes is payable semi-annually on December 15th and June 15th of each year through the maturity date of December 15, 2026. The exchangeable notes do not contain any restrictive financial covenants.
Under certain circumstances, holders may exchange the notes for shares of the Company’s common stock. The initial exchange rate is 21.9414 shares of common stock per $1,000 principal amount of notes. This is equal to an initial exchange price of $45.58 per share. The exchange price represents a 35% premium over the closing share price at date of issuance. The notes may be exchanged under the following circumstances:
•
during any fiscal quarter (and only during such fiscal quarter), if the last reported sale price of the Company’s common stock is greater than or equal to 135% of the applicable exchange price of the notes for at least 20 trading days in the period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter;
•
prior to December 15, 2011, during the five business-day period after any ten consecutive trading-day period (the “measurement period”) in which the trading price of $1,000 principal amount of notes for each trading day in the measurement period was less than 95% of the product of the last reported sale price of the Company’s common stock and the exchange rate on such trading day;
•
if the notes have been called for redemption;
•
upon the occurrence of specified corporate transactions; or
•
at any time beginning on September 15, 2026, and ending at the close of business on the second business day immediately preceding the maturity date of December 15, 2026.
Holders of the senior exchangeable notes may also require the Company to purchase all or a portion of the notes on December 15, 2011, December 15, 2016 and December 15, 2021 subject to certain administrative formalities. In
each case, the purchase price payable will be equal to 100% of the principal amount of the notes to be purchased plus any accrued and unpaid interest with all amounts payable in cash.
As the holders of the senior exchangeable notes have the ability to require the Company to purchase all of the notes on December 15, 2011, these notes are deemed to be a current liability as of December 31, 2010. In accordance with authoritative guidance related to the classification of short-term debt that is expected to be refinanced, the Company utilized the amount available under its current bank revolving credit facility of approximately $216.0 million at December 31, 2010 and classified this portion as long-term under the assumption that the revolving credit facility could be used to refinance this debt, if required.
In connection with the exchangeable note transaction, the Company simultaneously entered into agreements with affiliates of the initial purchasers to purchase call options and sell warrants on its common stock. The Company may exercise the call options it purchased at any time to acquire approximately 8.8 million shares of its common stock at a strike price of $45.58 per share. The owners of the warrants may exercise the warrants to purchase from the Company approximately 8.8 million shares of the Company’s common stock at a price of $59.42 per share, subject to certain anti-dilution and other customary adjustments. The warrants may be settled in cash, in common stock or in a combination of cash and common stock, at the Company’s option. Lehman Brothers OTC Derivatives, Inc. (LBOTC) is the counterparty to 50% of the Company’s call option and warrant transactions. In October 2008, LBOTC filed for bankruptcy protection. We continue to carefully monitor the developments affecting LBOTC. Although the Company may not be able to retain the benefit of the call option due to LBOTC’s bankruptcy, the Company does not expect that there will be a material impact, if any, on the financial statements or results of operations. The call option and warrant transactions described above do not affect the terms of the outstanding exchangeable notes.
Effective January 1, 2009, the Company has retrospectively adopted authoritative guidance related to debt with conversion and other options, which requires the proceeds from the issuance of our 1.50% senior exchangeable notes (described below) to be allocated between a liability component (issued at a discount) and an equity component. The resulting debt discount is amortized over the period the exchangeable debt is expected to be outstanding as additional non-cash interest expense. The Company used an effective interest rate of 6.89% and will amortize this initial debt discount through December 12, 2011. The carrying amount of the equity component is $55.1 million at December 31, 2010 and 2009.
The provisions of this authoritative guidance are effective for fiscal years beginning after December 15, 2008 and require retrospective application. The Company’s consolidated statement of operations for the year ended December 31, 2008 has been adjusted from the previously reported amounts as follows (in thousands, except per share amounts):
The non-cash increase to interest expense, exclusive of amounts to be capitalized, was approximately $19.2 million and $17.8 million for the years ended December 31, 2010 and 2009, respectively and will be approximately $19.7 million for the year ended December 31, 2011.
Annual maturities of long-term debt for each of the five fiscal years following December 31, 2010 and thereafter are as follows (in thousands):
(9) Stock Based and Long-Term Compensation
The Company maintains various stock incentive plans that provide long-term incentives to the Company’s key employees, including officers, directors, consultants and advisers (Eligible Participants). Under the incentive plans, the Company may grant incentive stock options, non-qualified stock options, restricted stock, restricted stock units, stock appreciation rights, other stock based awards or any combination thereof to Eligible Participants. The Company has authorized 14.8 million shares of common stock related to the various long-term incentive plans. The Compensation Committee of the Company’s Board of Directors establishes the terms and conditions of any awards granted under the plans, provided that the exercise price of any stock options granted may not be less than the fair value of the common stock on the date of grant.
Stock Options
The Company has granted non-qualified stock options under its stock incentive plans. The options generally vest in equal installments over three years and expire in ten years. Non-vested options are generally forfeited upon termination of employment. In 2008, the Company amended its outstanding employee stock options to (1) provide immediate vesting of the stock options upon the optionee’s termination of employment due to death and disability, and, if approved by the Committee, upon retirement and termination of employment by the Company without cause, (2) make the period during which stock options can be exercised following termination of employment due to death, disability and retirement consistent among all outstanding option agreements by providing that the optionee has until the end of the original term of the stock option to exercise, and (3) extend the time during which the stock option may be exercised following a termination by the Company without cause or a termination without cause within one year following a change of control to five years following the termination, but in no event later than ten years following the date of grant. During 2010, the Company granted 1,549,058 non-qualified stock options under these same terms.
In accordance with authoritative guidance related to stock based compensation, the Company recognizes compensation expense for stock option grants based on the fair value at the date of grant using the Black-Scholes-Merton option pricing model. The Company uses historical data, among other factors, to estimate the expected price volatility, the expected option life and the expected forfeiture rate. The risk-free rate is based on the U.S. Treasury yield curve in effect at the time of grant for the expected life of the option. The following table presents the fair value of stock option grants made during the years ended December 31, 2010, 2009 and 2008 and the related assumptions used to calculate the fair value:
The Company’s compensation expense related to stock options for the years ended December 31, 2010, 2009 and 2008 was approximately $15.5 million, $2.4 million and $2.6 million, respectively, which is reflected in general and administrative expenses. During 2010, the Company modified 1,418,395 options, affecting three employees in connection with the management transition of certain executive officers. These options were accelerated to vest by December 31, 2010. The Company incurred incremental compensation cost of approximately $9.8 million during the year as a result of this modification.
The following table summarizes stock option activity for the years ended December 31, 2010, 2009 and 2008:
The aggregate intrinsic value in the table above represents the total pre-tax intrinsic value (the difference between the Company’s closing stock price on December 31, 2010 and the option price, multiplied by the number of “in-the-money” options) that would have been received by the option holders if all the options had been exercised on December 31, 2010. The Company expects all of its remaining non-vested options to vest as they are primarily held by its officers and senior managers.
The total intrinsic value of options exercised during the year ended December 31, 2010 (the difference between the stock price upon exercise and the option price) was approximately $1.5 million. The Company received approximately $0.9 million, $0.4 million and $4.3 million during the years ended December 31, 2010, 2009 and 2008, respectively, from employee stock option exercises. In accordance with authoritative guidance related to stock based compensation, the Company has reported the tax benefits of approximately $0.6 million, $0.2 million and $5.4 million from the exercise of stock options for the years ended December 31, 2010, 2009 and 2008, respectively, as financing cash flows.
A summary of information regarding stock options outstanding at December 31, 2010 is as follows:
The following table summarizes non-vested stock option activity for the year ended December 31, 2010:
As of December 31, 2010, there was approximately $6.9 million of unrecognized compensation expense related to non-vested stock options outstanding. The Company expects to recognize approximately $3.1 million, $2.6 million and $1.2 million of compensation expense during the years 2011, 2012 and 2013, respectively, for these non-vested stock options outstanding.
Restricted Stock
During the year ended December 31, 2010, the Company granted 357,826 shares of restricted stock to its employees. Shares of restricted stock generally vest in equal annual installments over three years. Non-vested shares are generally forfeited upon the termination of employment. Holders of restricted stock are entitled to all rights of a shareholder of the Company with respect to the restricted stock, including the right to vote the shares and receive any dividends or other distributions. Compensation expense associated with restricted stock is measured based on the grant date fair value of our common stock and is recognized on a straight line basis over the vesting period. The Company’s compensation expense related to restricted stock outstanding for the years ended December 31, 2010, 2009 and 2008 was approximately $11.4 million, $5.8 million and $4.7 million, respectively, which is reflected in general and administrative expenses. During 2010, the Company modified 282,781 shares of restricted stock affecting three employees in connection with the management transition of certain executive officers. These shares of restricted stock were accelerated to vest by December 31, 2010. The Company incurred incremental compensation cost of approximately $4.3 million during the year as a result of this modification.
A summary of the status of restricted stock for the year ended December 31, 2010 is presented in the table below:
As of December 31, 2010, there was approximately $12.0 million of unrecognized compensation expense related to non-vested restricted stock. The Company expects to recognize approximately $5.7 million, $4.2 million and $2.1 million during the years 2011, 2012 and 2013, respectively, for non-vested restricted stock.
Restricted Stock Units
Under the Amended and Restated 2004 Directors Restricted Stock Units Plan, each non-employee director is issued annually a number of Restricted Stock Units (RSUs) having an aggregate dollar value determined by the Company’s Board of Directors. The exact number of units is determined by dividing the dollar value determined by the Company’s Board of Directors by the fair market value of the Company’s common stock on the day of the annual stockholders’ meeting or a pro rata amount if the appointment occurs subsequent to the annual stockholders’ meeting. An RSU represents the right to receive from the Company, within 30 days of the date the director ceases to serve on the Board, one share of the Company’s common stock. As a result of this plan, 136,173 restricted stock units were outstanding at December 31, 2010. The Company’s expense related to RSUs for the years ended December 31, 2010, 2009 and 2008 was approximately $1.2 million, $0.6 million and $0.8 million, respectively, which is reflected in general and administrative expenses.
A summary of the activity of restricted stock units for the year ended December 31, 2010 is presented in the table below:
Performance Share Units
The Company has issued performance share units (PSUs) to its employees as part of the Company’s long-term incentive program. There is a three year performance period associated with each PSU grant. The two performance measures applicable to all participants are the Company’s return on invested capital and total shareholder return relative to those of the Company’s pre-defined “peer group.” The PSUs provide for settlement in cash or up to 50% in equivalent value in the Company’s common stock, if the participant has met specified continued service requirements. At December 31, 2010, there were 325,845 PSUs outstanding (71,774, 72,062, 100,438 and 81,571 related to performance periods ending December 31, 2010, 2011, 2012 and 2013, respectively). The Company’s compensation expense related to all outstanding PSUs for the years ended December 31, 2010, 2009 and 2008 was approximately $5.2 million, $7.3 million and $6.7 million, respectively, which is reflected in general and administrative expenses. The Company has recorded a current liability of approximately $6.0 million and $6.4 million at December 31, 2010 and 2009, respectively, for outstanding PSUs, which is reflected in accrued expenses. Additionally, the Company has recorded a long-term liability of approximately $7.0 million and $7.8 million at December 31, 2010 and 2009, respectively, for outstanding PSUs, which is reflected in other long-term liabilities. In 2010, the Company paid approximately $6.4 million in cash to settle PSUs for the performance period ended December 31, 2009. In 2009, the Company paid approximately $4.7 million in cash and issued approximately 71,400 shares of its common stock to its employees to settle PSUs for the performance period ended December 31, 2008.
Employee Stock Purchase Plan
The Company has employee stock purchase plans under which an aggregate of 1,250,000 shares of common stock were reserved for issuance. Under these stock purchase plans, eligible employees can purchase shares of the Company’s common stock at a discount. The Company received $1.9 million, $2.0 million and $1.6 million related to shares issued under these plans for the years ended December 31, 2010, 2009 and 2008, respectively. For the years ended December 31, 2010, 2009 and 2008, the Company recorded compensation expense of approximately $345,000, $350,000 and $275,000, respectively, which is reflected in general and administrative expenses. Additionally, the Company issued approximately 94,200, 133,400 and 57,000 shares for the years ended December 31, 2010, 2009 and 2008, respectively, related to these stock purchase plans.
(10) Income Taxes
The components of income and loss from continuing operations before income taxes for the years ended December 31, 2010, 2009 and 2008 are as follows (in thousands):
The components of income tax expense (benefit) for the years ended December 31, 2010, 2009 and 2008 are as follows (in thousands):
Income tax expense (benefit) differs from the amounts computed by applying the U.S. Federal income tax rate of 35% to income (loss) before income taxes for the years ended December 31, 2010, 2009 and 2008 as follows (in thousands):
The significant components of deferred income taxes at December 31, 2010 and 2009 are as follows (in thousands):
During 2010, the Company reduced the valuation allowance and corresponding deferred tax asset for net operating loss carry forwards that it believes will not be utilized due to loss limitations prescribed by the Internal Revenue Code. This adjustment did not affect current year earnings.
The net deferred tax assets reflect management’s estimate of the amount that will be realized from future profitability and the reversal of taxable temporary differences that can be predicted with reasonable certainty. A valuation allowance is recognized if it is more likely than not that at least some portion of any deferred tax asset will not be realized.
Net deferred tax liabilities were classified in the consolidated balance sheet at December 31, 2010 and 2009 as follows (in thousands):
As of December 31, 2010, the Company had approximately $1.3 million in net operating loss carryforwards, which are available to reduce future taxable income. The expiration dates for utilization of the loss carryforwards are 2019 through 2025. Utilization of $0.7 million of the net operating loss carryforwards will be subject to the annual limitations due to the ownership change limitations provided by the Internal Revenue Code of 1986, as amended. The annual limitations may result in expiration of the net operating loss before full utilization.
The Company has not provided United States income tax expense on earnings of its foreign subsidiaries, since the Company has reinvested or expects to reinvest the undistributed earnings indefinitely. At December 31, 2010, the undistributed earnings of the Company’s foreign subsidiaries were approximately $157.8 million. If these earnings are repatriated to the United States in the future, additional tax provisions may be required. It is not practicable to estimate the amount of taxes that might be payable on such undistributed earnings.
Effective January 1, 2007, the Company adopted authoritative guidance surrounding accounting for uncertainty in income taxes. It is the Company’s policy to recognize interest and applicable penalties related to uncertain tax positions in income tax expense.
The Company files income tax returns in the U.S. federal and various state and foreign jurisdictions. The number of years that are open under the statute of limitations and subject to audit varies depending on the tax jurisdiction. The Company remains subject to U.S. federal tax examinations for years after 2006.
The Company had approximately $24.8 million, $11.0 million and $9.7 million of unrecorded tax benefits at December 31, 2010, 2009 and 2008, respectively, all of which would impact the Company’s effective tax rate if recognized. An increase of $16.5 million was related to foreign income tax attributable to foreign acquisitions.
The activity in unrecognized tax benefits at December 31, 2010, 2009 and 2008 is as follows (in thousands):
(11) Stockholders’ Equity
In December 2009, the Company’s Board of Directors authorized a $350 million share repurchase program of the Company’s common stock that will expire on December 31, 2011, replacing the previous repurchase program that expired on December 31, 2009. Under this program, the Company may purchase shares through open market transactions at prices deemed appropriate by management. There was no common stock repurchased and retired during the years ended December 31, 2010 and 2009. For the year ended December 31, 2008, the Company purchased and retired 3,717,000 shares of its common stock for an aggregate amount of approximately $103.8 million.
(12) Gain on Sale of Businesses
In December 2010, the Company sold a liftboat from its 175-foot leg length class for approximately $5.4 million, inclusive of a $0.1 million receivable. As a result of this liftboat sale, the Company recorded a pre-tax gain of approximately $1.1 million for the year ended December 31, 2010.
In the fourth quarter of 2009, the Company sold four liftboats from its 145-foot leg length class for approximately $7.7 million. As a result of this sale of these liftboats, the Company recorded a pre-tax gain of approximately $2.1 million for the year ended December 31, 2009.
On March 14, 2008, the Company completed the sale of 75% of its interest in SPN Resources. As part of this transaction, SPN Resources contributed an undivided 25% of its working interest in each of its oil and gas properties to a newly formed subsidiary and then sold all of its equity interest in the subsidiary. SPN Resources then effectively sold 66 2/3% of its outstanding membership interests. These two transactions generated cash proceeds of approximately $167.2 million and resulted in a pre-tax gain of approximately $37.1 million in 2008. SPN Resources’ operations constituted substantially all of the Company’s oil and gas segment. Subsequent to March 14, 2008, the Company accounts for its remaining 33 1/3% interest in SPN Resources using the equity-method. The results of SPN Resources’ operations through March 14, 2008 were consolidated.
In the third quarter of 2007, the Company sold the assets of a non-core drilling products and services business for approximately $16.3 million in cash and $2.0 million in an interest-bearing note receivable. As certain conditions were met during the year ended December 31, 2008, the Company received cash of approximately $6.0 million, which resulted in an additional pre-tax gain on the sale of the business of approximately $3.3 million.
The Company also sold the assets of its field management division in 2007 for approximately $1.8 million in cash. As certain conditions were met during the year ended December 31, 2008 in conjunction with the sale of this division, the Company received cash of $0.5 million, all of which resulted in an additional pre-tax gain on the sale of the business.
(13) Profit Sharing and Retirement Plans
The Company maintains a defined contribution profit sharing plan for employees who have satisfied minimum service requirements. Employees may contribute up to 75% of their earnings to the plans subject to the annual dollar limitations imposed by the Internal Revenue Service. The Company may provide a discretionary match, not to exceed 5% of an employee’s salary. The Company made contributions of approximately $3.3 million, $3.8 million and $4.0 million in 2010, 2009 and 2008, respectively.
The Company has a non-qualified deferred compensation plan which allows certain highly compensated employees the option to defer up to 75% of their base salary, up to 100% of their bonus, and up to 100% of the cash portion of their performance share unit compensation to the plan. Payments are made to participants based on their annual enrollment elections and plan balances. Participants earn a return on their deferred compensation that is based on hypothetical investments in certain mutual funds. Changes in market value of these hypothetical participant investments are reflected as an adjustment to the deferred compensation liability of the Company with an offset to compensation expense (see note 18). At December 31, 2010 and 2009, the liability of the Company to the participants was approximately $14.2 million and $15.8 million, respectively, and is recorded in other long-term liabilities, which reflects the accumulated participant deferrals and earnings (losses) as of that date. Additionally at December 31, 2010, the Company had $3.0 million in accounts payable in anticipation of pending payments. For the years ended December 31, 2010, 2009 and 2008, the Company recorded compensation expense of $1.8 million, $2.8 million and ($2.8) million, respectively, related to the earnings and losses of the deferred compensation plan liability. The Company makes contributions that approximate the participant deferrals into various investments, principally life insurance that is invested in mutual funds similar to the participants’ hypothetical investment elections. Changes in market value of the investments and life insurance are reflected as adjustments to the deferred compensation plan asset with an offset to other income (expense). At December 31, 2010 and 2009, the deferred contribution plan asset was approximately $10.8 million and $12.4 million, respectively, and is recorded in intangible and other long-term assets. For the years ended December 31, 2010, 2009 and 2008, the Company
recorded other income (expense) of $0.8 million, $0.6 million and ($4.0) million, respectively, related to the earnings and losses of the deferred compensation plan assets.
The Company also has a supplemental executive retirement plan (SERP). The SERP provides retirement benefits to the Company’s executive officers and certain other designated key employees. The SERP is an unfunded, non-qualified defined contribution retirement plan, and all contributions under the plan are unfunded credits to a notional account maintained for each participant. Under the SERP, the Company will generally make annual contributions to a retirement account based on age and years of service. During 2010 and 2009, the participants in the plan received contributions ranging from 5% to 35% of salary and annual cash bonus, which totaled approximately $5.5 million and $2.2 million, respectively. The Company may also make discretionary contributions to a participant’s retirement account. In 2010, the Company made a discretionary contribution to the account of its former chief operating officer in the amount of $4.7 million as part of its executive management transition. Also in 2008, the Company made a discretionary contribution to the account of its former chief executive officer in the amount of $10 million. The Company recorded $5.6 million, $2.1 million and $11.3 million of compensation expense in general and administrative expenses for the years ended December 31, 2010, 2009 and 2008, respectively, inclusive of discretionary contributions.
(14) Segment Information
Business Segments
During 2009, the Company renamed two of its segments in order to more accurately describe the markets and customers served by the businesses operating in each segment. The content of these segments has not changed, exclusive of the acquisitions of Superior Completion Services, Hallin and the Bullwinkle platform. The Company currently has three reportable segments: subsea and well enhancement (formerly well intervention), drilling products and services (formerly rental tools), and marine. The subsea and well enhancement segment provides production-related services used to enhance, extend and maintain oil and gas production, which include integrated subsea services and engineering services, mechanical wireline, hydraulic workover and snubbing, well control, coiled tubing, electric line, pumping and stimulation and wellbore evaluation services; well plug and abandonment services; stimulation and sand control equipment and services; and other oilfield services used to support drilling and production operations. The subsea and well enhancement segment also includes production handling arrangements, as well as the production and sale of oil and gas. The drilling products and services segment rents and sells stabilizers, drill pipe, tubulars and specialized equipment for use with onshore and offshore oil and gas well drilling, completion, production and workover activities. It also provides on-site accommodations and bolting and machining services. The marine segment operates liftboats for production service activities, as well as oil and gas production facility maintenance, construction operations and platform removals. During the year ended December 31, 2008, the Company sold 75% of its interest in SPN Resources. SPN Resources’ operations constituted substantially all the oil and gas segment. Oil and gas eliminations represent products and services provided to the oil and gas segment by the Company’s three other segments. Certain previously reported amounts have been reclassified to conform to the presentation in the current period.
The accounting policies of the reportable segments are the same as those described in note 1 of these notes to the consolidated financial statements. The Company evaluates the performance of its operating segments based on operating profits or losses. Segment revenues reflect direct sales of products and services for that segment, and each segment records direct expenses related to its employees and its operations. Identifiable assets are primarily those assets directly used in the operations of each segment.
Summarized financial information concerning the Company’s segments as of December 31, 2010, 2009 and 2008 and for the years then ended is shown in the following tables (in thousands):
Geographic Segments
The Company attributes revenue to various countries based on the location where services are performed or the destination of the drilling products or equipment sold or leased. Long-lived assets consist primarily of property, plant, and equipment and are attributed to various countries based on the physical location of the asset at a given fiscal year end. The Company’s information by geographic area is as follows (amounts in thousands):
(15) Guarantee
As part of SPN Resources’ acquisition of its oil and gas properties, the Company guaranteed SPN Resources’ performance of its decommissioning liabilities. In accordance with authoritative guidance related to guarantees, the Company has assigned an estimated value of $2.6 million and $2.7 million at December 31, 2010 and 2009, respectively, related to decommissioning performance guarantees, which is reflected in other long-term liabilities. The Company believes that the likelihood of being required to perform these guarantees is remote. In the unlikely event that SPN Resources defaults on the decommissioning liabilities existing at the closing date, the total maximum potential obligation under these guarantees is estimated to be approximately $110.2 million, net of the contractual right to receive payments from third parties, which is approximately $24.6 million, as of December 31, 2010. The total maximum potential obligation will decrease over time as the underlying obligations are fulfilled by SPN Resources.
(16) Commitments and Contingencies
The Company leases many of its office, service and assembly facilities under operating leases. In addition, the Company also leases certain assets used in providing services under operating leases. The leases expire at various dates over an extended period of time. Total rent expense was approximately $15.1 million, $12.0 million and $10.3 million in 2010, 2009 and 2008, respectively. Future minimum lease payments under non-cancelable leases for the five years ending December 31, 2011 through 2015 and thereafter are as follows: $20.5 million, $15.8 million, $13.2 million, $12.0 million, $9.7 million and $38.6 million, respectively.
Due to the nature of the Company’s business, the Company is involved, from time to time, in routine litigation or subject to disputes or claims regarding our business activities. Legal costs related to these matters are expensed as incurred. In management’s opinion, none of the pending litigation, disputes or claims will have a material adverse effect on the Company’s financial condition, results of operations or liquidity.
(17)
Interim Financial Information (Unaudited)
The following is a summary of consolidated interim financial information for the years ended December 31, 2010 and 2009 (amounts in thousands, except per share data).
(18) Fair Value Measurements
The Company follows authoritative guidance for fair value measurements relating to financial and nonfinancial assets and liabilities, including presentation of required disclosures herein. This guidance establishes a fair value framework requiring the categorization of assets and liabilities into three levels based upon the assumptions (inputs) used to price the assets and liabilities. Level 1 provides the most reliable measure of fair value, whereas Level 3 generally requires significant management judgment. The three levels are defined as follows:
Level 1: Unadjusted quoted prices in active markets for identical assets and liabilities.
Level 2: Observable inputs other than those included in Level 1 such as quoted prices for similar assets and liabilities in active markets; quoted prices for identical assets or liabilities in inactive markets or model-derived valuations or other inputs that can be corroborated by observable market data.
Level 3: Unobservable inputs reflecting management’s own assumptions about the inputs used in pricing the asset or liability.
The following table provides a summary of the financial assets and liabilities measured at fair value on a recurring basis at December 31, 2010 and December 31, 2009 (in thousands):
The Company’s non-qualified deferred compensation plan allows officers and highly compensated employees to defer receipt of a portion of their compensation and contribute such amounts to one or more hypothetical investment funds (see note 13). The Company entered into a separate trust agreement, subject to general creditors, to segregate the assets of the plan and it reports the accounts of the trust in its consolidated financial statements. These investments are reported at fair value based on unadjusted quoted prices in active markets for identifiable assets and observable inputs for similar assets and liabilities, which represent Levels 1 and 2, respectively in the fair value hierarchy. The realized and unrealized holding gains and losses related to non-qualified deferred compensation assets are recorded as other income (expense). The realized and unrealized holding gains and losses related to non-qualified deferred compensation liabilities are recorded in general and administrative expenses.
In March 2010, the Company entered into an interest rate swap agreement for a notional amount of $150 million, whereby the Company is entitled to receive semi-annual interest payments at a fixed rate of 6 7/8% per annum and is obligated to make quarterly interest payments at a floating rate, which is adjusted every 90 days, based on LIBOR plus a fixed margin. The Company entered into the interest rate swap in an effort to achieve a more balanced debt
portfolio. The swap agreement, scheduled to terminate on June 1, 2014, is designated as a fair value hedge of a portion of the 6 7/8% unsecured senior notes, as the derivative has been tested to be highly effective in offsetting changes in the fair value of the underlying note. As this derivative is classified as a fair value hedge, the changes in the fair value of the derivative are offset against the changes in the fair value of the underlying note in interest expense, net (see note 19).
In 2009, the Company adopted the authoritative guidance regarding non-financial assets and non-financial liabilities that are remeasured at fair value on a non-recurring basis. In accordance with this guidance, long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. During the year ended December 31, 2010, the Company wrote off approximately $32.0 million of long-lived liftboat components primarily related to the two partially completed 265-foot class liftboats. Approximately $9.1 million of remaining long-lived assets associated with these liftboats was reclassified to intangible and other long term assets since these components can be used in the future on other liftboats. During the year ended December 31, 2009, due to continued decline in demand for services in the domestic land market, the Company identified impairments of certain long-lived assets of approximately $212.5 million (see note 3). Additionally, during 2009, the Company recorded a $36.5 million reduction in the value of its equity-method investment in BOG. In April 2009, BOG defaulted under its loan agreements due primarily to the impact of pipeline curtailments from Hurricanes Gustav and Ike in 2008 and the decline of natural gas and oil prices. As a result of continued negative BOG operating results, lack of viable interested buyers and unsuccessful attempts to renegotiate the terms and conditions of its loan agreements with lenders on terms that would preserve the Company’s investment, the Company wrote off the remaining carrying value of its investment in BOG (see note 7).
The following table reflects the fair value measurements used in testing the impairment of long-lived assets and equity-method investments during the years ended December 31, 2010 and 2009 (in thousands):
The Company manages its debt portfolio by targeting an overall desired position of fixed and floating rates and may employ interest rate swaps from time to time to achieve its goal. The Company does not use derivative financial instruments for trading or speculative purposes.
In March 2010, the Company entered into an interest rate swap agreement for a notional amount of $150 million related to its fixed rate debt maturing in 2014. This transaction was designated as a fair value hedge since the swap hedges against the change in fair value of fixed rate debt resulting from changes in interest rates. The Company recorded a derivative asset of $0.2 million within intangible and other long-term assets in the consolidated balance sheet as of December 31, 2010. The change in fair value of the interest rate swap is included in the adjustments to reconcile net income to net cash provided by operating activities in the consolidated statements of cash flows.
The location and effect of the derivative instrument on the consolidated statements of operations for the year ended December 31, 2010, presented on a pre-tax basis, is as follows (in thousands):
For the year ended December 31, 2010, approximately $0.2 million of interest income was related to the ineffectiveness associated with this fair value hedge. Hedge ineffectiveness represents the difference between the changes in fair value of the derivative instruments and the changes in fair value of the fixed rate debt attributable to changes in the benchmark interest rate.
This interest rate swap exposes the Company to credit risk to the extent that the counterparty may be unable to meet the terms of agreement. The counterparty to this agreement is a major financial institution which has an investment grade credit rating and is considered “well-capitalized” under applicable regulatory capital adequacy guidelines. Should the counterparty to this interest rate swap agreement fail to perform according to the terms of the contract, the Company would be required to pay interest at the stated rate of 6 7/8% related to its $300 million of unsecured senior notes with a maturity date of 2014.
(20) Supplementary Oil and Natural Gas Disclosures (Unaudited)
On January 31, 2010, Wild Well acquired 100% ownership of Shell Offshore Inc.’s Gulf of Mexico Bullwinkle platform and its related assets, including 29 wells, and assumed the decommissioning obligation for such assets. Immediately after Wild Well acquired these assets, it conveyed an undivided 49% interest in these assets and the related well plugging and abandonment obligations to Dynamic Offshore, which operates these assets (see note 4). The Company also has an interest in oil and gas operations through its equity-method investments in SPN Resources and DBH (see note 7). The Company’s equity-method investments in SPN Resources and DBH, as well as its acquisition of the Bullwinkle platform and its related assets, provide the Company additional opportunities for our subsea and well enhancement, decommissioning and platform management services.
In January 2010, the Financial Accounting Standards Board issued an update to the authoritative guidance related to oil and gas reserve estimation and disclosures that expands the definition of oil- and gas-producing activities and requires disclosures of reserve quantities and standardized measure of cash flows for equity-method investments that have significant oil- and gas-producing activities.
The Company’s December 31, 2010 estimates of proved reserves are based on reserve reports prepared by DeGolyer and MacNaughton and Netherland, Sewell & Associates, Inc., independent petroleum engineers. Users of this information should be aware that the process of estimating quantities of “proved”, “proved developed” and “proved undeveloped” natural gas and crude oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. This data may also change substantially over time as a result of multiple factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures. Proved reserves are estimated quantities of natural gas, crude oil and condensate that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing
economic and operating conditions. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for completion.
Oil and Natural Gas Reserves
The following table sets forth the Company’s net proved reserves, including the changes therein, and proved developed reserves:
Costs Incurred in Oil and Natural Gas Activities
The following table displays certain information regarding the costs incurred associated with finding, acquiring and developing the Company’s proved oil and natural gas reserves for the year ended December 31, 2010 and 2009 (in thousands).
Capitalized costs for oil and gas producing activities consist of the following (in thousands):
Productive Wells Summary
The following table presents the Company’s ownership of productive oil and natural gas wells as of December 31, 2010. Productive wells consist of producing wells and wells capable of production. In the table, “gross” refers to the total wells in which the Company owns an interest and “net” refers to the sum of fractional interests owned in gross wells.
Acreage
The following table sets forth information as of December 31, 2010 relating to acreage held by the Company. Developed acreage is assigned to productive wells.
Drilling Activity
The following table shows the Company’s drilling activity for the years ended December 31, 2010 and 2009. The Company did not engage in any drilling activity related to its ownership of the Bullwinkle platform and its related assets during the year ended December 31, 2010. In the table, “gross” refers to the total wells in which the Company has a working interest and “net” refers to the gross wells multiplied by the Company’s working interest in these wells. Well activity refers to the number of wells completed during a fiscal year, regardless of when drilling first commenced.
Results of Operations
The following table sets forth the Company’s results of operations for producing activities:
All of the Company’s consolidated oil and gas operations, as well as its share of equity-method investments are in the Gulf of Mexico. In 2010, the Company’s consolidated entities’ average sales prices were $77.04 per barrel of oil and $5.00 per mcf of gas, with an average production cost of $19.99 per barrel of oil equivalent. The Company’s share of equity-method investments average sales prices were $79.21 per barrel of oil and $4.78 per mcf of gas in 2010 and $59.28 per barrel of oil and $4.22 per mcf of gas in 2009. Average production costs were $25.35 and $25.68 per barrel of oil equivalent in the years ended December 31, 2010 and 2009, respectively.
Standardized Measure of Discounted Future Net Cash Flows Relating to Reserves
The following information has been developed utilizing procedures prescribed by authoritative guidance related to oil and gas activities. It may be useful for certain comparative purposes, but should not be solely relied upon in evaluating the Company or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the standardized measure of discounted future net cash flows be viewed as representative of the current value of the Company.
The Company believes that the following factors should be taken into account in reviewing the following information: (1) future costs and selling prices will differ from those required to be used in these calculations; (2) due to future market conditions and governmental regulations, actual rates of production achieved in future years may vary significantly from the rate of production assumed in the calculations; (3) selection of a 10% discount rate is arbitrary and may not be reasonable as a measure of the relative risk inherent in realizing future net oil and gas revenues; and (4) future net revenues may be subject to different rates of income taxation.
Under the standardized measure, future cash inflows were estimated by applying twelve month average oil and natural gas prices adjusted for differentials. Future cash inflows were reduced by estimated future development, abandonment and production costs based on period-end costs in order to arrive at net cash flow before tax. Future income tax expense has been computed by applying period-end statutory tax rates to aggregate future net cash flows, reduced by the tax basis of the properties involved and tax carryforwards. Use of a 10% discount rate is required by authoritative guidance related to oil and gas activities.
The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves at December 31, 2010 and 2009 is as follows (in thousands):
A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved oil and natural gas reserves for the years ended December 31, 2010 and 2009 is as follows (in thousands):
The December 31, 2010 amount was estimated by DeGolyer and MacNaughton and Netherland, Sewell & Associates, Inc. using a twelve month average WTI Cushing price of $79.40 per barrel (bbl), and a Henry Hub gas price of $4.38 per million British Thermal Units, and price differentials. The December 31, 2009 amount was estimated by DeGolyer and MacNaughton and Netherland, Sewell & Associates, Inc. using a twelve month average WTI Cushing price of $61.04 per barrel (bbl), and a Henry Hub gas price of $3.86 per million British Thermal Units, and price differentials.
In accordance with authoritative guidance, the Company has evaluated and disclosed all material subsequent events that occurred after the balance sheet date, but before financial statements were issued.
In January 2010, the Financial Accounting Standards Board issued Accounting Standards Update 2010-03 (ASU 2010-03), “Oil and Gas Reserve Estimation and Disclosures.” The update provides an amendment to Accounting Standards Codification 932 (ASC 932), “Extractive Activities - Oil and Gas,” that expands the definition of oil- and gas-producing activities and requires disclosures of reserve quantities and standardized measure of cash flows for equity-method investments that have significant oil- and gas-producing activities. ASU 2010-03 is effective for annual reporting periods ending on or after December 31, 2009. ASU 2010-03 allows an entity that becomes subject to the disclosure requirements of ASC 932 due to the change to the definition of significant oil- and gas-producing activities to apply the disclosure provisions of ASC 932 in annual periods beginning after December 31, 2009. As such, the Company included the disclosures required by ASU 2010-03 for the annual reporting period ended December 31, 2010.
On January 1, 2010, the Company adopted Accounting Standards Codification 810-10 (ASC 810-10), “Amendments to FASB Interpretation No. 46(R), Consolidation of Variable Interest Entities,” for determining whether an entity is a variable interest entity (VIE) and requires an enterprise to perform an analysis to determine whether the enterprise’s variable interest or interests give it a controlling financial interest in a VIE. ASC 810-10 also requires ongoing assessments of whether an enterprise is the primary beneficiary of a VIE, requires enhanced disclosures and eliminates the scope exclusion for qualifying special-purpose entities. The adoption of ASC 810-10 did not have a significant impact on the Company’s results of operations or financial position.
On January 1, 2010, the Company adopted Accounting Standards Update 2010-06 (ASU 2010-06), “Improving Disclosures about Fair Value Measurements.” The update provides an amendment to ASC 820-10, “Fair Value Measurements and Disclosures,” requiring additional disclosures of significant transfers between Level 1 and Level 2 within the fair value hierarchy as well as information about purchases, sales, issuances and settlements using unobservable inputs (Level 3). ASU 2010-06 is effective for interim and annual reporting periods beginning after December 15, 2009 for new disclosures and clarifications of existing disclosures, except for disclosures about purchases, sales, issuances and settlements in the rollforward of activity in the Level 3 fair value measurements, which are effective for fiscal years beginning after December 15, 2010. The adoption of ASU 2010-06 did not have a significant impact on the Company’s results of operations or financial position.
In October 2009, the Financial Accounting Standards Board issued Accounting Standards Update 2009-13 (ASU 2009-13), “Multiple-Deliverable Revenue Arrangements.” The new standard changes the requirements for establishing separate units of accounting in a multiple element arrangement and requires the allocation of arrangement consideration to each deliverable based on the relative selling price. The selling price for each deliverable is based on vendor-specific objective evidence (VSOE) if available, third-party evidence if VSOE is not available, or estimated selling price if neither VSOE or third-party evidence is available. ASU 2009-13 is effective for revenue arrangements entered into in fiscal years beginning on or after June 15, 2010. The Company does not expect that the adoption of ASU 2009-13 will have a significant impact on the results of operations and financial position.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Item 9A. Controls and Procedures
Our management has established and maintains a system of disclosure controls and procedures to provide reasonable assurances that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is appropriately recorded, processed, summarized and reported within the time periods specified by the Securities and Exchange Commission (SEC). In addition, the disclosure controls and procedures ensure that information required to be disclosed, accumulated and communicated to management, including our Chief Executive Officer (CEO) and Chief Financial Officer (CFO), allow timely decisions regarding required disclosure. An evaluation was carried out, under the supervision and with the participation of our management, including our CEO and CFO, of the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-14(e) and Rule 15d-15(e) of the Securities Exchange Act of 1934) as of the end of the period covered by this report. Based on that evaluation, our principal executive and financial officers have concluded that our disclosure controls and procedures as of December 31, 2010 were effective to provide reasonable assurance that information required to be disclosed by us in reports we file with the SEC is recorded, processed, summarized and reported within the time periods required by the SEC’s rules and forms, and is accumulated and communicated to management, including our CEO and CFO, as appropriate, to allow timely decisions regarding disclosures. Management’s report and the independent registered public accounting firm’s attestation report are included herein under the captions “Management’s Annual Report on Internal Control over Financial Reporting” and “Report of Independent Registered Public Accounting Firm,” and are incorporated by reference.
There has been no change in our internal control over financial reporting during the three months ended December 31, 2010, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Management’s Annual Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over our financial reporting, and for performing an assessment of the effectiveness of internal control over our financial reporting as of December 31, 2010. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Our system of internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on the financial statements. Management recognizes that there are inherent limitations in the effectiveness of any internal control over financial reporting, including the possibility of human error and the circumvention or overriding of internal control. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may be inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Our management, including our principal executive officer and principal financial officer, performed an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2010 based upon criteria in “Internal Control - Integrated Framework,” issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this assessment, our management determined that as of December 31, 2010, our internal control over financial reporting was effective based on those criteria.
Our internal control over financial reporting as of December 31, 2010 has been audited by KPMG, LLP, an independent registered public accounting firm, as stated in their report which appears herein.
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Superior Energy Services, Inc.:
We have audited Superior Energy Services, Inc.’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Superior Energy Services, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on Superior Energy Services, Inc.’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Superior Energy Services, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Superior Energy Services, Inc. and subsidiaries as of December 31, 2010 and 2009, and the related consolidated statements of operations, changes in stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2010, and our report dated February 25, 2011 expressed an unqualified opinion on those consolidated financial statements.
New Orleans, Louisiana
February 25, 2011
Item 9B.
Item 9B. Other Information
None.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance
Information relating to our executive officers is included in Part I, Item 4A, and is incorporated herein by reference. Information relating to our Code of Business Ethics and Conduct that applies to all of our directors, officers and employees, including our senior financial officers, is included in Part I, Item 1, and is incorporated herein by reference. Other information required by this item will be contained in our definitive proxy statement to be filed pursuant to Regulation 14A and is incorporated herein by reference.
Item 11.
Item 11. Executive Compensation
Information required by this item will be contained in our definitive proxy statement to be filed pursuant to Regulation 14A and is incorporated herein by reference.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Information required by this item will be contained in our definitive proxy statement to be filed pursuant to Regulation 14A and is incorporated herein by reference.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Information required by this item will be contained in our definitive proxy statement to be filed pursuant to Regulation 14A and is incorporated herein by reference.
Item 14.
Item 14. Principal Accounting Fees and Services
Information required by this item will be contained in our definitive proxy statement to be filed pursuant to Regulation 14A and is incorporated herein by reference.
PART IV
Item 15.
Item 15. Exhibits, Financial Statement Schedules
(3) Exhibits
Exhibit No.
Description
101.CAL**
XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB**
XBRL Taxonomy Extension Label Linkbase Document
101.PRE**
XBRL Taxonomy Extension Presentation Linkbase Document
*
Filed herein
**
Furnished with this Form 10-K
^
Management contract or compensatory plan or arrangement
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
Schedule
SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Schedule II
Valuation and Qualifying Accounts
Years Ended December 31, 2010, 2009 and 2008
(in thousands)