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

For the Transition Period from                      to                     

SUPERIOR ENERGY SERVICES, INC.

Delaware (State or other jurisdiction of incorporation or organization)		75-2379388 (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, including area code:		(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 þ No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) 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 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
				(Do not check this of a smaller reporting company)

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, 2010 based on the closing price on the New York Stock Exchange on that date was $1,458,240,000.

The number of shares of the registrant’s common stock outstanding on February 18, 2011 was 78,892,650.

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, 2010

TABLE OF CONTENTS

		Page
PART I
Item 1. Business		1
Item 1A. Risk Factors		6
Item 1B. Unresolved Staff Comments		14
Item 2. Properties		14
Item 3. Legal Proceedings		14
Item 4A. Executive Officers of Registrant		15
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities		16
Item 6. Selected Financial Data		19
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations		20
Item 7A. Quantitative and Qualitative Disclosures about Market Risk		34
Item 8. Financial Statements and Supplementary Data		36
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		81
Item 9A. Controls and Procedures		81
Item 9B. Other Information		84
PART III
Item 10. Directors, Executive Officers and Corporate Governance		84
Item 11. Executive Compensation		84
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		84
Item 13. Certain Relationships and Related Transactions, and Director Independence		84
Item 14. Principal Accounting Fees and Services		84
PART IV
Item 15. Exhibits, Financial Statement Schedules		85
EX-10.11
EX-10.21
EX-12.1
EX-21.1
EX-23.1
EX-23.2
EX-23.3
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-99.1
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

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. Further, we may make changes to our business plans that could or will affect our results. 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. We caution you that we do not intend to update our forward-looking statements, notwithstanding any changes in our assumptions, changes in our business plans, our actual experience, or other changes, and we undertake no obligation to update any forward-looking statements.

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, drilling products and services and marine segments. We believe that we are one of the few companies capable of providing the services and tools necessary to maintain, enhance and extend the life of producing wells, as well as plug and abandonment services at the end of their life cycle. We also own oil and gas properties in the Gulf of Mexico. We believe that our ability to provide our customers with multiple services and to coordinate and integrate their delivery, particularly offshore through the use of our liftboats, allows us to maximize efficiency, reduce lead time and provide cost effective solutions for our customers. We have expanded geographically and now have a significant presence in both domestic and international market areas. Excluding the continental United States, we currently have physical locations in the following geographic regions: Latin America (Brazil, Colombia, Ecuador, Trinidad and Tobago and Venezuela), North America (Canada), North Sea and Europe (Norway, Netherlands, Germany and the United Kingdom), Middle East (Kazakhstan and United Arab Emirates), West Africa (Angola and Nigeria) and Asia Pacific (Australia, Indonesia, Malaysia and Singapore).

Operations

Our operations are organized into the following business segments:

Subsea and Well Enhancement. We provide subsea and well enhancement services that are used to build out oil and gas production infrastructure, stimulate oil and gas production, plug and abandon uneconomic or non-producing wells and decommission offshore oil and gas platforms. Our subsea and well enhancement services include integrated subsea and engineering services, coiled tubing, electric line, pumping and stimulation, gas lift, well control, hydraulic workover and snubbing, mechanical wireline, recompletion, stimulation and sand control equipment and services, well evaluation, offshore oil and gas tank and vessel cleaning, decommissioning and plug and abandonment. In connection with our acquisition of the Bullwinkle platform and its related assets, production

handling arrangements, as well as the production and sale of oil and gas from our properties in the Gulf of Mexico are included in this segment. Additionally, we manufacture and sell specialized drilling rig instrumentation equipment. Our subsea and well enhancement segment conducts operations in over 50 countries within Latin America, North America, the North Sea region, Continental Europe, the Middle East, Central Asia, West Africa and the Asia Pacific region.

We believe we are the leading provider of wireline services in the Gulf of Mexico. We service this market area with approximately 135 offshore wireline units, 25 offshore electric line units and ten dedicated liftboats configured specifically for wireline services. We also own and operate 47 land wireline units, 67 land electric line units, 33 land coiled tubing units and six offshore coiled tubing units. Additionally, we own two derrick barges each equipped with an 800 metric ton crane, two dynamically positioned vessels suited for subsea intervention projects, three saturation diving systems and 25 remotely operated vehicles used for inspection, repair and maintenance work. We are also a lessee of a third dynamically positioned subsea vessel under a capital lease that expires in 2019.

Drilling Products and Services. We believe we are a leading provider of drilling products and services. We manufacture, sell and rent specialized equipment for use with offshore and onshore oil and gas well drilling, completion, production and workover activities. Through internal growth and acquisitions, we have increased the size and breadth of our drilling products inventory and geographic scope of operations so that we now conduct operations offshore in the Gulf of Mexico, onshore in the United States and in select international market areas. We currently have locations in all of the major staging points in Louisiana and Texas for oil and gas activities in the Gulf of Mexico, and in North Louisiana, Texas, Arkansas, Oklahoma, Colorado, Pennsylvania, North Dakota and Wyoming. Our drilling products and services segment conducts operations in over 35 countries within Latin America, North America, the North Sea region, Continental Europe, the Middle East, Central Asia, West Africa and the Asia Pacific region. Our drilling products and services include pressure control equipment, specialty tubular goods including drill pipe and landing strings, connecting iron, handling tools, stabilizers, drill collars and on-site accommodations.

Marine Services. We own and operate a fleet of liftboats that is highly complementary to our subsea and well enhancement services. A liftboat is a self-propelled, self-elevating work platform with legs, cranes and living accommodations. Our fleet consists of 25 liftboats with leg lengths ranging from 145 feet to 265 feet. Our liftboat fleet has leg lengths and deck spaces that are suited to deliver our production-related bundled services and support customers in their construction, maintenance and other production enhancement projects. All of our liftboats are currently located either in the Gulf of Mexico or the Atlantic Ocean.

Equity-Method Investments. Our equity-method investments in SPN Resources, LLC (SPN Resources) and DBH, LLC (DBH), the successor company of Beryl Oil and Gas, LP, provide us additional opportunities for our subsea and well enhancement, decommissioning and platform management services. SPN Resources and DBH utilize our production-related assets and services to maintain, enhance and extend existing production of these properties. At the end of a property’s economic life, we offer services to plug and abandon the wells and decommission and abandon the facilities.

For additional industry segment financial information, see note 14 to our consolidated financial statements included in Item 8 of this Form 10-K.

Customers

Our customers are the major and independent oil and gas companies that are active in the geographic areas in which we operate. In 2010, no single customer accounted for more than 10% of our total revenue. Of our 2009 and 2008 total revenue, Chevron accounted for approximately 15% and 12%, respectively, Apache accounted for approximately 13% and 11%, respectively, and BP accounted for approximately 11% for each year. Our inability to continue to perform services for a number of our large existing customers, if not offset by sales to new or other existing customers, could have a material adverse effect on our business and operations.

Competition

We operate in highly competitive areas of the oilfield services industry. The products and services of each of our operating segments are sold in highly competitive markets, and our revenues and earnings can be affected by the following factors:

	•		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 the principal competitive factors in the market areas that we serve are price, product and service quality, safety record, equipment availability and technical proficiency.

Our operations may be adversely affected if our current competitors or new market entrants introduce products or services with better features, performance, prices or other characteristics than our products and services. Further, if our competitors construct additional liftboats, it could affect vessel utilization and resulting day rates. Competitive pressures or other factors also may result in significant price competition that could reduce our operating cash flow and earnings. In addition, competition among oilfield service and equipment providers is affected by each provider’s reputation for safety and quality.

Potential Liabilities and Insurance

Our operations involve a high degree of operational risk and expose us to significant liabilities. Failure or loss of our equipment could result in personal injury, damage or loss of property and equipment, environmental accidents and pollution and other damages for which we could be liable. Litigation arising from a catastrophic occurrence, such as a sinking of a marine vessel or a fire, explosion or well blowout at a location we lease or where our equipment and services are used may result in substantial claims for damages. We also may have limited exposure to liability for economic losses sustained by third parties due to catastrophic occurrences.

In addition to liability exposure for our own actions, we may also be liable for damages caused by the fault of third parties, including our customers. This is due to indemnification rights contained in most of our customer contracts, pursuant to which we agree to indemnify our customers for any personal injuries or property damages sustained by our personnel or equipment, regardless of who is at fault for such injuries or damages.

We maintain insurance against risks that we believe is consistent in types and amounts with industry standards and is required by our customers, including coverage for our contractual indemnification obligations. Changes in the insurance industry in the past few years have led to higher insurance costs and deductibles as well as lower coverage limits, causing us to rely on self insurance against many risks associated with our business. The availability of insurance covering risks we typically insure against may continue to decrease, and the costs of such insurance and

deductibles may continue to increase, forcing us to self insure against more business risks, including the risks associated with hurricanes. The insurance that we are able to obtain may have higher deductibles, higher premiums, lower limits and more restrictive policy terms.

Health, Safety and Environmental Assurance

We have established health, safety and environmental performance as a corporate priority. Our goal is to be an industry leader in this area by focusing on the belief that all safety and environmental incidents are preventable and an injury-free workplace is achievable by emphasizing correct behavior. We have a company-wide effort to enhance our behavioral safety process and training program to make safety a constant area of focus through open communication with all of our offshore, onshore and yard employees. In addition, we investigate all incidents with a priority of identifying and implementing the corrective measures necessary to reduce the chance of reoccurrence.

Government Regulation

Our business is significantly affected by the following:

	•		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. Additionally, the denial or delay of, or any other changes in the procedures and timing for, issuing permits necessary to our and our customers’ operations could significantly affect our business. We also cannot predict whether additional laws and regulations will be adopted, including changes in regulatory oversight, increase of inspection costs or removal of applicable liability caps, or the effect such changes may have on us, our businesses or our financial condition. The demand for our services from the oil and gas industry would be affected by changes in applicable laws and regulations. The adoption of new laws and regulations curtailing drilling for oil and gas in our operating areas for economic, environmental or other policy reasons could also adversely affect our operations by limiting demand for our services.

Environmental Regulations

General. Our operations are subject to extensive federal, state and local laws and regulations relating to the generation, storage, handling, emission, transportation and discharge of materials into the environment. Permits are required for the conduct of our business and operation of our various marine vessels. These permits can be revoked, modified or renewed by issuing authorities. Governmental authorities enforce compliance with their regulations through administrative or civil penalties, corrective action orders, injunctions or criminal prosecution. Although we believe that compliance with environmental regulations will not have a material adverse effect on us, risks of substantial costs and liabilities related to environmental compliance issues are part of our operations. No assurance can be given that significant costs and liabilities will not be incurred.

Federal laws and regulations applicable to our operations include those controlling the discharge of materials into the environment, requiring removal and cleanup of materials that may harm the environment, requiring consistency with applicable coastal zone management plans, or otherwise relating to the protection of the environment.

Our insurance policies provide liability coverage for sudden and accidental occurrences of pollution or clean up and containment in amounts that we believe are prudent and comparable to policy limits carried by others in our industry.

Outer Continental Shelf Lands Act. The Outer Continental Shelf Lands Act (OCSLA) and regulations promulgated pursuant thereto impose a variety of regulations relating to safety and environmental protection applicable to lessees, permittees and other parties operating on the Outer Continental Shelf. Specific design and operational standards may apply to Outer Continental Shelf vessels, rigs, platforms, vehicles and structures. Violations of lease conditions or regulations issued pursuant to OCSLA can result in substantial civil and criminal penalties as well as potential

court injunctions curtailing operations and the cancellation of leases. Enforcement liabilities under OCSLA can result from either governmental or citizen prosecution. We believe that we substantially comply with OCSLA and its regulations.

Solid and Hazardous Waste. We own and lease numerous properties that have been used in connection with the production of oil and gas for many years. Although we believe we utilize operating and disposal practices that are standard in the industry, it is possible that hydrocarbons or other solid wastes may have been disposed of or released on or under the properties owned and leased by us. Federal and state laws applicable to oil and gas wastes and properties continue to be stricter over time. Under these increasingly stringent requirements, we could be required to remove or remediate previously disposed wastes (including wastes disposed or released by prior owners and operators) or clean up property contamination (including groundwater contamination by prior owners or operators) or to perform plugging operations to prevent future contamination. We generate some hazardous wastes that are already subject to the Federal Resource Conservation and Recovery Act (RCRA) and comparable state statutes. The Environmental Protection Agency (EPA) has limited the disposal options for certain hazardous wastes. It is possible that certain wastes currently exempt from treatment as hazardous wastes may in the future be designated as hazardous wastes under RCRA or other applicable statutes. We could, therefore, be subject to more rigorous and costly disposal requirements in the future than we encounter today.

Superfund. The Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on certain persons with respect to the release of hazardous substances into the environment. These persons include the owner and operator of a site and any party that disposed of or arranged for the disposal of hazardous substances found at a site. CERCLA also authorizes the EPA, and in some cases, private parties, to undertake actions to clean up such hazardous substances, or to recover the costs of such actions from the responsible parties. In the course of business, we have generated and will continue to generate wastes that may fall within CERCLA’s definition of hazardous substances. We may also be an operator of sites on which hazardous substances have been released. As a result, we may be responsible under CERCLA for all or part of the costs to clean up sites where such wastes have been disposed.

Oil Pollution Act. The Federal Oil Pollution Act of 1990 (OPA) and resulting regulations impose a variety of obligations on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills in waters of the United States. The term “waters of the United States” has been broadly defined to include inland water bodies, including wetlands and intermittent streams. OPA assigns liability to each responsible party for oil removal costs and a variety of public and private damages. We believe that we substantially comply with OPA and related federal regulations.

Clean Water Act. The Federal Water Pollution Control Act (Clean Water Act) and resulting regulations, which are implemented through a system of permits, also govern the discharge of certain contaminants into waters of the United States. Sanctions for failure to comply strictly with the Clean Water Act are generally resolved by payment of fines and correction of any identified deficiencies. However, regulatory agencies could require us to cease operation of our marine vessels that are the source of water discharges. We believe that we substantially comply with the Clean Water Act and related federal and state regulations.

Clean Air Act. Our operations are subject to local, state and federal laws and regulations to control emissions from sources of air pollution. Payment of fines and correction of any identified deficiencies generally resolve penalties for failure to comply strictly with air regulations or permits. Regulatory agencies could also require us to cease operation of certain marine vessels that are air emission sources. We believe that we substantially comply with the emission standards under local, state, and federal laws and regulations.

Maritime Employees

Certain of our employees who perform services on offshore platforms and marine vessels are covered by the provisions of the Jones Act, the Death on the High Seas Act and general maritime law. These laws operate to make the liability limits established under state workers’ compensation laws inapplicable to these employees. Instead, these employees or their representatives are permitted to pursue actions against us for damages resulting from job related injuries, with generally no limitations on our potential liability.

Employees

As of January 31, 2011, we had approximately 5,700 employees. None of our employees are represented by a union or covered by a collective bargaining agreement. We believe that our relationship with our employees is good.

Facilities

Our principal executive offices are located at 601 Poydras Street, Suite 2400, New Orleans, Louisiana 70130. We own an operating facility on a 17-acre tract in Harvey, Louisiana, which we use to support our subsea and well enhancement, drilling products and services, and marine operations. Our other principal operating facility is located on a 32-acre tract in Broussard, Louisiana, which we use to support our drilling products and services and subsea and well enhancement operations in the Gulf of Mexico. We also own an operating facility on a 23-acre tract in Houston, Texas, which serves as a manufacturing, testing and research and design center. In addition, we own certain facilities and lease other office, service and assembly facilities under various operating leases. We have a total of approximately 150 owned or leased operating facilities located throughout the world. We believe that all of our leases are at competitive or market rates and do not anticipate any difficulty in leasing suitable additional space as may be needed or extending terms when our current leases expire.

Intellectual Property

We own numerous patents that we use in our operations, many of which we acquired from Baker Hughes Incorporated in August 2010 (see note 4 to our consolidated financial statements included in Item 8 of this Form 10-K). We protect these patents by registering them with the U.S. Patent and Trademark Office and with governmental agencies in foreign countries, particularly where our products and services are offered. We intend to vigorously enforce and protect our patents and other intellectual properties. In addition, we rely to a great extent on the technical expertise and know-how of our personnel to maintain our competitive position.

Other Information

We have our principal executive offices at 601 Poydras Street, Suite 2400, New Orleans, Louisiana 70130. Our telephone number is (504) 587-7374. We also have a website at http://www.superiorenergy.com. Copies of the annual, quarterly and current reports we file with the SEC, and any amendments to those reports, are available on our website free of charge soon after such reports are filed with or furnished to the SEC. The information posted on our website is not incorporated into this Annual Report on Form 10-K. Alternatively, you may access these reports at the SEC’s internet website: http://www.sec.gov/.

We have a Code of Business Ethics and Conduct, which applies to all of our directors, officers and employees. The Code of Business Ethics and Conduct is publicly available on our website at http://www.superiorenergy.com. Any waivers to the Code of Business Ethics and Conduct by directors or executive officers and any material amendment to the Code of Business Ethics and Conduct will be posted promptly on our website and/or disclosed in a current report on Form 8-K.

Item 1A. Risk Factors

You should carefully consider the following factors in addition to the other information contained in this Annual Report. The risks described below are the material risks that we have identified. In addition, they may not be the only material risks that we face. There are many factors that affect our business and the results of our operations, many of which are beyond our control. Additional risks and uncertainties not currently known to us or that we currently view as immaterial may also impair our business operations. If any of these risks develop into actual events, it could materially and adversely affect our business, financial condition, results of operations and cash flows. If that occurred, the trading price of our common stock could decline and you could lose part or all of your investment.

The Deepwater Horizon incident could have a lingering significant impact on exploration and production activities in United States coastal waters that could adversely affect demand for our services and equipment.

As an oil and gas service company, the success and profitability of our operations in the United States are influenced by the level of drilling and exploration activity in the Gulf of Mexico. Revenue generated from our Gulf of Mexico market area was approximately $675.8 million, $804.9 million and $1,204.6 million for the years ended December 31, 2010, 2009 and 2008, respectively.

The April 2010 catastrophic explosion of the Deepwater Horizon, the related oil spill in the Gulf of Mexico and the U.S. Government’s response to these events has significantly and adversely disrupted oil and gas exploration activities in the Gulf of Mexico. Shortly after the explosion, the United States government imposed a moratorium effectively suspending all deepwater drilling activity in the Gulf of Mexico which was subsequently lifted. Although the moratorium did not suspend drilling activity in the shallow waters of the Gulf of Mexico, new safety and permitting requirements have been imposed on shallow water operators, resulting in fewer drilling permits being issued to shallow water operators since the Deepwater Horizon explosion. Additionally, the commission appointed by the President of the United States to study the causes of the catastrophe released its report and has recommended certain legislative and regulatory measures that should be taken with the stated goal to minimize the possibility of a reoccurrence of a disastrous spill. Various bills are being considered by Congress which, if enacted, could either significantly increase the costs of conducting drilling and exploration activities in the Gulf of Mexico, particularly in deep waters, or possibly drive a substantial portion of drilling and operation activity out of the Gulf of Mexico.

There are a number of uncertainties affecting the oil and gas industry that continue to exist in the aftermath of the Deepwater Horizon events and the release of the commission report, including whether Congress will repeal the $75 million cap for non-reclamation liabilities under the Oil Pollution Act of 1990, whether insurance will continue to be available at a reasonable cost and with reasonable policy limits to support drilling and exploration activity in the Gulf of Mexico, whether permits for drilling and other oilfield service activities will be issued and at what rate, and whether the overall legislative and regulatory response to the disaster will discourage investment in oil and gas exploration in the Gulf of Mexico. Although the eventual outcome of these uncertainties is currently unknown, any one or more of them could constrict the return of demand for our products and services to historical levels or further reduce demand for our products and services, which could adversely affect our operations in the Gulf of Mexico. However, until the ultimate regulatory response to these events becomes more certain, we cannot accurately predict the extent of the impact those responses could have on our customers and similarly, the long term impact on our business and operations. Any regulatory response that has the effect of materially curtailing drilling and exploration activity in the Gulf of Mexico will ultimately adversely affect our operations in the Gulf of Mexico.

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

Economic conditions in the United States and international markets in which we operate could substantially affect our revenue and profitability. The lingering domestic and global financial crises, the associated fluctuating oil and gas prices, and the disruption in the credit markets have had an adverse effect on our operating results and financial condition, and if sustained or worsened, such adverse effects could continue or worsen. Additionally, if the disruption in the credit markets continues, some of our suppliers and customers may be unable to recover from, or could face additional credit issues, cash flow problems and other financial hardships.

Changes in governmental banking, monetary and fiscal policies to restore the domestic and global financial markets and increase credit availability may not be effective. It is difficult to determine the breadth and duration of the domestic and global financial crises and the many ways in which they may affect our suppliers, customers and our business in general. The continuation or further deterioration of these difficult financial and macroeconomic conditions could have a significant adverse effect on our results of operations and cash flows.

Our borrowing capacity could be affected by the uncertainty impacting credit markets generally.

Lingering disruptions in the credit and financial markets could adversely affect financial institutions, inhibit lending and limit access to capital and credit for many companies. Although we believe that the banks participating in our

credit facility have adequate capital and resources, we can provide no assurance that all of those banks will continue to operate as a going concern in the future. If any of the banks in our lending group were to fail, it is possible that the borrowing capacity under our credit facility would be reduced. In the event that the availability under our credit facility was reduced significantly, we could be required to obtain capital from alternate sources in order to finance our capital needs. Our options for addressing such capital constraints would include, but not be limited to, (1) obtaining commitments from the remaining banks in the lending group or from new banks to fund increased amounts under the terms of our credit facility, (2) accessing the public capital markets, or (3) delaying certain projects. If it became necessary to access additional capital, any such alternatives could have terms less favorable than those terms under our existing credit facility, which could have a material effect on our consolidated financial position, results of operations and cash flows.

If future financing is not available to us when required, as a result of limited access to the credit markets or otherwise, or is not available to us on acceptable terms, we may be unable take advantage of business opportunities or respond to competitive pressures, either of which could have a material adverse effect on our consolidated financial position, results of operations and cash flows.

We are subject to the cyclical nature of the oil and gas industry.

Demand for most of our oilfield services is substantially dependent on the level of expenditures by the oil and gas industry. This level of activity has traditionally been volatile as a result of sensitivities to oil and gas prices and generally dependent on the industry’s view of future oil and gas prices. The purchases of the products and services we provide are, to a substantial extent, deferrable in the event oil and gas companies reduce expenditures. Therefore, the willingness of our customers to make expenditures is critical to our operations. Oil and gas prices are very volatile and could be affected by many factors, including the following:

	•		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;
	•		domestic and global political and economic uncertainty, socio-political unrest and instability or hostilities;
	•		demand for and availability of alternative, competing sources of energy; and
	•		technological advances affecting energy exploration, production and consumption.

Although the effects of changing prices on activity levels in production and development sectors of the oil and gas industry are less immediate and as a result, less volatile than the exploration sector, producers generally react to declining oil and gas prices by reducing expenditures. This has, in the past, adversely affected and may in the future adversely affect our business. We are unable to predict future oil and gas prices or the level of oil and gas industry activity. A prolonged low level of activity in the oil and gas industry will adversely affect the demand for our products and services and our financial condition, results of operations and cash flows.

Our industry is highly competitive.

We operate in highly competitive areas of the oilfield services industry. The products and services of each of our principal industry segments are sold in highly competitive markets, and our revenues and earnings may be affected by the following factors:

	•		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, likely resulting in lower day rates and utilization. Competitive pressures or other factors also may result in significant price competition that could have a material adverse effect on our results of operations and financial condition. Finally, competition among oilfield service and equipment providers is also affected by each provider’s reputation for safety and quality.

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

Our international revenues accounted for approximately 28%, 22%, and 17% of our total revenues in 2010, 2009, and 2008, respectively. Our international operations are subject to a number of risks inherent in any business operating in foreign countries, including, but not limited to, the following:

	•		political, social and economic instability;
	•		potential expropriation, seizure or nationalization of assets;
	•		increased operating costs;
	•		civil unrest and protests, strikes, 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 or total loss by these storms. Although we maintain insurance on our properties, due to the significant losses incurred as a consequence of the hurricanes that occurred in the Gulf of Mexico in recent years these coverages are not comparable with that of prior years. For instance, since 2006, our insurance policies now have an annual aggregate limit, rather than an occurrence limit. Also, our deductible for wind damage versus non-wind damage events is between five and ten times higher. Thus, we are at greater risk of loss due to severe weather conditions. Any significant uninsured losses could have a material adverse effect on our financial position, results of operations and cash flows.

Damage to our equipment caused by high winds and turbulent seas could cause us to curtail or suspend service operations for significant periods of time until damage can be assessed and repaired. Moreover, even if we do not experience direct damage from any of these storms, we may experience disruptions in our operations because

customers may curtail or suspend their development activities due to damage to their platforms, pipelines and other related facilities. We do not maintain business interruption insurance that could protect us from these events.

We depend on key personnel.

Our success depends to a great degree on the abilities of our key management personnel, particularly our chief executive officer and other high-ranking executives. The loss of the services of one or more of these key employees could adversely affect us.

We might be unable to employ a sufficient number of skilled workers.

The delivery of our products and services require personnel with specialized skills and experience. As a result, our ability to remain productive and profitable will depend upon our ability to employ and retain skilled workers. In addition, our ability to expand our operations depends in part on our ability to increase the size of our skilled labor force. The demand for skilled workers in our industry is high, and the supply is limited. We could be faced with severe shortages of experienced personnel as we expand our operations and enter new markets. In developed countries, many senior engineers, managers and other professionals are reaching retirement age, with no assurance that enough college graduates and younger workers will be ready to replace them.

In addition, although our employees are not covered by a collective bargaining agreement, the marine services industry has in the past been targeted by maritime labor unions in an effort to organize Gulf of Mexico employees. A significant increase in the wages paid by competing employers or the unionization of our Gulf of Mexico employees could result in a reduction of our skilled labor force, increases in the wage rates that we must pay or both. If either of these events were to occur, our capacity and profitability could be diminished and our growth potential could be impaired.

We depend on significant customers.

We derive a significant amount of our revenue from a small number of major and independent oil and gas companies. In 2010, no single customer accounted for more than 10% of our total revenue. Of our 2009 and 2008 total revenue, Chevron accounted for approximately 15% and 12%, respectively, Apache accounted for approximately 13% and 11%, respectively, and BP accounted for approximately 11% for each year. Our inability to continue to perform services for a number of our large existing customers, if not offset by sales to new or other existing customers, could have a material adverse effect on our business and operations.

The terms of our contracts could expose us to unforeseen costs and costs not within our control.

Under fixed-price contracts, turnkey or modified turnkey contracts, we agree to perform a defined scope of work for a fixed price. Extra work, which is subject to customer approval, is billed separately. As a result, we can improve our expected profit by superior contract performance, productivity, worker safety and other factors resulting in cost savings. However, we could incur cost overruns above the approved contract price, which may not be recoverable. Prices for these contracts are established based largely upon estimates and assumptions relating to project scope and specifications, personnel and material needs. These estimates and assumptions may prove inaccurate or conditions may change due to factors out of our control, resulting in cost overruns, which we may be required to absorb and could have a material adverse effect on our business, financial condition and results of operations. In addition, our profits from these contracts could decrease and we could experience losses if we incur difficulties in performing the contracts or are unable to secure suitable commitments from our subcontractors and other suppliers. Many of these contracts require us to satisfy specified progress milestones or performance standards in order to receive payment. Under these types of arrangements, we may incur significant costs for equipment, labor and supplies prior to receipt of payment. If the customer fails or refuses to pay us for any reason, there is no assurance we will be able to collect amounts due to us for costs previously incurred. In some cases, we may find it necessary to terminate subcontracts and we may incur costs or penalties for canceling our commitments to them. If we are unable to collect amounts owed to us under these contracts, we may be required to record a charge against previously recognized earnings related to the project, and our liquidity, financial condition and results of operations could be adversely affected.

Percentage-of-completion accounting for contract revenue may result in material adjustments.

A portion of our revenue is recognized using the percentage-of-completion method of accounting. The percentage-of-completion accounting practices that we use result in our recognizing contract revenue and earnings ratably over the contract term based on the proportion of actual costs incurred to our estimated total contract costs. The earnings or losses recognized on individual contracts are based on estimates of contract revenue and costs. We review our estimates of contract revenue, costs and profitability on a monthly basis. Prior to contract completion, we may adjust our estimates on one or more occasions as a result of changes in cost estimates, change orders to the original contract, collection disputes with the customer on amounts invoiced or claims against the customer for extra work or increased cost due to customer-induced delays and other factors. Contract losses are recognized in the fiscal period in which the loss is determined. Contract profit estimates are also adjusted in the fiscal period in which it is determined that an adjustment is required. No restatements are made to prior periods for changes in these estimates. As a result of the requirements of the percentage-of-completion method of accounting, the possibility exists, for example, that we could have estimated and reported a profit on a contract over several prior periods and later determine that all or a portion of such previously estimated and reported profits were overstated or understated. If this occurs, the cumulative impact of the change will be reported in the period in which such determination is made, thereby eliminating all or a portion of any profits related to long-term contracts that would have otherwise been reported in such period or even resulting in a loss being reported for such period.

The dangers inherent in our operations and the limits on insurance coverage could expose us to potentially significant liability costs and materially interfere with the performance of our operations.

Our operations are subject to numerous operating risks inherent in the oil and gas industry that could result in substantial losses. These risks include the following:

	•		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.

These risks affect our provision of oilfield services and equipment, as well as our oil and gas operations. Our liftboats and marine vessels are also subject to operating risks such as catastrophic marine disasters, adverse weather conditions, collisions and navigation errors.

The realization of these risks could result in catastrophic events causing personal injury, loss of life, damage to or destruction of wells, production facilities or other property or equipment, or damages to the environment, which could lead to claims against us for substantial damages. In addition, certain of our employees who perform services on offshore platforms and marine vessels are covered by provisions of the Jones Act, the Death on the High Seas Act and general maritime law. These laws make the liability limits established by federal and state workers’ compensation laws inapplicable to these employees and instead permit them or their representatives to pursue actions against us for damages for job related injuries. Realization of any of the foregoing by our equity-method investments engaged in oil and gas production could result in significant impairment to our equity-method investment balances.

As a result of indemnification obligations contained in most of our customer contracts, we may also be required to indemnify our customers for any damages sustained by our employees or equipment, regardless of whether those damages were caused by us.

We maintain several types of insurance to cover liabilities arising from our operations. These policies include primary and excess umbrella liability policies with limits of $200 million dollars per occurrence, including sudden and accidental pollution incidents. We also maintain property insurance on our physical assets, including marine vessels and operating equipment and platforms and wells. The cost of many of the types of insurance coverage maintained for our oil and gas operations has increased significantly due to losses as a result of hurricanes that

occurred in the Gulf of Mexico in recent years and resulted in the retention of significant additional risk by us and our equity-method investments, primarily through higher insurance deductibles. Also, most of these property insurance policies now have annual aggregate limits, rather than occurrence-based limits, for named storm damages and significantly higher deductibles for wind damage. Very few insurance underwriters offer certain types of insurance coverage maintained by us, and there can be no assurance that any particular type of insurance coverage will continue to be available in the future, that we will not accept retention of additional risk through higher insurance deductibles or otherwise, or that we will be able to purchase our desired level of insurance coverage at commercially feasible rates.

The frequency and severity of incidents related to our operating risks affect our operating costs, insurability, revenue derived from our equity-method investments, and relationships with customers, employees and regulators. Any increase in the frequency or severity of such incidents, or the general level of compensation and damage awards with respect to such incidents, could adversely affect our ability to obtain insurance or projects from oil and gas companies. Also, any significant uninsured losses could have a material adverse effect on our financial position, results of operations and cash flows.

We are vulnerable to the potential difficulties associated with rapid expansion.

We have grown rapidly over the last several years through internal growth and acquisitions of other companies. We believe that our future success depends on our ability to manage the rapid growth that we have experienced and the demands from increased responsibility on our management personnel. The following factors could present difficulties to us:

	•		lack of experienced management-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 that we will be able to identify and acquire acceptable acquisition candidates on terms favorable to us in the future. We may be required to incur substantial indebtedness to finance future acquisitions. Such additional debt service requirements may impose a significant burden on our results of operations and financial condition. We cannot assure you that we will be able to successfully consolidate the operations and assets of any acquired business with our own business. Acquisitions may not perform as expected when the transaction was consummated and may be dilutive to our overall operating results. In addition, our management may not be able to effectively manage our increased size or operate a new line of business.

The nature of our industry subjects us to compliance with regulatory and environmental laws.

Our business is significantly affected by a wide range of local, state and federal statutes, rules, orders and regulations, as well as international laws in the other countries in which we operate, relating to the oil and gas industry in general, and more specifically with respect to the environment, health and safety, waste management and the manufacture, storage, handling and transportation of hazardous wastes. The failure to comply with these rules and regulations can result in the revocation of permits, corrective action orders, administrative or civil penalties and criminal prosecution. Further, laws and regulations in this area are complex and change frequently. Changes in laws or regulations, or their enforcement, could subject us to material costs.

Our operations are also subject to certain requirements under OPA. Under OPA and its implementing regulations, “responsible parties,” including owners and operators of certain vessels, are strictly liable for damages resulting from spills of oil and other related substances in the United States waters, subject to certain limitations. OPA also requires a responsible party to submit proof of its financial ability to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. Further, OPA imposes other requirements, such as the preparation of oil spill response plans. In the event of a substantial oil spill, we could be required to expend

potentially significant amounts of capital which could have a material adverse effect on our future operations and financial results.

We have compliance costs and potential environmental liabilities with respect to our offshore and onshore operations, including our environmental cleaning services. Certain environmental laws provide for joint and several liabilities for remediation of spills and releases of hazardous substances. These environmental statutes may impose liability without regard to negligence or fault. In addition, we may be subject to claims alleging personal injury or property damage as a result of alleged exposure to hazardous substances. We believe that our present operations substantially comply with applicable federal and state pollution control and environmental protection laws and regulations. We also believe that compliance with such laws has not had a material adverse effect on our operations. However, we are unable to predict whether environmental laws and regulations will have a material adverse effect on our future operations and financial results. Sanctions for noncompliance may include revocation of permits, corrective action orders, administrative or civil penalties and criminal prosecution.

Federal, state and local statutes and regulations require permits for plugging and abandonment and reports concerning operations. A decrease in the level of enforcement of such laws and regulations in the future would adversely affect the demand for our services and products. In addition, demand for our services is affected by changing taxes, price controls and other laws and regulations relating to the oil and gas industry generally. The adoption of laws and regulations curtailing exploration and development drilling for oil and gas in our areas of operations for economic, environmental or other policy reasons could also adversely affect our operations by limiting demand for our services.

The regulatory burden on our business increases our costs and, consequently, affects our profitability. We are unable to predict the level of enforcement of existing laws and regulations, how such laws and regulations may be interpreted by enforcement agencies or court rulings, or whether additional laws and regulations will be adopted. We are also unable to predict the effect that any such events may have on us, our business or our financial condition.

A terrorist attack or armed conflict could harm our business.

Terrorist activities, anti-terrorist efforts and other armed conflicts may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our services and causing a reduction in our revenues. Oil and gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to customers’ operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

Regulation of greenhouse gas emissions effects and climate change issues may adversely affect our operations and markets.

The impact and implication of greenhouse gas emissions has received increasing attention, especially in the form of proposals to regulate the emissions. Regulation of emissions has been proposed on an international, national, regional, state and local level. These proposals include an international protocol, which has gone into effect but is not binding on the United States, and numerous bills introduced to the U.S. Congress relating to climate change.

In June 2009, a bill to control and reduce emissions of greenhouse gasses in the United States, was approved by the U.S. House of Representatives. The legislation, often referred to as a “cap-and-trade” system, would limit greenhouse gas emissions while creating a corresponding market for the purchase and sale of emission permits. Although not passed by the U.S. Senate, and therefore not law, the Senate has initiated drafting its own legislation for the control and reduction of greenhouse emissions.

It is not currently feasible to predict whether, or which of, the current greenhouse gas emission proposals will be adopted. In addition, there may be subsequent international treaties, protocols or accords that the United States joins in the future. The potential passage of climate change regulation may impact our operations, however, since it may limit demand and production of fossil fuels by our customers. The impact on our customers, in turn, may adversely affect demand for our products and services, which could adversely impact our operations.

Estimates of our oil and gas reserves and potential liabilities relating to our oil and gas properties may be incorrect.

We acquire mature oil and gas properties in the Gulf of Mexico on an “as is” basis and assume all plugging, abandonment, restoration and environmental liability with limited remedies for breaches of representations and warranties. Acquisitions of these properties require an assessment of a number of factors beyond our control, including estimates of recoverable reserves, future oil and gas prices, operating costs and potential environmental and plugging and abandonment liabilities. These assessments are complex and inherently imprecise, and, with respect to estimates of oil and gas reserves, require significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. In addition, since these properties are typically mature, our facilities and operations may be more susceptible to hurricane damage, equipment failure or mechanical problems. In connection with these assessments, we perform due diligence reviews that we believe are generally consistent with industry practices. However, our reviews may not reveal all existing or potential problems. In addition, our reviews may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We may not always discover structural, subsurface, environmental or other problems that may exist or arise.

Actual future production, cash flows, development expenditures, operating and abandonment expenses and quantities of recoverable oil and gas reserves may vary substantially from those estimated by us and any significant variance in these assumptions could materially affect the estimated quantity and value of our proved reserves. Therefore, the risk is that we may overestimate the value of economically recoverable reserves and/or underestimate the cost of plugging wells and abandoning production facilities. If costs of abandonment are materially greater or actual reserves are materially lower than our estimates, they could have an adverse effect on earnings.

Item 1B. 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 and claims that are incidental to the conduct of our business. Our management does not believe that the outcome of any ongoing proceedings, individually or collectively, would have a material adverse affect on our financial condition, results of operations or cash flows.

Item 4A. Executive Officers of Registrant

David D. Dunlap, age 49, was appointed as our Chief Executive Officer in April 2010 and President in February 2011. Prior to joining us, he was employed by BJ Services Company as its Executive Vice President and Chief Operating Officer since 2007. Mr. Dunlap joined BJ Services in 1984 and held numerous positions during his tenure including President of the International Division, Vice President for the Coastal Division of North America and U.S. Sales and Marketing Manager.

Robert S. Taylor, age 56, has served as our Chief Financial Officer since January 1996, as one of our Executive Vice Presidents since September 2004, and as our Treasurer since July 1999. He also served as one of our Vice Presidents from July 1999 to September 2004.

A. Patrick Bernard, age 53, has served as our Senior Executive Vice President since July 2006 and as one of our Executive Vice Presidents since September 2004. He served as one of our Vice Presidents from June 2003 until September 2004. From July 1999 until June 2003, Mr. Bernard served as the Chief Financial Officer of our wholly-owned subsidiary International Snubbing Services, L.L.C. and its predecessor company.

Patrick J. Campbell, age 66, has served as one of our Executive Vice Presidents since April 2009. Prior to this position, he served as President and Chief Operating Officer of our wholly-owned subsidiary, Wild Well Control, Inc., since 2000. Mr. Campbell joined Wild Well Control in 1990 and served as its Executive Vice President until 2000.

L. Guy Cook, III, age 42, has served as one of our Executive Vice Presidents since September 2004. He has also served as an Executive Vice President of our wholly-owned subsidiary Superior Energy Services, L.L.C., and previously as a Vice President of this subsidiary and its predecessor company since August 2000.

Charles M. Hardy, age 65, has served as one of our Executive Vice Presidents since January 2008. Prior to this position, he served as Vice President and General Manager of our Marine Services division since May 2005, and previously as Vice President of Sales for this same division since August 2004. From July 2000 to July 2004, Mr. Hardy served as Vice President of Operations of Trico Marine Operators, Inc.

Samuel Hardy Jr., age 58, was appointed as one of our Executive Vice Presidents in February 2011. He joined the Company with the acquisition of Warrior Energy Services Corporation in December 2006. Mr. Hardy has served as the Chief Operating Officer of Warrior Energy Services Corporation since August 2000.

William B. Masters, age 53, has served as our General Counsel and one of our Executive Vice Presidents since March 2008. He was previously a partner in the law firm Jones, Walker, Waechter, Poitevent, Carrère & Denègre L.L.P. for more than 20 years.

Danny R. Young, age 55, has served as one of our Executive Vice Presidents since September 2004. Mr. Young has also served as an Executive Vice President of Superior Energy Services, L.L.C. from January 2002 to May 2005, he served as Vice President of Health, Safety and Environment and Corporate Services of Superior Energy Services, L.L.C.

Patrick J. Zuber, age 50, has served as one of our Executive Vice Presidents since January 2008. Prior to joining us, he was employed by Weatherford International, Ltd. from June 1999 to December 2007 and held numerous positions during his tenure including Vice President for the Middle East region, Vice President for the Asia Pacific region and General Manager for the Underbalanced Drilling Division for the Middle East and North Africa region.

PART II

Item 5. 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
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
2010
First Quarter		$	26.45			$	19.52
Second Quarter			28.01				18.54
Third Quarter			27.13				18.69
Fourth Quarter			35.19				25.57

As of February 18, 2011, there were 78,892,650 shares of our common stock outstanding, which were held by 163 record holders.

Dividend Information

We have never paid cash dividends on our common stock. We currently expect to retain all of the cash our business generates to fund the operation and expansion of our business and repurchase stock. In addition, the terms of our credit facility and the indenture governing our 6 7/8% unsecured senior notes due 2014 restrict our ability to pay dividends.

Equity Compensation Plan Information

Information required by this item with respect to compensation plans under which our equity securities are authorized for issuance is incorporated by reference from Part III, Item 12.

Issuer Purchases of Equity Securities

In December 2009, our Board of Directors approved a $350 million share repurchase program that will expire on December 31, 2011. The following table provides information about our common stock repurchased and retired during each month for the three months ended December 31, 2010:

										Total Number				Approximate
										of Shares				Dollar Value of
		Total Number								Purchased as				Shares that May
		of Shares				Average Price Paid				Part of Publicly				Yet be Purchased
Period		Purchased (1)				per Share				Announced Plan (2)				Under the Plan (2)
October 1 - 31, 2010			—			$	—				—			$	350,000,000
November 1 - 30, 2010			—			$	—				—			$	350,000,000
December 1 - 31, 2010			89,391			$	34.60				—			$	350,000,000
October 1, 2010 through
December 31, 2010			89,391			$	34.60				—			$	350,000,000

Performance Graph

The following performance graph and related information shall not be deemed “solicitating material” or “filed” with the Securities and Exchange Commission, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933 or Securities Exchange Act of 1934, except to the extent that we specifically incorporate it by reference into such filing.

The following graph compares the total stockholder return on our common stock for the last five years with the total return on the S&P 500 Stock Index and a Self-Determined Peer Group for the same period. The information in the graph is based on the assumption of a $100 investment on January 1, 2006 at closing prices on December 31, 2005. The comparisons in the graph are required by the Securities and Exchange Commission and are not intended to be a forecast or be indicative of possible future performance of our common stock.

		Years Ended December 31,
		2006				2007				2008				2009				2010
Superior Energy Services, Inc.		$	155			$	164			$	76			$	115			$	166
S&P500 Stock Index		$	116			$	122			$	77			$	97			$	112
Peer Group (Current)		$	116			$	169			$	60			$	100			$	141
Peer Group (Prior)		$	103			$	140			$	54			$	88			$	113

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, 2005.

During 2010, we amended our Self-Determined Peer Group as there was a reduction in the number of peer companies due to merger activity. We believe our current Self-Determined Peer Group better reflects our current size as well as our potential for growth. Our current Self-Determined Peer Group consists of the peer group of 14 companies whose average stockholder return levels comprise part of the performance criteria established by the Compensation Committee under our long-term incentive compensation program: Baker Hughes, Inc., Basic Energy Services, Inc., Cameron International Corp., Complete Production Services, Inc., Global Industries, Ltd., Helix Energy Solutions Group, Inc., Hercules Offshore, Inc., Key Energy Services, Inc., National Oilwell Varco, Inc., Oceaneering International, Inc., Oil States International, Inc., RPC, Inc., Tetra Technologies, Inc. and Weatherford International, Ltd. Our prior Self-Determined Peer Group included Helix Energy Solutions Group, Inc., Helmerich & Payne, Inc., Oceaneering International, Inc., Oil States International, Inc., Pride International, Inc., RPC, Inc., Seacor Holdings Inc., Tetra Technologies, Inc., and Weatherford International, Ltd.

Item 6. 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,
		2010				2009				2008				2007				2006
Revenues		$	1,681,616			$	1,449,300			$	1,881,124			$	1,572,467			$	1,093,821
Income (loss) from operations			168,266				(51,384	)			565,692				465,838				316,889
Net income (loss)			81,817				(102,323	)			351,475				271,558				187,663
Net income (loss) per share:
Basic			1.04				(1.31	)			4.39				3.35				2.35
Diluted			1.03				(1.31	)			4.33				3.30				2.31
Total assets			2,907,533				2,516,665				2,490,145				2,255,295				1,872,067
Long-term debt, net			681,635				848,665				654,199				637,789				622,508
Decommissioning liabilities, less current portion			100,787				—				—				88,158				87,046
Stockholders’ equity			1,280,551				1,178,045				1,254,273				1,025,666				765,237

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with our consolidated financial statements and applicable notes to our consolidated financial statements and other information included elsewhere in this Annual Report on Form 10-K, including risk factors disclosed in Part I, Item 1A. The following information contains forward-looking statements, which are subject to risks and uncertainties. Should one or more of these risks or uncertainties materialize, our actual results may differ from those expressed or implied by the forward-looking statements. See “Forward-Looking Statements” at the beginning of this Annual Report on Form 10-K.

Executive Summary

We believe we are a leading provider of oilfield services and equipment focused on serving the drilling-related needs of oil and gas companies primarily through our drilling products and services segment, and the production-related needs of oil and gas companies through our subsea and well enhancement, drilling products and services and marine segments. We have expanded geographically into select domestic land and international market areas. Through our subsidiary, Wild Well Control, Inc. (Wild Well), and our equity-method investments, we also own oil and gas properties in the Gulf of Mexico.

The financial performance of our various products and services are reported in three operating segments — subsea and well enhancement, drilling products and services, and marine.

Overview of our business segments

The subsea and well enhancement segment consists of specialized down-hole services, which are both labor and equipment intensive. We offer a wide variety of services used to maintain, enhance and extend oil and gas production from mature wells. In 2010, approximately 40% of this segment’s revenue was derived from work performed for customers in the Gulf of Mexico market area (down from 59% in 2009), while approximately 34% of segment revenue was from the domestic land market area (up from 23% in 2009) and approximately 26% of segment revenue was from international market areas (up from 18% in 2009). While our income from operations as a percentage of segment revenue tends to be fairly consistent, special projects such as well control can directly increase our profitability.

The drilling products and services segment is capital intensive with higher operating margins as a result of relatively low operating expenses. The largest fixed cost is depreciation as there is little labor associated with our drilling products and services businesses. The financial performance is primarily a function of changes in volume rather than pricing. In 2010, approximately 32% of segment revenue was derived from the Gulf of Mexico market area (down from 40% in 2009), while approximately 35% of segment revenue was from the domestic land market area (up from 25% in 2009) and approximately 33% of segment revenue was from international market areas (down from 35% in 2009). Three rental products and their ancillary equipment (accommodations, drill pipe and stabilization tools) each accounted for more than 20% of this segment’s revenue in 2010.

The marine segment is comprised of our 25 rental liftboats. Operating costs of our liftboats are relatively fixed, and therefore, income from operations as a percentage of revenue can vary significantly from quarter to quarter and year to year based on changes in dayrates and utilization levels. With most of our liftboats currently operating in the Gulf of Mexico, our activity levels can be impacted by harsh weather, especially tropical systems that occur during hurricane season.

Market drivers and conditions

The oil and gas industry remains highly cyclical and seasonal. Activity levels are driven primarily by traditional energy industry activity indicators, which include current and expected commodity prices, drilling rig counts, well completions and workover activity, geological characteristics of producing wells which determine the number of services required per well, oil and gas production levels, and customers’ spending allocated for drilling and production work, which is reflected in our customers’ operating expenses or capital expenditures.

Historical market indicators are listed below:

						%								%
		2010				Change				2009				Change				2008
Worldwide Rig Count (1)
U.S.			1,546				42	%			1,089				-42	%			1,879
International (2)			1,094				10	%			997				-8	%			1,079
Commodity Prices (average)
Crude Oil (West Texas Intermediate)		$	79.61				27	%		$	62.67				-37	%		$	99.73
Natural Gas (Henry Hub)		$	4.41				3	%		$	4.27				-53	%		$	9.04

As indicated by the table above, the major activity drivers improved in 2010. The average number of drilling rigs working in the United States, which is more weighted toward natural gas drilling than oil drilling, increased 42%, while the international rig count, which is more weighted toward oil drilling than natural gas drilling, increased 10%. The average price of West Texas Intermediate crude oil increased 27% while the average price of natural gas at Henry Hub increased 3% from 2009.

The following table compares our revenues generated from major geographic regions for the years ended December 31, 2010 and 2009 (in thousands). We attribute revenue to countries based on the location where services are performed or the destination of the sale of products.

		Revenue
		2010				%				2009				%				Change
Gulf of Mexico		$	675,836				40	%		$	804,944				56	%		$	(129,108	)
U.S. Domestic Land			540,459				32	%			321,127				22	%			219,332
International			465,321				28	%			323,229				22	%			142,092
Total		$	1,681,616				100	%		$	1,449,300				100	%		$	232,316

Higher oil prices, the increase in drilling rig counts (particularly the number of horizontal drilling rigs in the domestic land market area) and higher overall industry activity increased pricing and utilization for our products and services in all segments, where our domestic land revenue increased 68% to $540.5 million. In this market area, we experienced a 75% increase in revenue from our subsea and well enhancement segment and a 54% increase in revenue from our drilling products and services segment. Within individual product and service lines, the largest increases in the domestic land market area were in coiled tubing, cased hole wireline, pressure control tools, rentals of accommodations and rentals and sales of stabilizers and related equipment.

Our Gulf of Mexico revenue declined 16% to $675.8 million due primarily to the deepwater drilling moratorium and lack of new deepwater drilling permits issued following the Deepwater Horizon incident in April 2010, which curtailed demand for our drilling products and services. In addition, we generated less revenue from special projects as a result of the conclusion of field work on our large-scale decommissioning project. Finally, our Gulf of Mexico liftboat revenue declined as a result of downtime for our two 265-foot class liftboats, which did not return to service until October and November 2010. These liftboats typically generate dayrates of approximately $40,000.

Our international revenue increased 44% to $465.3 million due primarily to the acquisition of Hallin Marine Subsea International Plc (Hallin) in January 2010, and increases in demand for down-hole drilling products in Latin America and hydraulic workover and snubbing services in Europe.

Industry Outlook

We believe drivers of industry demand, commodity prices and drilling rig counts should remain favorable in most geographic market area, with the exception of the Gulf of Mexico. We believe domestic land market areas with high concentrations of horizontal drilling remain underserved for products and services such as coiled tubing, premium drill pipe and ancillary products. Internationally, we will continue to build out market areas, such as Brazil, that provide us the best opportunities to provide as many products and services as possible. As a result, we anticipate that we will continue to grow revenue and earnings from international market areas, but at a slower, more measured pace than the domestic land market area. Accordingly, a significant portion of our capital expenditures in 2011 will be allocated to these areas.

Our Gulf of Mexico operations generally focus on three areas: drilling support, production enhancement and decommissioning (or end of life) services. Our exposure to drilling activity is primarily in the drilling products and services segment. We anticipate that our financial performance from the Gulf of Mexico in this segment will continue to be curtailed due to the lack of drilling in the deepwater Gulf of Mexico market area as a result of the aftermath of the Deepwater Horizon incident. The industry continues in its efforts to interpret and comply with new government regulations to obtain new drilling permits. The pace at which new permits are issued and rigs resume drilling will drive demand for our drilling products and services. Operations in our subsea and well enhancement and marine segments are primarily focused on production enhancement and end of life activities in the shallow water Gulf of Mexico. A new regulatory initiative aimed at removing idle iron in the Gulf of Mexico may increase long-term demand for our plug and abandonment and decommissioning services.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based on our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes. Note 1 to our consolidated financial statements contains a description of the significant accounting policies used in the preparation of our financial statements. We evaluate our estimates on an ongoing basis, including those related to long-lived assets and goodwill, income taxes, allowance for doubtful accounts, long-term construction accounting, self insurance and oil and gas properties. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances. Actual amounts could differ significantly from these estimates under different assumptions and conditions.

We define a critical accounting policy or estimate as one that is both important to our financial condition and results of operations and requires us to make difficult, subjective or complex judgments or estimates about matters that are uncertain. We believe that the following are the critical accounting policies and estimates used in the preparation of our consolidated financial statements. In addition, there are other items within our consolidated financial statements that require estimates but are not deemed critical as defined in this paragraph.

Long-Lived Assets. We review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of any such asset may not be recoverable. We record impairment losses on long-lived assets used in operations when the fair value of those assets is less than their respective carrying amount. Fair value is measured, in part, by the estimated cash flows to be generated by those assets. Our cash flow estimates are based upon, among other things, historical results adjusted to reflect our best estimate of future market rates, utilization levels and operating performance. Our estimates of cash flows may differ from actual cash flows due to, among other things, changes in economic conditions or changes in an asset’s operating performance. Assets are grouped by subsidiary or division for the impairment testing, except for liftboats, which are grouped together by leg length. These groupings represent the lowest level of identifiable cash flows. We have long-lived assets, such as facilities, utilized by multiple operating divisions that do not have identifiable cash flows. Impairment testing for these long-lived assets is based on the consolidated entity. Assets to be disposed of are reported at the lower of the carrying amount or fair value less estimated costs to sell. Our estimate of fair value represents our best estimate based on industry trends and reference to market transactions and is subject to variability. The oil and gas industry is cyclical and our estimates of the period over which future cash flows will be generated, as well as the

predictability of these cash flows, can have a significant impact on the carrying value of these assets and, in periods of prolonged down cycles, may result in impairment charges.

During the fourth quarter of 2010, after a thorough and comprehensive evaluation of liftboat components primarily related to two partially constructed 265-foot class liftboats, we determined that it was impractical to finish the construction of these two vessels. As such, we recorded approximately $32.0 million of a reduction in the value of these tangible assets (property, plant and equipment) within the marine segment (see note 3 to our consolidated financial statements included in Part II, Item 8). We will utilize the remaining components of these vessels as spares for our existing fleet.

During the second quarter of 2009, we recorded approximately $92.7 million of impairment expense in connection with our intangible assets within our subsea and well enhancement segment. This reduction in value of intangible assets was primarily due to the decline in demand for services in the domestic land market area. During the fourth quarter of 2009, the domestic land market area remained depressed and our forecast of this market did not suggest a timely recovery sufficient to support our current carrying values. As such, we recorded approximately $119.8 million of impairment expense related to our tangible assets (property, plant and equipment) within the same segment (see note 3 to our consolidated financial statements included in Part II, Item 8).

Goodwill. In assessing the recoverability of goodwill, we must make assumptions regarding estimated future cash flows and other factors to determine the fair value of the respective assets. We test goodwill for impairment in accordance with authoritative guidance related to goodwill and other intangibles, which requires that goodwill as well as other intangible assets with indefinite lives not be amortized, but instead tested annually for impairment. Our annual testing of goodwill is based on carrying value and our estimate of fair value at December 31. We estimate the fair value of each of our reporting units (which are consistent with our business segments) using various cash flow and earnings projections discounted at a rate estimated to approximate the reporting units’ weighted average cost of capital. We then compare these fair value estimates to the carrying value of our reporting units. If the fair value of the reporting units exceeds the carrying amount, no impairment loss is recognized. Our estimates of the fair value of these reporting units represent our best estimates based on industry trends and reference to market transactions. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events.

Based on business conditions and market values that existed at December 31, 2010, we concluded that no goodwill impairment loss was required. Even though we recognized a $32.0 million reduction in the value of liftboat components within the marine segment in 2010, the estimated future cash flows used in the fair value calculation of this segment from the remainder of the fleet was more than sufficient to support the carrying value of this reporting unit.

Income Taxes. We use the asset and liability method of accounting for income taxes. This method takes into account the differences between financial statement treatment and tax treatment of certain transactions. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. Our deferred tax calculation requires us to make certain estimates about our future operations. Changes in state, federal and foreign tax laws, as well as changes in our financial condition or the carrying value of existing assets and liabilities, could affect these estimates. The effect of a change in tax rates is recognized as income or expense in the period that the rate is enacted.

Allowance for Doubtful Accounts. We maintain an allowance for doubtful accounts for estimated losses resulting from the inability of some of our customers to make required payments. These estimated allowances are periodically reviewed on a case by case basis, analyzing the customer’s payment history and information regarding the customer’s creditworthiness known to us. In addition, we record a reserve based on the size and age of all receivable balances against those balances that do not have specific reserves. If the financial condition of our customers deteriorates, resulting in their inability to make payments, additional allowances may be required.

Revenue Recognition. Our products and services are generally sold based upon purchase orders or contracts with customers that include fixed or determinable prices. We recognize revenue when services or equipment are

provided and collectability is reasonably assured. We contract for marine, subsea and well enhancement and environmental projects either on a day rate or turnkey basis, with a majority of our projects conducted on a day rate basis. The products we rent within our drilling products and services segment are rented on a day rate basis, and revenue from the sale of equipment is recognized when the equipment is shipped.

Long-Term Construction Accounting for Revenue and Profit (Loss) Recognition. A portion of our revenue is derived from long-term contracts. For contracts that meet the criteria under the authoritative guidance related to construction-type and production-type contracts, we recognize revenues on the percentage-of-completion method, primarily based on costs incurred to date compared with total estimated contract costs. It is possible there will be future and currently unforeseeable significant adjustments to our estimated contract revenues, costs and profitability for contracts currently in process. These adjustments could, depending on the magnitude of the adjustments, materially, positively or negatively, affect our operating results in an annual or quarterly reporting period. To the extent that an adjustment in the estimated total contract cost impacts estimated profit of the contract, the cumulative change to revenue and profitability is reflected in the period in which this adjustment in estimate is identified. The accuracy of the revenue and estimated earnings we report for fixed-price contracts is dependent upon the judgments we make in estimating our contract performance and contract revenue and costs.

We use the percentage-of-completion method for recognizing our revenues and related costs on our contract to decommission seven downed oil and gas platforms and related well facilities located in the Gulf of Mexico. During the fourth quarter of 2009, as the project to decommission seven downed oil and gas platforms and well facilities neared completion, we determined it was necessary to increase the total cost estimate due to various well conditions and other technical issues associated with this complex and challenging project (see note 5 to our consolidated financial statements included in Part II, Item 8).

Self Insurance. We self insure, through deductibles and retentions, up to certain levels for losses related to workers’ compensation, third party liability insurances, property damage, and group medical. With our growth, we have elected to retain more risk by increasing our self insurance. We accrue for these liabilities based on estimates of the ultimate cost of claims incurred as of the balance sheet date. We regularly review our estimates of reported and unreported claims and provide for losses through reserves. We also have actuarial reviews of our estimates for losses related to workers’ compensation and group medical on an annual basis. While we believe these estimates are reasonable based on the information available, our financial results could be impacted if litigation trends, claims settlement patterns and future inflation rates are different from our estimates. Although we believe adequate reserves have been provided for expected liabilities arising from our self insured obligations, and we believe that we maintain adequate insurance coverage, we cannot assure that such coverage will adequately protect us against liability from all potential consequences.

Oil and Gas Properties. Our subsidiary, Wild Well, and our equity-method investments, SPN Resources and DBH, acquire mature oil and gas properties and assume the related well abandonment and decommissioning liabilities. Each of these entities follows the successful efforts method of accounting for their investment in oil and natural gas properties. Under the successful efforts method, the costs of successful exploratory wells and leases containing productive reserves are capitalized. Costs incurred to drill and equip developmental wells, including unsuccessful developmental wells, are capitalized. Other costs such as geological and geophysical costs and the drilling costs of unsuccessful exploratory wells are expensed. Wild Well’s property purchase was recorded at the value exchanged at closing, combined with an estimate of its proportionate share of the decommissioning liability assumed in the purchase. All capitalized costs are accumulated and recorded separately for each field and allocated to leasehold costs and well costs. Leasehold costs and well costs are depleted on a units-of-production basis based on the estimated remaining equivalent proved developed oil and gas reserves of each field.

We estimate the third party market price to plug and abandon wells, abandon the pipelines, decommission and remove the platforms and clear the sites, and use that estimate to record our proportionate share of the decommissioning liability. In estimating the decommissioning liabilities, we perform detailed estimating procedures, analysis and engineering studies. Whenever practical, we will utilize the services of our subsidiaries to perform well abandonment and decommissioning work. When these services are performed by our subsidiaries, all recorded intercompany revenues and expenses are eliminated in the consolidated financial statements. The recorded decommissioning liability associated with a specific property is fully extinguished when the property is completely abandoned. The liability is first reduced by all cash expenses incurred to abandon and decommission the property.

If the liability exceeds (or is less than) our incurred costs, the difference is reported as income (or loss) in the period in which the work is performed. We review the adequacy of our decommissioning liability whenever indicators suggest that the estimated cash flows underlying the liability have changed materially. The timing and amounts of these cash flows are subject to changes in the energy industry environment and may result in additional liabilities recorded, which in turn would increase the carrying values of the related properties.

Oil and gas properties are assessed for impairment in value on a field-by-field basis whenever indicators become evident. We use our current estimate of future revenues and operating expenses to test the capitalized costs for impairment. In the event net undiscounted cash flows are less than the carrying value, an impairment loss is recorded based on the present value of expected future net cash flows over the economic lives of the reserves.

Proved Reserve Estimates. Our reserve information is prepared by independent reserve engineers in accordance with guidelines established by the Securities and Exchange Commission. There are a number of uncertainties inherent in estimating quantities of proved reserves, including many factors beyond our control such as commodity pricing. Reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. In accordance with the Securities and Exchange Commission’s guidelines, we use twelve month average prices, year end costs and a 10% discount rate to determine the present value of future net cash flow. Actual prices and costs may vary significantly, and the discount rate may or may not be appropriate based on outside economic conditions.

Comparison of the Results of Operations for the Years Ended December 31, 2010 and 2009

For the year ended December 31, 2010, our revenue was $1,681.6 million and our net income was $81.8 million, or $1.03 diluted earnings per share. Included in the results for the year ended December 31, 2010 were pre-tax management transition expenses of approximately $35.0 million, as well as non-cash pre-tax charges of $32.0 million for the reduction in value of assets within our marine segment. For the year ended December 31, 2009, our revenue was $1,449.3 million and net loss was $102.3 million, or $1.31 loss per share. Net loss for the year ended December 31, 2009 included a non-cash, pre-tax charge of $212.5 million for the reduction in value of assets within our subsea and well enhancement segment and $36.5 million for the reduction in value of our remaining equity-method investment in Beryl Oil and Gas L.P. (BOG). Also included in the results for the year ended December 31, 2009 were losses of $18.0 million from our share of equity-method investments and $4.6 million of other non-cash charges related to SPN Resources.

The following table compares our operating results for the years ended December 31, 2010 and 2009 (in thousands). Cost of services, rentals and sales excludes depreciation, depletion, amortization and accretion for each of our business segments.

		Revenue												Cost of Services, Rentals and Sales
		2010				2009				Change				2010				%				2009				%				Change
Subsea and Well Enhancement		$	1,112,662			$	919,335			$	193,327			$	675,447				61	%		$	616,116				67	%		$	59,331
Drilling Products and Services			474,707				426,876				47,831				176,453				37	%			143,802				34	%			32,651
Marine			94,247				103,089				(8,842	)			66,813				71	%			64,116				62	%			2,697
Total		$	1,681,616			$	1,449,300			$	232,316			$	918,713				55	%		$	824,034				57	%		$	94,679

The following discussion analyzes our results on a segment basis.

Subsea and Well Enhancement Segment

Revenue for our subsea and well enhancement segment was $1,112.7 million for the year ended December 31, 2010, as compared to $919.3 million for 2009. Our increase in revenue and profitability is primarily due to demand increases in the domestic land and international market areas. Revenue from our domestic land market area increased approximately 75% due to demand for coiled tubing, cased hole wireline, well control services and hydraulic workover and snubbing services. Additionally, revenue from our international market areas increased approximately 77% primarily due to our acquisition of Hallin along with increased revenue from our well control services and hydraulic workover and snubbing services. Revenue from our Gulf of Mexico market area decreased approximately 18% primarily based on a decline in revenue from work associated with our large-scale decommissioning project. This decrease was partially offset by increased well control work and plug and abandonment activity, as well as our acquisitions of Superior Completion Services and the Bullwinkle platform.

Cost of services decreased to 61% of segment revenue in 2010, as compared to 67% of segment revenue in 2009. Similar to revenue, our profitability increased due to increased demand for coiled tubing, cased hole wireline, well control services and hydraulic workover and snubbing services. Additionally, cost of services as a percentage of revenue for 2009 was impacted due to the adjustment related to our large-scale decommissioning project. During the fourth quarter of 2009 as we neared completion of this project, we determined it was necessary to increase our total cost estimate due to various well conditions and other technical issues associated with this complex and challenging project. As the revenue related to this long-term contract is recorded on the percentage-of-completion method utilizing costs incurred as a percentage of total estimated costs, the cumulative effect of changes to estimated total contract costs was recognized in the period in which revisions were identified.

Drilling Products and Services Segment

Revenue for our drilling products and services segment was $474.7 million for the year ended December 31, 2010, an approximate 11% increase from 2009. Cost of services increased to 37% of segment revenue in 2010 from 34% in 2009. The increase in revenue for this segment is primarily related to rentals of our accommodation units and specialty tubulars, specifically in our domestic land market area. Revenue in our domestic land market area increased approximately 54% for the year ended December 31, 2010 over the same period in 2009. Revenue generated from our international market areas increased approximately 5%. Revenue from our Gulf of Mexico market area decreased approximately 11% due to decreased demand for specialty tubulars and stabilization equipment as a result of the lingering effects of the deepwater drilling moratorium. The decrease in demand for specialty tubulars was partially offset by an increase in demand for accommodation rentals, which benefited from oil spill cleanup efforts. Cost of services as a percentage of revenue increased 4% as rentals from high-margin drill pipe, specialty tubulars and stabilization equipment fell significantly in the Gulf of Mexico due to the deepwater drilling moratorium.

Marine Segment

Our marine segment revenue for the year ended December 31, 2010 decreased 9% from 2009 to $94.3 million. Our cost of services percentage increased to 71% of segment revenue for the year ended December 31, 2010 from 62% in 2009 primarily due to increased liftboat inspections and maintenance costs coupled with decreased revenue. Due to the high fixed cost nature of this segment, cost of services does not fluctuate proportionately with revenue. The fleet’s average utilization increased to approximately 67% in 2010 from 52% in 2009. However, the fleet’s average dayrate decreased to approximately $13,600 in 2010 from $16,800 in 2009. The average dayrate decreased as several of our larger liftboats were not available for work due to inspections and repairs. Both of our 250-foot class liftboats were out of service for an extended period of time for U.S. Coast Guard inspections. Additionally, our two completed 265-foot class liftboats recently returned to service in October and November of 2010 after being out of service for repairs since November 2009. In December 2010, we also sold one of our 175-foot class liftboats for $5.4 million and recorded a gain of approximately $1.1 million.

Depreciation, Depletion, Amortization and Accretion

Depreciation, depletion, amortization and accretion increased to $220.8 million for the year ended December 31, 2010 from $207.1 million in 2009. Depreciation, depletion, amortization and accretion expense related to our subsea and well enhancement segment increased $5.3 million, or 6%, in 2010 from the same period in 2009. Increases in depreciation, depletion, amortization and accretion related to the acquisitions of Superior Completion Services, Hallin and the Bullwinkle platform, along with 2009 and 2010 capital expenditures, were offset by the decrease in depreciation and amortization as a result of the $212.5 million reduction in value of assets related to our domestic land market area recorded in 2009. Depreciation and amortization expense increased within our drilling products and services segment by $9.1 million, or 9%, due to 2009 and 2010 capital expenditures. Depreciation expense related to the marine segment decreased $0.7 million, or 6%. The decrease in depreciation expense in our marine segment is attributable to the fact that our 250-foot class liftboats were out of service for an extended period of time for U.S. Coast Guard inspections and our two completed 265-foot class liftboats returned to service in the October and November of 2010 after being out of the service for repairs since November 2009.

General and Administrative Expenses

General and administrative expenses increased to $342.9 million for the year ended December 31, 2010 from $259.1 million in 2009. Included in this increase is approximately $35.0 million of management transition expenses. Additional increases in general and administrative expenses include the acquisitions of Superior Completion Services and Hallin, as well as increased bonus and compensation expense due to our improved performance, and additional infrastructure to enhance our growth.

Reduction in Value of Assets

During the fourth quarter of 2010, we recorded a reduction in the value of assets totaling $32.0 million in connection with liftboat components primarily related to our two partially completed 265-foot class liftboats. After a detailed evaluation, we concluded in December that it was impractical to complete these vessels. As such, we reduced our carrying value in these assets to their respective net realizable value and will utilize the remaining components as spares for our existing fleet.

During the second quarter of 2009, we recorded an expense of approximately $92.7 million in connection with intangible assets within our subsea and well enhancement segment. This reduction in value of intangible assets was primarily due to the decline in demand for services in the domestic land market area. During the fourth quarter of 2009, the domestic land market area remained depressed and our forecast of this market did not suggest a timely recovery sufficient to support our current carrying values. As such, we recorded an expense of approximately $119.8 million related to our tangible assets (property, plant and equipment) within the same segment.

Additionally in 2009, we recorded a $36.5 million expense to write off our remaining investment in BOG, an equity-method investment in which we owned a 40% interest. In April 2009, BOG defaulted under its loan agreements due primarily to the impact of production curtailments from Hurricanes Gustav and Ike in 2008 and the decline of natural gas and oil prices. As a result of continued negative BOG operating results, lack of viable interested buyers and unsuccessful attempts to renegotiate the terms and conditions of BOG’s loan agreements, we wrote off the remaining carrying value of our investment in BOG.

Comparison of the Results of Operations for the Years Ended December 31, 2009 and 2008

For the year ended December 31, 2009, our revenue was $1,449.3 million and our net loss was $102.3 million, or $1.31 loss per share. Included in the results for the year ended December 31, 2009 were non-cash, pre-tax charges of $212.5 million for the reduction in value of assets within our subsea and well enhancement segment and $36.5 million for the reduction in value of our remaining equity-method investment in BOG. Also included in the results for the year ended December 31, 2009 were losses of $18.0 million from our share of equity-method investments and $4.6 million of other non-cash charges related to SPN Resources. For the year ended December 31, 2008, revenue was $1,881.1 million, and net income was $351.5 million or $4.33 diluted earnings per share. Net income for the year ended December 31, 2008 included a $40.9 million gain from the sale of businesses. Revenue across all segments was lower in 2009 as compared to 2008 as a result of the significant downturn in commodity prices, the drilling rig count and overall industry activity. Revenue in our oil and gas segment decreased due the fact that we sold 75% of our interest in SPN Resources in March 2008. SPN Resources represented substantially all of our operating oil and gas segment. Subsequent to the sale of our interest on March 14, 2008, we account for our remaining interest in SPN Resources using the equity-method.

The following table compares our operating results for the years ended December 31, 2009 and 2008 (in thousands). Cost of services, rentals and sales excludes depreciation, depletion, amortization and accretion for each of our business segments. Oil and gas eliminations represent products and services provided to the oil and gas segment by our other segments.

		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

Revenue for our subsea and well enhancement segment was $919.3 million for the year ended December 31, 2009, as compared to $1,155.2 million for 2008. Cost of services increased to 67% of segment revenue in 2009, as compared to 55% of segment revenue in 2008. Our revenue decreased 20% due to a $139.5 million decrease in our domestic land business as a result of the significant downturn in commodity prices, the drilling rig count and overall industry activity in North America. Additionally, our revenue from a large-scale platform decommissioning project decreased approximately 29% due to the combination of less work being performed coupled with an increase in the estimated total cost of this project. During the fourth quarter of 2009 as we neared completion of this project, we determined it was necessary to increase our total cost estimate due to various well conditions and other technical issues associated with this complex and challenging project. As the revenue related to this long-term contract is recorded on the percentage-of-completion method utilizing costs incurred as a percentage of total estimated costs, the cumulative effect of changes to estimated total contract costs was recognized in the period in which revisions were identified. Revenue from international market areas grew 11% in 2009 due to an increase in emergency well control work and the commencement of three projects off the coast of Angola.

Drilling Products and Services Segment

Revenue for our drilling products and services segment was $426.9 million for the year ended December 31, 2009, an approximate 23% decrease from 2008. Cost of services increased to 34% of segment revenue in 2009 from 32% in 2008. The decrease in drilling products and services revenue is primarily related to a decrease in the rentals of our on-site accommodation units and stabilization equipment, specifically in the domestic land market area, and rentals of our drill pipe and stabilization equipment in international market areas. Drilling products and services revenue in our domestic land market area decreased 42% to approximately $108.4 million in 2009 from 2008. Additionally, drilling products and services revenue generated from the Gulf of Mexico and international market areas decreased by 14% and 10%, respectively, in 2009 from 2008.

Marine Segment

Our marine segment revenue for the year ended December 31, 2009 decreased 15% from 2008 to $103.1 million. Cost of services as a percentage of revenue remained constant at 62% in 2009 and 2008. The fleet’s average utilization decreased to approximately 52% in 2009 from 66% in 2008. The utilization decrease was offset by an increase in the fleet’s average dayrate, which increased 8% to approximately $16,800 in 2009 from $15,600 in 2008. The increase in average dayrate was primarily due to the addition of two 265-foot class vessels in the second quarter of 2009. Generally, cost of services does not fluctuate proportionately with revenue due to the high fixed costs associated with this segment; thus, a decrease in revenue would typically result in higher cost of service as a percentage of revenue. However, during 2008, we incurred substantial costs for maintenance to our liftboat fleet. Additionally, we benefited from a decrease in insurance expense in 2009 as a result of our favorable loss history and more competitive marine insurance markets.

In the fourth quarter of 2009, our two 265-foot class liftboats were removed from service following damage to one of the vessels during Hurricane Ida. Both vessels returned to service in the fourth quarter of 2010. Additionally, we sold four liftboats from our 145 — 155-foot class for approximately $7.7 million and recorded a gain of approximately $2.1 million.

Oil and Gas Segment

In March 2008, we sold 75% of our interest in SPN Resources for approximately $167.2 million and recorded a pre-tax gain on sale of this business of approximately $37.1 million. SPN Resources represented substantially all of our oil and gas segment. Subsequent to the sale of our interest on March 14, 2008, we account for our remaining interest in SPN Resources using the equity-method.

Depreciation, Depletion, Amortization and Accretion

Depreciation, depletion, amortization and accretion increased to $207.1 million for the year ended December 31, 2009 from $175.5 million in 2008. Depreciation and amortization expense related to our subsea and well enhancement segment increased $17.8 million, or 25%, in 2009 from the same period in 2008. The increase in depreciation and amortization expense for this segment is primarily attributable to our 2009 and 2008 capital expenditures partially offset by a decrease in the amortization expense as a result of a $92.7 million reduction in the value of amortizable intangible assets in the second quarter of 2009. Depreciation and amortization expense related to our drilling products and services segment increased $15.2 million, or 17%, in 2009 from the same period in 2008 primarily due to our 2009 and 2008 capital expenditures. Depreciation expense related to the marine segment in 2009 increased approximately $1.4 million, or 14%, from 2008. The increase in depreciation expense for the marine segment is primarily attributable to the delivery of two new vessels, which was partially offset by lower utilization.

General and Administrative Expenses

General and administrative expenses decreased to $259.1 million for the year ended December 31, 2009 from $282.6 million in 2008. General and administrative expenses related to our subsea and well enhancement and drilling products and services segments decreased $21.8 million, or 8%, from 2008 to 2009. The decrease in general and administrative expense within these two segments is primarily related to decreased incentive compensation expenses. General and administrative expenses related to our marine segment increased $7.1 million primarily due to the expense incurred as a result of the write-down of components from one of our 265-foot class liftboats in the fourth quarter of 2009.

Reduction in Value of Assets

During the second quarter of 2009, we recorded an expense of approximately $92.7 million in connection with intangible assets within our subsea and well enhancement segment. This reduction in value of intangible assets was primarily due to the decline in demand for services in the domestic land market area. During the fourth quarter of 2009, the domestic land market area remained depressed and our forecast of this market did not suggest a timely

recovery sufficient to support our current carrying values. As such, we recorded an expense of approximately $119.8 million related to our tangible assets (property, plant and equipment) within the same segment.

Additionally, we recorded a $36.5 million expense to write off our remaining investment in BOG, an equity-method investment in which we owned a 40% interest. In April 2009, BOG defaulted under its loan agreements due primarily to the impact of production curtailments from Hurricanes Gustav and Ike in 2008 and the decline of natural gas and oil prices. As a result of continued negative BOG operating results, lack of viable interested buyers and unsuccessful attempts to renegotiate the terms and conditions of BOG’s loan agreements, we wrote off the remaining carrying value of our investment in BOG.

Liquidity and Capital Resources

In the year ended December 31, 2010, we generated net cash from operating activities of $456.0 million as compared to $276.1 million in 2009. This increase is primarily attributable to the billings and receipt of payments related to the large-scale decommissioning contract in the Gulf of Mexico. Included in other current assets is approximately $144.5 million and $209.5 million at December 31, 2010 and 2009, respectively, of costs and estimated earnings in excess of billings related to this project. Billings, and subsequent receipts, are based on the completion of milestones.

Our primary liquidity needs are for working capital, and to fund capital expenditures, debt service and acquisitions. Our primary sources of liquidity are cash flows from operations and available borrowings under our revolving credit facility. We had cash and cash equivalents of $50.7 million and $206.5 million at December 31, 2010 and 2009, respectively. At December 31, 2009, $167.1 million was held in a foreign account in anticipation of the January 2010 acquisition of Hallin.

We spent $323.2 million of cash on capital expenditures during the year ended December 31, 2010. Approximately $142.9 million was used to expand and maintain our drilling products and services equipment inventory, approximately $30.0 million was spent on our marine segment and approximately $150.3 million was used to expand and maintain the asset base of our subsea and well enhancement segment.

In August 2010, we acquired certain assets used in Baker Hughes’ Gulf of Mexico stimulation and sand control business (currently operating as Superior Completion Services), for approximately $54.3 million of cash. Baker Hughes was required to divest this business by the Department of Justice in connection with its acquisition of BJ Services Company. The acquisition of these assets, along with a manufacturing facility and related product line, provides us greater exposure to well completions and intervention projects earlier in the life cycle of the well.

In January 2010, we acquired Hallin for approximately $162.3 million of cash. Additionally, we repaid approximately $55.5 million of Hallin’s debt. Hallin is an international provider of integrated subsea services and engineering solutions, focused on installing, maintaining and extending the life of subsea wells. Hallin operates in international offshore oil and gas markets with offices and facilities located in Singapore, Indonesia, Australia, Scotland and the United States.

In July 2010, we amended our bank revolving credit facility to increase the borrowing capacity to $400 million from $325 million, with the right, at our option, to increase the borrowing capacity of the facility to $550 million. Any amounts outstanding under the revolving credit facility are due on July 20, 2014. At December 31, 2010, we had $175.0 million outstanding under the bank credit facility with a weighted average interest rate of 3.4% per annum. Our borrowings under the revolving credit facility remained essentially constant during 2010. We anticipate collecting $144.5 million late in the first half of 2011 in connection with the large-scale platform decommissioning project in the Gulf of Mexico, pending certain regulatory approvals. At February 18, 2011, we had $161.5 million outstanding under the bank credit facility with a weighted average interest rate of 3.6% per annum. We also had $8.3 million of letters of credit outstanding, which reduces our borrowing capacity under this credit facility. Borrowings under the credit facility bear interest at LIBOR plus margins that depend on our leverage ratio. Indebtedness under the credit facility is secured by substantially all of our assets, including the pledge of the stock of our principal subsidiaries. The credit facility contains customary events of default and requires that we satisfy various financial covenants. It also limits our ability to pay dividends or make other distributions, make acquisitions, create liens or incur additional indebtedness.

At December 31, 2010, we had outstanding $13.4 million in U.S. Government guaranteed long-term financing under Title XI of the Merchant Marine Act of 1936, which is administered by the Maritime Administration (MARAD), for two 245-foot class liftboats. This debt bears an interest rate of 6.45% per annum and is payable in equal semi-annual installments of $405,000 on June 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.

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.

The Company’s current long-term issuer credit rating is BB+ by Standard and Poor’s and Ba3 by Moody’s. Our credit rating may be impacted by the rating agencies’ view of the cyclical nature of our industry sector.

We also have outstanding $400 million of 1.50% senior exchangeable notes due 2026. The exchangeable notes bear interest at a rate of 1.50% per annum and decrease to 1.25% per annum on December 15, 2011. Interest on the exchangeable notes is payable semi-annually in arrears on December 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 exchange rate is equal to an initial exchange price of $45.58 per share. The exchange price represents a 35% premium over the closing share price at the date of issuance. The notes may be exchanged under the following circumstances:

	•		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.

Holders of the senior exchangeable notes may also require us to purchase all or a portion of their notes on December 15, 2011, December 15, 2016 and December 15, 2021 subject to certain administrative formalities. In each case, the purchase price payable will be equal to 100% of the principal amount of the notes to be purchased plus any accrued and unpaid interest with all amounts payable in cash.

As the holders of the senior exchangeable notes have the ability to require us to purchase all of their notes on December 15, 2011, these notes are deemed to be a current liability as of December 31, 2010. In accordance with authoritative guidance related to the classification of short-term debt that is expected to be refinanced, we utilized the amount available under our current bank revolving credit facility of approximately $216.0 million at December 31, 2010 and classified this portion of the senior exchangeable notes as long-term under the assumption that the revolving credit facility could be used to refinance this debt, if required.

We also have the option to redeem for cash the senior exchangeable notes at any time on or after December 15, 2011 at a price equal to 100% of the principal amount to be redeemed plus accrued and unpaid interest. During 2011, we intend to incur additional debt in order to refinance these notes in December 2011 through either the exercise of our redemption right or the note holder purchase option.

In connection with the issuance of the exchangeable notes, we entered into agreements with affiliates of the initial purchasers to purchase call options and sell warrants on our common stock. We may exercise the call options we purchased at any time to acquire approximately 8.8 million shares of our common stock at a strike price of $45.58 per share. The owners of the warrants may exercise the warrants to purchase from us approximately 8.8 million shares of our common stock at a price of $59.42 per share, subject to certain anti-dilution and other customary adjustments. The warrants may be settled in cash, in common stock or in a combination of cash and common stock, at our option. These transactions may potentially reduce the dilution of our common stock from the exchange of the notes by increasing the effective exchange price to $59.42 per share. Lehman Brothers OTC Derivatives, Inc. (LBOTC) is the counterparty to 50% of our call option and warrant transactions. In October 2008, LBOTC filed for bankruptcy protection. We continue to carefully monitor the developments affecting LBOTC. Although we may not retain the benefit of the call option due to LBOTC’s bankruptcy, we do not expect that there will be a material impact, if any, on the financial statements or results of operations. The call option and warrant transactions described above do not affect the terms of the outstanding exchangeable notes.

The following table summarizes our contractual cash obligations and commercial commitments at December 31, 2010 (amounts in thousands). We do not have any other material obligations or commitments.

Description		2011				2012				2013				2014				2015				Thereafter
Long-term debt, including estimated interest payments		$	220,969			$	42,325			$	42,706			$	715,913			$	1,449			$	12,904
Capital lease obligations, including estimated interest payments			6,225				6,225				6,225				6,225				6,225				19,194
Decommissioning liabilities			16,929				3,146				8,023				6,903				1,279				81,436
Operating leases			14,313				9,611				7,008				5,787				3,511				19,415
Vessel Construction			37,292				29,834				—				—				—				—
Other long-term liabilities			—				15,348				17,543				14,886				7,509				26,438
Total		$	295,278			$	106,489			$	81,505			$	749,714			$	19,973			$	159,387

We currently believe that we will spend approximately $500 million on capital expenditures, excluding acquisitions, during 2011. We believe that our current working capital, cash generated from our operations and availability under our revolving credit facility will provide sufficient funds for our identified capital projects.

In May 2010, we signed a contract for construction of a compact semi-submersible vessel. This vessel is designed for both shallow and deepwater conditions and will be capable of performing subsea construction, inspection, repairs and maintenance work as well as subsea light well intervention and abandonment work.

We intend to continue implementing our growth strategy of increasing our scope of services through both internal growth and strategic acquisitions. We expect to continue to make the capital expenditures required to implement our growth strategy in amounts consistent with the amount of cash generated from operating activities, the availability of additional financing and our credit facility. Depending on the size of any future acquisitions, we may require additional equity or debt financing in excess of our current working capital and amounts available under our revolving credit facility.

Off-Balance Sheet Arrangements

We have no off-balance sheet financing arrangements other than potential additional consideration that may be payable as a result of the future operating performances of certain acquisitions. At December 31, 2010, the maximum additional consideration payable for these acquisitions was approximately $4.0 million. Since these acquisitions occurred before we adopted the revised authoritative guidance for business combinations, these amounts are not classified as liabilities and are not reflected in our financial statements until the amounts are fixed and determinable. When amounts are determined, they are capitalized as part of the purchase price of the related acquisition. We do not have any other financing arrangements that are not required under generally accepted accounting principles to be reflected in our financial statements. During the year ended December 31, 2010, we paid additional consideration of approximately $15.3 million as a result of prior acquisitions.

Hedging Activities

In an effort to achieve a more balanced debt portfolio by targeting an overall desired position of fixed and floating rates, we entered into an interest rate swap in March 2010 whereby we are entitled to receive semi-annual interest payments at a fixed rate of 6 7/8% per annum and are obligated to make quarterly interest payments at a variable rate. Interest rate swap agreements that are effective at hedging the fair value of fixed-rate debt agreements are designated and accounted for as fair value hedges. At December 31, 2010, we had fixed-rate interest on approximately 63% of our long-term debt. As of December 31, 2010, we had a notional amount of $150 million related to this interest rate swap with a variable interest rate, which is adjusted every 90 days, based on LIBOR plus a fixed margin.

From time to time, we enter into forward foreign exchange contracts to mitigate the impact of foreign currency fluctuations. The forward foreign exchange contracts we enter into generally have maturities ranging from one to eighteen months. We do not enter into forward foreign exchange contracts for trading purposes. During the years ended December 31, 2010 and 2009, we held outstanding foreign currency forward contracts in order to hedge exposure to currency fluctuations. These contracts were not accounted for as hedges and were marked to fair market value each period. As of December 31, 2010, we had no outstanding foreign currency forward contracts.

Recently Issued Accounting Pronouncements

In January 2010, the Financial Accounting Standards Board issued Accounting Standards Update 2010-03 (ASU 2010-03), “Oil and Gas Reserve Estimation and Disclosures.” The update provides an amendment to Accounting Standards Codification 932 (ASC 932), “Extractive Activities — Oil and Gas,” that expands the definition of oil- and gas-producing activities and requires disclosures of reserve quantities and standardized measure of cash flows for equity-method investments that have significant oil- and gas-producing activities. ASU 2010-03 is effective for annual reporting periods ending on or after December 31, 2009. ASU 2010-03 allows an entity that becomes subject to the disclosure requirements of ASC 932 due to the change to the definition of significant oil- and gas-producing activities to apply the disclosure provisions of ASC 932 in annual periods beginning after December 31, 2009. As such, we included the disclosures required by ASU 2010-03 for our annual reporting period ended December 31, 2010.

On January 1, 2010, we adopted Accounting Standards Codification 810-10 (ASC 810-10), “Amendments to FASB Interpretation No. 46(R), Consolidation of Variable Interest Entities,” for determining whether an entity is a variable interest entity (VIE) and requires an enterprise to perform an analysis to determine whether the enterprise’s variable interest or interests give it a controlling financial interest in a VIE. ASC 810-10 also requires ongoing assessments of whether an enterprise is the primary beneficiary of a VIE, requires enhanced disclosures and eliminates the scope exclusion for qualifying special-purpose entities. The adoption of ASC 810-10 did not have a significant impact on our results of operations and financial position.

On January 1, 2010, we adopted Accounting Standards Update 2010-06 (ASU 2010-06), “Improving Disclosures about Fair Value Measurements.” The update provides an amendment to ASC 820-10, “Fair Value Measurements and Disclosures,” requiring additional disclosures of significant transfers between Level 1 and Level 2 within the fair value hierarchy, as well as information about purchases, sales, issuances and settlements using unobservable inputs (Level 3). ASU 2010-06 is effective for interim and annual reporting periods beginning after December 15,

2009 for new disclosures and clarifications of existing disclosures, except for disclosures about purchases, sales, issuances and settlements in the rollforward of activity in the Level 3 fair value measurements, which are effective for fiscal years beginning after December 15, 2010. The adoption of ASU 2010-06 did not have a significant impact on our results of operations and financial position.

In October 2009, the Financial Accounting Standards Board issued Accounting Standards Update 2009-13 (ASU 2009-13), “Multiple-Deliverable Revenue Arrangements.” The new standard changes the requirements for establishing separate units of accounting in a multiple element arrangement and requires the allocation of arrangement consideration to each deliverable based on the relative selling price. The selling price for each deliverable is based on vendor-specific objective evidence (VSOE) if available, third-party evidence if VSOE is not available, or estimated selling price if neither VSOE or third-party evidence is available. ASU 2009-13 is effective for revenue arrangements entered into in fiscal years beginning on or after June 15, 2010. We do not expect that the impact the adoption of ASU 2009-13 will have a significant impact on our results of operations and financial position.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

We are exposed to market risks associated with foreign currency fluctuations and changes in interest rates. A discussion of our market risk exposure in financial instruments follows.

Foreign Currency Exchange Rates

Because we operate in a number of countries throughout the world, we conduct a portion of our business in currencies other than the U.S. dollar. The functional currency for our international operations, other than certain operations in the United Kingdom and Europe, is the U.S. dollar, but a portion of the revenues from our foreign operations is paid in foreign currencies. The effects of foreign currency fluctuations are partly mitigated because local expenses of such foreign operations are also generally denominated in the same currency. We continually monitor the currency exchange risks associated with all contracts not denominated in the U.S. dollar.

We do not hold derivatives for trading purposes or use derivatives with complex features. Assets and liabilities of certain subsidiaries in the United Kingdom and Europe are translated at end of period exchange rates, while income and expense are translated at average rates for the period. Translation gains and losses are reported as the foreign currency translation component of accumulated other comprehensive loss in stockholders’ equity.

When we believe prudent, we enter into forward foreign exchange contracts to hedge the impact of foreign currency fluctuations. The forward foreign exchange contracts we enter into generally have maturities ranging from one to eighteen months. We do not enter into forward foreign exchange contracts for trading purposes. As of December 31, 2010, we had no outstanding foreign currency forward contracts.

Interest Rates

At December 31, 2010, our debt (exclusive of discounts), was comprised of the following (in thousands):

		Fixed				Variable
		Rate Debt				Rate Debt
Bank revolving credit facility due 2014 ^		$	—			$	175,000
6.875% Senior notes due 2014 *			150,000				150,000
1.50% Senior exchangeable notes due 2026			400,000				—
U.S. Government guaranteed long-term financing due 2027			13,356				—
Total Debt		$	563,356			$	325,000

Based on the amount of this debt outstanding at December 31, 2010, a 10% increase in the variable interest rate would increase our interest expense for the year ended December 31, 2010 by approximately $1.3 million, while a 10% decrease would decrease our interest expense by approximately $1.3 million.

Equity Price Risk

We have $400 million of 1.50% senior exchangeable notes due 2026. The notes are, subject to the occurrence of specified conditions, exchangeable for our common stock initially at an exchange price of $45.58 per share, which would result in an aggregate of approximately 8.8 million shares of common stock being issued upon exchange. We may redeem for cash all or any part of the notes on or after December 15, 2011 for 100% of the principal amount redeemed. The holders may require us to repurchase for cash all or any portion of the notes on December 15, 2011, December 15, 2016 and December 15, 2021 for 100% of the principal amount of notes to be purchased plus any accrued and unpaid interest. The notes do not contain any restrictive financial covenants.

Each $1,000 of principal amount of the notes is initially exchangeable into 21.9414 shares of our common stock, subject to adjustment upon the occurrence of specified events. Holders of the notes may exchange their notes prior to maturity only if (1) the price of our common stock reaches 135% of the applicable exchange rate during certain periods of time specified in the notes; (2) specified corporate transactions occur; (3) the notes have been called for redemption; or (4) the trading price of the notes falls below a certain threshold. In addition, in the event of a fundamental change in our corporate ownership or structure, the holders may require us to repurchase all or any portion of the notes for 100% of the principal amount.

We also have agreements with affiliates of the initial purchasers to purchase call options and sell warrants of our common stock. We may exercise the call options at any time to acquire approximately 8.8 million shares of our common stock at a strike price of $45.58 per share. The owners of the warrants may exercise their warrants to purchase from us approximately 8.8 million shares of our common stock at a price of $59.42 per share, subject to certain anti-dilution and other customary adjustments. The warrants may be settled in cash, in shares or in a combination of cash and shares, at our option. Lehman Brothers OTC Derivatives, Inc. (LBOTC) is the counterparty to 50% of our call option and warrant transactions. We continue to carefully monitor the developments affecting LBOTC. Although we may not be able to retain the benefit of the call option due to LBOTC’s bankruptcy, we do not expect that there will be a material impact, if any, on the financial statements or results of operations. The call option and warrant transactions described above do not affect the terms of the outstanding exchangeable notes.

For additional discussion of the notes, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” in Part II, Item 7.

Commodity Price Risk

Our revenues, profitability and future rate of growth significantly depend upon the market prices of oil and natural gas. Lower prices may also reduce the amount of oil and gas that can economically be produced.

Item 8. Financial Statements and Supplementary Data

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders
Superior Energy Services, Inc.:

We have audited the accompanying consolidated balance sheets of Superior Energy Services, Inc. and subsidiaries as of December 31, 2010 and 2009, and the related consolidated statements of operations, changes in stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2010. In connection with our audits of the consolidated financial statements, we also have audited financial statement schedule, Valuation and Qualifying Accounts. These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Superior Energy Services, Inc. and subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

As discussed in note 4 to the consolidated financial statements, the Company changed its method of accounting for business combinations in 2009 due to the adoption of new accounting requirements issued by the Financial Accounting Standards Board.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Superior Energy Services, Inc.’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 25, 2011 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP

New Orleans, Louisiana
February 25, 2011

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Balance Sheets
December 31, 2010 and 2009
(in thousands, except share data)

		2010				2009
ASSETS
Current assets:
Cash and cash equivalents		$	50,727			$	206,505
Accounts receivable, net of allowance for doubtful accounts of $22,618 and $23,679 at December 31, 2010 and 2009, respectively			452,450				337,151
Income taxes receivable			—				12,674
Prepaid expenses			25,828				20,209
Inventory and other current assets			235,047				287,024
Total current assets			764,052				863,563
Property, plant and equipment, net			1,313,150				1,058,976
Goodwill			588,000				482,480
Notes receivable			69,026				—
Equity-method investments			59,322				60,677
Intangible and other long-term assets, net			113,983				50,969
Total assets		$	2,907,533			$	2,516,665
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	110,276			$	63,466
Accrued expenses			162,044				133,602
Income taxes payable			2,475				—
Deferred income taxes			29,353				30,501
Current portion of decommissioning liabilities			16,929				—
Current maturities of long-term debt			184,810				810
Total current liabilities			505,887				228,379
Deferred income taxes			223,936				209,053
Decommissioning liabilities			100,787				—
Long-term debt, net			681,635				848,665
Other long-term liabilities			114,737				52,523
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 78,951,053 and 78,559,350 shares at December 31, 2010 and 2009, respectively			79				79
Additional paid in capital			415,278				387,885
Accumulated other comprehensive loss, net			(25,700	)			(18,996	)
Retained earnings			890,894				809,077
Total stockholders’ equity			1,280,551				1,178,045
Total liabilities and stockholders’ equity		$	2,907,533			$	2,516,665

See accompanying notes to consolidated financial statements.

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Statements of Operations
Years Ended December 31, 2010, 2009 and 2008
(in thousands, except per share data)

		2010				2009				2008
Revenues		$	1,681,616			$	1,449,300			$	1,881,124
Costs and expenses:
Cost of services (exclusive of items shown separately below)			918,713				824,034				898,294
Depreciation, depletion, amortization and accretion			220,835				207,114				175,500
General and administrative expenses			342,881				259,093				282,584
Reduction in value of assets			32,004				212,527				—
Gain on sale of businesses			1,083				2,084				40,946
Income (loss) from operations			168,266				(51,384	)			565,692
Other income (expense):
Interest expense, net of amounts capitalized			(57,377	)			(50,906	)			(46,684	)
Interest income			5,143				926				2,975
Other income (expense)			825				571				(3,977	)
Earnings (losses) from equity-method investments, net			8,245				(22,600	)			24,373
Reduction in value of equity-method investment			—				(36,486	)			—
Income (loss) before income taxes			125,102				(159,879	)			542,379
Income taxes			43,285				(57,556	)			190,904
Net income (loss)		$	81,817			$	(102,323	)		$	351,475
Basic earnings (loss) per share		$	1.04			$	(1.31	)		$	4.39
Diluted earnings (loss) per share		$	1.03			$	(1.31	)		$	4.33
Weighted average common shares used in computing earnings per share:
Basic			78,758				78,171				79,990
Incremental common shares from stock options			840				—				1,163
Incremental common shares from restricted stock units			136				—				60
Diluted			79,734				78,171				81,213

See accompanying notes to consolidated financial statements.

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Statements of Changes in Stockholders’ Equity
Years Ended December 31, 2010, 2009 and 2008
(in thousands, except share data)

																						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, 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 (loss) -
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
Comprehensive income:
Net loss			—				—				—				—				—				—				(102,323	)			(102,323	)
Other comprehensive income (loss) -
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 Changes in Stockholders’ Equity (Continued)
Years Ended December 31, 2010, 2009 and 2008
(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, 2009			—			$	—				78,559,350			$	79			$	387,885			$	(18,996	)		$	809,077			$	1,178,045
Comprehensive income:
Net income			—				—				—				—				—				—				81,817				81,817
Other comprehensive loss -
Foreign currency translation adjustment			—				—				—				—				—				(6,704	)			—				(6,704	)
Total comprehensive income			—				—				—				—				—				(6,704	)			81,817				75,113
Grant of restricted stock units			—				—				—				—				950				—				—				950
Restricted stock grant and compensation expense, net of forfeitures			—				—				342,694				—				11,367				—				—				11,367
Exercise of stock options			—				—				87,150				—				927				—				—				927
Tax benefit from exercise of stock options			—				—				—				—				560				—				—				560
Stock option compensation expense			—				—				—				—				15,493				—				—				15,493
Shares issued under Employee Stock Purchase Plan			—				—				94,250				—				2,233				—				—				2,233
Shares withheld and retired			—				—				(132,391	)			—				(4,137	)			—				—				(4,137	)
Balances, December 31, 2010			—			$	—				78,951,053			$	79			$	415,278			$	(25,700	)		$	890,894			$	1,280,551

See accompanying notes to consolidated financial statements.

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Statements of Cash Flows
Years Ended December 31, 2010, 2009 and 2008
(in thousands)

		2010				2009				2008
Cash flows from operating activities:
Net income (loss)		$	81,817			$	(102,323	)		$	351,475
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion			220,835				207,114				175,500
Deferred income taxes			7,716				(74,874	)			98,093
Reduction in value of assets			32,004				212,527				—
Reduction in value of equity-method investments			—				36,486				—
Stock based and performance share unit compensation expense, net			27,207				11,785				12,182
Retirement and deferred compensation plans expense, net			4,825				1,550				15,255
(Earnings) losses from equity-method investments, net of cash received			2,905				28,606				(7,102	)
Amortization of debt acquisition costs and note discount			23,954				21,744				19,963
Gain on sale of businesses			(1,083	)			(2,084	)			(40,946	)
Other reconciling items, net			(4,708	)			—				—
Changes in operating assets and liabilities, net of acquisitions and dispositions:
Receivables			(89,800	)			25,609				(77,565	)
Inventory and other current assets			85,687				(51,320	)			(184,602	)
Accounts payable			20,303				(24,637	)			20,252
Accrued expenses			14,754				(41,264	)			(5,917	)
Decommissioning liabilities			(1,759	)			—				(6,160	)
Income taxes			10,510				(2,301	)			12,434
Other, net			20,806				29,485				19,497
Net cash provided by operating activities			455,973				276,103				402,359
Cash flows from investing activities:
Payments for capital expenditures			(323,244	)			(286,277	)			(453,861	)
Acquisitions of businesses, net of cash acquired			(276,077	)			(1,247	)			(8,410	)
Cash proceeds from sale of businesses, net of cash sold			5,250				7,716				155,312
Cash contributed to equity-method investment			—				(8,694	)			—
Other			(9,402	)			(3,769	)			(3,578	)
Net cash used in investing activities			(603,473	)			(292,271	)			(310,537	)
Cash flows from financing activities:
Net borrowings from revolving line of credit			(2,000	)			177,000				—
Principal payments on long-term debt			(810	)			(810	)			(810	)
Payment of debt acquisition costs			(5,182	)			(2,308	)			—
Proceeds from exercise of stock options			927				375				4,274
Tax benefit from exercise of stock options			560				170				5,411
Proceeds from issuance of stock through employee benefit plans			1,891				1,958				1,558
Purchase and retirement of stock			—				—				(103,784	)
Other			(3,443	)			—				—
Net cash provided by (used in) financing activities			(8,057	)			176,385				(93,351	)
Effect of exchange rate changes on cash			(221	)			1,435				(5,267	)
Net increase (decrease) in cash and cash equivalents			(155,778	)			161,652				(6,796	)
Cash and cash equivalents at beginning of year			206,505				44,853				51,649
Cash and cash equivalents at end of year		$	50,727			$	206,505			$	44,853