UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

þ		Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

o		Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Commission File No. 001-34037

SUPERIOR ENERGY SERVICES, INC.

Delaware		75-2379388
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
601 Poydras, Suite 2400
New Orleans, LA		70130
(Address of principal executive offices)		(Zip Code)
Registrant’s telephone number: (504) 587-7374

Securities registered pursuant to Section 12(b) of the Act:

Title of each class:		Name of each exchange on which registered:
Common Stock, $.001 Par Value		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:
None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes o No þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer þ		Accelerated filer o		Non-accelerated o		Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

The aggregate market value of the voting stock held by non-affiliates of the registrant at June 30, 2009 based on the closing price on the New York Stock Exchange on that date was $1,343,725,000.

The number of shares of the registrant’s common stock outstanding on February 18, 2010 was 78,530,517.

Certain information called for by Items 10, 11, 12, 13 and 14 of Part III is incorporated by reference from the registrant’s definitive proxy statement to be filed pursuant to Regulation 14A.

 

 

SUPERIOR ENERGY SERVICES, INC.
Annual Report on Form 10-K for
the Fiscal Year Ended December 31, 2009

TABLE OF CONTENTS

		Page
PART I
Item 1. Business			1
Item 1A. Risk Factors			6
Item 1B. Unresolved Staff Comments			13
Item 2. Properties			13
Item 3. Legal Proceedings			13
Item 4. Submission of Matters to a Vote of Security Holders			13
Item 4A. Executive Officers of Registrant			14
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities			15
Item 6. Selected Financial Data			17
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			18
Item 7A. Quantitative and Qualitative Disclosures about Market Risk			30
Item 8. Financial Statements and Supplementary Data			32
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			70
Item 9A. Controls and Procedures			70
Item 9B. Other Information			73
PART III
Item 10. Directors, Executive Officers and Corporate Governance			73
Item 11. Executive Compensation			73
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			73
Item 13. Certain Relationships and Related Transactions, and Director Independence			73
Item 14. Principal Accounting Fees and Services			73
PART IV
Item 15. Exhibits, Financial Statement Schedules			74
EX-10.11
EX-10.21
EX-21.1
EX-23.1
EX-23.2
EX-23.3
EX-31.1
EX-31.2
EX-32.1
EX-32.2

FORWARD-LOOKING STATEMENTS

We have included or incorporated by reference in this Annual Report on Form 10-K, and from time to time our management may make statements that may constitute “forward-looking statements” within the meaning of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Forward-looking statements are not historical facts but instead represent only our current belief regarding future events, many of which, by their nature, are inherently uncertain and outside our control. The forward-looking statements contained in this Annual Report on Form 10-K are based on information as of the date of this report. Many of these forward-looking statements relate to future industry trends, actions, future performance or results of current and anticipated initiatives and the outcome of contingencies and other uncertainties that may have a significant impact on our business, future operating results and liquidity. We try, whenever possible, to identify these statements by using words such as “anticipate,” “believe,” “should,” “estimate,” “expect,” “plan,” “project” and similar expressions. We caution you that these statements are only predictions and are not guarantees of future performance. These forward-looking statements and our actual results, developments and business are subject to certain risks and uncertainties that could cause actual results and events to differ materially from those anticipated by these statements. By identifying these statements for you in this manner, we are alerting you to the possibility that our actual results may differ, possibly materially, from the anticipated results indicated in these forward-looking statements. Important factors that could cause actual results to differ from those in the forward-looking statements include, among others, those discussed below and under “Risk Factors” in Part I, Item 1A and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7.

PART I

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 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 so that we now have a significant presence in both select domestic land and international markets.

Operations

During 2009, we renamed two of our 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. Our operations are organized into the following business segments:

Subsea and Well Enhancement (formerly Well Intervention). 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 coiled tubing, electric line, pumping and stimulation, gas lift, well control, snubbing, recompletion, engineering and well evaluation, offshore oil and gas tank and vessel cleaning, decommissioning, plug and abandonment and mechanical wireline. We believe we are the leading provider of wireline services in the Gulf of Mexico with approximately 142 offshore wireline units, 24 offshore electric line units, seven offshore coiled tubing units and 10 dedicated liftboats configured specifically for wireline services. We also own and operate 43 land wireline units, 68 land electric line units and 32 land coiled tubing units. Additionally, we own two derrick barges each equipped with an 880 metric ton crane. We also manufacture and sell specialized drilling rig instrumentation equipment.

In January 2010, we acquired Hallin Marine Subsea Plc (Hallin), an international provider of integrated subsea services and engineering solutions, focused on installing, maintaining and extending the life of subsea wells. The acquisition of Hallin provides us the opportunity to enhance our position in the subsea and well enhancement market through existing subsea assets (remotely operated vehicles, saturation diving systems and chartered vessels) and a newbuild vessel program.

Drilling Products and Services (formerly Rental Tools). 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, and Wyoming. Our drilling products and services segment conducts operations in 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 we believe 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 26 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 in the Gulf of Mexico and the Caribbean.

Oil and Gas Operations. On March 14, 2008, we completed the sale of 75% of our interest in SPN Resources, LLC (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. SPN Resources’ operations constituted substantially all of our oil and gas segment. Subsequent to the sale of control of SPN Resources, we account for our remaining interest in SPN Resources using the equity-method within the oil and gas segment (see note 4 to our consolidated financial statements included in Item 8 of this Form 10-K).

Our equity-method investments, SPN Resources and DBH, LLC (DBH), the successor company of Beryl Oil and Gas, LP, as well as our recent acquisition of Bullwinkle platform and related assets from Shell Offshore, LLC, 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. 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%. Sales to Shell accounted for approximately 11% of our total revenue in 2007. 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:

	•		changes in competitive prices;
	•		oil and gas prices and industry perceptions of future prices;
	•		fluctuations in the level of activity by oil and gas producers;
	•		changes in the number of liftboats operating in the Gulf of Mexico;
	•		the ability of oil and gas producers to generate capital;
	•		general economic conditions; and
	•		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 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 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. Although we believe that our reputation for safety and quality service is good, we cannot assure that we will be able to maintain our competitive position.

Potential Liabilities and Insurance

Our operations involve a high degree of operational risk, particularly of personal injury, damage or loss of equipment and environmental accidents. Failure or loss of our equipment could result in property damages, personal injury, environmental pollution and other damages for which we could be liable. Litigation arising from the sinking of a marine vessel or a catastrophic occurrence, such as a fire, explosion or well blowout at a location where our equipment and services are used may result in large claims for damages. We maintain insurance against risks that we believe is consistent in types and amounts with industry standards and is required by our customers. 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:

	•		federal, state and international laws and other regulations relating to the oil and gas industry;
	•		changes in such laws and regulations; and
	•		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. We also cannot predict whether additional laws and regulations will be adopted, 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, 2010, we had approximately 4,800 employees. None of our employees is 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 support the operations conducted by our liftboats from a 3.5-acre maintenance and office facility in New Iberia, Louisiana. We also own certain facilities and lease other office, service and assembly facilities under various operating leases, including a 7-acre office and training facility

located in Houston, Texas. 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 use several patented items in our operations that we believe are important, but not indispensable, to our operations. Although we anticipate seeking patent protection when possible, we rely to a greater 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 adopted 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. 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. There are many factors that affect our business and the results of our operations, many of which are beyond our control. In addition, they may not be the only material risks that we face. 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.

Adverse macroeconomic and business conditions may significantly and negatively affect our results of operations.

Economic conditions in the United States and in foreign markets in which we operate could substantially affect our revenue and profitability. The domestic and global financial crisis, the associated fluctuating oil and gas prices, and the unprecedented levels of disruption and continuing illiquidity 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, as a result of continuing illiquidity in the credit markets, some of our suppliers and customers are facing credit issues and could experience cash flow problems and other financial hardships.

Changes in governmental banking, monetary and fiscal policies to restore liquidity and increase credit availability may not be effective. It is difficult to determine the breadth and duration of the domestic and global financial crisis and the many ways in which it 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 access to borrowing capacity could be affected by the turmoil and uncertainty impacting credit markets generally.

Disruptions in the credit and financial markets have adversely affected financial institutions, inhibited lending and limited access to capital and credit for many companies. Several large financial institutions have either recently failed or been dependent on the assistance of the U.S. federal government to continue to operate as a going concern. Although we believe that the banks participating in our credit facility have adequate capital and resources, we can provide no assurance that all of these 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, it is likely that any such alternatives in the current market would be on terms less favorable than under our existing credit facility terms, 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.

The continued financial crisis in the global economy has led to fluctuating oil and natural gas prices and a lower number of rigs drilling. These conditions may result in continued reductions in capital expenditures by our customers, project cancellations if project economics become unprofitable and shut-in oil and natural gas production. As long as these conditions prevail, we expect reduced pricing and utilization for our products and services, especially in North America.

Demand for the majority 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 have recently been very volatile and are affected by many factors, including the following:

	•		the level of worldwide oil and gas exploration and production;
	•		the cost of exploring for, producing and delivering oil and gas;
	•		demand for energy, which is affected by worldwide economic activity and population growth;
	•		the ability of the Organization of Petroleum Exporting Countries, or OPEC, to set and maintain production levels for oil;
	•		the discovery rate of new oil and gas reserves;
	•		political and economic uncertainty, socio-political unrest and regional instability or hostilities; and
	•		technological advances affecting energy exploration, production and consumption.

Although activity levels in production and development sectors of the oil and gas industry are less immediately affected by changing prices 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:

	•		changes in competitive prices;
	•		fluctuations in the level of activity in major markets;
	•		an increased number of liftboats in the Gulf of Mexico;
	•		general economic conditions; and
	•		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. 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. Although we believe that our reputation for safety and quality service is good, we cannot guarantee that we will be able to maintain our competitive position.

A significant portion of our revenue is derived from our non-United States operations, which exposes us to additional political, economic and other uncertainties.

Our non-United States revenues accounted for approximately 22%, 17% and 19% of our total revenues in 2009, 2008, and 2007, 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:

	•		political, social and economic instability;
	•		potential expropriation, seizure or nationalization of assets;
	•		increased operating costs;
	•		social unrest, acts of terrorism, war or other armed conflict;
	•		renegotiating, cancellation or forced modification of contracts;
	•		import-export quotas;
	•		confiscatory taxation or other adverse tax policies;
	•		currency fluctuations;
	•		restrictions on the repatriation of funds;
	•		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
	•		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:

	•		the awarding of contracts to local contractors;
	•		the employment of local citizens; and
	•		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 and/or total loss by these storms. Damage caused by high winds and turbulent seas could potentially cause us to curtail 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 their development activities due to damage to their platforms, pipelines and other related facilities.

Due to the losses as a consequence of the hurricanes that occurred in the Gulf of Mexico in recent years, we have not been able to obtain insurance coverage comparable with that of prior years, thus putting us at a 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.

We depend on key personnel.

Our success depends to a great degree on the abilities of our key management personnel, particularly our chief executive and operating officers 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. 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. 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%. Shell accounted for approximately 11% of our total revenue in 2007. 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 the contract for a fixed price or a defined scope of work and extra work, which is subject to customer approval, and 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.

In 2009 and 2008, a portion of our revenue was 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:

	•		fires;
	•		explosions, blowouts and cratering;
	•		hurricanes and other extreme weather conditions;
	•		mechanical problems, including pipe failure;
	•		abnormally pressured formations; and
	•		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.

Our liftboats and marine vessels are also subject to operating risks such as catastrophic marine disasters, adverse weather conditions, collisions and navigation errors.

The occurrence of these risks could result in substantial losses due to personal injury, loss of life, damage to or destruction of wells, production facilities or other property or equipment, or damages to the environment. 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. In such actions, there is generally no limitation on our potential liability.

Any litigation arising from a catastrophic occurrence involving our services or equipment could result in large claims for damages. The frequency and severity of such incidents affect our operating costs, insurability and relationships with customers, employees and regulators. Any increase in the frequency or severity of such incidents, or the general level of compensation awards with respect to such incidents, could affect our ability to obtain insurance or projects from oil and gas companies. We maintain several types of insurance to cover liabilities arising

from our services, including onshore and offshore non-marine operations, as well as marine vessel operations. These policies include primary and excess umbrella liability policies with limits of $100 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. Successful claims for which we are not fully insured may adversely affect our working capital and profitability.

The cost of many of the types of insurance coverage maintained by us has increased significantly during recent years and resulted in the retention of additional risk by us, primarily through higher insurance deductibles. 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. Further, due to the losses as a result of hurricanes that occurred in the Gulf of Mexico in recent years, we were not be able to obtain insurance coverage comparable with that of prior years, thus putting us at a greater risk of loss due to severe weather conditions. In addition, costs have significantly increased for windstorm or hurricane coverage which also imposes higher deductibles and limits maximum aggregate recoveries. Any significant uninsured losses could have a material adverse effect on our financial position, results of operations and cash flows.

The occurrence of any of these risks could also subject us to clean-up obligations, regulatory investigation, penalties or suspension of operations. Further, our operations may be materially curtailed, delayed or canceled as a result of numerous factors, including the following:

	•		the presence of unanticipated pressure or irregularities in formations;
	•		equipment failures or accidents;
	•		adverse weather conditions;
	•		compliance with governmental requirements; and
	•		shortages or delays in obtaining equipment or in the delivery of equipment and services.

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:

	•		lack of sufficient executive-level personnel;
	•		increased administrative burden; and
	•		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 you 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 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 conflict 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.

Item 1B. Unresolved Staff Comments

None.

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. Legal Proceedings

We are involved in various legal and other proceedings that are incidental to the conduct of our business. We do not believe that any of these proceedings, if adversely determined, would have a material adverse affect on our financial condition, results of operations or cash flows.

Item 4. Submission of Matters to a Vote of Security Holders

None.

Item 4A. Executive Officers of Registrant

Terence E. Hall, age 64, has served as our Chairman of the Board and Chief Executive Officer and as a Director since December 1995. From December 1995 to November 2004, Mr. Hall also served as our President. Mr. Hall also serves as a member of the Board of Directors for Whitney Holding Corporation since December 2008.

Kenneth L. Blanchard, age 60, has served as our President since November 2004, and as our Chief Operating Officer since June 2002. Mr. Blanchard also served as one of our Executive Vice Presidents from December 1995 to November 2004.

Robert S. Taylor, age 55, 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 52, 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 C. Campbell, age 65, was appointed as one of our Executive Vice Presidents in April 2009. He has 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 41, 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. since May 2006, and previously as a Vice President of this subsidiary and its predecessor company since August 2000. He served as our Director of Investor Relations from April 1997 to February 2000 and was also responsible for integrating our acquisitions during that time.

Charles M. Hardy, age 64, has served as one of our Executive Vice Presidents since January 2008. He has also 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.

James A. Holleman, age 52, has served as one of our Executive Vice Presidents since September 2004. He served as one of our Vice Presidents from July 1999 to September 2004. Mr. Holleman has served as an Executive Vice President since May 2006, and previously as a Vice President since July 1999 of Superior Energy Services, L.L.C. From 1994 until July 1999, he served as the Chief Operating Officer of Cardinal Services, Inc., which we acquired in July 1999 and is the predecessor to Superior Energy Services, L.L.C.

William B. Masters, age 52, 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 54, has served as one of our Executive Vice Presidents since September 2004. Since May 2006, Mr. Young has 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 49, has served as one of our Executive Vice Presidents since January 2008. Prior to joining us, he was employed with Weatherford International, Ltd. from June 1999 to December 2007, most recently serving as Vice President for the Middle East region since January 2007. From September 2005 to December 2007, Mr. Zuber served as Vice President for the Asia Pacific region. From March 2002 to August 2005, he served as General Manager for the Underbalanced Drilling Division for the Middle East and North Africa region.

PART II

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.

		High				Low
2008
First Quarter		$	45.14			$	34.90
Second Quarter			57.25				40.04
Third Quarter			54.42				29.95
Fourth Quarter			30.28				11.64
2009
First Quarter		$	18.37			$	11.52
Second Quarter			24.19				12.97
Third Quarter			22.86				15.49
Fourth Quarter			25.78				20.14

As of February 18, 2010, there were 78,530,517 shares of our common stock outstanding, which were held by 173 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. There was no common stock repurchased and retired during the quarter ended December 31, 2009.

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, 2005 at closing prices on December 31, 2004. 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.

				Years Ended December 31,
				2005					2006					2007					2008					2009
	Superior Energy Services, Inc.			$	137				$	212				$	223				$	103				$	158
	S&P 500 Stock Index			$	105				$	121				$	128				$	81				$	102
	Peer Group			$	152				$	157				$	213				$	82				$	134

NOTES:

	•		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.
	•		The index level for all series was set to $100.00 on December 31, 2004.

Our Self-Determined Peer Group consists of the same peer group of eleven companies whose average stockholder return levels comprise part of the performance criteria established by the Compensation Committee under our long-term incentive compensation program: BJ Services Company, Helix Energy Solutions Group, Inc., Helmerich & Payne, Inc., Oceaneering International, Inc., Oil States International, Inc., Pride International, Inc., RPC, Inc., Seacor Holdings Inc., Smith International, Inc., Tetra Technologies, Inc., and Weatherford International, Ltd.

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.

		Years Ended December 31,
		2009				2008				2007				2006				2005
Revenues		$	1,449,300			$	1,881,124			$	1,572,467			$	1,093,821			$	735,334
Income (loss) from operations			(51,384	)			565,692				465,838				316,889				125,603
Net income (loss)			(102,323	)			351,475				271,558				187,663				67,859
Net income (loss) per share:
Basic			(1.31	)			4.39				3.35				2.35				0.87
Diluted			(1.31	)			4.33				3.30				2.31				0.85
Total assets			2,516,665				2,490,145				2,255,295				1,872,067				1,097,250
Long-term debt, net			848,665				654,199				637,789				622,508				216,596
Decommissioning liabilities, less current portion			—				—				88,158				87,046				107,641
Stockholders’ equity			1,178,045				1,254,273				1,025,666				765,237				524,374

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 and marine segments. In recent years, we have expanded geographically into select domestic land and international market areas. We also own oil and gas properties in the Gulf of Mexico that provide us additional opportunities for our subsea and well enhancement, decommissioning and platform management services.

During 2009, we renamed two of our segments in order to more accurately describe the markets and customers served by the businesses in each segment. The content of these segments has not changed. The financial performance of our various products and services are reported in four operating segments — subsea and well enhancement (formerly well intervention), drilling products and services (formerly rental tools), marine and oil and gas.

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 2009, approximately 59% of this segment’s revenue was derived from work performed in the Gulf of Mexico market area, while approximately 23% of segment revenue was from the domestic land market area and approximately 18% of segment revenue was from international market areas. 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. This segment’s financial performance primarily is a function of changes in volume rather than pricing. In 2009, approximately 40% of segment revenue was derived from the Gulf of Mexico market area, while approximately 25% of segment revenue was from the domestic land market area and approximately 35% of segment revenue was from international market areas. Three rental products and their ancillary equipment — accommodations, drill pipe and stabilization and other downhole equipment — accounted for more than 90% of this segment’s revenue in 2009.

The marine segment is comprised of our 26 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. Our activity levels can be severely impacted by harsh weather, especially 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:

						%								%
		2009				Change				2008				Change				2007
Worldwide Rig Count (1)
U.S.			1,089				-42	%			1,879				6	%			1,768
International (2)			997				-8	%			1,079				7	%			1,005
Commodity Prices (average)
Crude Oil (West Texas Intermediate)		$	62.67				-37	%		$	99.73				38	%		$	72.19
Natural Gas (Henry Hub)		$	4.27				-53	%		$	9.04				4	%		$	8.67

As indicated by the table above, all major activity drivers declined sharply in 2009. The average number of drilling rigs working in the United States — which is more weighted toward natural gas drilling than oil drilling — declined 42%, while the international rig count — which is more weighted toward oil drilling than natural gas drilling — declined 8%. The average price of West Texas Intermediate crude oil decreased 37% from 2008, while the average price of natural gas at Henry Hub declined 53% from 2008.

Factors impacting our 2009 financial performance

The following table compares our revenues generated from major geographic regions for the years ended December 31, 2009 and 2008 (in thousands). We attribute revenue to countries based on the location where services are performed or the destination of the sale of products.

		Revenue
		2009				%				2008				%				Change
Gulf of Mexico		$	804,944				56	%		$	1,024,589				54	%		$	(219,645	)
U.S. Domestic Land			321,127				22	%			539,795				29	%			(218,668	)
International			323,229				22	%			316,740				17	%			6,489
Total		$	1,449,300				100	%		$	1,881,124				100	%		$	(431,824	)

The significant downturn in commodity prices, the drilling rig count and overall industry activity reduced pricing and utilization of our products and services in all segments and geographic markets, especially in North America, where our domestic land revenue decreased 41% to $321.1 million. In this market, we experienced a 42% decrease in revenue from our drilling products and services segment and a 40% decrease in revenue from our subsea and well enhancement segment. Within individual product/service lines, the largest declines in the domestic land market areas were in coiled tubing, cased hole wireline, well control, rentals of accommodations and rentals and sales of stabilizers and related equipment.

Our Gulf of Mexico revenue declined 21% to $804.9 million due to (1) the aforementioned industry downturn; (2) reduced revenue on our large-scale decommissioning project; and , (3) the March 2008 sale of 75% of our interest in SPN Resources, our oil and gas production subsidiary which contributed $55 million in revenue in 2008.

Our international revenue increased 2% to $323.2 million due primarily to a project in Mexico involving one of our 245-ft. class liftboats. International revenue in our subsea and well enhancement segment increased 11% as we started three projects off the coast of Angola and experienced increased demand for emergency well control work in West Africa. This increase was offset by a 10% decrease in revenue from our drilling products and services segment primarily due to a decrease in drill pipe rentals in the North Sea and rentals of stabilization equipment in international markets.

Industry Outlook

The weak industry conditions that prevailed throughout much of 2009 are showing signs of stabilizing. Domestic drilling rig count and oil and natural gas prices have steadily increased towards the end of 2009. However, there is still much uncertainty regarding overall demand for oilfield products and services. As a result, we anticipate utilization for many of our products and services to increase in 2010. Pricing could increase as the year progresses and will depend on utilization of our assets and continued improvement in industry fundamentals.

While the worst of the domestic and global financial crisis appears to be over, the U.S. economy has yet to show strong enough growth to spur significant increases in industrial demand for hydrocarbons, particularly natural gas, which is a major driver of domestic oilfield activity. Low industrial demand coupled with persistently high supplies of domestic natural gas make it difficult to forecast the pace of increases in our activity. In addition, changes in demand for our products and services tend to lag changes in the drilling rig count.

Our response to market conditions has been to reduce headcount in certain geographic markets without impairing our ability to participate in an increase in demand once industry conditions improve, move assets to other geographic markets, consolidate certain facilities and reduce operating costs. In addition, we continue to pursue new growth initiatives through acquisitions. In January 2010, we acquired both Hallin Marine Subsea International Plc, an international provider of integrated subsea services and engineering solutions, and a 51% interest in the Gulf of Mexico-based Bullwinkle platform and related oil and gas assets from Shell Offshore Inc., which provides us an opportunity to use our services to produce the field’s remaining oil and gas reserves, plug and abandon the property’s 29 wells and decommission the platform once the field reaches the end of its economic life. The Bullwinkle platform will also generate revenue from production handling agreements which will be recorded in our subsea and well enhancement segment.

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 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 and self insurance. 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 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 is primarily due to the decline in demand for services in the domestic land markets. During the fourth quarter of 2009, the domestic land markets 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 Accounting Standard Codification 350-10 (ASC 350-10), “Intangibles — Goodwill and Other.” ASC 350-10 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, 2009, we concluded that no goodwill impairment loss was required. Even though we recognized a $212.5 million impairment of long-lived assets within the subsea and well enhancement segment during 2009, the estimated future cash flows, used in the fair value calculation of this segment, from our Gulf of Mexico and international markets more than offset the depressed land markets.

If, among other factors, (1) our market capitalization declines or remains below our stockholders’ equity, (2) the fair value of our reporting units decline, or (3) the adverse impacts of economic or competitive factors are worse than anticipated, we could conclude in future periods that impairment losses are required in order to reduce the carrying value of our goodwill and long-lived assets. Depending on the severity of the changes in the key factors underlying the valuation of our reporting units, such losses could be significant.

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 collectibility 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. 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. We estimate the percentage complete utilizing costs incurred as a percentage of total estimated costs.

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).

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 Accounting Standards Codification 605-35, “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.

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.

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 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. 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.

		Revenue												Cost of Services, Rentals and Sales
		2009				2008				Change				2009				%				2008				%				Change
Subsea and Well Enhancement		$	919,335			$	1,155,221			$	(235,886	)		$	616,116				67	%		$	633,127				55	%		$	(17,011	)
Drilling Products and Services			426,876				550,939				(124,063	)			143,802				34	%			178,563				32	%			(34,761	)
Marine			103,089				121,104				(18,015	)			64,116				62	%			74,830				62	%			(10,714	)
Oil and Gas			—				55,072				(55,072	)			—				—				12,986				24	%			(12,986	)
Less: Oil and Gas Elim			—				(1,212	)			1,212				—				—				(1,212	)			—				1,212
Total		$	1,449,300			$	1,881,124			$	(431,824	)		$	824,034				57	%		$	898,294				48	%		$	(74,260	)

The following discussion analyzes our results on a segment basis.

Subsea and Well Enhancement Segment (formerly Well Intervention 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 is recognized in the period in which revisions are identified. Revenue from international markets 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 (formerly Rental Tools)

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, and rentals of our drill pipe and stabilization equipment in international markets. Drilling products and services revenue in our domestic land markets 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 markets 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-ft. 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-ft. class liftboats were removed from service following damage to one of the vessels during Hurricane Ida. One vessel is expected to return to service by the second quarter of 2010 and the other in the third quarter of 2010. Additionally, we sold four liftboats from our 145 – 155-ft. 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-ft. 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 is primarily due to the decline in demand for services in the domestic land markets. During the fourth quarter of 2009, the domestic land markets 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.

Comparison of the Results of Operations for the Years Ended December 31, 2008 and 2007

For the year ended December 31, 2008, our revenue was $1,881.1 million, resulting in net income of $351.5 million or $4.33 diluted earnings per share. The results included a pre-tax gain of $40.9 million from the sale of businesses. For the year ended December 31, 2007, revenue was $1,572.5 million, and net income was $271.6 million or $3.30 diluted earnings per share. Net income for the year ended December 31, 2007 included a pre-tax gain of $7.5 million from the sale of a non-core drilling products and services business. Net income for the years ended December 31, 2008 and 2007 include additional non-cash interest expense of $16.3 million and $15.2 million, respectively, as we retrospectively adopted Accounting Standards Codification 470-20, “Debt with Conversion and Other Options” that required the proceeds from the issuance of our 1.50% senior exchangeable notes to be allocated between a liability component 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. Revenue in the subsea and well enhancement segment was higher primarily as a result of an increase in engineering and project management services associated with a large-scale platform decommissioning project. Revenue in the drilling products and services segment was higher as a result of increased production-related projects and drilling activity worldwide, recent acquisitions and continued expansion of our drilling products and services business. Both revenue and income from operations decreased in our marine segment due to lower utilization and dayrates. 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, 2008 and 2007 (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.

		Revenue												Cost of Services, Rentals and Sales
		2008				2007				Change				2008				%				2007				%				Change
Subsea and Well Enhancement		$	1,155,221			$	761,015			$	394,206			$	633,127				55	%		$	419,818				55	%		$	213,309
Drilling Products and Services			550,939				496,290				54,649				178,563				32	%			156,731				32	%			21,832
Marine			121,104				127,898				(6,794	)			74,830				62	%			60,432				47	%			14,398
Oil and Gas			55,072				192,700				(137,628	)			12,986				24	%			66,580				35	%			(53,594	)
Less: Oil and Gas Elim			(1,212	)			(5,436	)			4,224				(1,212	)			—				(5,436	)			—				4,224
Total		$	1,881,124			$	1,572,467			$	308,657			$	898,294				48	%		$	698,125				44	%		$	200,169

The following discussion analyzes our results on a segment basis.

Subsea and Well Enhancement Segment (formerly Well Intervention)

Revenue for our subsea and well enhancement segment was $1,155.2 million for the year ended December 31, 2008, as compared to $761.0 million for 2007. Cost of services remained constant at 55% of segment revenue in 2008 and 2007. Our revenue increased 53% as the result of our performance on a large-scale platform decommissioning project. We also experienced an increase in revenue from a full year of expansion of wireline and snubbing services in Continental Europe. Additionally, revenue from coiled tubing services increased approximately 37% mainly from additional activity and the addition of new equipment in domestic land market areas. These increases were offset by a decrease in revenue from the completion of a construction contract for the sale of a derrick barge in June 2008. We recognized revenue for this construction contract throughout 2007 using the percentage-of-completion method. Revenue from land and international market areas grew 9% and 11%, respectively, in 2008.

Drilling Products and Services Segment (formerly Rental Tools)

Revenue for our drilling products and services segment was $550.9 million for the year ended December 31, 2008, an approximate 11% increase from the same period in 2007. Cost of services remained constant at 32% of segment revenue in 2008 and 2007. Our largest increases in revenue were generated from our stabilizers and on-site accommodations. These increases were partially offset by the loss of revenue from the sale of a non-core rental

business in 2007. Our largest geographic revenue improvements were in the Gulf of Mexico where revenue increased 27% to approximately $197.3 million in 2008 over the same period in 2007. We also experienced significant increases in the South American and African market areas. These increases were partially offset by a decrease in drill pipe rental in the North Sea market.

Marine Segment

Our marine segment revenue for the year ended December 31, 2008 decreased 5% from 2007 to $121.1 million. Conversely, cost of services increased 24% for the year ended December 31, 2008, from the same period in 2007, due to lower utilization, increased maintenance and higher direct costs. The increase in maintenance cost is partially due to the fact that we use periods of lower utilization as an opportunity to perform required maintenance to our liftboat fleet. Additionally, cost of services usually does not fluctuate proportionately with revenue due to the high fixed costs associated with this segment. The fleet’s average utilization decreased to approximately 66% in 2008 from 71% in 2007. The fleet’s average dayrate decreased 10% to approximately $15,600 in 2008 from $17,300 in 2007.

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 decreased to $175.5 million for the year ended December 31, 2008 from $187.8 million in 2007. Depreciation, depletion and accretion for our oil and gas segment decreased $56.4 million, or 95%, in 2008 from 2007. As a result of the sale of our 75% interest in SPN Resources on March 14, 2008, we ceased the depreciation and depletion for this segment when these assets were identified as available for sale in January 2008. Depreciation and amortization expense related to our subsea and well enhancement and drilling products and services segments for 2008 increased by $42.8 million, or 35%, from 2007. The increase in depreciation and amortization expense for these segments is primarily attributable to our 2008 and 2007 capital expenditures. Depreciation expense related to the marine segment in 2008 increased approximately $1.2 million, or 14%, from 2007. 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 increased to $282.6 million for the year ended December 31, 2008 from $228.1 million in 2007. General and administrative expenses related to our subsea and well enhancement and drilling products and services segments increased $55.1 million, or 27%, from 2007 to 2008. The increase in general and administrative expense is primarily related to increased expenses associated with our geographic expansion, increased retirement benefits, increased incentive compensation expenses due to our strong operating results and additional infrastructure to enhance our growth. General and administrative expenses remained constant at approximately 15% of revenue for 2008 and 2007.

Liquidity and Capital Resources

In the year ended December 31, 2009, we generated net cash from operating activities of $276.1 million as compared to $402.4 million in 2008. The decrease in cash generated from operating activities is primarily due to the overall decrease in sales and profitability from 2008 to 2009. Our primary liquidity needs are for working capital, capital expenditures, acquisitions and debt service. Our primary sources of liquidity are cash flows from operations and borrowings under our revolving credit facility. We had cash and cash equivalents of $206.5 million at December 31, 2009 compared to $44.9 million at December 31, 2008. As of December 31, 2009, $167.1 million was held in a foreign account in anticipation of the January 2010 acquisition of Hallin.

We spent $286.3 million of cash on capital expenditures during the year ended December 31, 2009. Approximately $124.8 million was used to expand and maintain our drilling products and services equipment inventory, approximately $61.9 million was spent on our marine segment and approximately $99.6 million was used to expand and maintain the asset base of our subsea and well enhancement segment.

In April 2008, we contracted to purchase a 50% interest in four 265-ft. class liftboats. The first two vessels were placed in service during April and May of 2009. In September 2009, we acquired the other 50% interest in the four liftboats for a total price of $38.1 million, following the other owner’s exercise of an option requiring us to purchase its interest in these liftboats. Construction on the two remaining vessels was suspended in March 2009, as a result of disputes with the builder. Those disputes have been resolved and the uncompleted vessels have been delivered to a different shipyard to be completed. We expect the remaining two vessels to be completed during the second half of 2011.

In May 2009, we amended our revolving credit facility to increase the borrowing capacity to $325 million from $250 million. Any amounts outstanding under the revolving credit facility are due on June 14, 2011. Costs incurred during the year ended December 31, 2009 associated with amending the revolving credit facility were approximately $2.3 million. These costs were capitalized and are being amortized over the remaining term of the credit facility. At February 18, 2010, we had approximately $188.6 million outstanding under the bank credit facility. Additionally, we had approximately $9.5 million of letters of credit outstanding, which reduces our borrowing capacity under this credit facility. Borrowings under the credit facility bear interest at a LIBOR rate 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.

We have $14.2 million outstanding at December 31, 2009 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 3^rd and December 3^rd 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.

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 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 1^st and December 1^st 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.

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 15^th and June 15^th 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 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:

•

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;

•

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;

•

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.

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 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.

The following table summarizes our contractual cash obligations and commercial commitments at December 31, 2009 (amounts in thousands) for our long-term debt (including estimated interest payments), operating leases and other long-term liabilities. We do not have any other material obligations or commitments.

Description		2010				2011				2012				2013				2014				Thereafter
Long-term debt, including estimated interest payments		$	37,259			$	209,319			$	27,231			$	27,179			$	316,814			$	474,354
Operating leases			13,191				7,609				4,609				2,654				2,221				14,434
Other long-term liabilities			—				16,647				10,103				6,948				4,544				14,281
Total		$	50,450			$	233,575			$	41,943			$	36,781			$	323,579			$	503,069

We currently believe that we will spend approximately $250 million on capital expenditures, excluding acquisitions, during 2010. 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.

On January 26, 2010, we acquired 100% of the equity interest of Hallin, for approximately $162.3 million of cash. Prior to December 31, 2009, we had borrowed approximately $169.8 million under our revolving credit facility in order to fund the acquisition. These funds were held in an escrow account at December 31, 2009. In conjunction with the acquisition, the Company repaid approximately $55.2 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; Jakarta, Indonesia; Perth, Australia; Aberdeen, Scotland; and Houston, Texas.

We anticipate collecting approximately $280 million for the remainder of 2010 in connection with the large-scale platform decommissioning project in the Gulf of Mexico. During January 2010, we collected approximately $69 million related to this project.

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 fund capital expenditures required to implement our growth strategy with 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 the potential additional consideration that may be payable as a result of the future operating performances of our acquisitions. At December 31, 2009, the maximum additional consideration payable for these acquisitions was approximately $26.3 million. Since these acquisitions occurred before the adoption of Accounting Standards Codification 805-10, “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.

Hedging Activities

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 year ended December 31, 2009, we held outstanding foreign currency forward contracts in order to hedge exposure to currency fluctuations between the British Pound Sterling and the Euro. These contracts were not accounted for as hedges and were marked to fair market value each period. As of December 31, 2009, we had no outstanding foreign currency forward contracts.

Recently Issued Accounting Pronouncements

In June 2009, the Financial Accounting Standards Board issued Accounting Standards Update No. 2009-01 (ASC Topic 105), “Generally Accepted Accounting Principles,” which establishes the FASB Accounting Standards Codification (the Codification or ASC) as the official single source of authoritative U.S. generally accepted accounting principles (GAAP). All existing accounting standards are superseded. All other accounting guidance not included in the Codification is considered non-authoritative. The Codification also includes all relevant Securities and Exchange Commission guidance organized using the same topical structure in separate sections within the Codification. Following the Codification, the Board will not issue new standards in the form of Statements, FASB Staff Positions or Emerging Issues Task Force Abstracts. Instead, it will issue Accounting Standards Updates which will serve to update the Codification, provide background information about the guidance and provide the basis for conclusions on the changes to the Codification. The Codification is not intended to change GAAP, but it changes the way GAAP is organized and presented. The Codification is effective for financial statements issued for interim and annual periods ending after September 15, 2009 and the principal impact on our financial statements is limited to disclosures as all current and future references to authoritative accounting literature will be referenced in accordance with the Codification.

In June 2009, the Financial Accounting Standards Board issued its 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. ASC 810-10 is effective for annual reporting periods beginning after November 15, 2009. We are currently evaluating the impact the adoption of ASC 810-10 will have 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 are currently evaluating the impact the adoption of ASU 2009-13 will have on our results of operations and financial position.

In January 2010, the Financial Accounting Standards Board issued 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. We are currently evaluating the impact the adoption of ASU 2010-06 will have on our disclosures within our financial statements.

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 have elected to defer the application of ASU 2010-03 until our annual reporting period ended December 31, 2010. We are currently evaluating the impact the adoption of ASU 2010-03 will have on our disclosures within our financial statements.

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 our 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. Any gains or losses associated with such fluctuations have not been material.

We do not hold derivatives for trading purposes or use derivatives with complex features. Assets and liabilities of our subsidiaries in the United Kingdom and Europe are translated at current 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 income (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, 2009, we had no outstanding foreign currency forward contracts.

Interest Rates

At December 31, 2009, $177.0 million of our long-term debt outstanding had variable interest rates. Based on the amount of this debt outstanding at December 31, 2009, a 10% increase in the variable interest rate would increase our interest expense for the year ended December 31, 2009 by approximately $528,000, while a 10% decrease would decrease our interest expense by approximately $528,000.

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. In October 2008, LBOTC filed for bankruptcy protection. 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.

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, 2009 and 2008, 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, 2009. 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, 2009 and 2008, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2009, 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 8 to the consolidated financial statements, the Company changed its method for accounting for debt with conversion and other options and, 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 FASB.

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, 2009, 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 26, 2010 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

KPMG LLP

New Orleans, Louisiana
February 26, 2010

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Balance Sheets
December 31, 2009 and 2008
(in thousands, except share data)

		2009				2008 *
ASSETS
Current assets:
Cash and cash equivalents		$	206,505			$	44,853
Accounts receivable, net of allowance for doubtful accounts of $23,679 and $18,013 at December 31, 2009 and 2008, respectively			337,151				360,357
Income taxes receivable			12,674				—
Prepaid expenses			20,209				18,041
Other current assets			287,024				208,739
Total current assets			863,563				631,990
Property, plant and equipment, net			1,058,976				1,114,941
Goodwill			482,480				477,860
Equity-method investments			60,677				122,308
Intangible and other long-term assets, net			50,969				143,046
Total assets		$	2,516,665			$	2,490,145
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	63,466			$	87,207
Accrued expenses			133,602				152,536
Income taxes payable			—				20,861
Deferred income taxes			30,501				36,830
Current maturities of long-term debt			810				810
Total current liabilities			228,379				298,244
Deferred income taxes			209,053				246,824
Long-term debt, net			848,665				654,199
Other long-term liabilities			52,523				36,605
Stockholders’ equity:
Preferred stock of $0.01 par value. Authorized, 5,000,000 shares; none issued			—				—
Common stock of $0.001 par value. Authorized, 125,000,000 shares; issued and outstanding 78,559,350 and 78,028,072 shares at December 31, 2009 and 2008, respectively			79				78
Additional paid in capital			387,885				375,436
Accumulated other comprehensive loss, net			(18,996	)			(32,641	)
Retained earnings			809,077				911,400
Total stockholders’ equity			1,178,045				1,254,273
Total liabilities and stockholders’ equity		$	2,516,665			$	2,490,145

See accompanying notes to consolidated financial statements.

* As adjusted for ASC 470-20 (See note 8)

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Statements of Operations
Years Ended December 31, 2009, 2008 and 2007
(in thousands, except per share data)

		2009				2008 *				2007 *
Oilfield service and rental revenues		$	1,449,300			$	1,826,052			$	1,379,767
Oil and gas revenues			—				55,072				192,700
Total revenues			1,449,300				1,881,124				1,572,467
Cost of oilfield services and rentals			824,034				885,308				631,545
Cost of oil and gas sales			—				12,986				66,580
Total cost of services, rentals and sales (exclusive of items shown separately below)			824,034				898,294				698,125
Depreciation, depletion, amortization and accretion			207,114				175,500				187,841
General and administrative expenses			259,093				282,584				228,146
Reduction in value of assets			212,527				—				—
Gain on sale of businesses			2,084				40,946				7,483
Income (loss) from operations			(51,384	)			565,692				465,838
Other income (expense):
Interest expense, net of amounts capitalized			(50,906	)			(46,684	)			(48,436	)
Interest income			926				2,975				2,662
Other income (expense)			571				(3,977	)			189
Earnings (losses) from equity-method investments, net			(22,600	)			24,373				(2,940	)
Reduction in value of equity-method investment			(36,486	)			—				—
Income (loss) before income taxes			(159,879	)			542,379				417,313
Income taxes			(57,556	)			190,904				145,755
Net income (loss)		$	(102,323	)		$	351,475			$	271,558
Basic earnings (loss) per share		$	(1.31	)		$	4.39			$	3.35
Diluted earnings (loss) per share		$	(1.31	)		$	4.33			$	3.30
Weighted average common shares used in computing earnings per share:
Basic			78,171				79,990				80,973
Incremental common shares from stock options			—				1,163				1,358
Incremental common shares from restricted stock units			—				60				58
Diluted			78,171				81,213				82,389

See accompanying notes to consolidated financial statements.

* As adjusted for ASC 470-20 (See note 8)

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Statements of Changes in Stockholders’ Equity
Years Ended December 31, 2009, 2008 and 2007
(in thousands, except share data)

																						Accumulated
		Preferred								Common								Additional				other
		stock				Preferred				stock				Common				paid-in				comprehensive				Retained
		shares				stock				shares				stock				capital *				income (loss), net				earnings *				Total
Balances, December 31, 2006			—			$	—				80,617,337			$	81			$	466,501			$	10,288			$	288,367			$	765,237
Comprehensive income:
Net income			—				—				—				—				—				—				271,558				271,558
Other comprehensive income -
Changes in fair value of hedging positions of equity-method investments, net of tax			—				—				—				—				—				(2,580	)			—				(2,580	)
Foreign currency translation adjustment			—				—				—				—				—				1,370				—				1,370
Total comprehensive income			—				—				—				—				—				(1,210	)			271,558				270,348
Grant of restricted stock units			—				—				—				—				840				—				—				840
Restricted stock grant and compensation expense, net of forfeitures			—				—				160,234				—				2,685				—				—				2,685
Exercise of stock options			—				—				867,916				1				8,439				—				—				8,440
Tax benefit from exercise of stock options			—				—				—				—				9,408				—				—				9,408
Stock option compensation expense			—				—				—				—				1,529				—				—				1,529
Shares issued under Employee Stock Purchase Plan			—				—				26,163				—				949				—				—				949
Shares repurchased and retired			—				—				(1,000,000	)			(1	)			(33,769	)			—				—				(33,770	)
Balances, December 31, 2007			—			$	—				80,671,650			$	81			$	456,582			$	9,078			$	559,925			$	1,025,666
Comprehensive income:
Net income			—				—				—				—				—				—				351,475				351,475
Other comprehensive income -
Changes in fair value of hedging positions of equity-method investments, net of tax			—				—				—				—				—				6,460				—				6,460
Foreign currency translation adjustment			—				—				—				—				—				(48,179	)			—				(48,179	)
Total comprehensive income			—				—				—				—				—				(41,719	)			351,475				309,756
Grant of restricted stock units			—				—				—				—				840				—				—				840
Restricted stock grant and compensation expense, net of forfeitures			—				—				501,112				1				4,685				—				—				4,686
Exercise of stock options			—				—				426,592				—				4,274				—				—				4,274
Tax benefit from exercise of stock options			—				—				—				—				5,411				—				—				5,411
Stock option compensation expense			—				—				—				—				2,643				—				—				2,643
Shares issued to settle restricted stock units			—				—				14,559				—				—				—				—				—
Shares issued to pay performance share units			—				—				74,405				—				2,948				—				—				2,948
Shares issued under Employee Stock Purchase Plan			—				—				56,754				—				1,833				—				—				1,833
Shares repurchased and retired			—				—				(3,717,000	)			(4	)			(103,780	)			—				—				(103,784	)
Balances, December 31, 2008			—			$	—				78,028,072			$	78			$	375,436			$	(32,641	)		$	911,400			$	1,254,273

See accompanying notes to consolidated financial statements.

* As adjusted for ASC 470-20 (See note 8)

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Statements of Changes in Stockholders’ Equity (Continued)
Years Ended December 31, 2009, 2008 and 2007
(in thousands, except share data)

																						Accumulated
		Preferred								Common								Additional				other
		stock				Preferred				stock				Common				paid-in				comprehensive				Retained
		shares				stock				shares				stock				capital				income (loss), net				earnings				Total
Balances, December 31, 2008			—			$	—				78,028,072			$	78			$	375,436			$	(32,641	)		$	911,400			$	1,254,273
Comprehensive income:
Net income (loss)			—				—				—				—				—				—				(102,323	)			(102,323	)
Other comprehensive income -
Disposition of hedging positions of equity-method investments, net of tax			—				—				—				—				—				(3,881	)			—				(3,881	)
Foreign currency translation adjustment			—				—				—				—				—				17,526				—				17,526
Total comprehensive loss			—				—				—				—				—				13,645				(102,323	)			(88,678	)
Grant of restricted stock units			—				—				—				—				700				—				—				700
Restricted stock grant and compensation expense, net of forfeitures			—				—				305,182				1				5,837				—				—				5,838
Exercise of stock options			—				—				38,717				—				375				—				—				375
Tax benefit from exercise of stock options			—				—				—				—				170				—				—				170
Stock option compensation expense			—				—				—				—				2,401				—				—				2,401
Shares issued to pay performance share units			—				—				71,392				—				920				—				—				920
Shares issued under Employee Stock Purchase Plan			—				—				133,360				—				2,308				—				—				2,308
Shares withheld and retired			—				—				(17,373	)			—				(262	)			—				—				(262	)
Balances, December 31, 2009			—			$	—				78,559,350			$	79			$	387,885			$	(18,996	)		$	809,077			$	1,178,045

See accompanying notes to consolidated financial statements.

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Statements of Cash Flows
Years Ended December 31, 2009, 2008 and 2007
(in thousands)

		2009				2008 *				2007 *
Cash flows from operating activities:
Net income (loss)		$	(102,323	)		$	351,475			$	271,558
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion			207,114				175,500				187,841
Deferred income taxes			(74,704	)			103,504				65,565
Reduction in value of assets			212,527				—				—
Reduction in value of equity-method investments			36,486				—				—
Tax benefit from exercise of stock options			(170	)			(5,411	)			(9,408	)
Stock based and performance share unit compensation expense, net			11,785				12,182				12,549
Retirement and deferred compensation plans (income) expense, net			1,550				15,255				(189	)
(Earnings) losses from equity-method investments, net of cash received			28,606				(7,102	)			2,940
Amortization of debt acquisition costs and note discount			21,744				19,963				18,697
Gain on sale of businesses			(2,084	)			(40,946	)			(7,483	)
Changes in operating assets and liabilities, net of acquisitions and dispositions:
Receivables			25,609				(77,565	)			(25,361	)
Other current assets			(51,320	)			(184,602	)			4,652
Accounts payable			(24,637	)			20,252				(7,036	)
Accrued expenses			(41,264	)			(5,917	)			7,591
Decommissioning liabilities			—				(6,160	)			(2,769	)
Income taxes			(2,301	)			12,434				8,524
Other, net			29,485				19,497				2,612
Net cash provided by operating activities			276,103				402,359				530,283
Cash flows from investing activities:
Payments for capital expenditures			(286,277	)			(453,861	)			(410,518	)
Acquisitions of businesses, net of cash acquired			(1,247	)			(8,410	)			(110,973	)
Acquisitions of oil and gas properties, net of cash acquired			—				—				(8,000	)
Cash proceeds from sale of businesses, net of cash sold			7,716				155,312				18,100
Cash contributed to equity-method investment			(8,694	)			—				—
Other			(3,769	)			(3,578	)			9,280
Net cash used in investing activities			(292,271	)			(310,537	)			(502,111	)
Cash flows from financing activities:
Net borrowings from revolving line of credit			177,000				—				—
Principal payments on long-term debt			(810	)			(810	)			(810	)
Payment of debt acquisition costs			(2,308	)			—				(83	)
Proceeds from exercise of stock options			375				4,274				8,440
Tax benefit from exercise of stock options			170				5,411				9,408
Proceeds from issuance of stock through employee benefit plans			1,958				1,558				806
Purchase and retirement of stock			—				(103,784	)			(33,770	)
Net cash provided by (used in) financing activities			176,385				(93,351	)			(16,009	)
Effect of exchange rate changes on cash			1,435				(5,267	)			516
Net increase (decrease) in cash and cash equivalents			161,652				(6,796	)			12,679
Cash and cash equivalents at beginning of year			44,853				51,649				38,970
Cash and cash equivalents at end of year		$	206,505			$	44,853			$	51,649