Edgar Filing: SUPERIOR ENERGY SERVICES INC

Large accelerated filer

Accelerated filer

Non-accelerated

¨ (Do not check this if a smaller reporting company)

Smaller reporting company

FORM 10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

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

For the fiscal year ended December 31, 2011

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

For the Transition Period from to

Commission File No. 001-34037

SUPERIOR ENERGY SERVICES, INC.

(Exact name of registrant as specified in its charter)


Delaware		75-2379388
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

11000 Equity Dr., Suite 300 Houston, TX		77041
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code: (281) 999-0047

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 x No ¨

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

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 x No ¨

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 x No ¨

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. ¨

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.

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

As of February 17, 2012, there were 157,592,337 shares of the registrant’s common stock outstanding. The aggregate market value of the registrant’s voting stock held by non-affiliates of the registrant (based on a closing price of such shares on the New York Stock Exchange on June 30, 2011) was $5.83 billion.

DOCUMENTS INCORPORATED BY REFERENCE

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, 2011

TABLE OF CONTENTS


		Page
PART I

Item 1.	Business		2
Item 1A.	Risk Factors		7
Item 1B.	Unresolved Staff Comments		13
Item 2.	Properties		14
Item 3.	Legal Proceedings		14
Item 4.	Mine Safety Disclosures		14

PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities		15
Item 6.	Selected Financial Data		18
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		19
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk		32
Item 8.	Financial Statements and Supplementary Data		34
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		86
Item 9A.	Controls and Procedures		86
Item 9B.	Other Information		89

PART III

Item 10.	Directors, Executive Officers and Corporate Governance		90
Item 11.	Executive Compensation		90
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		90
Item 13.	Certain Relationships and Related Transactions, and Director Independence		90
Item 14.	Principal Accounting Fees and Services		90

PART IV

Item 15.	Exhibits, Financial Statement Schedules		91

FORWARD-LOOKING STATEMENTS

This report, as well as other filings made by us with the SEC and our releases to the public, contain various statements relating to future results and other forward-looking statements within the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Generally, the words “expects,” “anticipates,” “targets,” “goals,” “projects,” “intends,” “plans,” “believes,” “seeks,” “estimates,” variations of such words and similar expressions identify forward-looking statements, although not all forward-looking statements contain these identifying words. In making any forward-looking statements, we believe that the expectations are based on reasonable assumptions. We caution readers that those statements are not guarantees of future performance and our actual results may differ materially from those anticipated, projected or assumed in the forward-looking statements.

These forward-looking statements are subject to a number of risks, uncertainties and assumptions, most of which are difficult to predict and many of which are beyond our control. It is not possible to identify all of these risks, uncertainties or assumptions, but they include the factors described below in Part I, Item 1A of this Annual Report.

Investors are cautioned that many of the assumptions on which our forward-looking statements are based are likely to change after our forward-looking statements are made. Further, we may make changes to our business plans that could or will affect our results. We undertake no obligation to update or revise any of our forward-looking statements, notwithstanding any changes in our assumptions, changes in our business plans, our actual experience, or other changes.

PART I

Item 1. Business

On February 7, 2012, we acquired Complete Production Services, Inc. (“Complete”) pursuant to a merger that substantially expanded the size and scope of our business. Except as otherwise noted, the description of our business contained in this Item 1 refers to the business of Superior and its consolidated subsidiaries, including Complete and its subsidiaries, except where we refer to results of operations or operating data prior to February 7, 2012. However, because the Complete acquisition occurred during the 2012 fiscal year, but prior to our filing of this Annual Report, the accompanying financial statements reflect the results of Superior’s stand-alone operations for the three year period ended December 31, 2011. Additional information on our acquisition of Complete is included in note 3 of our consolidated financial statements included in Part II, Item 8 of this Annual Report.

General

We believe we are a leading, highly diversified provider of specialized oilfield services and equipment. As a result of the Complete acquisition, we significantly added to our geographic footprint on U.S. land and in product and service offering. We now offer a wider variety of products and services throughout the economic life of an oil and gas well, including end of life services. The acquisition of Complete greatly expanded our ability to offer more products and services related to the completion of a well prior to full production commencing, and enhanced our full suite of intervention services used to carry out wellbore maintenance operations during a well’s producing phase.

We serve energy industry customers who focus on developing and producing oil and gas worldwide. Our operations are managed and organized by both business units and geomarkets offering product and service families within various phases of a well’s economic lifecycle. We report our operating results in three segments: (1) Subsea and Well Enhancement; (2) Drilling Products and Services; and (3) Marine. Given our history of growth and long-term strategy of expanding geographically, we provide supplemental segment revenue information in three geographic areas: U.S. land, Gulf of Mexico and international.

Complete Acquisition

On February 7, 2012, we completed our acquisition of Complete through its merger with one of our subsidiaries. Complete provides specialized completion and production services and products to oil and gas companies. At the time of the acquisition, Complete’s business was comprised of two segments: completion and production services and drilling services. Approximately 96% of Complete’s 2011 revenue was derived from its completion and production services segment, which provides intervention services (including completion, workover and maintenance services), downhole and wellsite services (including wireline, production optimization, production testing and rental, fishing and pressure testing services) and fluid handling services. Virtually all of Complete’s operations are located in U.S land basins, particularly in major unconventional basins in the Rocky Mountain region, Texas, Oklahoma, Louisiana, Arkansas and Pennsylvania. We are currently in the process of integrating Complete’s operations into our Subsea and Well Enhancement segment.

The merger resulted in several important changes to our operations, including

•

significantly increasing our onshore presence in the U.S., thereby reducing the percentage of revenue that we expect to derive from our international and Gulf of Mexico operations;

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expanding our fleet of coiled tubing units, which we believe makes us one of the leading providers of coiled tubing services in the U.S.;

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expanding our existing wireline, rental and fishing products and services; and

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expanding our operations into new product and service lines, including:

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hydraulic fracturing, stimulation and cementing services through Complete’s fleet of pressure pumping equipment;

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fluid handling services, including fluid procurement, transportation, treatment, heating, pumping and disposal services, through Complete’s fleet of specialized trucks and frac tanks, fluid disposal facilities and other fluid management assets; and

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well servicing through Complete’s fleet of well service rigs and swabbing units.

Products and Services

Well Lifecycle Products and Services

We offer a wide variety of conventional products and services generally categorized by their typical use during the economic life of a well—drilling, completions and production.

•

Drilling products—Includes downhole drilling tools and surface rentals.

•

Downhole drilling tools—Includes rentals of tubulars, such as primary drill pipe strings, tubing landing strings, completion tubulars and associated accessories, and manufacturing and rentals of bottom hole tools, including stabilizers, non-magnetic drill collars, and hole openers.

•

Surface rentals—Includes rentals of temporary onshore and offshore accommodation modules and accessories.

•

Onshore completion and workover services—Includes pressure pumping, fluid handling and workover services.

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Pressure pumping—Includes hydraulic fracturing, high pressure pumping, cementing and stimulation services used to complete and stimulate production in new oil and gas wells.

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Fluid handling—Includes services used to obtain, move, store and dispose of fluids that are involved in the development and production of oil and gas reservoirs including specialized trucks, fracturing tanks and other assets that transport, heat, pump and dispose of fluids.

•

Well servicing rigs—Provides a variety of well completion, workover and maintenance services including installations, completions, sidetracking of wells and support for perforating operations.

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Production services—Includes intervention services and specialized pressure-control tools used for pressure control and intervention operations.

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Intervention services—Includes services to enhance, maintain and extend oil and gas production during the life of the well, including coiled tubing, cased hole and mechanical wireline, hydraulic workover and snubbing, production testing and optimization, and pressure pumping services.

•

Specialized pressure-control tools—Surface and downhole products used to manage and control pressure throughout the life of a well, including blowout preventers, choke manifolds, fracturing flow back trees, and downhole valves for drilling, workover, and well intervention operations.

Subsea and Technical Solutions

Products and services in this grouping generally address customer-specific needs with their applications typically requiring specialized engineering, manufacturing or project planning. Most operations requiring our innovative and technical solutions are generally in offshore environments during the completion, production and decommissioning phase of an oil or gas well. These products and services include pressure control services, completion tools and services, subsea construction, end-of-life services, marine technical services and liftboats.

•

Pressure control services—Resolves well control and pressure control problems through firefighting, engineering and well control training.

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Completion tools and services—Includes products and services to control sand and maximize oil and gas production during the completion phase of an offshore well including sand control systems, well screens and filters, and surface-controlled sub surface safety valves.

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Subsea construction—Includes subsea well intervention, inspection, repair and maintenance services utilizing subsea operating vessels, diving systems, remotely operated vehicles and engineering services.

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End-of-life services—Includes offshore well and platform decommissioning, including plugging and abandoning wells at the end of their economic life and dismantling and removing associated infrastructure.

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Marine technical services—Includes technical solutions for oil and gas offshore and marine applications including naval architecture and marine engineering, subsea and offshore engineering design, harsh environment engineering, subsea and offshore installations, and project management services.

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Liftboats—Self-elevated, self-propelled barges used to support production, maintenance and construction operations in shallow water environments.

Customers

Our customers are the major and independent oil and gas companies that are active in the geographic areas in which we operate. Based on combined revenues from us and Complete, EOG Resources accounted for approximately 10% of total combined revenue in 2011 and Chevron accounted for approximately 10% of total combined revenue in 2009. There were no customers that exceeded 10% of total combined revenues in 2010. 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 provide products and services worldwide in highly competitive markets. Our revenues and earnings can be affected by several factors, including changes in competition, fluctuations in drilling activity, perceptions of future prices of oil and gas, government regulation and general economic conditions. We believe that the principal competitive factors are price, performance, product and service quality, safety, response time and breadth of products.

We believe our primary competitors include Weatherford, Baker Hughes, Halliburton and Schlumberger. We also compete with various other regional and local providers within certain services and geographic markets.

Potential Liabilities and Insurance

Our operations involve a high degree of operational risk and expose us to significant liabilities. An accident involving our services or equipment, or the failure of a product, could result in personal injury, loss of life, damage to property, equipment or the environment. Litigation arising from a catastrophic occurrence, such as fire, explosion, well blowout or vessel loss, may result in substantial claims for damages.

We generally attempt to negotiate the terms of our customer contracts consistent with general industry practice to be responsible for our own products and services and for our customers to retain liability for drilling and related operations. Consistent with this practice, we generally attempt to take responsibility for our own people and property and intend for our customers, such as the well operators, to take responsibility for their own personnel, property and all liabilities related to the well and subsurface operations, regardless of either party’s negligence.

We maintain a commercial general liability insurance policy program that covers against certain operating hazards, including product liability claims and personal injury claims, as well as certain limited environmental pollution claims for damage to a third party or its property arising out of contact with pollution for which we are liable, but well control costs are not covered by this program. All of the insurance policies purchased by us are subject to self insured retention amounts for which we are responsible for payment, specific terms, conditions, limitations and exclusions. There can be no assurance that the nature and amount of insurance we maintain will be sufficient to fully protect us against all liabilities related to our business.

Government Regulation

Our business is significantly affected by laws and other regulations. These laws and regulations relate to, among other things:

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worker safety standards;

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the protection of the environment;

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the handling and transportation of hazardous materials; and

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the mobilization of our equipment to work sites.

Numerous permits are required for the conduct of our business and operation of our various facilities, including our underground injection wells, marine vessels, trucks and other heavy equipment. These permits can be revoked, modified or renewed by issuing authorities.

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. We also cannot predict whether additional laws and regulations will be adopted, including changes in regulatory oversight, increase of federal, state or local taxes, increase of inspection costs, or the effect such changes may have on us, our businesses or our financial condition.

Environmental Matters

Our operations, and those of our customers, are also subject to extensive laws, regulations and treaties relating to air and water quality, generation, storage and handling of hazardous materials, and emission and discharge of materials into the environment. We believe we are in substantial compliance with all regulations affecting our business. Historically, our expenditures in furtherance of our compliance with these laws, regulations and treaties have not been material, and we do not expect the cost of compliance to be material for 2012.

Seasonality

Seasonal weather and severe weather conditions can temporarily impair our operations and reduce demand for our products and services. Examples of seasonal events that negatively affect our operations include severe cold during winter months in the U.S. and hurricanes during the summer months in the Gulf of Mexico.

Employees

As of December 31, 2011, we had approximately 6,500 employees. As of February 17, 2012, following the Complete acquisition, we had approximately 14,000 employees. Certain of our international operations are subject to union contracts. These contracts cover less than 1% of our employees. We believe that our relationship with our employees is good.

Facilities

Our principal executive offices are located at 11000 Equity Drive, Suite 300, Houston, Texas, 77041. We own or lease a large number of facilities in the various areas in which we operate.

Intellectual Property

We seek patent and trademark protections throughout the world for our technology when we deem it prudent, and we aggressively pursue protection of these rights. Most of our patents are used in our stimulation and sand control business, which we acquired from Baker Hughes Incorporated in 2010 (see note 3 of our consolidated financial statements included in Part II, Item 8 of this Annual Report). We believe our patents and trademarks are adequate for the conduct of our business, and that no single patent or trademark is critical to our business. In addition, we rely to a great extent on the technical expertise and know-how of our personnel to maintain our competitive position.

Executive Officers of Registrant

David D. Dunlap, age 50, has served as our Chief Executive Officer since April 2010 and our President since 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 57, 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 54, has served as a 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.

Brian K. Moore, age 55, was appointed Senior Executive Vice President of North America Services on February 7, 2012. From March 2007 until the effectiveness of the Complete acquisition, Mr. Moore was President and Chief Operating Officer of Complete and its predecessor companies since April 2004.

Westervelt T. Ballard, Jr., age 40, was appointed Executive Vice President of International Services on February 7, 2012. Mr. Ballard previously served as Vice President of Corporate Development since joining us in June 2007. Prior to joining us, Mr. Ballard spent six years working in private equity.

L. Guy Cook, III, age 43, 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.

William B. Masters, age 54, 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.

Gregory A. Rosenstein, age 44, was appointed Executive Vice President of Corporate Development on February 7, 2012. He also is our Corporate Secretary and our main point of contact for investor relations matters, having recently served as Vice President of Investor Relations. He has been with us since March 2000.

Danny R. Young, age 56, 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.

Other Information

We have our principal executive offices at 11000 Equity Drive, Suite 300, Houston, Texas 77041. Our telephone number is (281) 999-0047. 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. 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 by directors or executive officers and any material amendment to our 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

An investment in our common stock or debt securities involves risks and uncertainties and our actual results and future trends may differ materially from our past or projected future performance. We urge investors to consider carefully the following risk factors in addition to the other information contained in this Annual Report. There may be additional risks, uncertainties, and factors not listed below that we are unaware of or do not currently consider material. Any of these could adversely affect our business, financial condition, results of operations and cash flows, and thus the value of your investment in our common stock or debt securities.

Our business depends on the level of activity in the oil and gas industry, which is significantly affected by volatile oil and gas prices and other factors.

Our business depends on the level of activity in oil and gas exploration, development and production in market sectors worldwide. Oil and gas prices and market expectations of potential changes in these prices significantly affect this level of activity. However, higher commodity prices do not necessarily translate into increased drilling activity since customers’ expectations of future commodity prices typically drive demand for our services. The availability of quality drilling prospects, exploration success, relative production costs, the stage of reservoir development and political and regulatory environments are also expected to affect the demand for our services. Worldwide military, political and economic events have in the past contributed to oil and gas price volatility and are likely to do so in the future. The demand for our services may be affected by numerous factors, including the following:

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the level of worldwide oil and gas exploration and production;

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the cost of exploring for, producing and delivering oil and gas;

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demand for energy, which is affected by worldwide economic activity and population growth;

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the ability of the Organization of Petroleum Exporting Countries, or OPEC, to set and maintain production levels for oil;

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the level of excess production capacity;

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the discovery rate of new oil and gas reserves;

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domestic and global political and economic uncertainty, socio-political unrest and instability or hostilities;

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demand for and availability of alternative, competing sources of energy; and

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technological advances affecting energy exploration, production and consumption.

A significant amount of our U.S. onshore business is focused on unconventional shale resource plays. The demand for those services is substantially affected by oil and gas prices and market expectations of potential changes in these prices. If the price of oil were to go below a certain threshold for an extended period of time, demand for our services in the U.S. land market would be greatly reduced having a material adverse effect on our financial condition, results of operations and cash flows.

The oil and gas industry has historically experienced periodic downturns, which have been characterized by reduced demand for oilfield services and downward pressure on the prices we charge. A significant downturn in the oil and gas industry will adversely affect the demand for oilfield services and our financial condition, results of operations and cash flows.

There are operating hazards inherent in the oil and natural gas industry that could expose us to substantial liabilities.

Our operations are subject to hazards present in the oil and gas industry, such as fire, explosion, blowouts, oil spills and leaks and spills of hazardous materials. These incidents, as well as accidents or problems in normal operations, expose us to a wide range of significant health, safety and environmental risks. Our product and service offerings involve production related activities, well control services, radioactive materials, explosives and other equipment and services that are deployed in challenging exploration, development and production environments. An accident involving these services or equipment, or the failure of a product, could cause personal injury, loss of life, damage to property, equipment or the environment. From time to time, customers and third parties may seek to hold us accountable for damages and costs incurred as a result of an accident, including pollution. Our insurance may not protect us against liability for some types of events, including events involving pollution, or against losses from business interruption. Moreover, we may not be able to maintain insurance at levels of risk coverage or policy limits that we deem adequate. Any damages caused by our services or products that are not covered by insurance, or are in excess of policy limits or subject to substantial deductibles, could adversely affect our financial condition, results of operations and cash flows.

We may not be fully indemnified against losses incurred due to catastrophic events for which we are not responsible.

As is customary in our industry, our contracts generally provide that we will indemnify and hold harmless our customers from any claims arising from personal injury or death of our employees, damage to or loss of our equipment, and pollution emanating from our equipment and services. Similarly, our customers agree to indemnify and hold us harmless from any claims arising from personal injury or death of their employees, damage to or loss of their equipment, and pollution caused from their equipment or the well reservoir (including uncontained oil flow from a reservoir). Our indemnification arrangements may not protect us in every case. For example, from time to time we may enter into contracts with less favorable indemnities or perform work without a contract that protects us. In addition, our indemnification rights may not fully protect us if the customer is insolvent or becomes bankrupt, does not maintain adequate insurance or otherwise does not possess sufficient resources to indemnify us. In addition, our indemnification rights may be held unenforceable in some jurisdictions. Our inability to fully realize the benefits of our contractual indemnification protections could result in significant liabilities and could adversely affect our financial condition, results of operations and cash flows.

Our business is subject to risks from economic stagnation and lower commodity prices.

Recent economic data indicates that the rate of economic growth in the United States and worldwide will remain lower than experienced several years ago. Prolonged periods of little or no economic growth will likely decrease demand for oil and gas, which could result in lower prices for oil and gas and therefore lower demand and potentially lower pricing for our services and products. A prolonged period of economic stagnation or deterioration could result in a significant adverse effect on our financial position, results of operations and cash flows. In addition, if a significant number of our customers experience a prolonged business decline or disruption as a result of economic slowdown or lower oil and gas prices, we may incur increased exposure to credit risk and bad debts.

The risk of future changes regarding the regulation of hydraulic fracturing could reduce or eliminate demand for our pressure pumping services.

Our hydraulic fracturing and fluid handling operations, which are core businesses of Complete, are subject to a range of applicable federal, state and local laws. Our hydraulic fracturing and fluid handling operations are designed and operated to minimize the risk, if any, of subsurface migration of hydraulic fracturing fluids and spillage or mishandling of hydraulic fracturing fluids. However, a proven case of subsurface migration of hydraulic fracturing fluids or a case of spillage or mishandling of hydraulic fracturing fluids during these

activities could potentially subject us to civil and/or criminal liability and the possibility of substantial costs, including environmental remediation, depending on the circumstances of the underground migration, spillage, or mishandling, the nature and scope of the underground migration, spillage, or mishandling, and the applicable laws and regulations.

The practice of hydraulically fracturing formations to stimulate the production of natural gas and oil has come under increased scrutiny from federal and state governmental authorities. The U.S. Environmental Protection Agency (EPA) is studying hydraulic fracturing, and legislation may be introduced in the U.S. Congress that would authorize the EPA to regulate hydraulic fracturing. In addition, some states are evaluating the adoption of legislation or regulations governing hydraulic fracturing. Any federal or state laws or regulations of hydraulic fracturing could adversely affect our operations and reduce or eliminate the demand for our hydraulic fracturing services.

Adverse and unusual weather conditions may affect our operations.

Our operations may be materially affected by severe weather conditions in areas where we operate. Severe weather, such as hurricanes, blizzards and extreme temperatures may cause evacuation of personnel, curtailment of services and suspension of operations, and loss of or damage to equipment and facilities. In addition, variations from normal weather patterns can have a significant impact on demand for oil and gas, thereby reducing demand for our services and equipment. Damage from any adverse weather conditions, and reductions in consumption of oil and gas due to weather variations, could adversely affect our financial condition, results of operations and cash flows.

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.

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 continued to significantly and adversely disrupt oil and gas exploration activities in the Gulf of Mexico. After the explosion, the U.S. government issued new guidelines and regulations regarding safety, environmental matters, drilling equipment and decommissioning applicable to the U.S. Gulf of Mexico, and may take other additional steps that could result in permitting delays, increased costs and reduced areas of operation, which could reduce the demand for our services.

At this time, we cannot predict with any certainty what further impact the Deepwater Horizon incident may have on the regulation of offshore oil and gas exploration and development activity, or on the cost or availability of insurance coverage to cover the risks of such operations. The enactment of new or stricter regulations in the U.S. and other countries where we operate could adversely affect our financial condition, results of operations and cash flows.

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

Lingering disruptions in the U.S. credit and financial markets and international disruptions from the European Union member states unable to service their debt obligations, which have caused investor concerns, 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 senior 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 senior credit facility would be reduced. In the event that the availability under our senior 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, obtaining commitments from the remaining banks in the lending group or from new banks to fund increased amounts under the terms of

our senior credit facility, and accessing the public capital markets. In addition, we may delay certain capital expenditures to ensure we maintain appropriate levels of liquidity. If it became necessary to access additional capital, any such alternatives could have terms less favorable than those terms under our senior 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.

Failure to retain key employees and skilled workers could adversely affect us.

Our performance could be adversely affected if we are unable to retain certain key employees and skilled workers. Our ability to continue to expand the scope of our services and products depends in part on our ability to increase the size of our skilled labor force. The loss of the services of one or more of our key employees or the inability to employ or retain skilled workers could adversely affect our operating results. The demand for skilled workers is high and the supply is limited, particularly in the United States where there are now significant unconventional oil and gas basins in areas that do not have a significant experienced workforce. We have experienced increases in labor costs in recent years and may continue to do so in the future. In addition, current and prospective employees may experience uncertainty about their future roles with us in connection with the integration of our businesses. This may adversely affect our ability to attract and retain key personnel.

We may not be able to successfully integrate Complete’s operations into our legacy operations.

Prior to the acquisition of Complete on February 7, 2012, we operated as independent public companies. We are currently devoting significant management attention and resources to integrating the business practices and operations of Complete with our legacy business practices and operations. We may encounter potential difficulties in the integration process, including the following:

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the failure to retain key employees of either of our legacy business or Complete’s business;

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the inability to successfully combine Complete’s business with our legacy business in a manner that permits us to achieve the anticipated benefits of the Complete acquisition in the time frame currently anticipated or at all;

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the complexities associated with managing the combined businesses out of a substantial number of different locations and integrating personnel from both us and Complete, while at the same time attempting to provide consistent, high quality services and equipment under a unified culture;

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potential unknown liabilities and unforeseen increased expenses associated with the Complete acquisition; and

•

performance shortfalls as a result of the diversion of management’s attention caused by finalizing the Complete acquisition and integrating the operations of Complete’s business with our legacy business.

For all these reasons, the integration process could result in the distraction of our management, the disruption of our ongoing business or inconsistencies in our services, equipment, standards, controls, procedures and policies, any of which could adversely affect our ability to maintain relationships with customers, vendors and employees or to achieve the anticipated benefits of the Complete acquisition, or could otherwise adversely affect our business and financial results.

Our international operations and revenue exposes us to additional political, economic and other uncertainties.

We have substantial international operations, and following the Complete acquisition, we intend to grow those operations further. 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;

•

deprivation of contract rights;

•

increased operating costs;

•

civil unrest and protests, strikes, acts of terrorism, war or other armed conflict;

•

import-export quotas;

•

confiscatory taxation or other adverse tax policies;

•

currency exchange controls;

•

currency exchange rate fluctuations and devaluations;

•

restrictions on the repatriation of funds; 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; and

•

the establishment of foreign subsidiaries with significant ownership positions reserved by the foreign government for local citizens.

While the impact of these factors is difficult to predict, any one or more of these factors could adversely affect our financial condition, results of operations and cash flows.

We are subject to environmental compliance costs and liabilities.

Our business is significantly affected by a wide range of environmental laws and regulations in the areas in which we operate, and increasingly stringent laws and regulations governing air emissions, water discharges and waste management. We incur, and expect to continue to incur, capital and operating costs to comply with these laws and regulations. The technical requirements of these laws and regulations are becoming increasingly complex and expensive to implement. These laws may provide for “strict liability” for remediation costs, damages to natural resources or threats to public health and safety. Strict liability can render a party liable for damages without regard to negligence or fault on the part of the party. Some environmental laws provide for joint and several strict liability for remediation of spills and releases of hazardous substances.

We use and generate hazardous substances and wastes in our operations. In addition, many of our current and former facilities are, or have been, used for industrial purposes. Accordingly, we could become subject to material liabilities relating to the investigation and cleanup of potentially contaminated properties, and to claims alleging personal injury or property damage as the result of exposures to, or releases of, hazardous substances. In addition, stricter enforcement of existing laws and regulations, new laws and regulations, the discovery of previously unknown contamination or the imposition of new or increased requirements could require us to incur costs or become the basis of new or increased liabilities that could reduce our earnings and our cash available for operations. We believe we are currently in substantial compliance with environmental laws and regulations.

World political events could affect the markets for our services.

World political events have resulted in military action in the Middle East, terrorist attacks and related unrest. Military action by the United States or other nations could escalate and further acts of terrorism may occur in the U.S. or elsewhere. Such acts of terrorism could be directed against us. Such developments have caused instability in the world’s financial and insurance markets in the past. In addition, these developments could lead to increased volatility in prices for crude oil and natural gas and could affect the markets for our products and services. Insurance premiums could increase and coverages may be unavailable in the future.

U.S. government regulations may effectively preclude us from actively engaging in business activities in certain countries. These regulations could be amended to restrict or prohibit business activities in certain countries where we currently operate or where we may wish to operate in the future.

We may not realize the anticipated benefits of mergers, acquisitions or divestitures.

A key element of our business strategy has been, and we believe will continue to be, the acquisition of other businesses. We entered into the agreement and plan of merger to acquire Complete with the expectation that it would result in numerous benefits including, among other things, expansion opportunities, an expanded product line and workforce better equipped to serve customers, maintaining business and customer levels and accretion to our earnings per share. Whether we realize the anticipated benefits from the Complete acquisition or any other transactions depends, in part, upon our ability to integrate the operations of the acquired business, the performance of the underlying product and service portfolio, and the performance of the management team and other personnel of the acquired operations. Accordingly, our financial results could be adversely affected from unanticipated performance issues, legacy liabilities, transaction-related charges, amortization of expenses related to intangibles, charges for impairment of long-term assets, credit guarantees, partner performance and indemnifications. While we believe that we have established appropriate and adequate procedures and processes to mitigate these risks, there is no assurance that these transactions will be successful. We also may make strategic divestitures from time to time. These transactions may result in continued financial involvement in the divested businesses, such as guarantees or other financial arrangements, following the transaction. Nonperformance by those divested businesses could affect our future financial results through additional payment obligations, higher costs or asset write-downs.

Demand for our products and services could be reduced or eliminated by governmental regulation or a change in the law regarding emissions.

A variety of regulatory developments, proposals or requirements have been introduced in the domestic and international regions that are focused on restricting the emission of carbon dioxide, methane and other greenhouse gases. Among these developments are the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol,” the Regional Greenhouse Gas Initiative in the Northeastern United States, and the Western Regional Climate Action Initiative in the Western United States. Also, in 2007, the U.S. Supreme Court held in Massachusetts, et al. v. EPA that greenhouse gases are an “air pollutant” under the federal Clean Air Act and thus subject to future regulation.

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 curtail production and demand for fossil fuels such as oil and gas in areas of the world where our customers operate and thus adversely affect future demand for our products and services, which may in turn adversely affect future results of operations.

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

From time to time, we may engage in projects that include the acquisition of oil and gas properties. 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 and could be in shallow water, 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 exists 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 our financial condition, results of operations and cash flows.

Business growth could outpace the capabilities of our infrastructure and workforce.

We cannot be certain that our infrastructure and workforce will be adequate to support our operations as we expand. Future growth after the Complete acquisition also could impose significant additional demands on our resources, resulting in additional responsibilities of our senior management, including the need to recruit and integrate new senior level managers, executives and operating personnel. We cannot be certain that we will be able to recruit and retain such additional personnel. To the extent that we are unable to manage our growth effectively, or are unable to attract and retain additional qualified personnel, we may not be able to expand our operations or execute our business plan.

We will incur substantial integration costs in connection with the Complete acquisition and the coordination of our and Complete’s businesses.

We have incurred substantial expenses in connection with the Complete acquisition, and we expect to incur substantial expenses in connection with coordinating the businesses, operations, policies and procedures of our legacy business and Complete’s business. While we have assumed that a certain level of transaction and coordination expenses will be incurred, there are a number of factors beyond our control that could affect the total amount or the timing of these transaction and coordination expenses. Many of the expenses that will be incurred, by their nature, are difficult to estimate accurately.

We may be exposed to unforeseen costs in some of our projects.

Some of our decommissioning business may be conducted under fixed price or “turnkey” contracts. Under fixed-price contracts, we agree to perform a defined scope of work for a fixed price. 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.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

Information on properties is contained in Part I, Item 1 of this Annual Report and in note 13 to our consolidated financial statements included in Part II, Item 8 of this Annual Report.

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 effect on our financial condition, results of operations or cash flows.

Item 4. Mine Safety Disclosures

Not Applicable.

PART II

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

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
2010
First Quarter	$	26.95	$	19.40
Second Quarter		28.93		18.09
Third Quarter		28.00		18.02
Fourth Quarter		35.44		25.35

2011
First Quarter	$	41.65	$	32.55
Second Quarter		41.49		33.39
Third Quarter		42.87		26.21
Fourth Quarter		31.44		22.19

As of February 17, 2012, there were 157,592,337 shares of our common stock outstanding, which were held by 152 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. In addition, the terms of our credit facility and the indentures governing all of our unsecured senior notes 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 of this Annual Report.

Issuer Purchases of Equity Securities

In December 2009, our Board of Directors approved a $350 million share repurchase program that expired on December 31, 2011 and was not renewed. The following table provides information about our common stock repurchased and retired during each month for the three months ended December 31, 2011:


Period	Total Number of Shares Purchased ⁽¹⁾		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plan ⁽²⁾		Approximate Dollar Value of Shares that May Yet be Purchased Under the Plan ⁽²⁾
October 1 – 31, 2011		1,184	$	26.76		—	$	350,000,000
November 1 – 30, 2011		—	$	—		—	$	350,000,000
December 1 – 31, 2011		—	$	—		—	$	350,000,000
October 1, 2011 through December 31, 2011		1,184	$	26.76		—	$	350,000,000

⁽¹⁾	Through our stock incentive plans, 1,184 shares were delivered to us by our employees to satisfy their tax withholding requirements upon vesting of restricted stock.

⁽²⁾	There was no common stock repurchased and retired under the share repurchase program during the quarter ended December 31, 2011.

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 Self-Determined Peer Groups, as described below, for the same period. The information in the graph is based on the assumption of a $100 investment on January 1, 2007 at closing prices on December 31, 2006.

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.

LOGO


	Years Ended December 31,
	2007		2008		2009		2010		2011
Superior Energy Services, Inc.	$	105	$	49	$	74	$	107	$	87
S&P 500 Stock Index	$	105	$	66	$	84	$	97	$	99
Peer Group (current)	$	146	$	61	$	101	$	136	$	120
Peer Group (prior)	$	146	$	52	$	87	$	122	$	114

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, 2006.

For 2011, we amended our Self-Determined Peer Group as a result of the Complete acquisition as well as mergers involving other companies in our peer group. 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 16 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, Incorporated, Basic Energy Services, Inc., Cameron International Corp., FMC Technologies Inc., Halliburton Co., Helix Energy Solutions Group, Inc., Helmerich & Payne Inc., Key Energy Services, Inc., Nabors Industries Ltd., National Oilwell Varco, Inc., Oceaneering International, Inc., Oil States International, Inc., Patterson-UTI Energy Inc., RPC, Inc., Schlumberger Ltd. and Weatherford International, Ltd. Our prior Self-Determined Peer Group included Baker Hughes, Incorporated, 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.

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. The financial data is in thousands, except per share amounts.


	Years Ended December 31,
	2011		2010		2009			2008		2007
Revenues	$	2,070,166	$	1,681,616	$	1,449,300		$	1,881,124	$	1,572,467
Income (loss) from operations		273,745		168,266		(51,384	)		565,692		465,838
Net income (loss)		142,554		81,817		(102,323	)		351,475		271,558
Net income (loss) per share:
Basic		1.79		1.04		(1.31	)		4.39		3.35
Diluted		1.76		1.03		(1.31	)		4.33		3.30
Total assets		4,048,145		2,907,533		2,516,665			2,490,145		2,255,295
Long-term debt, net		1,685,087		681,635		848,665			654,199		637,789
Decommissioning liabilities, less current portion		108,220		100,787		—			—		88,158
Stockholders’ equity		1,453,599		1,280,551		1,178,045			1,254,273		1,025,666

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, 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.

Executive Summary

On February 7, 2012, we acquired Complete Production Services, Inc. (“Complete”) pursuant to a merger that substantially expanded the size and scope of our business. Except as otherwise noted, the description of our business contained in this Item 7 refers to the business of Superior and its consolidated subsidiaries, including Complete and its subsidiaries, except where we refer to results of operations or operating data prior to February 7, 2012. However, because the Complete acquisition occurred during the 2012 fiscal year, but prior to our filing of this Annual Report, the accompanying financial statements reflect the results of Superior’s stand-alone operations as of December 31, 2011. Additional information on our acquisition of Complete is included in note 3 of our consolidated financial statements included in Part II, Item 8 of this Annual Report. Additionally, on February 22, 2012, we entered into an agreement to sell our marine segment, consisting of a fleet of 18 liftboats.

We believe we are a leading, highly diversified provider of specialized oilfield services and equipment. As a result of the Complete acquisition, we significantly added to our U.S. land geographic footprint and product and service offering. We now offer a wider variety of products and services throughout the economic life of an oil and gas well. The acquisition of Complete greatly expanded our ability to offer more products and services related to the completion of a well prior to full production commencing, and enhanced our full suite of intervention services used to carry out wellbore maintenance operations during a well’s producing phase.

We serve energy industry customers who focus on developing and producing oil and gas worldwide. Our operations are managed and organized by both business units and geomarkets offering product and service families within various phases of a well’s economic lifecycle, including end of life services. Business unit and geomarket leaders report to executive vice presidents, and we report our operating results in three segments: Subsea and Well Enhancement, Drilling Products and Services and Marine. Given our history of growth and long-term strategy of expanding geographically, we provide supplemental segment revenue information in three geographic areas: (1) U.S. land; (2) Gulf of Mexico; and (3) international.

Overview of our business segments

The subsea and well enhancement segment consists of completion and workover services, production services and subsea and technical solutions, all of which are labor and equipment intensive. In 2011, approximately 42% of segment revenue was from the U.S. land market area (up from 34% in 2010), while approximately 32% of this segment’s revenue was derived from work performed for customers in the Gulf of Mexico market area (down from 40% in 2010) and approximately 27% of segment revenue was from international market areas (which remained constant from 2010).

Following the acquisition of Complete, a significantly larger amount of revenue from this segment is expected to come from the U.S. land market areas. We intend to continue to focus our capital expenditures on expanding our existing products and services into U.S. land market areas that are driven by oil and liquids-rich drilling and completion activity, and on expanding into new and existing international market areas. In the U.S., the acquisition of Complete will allow us to take advantage of opportunities with larger oil and gas producers that procure services from providers offering multiple and complementary product lines. This segment’s income from operations as a percentage of segment revenue (“operating margin”) can vary based on drilling and completion spending and activity, especially in the U.S. land market areas.

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 2011, approximately 46% of segment revenue was derived from U.S. land market areas (up from 35% in 2010), while approximately 25% of segment revenue was from the Gulf of Mexico market area (down from 32% in 2010) and approximately 29% of segment revenue was from international market areas (down from 33% in 2010). Three drilling products and their ancillary equipment (accommodations, drill pipe and stabilization tools) each accounted for more than 20% of this segment’s revenue in 2011.

The marine segment is comprised of our 18 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 all 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. We entered into an agreement on February 22, 2012 to sell our marine segment. We expect this transaction to close in March of 2012.

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 and intensity 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:


	2011		% Change			2010		% Change			2009
Worldwide Rig Count ⁽¹⁾
U.S.		1,879		22	%		1,546		42	%		1,089
International ⁽²⁾		1,167		7	%		1,094		10	%		997
Commodity Prices (average)
Crude Oil (West Texas Intermediate)	$	95.47		19	%	$	80.12		28	%	$	62.74
Natural Gas (Henry Hub)	$	4.09		-8	%	$	4.44		3	%	$	4.29

⁽¹⁾	Estimate of drilling activity as measured by average active drilling rigs based on Baker Hughes Incorporated rig count information.

⁽²⁾	Excludes Canadian Rig Count.

As indicated by the table above, the major activity drivers continued to improve in 2011. The average number of drilling rigs working in the United States increased 22%, while the international rig count increased 7%. The average price of West Texas Intermediate crude oil increased 19% while the average price of Henry Hub natural gas decreased 8% from 2010.

The following table compares our revenues generated from major geographic regions for the years ended December 31, 2011 and 2010 (in thousands). We attribute revenue to countries based on the location where services are performed or the destination of the sale of products.


	Revenue
	2011		%			2010		%			Change
Gulf of Mexico	$	669,166		32	%	$	675,836		40	%	$	(6,670	)
U.S. Land		856,130		42	%		540,459		32	%		315,671
International		544,870		26	%		465,321		28	%		79,549

Total	$	2,070,166		100	%	$	1,681,616		100	%	$	388,550

In 2011, our U.S. land revenue increased 58% to $856.1 million as a result of higher oil prices, the increase in drilling rig counts (particularly the number of rigs drilling horizontal wells in the U.S. land market areas) and higher overall industry activity which led to increased utilization of existing assets and high utilization of new assets added through capital expenditures. In this market area, we experienced a 53% increase in revenue from our subsea and well enhancement segment and a 71% increase in revenue from our drilling products and services segment. Within individual product and service lines, the largest increases in the U.S. land market area were in coiled tubing, cased hole wireline, pressure control tools, rentals of accommodations and rentals and sales of premium drill pipe and accessories.

Our Gulf of Mexico revenue declined 1% to $669.2 million. The slow recovery in activity following the Deepwater Horizon incident in April 2010 without the offsetting spill recovery work that we concluded in the fourth quarter of 2010 resulted in a slight decline in our Gulf of Mexico revenue. Drilling and production activity was slow to recover through most of 2011 due to the slow pace of permits issued for such projects early in the year. While the incident curtailed much activity in the second half of 2010, the incident also created demand for many of our products and services during the well capping and cleanup phases, which were completed in the fourth quarter of 2010.

Our international revenue increased 17% to $554.9 million due primarily to improved performance at Hallin, increases in demand for completion tools, and down-hole drilling products and hydraulic workover and snubbing services in Latin America.

Industry Outlook

We believe drivers of industry demand, commodity prices and drilling rig counts should remain favorable in most geographic market areas. We also believe Gulf of Mexico deep water activity will continue to gradually increase. We believe U.S. land market areas with high concentrations of rigs drilling horizontal oil wells will remain underserved for products and services such as coiled tubing, premium drill pipe and ancillary products. Internationally, we expect to continue to build out market areas, such as Australia and Brazil, that provide us the best opportunities to provide as many products and services as possible. We expect our 2012 capital expenditures allocated for expansion in the U.S. land and international market areas will substantially increase over 2011 levels.

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 gradually increase as the number of permits for deep water drilling increases, resulting in more rigs drilling in 2012 than 2011. In the shallow water Gulf of Mexico, most of our revenue is related to production enhancement and end of life services. We anticipate that demand for products and services participating in these market segments will remain stable.

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 of our consolidated financial statements, which is included in Part II, Item 8 of this Annual Report, 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, goodwill, income taxes, allowance for doubtful accounts, revenue recognition, 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.

As a result of pursuing strategic alternatives, we entered into an agreement dated February 22, 2012 to sell our marine segment. As such, we concluded that indicators of impairment existed and therefore conducted a fair value assessment of our liftboats at December 31, 2011. This valuation included two components: estimated undiscounted cash flows and indicated valuation evidenced by tenders from prospective buyers. We then applied a weighted average to the two components to obtain an estimate of the fair market value of the liftboats. Based on this valuation analysis, we determined that the liftboats had a fair market value that was approximately $35.8 million less than their carrying value. Therefore, a reduction in the value of assets (property, plant and equipment) was recorded for approximately $35.8 million.

Goodwill. In assessing the recoverability of goodwill, we 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.

We completed our assessment as of December 31, 2011 to determine whether our goodwill was impaired, and as a result we determined that it was more likely than not that the fair value of our marine segment was less than its carrying amount, indicating that goodwill was potentially impaired. As a result, we initiated the second step of the goodwill impairment test which involved calculating the implied fair value of our goodwill by allocating the fair value of the marine segment to all of the assets and liabilities other than goodwill and comparing it to the carrying amount of goodwill. We determined that the implied fair value of our goodwill for our marine segment was less than its carrying value and wrote-off the segment’s goodwill balance of $10.3 million, which was recorded as a reduction in the value of assets. Based on business conditions and market values that existed at December 31, 2011, we concluded that no goodwill impairment was required in our subsea and well enhancement and drilling and product services segments.

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 title to the equipment has transferred to the customer.

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 of this Annual Report).

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 obtain actuarial reviews to evaluate the reasonableness of internal estimates for losses related to workers’ compensation and group medical on an annual basis. Our financial results could be impacted if litigation trends, claims settlement patterns and future inflation rates are different from our estimates.

Oil and Gas Properties. Our subsidiary, Wild Well Control Inc. (Wild Well), and our equity-method investment, Dynamic Offshore Holding, LP (Dynamic Offshore), have oil and gas properties and the related well abandonment and decommissioning liabilities. Each of these entities follows the successful efforts method of accounting for their investment in oil and 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. 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 the field.

We estimate the third party market price to plug and abandon wells, abandon pipelines, decommission and remove platforms and clear 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, 2011 and 2010

For the year ended December 31, 2011, our revenue was $2,070.2 million and our net income was $142.6 million, or $1.76 diluted earnings per share. Included in the results for the year ended December 31, 2011 were non-cash pre-tax charges of $46.1 million for the reduction in value of assets within our marine segment. 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.

The following table compares our operating results for the years ended December 31, 2011 and 2010 (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
	2011		2010		Change			2011		%			2010		%			Change
Subsea and Well Enhancement	$	1,367,834	$	1,112,662	$	255,172		$	832,568		61	%	$	675,447		61	%	$	157,121
Drilling Products and Services		611,101		474,707		136,394			220,647		36	%		176,453		37	%		44,194
Marine		91,231		94,247		(3,016	)		64,788		71	%		66,813		71	%		(2,025	)

Total	$	2,070,166	$	1,681,616	$	388,550		$	1,118,003		54	%	$	918,713		55	%	$	199,290

The following discussion analyzes our results on a segment basis.

Subsea and Well Enhancement Segment

Revenue for our subsea and well enhancement segment was $1,367.8 million for the year ended December 31, 2011, as compared to $1,112.7 million for 2010. Cost of services remained constant at 61% of segment revenue in both 2011 and 2010. Our increase in revenue and profitability is due to demand increases in the U.S. land and international market areas. Revenue from our U.S. land market area increased approximately 53% due to demand for coiled tubing, cased hole wireline, well control and pressure pumping services, as well as hydraulic workover and snubbing services. Additionally, revenue from our international market areas increased approximately 24% primarily due increased revenue from our subsea projects, well control services, hydraulic workover and snubbing services and our acquisition of Superior Completion Services in August of 2010. Revenue from our Gulf of Mexico market area decreased approximately 3% primarily based on a decline in revenue from work associated with our large-scale decommissioning project as well as a decrease in well control services. The decrease in the Gulf of Mexico was partially offset by increased revenue from cased hole wireline services, hydraulic snubbing and workover services and the acquisition of Superior Completion Services in 2010.

Drilling Products and Services Segment

Revenue for our drilling products and services segment was $611.1 million for the year ended December 31, 2011, an approximate 29% increase from 2010. Cost of services decreased slightly to 36% of segment revenue in

2011 from 37% in 2010. The increase in revenue for this segment is primarily related to rentals of our accommodation units, drill pipe and specialty tubulars, specifically in our U.S. land market area. Revenue in our U.S. land market area increased approximately 71% for the year ended December 31, 2011 over the same period in 2010. Revenue generated from our international market areas increased approximately 12% for the year ended December 31, 2011 over the same period in 2010. This increase was primarily related to increased rentals of drill pipe and specialty tubulars. Revenue from our Gulf of Mexico market area remained essentially flat due to the lingering effects of the Macondo oil spill in April 2010.

Marine Segment

Our marine segment revenue for the year ended December 31, 2011 decreased approximately 3% from 2010 to $91.2 million. Our cost of services percentage remained constant at 71% of segment revenue for the years ended December 31, 2011 and 2010. Due to the high fixed cost nature of this segment, cost of services does not fluctuate proportionately with revenue. The fleet’s average utilization decreased to approximately 66% in 2011 from 67% in 2010. However, the fleet’s average dayrate increased to approximately $16,300 in 2011 from $13,600 in 2010. This is primarily due to the fact that our two 265 foot-class vessels, which typically generate our highest day rates, returned to work in the fourth quarter of 2010 after being taken out of service for repairs in the fourth quarter of 2009. During 2011, we sold seven of our smaller liftboats for $22.8 million and recorded gains of approximately $8.6 million. 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.

On February 22, 2012, we entered into an agreement to sell the assets comprising our marine segment, or 18 liftboats. We expect this transaction to close in March of 2012.

Depreciation, Depletion, Amortization and Accretion

Depreciation, depletion, amortization and accretion increased to $257.3 million for the year ended December 31, 2011 from $220.8 million in 2010. Depreciation, depletion, amortization and accretion expense related to our subsea and well enhancement segment increased $20.3 million, or 21%, in 2011 from the same period in 2010. Increases in depreciation, depletion, amortization and accretion are related to the acquisition of Superior Completion Services, capital expenditures and increased utilization of subsea vessels. Depreciation and amortization expense increased within our drilling products and services segment by $16.1 million, or 14%, due to capital expenditures. Depreciation expense related to the marine segment remained constant for the years ended December 31, 2011 and 2010.

General and Administrative Expenses

General and administrative expenses increased to $383.6 million for the year ended December 31, 2011 from $342.9 million in 2010, which included approximately $35.0 million of management transition expenses. Increases in general and administrative expenses are attributable to the acquisition of Superior Completion Services and increased bonus and compensation expense due to our improved performance as well as additional infrastructure to enhance our growth.

Reduction in Value of Assets

As a result of pursuing strategic alternatives, we entered into an agreement on February 22, 2012 to sell our marine segment. As such, we recorded a reduction in the value of assets for approximately $46.1 million which included a write down of property and equipment of approximately $35.8 million and a write down of goodwill of approximately $10.3 million.

During 2010, we recorded a reduction in the value of assets totaling $32.0 million in connection with liftboat components primarily related to two partially completed liftboats. After a detailed evaluation, we concluded in December 2010 that it was impractical to complete these vessels. As such, we reduced our carrying value in these assets to their respective net realizable value.

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. 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.

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 U.S. land and international market areas. Revenue from our U.S. 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 U.S. land market area. Revenue in our U.S. 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 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 U.S. 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 very low utilization of our larger boats as 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 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 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.

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 U.S. land market area. During the fourth quarter of 2009, the U.S. 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.

Liquidity and Capital Resources

In the year ended December 31, 2011, we generated net cash from operating activities of $492.8 million as compared to $456.0 million in 2010. 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 $80.3 million at December 31, 2011 compared to $50.7 million at December 31, 2010. In addition, we had restricted cash and cash equivalents of approximately $785.3 million that was used to partially fund the Complete acquisition. At December 31, 2011, approximately $46.6 million of our cash balance was held in foreign jurisdictions. Cash balances held in foreign jurisdictions could be repatriated to the United States; however, they would be subject to United States federal income taxes, less applicable foreign tax credits. The Company has not provided United States income tax expense on earnings of its foreign subsidiaries because it expects to reinvest the undistributed earnings indefinitely.

We expect increased liquidity in 2012 from Complete’s cash on hand at the date of acquisition. In addition, we collected $45.5 million, exclusive of selling costs, in February 2012 from the sale of a derrick barge. We also expect to collect $134.0 million, exclusive of working capital and selling costs, from the pending sale of our marine segment in the first quarter of 2012 and $129.7 million late in the first half of 2012 in connection with the large-scale platform decommissioning project in the Gulf of Mexico, pending certain regulatory approvals. These amounts are exclusive of any tax payments related to these transactions.

We spent $484.6 million of cash on capital expenditures during the year ended December 31, 2011. Approximately $200.9 million was used to expand and maintain our drilling products and services equipment inventory, approximately $2.5 million was spent on our marine segment and approximately $281.2 million was used to expand and maintain the asset base of our subsea and well enhancement segment.

At December 31, 2011, we had a $400 million bank revolving credit facility. Any amounts outstanding under the revolving credit facility were due on July 20, 2014. At December 31, 2011, we had $75.0 million outstanding under the bank credit facility with a weighted average interest rate of 5.0% per annum. On February 7, 2012, at the time of the Complete acquisition, we amended our revolving credit facility to increase the borrowing capacity to $600 million from $400 million, and to include a $400 million term loan. The maturity date for both the credit facility and the term loan is February 7, 2017, and any amounts outstanding under the revolving credit facility

and the term loan are due at maturity. The principal balance of the term loan is payable in installments of $5.0 million on the last day of each fiscal quarter, commencing June 30, 2012. At February 17, 2012, we had $211.0 million outstanding under the bank credit facility with a weighted average interest rate of 3.6% per annum. We also had $33.3 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, 2011, we had outstanding $12.5 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 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 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 notified MARAD of our intent to repay this facility in connection with the sale of our marine segment.

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^stof 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.

In April 2011, we issued $500 million of 6 3/8% unsecured senior notes due 2019. The indenture governing the 6 3/8% senior notes requires semi-annual interest payments on May 1^st and November 1^stof each year through the maturity date of May 1, 2019. The indenture contains certain covenants that, among other things, limit us from incurring additional debt, repurchasing capital stock, paying dividends or making other distributions, incurring liens, selling assets or entering into certain mergers or acquisitions. We used a portion of the net proceeds of this offering, together with borrowings under our revolving credit facility to redeem, on December 15, 2011, all of our outstanding $400 million 1.50% senior exchangeable notes.

In December 2011, we issued $800 million of 7 1/8% unsecured senior notes due 2021. The indenture governing the 7 1/8% senior notes requires semi-annual interest payments on June 15^th and December 15^thof each year through the maturity date of December 15, 2021. The indenture contains certain covenants that, among other things, limit us from incurring additional debt, repurchasing capital stock, paying dividends or making other distributions, incurring liens, selling assets or entering into certain mergers or acquisitions. We used proceeds from this offering to partially fund the Complete acquisition.

Our current long-term issuer credit rating is BB+ by Standard and Poor’s (S&P) and Ba2 by Moody’s. S&P recently revised its outlook on our company to positive from stable, as well as affirmed their BB+ corporate credit rating. S&P’s positive outlook reflects their expectation that we will enhance operating momentum with the Complete acquisition.

The following table summarizes our contractual cash obligations and commercial commitments at December 31, 2011 (amounts in thousands). We do not have any other material obligations or commitments.


Description	2012		2013		2014		2015		2016		Thereafter
Long-term debt, including estimated interest payments	$	116,582	$	114,804	$	477,773	$	90,324	$	90,272	$	1,676,195
Capital lease obligations, including estimated interest payments		6,225		6,225		6,225		6,225		6,225		12,969
Decommissioning liabilities, undiscounted		10,552		5,276		8,793		5,276		5,276		129,069
Operating leases		14,493		10,785		8,095		4,608		2,918		17,743
Vessel construction		44,750		—		—		—		—		—
Other long-term liabilities		—		22,868		9,588		9,445		8,097		30,778

Total	$	192,602	$	159,958	$	510,474	$	115,878	$	112,788	$	1,866,754

We currently believe that we will spend approximately $1.1 billion to $1.2 billion on capital expenditures, excluding acquisitions, during 2012. We believe that our current working capital, cash generated from our operations, cash generated from dispositions 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. The vessel is expected to be delivered in the first half of 2013.

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, cash proceeds from dispositions, 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 an acquisition and a guarantee on the performance of certain decommissioning liabilities. We do not have any other financing arrangements that are not required under generally accepted accounting principles to be reflected in our financial statements.

At December 31, 2011, the maximum additional consideration payable for an acquisition was approximately $3.0 million. Since this acquisition 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. During the year ended December 31, 2011, we paid additional consideration of approximately $1.2 million as a result of prior acquisitions.

In connection with the sale of SPN Resources in 2008, we guaranteed the performance of its decommissioning liabilities. In accordance with authoritative guidance related to guarantees, we have assigned an estimated value of $2.6 million at December 31, 2011 and 2010 related to decommissioning performance guarantees, which is reflected in other long-term liabilities. We believe that the likelihood of being required to perform these guarantees is remote. In the unlikely event that Dynamic Offshore defaults on the decommissioning liabilities,

the total maximum potential obligation under these guarantees is estimated to be approximately $158.7 million, net of the contractual right to receive payments from third parties, which is approximately $24.6 million, as of December 31, 2011. The total maximum potential obligation will decrease over time as the underlying obligations are fulfilled by SPN Resources.

Hedging Activities

In an attempt to achieve a more balanced debt portfolio, 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, 2011, we had fixed-rate interest on approximately 87% of our long-term debt. As of December 31, 2011, 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 may enter into forward foreign exchange contracts to hedge the impact of foreign currency fluctuations. We do not enter into forward foreign exchange contracts for trading purposes. During the years ended December 31, 2011 and 2009, we did not hold any foreign currency forward contracts. During the year ended December 31, 2010, we held foreign currency forward contracts outstanding in order to hedge exposure to currency fluctuations. These contracts are not designated as hedges and are marked to fair market value each period. As of December 31, 2011, we had no outstanding foreign currency forward contracts.

Recently Issued Accounting Pronouncements

See Part II, Item 8, “Financial Statements and Supplementary Data—Note 1—Summary of Significant Accounting Policies—Recently Issued Accounting Pronouncements.”

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, 2011, we had no outstanding foreign currency forward contracts.

Interest Rates

At December 31, 2011, our debt (exclusive of discounts), was comprised of the following (in thousands):


	Fixed Rate Debt		Variable Rate Debt
Bank revolving credit facility due 2014 ^	$	—	$	75,000
6.875% Senior notes due 2014 *		150,000		150,000
6.375% Senior notes due 2019		500,000		—
7.125% Senior notes due 2021		800,000		—
U.S. Government guaranteed long-term financing due 2027		12,546		—

Total Debt	$	1,462,546	$	225,000

(^)	Upon the consummation of the Complete acquisition, we amended our revolving credit facility to increase the borrowing capacity to $600 million from $400 million and added a $400 million term loan. Additionally, the amendment extended the maturity date to February 7, 2017.

(*)

In March 2010, we entered into an interest rate swap agreement for a notional amount of $150 million, whereby we are entitled to receive semi-annual interest payments at a fixed rate of 6 7/8% per annum and are obligated to make quarterly interest payments at a variable rate. The variable interest rate, which is adjusted every 90 days, is based on LIBOR plus a fixed margin.

Based on the amount of this debt outstanding at December 31, 2011, a 10% increase in the variable interest rate would increase our interest expense for the year ended December 31, 2011 by approximately $1.2 million, while a 10% decrease would decrease our interest expense by approximately $1.2 million.

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, 2011 and 2010, 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, 2011. 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, 2011 and 2010, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles. 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.

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, 2011, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 28, 2012 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

KPMG LLP

New Orleans, Louisiana

February 28, 2012

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

Consolidated Balance Sheets

December 31, 2011 and 2010

(in thousands, except share data)


	2011			2010
ASSETS
Current assets:
Cash and cash equivalents	$	80,274		$	50,727
Accounts receivable, net of allowance for doubtful accounts of $17,484 and $22,618 at December 31, 2011 and 2010, respectively		540,602			452,450
Prepaid expenses		34,037			25,828
Inventory and other current assets		228,309			235,047

Total current assets		883,222			764,052

Property, plant and equipment, net		1,507,368			1,313,150
Goodwill		581,379			588,000
Notes receivable		73,568			69,026
Equity-method investments		72,472			59,322
Intangible and other long-term assets, net		930,136			113,983

Total assets	$	4,048,145		$	2,907,533

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	178,645		$	110,276
Accrued expenses		197,574			162,044
Income taxes payable		717			2,475
Deferred income taxes		831			29,353
Current portion of decommissioning liabilities		14,956			16,929
Current maturities of long-term debt		810			184,810

Total current liabilities		393,533			505,887

Deferred income taxes		297,458			223,936
Decommissioning liabilities		108,220			100,787
Long-term debt, net		1,685,087			681,635
Other long-term liabilities		110,248			114,737
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 80,425,443 and 78,951,053 shares at December 31, 2011 and 2010, respectively		80			79
Additional paid in capital		447,007			415,278
Accumulated other comprehensive loss, net		(26,936	)		(25,700	)
Retained earnings		1,033,448			890,894

Total stockholders’ equity		1,453,599			1,280,551

Total liabilities and stockholders’ equity	$	4,048,145		$	2,907,533

See accompanying notes to consolidated financial statements.

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

Consolidated Statements of Operations

Years Ended December 31, 2011, 2010 and 2009

(in thousands, except per share data)


	2011			2010			2009
Revenues	$	2,070,166		$	1,681,616		$	1,449,300
Costs and expenses:
Cost of services (exclusive of items shown separately below)		1,118,003			918,713			824,034
Depreciation, depletion, amortization and accretion		257,313			220,835			207,114
General and administrative expenses		383,567			342,881			259,093
Reduction in value of assets		46,096			32,004			212,527
Gain on sale of businesses		8,558			1,083			2,084

Income (loss) from operations		273,745			168,266			(51,384	)

Other income (expense):
Interest expense, net of amounts capitalized		(73,843	)		(57,377	)		(50,906	)
Interest income		6,226			5,143			926
Other income (expense)		(822	)		825			571
Earnings (losses) from equity-method investments, net		16,394			8,245			(22,600	)
Reduction in value of equity-method investment		—			—			(36,486	)

Income (loss) before income taxes		221,700			125,102			(159,879	)
Income taxes		79,146			43,285			(57,556	)

Net income (loss)	$	142,554		$	81,817		$	(102,323	)

Basic earnings (loss) per share	$	1.79		$	1.04		$	(1.31	)

Diluted earnings (loss) per share	$	1.76		$	1.03		$	(1.31	)

Weighted average common shares used in computing earnings per share:
Basic		79,654			78,758			78,171
Incremental common shares from stock options		1,271			840			—
Incremental common shares from restricted stock units		170			136			—

Diluted		81,095			79,734			78,171

See accompanying notes to consolidated financial statements.

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

Consolidated Statements of Changes in Stockholders’ Equity

Years Ended December 31, 2011, 2010 and 2009

(in thousands, except share data)


	Preferred stock shares		Preferred stock		Common stock shares			Common stock		Additional paid-in capital			Accumulated other comprehensive income (loss), net			Retained earnings			Total
Balances, December 31, 2008		—	$	—		78,028,072		$	78	$	375,436		$	(32,641	)	$	911,400		$	1,254,273
Comprehensive income (loss):
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 income (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 unit		—		—		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

Comprehensive income (loss):
Net income		—		—		—			—		—			—			81,817			81,817
Other comprehensive loss—Foreign currency translation adjustment		—		—		—			—		—			(6,704	)		—			(6,704	)

Total comprehensive income (loss)		—		—		—			—		—			(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 to pay performance share unit		—		—		—			—		—			—			—			—
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 Changes in Stockholders’ Equity (Continued)

Years Ended December 31, 2011, 2010 and 2009

(in thousands, except share data)


	Preferred stock shares		Preferred stock		Common stock shares			Common stock		Additional paid-in capital			Accumulated other comprehensive income (loss), net			Retained earnings		Total
Balances, December 31, 2010		—	$	—		78,951,053		$	79	$	415,278		$	(25,700	)	$	890,894	$	1,280,551
Comprehensive income (loss):
Net income		—		—		—			—		—			—			142,554		142,554
Other comprehensive loss—Foreign currency translation adjustment		—		—		—			—		—			(1,236	)		—		(1,236	)

Total comprehensive income (loss)		—		—		—			—		—			(1,236	)		142,554		141,318
Grant of restricted stock units		—		—		—			—		1,140			—			—		1,140
Restricted stock grant and compensation expense, net of forfeitures		—		—		541,425			—		5,996			—			—		5,996
Exercise of stock options		—		—		876,435			1		10,262			—			—		10,263
Tax benefit from exercise of stock options		—		—		—			—		9,004			—			—		9,004
Stock option compensation expense		—		—		—			—		3,348			—			—		3,348
Shares issued to pay performance share units		—		—		67,288			—		2,759			—			—		2,759
Shares issued under Employee Stock Purchase Plan		—		—		75,745			—		2,594			—			—		2,594
Share issuance cost		—		—		—			—		(335	)		—			—		(335	)
Shares withheld and retired		—		—		(86,503	)		—		(3,039	)		—			—		(3,039	)

Balances, December 31, 2011		—	$	—		80,425,443		$	80	$	447,007		$	(26,936	)	$	1,033,448	$	1,453,599

See accompanying notes to consolidated financial statements.

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

Consolidated Statements of Cash Flows

Years Ended December 31, 2011, 2010 and 2009

(in thousands)


	2011			2010			2009
Cash flows from operating activities:
Net income (loss)	$	142,554		$	81,817		$	(102,323	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		257,313			220,835			207,114
Deferred income taxes		48,073			8,276			(74,704	)
Excess tax benefit from stock-based compensation		(9,004	)		(560	)		(170	)
Reduction in value of assets		46,096			32,004			212,527
Reduction in value of equity-method investments		—			—			36,486
Stock based and performance share unit compensation expense		14,032			27,207			11,785
Retirement and deferred compensation plans expense		1,990			4,825			1,550
(Earnings) losses from equity-method investments, net of cash received		(13,152	)		2,905			28,606
Amortization of debt acquisition costs and note discount		25,178			23,954			21,744
Gain on sale of businesses		(8,558	)		(1,083	)		(2,084	)
Other reconciling items, net		(6,426	)		(4,708	)		—
Changes in operating assets and liabilities, net of acquisitions and dispositions:
Accounts receivable		(86,814	)		(89,800	)		25,609
Inventory and other current assets		2,182			85,687			(51,320	)
Accounts payable		40,289			20,303			(24,637	)
Accrued expenses		24,961			14,754			(41,264	)
Decommissioning liabilities		(504	)		(1,759	)		—
Income taxes		(1,378	)		10,510			(2,301	)
Other, net		15,972			20,806			29,485

Net cash provided by operating activities		492,804			455,973			276,103
Cash flows from investing activities:
Payments for capital expenditures		(484,648	)		(323,244	)		(286,277	)
Acquisitions of businesses, net of cash acquired		(1,748	)		(276,077	)		(1,247	)
Proceeds from sale of businesses		22,349			5,250			7,716
Change in restricted cash held for acquisition of a business		(785,280	)		—			—
Purchase of short-term investments		(223,491	)		—			—
Proceeds from sale of short-term investments		223,630			—			—
Cash contributed to equity-method investment		—			—			(8,694	)
Other		(721	)		(9,402	)		(3,769	)

Net cash used in investing activities		(1,249,909	)		(603,473	)		(292,271	)
Cash flows from financing activities:
Net (payments) borrowings from revolving line of credit		(100,000	)		(2,000	)		177,000
Proceeds from issuance of long-term debt		1,300,000			—			—
Principal payments of long-term debt		(400,810	)		(810	)		(810	)
Payment of debt issuance costs		(24,428	)		(5,182	)		(2,308	)
Proceeds from exercise of stock options		10,263			927			375
Excess tax benefit from stock-based compensation		9,004			560			170
Proceeds from issuance of stock through employee benefit plans		2,206			1,891			1,958
Other		(9,662	)		(3,443	)		—

Net cash provided by (used in) financing activities		786,573			(8,057	)		176,385
Effect of exchange rate changes on cash		79			(221	)		1,435

Net increase (decrease) in cash and cash equivalents		29,547			(155,778	)		161,652
Cash and cash equivalents at beginning of year		50,727			206,505			44,853

Cash and cash equivalents at end of year	$	80,274		$	50,727		$	206,505

See accompanying notes to consolidated financial statements.

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2011, 2010 and 2009

(1)	Summary of Significant Accounting Policies

(a)

Basis of Presentation

The consolidated financial statements include the accounts of Superior Energy Services, Inc. and subsidiaries (the Company). All significant intercompany accounts and transactions are eliminated in consolidation. Certain previously reported amounts have been reclassified to conform to the 2011 presentation.

(b)

Business

The Company is a leading provider of specialized oilfield services and equipment focusing on serving the production and drilling-related needs of oil and gas companies. The Company provides most of the products and services necessary to maintain, enhance and extend producing wells, as well as plug and abandonment services at the end of their life cycle.

(c)

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make significant estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

(d)

Major Customers and Concentration of Credit Risk

The majority of the Company’s business is conducted with major and independent oil and gas exploration companies. The Company evaluates the financial strength of its customers and provides allowances for probable credit losses when deemed necessary.

The market for the Company’s services and products is the oil and gas industry in the United States and select international market areas. Oil and gas companies make capital expenditures on exploration, drilling and production operations. The level of these expenditures historically has been characterized by significant volatility.

The Company derives a large amount of revenue from a small number of major and independent oil and gas companies. In 2011 and 2010, no single customer accounted for more than 10% of total revenue. In 2009 Chevron accounted for approximately 15%, Apache accounted for approximately 13% and BP accounted for approximately 11% of total revenue, primarily related to our subsea and well enhancement segment.

In addition to trade receivables, other financial instruments that potentially subject the Company to concentrations of credit risk consist of cash and derivative instruments used in hedging activities. The Company periodically evaluates the creditworthiness of financial institutions that may serve as a counterparty. The financial institutions in which the Company transacts business are large, investment grade financial institutions which are “well-capitalized” under applicable regulatory capital adequacy guidelines, thereby minimizing its exposure to credit risks for deposits in excess of federally insured amounts and for failure to perform as the counterparty on interest rate swap agreements.

(e)

Cash Equivalents

The Company considers all short-term investments with a maturity of 90 days or less when purchased to be cash equivalents.

(f)

Accounts Receivable and Allowances

Trade accounts receivable are recorded at the invoiced amount or the earned amount but not yet invoiced and do not bear interest. The Company maintains allowances for estimated uncollectible receivables including bad debts and other items. The allowance for doubtful accounts is based on the Company’s best estimate of probable uncollectible amounts in existing accounts receivable. The Company determines the allowance based on historical write-off experience and specific identification.

(g)

Inventory and Other Current Assets

Inventories are stated at the lower of cost or market. Cost is determined using the first-in, first-out (FIFO) or weighted-average cost methods for finished goods and work-in-process. Supplies and consumables consist principally of products used in our services provided to customers.

Inventory and other current assets include approximately $83.1 million and $70.0 million of inventory at December 31, 2011 and 2010, respectively. Our inventory balance at December 31, 2011 consisted of approximately $39.0 million of finished goods, $2.3 million of work-in-process, $5.4 million of raw materials and $36.4 million of supplies and consumables. Our inventory balance at December 31, 2010 consisted of $31.4 million of finished goods, $1.4 million of work-in-process, $2.2 million of raw materials and $35.0 million of supplies and consumables.

Additionally, inventory and other current assets include approximately $133.4 million and $146.9 million of costs incurred and estimated earnings in excess of billings on uncompleted contracts at December 31, 2011 and 2010, respectively. The Company follows the percentage-of-completion method of accounting for applicable contracts.

(h)

Property, Plant and Equipment

Property, plant and equipment are stated at cost, except for assets acquired using purchase accounting, which are recorded at fair value as of the date of acquisition. With the exception of the Company’s larger marine vessels, depreciation is computed using the straight line method over the estimated useful lives of the related assets as follows:


Buildings and improvements		3 to 40 years
Marine vessels and equipment		5 to 25 years
Machinery and equipment		2 to 20 years
Automobiles, trucks, tractors and trailers		3 to 5 years
Furniture and fixtures		2 to 10 years

The Company’s larger marine vessels are depreciated using the units-of-production method based on the utilization of the vessels and are subject to a minimum amount of annual depreciation. The units-of-production method is used for these assets because depreciation occurs primarily through use rather than through the passage of time.

The Company follows the successful efforts method of accounting for its 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 development wells, are capitalized. Other costs such as geological and

geophysical costs and the drilling costs of unsuccessful exploratory wells expensed. Leasehold and well costs are depleted on a units-of-production basis based on the estimated remaining equivalent proved oil and gas reserves of each field.

The Company capitalizes interest on the cost of major capital projects during the active construction period. Capitalized interest is added to the cost of the underlying assets and is amortized over the useful lives of the assets. The Company capitalized approximately $7.1 million, $2.7 million and $2.9 million in 2011, 2010 and 2009, respectively, of interest for various capital projects.

In accordance with authoritative guidance on property, plant and equipment, long-lived assets, such as property, plant and equipment and purchased intangibles subject to amortization are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Recoverability of assets to be held and used is assessed by a comparison of the carrying amount of such assets to their fair value calculated, in part, by the estimated undiscounted future cash flows expected to be generated by the assets. Cash flow estimates are based upon, among other things, historical results adjusted to reflect the best estimate of future market rates, utilization levels, and operating performance. Estimates of cash flows may differ from actual cash flows due to, among other things, changes in economic conditions or changes in an asset’s operating performance. The Company’s assets are grouped by subsidiary or division for the impairment testing, except for liftboats, which are grouped together by leg length. These groupings represent the lowest level of identifiable cash flows. The Company has long-lived assets, such as facilities, utilized by multiple operating divisions that do not have identifiable cash flows. Impairment testing for these long-lived assets is based on the consolidated entity. If the assets’ fair value is less than the carrying amount of those items, impairment losses are recorded in the amount by which the carrying amount of such assets exceeds the fair value. Assets to be disposed of are reported at the lower of the carrying amount or fair value less estimated costs to sell. The net carrying value of assets not fully recoverable is reduced to fair value. The estimate of fair value represents the Company’s best estimate based on industry trends and reference to market transactions and is subject to variability. The oil and gas industry is cyclical and these estimates of the period over which future cash flows will be generated, as well as the predictability of these cash flows, can have a significant impact on the carrying values of these assets and, in periods of prolonged down cycles, may result in impairment charges.

As a result of pursuing strategic alternatives, the Company entered into an agreement dated February 22, 2012 to sell its marine segment. As such, the Company concluded that indicators of impairment existed and therefore conducted a fair value assessment of the liftboats at December 31, 2011. This valuation included two components: estimated undiscounted cash flows and indicated valuation evidenced by tenders from prospective buyers. A weighted average was applied to the two components to obtain an estimate of the fair market value of the liftboats. Based on this valuation analysis, the Company determined that the liftboats had a fair market value that was approximately $35.8 million less than their carrying value. Therefore, a reduction in the value of assets (property, plant and equipment) was recorded for approximately $35.8 million.

For the year ended December 31, 2010, the Company recorded a reduction in the value of assets totaling $32.0 million in connection with liftboat components primarily related to the two partially completed liftboats. For the year ended December 31, 2009, the Company recorded approximately $119.8 million reduction in the value of assets, related to property, plant and equipment, due to the decline in the U.S. land market area.

(i)

Goodwill

In accordance with authoritative guidance on intangible assets, goodwill is tested for impairment annually as of December 31 or on an interim basis if events or circumstances indicate that the fair value of the asset has decreased below its carrying value. In order to estimate the fair value of the reporting units (which is consistent with the reported business segments), the Company used a weighting of the

discounted cash flow method and the public company guideline method of determining fair value of each reporting unit. The Company weighted the discounted cash flow method 80% and the public company guideline method 20% due to differences between the Company’s reporting units and the peer companies’ size, profitability and diversity of operations. In order to validate the reasonableness of the estimated fair values obtained for the reporting units, a reconciliation of fair value to market capitalization was performed for each unit on a standalone basis. A control premium, derived from market transaction data, was used in this reconciliation to ensure that fair values were reasonably stated in conjunction with the Company’s capitalization. These fair value estimates were then compared to the carrying value of the reporting units. No impairment loss was recognized during the years ended December 31, 2010 and 2009, as the fair value of the reporting unit exceeded the carrying amount. A significant amount of judgment was involved in performing these evaluations since the results are based on estimated future events.

The Company completed its assessment at December 31, 2011 to determine whether goodwill was impaired and as a result determined that it was more likely than not that the fair value of the marine segment was less than its carrying amount, indicating that goodwill was potentially impaired. As a result, the Company initiated the second step of the goodwill impairment test which involved calculating the implied fair value of the goodwill by allocating the fair value of the marine segment to all of the assets and liabilities other than goodwill and comparing it to the carrying amount of goodwill. The Company determined that the implied fair value of the goodwill for the marine segment was less than its carrying value and fully wrote-off the goodwill balance of $10.3 million, which was recorded as a reduction in the value of assets.

The following table summarizes the activity for the Company’s goodwill for the years ended December 31, 2011 and 2010 (amounts in thousands):


	Subsea and Well Enhancement			Drilling Products and Services			Marine			Total
Balance, December 31, 2009	$	332,111		$	139,436		$	10,933		$	482,480
Acquisition activities		93,650			—			—			93,650
Disposition activities		—			—			(80	)		(80	)
Additional consideration paid for prior acquisitions		14,029			1,000			—			15,029
Foreign currency translation adjustment		(2,106	)		(973	)		—			(3,079	)

Balance, December 31, 2010	$	437,684		$	139,463		$	10,853		$	588,000
Acquisition activities		3,563			—			—			3,563
Disposition activities		—			—			(519	)		(519	)
Reduction in value of asset		—			—			(10,334	)		(10,334	)
Additional consideration paid for prior acquisitions		—			1,000			—			1,000
Foreign currency translation adjustment		(296	)		(35	)		—			(331	)

Balance, December 31, 2011	$	440,951		$	140,428		$	—		$	581,379

If, among other factors, (1) the Company’s market capitalization declines and remains below its stockholders’ equity, (2) the fair value of the reporting units decline, or (3) the adverse impacts of economic or competitive factors are worse than anticipated, the Company could conclude in future periods that impairment losses are required.

(j)

Notes Receivable

Notes receivable consist of a commitment from the seller of oil and gas properties towards the abandonment of the acquired property. Pursuant to an agreement with the seller, the Company will

invoice the seller an agreed upon amount at the completion of certain decommissioning activities. The gross amount of this note totaled $115.0 million and is recorded at present value using an effective interest rate of 6.58%. The related discount is amortized to interest income based on the expected timing of the platform’s removal. The Company recorded interest income related to notes receivable of $4.5 million for each of the years ended December 31, 2011 and 2010.

(k)

Intangible and Other Long-Term Assets

Intangible and other long-term assets consist of the following at December 31, 2011 and 2010 (amounts in thousands):


	December 31, 2011							December 31, 2010
	Gross		Accumulated			Net		Gross		Accumulated			Net
	Amount		Amortization			Balance		Amount		Amortization			Balance
Customer relationships	$	23,707	$	(6,144	)	$	17,563	$	23,306	$	(4,317	)	$	18,989
Tradenames		18,005		(2,706	)		15,299		17,924		(1,622	)		16,302
Non-compete agreements		1,697		(1,126	)		571		1,320		(1,211	)		109
Debt issuance costs		41,449		(10,039	)		31,410		25,886		(14,412	)		11,474
Deferred compensation plan assets		10,598		—			10,598		10,820		—			10,820
Escrowed cash		50,196		—			50,196		33,013		—			33,013
Restricted cash and cash equivalents		785,280		—			785,280		—		—			—
Long-term assets held as major replacement spares		13,806		—			13,806		19,999		—			19,999
Other		6,018		(605	)		5,413		3,780		(503	)		3,277

Total	$	950,756	$	(20,620	)	$	930,136	$	136,048	$	(22,065	)	$	113,983

Customer relationships, tradenames, and non-compete agreements are amortized using the straight line method over the life of the related asset with weighted average useful lives of 13 years, 17 years, and 3 years, respectively. Debt issuance costs are amortized primarily using the effective interest method over the life of the related debt agreements with a weighted average useful life of 9 years. Amortization of debt issuance costs is recorded in interest expense. Amortization expense (exclusive of debt issuance costs) was approximately $3.4 million, $3.3 million and $4.3 million for the years ended December 31, 2011, 2010 and 2009, respectively. Estimated annual amortization of intangible assets (exclusive of debt acquisition costs) will be approximately $3.4 million for 2012, $3.3 million for 2013, $3.2 million for 2014, $3.0 million for 2015 and $2.9 million for 2016, excluding the effects of any acquisitions or dispositions subsequent to December 31, 2011.

In connection with the issuance of the Company’s $800 million of 7 1/8% unsecured senior notes due 2021, certain restrictions were placed on the proceeds from the issuance of these notes. These restrictions limit the Company to use the proceeds, net of fees and expenses from the issuance, for the acquisition of Complete Production Services, Inc. (NYSE: CPX) (Complete). At December 31, 2011, the Company held $785.3 million in other long-term assets as net proceeds from the issuance of these notes (see note 8), which were used to partially fund the acquisition of Complete on February 7, 2012.

As a result of the annual review for impairment of long-lived assets in accordance with authoritative guidance, the Company recorded approximately $92.7 million as a reduction in the value of intangible assets during the year ended December 31, 2009.

(l)

Decommissioning Liabilities

The Company records estimated future decommissioning liabilities in accordance with the authoritative guidance related to asset retirement obligations (decommissioning liabilities), which requires entities to

record the fair value of a liability for an asset retirement obligation in the period in which it is incurred, with a corresponding increase in the carrying amount of the related long-lived asset. Subsequent to initial measurement, the decommissioning liability is required to be accreted each period to present value. The Company’s decommissioning liabilities associated with the Bullwinkle platform and its related assets consist of costs related to the plugging of wells, the removal of the related facilities and equipment, and site restoration.

Whenever practical, the Company utilizes its own equipment and labor services to perform well abandonment and decommissioning work. When the Company performs these services, all recorded intercompany revenues and related costs of services are eliminated in the consolidated financial statements. The recorded decommissioning liability associated with a specific property is fully extinguished when the property is abandoned. The recorded liability is first reduced by all cash expenses incurred to abandon and decommission the property. If the recorded liability exceeds (or is less than) the Company’s total costs, then the difference is reported as income (or loss) within revenue during the period in which the work is performed. The Company reviews the adequacy of its decommissioning liabilities whenever indicators suggest that the estimated cash flows needed to satisfy the liability have changed materially. The Company reviews its estimates for the timing of these expenditures on a quarterly basis.

In connection with the acquisition of Superior Completion Services in 2010, the Company assumed approximately $10.0 million of decommissioning liabilities associated with restoring two chartered vessels to the original condition in which they were received.

The following table summarizes the activity for the Company’s decommissioning liabilities for the years ended December 31, 2011 and 2010 (amounts in thousands):


	2011			2010
Decommissioning liabilities, December 31, 2010 and 2009, respectively	$	117,716		$	—
Liabilities acquired and incurred		—			136,559
Liabilities settled		(504	)		(1,759	)
Accretion		6,752			7,018
Revision in estimated liabilities		(788	)		(24,102	)

Total decommissioning liabilities, December 31, 2011and 2010, respectively		123,176			117,716
Less: current portion of decommissioning liabilities at December 31, 2011 and 2010, respectively		14,956			16,929

Long-term decommissioning liabilities, December 31, 2011 and 2010, respectively	$	108,220		$	100,787

(m)

Revenue Recognition

Products and services are generally sold based upon purchase orders or contracts with customers that include fixed or determinable prices. Revenue is recognized when services or equipment are provided and collectability is reasonably assured. The Company contracts for marine and subsea and well enhancement projects either on a day rate or turnkey basis, with a vast majority of its projects conducted on a day rate basis. The Company’s drilling products and services are billed on a day rate basis, and revenue from the sale of equipment is recognized when the title to the equipment has been transferred. Reimbursements from customers for the cost of drilling products and services that are damaged or lost down-hole are reflected as revenue at the time of the incident. The Company accounted for the revenue and related costs on a large-scale platform decommissioning contract on the

percentage-of-completion method utilizing costs incurred as a percentage of total estimated costs (see note 5). The Company recognizes oil and gas revenue from its interests in producing wells as oil and natural gas is sold.

(n)

Taxes Collected from Customers

In accordance with authoritative guidance related to taxes collected from customers and remitted to governmental authorities, the Company elected to net taxes collected from customers against those remitted to government authorities in the financial statements consistent with the historical presentation of this information.

(o)

Income Taxes

The Company accounts for income taxes and the related accounts under the asset and liability method. Deferred income taxes reflect the impact of temporary differences between amounts of assets and liabilities for financial reporting purposes and such amounts as measured by tax laws and rates that are in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on the deferred income taxes is recognized in income in the period in which the change occurs. A valuation allowance is recorded when management believes it is more likely than not that at least some portion of any deferred tax asset will not be realized.

The Company has adopted authoritative guidance surrounding accounting for uncertainty in income taxes. It is the Company’s policy to recognize interest and applicable penalties related to uncertain tax positions in income tax expense.

(p)

Earnings (Loss) per Share

Basic earnings (loss) per share is computed by dividing net income (loss) available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share is computed in the same manner as basic earnings per share except that the denominator is increased to include the number of additional common shares that could have been outstanding assuming the exercise of stock options and restricted stock units and the potential shares that would have a dilutive effect on earnings per share using the treasury stock method.

Stock options and restricted stock units for approximately 540,000, 1,650,000 and 1,180,000 shares were excluded in the computation of diluted earnings per share for the years ended December 31, 2011, 2010 and 2009, respectively, as the effect would have been anti-dilutive.

(q)

Fair Value Measurements

The Company follows authoritative guidance for fair value measurements relating to financial and nonfinancial assets and liabilities, including presentation of required disclosures herein. This guidance establishes a fair value framework requiring the categorization of assets and liabilities into three levels based upon the assumptions (inputs) used to price the assets and liabilities. Level 1 provides the most reliable measure of fair value, whereas Level 3 generally requires significant management judgment. The three levels are defined as follows:

Level 1: Unadjusted quoted prices in active markets for identical assets and liabilities;

Level 2: Observable inputs other than those included in Level 1 such as quoted prices for similar assets and liabilities in active markets; quoted prices for identical assets or liabilities in inactive markets or model-derived valuations or other inputs that can be corroborated by observable market data; and

Level 3: Unobservable inputs reflecting management’s own assumptions about the inputs used in pricing the asset or liability.

(r)

Financial Instruments

The fair value of the Company’s financial instruments of cash equivalents, accounts receivable, accounts payable, accrued expenses and revolving credit facility approximates their carrying amounts due to their short maturity or market interest rates. The fair value of the Company’s debt was approximately $1,749.8 million and $902.5 million at December 31, 2011 and 2010, respectively. The fair value of these debt instruments is determined by reference to the market value of the instrument as quoted in an over-the-counter market.

(s)

Foreign Currency

Results of operations for foreign subsidiaries with functional currencies other than the U.S. dollar are translated using average exchange rates during the period. Assets and liabilities of these foreign subsidiaries are translated using the exchange rates in effect at the balance sheet dates, and the resulting translation adjustments are reported as accumulated other comprehensive income (loss) in the Company’s stockholders’ equity.

For international subsidiaries where the functional currency is the U.S. dollar, financial statements are remeasured into U.S. dollars using the historical exchange rate for most of the long-term assets and liabilities and the balance sheet date exchange rate for most of the current assets and liabilities. An average exchange rate is used for each period for revenues and expenses. These transaction gains and losses, as well as any other transactions in a currency other than the functional currency, are included in general and administrative expenses in the consolidated statements of operations in the period in which the currency exchange rates change. For the years ended December 31, 2011, 2010 and 2009 the Company recorded approximately $1.4 million, $1.6 million and $3.5 million of foreign currency gains, respectively.

(t)

Stock-Based Compensation

In accordance with authoritative guidance related to stock compensation, the Company records compensation costs relating to share -based payment transactions and includes such costs in general and administrative expenses in the statement of operations. The cost is measured at the grant date, based on the calculated fair value of the award, and is recognized as an expense over the employee’s requisite service period (generally the vesting period of the equity award). Excess tax benefits of awards that are recognized in equity related to stock option exercises and restricted stock vesting are reflected as financing cash flows.

(u)

Derivative Instruments and Hedging Activities

The Company recognizes all derivative instruments as either assets or liabilities in the balance sheet at their respective fair values. 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. The Company also assesses, both at inception of the hedging relationship and on an ongoing basis, whether the derivatives used in hedging relationships are highly effective in offsetting changes in fair value.

In an attempt to achieve a more balanced debt portfolio, the Company entered into an interest rate swap in March 2010. Under this agreement, the Company is entitled to receive semi-annual interest payments at a fixed rate of 6 7/8% per annum and is obligated to make quarterly interest payments at a variable rate. At December 31, 2011, the Company had fixed-rate interest on approximately 87% of its long-term debt. As of December 31, 2011, the Company had a notional amount of $150 million related to this interest rate swap with a variable interest rate, which is adjusted every 90 days, based on LIBOR plus a fixed margin.

From time to time, the Company may enter into forward foreign exchange contracts to hedge the impact of foreign currency fluctuations. The Company does not enter into forward foreign exchange

contracts for trading purposes. During the years ended December 31, 2011 and 2009, the Company did not hold any foreign currency forward contracts. During the year ended December 31, 2010, the Company held foreign currency forward contracts outstanding in order to hedge exposure to currency fluctuations. These contracts are not designated as hedges, for hedge accounting treatment, and were marked to fair market value each period and changes in fair value were recognized in earnings.

(v)

Other Comprehensive Loss

The following table reconciles the change in accumulated other comprehensive loss for the years ended December 31, 2011 and 2010 (amounts in thousands):


	2011			2010
Accumulated other comprehensive loss, net, December 31, 2010 and 2009, respectively	$	(25,700	)	$	(18,996	)
Other comprehensive loss, net of tax: Foreign currency translation adjustment		(1,236	)		(6,704	)

Accumulated other comprehensive loss, net, December 31, 2011 and 2010, respectively	$	(26,936	)	$	(25,700	)

(w)

Equity—Method Investments

Investments in entities that are not controlled by the Company, but where the Company has the ability to exercise significant influence over the operations, are accounted for using the equity-method. The Company’s share of the income or losses of these entities is reflected as earnings or losses from equity-method investments in its consolidated statements of operations.

(x)

Self Insurance Reserves

The Company is self insured, through deductibles and retentions, up to certain levels for losses related to workers’ compensation, third party liability insurances, property damage, and group medical. With the Company’s growth, the Company has elected to retain more risk by increasing its self insurance. The Company accrues for these liabilities based on estimates of the ultimate cost of claims incurred as of the balance sheet date. The Company regularly reviews the estimates of reported and unreported claims and provides for losses through reserves. The Company obtains actuarial reviews to evaluate the reasonableness of internal estimates for losses related to workers’ compensation and group medical on an annual basis.

(y)

Subsequent Events

In accordance with authoritative guidance, the Company has evaluated and disclosed all material subsequent events that occurred after the balance sheet date, but before financial statements were issued.

(z)

Recently Issued Accounting Pronouncements

In June 2011, the FASB issued Accounting Standards Update No. 2011-05, “Presentation of Comprehensive Income” (“ASU 2011-05”). The amendments in ASU 2011-05 allow an entity the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In both instances, an entity is required to present each component of net income along with total net income, each component of other comprehensive income along with a total for other comprehensive income, and a total amount for comprehensive

income. ASU 2011-05 eliminates the option to present the components of other comprehensive income as part of the statement of changes in stockholders’ equity. The amendments in ASU 2011-05 do not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income. However, in December 2011, the FASB issued Accounting Standards Update No. 2011-12, “Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05” (“ASU 2011-12”), which deferred the guidance on whether to require entities to present reclassification adjustments out of accumulated other comprehensive income by component in both the statement where net income is presented and the statement where other comprehensive income is presented for both interim and annual financial statements. ASU 2011-12 reinstated the requirements for the presentation of reclassifications that were in place prior to the issuance of ASU 2011-05 and did not change the effective date for ASU 2011-05. For public entities, the amendments in ASU 2011-05 and ASU 2011-12 are effective for fiscal years, and interim periods within those years, beginning after December 15, 2011, and should be applied retrospectively. The adoption of this guidance will change the Company’s financial statement presentation of comprehensive income but will not impact the consolidated financial position or results of operations.

In September 2011, the FASB issued ASU No. 2011-08, “Intangibles—Goodwill and Other” (“ASU 2011-08”). ASU 2011-08 allows a qualitative assessment of whether it is more likely than not that a reporting unit’s fair value is less than its carrying amount before applying the two-step goodwill impairment test. If it is more likely than not that the fair value of a reporting unit is less than its carrying amount, then the two-step impairment test would be performed. ASU 2011-08 is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011, and early adoption is permitted. This update changed the process the Company used to test goodwill for impairment, but did not have a material impact on its consolidated financial statements.

In December 2011, the FASB issued ASU 2011-11, “Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities” (“ASU 2011-11”). This newly issued accounting standard requires an entity to disclose both gross and net information about instruments and transactions eligible for offset in the statement of financial position as well as instruments and transactions executed under a master netting or similar arrangement and was issued to enable users of financial statements to understand the effects or potential effects of those arrangements on its financial position. This ASU is required to be applied retrospectively and is effective for fiscal years, and interim periods within those years, beginning on or after January 1, 2013. As this accounting standard only requires enhanced disclosure, the adoption of this standard is not expected to have an impact on our consolidated financial position or results of operations.

(2)	Supplemental Cash Flow Information

The following table includes the Company’s supplemental cash flow information for the years ended December 31, 2011, 2010 and 2009 (amounts in thousands):


	2011			2010			2009
Cash paid for interest, net of amounts capitalized	$	39,539		$	34,034		$	28,833

Cash paid for income taxes	$	22,320		$	25,435		$	16,434

Details of business acquisitions:
Fair value of assets	$	8,650		$	515,767		$	1,247
Fair value of liabilities		(6,902	)		(228,417	)		—

Cash paid		1,748			287,350			1,247
Less cash acquired		—			(11,273	)		—

Net cash paid for acquisitions	$	1,748		$	276,077		$	1,247

Details of proceeds from sale of businesses:
Book value of assets	$	13,791		$	4,236		$	5,632
Book value of liabilities		—			81			—
Receivable due from sale		—			(150	)		—
Gain on sale of business		8,558			1,083			2,084

Proceeds from sale of businesses	$	22,349		$	5,250		$	7,716

Non-cash investing activity:
Long term payable on vessel construction	$	—		$	—		$	5,000

Capital expenditures included in accounts payable	$	23,053		$	—		$	—

Additional consideration payable on acquisitions	$	—		$	—		$	484

Non-cash financing activity:
Share settlement for employee tax liability	$	—		$	3,093		$	—

(3)	Acquisitions

In September 2011, the Company acquired 100% of the equity interest in a pressure pumping company based in Brazil in order to expand the breadth of services offered in Brazil. The Company paid approximately $0.5 million at closing, with an additional $5.8 million payable after the settlement of certain liabilities and administrative formalities. Identifiable intangible assets include goodwill of $3.6 million, all of which was assigned to the Company’s subsea and well enhancement segment.

In August 2010, the Company acquired certain assets (operating as Superior Completion Services) from subsidiaries of Baker Hughes Incorporated (Baker Hughes) for approximately $54.3 million. The assets purchased were used in Baker Hughes’ Gulf of Mexico stimulation and sand control business.

In January 2010, the Company acquired 100% of the equity interest of Hallin Marine Subsea International Plc (Hallin) for approximately $162.3 million. Additionally, the Company repaid approximately $55.5 million of Hallin’s debt. Hallin is an international provider of integrated subsea services and engineering solutions, focused on installing, maintaining and extending the life of subsea wells. Hallin operates in international offshore oil and gas markets with offices and facilities located in Singapore, Indonesia, Australia, Scotland and the United States.

In January 2010, Wild Well Control, Inc. (Wild Well), a wholly-owned subsidiary of the Company, acquired 100% ownership of Shell Offshore, Inc.’s Gulf of Mexico Bullwinkle platform and its related assets and assumed the related decommissioning obligation. Immediately after Wild Well acquired these assets, it conveyed an

undivided 49% interest in these assets and the related well plugging and abandonment obligations to Dynamic Offshore Holding, LP (Dynamic Offshore), which operates these assets. Additionally, Dynamic Offshore will pay Wild Well to extinguish its 49% portion of the well plugging and abandonment obligation (see note 5).

The Company has an off-balance sheet financing arrangement for additional consideration that may be payable as a result of the future operating performance of an acquisition. At December 31, 2011, the maximum additional contingent consideration payable was approximately $3.0 million and will be determined and payable through 2012. Since this acquisition occurred before the Company adopted the revised authoritative guidance for business combinations, these amounts are not classified as liabilities and are not reflected in the Company’s financial statements until the amounts are fixed and determinable. The Company paid additional consideration of approximately $1.2 million for the year ended December 31, 2011, as a result of prior acquisitions. Of the consideration paid, $1.0 million was capitalized during the year ended December 31, 2011 and $0.2 million had been capitalized and accrued during 2010.

Subsequent Event

On February 7, 2012, the Company acquired Complete Production Services, Inc. (“Complete”) pursuant to a merger that substantially expanded the size and scope of the Company. The total consideration for this acquisition approximates $2,917.9 million, which includes both cash and stock. Complete stockholders received 0.945 of a share of the Company’s common stock and $7.00 cash for each share of Complete’s common stock outstanding at the time of the acquisition. In total, the Company paid approximately $553.9 million in cash and issued approximately 75.5 million shares valued at approximately $2,310.7 million (based on the closing price of the Company’s common stock on the acquisition date of $30.90). Additionally, the Company will repay $650.0 million of Complete’s debt.

During the year ended December 31, 2011, the Company expensed approximately $4.5 million of acquisition related costs, which was recorded in general and administrative expenses. The Company expects to incur approximately $23.0 million of additional acquisition related costs in the first quarter of 2012 related to this acquisition.

Complete focuses on providing specialized completion and production services and products that help oil and gas companies develop hydrocarbon reserves, reduce costs and enhance production. Complete’s operations are located throughout the United States and Mexico. Management believes that the acquisition will position the combined company as the only mid-cap oilfield service company in the United States (a company with market capitalization between $3 billion and $10 billion) providing services and equipment to upstream oil and natural gas operators, making the combined company better equipped to compete with the larger oilfield service companies and to expand internationally. Complete will be reported under the subsea and well enhancement segment.

The Company funded the Complete acquisition with $800 million of 7 1/8% unsecured senior notes due 2021 which were issued in December 2011, a $400 million term loan facility and by increasing the capacity of the Company’s revolving credit facility from $400 million to $600 million (see note 8).

The transaction will be accounted for using the acquisition method of accounting which requires that, among other things, assets acquired and liabilities assumed be recorded at their fair values as of the acquisition date. The excess of the consideration transferred over those fair values is recorded as goodwill. None of the goodwill related to this acquisition will be deductible for tax purposes. As the initial valuation and subsequent purchase accounting for this acquisition is incomplete due to the timing of the acquisition, the Company is unable to provide the allocation of the aggregate purchase price for each major class of assets acquired and liabilities assumed. Since the pro forma statement of earnings data is dependent on the purchase price allocation, the Company is also unable to provide pro forma information for the year ending December 31, 2011 at this time. These disclosures will be included in our interim consolidated financial statements for the period ending March 31, 2012.

(4)	Dispositions

During 2011, the Company sold seven liftboats for approximately $22.3 million, net of commissions, resulting in a pre-tax gain of approximately $8.6 million for the year ended December 31, 2011. In December 2010, the Company sold one liftboat for approximately $5.4 million, inclusive of a $0.1 million receivable, resulting in a pre-tax gain of approximately $1.1 million for the year ended December 31, 2010. In 2009, the Company sold four liftboats for approximately $7.7 million resulting in a pre-tax gain of approximately $2.1 million for the year ended December 31, 2009.

Subsequent Events

On February 15, 2012, the Company sold a derrick barge to a marine construction company based in India. The Company received proceeds of $44.3 million, inclusive of selling costs. The carrying value of the derrick barge and related assets approximated $37.9 million, exclusive of $9.7 million of goodwill. The Company expects to record a pre-tax loss of approximately $3.3 million in the first quarter of 2012 in connection with this sale. The operations of this derrick barge have been reported under the Subsea and Well Enhancement Segment.

On February 22, 2012, the Company entered into an agreement to sell the assets comprising its marine segment, or 18 liftboats. The Company is expected to receive cash proceeds of approximately $134 million, exclusive of working capital and selling costs, which approximates the segment’s carrying value at December 31, 2011. At December 31, 2011, the Company had outstanding $12.5 million in U.S. Government guaranteed long-term financing, which is administered by the Maritime Administration, for two liftboats. The Company has notified the Maritime Administration of its intent to repay this facility in connection with the sale of its marine segment. The Company expects to record an additional pre-tax loss at the time of sale for various expenses, including commissions, separation agreements and losses on the extinguishment of debt. The sale of these assets will constitute all of the marine segment as defined in the segment disclosure (see note 11). The Company expects this transaction to close in March of 2012.

(5)	Long-Term Contracts

In January 2010, Wild Well acquired 100% ownership of Shell Offshore Inc.’s Gulf of Mexico Bullwinkle platform and its related assets, and assumed the decommissioning obligations of such assets. In connection with the conveyance of an undivided 49% interest in these assets and the related well plugging and abandonment obligations, Dynamic Offshore will pay Wild Well to extinguish its portion of the well plugging and abandonment obligations, limited to the current fair value of the obligation at the time of acquisition. As part of the asset purchase agreement with Shell Offshore Inc., Wild Well was required to obtain a $50 million performance bond as well as fund $50 million into an escrow account. Included in intangible and other long-term assets, net is escrowed cash of $50.2 million and $33.0 million as of December 31, 2011 and 2010, respectively. Included in other long-term liabilities is deferred revenue of $24.6 million and $16.2 million as of December 31, 2011 and 2010, respectively.

In December 2007, Wild Well entered into contractual arrangements pursuant to which it is decommissioning seven downed oil and gas platforms and related wells located offshore in the Gulf of Mexico for a fixed sum of $750 million, which is payable in installments upon the completion of specified portions of work. The contract contains certain covenants primarily related to Wild Well’s performance of the work. As of December 31, 2011, the work on this project was substantially complete, pending certain regulatory approvals. The revenue related to the contract for decommissioning these downed platforms and wells was recorded on the percentage-of-completion method utilizing costs incurred as a percentage of total estimated costs. Included in other current assets at December 31, 2011 and 2010 is approximately $129.7 million and $144.5 million, respectively, of costs and estimated earnings in excess of billings related to this contract.

(6)	Property, Plant and Equipment

A summary of property, plant and equipment at December 31, 2011 and 2010 (in thousands) is as follows:


	2011			2010
Buildings, improvements and leasehold improvements	$	139,432		$	127,725
Marine vessels and equipment		417,413			499,398
Machinery and equipment		1,596,580			1,248,318
Automobiles, trucks, tractors and trailers		38,770			31,934
Furniture and fixtures		40,575			35,124
Construction-in-progress		171,108			83,694
Land		29,518			24,223
Oil and gas producing assets		44,109			34,336

		2,477,505			2,084,752
Accumulated depreciation and depletion		(970,137	)		(771,602	)

Property, plant and equipment, net	$	1,507,368		$	1,313,150

In connection with the review for impairment of long-lived assets in accordance with authoritative guidance, the Company recorded approximately $35.8 million as a reduction in the value of property, plant and equipment during the year ended December 31, 2011 as the indicated valuation from prospective buyers was less than the carrying value of certain marine assets. During 2010, the Company recorded a reduction in the value of assets totaling $32.0 million in connection with liftboat components primarily related to the partially completed liftboats. During 2009, the Company recorded approximately $119.8 million as a reduction in the value of property, plant and equipment during the year ended December 31, 2009 primarily related to assets servicing the U.S. land market area.

The Company had approximately $23.2 million and $22.7 million of leasehold improvements at December 31, 2011 and 2010, respectively. These leasehold improvements are depreciated over the shorter of the life of the asset or the term of the lease using the straight line method. Depreciation expense (excluding depletion, amortization and accretion) was approximately $224.6 million, $207.7 million, $202.8 million for the years ended December 31, 2011, 2010 and 2009, respectively.

Capital Lease

Hallin is the lessee of a dynamically positioned subsea vessel under a capital lease expiring in 2019 with a 2 year renewal option. Hallin owns a 5% equity interest in the entity that owns this leased asset. The entity owning this vessel had $28.9 million of debt as of December 31, 2011, all of which was non-recourse to the Company. The amount of the asset and liability under this capital lease is recorded at the present value of the lease payments. This vessel is depreciated using the units-of-production method based on the utilization of the vessel and is subject to a minimum amount of annual depreciation. The units-of-production method is used for this vessel because depreciation occurs primarily through use rather than through the passage of time. The vessel’s gross asset value under the capital lease was approximately $37.6 million at inception and depreciation expense was approximately $4.2 million for the year ending December 31, 2011 and $3.8 million from the date of acquisition through December 31, 2010. At December 31, 2011 and 2010, the Company had approximately $29.5 million and $33.0 million, respectively, included in other long-term liabilities, and approximately $3.6 million and $3.2 million, respectively, included in accounts payable related to the obligations under this capital lease. The future minimum lease payments under this capital lease are approximately $3.6 million, $3.9 million, $4.2 million, $4.6 million and $5.0 million in the years ending December 31, 2012, 2013, 2014, 2015 and 2016 respectively, exclusive of interest at an annual rate of 8.5%. For each of the years ended December 31, 2011 and 2010, the Company recorded interest expense of approximately $3.0 million in connection with this capital lease.

(7)	Equity-Method Investments

In March 2011, the Company contributed all of its equity interests in SPN Resources and DBH, LLC (DBH) to Dynamic Offshore, the majority owner of both SPN Resources and DBH, in exchange for a 10% limited partnership interest in Dynamic Offshore. Following these contributions, Dynamic Offshore owns all the equity interests of SPN Resources and DBH. Prior to these contributions, the Company accounted for its equity interests in SPN Resources and DBH as separate equity-method investments. The Company’s equity interest in Dynamic Offshore is accounted for as an equity-method investment with a balance of approximately $70.6 million at December 31, 2011. The Company recorded income from its equity-method investment in Dynamic Offshore of approximately $15.0 million for the ten months ended December 31, 2011 following the contributions. Additionally, the Company received approximately $2.8 million of cash distributions from its equity-method investment in Dynamic Offshore for the ten month period ended December 31, 2011. The Company, where possible and at competitive rates, provides its products and services to assist Dynamic Offshore in producing and developing its oil and gas properties. The Company had a receivable from Dynamic Offshore of approximately $9.8 million at December 31, 2011. The Company also recorded revenue from Dynamic Offshore of approximately $44.9 million for the ten months ended December 31, 2011 following the contributions. Additionally, the Company has a receivable from Dynamic Offshore of approximately $14.0 million as of December 31, 2011 related to its share of oil and natural gas commodity sales and production handling arrangement fees.

The Company’s equity-method investment balance in SPN Resources was approximately $43.6 million at December 31, 2010. The Company recorded earnings from its equity-method investment in SPN Resources of approximately $0.2 million for the two months ended February 28, 2011 prior to the contributions and approximately $1.2 million for the year ended December 31, 2010. The Company recorded losses from this equity-method investment of approximately $7.6 million for the year ended December 31, 2009. Additionally, the Company received approximately $9.9 million and $5.9 million, respectively, of cash distributions from its equity-method investment in SPN Resources for the years ended December 31, 2010 and 2009. The Company, where possible and at competitive rates, provides its products and services to assist SPN Resources in producing and developing its oil and gas properties. The Company had a receivable from SPN Resources of approximately $3.2 million at December 31, 2010. The Company also recorded revenue from SPN Resources of approximately $0.3 million for the two months ended February 28, 2011 and approximately $11.4 million and $11.0 million, respectively, for the years ended December 31, 2010 and 2009. The Company also reduces its revenue and its investment in SPN Resources for its respective ownership interest when products and services are provided to and capitalized by SPN Resources. As these capitalized costs are depleted by SPN Resources, the Company then increases its revenue and investment in SPN Resources. As such, the Company recorded a net increase in revenue and its investment in SPN Resources of approximately $0.6 million for the year ended December 31, 2009.

During the year ended December 31, 2009, the Company wrote off the remaining carrying value of its 40% interest in Beryl Oil and Gas L.P. (BOG), $36.5 million, and suspended recording its share of BOG’s operating results under equity-method accounting as a result of continued negative BOG operating results, lack of viable interested buyers and unsuccessful attempts to renegotiate the terms and conditions of its loan agreements with lenders on terms that would preserve the Company’s investment. The Company’s total cash contribution for this equity-method investment in BOG was approximately $57.8 million. The Company recorded a loss from its equity-method investment in BOG of approximately $14.0 million for the year ended December 31, 2009. The Company also recorded revenue of approximately $7.0 million from BOG for the year ended December 31, 2009. The Company also recorded a decrease in its investment in BOG of approximately $6.1 million for the year ended December 31, 2009 for its proportionate share of accumulated other comprehensive income generated from hedging transactions. The Company recorded a net increase in revenue and its investment in BOG for services provided by the Company that were capitalized by BOG of approximately $0.2 million for the year ended December 31, 2009.

In October 2009, DBH acquired BOG in connection with a restructuring of BOG in which the previously existing debt obligations of BOG were partially extinguished and otherwise renegotiated. Simultaneous with that

acquisition, the Company acquired a 24.6% membership interest in DBH for approximately $8.7 million. DBH’s purchase of BOG using the acquisition method of accounting resulted in a difference between the carrying amount of the Company’s investment in DBH and the underlying equity in net assets. The difference is being adjusted against the equity in earnings based on the depletion of DBH’s oil and gas assets and related reserves. The Company’s equity-method investment balance in DBH was approximately $13.8 million at December 31, 2010. The Company recorded earnings from its equity-method investment in DBH of approximately $0.9 million for the two months ended February 28, 2011 prior to the contributions and $7.1 million for the year ended December 31, 2010. From the date of acquisition through December 31, 2009, the Company recorded a loss from its equity-method investment in DBH of approximately $1.0 million. Additionally, the Company received approximately $1.0 million of cash distributions from its equity-method investment in DBH for the year ended December 31, 2010. The Company had a receivable from this equity-method investment of approximately $1.4 million at December 31, 2010. The Company also recorded revenue from this equity-method investment of approximately $0.9 million for the two months ended February 28, 2011 prior to the contributions and $4.1 million for the year ended December 31, 2010. From the date of acquisition through December 31, 2009, the Company recorded revenue from this equity-method investment of $2.4 million.

Combined summarized financial information for all investments that are accounted for using the equity-method of accounting is as follows (in thousands):


	December 31,
	2011		2010
Current Assets	$	229,516	$	104,241
Noncurrent assets		1,305,514		487,136

Total assets	$	1,535,030	$	591,377

Current liabilities	$	202,465	$	49,587
Noncurrent liabilities		797,031		197,672

Total liabilities	$	999,496	$	247,259


	Years Ended December 31,
	2011		2010			2009
Revenues	$	468,140	$	204,935		$	245,092
Cost of sales		181,433		80,525			110,101

Gross profit	$	286,707	$	124,410		$	134,991

Income (loss) from continuing operations	$	95,581	$	(8,016	)	$	(10,024	)

Subsequent Event

On February 1, 2012, SandRidge Energy Inc. (NYSE: SD) entered into an agreement to acquire Dynamic Offshore for aggregate consideration of $1.275 billion consisting of approximately $680 million in cash and approximately 74 million shares of SandRidge common stock valued at an assumed price of $8.02 per share. This sale is expected to close in the second quarter of 2012, at which time the anticipated gain will be reflected. In accordance with authoritative guidance related to equity securities, the Company will account for the shares received through this transaction as available-for-sale securities. The shares will be recorded at their fair market value and any unrealized gains or losses will be excluded from earnings and reported as a net amount within accumulated other comprehensive income (loss) within stockholders’ equity.

(8)

Debt

The Company’s long-term debt as of December 31, 2011 and 2010 consisted of the following (in thousands):


	2011			2010
Revolving credit facility—interest payable monthly at floating rate, due December 2014	$	75,000		$	175,000
U.S. Government guaranteed long-term financing—interest payable semiannually at 6.45%, due in semiannual installments through June 2027		12,546			13,356
Senior Notes—interest payable semiannually at 6⁷/8%, due June 2014		300,000			300,000
Discount on 6 ⁷/8% Senior Notes		(1,649	)		(2,248	)
Senior Notes—interest payable semiannually at 6³/8%, due May 2019		500,000			—
Senior Notes—interest payable semiannually at 7¹/8%, due December 2021		800,000			—
Senior Exchangeable Notes—interest payable semiannually at 1.5% until December 2011 and 1.25% thereafter		—			400,000
Discount on 1.5% Senior Exchangeable Notes		—			(19,663	)

		1,685,897			866,445
Less current portion		810			184,810

Long-term debt	$	1,685,087		$	681,635

The Company had a $400 million bank revolving credit facility. Any amounts outstanding under the revolving credit facility were due on July 20, 2014. The weighted average interest rate on amounts outstanding under the revolving credit facility was 5.0% and 3.4% per annum at December 31, 2011 and 2010, respectively. On February 7, 2012, this revolving credit facility was amended in connection with the Complete acquisition. See additional details on this amendment within the subsequent event portion of this footnote.

The Company also had approximately $11.0 million of letters of credit outstanding, which reduce the Company’s borrowing availability under the revolving credit facility. Amounts borrowed under the credit facility bear interest at a LIBOR rate plus margins that depend on the Company’s leverage ratio. Indebtedness under the credit facility is secured by substantially all of the Company’s assets, including the pledge of the stock of the Company’s principal domestic subsidiaries. The credit facility contains customary events of default and requires that the Company satisfy various financial covenants. It also limits the Company’s ability to pay dividends or make other distributions, make acquisitions, make changes to the Company’s capital structure, create liens or incur additional indebtedness. At December 31, 2011, the Company was in compliance with all such covenants.

At December 31, 2011, the Company had outstanding $12.5 million in U.S. Government guaranteed long-term financing under Title XI of the Merchant Marine Act of 1936, which is administered by the Maritime Administration, for two liftboats. The debt bears interest at 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. The Company’s obligations are secured by mortgages on the two liftboats. In accordance with the agreement, the Company is required to comply with certain covenants and restrictions, including the maintenance of minimum net worth, working capital and debt-to-equity requirements. At December 31, 2011, the Company was in compliance with all such covenants. The Company has notified the Maritime Administration of its intent to repay this facility in connection with the sale of the marine segment.

The Company also has outstanding $300 million of 6⁷/8% 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 the Company from incurring additional debt, repurchasing capital stock, paying dividends or making other distributions, incurring liens, selling assets or entering into certain mergers or acquisitions. At December 31, 2011, the Company was in compliance with all such covenants.

In April 2011, the Company issued $500 million of 6³/8% unsecured senior notes due 2019. Costs associated with the issuance of these notes were approximately $9.7 million and were capitalized and will be amortized over the term of the 6³/8% senior notes. The Company used a portion of the proceeds of this debt issuance to redeem all of the outstanding $400 million 1.50% senior exchangeable notes on December 15, 2011. The indenture governing the 6³/8% senior notes requires semi-annual interest payments on May 1^st and November 1^stof each year through the maturity date of May 1, 2019. The indenture contains certain covenants that, among other things, limit the Company from incurring additional debt, repurchasing capital stock, paying dividends or making other distributions, incurring liens, selling assets or entering into certain mergers or acquisitions. At December 31, 2011, the Company was in compliance with all such covenants.

In December 2011, the Company issued $800 million of 7¹/8% unsecured senior notes due 2021. Costs associated with the issuance of these notes were approximately $15.1 million and were capitalized and will be amortized over the term of the notes. Certain restrictions were placed on the proceeds from the issuance of these notes. These restrictions limited the Company to use the proceeds, net of fees and expenses from the issuance, to partially fund the Complete acquisition which occurred in February 2012 (see note 3). The indenture governing the 7¹/8% senior notes requires semi-annual interest payments on June 15^th and December 15^thof each year through the maturity date of December 15, 2021. The indenture contains certain covenants that, among other things, limit the Company from incurring additional debt, repurchasing capital stock, paying dividends or making other distributions, incurring liens, selling assets or entering into certain mergers or acquisitions. At December 31, 2011, the Company was in compliance with all such covenants.

On December 15, 2011, the Company redeemed all of its outstanding $400 million 1.50% senior exchangeable notes for 100% of the principal amount. As the holders of the Company’s 1.50% senior exchangeable notes had the ability to require the Company to purchase all of the notes on December 15, 2011, the entire amount of these notes would have been deemed to be a current liability at December 31, 2010. However, in accordance with accounting guidance related to classification of short-term debt that is to be refinanced, the Company utilized the amount available to it under its revolving credit facility as of December 31, 2010 of approximately $216.0 million to classify this portion as long-term under the assumption that the revolving credit facility could be used to refinance that portion of the debt.

Annual maturities of long-term debt for each of the five fiscal years following December 31, 2011 and thereafter are as follows (in thousands):


2012		810
2013		810
2014		375,810
2015		810
2016		810
Thereafter		1,308,496

Total	$	1,687,546

Subsequent Events

On February 7, 2012, in connection with the Complete acquisition, the Company amended its bank credit facility to increase the revolving borrowing capacity to an aggregate amount of $600 million from $400 million and to include a $400 million term loan. The maturity date of both the credit facility and the term loan is February 7, 2017, and any amounts outstanding under the revolving credit facility and the term loan are due at maturity. The principal balance of the term loan is payable in installments of $5.0 million on the last day of each fiscal quarter, commencing on June 30, 2012. Costs associated with these amendments totaled approximately $24.5 million. These costs will be capitalized and amortized over the term of the credit facility.

(9)	Stock-Based and Long-Term Compensation

The Company maintains various stock incentive plans that provide long-term incentives to the Company’s key employees, including officers, directors, consultants and advisers (Eligible Participants). Under the incentive plans, the Company may grant incentive stock options, non-qualified stock options, restricted stock, restricted stock units, stock appreciation rights, other stock-based awards or any combination thereof to Eligible Participants. The Compensation Committee of the Company’s Board of Directors establishes the terms and conditions of any awards granted under the plans, provided that the exercise price of any stock options granted may not be less than the fair value of the common stock on the date of grant.

Stock Options

The Company has granted non-qualified stock options under its stock incentive plans. The stock options generally vest in equal installments over three years and expire in ten years. Non-vested stock options are generally forfeitable upon termination of employment. During 2011, the Company granted 207,183 non-qualified stock options under these same terms.

In accordance with authoritative guidance related to stock-based compensation, the Company recognizes compensation expense for stock option grants based on the fair value at the date of grant using the Black-Scholes-Merton option pricing model. The Company uses historical data, among other factors, to estimate the expected price volatility, the expected life of the stock option and the expected forfeiture rate. The risk-free rate is based on the U.S. Treasury yield curve in effect at the time of grant for the expected life of the stock option. The following table presents the fair value of stock option grants made during the years ended December 31, 2011, 2010 and 2009, and the related assumptions used to calculate the fair value:


	Years Ended December 31,
	2011 Actual			2010 Actual			2009 Actual
Weighted average fair value of grants	$	13.54		$	10.56		$	8.95

Black-Scholes-Merton Assumptions:
Risk free interest rate		0.85	%		2.07	%		1.77	%
Expected life (years)		5			4			4
Volatility		56.31	%		49.28	%		53.57	%
Dividend yield		—			—			—

The Company’s compensation expense related to stock options for the years ended December 31, 2011, 2010 and 2009 was approximately $3.3 million, $15.5 million and $2.4 million, respectively, which is reflected in general and administrative expenses. During 2010, the Company modified 1,418,395 stock options, affecting three employees in connection with the management transition of certain executive officers. These stock options were accelerated to vest by December 31, 2010. The Company incurred incremental compensation cost of approximately $9.8 million during 2010 as a result of this modification.

The following table summarizes stock option activity for the years ended December 31, 2011, 2010 and 2009:


	Number of Options			Weighted Average Option Price		Weighted Average Remaining Contractual Term (in years)		Aggregate Intrinsic Value (in thousands)
Outstanding at December 31, 2008		3,267,910		$	15.37
Granted		309,352		$	20.01
Exercised		(38,717	)	$	9.71

Outstanding at December 31, 2009		3,538,545		$	15.84
Granted		1,549,058		$	25.04
Exercised		(87,150	)	$	10.62

Outstanding at December 31, 2010		5,000,453		$	18.78
Granted		207,183		$	28.97
Exercised		(876,435	)	$	11.71

Outstanding at December 31, 2011		4,331,201		$	20.70		6.0	$	36,885

Exercisable at December 31, 2011		3,647,745		$	19.62		5.4	$	34,783

Options expected to vest		683,456		$	26.46		8.9	$	2,102

The aggregate intrinsic value in the table above represents the total pre-tax intrinsic value (the difference between the Company’s closing stock price on December 31, 2011 and the stock option price, multiplied by the number of “in-the-money” stock options) that would have been received by the stock option holders if all the options had been exercised on December 31, 2011. The Company expects all of its remaining non-vested options to vest as they are primarily held by its officers and senior managers.

The total intrinsic value of stock options exercised during the year ended December 31, 2011 (the difference between the stock price upon exercise and the option price) was approximately $23.4 million. The Company received approximately $10.3 million, $0.9 million and $0.4 million during the years ended December 31, 2011, 2010 and 2009, respectively, from employee stock option exercises. In accordance with authoritative guidance related to stock-based compensation, the Company has reported the tax benefits of approximately $7.4 million, $0.6 million, $0.2 million from the exercise of stock options for the years ended December 31, 2011, 2010 and 2009, respectively, as financing cash flows.

A summary of information regarding stock options outstanding at December 31, 2011 is as follows:


	Options Outstanding						Options Exercisable
Range of Exercise Prices	Shares		Weighted Average Remaining Contractual Life		Weighted Average Price		Shares		Weighted Average Price
$7.31 – $8.79		61,665		1.3 years	$	8.78		61,665	$	8.78
$9.10 – $9.90		80,313		0.4 years	$	9.48		80,313	$	9.48
$10.36 – $10.90		770,268		2.6 years	$	10.66		770,268	$	10.66
$12.45 – $13.34		309,977		6.9 years	$	12.88		309,977	$	12.88
$17.46 – $23.00		1,502,669		6.3 years	$	19.92		1,236,572	$	19.55
$24.00 – $30.00		1,133,657		7.9 years	$	25.98		829,664	$	25.38
$34.40 – $37.64		464,239		6.8 years	$	35.37		350,873	$	35.57
$40.00 – $40.69		8,413		6.2 years	$	40.69		8,413	$	40.69

The following table summarizes non-vested stock option activity for the year ended December 31, 2011:


	Number of Options			Weighted Average Grant Date Fair Value
Non-vested at December 31, 2010		869,971		$	10.23
Granted		207,183		$	13.54
Vested		(393,698	)	$	9.61

Non-vested at December 31, 2011		683,456		$	11.59

As of December 31, 2011, there was approximately $6.8 million of unrecognized compensation expense related to non-vested stock options outstanding. The Company expects to recognize approximately $3.7 million, $2.2 million and $0.9 million of compensation expense during the years 2012, 2013 and 2014, respectively, for these outstanding non-vested stock options.

Restricted Stock

During the year ended December 31, 2011, the Company granted 567,083 shares of restricted stock to its employees. Shares of restricted stock generally vest in equal annual installments over three years. Non-vested shares are generally forfeitable upon the termination of employment. Holders of restricted stock are entitled to all rights of a shareholder of the Company with respect to the restricted stock, including the right to vote the shares and receive any dividends or other distributions. Compensation expense associated with restricted stock is measured based on the grant date fair value of our common stock and is recognized on a straight line basis over the vesting period. The Company’s compensation expense related to restricted stock outstanding for the years ended December 31, 2011, 2010 and 2009 was approximately $6.0 million, $11.4 million and $5.8 million, respectively, which is reflected in general and administrative expenses. During 2010, the Company modified 282,781 shares of restricted stock affecting three employees in connection with the management transition of certain executive officers. These shares of restricted stock were accelerated to vest by December 31, 2010. The Company incurred incremental compensation cost of approximately $4.3 million during the year as a result of this modification.

A summary of the status of restricted stock for the year ended December 31, 2011 is presented in the table below:


	Number of Shares			Weighted Average Grant Date Fair Value
Non-vested at December 31, 2010		792,436		$	22.25
Granted		567,083		$	28.84
Vested		(294,144	)	$	19.80
Forfeited		(25,658	)	$	22.49

Non-vested at December 31, 2011		1,039,717		$	27.07

As of December 31, 2011, there was approximately $21.8 million of unrecognized compensation expense related to non-vested restricted stock. The Company expects to recognize approximately $9.1 million, $7.4 million, $5.3 million during the years 2012, 2013 and 2014, respectively, for non-vested restricted stock. In accordance with authoritative guidance related to stock-based compensation, the Company has reported tax benefits of approximately $1.6 million from the vesting of restricted stock for the year ended December 31, 2011 as financing cash flows.

Restricted Stock Units

Under the Amended and Restated 2004 Directors Restricted Stock Units Plan, each non-employee director is issued annually a number of Restricted Stock Units (RSUs) having an aggregate dollar value determined by the Company’s Board of Directors. The exact number of RSUs granted is determined by dividing the dollar value determined by the Company’s Board of Directors based on the fair market value of the Company’s common stock on the day of the annual stockholders’ meeting or a pro rata amount if the appointment occurs subsequent to the annual stockholders’ meeting. An RSU represents the right to receive from the Company, within 30 days of the date the director ceases to serve on the Board, one share of the Company’s common stock. At December 31, 2011, 170,457 RSUs were outstanding under this plan. The Company’s expense related to RSUs for the years ended December 31, 2011, 2010 and 2009 was approximately $1.2 million, $1.2 million and $0.6 million, respectively, which is reflected in general and administrative expenses.

A summary of the activity of restricted stock units for the year ended December 31, 2011 is presented in the table below:


	Number of Restricted Stock Units		Weighted Average Grant Date Fair Value
Outstanding at December 31, 2010		136,173	$	27.02
Granted		34,284	$	35.10

Outstanding at December 31, 2011		170,457	$	28.64

Performance Share Units

The Company has issued performance share units (PSUs) to its employees as part of the Company’s long-term incentive program. There is a three year performance period associated with each PSU grant. The two performance measures applicable to all participants are the Company’s return on invested capital and total shareholder return relative to those of the Company’s pre-defined “peer group.” The PSUs provide for settlement in cash or up to 50% in equivalent value in the Company’s common stock, provided the participant has met specified continued service requirements. At December 31, 2011, there were 366,133 PSUs outstanding (70,522, 96,673, 81,154 and 117,784 related to performance periods ending December 31, 2011, 2012, 2013 and 2014, respectively). The Company’s compensation expense related to all outstanding PSUs for the years ended December 31, 2011, 2010 and 2009 was approximately $3.2 million, $5.2 million and $7.3 million, respectively, which is reflected in general and administrative expenses. The Company has recorded a current liability of approximately $3.8 million and $6.0 million at December 31, 2011 and 2010, respectively, for outstanding PSUs, which is reflected in accrued expenses. Additionally, the Company has recorded a long-term liability of approximately $6.8 million and $7.0 million at December 31, 2011 and 2010, respectively, for outstanding PSUs, which is reflected in other long-term liabilities. In 2011, the Company paid approximately $2.8 million and issued approximately 67,300 shares of its common stock to settle PSUs for the performance period ended December 31, 2010. In 2010, the Company paid approximately $6.4 million in cash to settle PSUs for the performance period ended December 31, 2009. In 2009, the Company paid approximately $4.7 million in cash and issued approximately 71,400 shares of its common stock to its employees to settle PSUs for the performance period ended December 31, 2008.

Employee Stock Purchase Plan

The Company has an employee stock purchase plan under which an aggregate of 1,250,000 shares of common stock were reserved for issuance. Under this stock purchase plan, eligible employees can purchase shares of the Company’s common stock at a discount. The Company received approximately $2.2 million, $1.9 million and $2.0 million related to shares issued under these plans for the years ended December 31, 2011, 2010 and 2009, respectively. For the years ended December 31, 2011, 2010 and 2009, the Company recorded compensation expense of approximately $388,000, $345,000 and $350,000, respectively, which is reflected in general and

administrative expenses. Additionally, the Company issued approximately 75,700, 94,200 and 133,400 shares for the years ended December 31, 2011, 2010 and 2009, respectively, related to these stock purchase plans.

Profit Sharing Plan

The Company maintains a defined contribution profit sharing plan for employees who have satisfied minimum service requirements. Employees may contribute up to 75% of their earnings to the plan subject to the contribution limitations imposed by the Internal Revenue Service. The Company may provide a discretionary match, not to exceed 5% of an employee’s salary. The Company made contributions of approximately $7.4 million, $3.3 million and $3.8 million in 2011, 2010 and 2009, respectively.

Non-Qualified Deferred Compensation Plan

The Company has a non-qualified deferred compensation plan which allows certain highly compensated employees the option to defer up to 75% of their base salary, up to 100% of their bonus, and up to 100% of the cash portion of their performance share unit compensation to the plan. Payments are made to participants based on their annual enrollment elections and plan balances. Participants earn a return on their deferred compensation that is based on hypothetical investments in certain mutual funds. Changes in market value of these hypothetical participant investments are reflected as an adjustment to the deferred compensation liability of the Company with an offset to compensation expense (see note 14). At December 31, 2011 and 2010, the liability of the Company to the participants was approximately $13.0 million and $14.2 million, respectively, which reflects the accumulated participant deferrals and earnings (losses) as of that date. These amounts are recorded in other long-term liabilities. Additionally at December 31, 2011 and 2010, the Company had approximately $2.8 million and $3.0 million in accounts payable in anticipation of pending payments. For the years ended December 31, 2011, 2010 and 2009, the Company recorded compensation income (expense) of approximately $0.1 million, ($1.8) million and ($2.8) million, respectively, related to the earnings and losses of the deferred compensation plan liability. The Company makes contributions that approximate the participant deferrals into various investments, principally life insurance that is invested in mutual funds similar to the participants’ hypothetical investment elections. Changes in market value of the investments and life insurance are reflected as adjustments to the deferred compensation plan asset with an offset to other income (expense). At December 31, 2011 and 2010, the deferred contribution plan asset was approximately $10.6 million and $10.8 million, respectively, and is recorded in intangible and other long-term assets. For the years ended December 31, 2011, 2010 and 2009, the Company recorded other income (expense) of ($0.2) million, $0.8 million and $0.6 million, respectively, related to the earnings and losses of the deferred compensation plan assets.

Supplemental Executive Retirement Plan

The Company also has a supplemental executive retirement plan (SERP). The SERP provides retirement benefits to the Company’s executive officers and certain other designated key employees. The SERP is an unfunded, non-qualified defined contribution retirement plan, and all contributions under the plan are unfunded credits to a notional account maintained for each participant. Under the SERP, the Company will generally make annual contributions to a retirement account based on age and years of service. During 2011, 2010 and 2009, the participants in the plan received contributions ranging from 5% to 35% of salary and annual cash bonus, which totaled approximately $1.0 million, $5.5 million and $2.2 million, respectively. The Company may also make discretionary contributions to a participant’s retirement account. In 2010, the Company made a discretionary contribution to the account of its former chief operating officer in the amount of $4.7 million as part of its executive management transition. The Company recorded $1.8 million, $5.6 million and $2.1 million of compensation expense in general and administrative expenses for the years ended December 31, 2011, 2010 and 2009, respectively, inclusive of discretionary contributions. During the year ended December 31, 2011, the Company paid approximately $5.5 million to select participants of this plan. There were no payments to participants of this plan in the years 2010 and 2009.

(10)	Income Taxes

The components of income and loss from continuing operations before income taxes for the years ended December 31, 2011, 2010 and 2009 are as follows (in thousands):


	2011		2010		2009
Domestic	$	220,908	$	117,988	$	(191,543	)
Foreign		792		7,114		31,664

	$	221,700	$	125,102	$	(159,879	)

The components of income tax expense (benefit) for the years ended December 31, 2011, 2010 and 2009 are as follows (in thousands):


	2011			2010			2009
Current:
Federal	$	19,810		$	16,002		$	1,555
State		551			1,939			(256	)
Foreign		19,716			17,628			16,019

		40,077			35,569			17,318

Deferred:
Federal		39,284			11,367			(71,874	)
State		1,658			(653	)		(1,831	)
Foreign		(1,873	)		(2,998	)		(1,169	)

		39,069			7,716			(74,874	)

	$	79,146		$	43,285		$	(57,556	)

Income tax expense (benefit) differs from the amounts computed by applying the U.S. Federal income tax rate of 35% to income (loss) before income taxes for the years ended December 31, 2011, 2010 and 2009 as follows (in thousands):


	2011			2010			2009
Computed expected tax expense (benefit)	$	77,595		$	43,786		$	(55,958	)
Increase (decrease) resulting from State and foreign income taxes		(3,300	)		1,768			(3,712	)
Other		4,851			(2,269	)		2,114

Income tax	$	79,146		$	43,285		$	(57,556	)

The tax effects of temporary differences that give rise to significant components of deferred income tax assets and liabilities at December 31, 2011 and 2010 are as follows (in thousands):


	2011		2010
Deferred tax assets:
Allowance for doubtful accounts	$	9,054	$	7,097
Operating loss and tax credit carryforwards		24,101		10,120
Compensation and employee benefits		28,305		29,358
Decommissioning liabilities		39,638		37,909
Deferred interest expense related to exchangeable notes		—		526
Other		35,005		21,626

Net deferred tax assets		136,103		106,636

Deferred tax liabilities:
Property, plant and equipment		317,033		248,453
Notes receivable		25,599		23,857
Goodwill and other intangible assets		22,432		19,555
Deferred revenue on long-term contracts		47,341		53,465
Other		21,987		14,595

Deferred tax liabilities		434,392		359,925

Net deferred tax liability	$	298,289	$	253,289

The net deferred tax assets reflect management’s estimate of the amount that will be realized from future profitability and the reversal of taxable temporary differences that can be predicted with reasonable certainty. A valuation allowance is recognized if it is more likely than not that at least some portion of any deferred tax asset will not be realized.

Net deferred tax liabilities were classified in the consolidated balance sheet at December 31, 2011 and 2010 as follows (in thousands):


	2011		2010
Deferred tax liabilities:
Current deferred income taxes	$	831	$	29,353
Noncurrent deferred income taxes		297,458		223,936

Net deferred tax liability	$	298,289	$	253,289

As of December 31, 2011, the Company had approximately $1.8 million in net operating loss carryforwards, which are available to reduce future taxable income. The expiration dates for utilization of the loss carryforwards are 2020 through 2026. Utilization of $0.6 million of the net operating loss carryforwards will be subject to the annual limitations due to the ownership change limitations provided by the Internal Revenue Code of 1986, as amended. As of December 31, 2011, the Company also has various state net operating loss carryforwards of an estimated $60 million with expiration dates from 2020 to 2026. A deferred tax asset of $3.7 million reflects the expected future tax benefit for the state loss carryforwards.

The Company has not provided United States income tax expense on earnings of its foreign subsidiaries, since the Company has reinvested or expects to reinvest the undistributed earnings indefinitely. At December 31, 2011, the undistributed earnings of the Company’s foreign subsidiaries were approximately $154 million. If these earnings are repatriated to the United States in the future, additional tax provisions may be required. It is not practicable to estimate the amount of taxes that might be payable on such undistributed earnings.

The Company files income tax returns in the U.S. federal and various state and foreign jurisdictions. The number of years that are open under the statute of limitations and subject to audit varies depending on the tax jurisdiction. The Company remains subject to U.S. federal tax examinations for years after 2007.

The Company had approximately $21.7 million, $24.8 million and $11.0 million of unrecorded tax benefits at December 31, 2011, 2010 and 2009, respectively, all of which would impact the Company’s effective tax rate if recognized.

The activity in unrecognized tax benefits at December 31, 2011, 2010 and 2009 is as follows (in thousands):


	2011			2010			2009
Unrecognized tax benefits,
December 31, 2010, 2009 and 2008, respectively	$	24,760		$	11,013		$	9,652
Additions based on tax positions related to current year		—			36			3,377
Additions based on tax positions related to prior years		871			16,607			186
Reductions based on tax positions related to prior years		(3,939	)		(2,896	)		(2,202	)

Unrecognized tax benefits,
December 31, 2011, 2010 and 2009, respectively	$	21,692		$	24,760		$	11,013

(11)	Segment Information

Business Segments

The Company currently has three reportable segments: subsea and well enhancement, drilling products and services, and marine. The subsea and well enhancement segment provides production-related services used to enhance, extend and maintain oil and gas production, which include integrated subsea services and engineering services, mechanical wireline, hydraulic workover and snubbing, well control, coiled tubing, electric line, pumping and stimulation and wellbore evaluation services; well plug and abandonment services; stimulation and sand control equipment and services; and other oilfield services used to support drilling and production operations. The subsea and well enhancement segment also includes production handling arrangements, as well as the production and sale of oil and gas. The drilling products and services segment rents and sells stabilizers, drill pipe, tubulars and specialized equipment for use with onshore and offshore oil and gas well drilling, completion, production and workover activities. It also provides on-site accommodations and bolting and machining services. The marine segment operates liftboats for production service activities, as well as oil and gas production facility maintenance, construction operations and platform removals.

The accounting policies of the reportable segments are the same as those described in note 1 of these notes to the consolidated financial statements. The Company evaluates the performance of its operating segments based on operating profits or losses. Segment revenues reflect direct sales of products and services for that segment, and each segment records direct expenses related to its employees and its operations. Identifiable assets are primarily those assets directly used in the operations of each segment.

Summarized financial information concerning the Company’s segments as of December 31, 2011, 2010 and 2009 and for the years then ended is shown in the following tables (in thousands):


2011	Subsea and Well Enhancement		Drilling Products and Services		Marine			Unallocated			Consolidated Total
Revenues	$	1,367,834	$	611,101	$	91,231		$	—		$	2,070,166
Cost of services, rentals, and sales (exclusive of items shown separately below)		832,568		220,647		64,788			—			1,118,003
Depreciation, depletion, amortization and accretion		115,616		130,801		10,896			—			257,313
General and administrative		253,550		121,274		8,743			—			383,567
Reduction in the value of assets		—		—		46,096			—			46,096
Gain on sale of businesses		—		—		8,558			—			8,558
Income (loss) from operations		166,100		138,379		(30,734	)		—			273,745
Interest expense, net		—		—		—			(73,843	)		(73,843	)
Interest income		4,542		—		—			1,684			6,226
Other income		105		—		—			(927	)		(822	)
Earnings from equity-method investments		—		—		—			16,394			16,394

Income (loss) before income taxes	$	170,747	$	138,379	$	(30,734	)	$	(56,692	)	$	221,700

Identifiable assets	$	2,863,550	$	947,679	$	164,444		$	72,472		$	4,048,145
Capital expenditures	$	286,066	$	219,121	$	2,514		$	—		$	507,701


2010	Subsea and Well Enhancement		Drilling Products and Services		Marine			Unallocated			Consolidated Total
Revenues	$	1,112,662	$	474,707	$	94,247		$	—		$	1,681,616
Cost of services, rentals, and sales (exclusive of items shown separately below)		675,447		176,453		66,813			—			918,713
Depreciation, depletion, amortization and accretion		95,306		114,722		10,807			—			220,835
General and administrative		221,615		107,191		14,075			—			342,881
Reduction in the value of assets		—		—		32,004						32,004
Gain on sale of business		—		—		1,083			—			1,083
Income (loss) from operations		120,294		76,341		(28,369	)		—			168,266
Interest expense, net		—		—		—			(57,377	)		(57,377	)
Interest income		4,548		—		—			595			5,143
Other income		—		—		—			825			825
Earnings from equity-method investments		—		—		—			8,245			8,245

Income (loss) before income taxes	$	124,842	$	76,341	$	(28,369	)	$	(47,712	)	$	125,102

Identifiable assets	$	1,769,813	$	802,785	$	255,883		$	79,052		$	2,907,533
Capital expenditures	$	150,313	$	142,942	$	29,989		$	—		$	323,244


2009	Subsea and Well Enhancement			Drilling Products and Services		Marine		Unallocated			Consolidated Total
Revenues	$	919,335		$	426,876	$	103,089	$	—		$	1,449,300
Cost of services, rentals, and sales (exclusive of items shown separately below)		616,116			143,802		64,116		—			824,034
Depreciation and amortization		89,986			105,613		11,515		—			207,114
General and administrative		149,122			90,318		19,653		—			259,093
Reduction in value of assets		212,527			—		—		—			212,527
Gain on sale of businesses		—			—		2,084		—			2,084
Income (loss) from operations		(148,416	)		87,143		9,889		—			(51,384	)
Interest expense, net		—			—		—		(50,906	)		(50,906	)
Interest income		—			—		—		926			926
Other income		—			—		—		571			571
Losses from equity-method investments		—			—		—		(22,600	)		(22,600	)
Reduction in the value of equity-method investment		—			—		—		(36,486	)		(36,486	)

Income (loss) before income taxes	$	(148,416	)	$	87,143	$	9,889	$	(108,495	)	$	(159,879	)

Identifiable assets	$	1,377,122		$	759,418	$	299,834	$	80,291		$	2,516,665
Capital expenditures	$	99,551		$	124,845	$	66,881	$	—		$	291,277

Geographic Segments

The Company attributes revenue to various countries based on the location where services are performed or the destination of the drilling products or equipment sold or leased. Long-lived assets consist primarily of property, plant and equipment and are attributed to various countries based on the physical location of the asset at a given fiscal year end. The Company’s information by geographic area is as follows (amounts in thousands):


	Revenues						Long-Lived Assets
	Years Ended December 31,						December 31,
	2011		2010		2009		2011		2010
United States	$	1,525,296	$	1,216,295	$	1,126,071	$	1,060,483	$	881,416
Other Countries		544,870		465,321		323,229		446,885		431,734

Total	$	2,070,166	$	1,681,616	$	1,449,300	$	1,507,368	$	1,313,150

(12)

Guarantee

In connection with the sale of SPN Resources in 2008, the Company guaranteed the performance of its decommissioning liabilities. In accordance with authoritative guidance related to guarantees, the Company has assigned an estimated value of $2.6 million at December 31, 2011 and 2010 related to decommissioning performance guarantees, which is reflected in other long-term liabilities. The Company believes that the likelihood of being required to perform these guarantees is remote. In the unlikely event that Dynamic Offshore defaults on the decommissioning liabilities existing at the closing date, the total maximum potential obligation under these guarantees is estimated to be approximately $158.7 million, net of the contractual right to receive payments from third parties, which is approximately $24.6 million, as of December 31, 2011. The total maximum potential obligation will decrease over time as the underlying obligations are fulfilled by SPN Resources.

(13)	Commitments and Contingencies

The Company leases many of its office, service and assembly facilities under operating leases. In addition, the Company also leases certain assets used in providing services under operating leases. The leases expire at various

dates over an extended period of time. Total rent expense was approximately $18.3 million, $15.1 million and $12.0 million in 2011, 2010 and 2009, respectively. Future minimum lease payments under non-cancelable leases for the five years ending December 31, 2012 through 2016 and thereafter are as follows: $20.7 million, $17.0 million, $14.3 million, $10.8 million, $9.1 million and $30.7 million, respectively.

Due to the nature of the Company’s business, the Company is involved, from time to time, in routine litigation or subject to disputes or claims regarding our business activities. Legal costs related to these matters are expensed as incurred. In management’s opinion, none of the pending litigation, disputes or claims will have a material adverse effect on the Company’s financial condition, results of operations or liquidity.

(14)	Fair Value Measurements

The following table provides a summary of the financial assets and liabilities measured at fair value on a recurring basis at December 31, 2011 and December 31, 2010 (in thousands):


	December 31, 2011		Fair Value Measurements at Reporting Date Using
	December 31, 2011		Level 1		Level 2		Level 3
Intangible and other long-term assets
Non-qualified deferred compensation assets	$	10,597	$	815	$	9,782		—
Interest rate swap	$	1,904		—	$	1,904		—
Accounts payable
Non-qualified deferred compensation liabilities	$	2,790		—	$	2,790		—
Other long-term liabilities
Non-qualified deferred compensation liabilities	$	12,975		—	$	12,975		—

	December 31, 2010		Level 1		Level 2		Level 3
Intangible and other long-term assets
Non-qualified deferred compensation assets	$	10,820	$	812	$	10,008		—
Interest rate swap	$	161		—	$	161		—
Accounts payable
Non-qualified deferred compensation liabilities	$	2,953	$	1,429	$	1,524		—
Other long-term liabilities
Non-qualified deferred compensation liabilities	$	14,236		—	$	14,236		—

The Company’s non-qualified deferred compensation plan allows officers and highly compensated employees to defer receipt of a portion of their compensation and contribute such amounts to one or more hypothetical investment funds (see note 9). The Company entered into a separate trust agreement, subject to general creditors, to segregate the assets of the plan and it reports the accounts of the trust in its consolidated financial statements. These investments are reported at fair value based on unadjusted quoted prices in active markets for identifiable assets and observable inputs for similar assets and liabilities, which represent Levels 1 and 2, respectively in the fair value hierarchy.

In March 2010, the Company entered into an interest rate swap agreement for a notional amount of $150 million, whereby the Company is entitled to receive semi-annual interest payments at a fixed rate of 6⁷/8% per annum and is obligated to make quarterly interest payments at a floating rate, which is adjusted every 90 days, based on LIBOR plus a fixed margin.

In accordance with authoritative guidance, non-financial assets and non-financial liabilities are remeasured at fair value on a non-recurring basis. During the year ended 2011, the Company wrote off approximately $46.1 million of certain long-lived assets to approximate the indicated fair value of the liftboats from prospective purchasers. During the year ended December 31, 2010, the Company wrote off approximately $32.0 million of long-lived liftboat components primarily related to the two partially completed liftboats. During the year ended December 31, 2009, the Company identified impairments of certain long-lived assets of approximately $212.5 million. Additionally, during 2009, the Company recorded a $36.5 million reduction in the value of its equity-method investment in BOG.

The following table reflects the fair value measurements used in testing the impairment of long-lived assets during the years ended December 31, 2011, 2010 and 2009 (in thousands):


			Fair Value Measurements at Reporting Date Using
	December 31, 2011		(Level 1)		(Level 2)		(Level 3)		Total Losses
Property, plant and equipment, net	$	134,000		—		—	$	134,000	$	(35,762	)
Goodwill	$	- 0 -					$	- 0 -	$	(10,334	)

	December 31, 2010		(Level 1)		(Level 2)		(Level 3)		Total Losses
Property, plant and equipment, net	$	- 0 -		—		—	$	- 0 -	$	(32,004	)

	December 31, 2009		(Level 1)		(Level 2)		(Level 3)		Total Losses
Property, plant and equipment, net	$	107,591		—		—	$	107,591	$	(119,844	)
Intangible and other long-term assets, net	$	- 0 -		—		—	$	- 0 -	$	(92,683	)
Equity-method investments	$	- 0 -		—		—	$	- 0 -	$	(36,486	)

(15)	Derivative Financial Instruments

From time to time, the Company may employ interest rate swaps in an attempt to achieve a more balanced debt portfolio. The Company does not use derivative financial instruments for trading or speculative purposes.

In March 2010, the Company entered into an interest rate swap agreement for a notional amount of $150 million related to its fixed rate debt maturing on June 1, 2014. This transaction was designated as a fair value hedge since the swap hedges against the change in fair value of fixed rate debt resulting from changes in interest rates. The Company recorded a derivative asset of $1.9 million and $0.2 million, respectively, within intangible and other long-term assets in the consolidated balance sheet at December 31, 2011 and 2010. The change in fair value of the interest rate swap is included in the adjustments to reconcile net income to net cash provided by operating activities in the consolidated statements of cash flows.

The location and effect of the derivative instrument on the consolidated statements of operations for the years ended December 31, 2011 and 2010, presented on a pre-tax basis, is as follows (in thousands):


	Location of (gain) loss recognized	Amount of (gain) loss recognized in the year ending December 31,
	Location of (gain) loss recognized	2011			2010
Interest rate swap	Interest expense, net	$	793		$	(1,742	)
Hedged item—debt	Interest expense, net		(2,536	)		1,581

		$	(1,743	)	$	(161	)

For the years ended December 31, 2011 and 2010, approximately $1.7 million and $0.2 million, respectively, of interest income was related to the ineffectiveness associated with this fair value hedge. Hedge ineffectiveness represents the difference between the changes in fair value of the derivative instruments and the changes in fair value of the fixed rate debt attributable to changes in the benchmark interest rate.

This interest rate swap exposes the Company to credit risk to the extent that the counterparty may be unable to meet the terms of agreement. The counterparty to this agreement is a major financial institution which has an investment grade credit rating and is considered “well-capitalized” under applicable regulatory capital adequacy guidelines. Should the counterparty to this interest rate swap agreement fail to perform according to the terms of the contract, the Company would be required to pay interest at the stated rate of 6 7/8% related to its $300 million of unsecured senior notes with a maturity date of 2014.

(16)	Financial Information of Guarantor Subsidiaries

In April 2011, SESI, L.L.C. (Issuer), a wholly-owned subsidiary of Superior Energy Services, Inc. (Parent), issued $500 million of unsecured 6³/8% senior notes due 2019. In December 2011, SESI, L.L.C. issued $800 million of unsecured 7¹/8% senior notes due 2021. The Parent, along with substantially all of its domestic subsidiaries, fully and unconditionally guaranteed the senior notes, and such guarantees are joint and several. All of the guarantor subsidiaries are wholly-owned subsidiaries of the Issuer. Domestic income taxes are paid by the Parent through a consolidated tax return and are accounted for by the Parent. In 2011, the Company reorganized its international legal entities. The following tables present the condensed consolidating balance sheets as of December 31, 2011 and 2010, and the condensed consolidating statements of operations and cash flows for the years ended December 31, 2011, 2010 and 2009.

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

Consolidating Balance Sheets

December 31, 2011

(in thousands)


	Parent			Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	—		$	29,057		$	6,272		$	44,945		$	—		$	80,274
Accounts receivable, net		—			531			437,963			143,444			(41,336	)		540,602
Income taxes receivable		—			—			—			698			(698	)		—
Prepaid expenses		34			3,893			9,796			20,314			—			34,037
Inventory and other current assets		—			1,796			214,381			12,132			—			228,309

Total current assets		34			35,277			668,412			221,533			(42,034	)		883,222

Property, plant and equipment, net		—			2,758			1,096,036			408,574			—			1,507,368
Goodwill		—			—			437,614			143,765			—			581,379
Notes receivable		—			—			73,568			—			—			73,568
Investments in subsidiaries		124,271			1,152,918			—			—			(1,277,189	)		—
Equity-method investments		—			70,614			—			1,858			—			72,472
Intangible and other long-term assets, net		—			828,447			71,625			30,064			—			930,136

Total assets	$	124,305		$	2,090,014		$	2,347,255		$	805,794		$	(1,319,223	)	$	4,048,145

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	—		$	4,307		$	128,996		$	86,723		$	(41,381	)	$	178,645
Accrued expenses		164			54,000			105,512			38,503			(605	)		197,574
Income taxes payable		1,415			—			—			—			(698	)		717
Deferred income taxes		831			—			—			—			—			831
Current portion of decommissioning liabilities		—			—			14,956			—			—			14,956
Current maturities of long-term debt		—			—			—			810			—			810

Total current liabilities		2,410			58,307			249,464			126,036			(42,684	)		393,533

Deferred income taxes		285,871			—			—			11,587			—			297,458
Decommissioning liabilities		—			—			108,220			—			—			108,220
Long-term debt, net		—			1,673,351			—			11,736			—			1,685,087
Intercompany payables/(receivables)		(96,987	)		988,160			(253,050	)		(7,276	)		(630,847	)		—
Other long-term liabilities		5,192			32,380			26,704			45,972			—			110,248
Stockholders’ equity:
Preferred stock of $.01 par value		—			—			—			—			—			—
Common stock of $.001 par value		80			—			—			4,212			(4,212	)		80
Additional paid in capital		447,007			124,271			—			517,209			(641,480	)		447,007
Accumulated other comprehensive loss, net		—			—			—			(26,936	)		—			(26,936	)
Retained earnings (accumulated deficit)		(519,268	)		(786,455	)		2,215,917			123,254			—			1,033,448

Total stockholders’ equity (deficit)		(72,181	)		(662,184	)		2,215,917			617,739			(645,692	)		1,453,599

Total liabilities and stockholders’ equity	$	124,305		$	2,090,014		$	2,347,255		$	805,794		$	(1,319,223	)	$	4,048,145

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

Consolidating Balance Sheets

December 31, 2010

(in thousands)


	Parent			Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	—		$	—		$	5,493		$	45,234		$	—		$	50,727
Accounts receivable, net		—			415			382,935			99,010			(29,910	)		452,450
Income taxes receivable		—			—			—			2,024			(2,024	)		—
Prepaid expenses		18			4,128			8,948			12,734			—			25,828
Inventory and other current assets		—			1,678			222,822			10,547			—			235,047
Intercompany interest receivable		—			15,883			—			—			(15,883	)		—

Total current assets		18			22,104			620,198			169,549			(47,817	)		764,052

Property, plant and equipment, net		—			3,189			957,561			352,400			—			1,313,150
Goodwill		—			—			447,467			140,533			—			588,000
Notes receivable		—			—			69,026			—			—			69,026
Intercompany notes receivable		—			456,280			—			—			(456,280	)		—
Investments in subsidiaries		124,271			602,461			4,347			4,347			(735,426	)		—
Equity-method investments		—			43,947			—			15,375			—			59,322
Intangible and other long-term assets, net		—			22,455			61,722			29,806			—			113,983

Total assets	$	124,289		$	1,150,436		$	2,160,321		$	712,010		$	(1,239,523	)	$	2,907,533

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	—		$	6,654		$	71,790		$	64,636		$	(32,804	)	$	110,276
Accrued expenses		153			42,821			91,451			27,619			—			162,044
Income taxes payable		4,499			—			—			—			(2,024	)		2,475
Deferred income taxes		29,353			—			—			—			—			29,353
Current portion of decommissioning liabilities		—			—			16,929			—			—			16,929
Current maturities of long-term debt		—			184,000			—			810			—			184,810
Intercompany interest payable		—			—			—			15,883			(15,883	)		—

Total current liabilities		34,005			233,475			180,170			108,948			(50,711	)		505,887

Deferred income taxes		211,173			—			—			12,763			—			223,936
Decommissioning liabilities		—			—			100,787			—			—			100,787
Long-term debt, net		—			669,089			—			12,546			—			681,635
Intercompany notes payable		—			—			—			456,280			(456,280	)		—
Intercompany payables/(receivables)		(100,882	)		760,164			(1,407	)		(125,246	)		(532,629	)		—
Other long-term liabilities		8,260			37,537			19,427			49,513			—			114,737
Stockholders’ equity:
Preferred stock of $.01 par value		—			—			4,347			4,347			(8,694	)		—
Common stock of $.001 par value		79			—			—			176			(176	)		79
Additional paid in capital		415,278			124,271			—			66,762			(191,033	)		415,278
Accumulated other comprehensive loss, net		—			—			—			(25,700	)		—			(25,700	)
Retained earnings (accumulated deficit)		(443,624	)		(674,100	)		1,856,997			151,621			—			890,894

Total stockholders’ equity (deficit)		(28,267	)		(549,829	)		1,861,344			197,206			(199,903	)		1,280,551

Total liabilities and stockholders’ equity	$	124,289		$	1,150,436		$	2,160,321		$	712,010		$	(1,239,523	)	$	2,907,533

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

Consolidating Statements of Operations

Year Ended December 31, 2011

(in thousands)


	Parent			Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	—		$	1,730,780		$	408,497		$	(69,111	)	$	2,070,166
Cost of services (exclusive of items shown separately below)		—			—			890,800			295,998			(68,795	)		1,118,003
Depreciation, depletion, amortization and accretion		—			523			211,988			44,802			—			257,313
General and administrative expenses		683			81,363			236,229			65,608			(316	)		383,567
Reduction in value of assets		—			—			46,096			—			—			46,096
Gain on sale of businesses		—			—			8,558			—			—			8,558

Income (loss) from operations		(683	)		(81,886	)		354,225			2,089			—			273,745

Other income (expense):
Interest expense, net		—			(72,414	)		(24	)		(1,405	)		—			(73,843	)
Interest income		—			1,097			4,536			593			—			6,226
Intercompany interest income (expense)		—			26,673			—			(26,673	)		—			—
Other income (expense)		—			(1,005	)		183			—			—			(822	)
Earnings (losses) from equity-method investments, net		—			15,180			—			1,214			—			16,394

Income (loss) before income taxes		(683	)		(112,355	)		358,920			(24,182	)		—			221,700
Income taxes		74,961			—			—			4,185			—			79,146

Net income (loss)	$	(75,644	)	$	(112,355	)	$	358,920		$	(28,367	)	$	—		$	142,554

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

Consolidating Statements of Operations

Year Ended December 31, 2010

(in thousands)


	Parent			Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	—		$	1,414,519		$	339,233		$	(72,136	)	$	1,681,616
Cost of services (exclusive of items shown separately below)		—			—			759,447			231,082			(71,816	)		918,713
Depreciation, depletion, amortization and accretion		—			515			181,216			39,104			—			220,835
General and administrative expenses		322			99,068			190,665			53,146			(320	)		342,881
Reduction in value of assets		—			—			32,004			—			—			32,004
Gain on sale of business		—			—			1,083			—			—			1,083

Income (loss) from operations		(322	)		(99,583	)		252,270			15,901			—			168,266

Other income (expense):
Interest expense, net		—			(53,716	)		(216	)		(3,445	)		—			(57,377	)
Interest income					150			4,467			526			—			5,143
Intercompany interest income (expense)		—			15,883			—			(15,883	)		—			—
Other income (expense)					825			—			—			—			825
Earnings (losses) from equity-method investments, net		—			985			—			7,260			—			8,245

Income (loss) before income taxes		(322	)		(135,456	)		256,521			4,359			—			125,102
Income taxes		37,662			—			—			5,623			—			43,285

Net income (loss)	$	(37,984	)	$	(135,456	)	$	256,521		$	(1,264	)	$	—		$	81,817

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

Consolidating Statements of Operations

Year Ended December 31, 2009

(in thousands)


	Parent			Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	—		$	1,307,542		$	186,807		$	(45,049	)	$	1,449,300
Cost of services (exclusive of items shown separately below)		—			—			763,029			106,054			(45,049	)		824,034
Depreciation and accretion		—			476			184,084			22,554			—			207,114
General and administrative expenses		(184	)		61,035			168,459			29,783			—			259,093
Reduction in value of assets		—			—			212,527			—			—			212,527
Gain on sale of businesses		—			—			2,084			—			—			2,084

Income (loss) from operations		184			(61,511	)		(18,473	)		28,416			—			(51,384	)

Other income (expense):
Interest expense, net		—			(48,894	)		(68	)		(1,944	)		—			(50,906	)
Interest income					87			670			169			—			926
Intercompany interest income (expense)		—			—			—			—			—			—
Other income (expense)					571			—			—			—			571
Earnings (losses) from equity-method investments, net		—			(21,631	)		—			(969	)		—			(22,600	)
Reduction in value of equity-method investments		—			(36,486	)		—			—			—			(36,486	)

Income (loss) before income taxes		184			(167,864	)		(17,871	)		25,672			—			(159,879	)
Income taxes		(65,805	)		—			—			8,249			—			(57,556	)

Net income (loss)	$	65,989		$	(167,864	)	$	(17,871	)	$	17,423		$	—		$	(102,323	)

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows

Year Ended December 31, 2011

(in thousands)


	Parent			Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidated
Cash flows from operating activities:
Net income (loss)	$	(75,644	)	$	(112,355	)	$	358,920		$	(28,367	)	$	142,554
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		—			523			211,988			44,802			257,313
Deferred income taxes		49,946			—			—			(1,873	)		48,073
Excess tax benefit from stock-based compensation		(9,004	)		—			—			—			(9,004	)
Reduction in value of assets		—			—			46,096			—			46,096
Stock-based and performance share unit compensation expense		—			14,032			—			—			14,032
Retirement and deferred compensation plans expense		—			1,990			—			—			1,990
(Earnings) losses from equity-method investments, net of cash received		—			(12,001	)		—			(1,151	)		(13,152	)
Amortization of debt acquisition costs and note discount		—			25,154			—			24			25,178
Gain on sale of businesses		—			—			(8,558	)		—			(8,558	)
Other reconciling items, net		—			(1,884	)		(4,542	)		—			(6,426	)
Changes in operating assets and liabilities, net of acquisitions and dispositions:
Accounts receivable		—			(117	)		(51,133	)		(35,564	)		(86,814	)
Inventory and other current assets		—			(117	)		5,348			(3,049	)		2,182
Accounts payable		—			(2,348	)		26,499			16,138			40,289
Accrued expenses		12			7,983			11,801			5,165			24,961
Decommissioning liabilities		—			—			(504	)		—			(504	)
Income taxes		(917	)		—			—			(461	)		(1,378	)
Other, net		(16	)		(1,024	)		18,646			(1,634	)		15,972

Net cash provided by operating activities		(35,623	)		(80,164	)		614,561			(5,970	)		492,804
Cash flows from investing activities:
Payments for capital expenditures		—			(93	)		(383,785	)		(100,770	)		(484,648	)
Change in restricted cash held for acquisition of a business		—			(785,280	)		—			—			(785,280	)
Purchase of short-term investments		—			(223,491	)		—			—			(223,491	)
Proceeds from sale of short-term investments		—			223,630			—			—			223,630
Acquisitions of businesses, net of cash acquired		—			—			(1,200	)		(548	)		(1,748	)
Proceeds from sale of businesses		—			—			22,349			—			22,349
Other		—			—			(721	)		—			(721	)
Intercompany receivables/payables		14,485			125,015			(250,425	)		110,925			—

Net cash used in investing activities		14,485			(660,219	)		(613,782	)		9,607			(1,249,909	)
Cash flows from financing activities:
Net (payments) borrowings from revolving line of credit		—			(100,000	)		—			—			(100,000	)
Proceeds from issuance of long-term debt		—			1,300,000			—			—			1,300,000
Principal payments on long-term debt		—			(400,000	)		—			(810	)		(400,810	)
Payment of debt issuance costs		—			(24,428	)		—			—			(24,428	)
Proceeds from exercise of stock options		10,263			—			—			—			10,263
Excess tax benefit from stock-based compensation		9,004			—			—			—			9,004
Proceeds from issuance of stock through employee benefit plans		2,206			—			—			—			2,206
Other		(335	)		(6,132	)		—			(3,195	)		(9,662	)

Net cash used in financing activities		21,138			769,440			—			(4,005	)		786,573
Effect of exchange rate changes on cash		—			—			—			79			79

Net increase (decrease) in cash and cash equivalents		—			29,057			779			(289	)		29,547
Cash and cash equivalents at beginning of period		—			—			5,493			45,234			50,727

Cash and cash equivalents at end of period	$	—		$	29,057		$	6,272		$	44,945		$	80,274

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows

Year Ended December 31, 2010

(in thousands)


	Parent			Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidated
Cash flows from operating activities:
Net income (loss)	$	(37,984	)	$	(135,456	)	$	256,521		$	(1,264	)	$	81,817
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		—			515			181,216			39,104			220,835
Deferred income taxes		10,650			—			—			(2,374	)		8,276
Excess tax benefit from stock-based compensation		(560	)		—			—			—			(560	)
Reduction in value of assets		—			—			32,004			—			32,004
Stock-based and performance share unit compensation expense		—			27,207			—			—			27,207
Retirement and deferred compensation plans expense		—			4,825			—			—			4,825
(Earnings) losses from equity-method investments, net of cash received		—			9,005			—			(6,100	)		2,905
Amortization of debt acquisition costs and note discount		—			23,954			—			—			23,954
Gain on sale of business		—			—			(1,083	)		—			(1,083	)
Other reconciling items, net		—			(161	)		(4,547	)		—			(4,708	)
Changes in operating assets and liabilities, net of acquisitions and dispositions:
Accounts receivable		—			275			(76,669	)		(13,406	)		(89,800	)
Inventory and other current assets		—			163			89,302			(3,778	)		85,687
Accounts payable		—			2,001			18,928			(626	)		20,303
Accrued expenses		38			5,800			1,735			7,181			14,754
Decommissioning liabilities		—			—			(1,759	)		—			(1,759	)
Income taxes		13,536			—			—			(3,026	)		10,510
Other, net		(1,417	)		(3,143	)		21,280			4,086			20,806

Net cash provided by operating activities		(15,737	)		(65,015	)		516,928			19,797			455,973
Cash flows from investing activities:
Payments for capital expenditures		—			—			(218,726	)		(104,518	)		(323,244	)
Acquisitions of businesses, net of cash acquired		—			—			(56,560	)		(219,517	)		(276,077	)
Proceeds from sale of business		—			—			5,250			—			5,250
Other		—			2,387			(11,537	)		(252	)		(9,402	)
Intercompany receivables/payables		12,359			(102,093	)		(234,733	)		324,467			—

Net cash used in investing activities		12,359			(99,706	)		(516,306	)		180			(603,473	)
Cash flows from financing activities:
Net (payments) borrowings from revolving line of credit		—			(2,000	)		—			—			(2,000	)
Principal payments on long-term debt		—			—			—			(810	)		(810	)
Payment of debt issuance costs		—			(5,182	)		—			—			(5,182	)
Proceeds from exercise of stock options		927			—			—			—			927
Excess tax benefit from stock-based compensation		560			—			—			—			560
Proceeds from issuance of stock through employee benefit plans		1,891			—			—			—			1,891
Other		—			—			—			(3,443	)		(3,443	)

Net cash used in financing activities		3,378			(7,182	)		—			(4,253	)		(8,057	)
Effect of exchange rate changes on cash		—			—			—			(221	)		(221	)

Net increase (decrease) in cash and cash equivalents		—			(171,903	)		622			15,503			(155,778	)
Cash and cash equivalents at beginning of period		—			171,903			4,871			29,731			206,505

Cash and cash equivalents at end of period	$	—		$	—		$	5,493		$	45,234		$	50,727

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows

Year Ended December 31, 2009

(in thousands)


	Parent			Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidated
Cash flows from operating activities:
Net income (loss)	$	65,989		$	(167,864	)	$	(17,871	)	$	17,423		$	(102,323	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		—			476			184,084			22,554			207,114
Deferred income taxes		(73,127	)		—			—			(1,577	)		(74,704	)
Excess tax benefit from stock-based compensation		(170	)		—			—			—			(170	)
Reduction in value of assets		—			—			212,527			—			212,527
Reduction in value of equity-method investments		—			36,486			—			—			36,486
Stock-based and performance share unit compensation expense		—			11,785			—			—			11,785
Retirement and deferred compensation plans expense		—			1,550			—			—			1,550
(Earnings) losses from equity-method investments, net of cash received		—			27,637			—			969			28,606
Amortization of debt acquisition costs and note discount		—			21,744			—			—			21,744
Gain on sale of businesses		—			—			(2,084	)		—			(2,084	)
Changes in operating assets and liabilities, net of acquisitions and dispositions:
Accounts receivable		—			(156	)		19,940			5,825			25,609
Inventory and other current assets		—			(211	)		(48,786	)		(2,323	)		(51,320	)
Accounts payable		—			609			(27,786	)		2,540			(24,637	)
Accrued expenses		(469	)		(13,381	)		(27,381	)		(33	)		(41,264	)
Income taxes		4,270			—			—			(6,571	)		(2,301	)
Other, net		1,970			6,925			17,493			3,097			29,485

Net cash provided by operating activities		(1,537	)		(74,400	)		310,136			41,904			276,103
Cash flows from investing activities:
Payments for capital expenditures		—			—			(240,907	)		(45,370	)		(286,277	)
Acquisitions of businesses, net of cash acquired		—			—			(1,247	)		—			(1,247	)
Proceeds from sale of businesses		—			—			7,716			—			7,716
Cash contributed to equity-method investment		—			—			—			(8,694	)		(8,694	)
Other		—			(3,769	)		—			—			(3,769	)
Intercompany receivables/payables		(966	)		64,509			(76,684	)		13,141			—

Net cash used in investing activities		(966	)		60,740			(311,122	)		(40,923	)		(292,271	)
Cash flows from financing activities:
Net (payments) borrowings from revolving line of credit		—			177,000			—			—			177,000
Principal payments on long-term debt		—			—			—			(810	)		(810	)
Payment of debt issuance costs		—			(2,308	)		—			—			(2,308	)
Proceeds from exercise of stock options		375			—			—			—			375
Excess tax benefit from stock-based compensation		170			—			—			—			170
Proceeds from issuance of stock through employee benefit plans		1,958			—			—			—			1,958

Net cash used in financing activities		2,503			174,692			—			(810	)		176,385
Effect of exchange rate changes on cash		—			—			—			1,435			1,435

Net increase (decrease) in cash and cash equivalents		—			161,032			(986	)		1,606			161,652
Cash and cash equivalents at beginning of period		—			10,871			5,857			28,125			44,853

Cash and cash equivalents at end of period	$	—		$	171,903		$	4,871		$	29,731		$	206,505

(17)	Interim Financial Information (Unaudited)

The following is a summary of consolidated interim financial information for the years ended December 31, 2011 and 2010 (amounts in thousands, except per share data).


	Three Months Ended
	March 31		June 30		Sept. 30		Dec. 31
2011
Revenues	$	413,981	$	510,806	$	565,342	$	580,037
Less:
Cost of services, rentals and sales		233,845		271,370		301,065		311,723
Depreciation, depletion, amortization and accretion		59,363		63,314		64,875		69,761

Gross profit		120,773		176,122		199,402		198,553
Net income		15,503		48,109		59,580		19,362
Earnings per share:
Continuing operations
Basic	$	0.20	$	0.60	$	0.75	$	0.24
Diluted		0.19		0.59		0.73		0.25


	Three Months Ended
	March 31		June 30		Sept. 30		Dec. 31
2010
Revenues	$	364,511	$	424,856	$	435,353	$	456,896
Less:
Cost of services, rentals and sales		199,052		229,916		232,308		257,437
Depreciation, depletion, amortization and accretion		51,048		54,299		56,805		58,683

Gross profit		114,411		140,641		146,240		140,776
Net income		21,526		24,065		33,217		3,009
Earnings (loss) per share:
Continuing operations
Basic	$	0.27	$	0.31	$	0.42	$	0.04
Diluted		0.27		0.30		0.42		0.04

(18)	Supplementary Oil and Natural Gas Disclosures (Unaudited)

On January 31, 2010, Wild Well acquired 100% ownership of Shell Offshore, Inc.’s Gulf of Mexico Bullwinkle platform and its related assets and assumed the related decommissioning obligation. Immediately after Wild Well acquired these assets, it conveyed an undivided 49% interest in these assets and the related well plugging and abandonment obligations to Dynamic Offshore, which operates these assets (see note 3). The Company also has an interest in oil and gas operations through its equity-method investment in Dynamic Offshore (see note 7).

In January 2010, the Financial Accounting Standards Board issued an update to the authoritative guidance related to oil and gas reserve estimation and disclosures that expands the definition of oil- and gas-producing activities and requires disclosures of reserve quantities and standardized measure of cash flows for equity-method investments that have significant oil- and gas-producing activities.

The Company’s December 31, 2011 estimates of proved reserves are based on reserve reports prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers. The Company’s December 31, 2010 estimates of proved reserves were based on reserve reports prepared by DeGoyler and MacNaughton and Netherland, Sewell & Associates, Inc. Users of this information should be aware that the process of estimating quantities of “proved”, “proved developed” and “proved undeveloped” natural gas and crude oil reserves is very complex, requiring significant subjective decisions in the evaluation of

all available geological, engineering and economic data for each reservoir. This data may also change substantially over time as a result of multiple factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures. Proved reserves are estimated quantities of natural gas, crude oil and condensate that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for completion.

Oil and Natural Gas Reserves

The following table sets forth the Company’s net proved reserves, including the changes therein, and proved developed reserves:


	Consolidated						Company’s Share of Equity-Method Investments
	Crude Oil (Mbbls)			Natural Gas (Mmcf)			Crude Oil (Mbbls)			Natural Gas (Mmcf)
Proved-developed and undeveloped reserves:
December 31, 2009		—			—			3,242			23,255
Purchase of reserves in place		5,686			4,377			34			8
Revisions		723			1,572			564			692
Extensions, discoveries and other additions		—			—			—			413
Change in ownership percentage		—			—			(32	)		(1,347	)
Production		(427	)		(648	)		(413	)		(2,910	)

December 31, 2010		5,982			5,301			3,395			20,111
Purchase of reserves in place		—			—			958			8,045
Revisions		887			1,338			412			(547	)
Extensions, discoveries and other additions		—			—			—			—
Sale of reserves in-place		—			—			(1,159	)		(8,467	)
Production		(439	)		(371	)		(399	)		(906	)

December 31, 2011		6,430			6,268			3,207			18,236

Proved-developed reserves:
December 31, 2010		4,166			3,848			2,972			18,228
December 31, 2011		3,495			3,229			2,606			14,695
Proved-undeveloped reserves:
December 31, 2010		1,817			1,453			423			1,885
December 31, 2011		2,935			3,039			602			3,542

Costs Incurred in Oil and Natural Gas Activities

The following table displays certain information regarding the costs incurred associated with finding, acquiring and developing the Company’s proved oil and natural gas reserves for the years ended December 31, 2011 and 2010 (in thousands).


	Consolidated				Company’s Share of Equity-Method Investments
	Years Ended December 31,				Years Ended December 31,
	2011		2010		2011		2010
Acquisition of properties—proved	$	—	$	34,336	$	32,586	$	629
Acquisition of properties—unproved		—		—		—		118
Exploratory costs		—		359		—		—
Development costs		10,560		30		18,367		9,980

Total costs incurred	$	10,560	$	34,725	$	50,953	$	10,727

Capitalized costs for oil and gas producing activities consist of the following (in thousands):


	Consolidated						Company’s Share of Equity-Method Investments
	Years Ended December 31,						Years Ended December 31,
	2011			2010			2011			2010
Unproved oil and gas properties	$	—		$	—		$	13,559		$	24,097
Proved oil and gas properties		44,109			34,336			159,527			144,324
Accumulated depreciation, depletion and amortization		(8,215	)		(3,038	)		(52,764	)		(49,849	)

Capitalized costs, net	$	35,894		$	31,298		$	120,322		$	118,572

Productive Wells Summary

The following table presents the Company’s ownership of productive oil and natural gas wells as of December 31, 2011. Productive wells consist of producing wells and wells capable of production. In the table, “gross” refers to the total wells in which the Company owns an interest and “net” refers to the sum of fractional interests owned in gross wells.


	Consolidated Total				Company’s Share of Equity-Method Investments Total
	Productive Wells				Productive Wells
	Gross		Net		Gross		Net
Oil		10.00		5.10		28.50		18.13
Natural gas		—		—		22.70		11.07

Total		10.00		5.10		51.20		29.20

Acreage

The following table sets forth information as of December 31, 2011 relating to acreage held by the Company. Developed acreage is assigned to productive wells.


	Consolidated				Company’s Share of Equity-Method Investments
	Gross Acreage		Net Acreage		Gross Acreage		Net Acreage
Developed		17,280		8,813		69,517		38,434
Undeveloped		—		—		5,560		4,574

Total		17,280		8,813		75,077		43,008

Drilling Activity

The following table shows the Company’s drilling activity for the years ended December 31, 2011 and 2010. The Company did not engage in any drilling activity related to its ownership of the Bullwinkle platform and its related assets during the year ended December 31, 2011. In the table, “gross” refers to the total wells in which the Company has a working interest and “net” refers to the gross wells multiplied by the Company’s working interest in these wells. Well activity refers to the number of wells completed during a fiscal year, regardless of when drilling first commenced.


	Company’s Share of Equity-Method Investments
	2011				2010
	Gross		Net		Gross		Net
Exploratory Wells
Productive		0.10		0.01		—		—
Non-productive		0.10		0.07		—		—

Total		0.20		0.08		—		—

Development Wells
Productive		0.20		0.03		0.25		0.15
Non-productive		0.10		0.02		—		—

Total		0.30		0.05		0.25		0.15

Results of Operations

The following table sets forth the Company’s results of operations for producing activities:


	Years Ended December 31,
	2011		2010
Consolidated Entities
Revenues
Sales	$	54,442	$	39,410
Production costs		12,293		9,511
Exploration expenses		—		359
Depreciation, depletion and amortization		11,928		10,057

		30,221		19,483
Income tax expenses		10,789		7,014

Results of operations from producing activities (excluding corporate overhead)	$	19,432	$	12,469

Company’s share of equity-method investments
Revenues
Sales	$	53,181	$	56,964
Production costs		22,034		23,375
Exploration expenses		—		105
Depreciation, depletion and amortization		18,449		18,557

		12,698		14,927
Income tax expenses		4,533		5,373

Results of operations from producing activities (excluding corporate overhead)	$	8,165	$	9,554

The Company’s consolidated oil and gas operations, as well as its share of equity-method investment are in the Gulf of Mexico. The Company’s consolidated entity’s average sales price was $108.79 per barrel of oil and $3.45 per mcf of gas in 2011 and $77.04 per barrel of oil and $5.00 per mcf of gas in 2010. Average production costs were $12.51 and $19.99 per barrel of oil equivalent in years ended December 31, 2011 and 2010, respectively. The Company’s share of its equity-method investment’s average sales price was $113.28 per barrel of oil and $4.40 per mcf of gas in 2011 and $79.21 per barrel of oil and $4.78 per mcf of gas in 2010. Average production costs were $26.30 and $25.35 per barrel of oil equivalent in 2011 and 2010, respectively.

Standardized Measure of Discounted Future Net Cash Flows Relating to Reserves

The following information has been developed utilizing procedures prescribed by authoritative guidance related to oil and gas activities. It may be useful for certain comparative purposes, but should not be solely relied upon in evaluating the Company or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the standardized measure of discounted future net cash flows be viewed as representative of the current value of the Company.

The Company believes that the following factors should be taken into account in reviewing this information: (1) future costs and selling prices will likely differ from those required to be used in these calculations; (2) due to future market conditions and governmental regulations, actual rates of production achieved in future years may vary significantly from the rate of production assumed in the calculations; (3) selection of a 10% discount rate is arbitrary and may not be reasonable as a measure of the relative risk inherent in realizing future net oil and gas revenues; and (4) future net revenues may be subject to different rates of income taxation.

Under the standardized measure, future cash inflows were estimated by applying period-end oil and natural gas prices adjusted for differentials. Future cash inflows were reduced by estimated future development, abandonment and production costs based on period-end costs in order to arrive at net cash flow before tax. Future income tax expense has been computed by applying period-end statutory tax rates to aggregate future net cash flows, reduced by the tax basis of the properties involved and tax carryforwards. Use of a 10% discount rate is required by authoritative guidance related to oil and gas activities.

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves at December 31, 2011 and 2010 is as follows (in thousands):


	Consolidated						Company’s Share of Equity-Method Investments
	2011			2010			2011			2010
Future cash inflows	$	701,170		$	486,199		$	414,246		$	356,126
Future production costs		(126,627	)		(43,392	)		(100,848	)		(83,215	)
Future development and abandonment costs		(58,388	)		(86,125	)		(67,760	)		(84,260	)
Future income tax expenses		(185,816	)		(129,262	)		(73,202	)		(66,161	)

Future net cash flows		330,339			227,420			172,436			122,490
10% annual discount for estimated timing of cash flows		92,590			57,928			39,704			20,014

Standardized measure of discounted future net cash flows	$	237,749		$	169,492		$	132,732		$	102,476

A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved oil and natural gas reserves for the years ended December 31, 2011 and 2010 is as follows (in thousands):


	Consolidated						Company’s Share of Equity-Method Investment
	2011			2010			2011			2010
Beginning of the period	$	169,492		$	—		$	102,476		$	64,136
Net change in sales and transfer prices and in production (lifting) costs related to future production		62,881			102,726			27,944			57,626
Changes in estimated future development costs		8,297			2,950			(8,862	)		(9,051	)
Sales and transfers of oil and gas produced during the period		(54,057	)		(29,542	)		(44,268	)		(32,370	)
Net change due to extensions, discoveries, and improved recovery		—			—			—			2,781
Net changes due to purchases and sales of minerals in place		—			70,993			51,781			(1,912	)
Net changes due to revisions in quantity estimates		57,189			38,206			22,005			16,859
Previously estimated development costs incurred during the period		17,980			1,758			13,840			16,570
Exchange transaction		—			—			(23,356	)		—
Accretion of discount		26,625			16,484			11,179			8,780
Other-unspecified		(12,650	)		2,338			(2,065	)		1,496
Net change in income taxes		(38,008	)		(36,421	)		(17,942	)		(22,439	)

Aggregate change in the standardized measure of discounted future net cash flows for the year		68,257			169,492			30,256			38,340

End of the period	$	237,749		$	169,492		$	132,732		$	102,476

The December 31, 2011 amount was estimated by Netherland, Sewell & Associates, Inc. using a twelve month average WTI Cushing price of $96.19 per barrel (bbl), and a Henry Hub gas price of $4.118 per million British Thermal Units, and price differentials. The December 31, 2010 amount was estimated by DeGoyler and MacNaughton and Netherland, Sewell & Associates, Inc. using a twelve month average WTI Cushing price of $79.40 per barrel (bbl), and a Henry Hub gas price of $4.38 per million British Thermal Units, and price differentials.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Our management has established and maintains a system of disclosure controls and procedures to provide reasonable assurances that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is appropriately recorded, processed, summarized and reported within the time periods specified by the Securities and Exchange Commission (SEC). In addition, the disclosure controls and procedures ensure that information required to be disclosed, accumulated and communicated to management, including our Chief Executive Officer (CEO) and Chief Financial Officer (CFO), allow timely decisions regarding required disclosure. An evaluation was carried out, under the supervision and with the participation of our management, including our CEO and CFO, of the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-14(e) and Rule 15d-15(e) of the Securities Exchange Act of 1934) as of the end of the period covered by this report. Based on that evaluation, our principal executive and financial officers have concluded that our disclosure controls and procedures as of December 31, 2011 were effective to provide reasonable assurance that information required to be disclosed by us in reports we file with the SEC is recorded, processed, summarized and reported within the time periods required by the SEC’s rules and forms, and is accumulated and communicated to management, including our CEO and CFO, as appropriate, to allow timely decisions regarding disclosures. Management’s report and the independent registered public accounting firm’s attestation report are included herein under the captions “Management’s Annual Report on Internal Control over Financial Reporting” and “Report of Independent Registered Public Accounting Firm,” and are incorporated by reference.

There has been no change in our internal control over financial reporting during the three months ended December 31, 2011, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Management’s Annual Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over our financial reporting, and for performing an assessment of the effectiveness of internal control over our financial reporting as of December 31, 2011. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Our system of internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on the financial statements. Management recognizes that there are inherent limitations in the effectiveness of any internal control over financial reporting, including the possibility of human error and the circumvention or overriding of internal control. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may be inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Our management, including our principal executive officer and principal financial officer, performed an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2011 based upon criteria in “Internal Control—Integrated Framework,” issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this assessment, our management determined that as of December 31, 2011, our internal control over financial reporting was effective based on those criteria.

Our internal control over financial reporting as of December 31, 2011 has been audited by KPMG, LLP, an independent registered public accounting firm, as stated in their report which appears herein.

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Superior Energy Services, Inc.:

We have audited Superior Energy Services, Inc.’s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Superior Energy Services, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on Superior Energy Services, Inc.’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Superior Energy Services, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Superior Energy Services, Inc. and subsidiaries as of December 31, 2011 and 2010, 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, 2011, and our report dated February 28, 2012 expressed an unqualified opinion on those consolidated financial statements.

KPMG LLP

New Orleans, Louisiana

February 28, 2012

Item 9B. Other Information

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

Information relating to our executive officers is included in Part I, Item 1 in this Annual Report, and is incorporated herein by reference. Information relating to our Code of Business Ethics and Conduct that applies to all of our directors, officers and employees, including our senior financial officers, is included in Part I, Item 1 of this Annual Report, and is incorporated herein by reference. Other information required by this item will be contained in our definitive proxy statement to be filed pursuant to Regulation 14A and is incorporated herein by reference.

Item 11. Executive Compensation

Information required by this item will be contained in our definitive proxy statement to be filed pursuant to Regulation 14A and is incorporated herein by reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Information required by this item will be contained in our definitive proxy statement to be filed pursuant to Regulation 14A and is incorporated herein by reference.

Item 13. Certain Relationships and Related Transactions, and Director Independence

Information required by this item will be contained in our definitive proxy statement to be filed pursuant to Regulation 14A and is incorporated herein by reference.

Item 14. Principal Accounting Fees and Services

Information required by this item will be contained in our definitive proxy statement to be filed pursuant to Regulation 14A and is incorporated herein by reference.

PART IV

Item 15. Exhibits, Financial Statement Schedules

(a)	(1) Financial Statements

The following financial statements are included in Part II of this Annual Report on Form 10-K:


Report of Independent Registered Public Accounting Firm—Audit of Financial Statements			34
Consolidated Balance Sheets as of December 31, 2011 and 2010			35
Consolidated Statements of Operations for the years ended December 31, 2011, 2010 and 2009			36
Consolidated Statements of Changes in Stockholders’ Equity for the years ended December 31, 2011, 2010 and 2009			37
Consolidated Statements of Cash Flows for the years ended December 31, 2011, 2010 and 2009			39
Notes to Consolidated Financial Statements			40
Management’s Report on Internal Control over Financial Reporting			87
Report of Independent Registered Public Accounting Firm—Audit of Internal Control over Financial Reporting			88

(2) Financial Statement Schedule

Schedule II—Valuation and Qualifying Accounts for the years ended December 31, 2011, 2010 and 2009			98

All other schedules are omitted because they are not applicable or the required information is included in the consolidated financial statements or notes thereto.

(3)

Exhibits


Exhibit No.		Description

2.1		Implementation Agreement, dated December 11, 2009, by and among Superior Energy Services, Inc., Superior Energy Services (UK) Limited and Hallin Marine Subsea International Plc (incorporated herein by reference to Exhibit 2.1 to Superior Energy Services, Inc.’s Form 8-K filed December 11, 2009 (File No. 001-34037)).

2.2		Rule 2.5 Announcement (incorporated herein by reference to Exhibit 2.2 to Superior Energy Services, Inc.’s Form 8-K filed December 11, 2009 (File No. 001-34037)).

2.3		Agreement and Plan of Merger, dated October 9, 2011, by and among Superior Energy Services, Inc., SPN Fairway Acquisition, Inc. and Complete Production Services, Inc. (incorporated herein by reference to Exhibit 2.1 to Superior Energy Services, Inc.’s Form 8-K filed October 12, 2011 (File No. 001-34037)).

3.1*		Composite Certificate of Incorporation of Superior Energy Services, Inc.

3.2		Amended and Restated Bylaws of Superior Energy Services, Inc. (as amended through February 23, 2011) (incorporated herein by reference to Exhibit 3.1 to Superior Energy Services, Inc.’s Form 8-K filed February 25, 2011 (File No. 001-34037)).

4.1		Specimen Stock Certificate (incorporated herein by reference to Amendment No. 1 to Superior Energy Services, Inc.’s Form S-4 on Form SB-2 (Registration Statement No. 33-94454)).


Exhibit No.		Description

4.2		Indenture, dated May 22, 2006, among SESI, L.L.C., the guarantors identified therein and The Bank of New York Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.2 to Superior Energy Services, Inc.’s Form 8-K filed May 23, 2006 (File No. 333-22603)), as amended by Supplemental Indenture, dated December 12, 2006, by and among Warrior Energy Services Corporation, SESI, L.L.C., the other Guarantors (as defined in the Indenture referred to therein) and The Bank of New York Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.1 to Superior Energy Services, Inc.’s 8-K filed December 13, 2006 (File No. 333-22603)), as further amended by Supplemental Indenture, dated September 13, 2007 but effective as of August 29, 2007, by and among Advanced Oilwell Services, Inc., SESI L.L.C., the other Guarantors (as defined in the Indenture referred to therein) and The Bank of New York Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.1 to Superior Energy Services, Inc.’s Form 8-K filed September 18, 2007 (File No. 333-22603)), as further amended by Supplemental Indenture, dated April 27, 2011, among Superior Energy Services Colombia, L.L.C., SESI, L.L.C., Superior Energy Services, Inc., the other Guarantors (as defined in the Indenture referred to therein) and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.3 to Superior Energy Services, Inc.’s Form 8-K filed April 27, 2011 (File No. 001-34037)).

4.3		Indenture, dated April 27, 2011, among SESI, L.L.C., each of the guarantors party thereto and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.1 to Superior Energy Services, Inc.’s Form 8-K filed April 27, 2011 (File No. 001-34037)).

4.4		Indenture, dated December 6, 2011, among SESI, L.L.C., each of the guarantors party thereto and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.1 to Superior Energy Services, Inc.’s Form 8-K filed December 12, 2011 (File No. 001-34037)).

10.1^		Amended and Restated Superior Energy Services, Inc. 1995 Stock Incentive Plan (incorporated herein by reference to Exhibit A to Superior Energy Services, Inc.’s Definitive Proxy Statement filed June 26, 1997 (File No. 000-20310)).

10.2		Wreck Removal Contract, dated December 31, 2007, by and among Wild Well Control, Inc., BP America Production Company, Chevron U.S.A. Inc. and GOM Shelf LLC (Superior Energy Services, Inc. agrees to furnish supplementally a copy of any omitted exhibits to the SEC upon request) (incorporated herein by reference to Exhibit 10.1 to Superior Energy Services, Inc.’s Form 8-K filed January 4, 2008 (File No. 333-22603)).

10.3^		Form of Employment Agreement for Robert S. Taylor (incorporated herein by reference to Exhibit 10.1 to Superior Energy Services, Inc.’s Form 8-K filed June 6, 2007 (File No. 333-22603)).


Exhibit No.		Description

10.4^		Superior Energy Services, Inc. 2007 Employee Stock Purchase Plan (incorporated herein by reference to Exhibit 10.1 to Superior Energy Services, Inc.’s Form 8-K filed May 24, 2007 (File No. 333-22603)).

10.5^		Form of Employment Agreement executed by Superior Energy Services, Inc. and each of Alan P. Bernard, Lynton G. Cook, III and Danny R. Young (incorporated herein by reference to Exhibit 10.2 to Superior Energy Services, Inc.’s Form 8-K filed June 6, 2007 (File No. 333-22603)).

10.6^		Superior Energy Services, Inc. 1999 Stock Incentive Plan (incorporated herein by reference to Superior Energy Services, Inc.’s Annual Report on Form 10-K for the year ended December 31, 1999 (File No. 333-22603)), as amended by Second Amendment to Superior Energy Services, Inc. 1999 Stock Incentive Plan, effective as of December 7, 2004 (incorporated herein by reference to Exhibit 10.2 to Superior Energy Services, Inc.’s Form 8-K filed December 20, 2004 (File No. 333-22603)).

10.7^		Amended and Restated Superior Energy Services, Inc. 2002 Stock Incentive Plan (incorporated herein by reference to Exhibit 10.9 to Superior Energy Services, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2003 (File No. 333-22603)), as amended by First Amendment to Superior Energy Services, Inc. 2002 Stock Incentive Plan, effective as of December 7, 2004 (incorporated herein by reference to Exhibit 10.1 to Superior Energy Services, Inc.’s Form 8-K filed December 20, 2004 (File No. 333-22603)).

10.8^		Superior Energy Services, Inc. Nonqualified Deferred Compensation Plan (incorporated herein by reference to Exhibit 10.11 to Superior Energy Services, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2009), as amended by Amendment No. 1 to the Superior Energy Nonqualified Deferred Compensation Plan (incorporated herein by reference to Exhibit 10.11 of Superior Energy Services, Inc.’s Form 10-K for the year ended December 31, 2011 (File No. 001-34037)).

10.9^		Superior Energy Services, Inc. 2005 Stock Incentive Plan (incorporated herein by reference to Appendix A to Superior Energy Services, Inc.’s Definitive Proxy Statement filed April 19, 2005 (File No. 333-22603)).

10.10^		Amended and Restated Superior Energy Services, Inc. 2004 Directors Restricted Stock Units Plan (incorporated herein by reference to Appendix B to Superior Energy Services, Inc.’s Definitive Proxy Statement filed April 20, 2006 (File No. 333-22603)).

10.11		Purchase, Contribution and Redemption Agreement, dated February 25, 2008, by and among Dynamic Offshore Resources, LLC, Moreno Group LLC, SESI, L.L.C., and SPN Resources, LLC (incorporated herein by reference to Exhibit 10.1 to Superior Energy Services, Inc.’s Form 8-K filed February 29, 2008 (File No. 333-22603)).

10.12^		Employment Agreement, dated March 1, 2008, by and between Superior Energy Services, Inc. and William B. Masters (incorporated herein by reference to Exhibit 10.1 to Superior Energy Services, Inc.’s Form 8-K filed March 6, 2008 (File No. 333-22603)).

10.13^		Superior Energy Services, Inc. Supplemental Executive Retirement Plan (incorporated herein by reference to Exhibit 10.21 to Superior Energy Services, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2009 (File No. 001-34037)), as amended by Amendment No. 1 to the Superior Energy Supplemental Executive Retirement Plan (incorporated herein by reference to Exhibit 10.21 to Superior Energy Services, Inc.’s Form 10-K for the year ended December 31, 2010 (File No. 001-34037)).

10.14^		Superior Energy Services, Inc. 2009 Stock Incentive Plan (incorporated herein by reference to Exhibit 10.1 to Superior Energy Services, Inc.’s Form 8-K filed May 27, 2009 (File No. 001-34037)).


Exhibit No.		Description

10.15		Third Amended and Restated Credit Agreement, dated February 7, 2012, among SESI, L.L.C., Superior Energy Services, Inc., JPMorgan Chase Bank, N.A. and the lenders party thereto (incorporated herein by reference to Exhibit 10.1 to Superior Energy Services, Inc.’s Form 8-K filed February 8, 2012 (File No. 001-34037)).

10.16^		Form of Stock Option Agreement under the Superior Energy Services, Inc. 2005 Stock Incentive Plan and the 2009 Stock Incentive Plan (incorporated herein by reference to Exhibit 10.1 to Superior Energy Services, Inc.’s Form 8-K filed December 16, 2009 (File No. 001-34037)).

10.17^		Form of Restricted Stock Agreement under the Superior Energy Services, Inc. 2005 Stock Incentive Plan and the 2009 Stock Incentive Plan (incorporated herein by reference to Exhibit 10.2 to Superior Energy Services, Inc.’s Form 8-K filed December 16, 2009 (File No. 001-34037)).

10.18^		Form of Performance Share Unit Award Agreement under the Superior Energy Services, Inc. 2005 Stock Incentive Plan and the 2009 Stock Incentive Plan (incorporated herein by reference to Exhibit 10.3 to Superior Energy Services, Inc.’s Form 8-K filed December 16, 2009 (File No. 001-34037)).

10.19^		Superior Energy Services, Inc. 2011 Stock Incentive Plan (incorporated herein by reference to Exhibit 10.1 to Superior Energy Services, Inc.’s Form 8-K filed May 26, 2011 (File No. 001-34037)).

10.20^		Form of Stock Option Agreement under the Superior Energy Services, Inc. 2011 Stock Incentive Plan (incorporated herein by reference to Exhibit 10.1 to Superior Energy Services, Inc.’s Form 8-K filed December 14, 2011 (File No. 001-34037)).

10.21^		Form of Restricted Stock Agreement under the Superior Energy Services, Inc. 2011 Stock Incentive Plan (incorporated herein by reference to Exhibit 10.2 to Superior Energy Services, Inc.’s Form 8-K filed December 14, 2011 (File No. 001-34037)).

10.22^		Form of Performance Share Unit Award Agreement under the Superior Energy Services, Inc. 2011 Stock Incentive Plan (incorporated herein by reference to Exhibit 10.3 to Superior Energy Services, Inc.’s Form 8-K filed December 14, 2011 (File No. 001-34037)).

10.23*		Complete Production Services, Inc. Amended and Restated 2001 Stock Incentive Plan.

10.24*		Amendment No. 1 to the Complete Production Services, Inc. Amended and Restated 2001 Stock Incentive Plan.

10.25*		Complete Production Services, Inc. 2008 Incentive Award Plan.

10.26*		Amendment No. 1 to the Complete Production Services, Inc. 2008 Incentive Award Plan.

10.27^		Employment Agreement, dated effective as of April 28, 2010, by and between Superior Energy Services, Inc. and David D. Dunlap (incorporated herein by reference to Exhibit 10.1 to Superior Energy Services, Inc.’s Form 8-K filed May 3, 2010 (File No. 001-34037)).

10.28^		Buy-Out Agreement, dated effective as of April 28, 2010, by and between Superior Energy Services, Inc. and Terence E. Hall (incorporated herein by reference to Exhibit 10.3 to Superior Energy Services, Inc.’s Form 8-K filed May 3, 2010 (File No. 001-34037)).

10.29^		Senior Advisor Agreement, dated effective as of May 20, 2011, by and between Superior Energy Services, Inc. and Terence E. Hall (incorporated herein by reference to Exhibit 10.4 to Superior Energy Services, Inc.’s Form 8-K filed May 3, 2010 (File No. 001-34037)).

10.30^		Senior Advisor Agreement, dated effective as of January 1, 2011, by and between Superior Energy Services, Inc. and Kenneth L. Blanchard (incorporated herein by reference to Exhibit 10.5 to Superior Energy Services, Inc.’s Form 8-K filed May 3, 2010 (File No. 001-34037)).


Exhibit No.		Description

10.31^		Letter Agreement, dated effective December 10, 2010, by and between Superior Energy Services, Inc. and Terence E. Hall (incorporated herein by reference to Exhibit 10.1 to Superior Energy Services, Inc.’s Form 8-K filed December 16, 2010 (File No. 001-34037)).

10.32^		Letter Agreement, dated effective December 10, 2010, by and between Superior Energy Services, Inc. and Kenneth L. Blanchard (incorporated herein by reference to Exhibit 10.2 to Superior Energy Services, Inc.’s Form 8-K filed December 16, 2010 (File No. 001-34037)).

10.33^*		Employment Agreement, dated June 1, 2007, between Superior Energy Services, Inc. and Gregory A. Rosenstein.

10.34^*		Amended and Restated Complete Production Services, Inc. Executive Agreement, dated December 31, 2008, between Complete Production Services, Inc. and Brian K. Moore.

10.35^		Superior Energy Services, Inc. Directors Deferred Compensation Plan (incorporated herein by reference to Exhibit 10.1 to Superior Energy Services, Inc.’s Form 8-K filed February 25, 2011 (File No. 001-34037)).

10.36		Purchase Agreement dated April 20, 2011, with respect to SESI, L.L.C.’s $500,000,000 6.375% Senior Notes due 2019 (incorporated herein by reference to Exhibit 10.1 to Superior Energy Services, Inc.’s Form 8-K filed April 26, 2011 (File No. 001-34037)).

10.37		Registration Rights Agreement dated April 27, 2011, by and among SESI, L.L.C., Superior Energy Services, Inc., the guarantors listed in Schedule 1 thereto and J.P. Morgan Securities LLC (incorporated herein by reference to Exhibit 10.1 to Superior Energy Services, Inc.’s Form 8-K filed April 27, 2011 (File No. 001-34037)).

10.38		Purchase Agreement dated November 21, 2011, with respect to SESI, L.L.C.’s $800,000,000 7.125% Senior Notes due 2021 (incorporated herein by reference to Exhibit 10.1 to Superior Energy Services, Inc.’s Form 8-K filed November 28, 2011 (File No. 001-34037)).

10.39		Registration Rights Agreement dated December 6, 2011, by and among SESI, L.L.C., Superior Energy Services, Inc., the guarantors listed in Schedule 1 thereto and J.P. Morgan Securities LLC (incorporated herein by reference to Exhibit 10.1 to Superior Energy Services, Inc.’s Form 8-K filed December 12, 2011 (File No. 001-34037)).

12.1*		Computation of Ratio of Earnings to Fixed Charges.

14.1		Code of Business Ethics and Conduct (incorporated herein by reference to Exhibit 14.1 to Superior Energy Services, Inc.’s Form 8-K filed on February 25, 2011 (File No. 001-34037)).

21.1*		Subsidiaries of Superior Energy Services, Inc.

23.1*		Consent of KPMG LLP, independent registered public accounting firm.

23.2*		Consent of Netherland, Sewell & Associates, Inc.

23.3*		Consent of DeGoyler and MacNaughton.

31.1*		Officer’s certification pursuant to Rules 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934, as amended.

31.2*		Officer’s certification pursuant to Rules 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934, as amended.

32.1*		Officer’s certification pursuant to Section 1350 of Title 18 of the U.S. Code.

32.2*		Officer’s certification pursuant to Section 1350 of Title 18 of the U.S. Code.

99.1*		Appraisal Report as of December 31, 2011 on Certain Properties owned by Superior Energy Services, Inc.

101.INS**		XBRL Instance Document


Exhibit No.		Description

101.SCH**		XBRL Taxonomy Extension Schema Document

101.CAL**		XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB**		XBRL Taxonomy Extension Label Linkbase Document

101.PRE**		XBRL Taxonomy Extension Presentation Linkbase Document

101.DEF**		XBRL Taxonomy Extension Definition Linkbase Document

*	Filed herein

**	Furnished with this Form 10-K

^	Management contract or compensatory plan or arrangement

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


	SUPERIOR ENERGY SERVICES, INC.

Date: February 28, 2012

	By:	/S/ DAVID D. DUNLAP
		David D. Dunlap
		Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.


Signature	Title	Date

/s/ DAVID D. DUNLAP David D. Dunlap	Chief Executive Officer (Principal Executive Officer)	February 28, 2012

/s/ ROBERT S. TAYLOR Robert S. Taylor	Executive Vice President, Treasurer and Chief Financial Officer (Principal Financial and Accounting Officer)	February 28, 2012

/s/ TERENCE E. HALL Terence E. Hall	Chairman of the Board	February 28, 2012

/s/ HAROLD J. BOUILLION Harold J. Bouillion	Director	February 28, 2012

/s/ ENOCH L. DAWKINS Enoch L. Dawkins	Director	February 28, 2012

/s/ JAMES M. FUNK James M. Funk	Director	February 28, 2012

/s/ ERNEST E. HOWARD, III Ernest E. Howard, III	Director	February 28, 2012

/s/ PETER D. KINNEAR Peter D. Kinnear	Director	February 28, 2012

/s/ MICHAEL M. MCSHANE Michael M. McShane	Director	February 28, 2012

/s/ W. MATT RALLS W. Matt Ralls	Director	February 28, 2012

/s/ JUSTIN L. SULLIVAN Justin L. Sullivan	Director	February 28, 2012

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

Schedule II Valuation and Qualifying Accounts

Years Ended December 31, 2011, 2010 and 2009

(in thousands)


Description	Balance at the beginning of the year		Charged to costs and expenses		Deductions		Balance at the end of the year
Year ended December 31, 2011:
Allowance for doubtful accounts	$	22,618	$	3,689	$	8,823	$	17,484
Year ended December 31, 2010:
Allowance for doubtful accounts	$	23,679	$	4,825	$	5,886	$	22,618
Year ended December 31, 2009:
Allowance for doubtful accounts	$	18,013	$	10,866	$	5,200	$	23,679