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, 2012

Or

¨ 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.

Large accelerated filer	x	Accelerated filer	¨
Non-accelerated	¨  (Do not check this if a smaller reporting company)	Smaller reporting company	¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange

Act).     Yes  ¨    No  x

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, 2012) was $3.21 billion. As of February 18, 2013, there were 159,467,014 shares of the registrant’s common stock outstanding.

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. AND SUBSIDIARIES

Annual Report on Form 10-K for

the Fiscal Year Ended December 31, 2012

TABLE OF CONTENTS

		Page
PART I
Item 1	Business		4
Item 1A	Risk Factors		10
Item 1B	Unresolved Staff Comments		17
Item 2	Properties		17
Item 3	Legal Proceedings		17
Item 4	Mine Safety Disclosures		17
PART II
Item 5	Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities		18
Item 6	Selected Financial Data		20
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations		21
Item 7A	Quantitative and Qualitative Disclosures about Market Risk		34
Item 8	Financial Statements and Supplementary Data		36
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		88
Item 9A	Controls and Procedures		88
Item 9B	Other Information		91
PART III
Item 10	Directors, Executive Officers and Corporate Governance		91
Item 11	Executive Compensation		91
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		91
Item 13	Certain Relationships and Related Transactions, and Director Independence		91
Item 14	Principal Accounting Fees and Services		91
PART IV
Item 15	Exhibits, Financial Statement Schedules		92

2

FORWARD-LOOKING STATEMENTS

This report, as well as other filings made by us with the Securities and Exchange Commission (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.

3

PART I

Item 1. Business

General

We believe we are a leading provider of specialized oilfield services and equipment. On February 7, 2012, we acquired Complete Production Services, Inc. (Complete), which significantly added to our geographic footprint in the U.S. land market area. We now offer a wider variety of products and services throughout the life cycle 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, as well as enhancing 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, which offer products and services within the various phases of a well’s economic lifecycle. Effective December 31, 2012, we report our operating results in four segments: (1) Drilling Products and Services; (2) Onshore Completion and Workover Services; (3) Production Services; and (4) Subsea and Technical Solutions. During the fourth quarter of 2012, we revised our internal reporting structure that we use in determining how to allocate resources. Prior to that, we reported our operating results in two segments: Drilling Products and Services and Subsea and Well Enhancement. 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

Complete provided 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 provided intervention services (including completion, coiled tubing, 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. The majority of Complete’s operations were located in U.S. land basins, particularly in major unconventional basins in the Rocky Mountain region, Texas, Oklahoma, Louisiana, Arkansas and Pennsylvania. Complete’s products and services are reported within our Onshore Completion and Workover Services and Production Services segments.

The acquisition of Complete resulted in several important changes to our operations, including the following:

• significantly increasing our presence in the U.S. land market, thereby reducing the percentage of revenue from our international and Gulf of Mexico operations;

• 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.;

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

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

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

• 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

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

4

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 Products and Services – 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.

• Pressure pumping – Includes hydraulic fracturing and high pressure pumping services used to complete and stimulate production in new oil and gas wells.

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

• Workover services – Provides a variety of well completion, workover and maintenance services including installations, completions, sidetracking of wells and support for perforating operations.

• Production Services – Includes intervention services and specialized pressure-control tools used for pressure control and intervention operations.

• 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 remedial pumping services (cementing and stimulation services).

• Specialized pressure-control tools – Surface and downhole products used to manage and control pressure throughout the life of an oil and gas 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, which typically require 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 and gas well. These products and services include pressure control services, completion tools and services, subsea construction, end-of-life services, and marine technical services. This segment also includes oil and gas revenue related to our ownership in the Bullwinkle platform and related assets.

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

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

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

5

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

• Marine technical services – Provides 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, well containment systems, and project management services.

Customers

Our customers are the major and independent oil and gas companies that are active in the geographic areas in which we operate. EOG Resources, Inc. (EOG Resources) accounted for approximately 13% of our revenues in 2012. Based on our combined revenue with Complete, EOG Resources accounted for approximately 10% of total combined revenue in 2011. There were no customers that exceeded 10% of total combined revenue in 2010. Our inability to continue to perform services for EOG Resources or a number of our other 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 International, Ltd., Baker Hughes Incorporated, Halliburton Company and Schlumberger N.V. 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, and 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 common industry practice whereby we 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 liability insurance program that covers against certain operating hazards, including product liability, property damage 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. These policies include primary and excess umbrella liability policies with limits of $250 million per occurrence, including sudden and accidental pollution incidents. All of the insurance policies purchased by us contain specific terms, conditions, limitations and exclusions and are subject to either deductibles or self-insured retention amounts for which we are responsible. 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.

6

Government Regulation

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

• worker safety standards;

• the protection of the environment;

• the handling and transportation of hazardous materials; and

• 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 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 2013.

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 high seas associated with cold fronts during the winter months and hurricanes during the summer months in the Gulf of Mexico, and severe cold during winter months in the U.S. land market area.

Employees

As of December 31, 2012, we had approximately 14,500 employees. Less than 4% of our employees in international locations are subject to union contracts. 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 throughout the world.

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. 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.

7

Executive Officers of Registrant

David D. Dunlap, age 51, 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 58, 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 55, 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 a wholly-owned subsidiary and its predecessor company.

Brian K. Moore, age 56, 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. Mr. Moore joined a predecessor company of Complete as President and Chief Executive Officer in April 2004.

Westervelt T. Ballard, Jr., age 41, 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 44, has served as one of our Executive Vice Presidents since September 2004. He has also served as an Executive Vice President of a wholly-owned subsidiary, and previously as a Vice President of a wholly-owned subsidiary and its predecessor company since August 2000.

William B. Masters, age 55, 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 L.L.P. for more than 20 years.

Gregory A. Rosenstein, age 45, 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 57, has served as one of our Executive Vice Presidents since September 2004. Mr. Young has also served as an Executive Vice President of a wholly-owned subsidiary. From January 2002 to May 2005, he served as Vice President of Health, Safety and Environment and Corporate Services of a wholly-owned subsidiary.

8

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 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 granted to 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.

9

Item 1A. Risk Factors

An investment in our securities involves risks. When considering an investment in our securities, you should carefully consider all of the risk factors described below, as well as in other reports and materials we file with the SEC and the other information included or incorporated by reference in this Form 10-K. If any of the risks described below or elsewhere in this Form 10-K were to occur, our business, financial condition, results of operations, cash flows, or prospects could be materially adversely affected. In such event, the trading price of our common stock or value of our other securities could decline and you could lose part or all of your investment. Additional risk and uncertainties not currently known to us or that we currently deem immaterial may also materially affect our financial condition, results of operations and cash flows.

Trends in oil and gas prices affect the level of exploration, development and production activity in the oil and gas industry.

Our business depends on the level of oil and gas exploration, development and production activity by oil and gas companies worldwide. The level of exploration, development and production activity is directly affected by trends in oil and gas prices, which historically have been volatile. Oil and gas prices are subject to large fluctuations in response to relatively minor changes in supply and demand, market uncertainty and a variety of other factors beyond our control. 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. Any prolonged reduction of oil and gas prices, as well as anticipated declines, could also result in lower levels of exploration, development and production activity. The demand for our services may be affected by numerous factors, including the following:

• the level of worldwide oil and gas exploration and production;

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

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

• the ability of the Organization of Petroleum Exporting Countries (OPEC) to set and maintain production levels for oil;

• the level of excess production capacity;

• the discovery rate of new oil and gas reserves;

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

• weather conditions and changes in weather patterns, including summer and winter temperatures that impact demand;

• the availability, proximity and capacity of transportation facilities;

• the level and effect of trading in commodity future markets, including trading by commodity price speculators and others;

• the nature and extent of governmental regulation (including environmental regulation) and taxation;

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

• technological advances affecting energy exploration, production and consumption.

10

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 inherent in the oil and gas industry that may lead to property damage, personal injury, death or the discharge of hazardous materials into the environment. Many of these events are outside of our control. Typically, we provide products and services at a well site where our personnel and equipment are located together with personnel and equipment of our customer and other service providers. From time to time, personnel are injured or equipment or property is damaged or destroyed as a result of accidents, failed equipment, faulty products or services, failure of safety measures, uncontained formation pressures or other dangers inherent in oil and gas exploration, development and production. Any of these events can be the result of human error. All of these risks expose us to a wide range of significant health, safety and environmental risks and potentially substantial litigation claims for damages. With increasing frequency, our products and services are deployed in more challenging exploration, development and production environments. 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 policies are subject to exclusions, limitations and other conditions, and may not protect us against liability for some types of events, including events involving a well blowout, 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 or on terms that we deem commercially reasonable. 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 or retentions, 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 business is subject to risks from lower capital spending by our customers.

Our business is directly affected by changes in capital expenditures by our customers, and reductions in their capital spending could reduce demand for our services and products. The rate of economic growth in the U.S. and worldwide has been lower than experienced since before the 2008 economic downturn. Prolonged periods of little or no economic growth will likely decrease demand for oil and gas and increase pricing pressure for our services and products. In addition, if a significant number of our customers experience a prolonged business decline or disruptions, we may incur increased exposure to credit risk and bad debts.

Increased regulation of or limiting or banning hydraulic fracturing could reduce or eliminate demand for our pressure pumping services.

Our hydraulic fracturing services are subject to a range of applicable federal, state and local laws. Our hydraulic fracturing services 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

11

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. Various federal legislative and regulatory initiatives have been undertaken which could result in additional requirements or restrictions being imposed on hydraulic fracturing operations. For example, the U.S. Department of Interior has issued proposed regulations that would apply to hydraulic fracturing wells subject to federal oil and gas leases that would impose requirements to disclose chemicals used in the fracturing process as well as certain prior approvals to conduct hydraulic fracturing . In addition, certain states have adopted laws and regulations requiring additional disclosure regarding chemicals used in the fracturing process, but with protections for proprietary information, and other states are evaluating the adoption of legislation or regulations governing hydraulic fracturing. Possible legislation or regulation could impose further disclosure obligations or other requirements, such as restrictions on use the use of certain chemicals or prohibitions on hydraulic fracturing in certain areas, which could affect our operations. The adoption of any future federal, state or local laws or implementing regulations could make it more difficult to complete oil and gas wells, adversely affecting our hydraulic fracturing business.

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, high winds and seas, blizzards and extreme temperatures may cause evacuation of personnel, curtailment of services and suspension of operations, inability to deliver materials to jobsites in accordance with contract schedules, loss of or damage to equipment and facilities and reduced productivity. 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.

Any capital financing that may be necessary may not be available at economic rates.

Turmoil in the credit and financial markets could adversely affect financial institutions, inhibit lending and limit our access to funding through borrowings under our credit facility or newly created facilities in the public or private market on terms we believe to be reasonable. 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.

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 technical personnel. 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 technical personnel could adversely affect our operating results. The demand for skilled personnel is high and the supply is limited. We have experienced increases in labor costs in recent years and may continue to do so in the future.

12

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

In connection with the Complete acquisition, we have been, and will continue to devote significant management attention and company-wide 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:

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

• 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;

• 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;

• 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 integrating 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.

In 2012, we conducted business in approximately 70 countries, and we intend to grow 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;

• inflation;

• deprivation of contract rights;

• increased operating costs;

• inability to collect receivables;

• 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, devaluations and conversion restrictions;

• restrictions on the repatriation of funds; and

• other forms of government regulation which are subject to change and are beyond our control.

13

Due to the unsettled political conditions in many oil producing countries, our operations, revenue and profitability are subject to the adverse consequences of war, the effects of terrorism, civil unrest, strikes, currency controls and governmental actions. These and the other risks outlined above could cause us to curtail or terminate operations, result in the loss of personnel or assets, disrupt financial and commercial markets and generate greater political and economic instability in some of the geographic areas in which we operate. Areas where we operate that have significant risk include the Middle East, Colombia, Indonesia, Kazakhstan, Nigeria and Mexico.

Control of oil and natural gas reserves by state-owned oil companies may impact the demand for our services.

In many countries around the world where we do business, all or a significant portion of the decision making regarding procuring our services and products is controlled by state-owned oil companies. State-owned oil companies may require their contractors to meet local content requirements or other local standards, such as joint ventures, that could be difficult or undesirable for the Company to meet. The failure to meet the local content requirements and other local standards may adversely impact the Company’s operations in those countries. In addition, our ability to work with state-owned oil companies is subject to our ability to negotiate and agree upon acceptable contract terms. In addition, many state-owned oil companies may require integrated contracts or turnkey contracts that could require the Company to provide services outside its core business. Providing services on an integrated or turnkey basis generally requires the Company to assume additional risks.

Changes in tax laws or tax rates, adverse positions taken by taxing authorities and tax audits could impact our operating results.

We have operations in numerous foreign countries. As a result, we are subject to the jurisdiction of a significant number of taxing authorities. Changes in tax laws or tax rates, the resolution of tax assessments or audits by various tax authorities could impact our operating results. In addition, we may periodically restructure our legal entity organization. If taxing authorities were to disagree with our tax positions in connection with any such restructurings, our effective tax rate could be impacted. The final determination of our income tax liabilities involves the interpretation of local tax laws, tax treaties and related authorities in each taxing jurisdiction, as well as the significant use of estimates and assumptions regarding future operations and results and the timing of income and expenses. We may be audited and receive tax assessments from taxing authorities that may ultimately result in assessment of additional taxes that are ultimately resolved with the authorities or through the courts. We believe these assessments may occasionally be based on erroneous and even arbitrary interpretations of local tax law. Resolution of any tax matter involves uncertainties and there are no assurances that the outcomes will be favorable.

We are subject to environmental laws and regulations which could reduce our business opportunities and revenue, and increase our costs and liabilities.

Our business is significantly affected by a wide range of laws and regulations in the areas in which we operate, and increasingly stringent environmental laws and regulations governing air emissions, water discharges and waste management. Generally, environmental laws have in recent years become more stringent and have sought to impose greater liability on a larger number of potentially responsible parties. The scope of regulation of our industry and services and products may increase further following the April 2010 Macondo accident in the Gulf of Mexico, including possible increases in liabilities or funding requirements imposed by governmental agencies.

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. For instance, 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, which could impose restrictions in greenhouse gas emissions. Also, the U.S.

14

Environmental Protection Agency (EPA) has undertaken efforts to collect information regarding greenhouse emissions, as well as adopting and implementing certain regulations to restrict emissions. The EPA has adopted rules requiring the reporting of certain onshore and offshore oil and gas production facilities and by certain large emissions sources. It is not currently feasible to predict whether, or which of, the current greenhouse gas emission proposals will be adopted, or what other actions may be taken, including subsequent EPA activity. 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.

Further, environmental 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. For example, our well service and fluids businesses routinely involve the handling of significant amounts of waste materials, some of which are classified as hazardous substances. We also store, transport and use radioactive and explosive materials in certain of 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 containment and disposal of hazardous substances, oilfield waste and other waste materials, the use of radioactive materials, the use of underground injection wells, 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.

We are affected by global economic factors and political events.

Our financial results depend on demand for our services and products in the U.S. and the foreign countries in which we operate. Declining economic conditions, or negative perceptions about economic conditions, could result in a substantial decrease in demand for our services and products. World political events could also result in further U.S. military actions, terrorist attacks and related unrest. Military action by the U. S. 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 oil and gas and could affect the markets for our products and services. Insurance premiums could also increase and coverages may be unavailable.

Uncertain economic conditions and instability make it particularly difficult for us to forecast demand trends. The timing and extent of any changes to currently prevailing market conditions is uncertain, and may affect demand for many of our services and products. Consequently, we may not be able to accurately predict future economic conditions or the effect of such conditions on demand for our services and products and resulting results of operations or financial condition.

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

We continually seek opportunities to increase efficiency and value through various transactions, including purchases or sales of assets or businesses. These transactions are intended to result in the offering of new services or products, the generation of income or cash, the creation of efficiencies or the reduction of risk. Whether we realize the anticipated benefits from an 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

15

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.

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 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 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.

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.

16

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

As previously reported in the Form 10-Q for the quarter ended March 31, 2012, Integrated Production Services, Inc. (IPS), a Complete legacy subsidiary, was named in a one count Misdemeanor Information, case number CR-11-00068, filed in the U.S. District Court for the Eastern District of Oklahoma on September 26, 2011, relating to an alleged violation of the Clean Water Act. IPS submitted a guilty plea on March 1, 2012 pursuant to a written agreement with the U.S. Department of Justice. IPS paid a $140,000 fine and $22,000 in the form of community service to the Oklahoma Department of Wildlife Conservation. In addition, IPS will serve two years of probation, during which IPS is required to implement an Environmental Compliance Program at a cost of no less than $38,000.

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.

17

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
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
2012
First Quarter	$	31.88	$	25.51
Second Quarter		28.21		17.54
Third Quarter		24.45		18.80
Fourth Quarter		21.76		18.00

As of February 18, 2013, there were 159,467,014 shares of our common stock outstanding, which were held by 145 record holders.

Dividend Information

Historically, we have not paid cash dividends on our common stock. We currently expect to retain all of the cash our business generates to fund the operation and expansion of our business, and to reduce our debt obligations. 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

The following table provides information about our common stock repurchased and retired during each month for the three months ended December 31, 2012:

Period	Total Number of Shares Purchased (1)		Average Price Paid per  Share
October 1 - 31, 2012		1,814	$	20.26
November 1 - 30, 2012		—	$	—
December 1 - 31, 2012		42,900	$	20.11
Total		44,714	$	20.12

⁽¹⁾  Through our stock incentive plans, 44,714 shares were delivered to us by our employees to satisfy their tax withholding requirements upon vesting of restricted stock.

18

Performance Graph

The following performance graph and related information shall not be deemed “solicitating material” or “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933 or the 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 five years ended December 31, 2012 with the total return on the S&P 500 Stock Index and our Self-Determined Peer Group, as described below, for the same period. The information in the graph is based on the assumption of a $100 investment on January 1, 2008 at closing prices on December 31, 2007.

The comparisons in the graph are required by the SEC and are not intended to be a forecast or be indicative of possible future performance of our common stock.

	Years Ended December 31,
	2008		2009		2010		2011		2012
Superior Energy Services, Inc.	$	46	$	71	$	102	$	83	$	60
S&P 500 Stock Index	$	63	$	80	$	92	$	94	$	109
Peer Group	$	42	$	69	$	93	$	82	$	81

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, 2007.

19

Our 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 Corporation, FMC Technologies, Inc., Halliburton Company, 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 N.V 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 in Part I, Items 7 and 8, respectively, in this Annual Report. The financial data is in thousands, except per share amounts.

				Years Ended December 31,
	2012			2011			2010			2009			2008
Revenues	$	4,568,068		$	1,964,332		$	1,563,043		$	1,320,641		$	1,760,020
Income (loss) from operations		706,522			296,389			173,852			(81,396	)		537,534
Net income (loss) from continuing operations		383,142			159,389			86,146			(120,540	)		335,604
Income (loss) from discontinued operations, net of tax		(17,207	)		(16,835	)		(4,329	)		18,217			15,871
Net income (loss)		365,935			142,554			81,817			(102,323	)		351,475
Net income (loss) from continuing operations per share:
Basic		2.57			2.00			1.09			(1.54	)		4.19
Diluted		2.54			1.97			1.08			(1.54	)		4.13
Net income (loss) from discontinued operations per share:
Basic		(0.12	)		(0.21	)		(0.05	)		0.23			0.20
Diluted		(0.12	)		(0.21	)		(0.05	)		0.23			0.20
Net income (loss) per share:
Basic		2.45			1.79			1.04			(1.31	)		4.39
Diluted		2.42			1.76			1.03			(1.31	)		4.33
Total assets*		7,802,886			4,048,145			2,907,533			2,516,665			2,490,145
Long-term debt, net*		1,814,500			1,685,087			681,635			848,665			654,199
Decommissioning liabilities, less current portion		93,053			108,220			100,787			—			—
Stockholders’ equity		4,231,079			1,453,599			1,280,551			1,178,045			1,254,273

* Total assets and long-term debt, net include amounts related to discontinued operations for years 2008 through 2011.

20

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, which substantially expanded the size and scope of our business. Given the substantial nature of this acquisition and its impact on our financial performance, comparisons between our results for years ended December 31, 2012 and 2011 may not be meaningful.

On February 15, 2012, we sold a derrick barge and on March 30, 2012, we sold the assets of our former Marine segment, consisting of a fleet of 18 liftboats. The operating results from these dispositions have been included within discontinued operations on the consolidated statements of income for all periods presented.

We believe we are a leading provider of specialized oilfield services and equipment. As a result of the Complete acquisition, we significantly added to our geographic footprint in the U.S. land market area. We now offer a wider variety of products and services throughout the life cycle 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, as well as enhancing 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 products and services 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 four segments: (1) Drilling Products and Services, (2) Onshore Completion and Workover Services, (3) Production Services, and (4) Subsea and Technical Solutions. 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

Prior to the fourth quarter of 2012, we reported our operating results in two segments: Drilling Products and Services and Subsea and Well Enhancement. During the fourth quarter of 2012, we revised our internal reporting structure that we use in determining how to allocate resources. As a result, we divided our previous segment identified as Subsea and Well Enhancement segment into three segments that better reflect our product and service offerings throughout the life cycle of a well: Onshore Completion and Workover Services, Production Services, and Subsea and Technical Solutions. Accordingly, all prior period segment disclosures have been recast to reflect this change in reporting structure. The Drilling Products and Services segment remains unchanged.

The Drilling Products and Services segment is capital intensive with higher operating margins relative to our other segments 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 2012, approximately 44% of segment revenue was derived from U.S. land market areas (down from 47% in 2011), while approximately 31% of segment revenue was from the Gulf of Mexico market area (up from 25% in 2011) and approximately 25% of segment revenue was from international market areas (down from 29% in 2011). Premium drill pipe accounted for more than 40% of revenue in this segment, while bottom hole assemblies and accommodations each accounted for more than 20% of this segment’s revenue in 2012.

21

The Onshore Completions and Workover Services segment consists primarily of services used in the completion and workover of oil and gas wells on land. These services include pressure pumping, well service rigs and fluid management services. In 2012, virtually all of this segment’s revenue was derived from U.S. land market areas and was comprised of products and services from the legacy Complete businesses. Demand for these services in the U.S. land market area can change quickly and is primarily dependent on the number of land wells drilled and completed. Given the cyclical nature of activity drivers in the U.S. land market areas coupled with the high labor intensity of these services, operating margins can fluctuate widely depending on supply and demand at a given point in the cycle. In an effort to lessen some of the volatility, we try to contract for three-year terms as much as 65% of our pressure pumping horsepower that is used for horizontal well fracturing. In addition, the volumes of produced water that we permanently dispose of for our customers typically generate stable revenue streams as they are primarily a by-product of ongoing oil and gas production from existing and mature wells. Pressure pumping is the largest service offering in this segment, representing more than 40% of segment revenue in 2012, while well service rigs and fluid management each account for more than 20% of segment revenue.

The Production Services segment consists of intervention services primarily used to maintain and extend oil and gas production during the life of a producing well, and specialized pressure-control tools used to manage and control pressure throughout the life of a well. The services provided are labor intensive and margins can fluctuate based on how much customers spend on enhancing existing oil and gas production from mature wells. In 2012, approximately 69% of segment revenue was derived from the U.S. land market area (up from 64% in 2011), while approximately 11% of segment revenue was from the Gulf of Mexico market area (down from 19% in 2011) and approximately 20% of segment revenue was from international market areas (up from 17% in 2011). Coiled tubing is the largest service offering in this segment, accounting for more than 30% of segment revenue in 2012. The significant growth in U.S. land revenue, as well as some of the growth in international revenue, in 2012 can be attributed to the Complete acquisition as legacy Complete businesses offered cased hole wireline, coiled tubing and remedial pumping in the U.S. land market area, as well as coiled tubing in Mexico.

The Subsea and Technical Solutions segment consists of products and services that generally address customer-specific needs and include offerings such as pressure control services, completion tools and services, subsea construction, end-of-life services, production handling arrangements, the production and sale of oil and gas, and marine technical services. In 2012, approximately 10% of segment revenue was derived from the U.S. land market area (down from 12% in 2011), while approximately 46% of segment revenue was from the Gulf of Mexico market area (down from 50% in 2011) and approximately 44% of segment revenue was from international market areas (up from 39% in 2011). Given the project-specific nature associated with several of the service offerings in this segment and the seasonality associated with shallow water Gulf of Mexico activity, revenue and operating margins in this segment can have significant variations from quarter to quarter. Pressure control and associated services represent the largest service offering in this segment, accounting for more than 30% of segment revenue in 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 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.

22

Historical market indicators are listed below:

	2012		% Change			2011		% Change			2010
Worldwide Rig Count (1)
U.S.		1,871		0	%		1,879		22	%		1,546
International (2)		1,234		6	%		1,167		7	%		1,094
Commodity Prices (average)
Crude Oil (West Texas Intermediate)	$	94.22		-1	%	$	95.47		19	%	$	80.12
Natural Gas (Henry Hub)	$	2.75		-33	%	$	4.09		-8	%	$	4.44

⁽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 were mixed in 2012 as compared with 2011. The average number of drilling rigs working in the U.S. was virtually unchanged, while the international rig count increased 6%. The average price of West Texas Intermediate crude oil decreased 1% while the average price of Henry Hub natural gas decreased 33%.

The following table compares our revenues generated from major geographic regions for the years ended December 31, 2012 and 2011 (in thousands). We attribute revenue to countries based on the location where services are performed or the destination of the rental or sale of products.

	Revenue
	2012		%			2011		%			Change
U.S. Land	$	3,043,599		67	%	$	856,130		43	%	$	2,187,469
Gulf of Mexico		725,929		16	%		582,008		30	%		143,921
International		798,540		17	%		526,194		27	%		272,346
Total	$	4,568,068		100	%	$	1,964,332		100	%	$	2,603,736

In 2012, our U.S. land revenue increased more than 3.5 times to $3,043.6 million as a result of the Complete acquisition, which contributed $1,593.7 million in the Onshore Completions and Workover segment and $606.8 million in the Production Services segment. U.S. land revenue from the Drilling Products and Services segment increased 20% despite a flat rig count environment. The growth was attributable to the increase in the number of rigs drilling horizontal wells in the U.S. land market areas, which resulted in higher utilization of new assets added through capital expenditures. U.S. land revenue in the Subsea and Technical Solutions segment increased 13% primarily due to increased demand for pressure control services and completion tools and services. Within individual product and service lines, the largest increases in the U.S. land market area were in pressure pumping, fluid management, well services rigs and coiled tubing primarily resulting from the Complete acquisition. In addition, we experienced strong growth in premium drill pipe and accommodations.

Our Gulf of Mexico revenue increased 25% to $725.9 million as this market benefitted from a strong rebound in deepwater drilling activity as well as shallow water intervention and decommissioning activity. The Drilling Products and Services segment, which has significant deepwater Gulf of Mexico exposure, experienced a 61% increase in revenue from the Gulf of Mexico. Downhole drilling tools such as bottom hole assemblies and premium drill pipe experienced the most growth. The Subsea and Technical Solutions segment revenue from the Gulf of Mexico increased 13%, while the Production Services segment revenue from the Gulf of Mexico

grew 10%.

23

Our international revenue increased 52% to $798.5 million due primarily to the Complete acquisition, which accounted for 44% of the increase as a result of its coiled tubing business in Mexico. As a result, the Production Services segment revenue from international market areas increased 129%. The Subsea and Technical Solutions segment revenue from international market areas increased 39% due to increased demand for pressure control services and subsea construction, while the Drilling Products and Services segment experienced a 9% increase in international revenue primarily due to increased rentals of downhole drilling tools.

Industry Outlook

Based on current expectations of the industry’s indicators of demand (commodity prices and drilling rig counts), we believe there will be lower activity in U.S. land markets and increasing demand in the Gulf of Mexico and international market areas.

During the last half of 2012, we believe utilization and pricing declined for many of our completion-oriented services such as pressure pumping, fluid management and coiled tubing due to weak prices for natural gas and natural gas liquids, and a reduction in the pace of spending by our customers. While we anticipate that customer spending levels in the U.S. land market areas will be at or near the same levels achieved in 2012, we don’t anticipate a full recovery in pricing in the short term. As a result, cost of service as a percentage of revenue is likely to be higher in 2013 for several products and services that have a high concentration of U.S. land revenue.

In the Gulf of Mexico, we anticipate continued growth in deepwater activity as well as steady or increasing activity for our shallow water services. 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 2013 than 2012. 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 business combinations, long-lived assets, goodwill, income taxes, allowance for doubtful accounts, revenue recognition, long-term contract 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.

Business Combinations—Purchase Price Allocation. We allocate the purchase price of an acquired business to its identifiable assets and liabilities based on estimated fair values. The excess of the purchase price over the amount allocated to the assets and liabilities, if any, is recorded as goodwill. We use all available information to estimate

24

fair values, including quoted market prices, the carrying value of acquired assets, and widely accepted valuation techniques such as discounted cash flows. We engage third-party appraisal firms to assist in fair value determination of property, plant and equipment, inventories, identifiable intangible assets, and any other significant assets or liabilities when appropriate. The judgments made in determining the estimated fair value assigned to each class of assets acquired and liabilities assumed, as well as asset lives, can materially impact our results of operations.

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, which 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.

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 as of 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.

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

25

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 services either on a day rate or turnkey basis, with a majority of our projects conducted on a day rate basis. We rent products 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 Contract 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 a reporting period. To the extent that an adjustment in the estimated total contract cost impacts estimated profit of the contract, the cumulative change to revenue and profitability is reflected in the period in which this adjustment in estimate is identified. The accuracy of the revenue and estimated earnings we report for fixed-price contracts is dependent upon the judgments we make in estimating our contract performance and contract revenue and costs.

Self-Insurance. We self-insure, through deductibles and retentions, up to certain levels for losses under our insurance programs. As a result of our growth, we have elected to retain more risk by increasing our self-insurance levels. 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, auto liability 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), has oil and gas properties as well as the related well abandonment and decommissioning liabilities. Wild Well follows the successful efforts method of accounting for its 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 and well costs are depleted on a units-of-production basis based on the estimated remaining equivalent 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.

26

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.

Discontinued Operations. We classify assets and liabilities of a disposal group as held for sale and discontinued operations if the following criteria are met: (1) management, with appropriate authority, commits to a plan to sell a disposal group; (2) the asset is available for immediate sale in its current condition; (3) an active program to locate a buyer and other actions to complete the sale have been initiated; (4) the sale is probable; (5) the disposal group is being actively marketed for sale at a reasonable price; and (6) actions required to complete the plan of sale indicate it is unlikely that significant changes to the plan of sale will occur or that the plan will be withdrawn. Once deemed held for sale, we no longer depreciate the assets of the disposal group. Upon sale, we calculate the gain or loss associated with the disposition by comparing the carrying value of the assets less direct costs of the sale with the proceeds received. In the consolidated statements of income, we present discontinued operations, net of tax effect, as a separate caption below net income from continuing operations.

Comparison of the Results of Operations for the Years Ended December 31, 2012 and 2011

For the year ended December 31, 2012, our revenue was $4,568.1 million and our net income from continuing operations was $383.1 million, or $2.54 diluted earnings per share from continuing operations. For the year ended December 31, 2011, our revenue was $1,964.3 million and our net income from continuing operations was $159.4 million, or $1.97 diluted earnings per share from continuing operations. Included in the results for 2012 was of $32.9 million of acquisition related costs, $2.3 million of loss on early extinguishment of debt, and $17.9 million of gain on the sale of our equity-method investment.

The following table compares our operating results for the years ended December 31, 2012 and 2011 (in thousands). Cost of services, rentals and sales excludes depreciation, depletion, amortization and accretion for each of our business segments.

	Revenue						Cost of Services
	2012		2011		Change		2012		%			2011		%			Change
Drilling Products and Services	$	775,066	$	611,101	$	163,965	$	255,853		33	%	$	220,647		36	%	$	35,206
Onshore Completion and Workover Services		1,593,977		—		1,593,977		1,039,732		65	%		—		—			1,039,732
Production Services		1,510,990		788,568		722,422		929,552		62	%		443,381		56	%		486,171
Subsea and Technical Solutions		688,035		564,663		123,372		464,336		67	%		382,381		68	%		81,955
Total	$	4,568,068	$	1,964,332	$	2,603,736	$	2,689,473		59	%	$	1,046,409		53	%	$	1,643,064

27

Given the transformational nature of the acquisition of Complete, supplemental pro forma information related to Complete and certain other acquisitions as if these acquisitions had occurred on January 1, 2011 is also provided for comparative purposes. The pro forma results below include operating results of certain acquisitions of Complete prior to February 7, 2012 and operating results of other businesses acquired in 2011 and 2012. The pro forma results do not include any potential synergies, cost savings or other expected benefits of the acquisition. Accordingly, the pro forma results should not be considered indicative of the results that would have occurred if the acquisition and related borrowings had been consummated as of January 1, 2011, nor are they indicative of future results. The following table compares our pro forma operating results for the years ended December 31, 2012 and 2011 (in thousands). Cost of services, rentals and sales excludes depreciation, depletion, amortization and accretion for each of our business segments.

	Pro Forma Revenue						Pro Forma Cost of Services
	2012		2011		Change		2012		%			2011		%			Change
Drilling Products and Services	$	775,066	$	611,101	$	163,965	$	255,853		33	%	$	220,647		36	%	$	35,206
Onshore Completion and Workover Services		1,785,866		1,599,774		186,092		1,165,473		65	%		1,001,469		63	%		164,004
Production Services		1,609,497		1,439,079		170,418		995,657		62	%		831,230		58	%		164,427
Subsea and Technical Solutions		688,035		564,663		123,372		464,336		67	%		382,381		68	%		81,955
Total	$	4,858,464	$	4,214,617	$	643,847	$	2,881,319		59	%	$	2,435,727		58	%	$	445,592

The following discussion analyzes our results on a segment basis:

Drilling Products and Services Segment

Revenue for our Drilling Products and Services segment was $775.1 million for the year ended December 31, 2012, an approximate 27% increase from 2011. Cost of services decreased to 33% of segment revenue in 2012 from 36% in 2011. The increase in revenue for this segment is primarily related to rentals of bottom hole assemblies, drill pipe and specialty tubulars in the Gulf of Mexico market area, and to rentals of accommodation units and premium drill pipe in the U.S. land market area. Revenue from our Gulf of Mexico market increased approximately 61% over the same period in 2011 as the market experienced a strong rebound in deepwater drilling activity. Revenue in our U.S. land market area increased approximately 20% for the year ended December 31, 2012 over the same period in 2011. Revenue generated from our international market areas increased approximately 9% for the year ended December 31, 2012 over the same period in 2011. This increase was primarily related to increased rentals of bottom hole assemblies, drill pipe and specialty tubulars.

Onshore Completion and Workover Services Segment

Revenue for our Onshore Completion and Workover Services segment was $1,594.0 million for the year ended December 31, 2012. Cost of services was 65% of revenue in 2012. There was no revenue recorded in 2011 as products and services that comprise this segment were acquired in 2012 as a result of the Complete acquisition. On a pro forma basis, revenue for 2012 in this segment was $1,785.9 million, an approximate 12% increase over 2011 pro forma revenue of $1,599.8 million, primarily due to utilization of new assets put in service in 2012 through capital expenditures. However, pro forma cost of services increased to 65% of pro forma segment revenue in 2012 from 63% in 2011 as overall utilization and pricing declined during the second half of 2012.

Production Services Segment

Revenue for our Production Services segment was $1,511.0 million for the year ended December 31, 2012, an approximate 92% increase over 2011. Cost of services increased to 62% of segment revenue from 56% in 2011. The Complete acquisition contributed approximately $727.9 million of revenue as we added coiled tubing, cased

28

hole wireline and remedial pumping assets to our existing asset base. In addition, we achieved strong growth in hydraulic workover and snubbing services as well as pressure control tools. Cost of services as a percentage of revenue was higher in 2012 due to a combination of lower utilization and pricing in the U.S. land market area for coiled tubing. Pro forma revenue in 2012 was $1,609.5 million, an approximate 12% increase over 2011 pro forma revenue of $1,439.1 million due to increases in coiled tubing activity during the first half of 2012 and new assets placed into services in 2012 through capital expenditures. Pro forma cost of services increased to 62% of pro forma revenue as compared with 58% in 2011 as a result of additional infrastructure required to support assets placed into service and an increase in certain labor and maintenance expenses.

Subsea and Technical Solutions Segment

Revenue for our Subsea and Technical Solutions segment was $688.0 million for the year ended December 31, 2012, an approximate 22% increase from 2011. Cost of services decreased slightly to 67% of segment revenue in 2012 from 68% in 2011. The primary factors driving the revenue growth were increased demand for pressure control services, subsea construction and completion tools and products. Higher margin pressure control work was offset by lower than anticipated margin for marine technical services, which was primarily related to delays in completing and deploying an oil containment system for a customer in Alaska.

Depreciation, Depletion, Amortization and Accretion

Depreciation, depletion, amortization and accretion increased to $509.3 million for the year ended December 31, 2012 from $244.9 million in 2011. The increase was driven primarily by the acquisition of Complete, which added approximately $221.8 million in depreciation, amortization and accretion expense. Depreciation and amortization expense increased within our Drilling Products and Services segment by $19.9 million, or 15%, and within our Subsea and Technical Solutions Group by $3.6 million, or 8% due to capital expenditures.

General and Administrative Expenses

General and administrative expenses increased to $662.8 million for the year ended December 31, 2012 from $376.6 million in 2011. Increases in general and administrative expenses are largely attributable to our 2012 acquisitions, which added approximately $220.3 million in general and administrative expenses, inclusive of acquisition and incremental stock based compensation expenses. Additionally, we continue to build our infrastructure to support our growth.

Discontinued Operations

Discontinued operations include operating results for both the derrick barge and liftboats with related assets that were sold in the first quarter of 2012. Losses from discontinued operations, net of tax, were $17.2 million for the year ended December 31, 2012 as compared to $16.8 million for the year ended December 31, 2011. In 2012, the Company recorded a pre-tax loss of approximately $3.1 million, inclusive of approximately $9.7 million of goodwill in connection with the sale of the derrick barge. Additionally, the 2012 loss includes a $4.7 million pretax loss on early extinguishment of debt in connection with the sale of our former Marine segment. In 2011, we recorded a pretax reduction in value of the Marine segment’s assets of 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. Also included in the loss from discontinued operations are gains on sale of liftboats, net of tax, of approximately $6.1 million for the year ended December 31, 2011.

29

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 $1,964.3 million and our net income from continuing operations was $159.4 million, or $1.97 diluted earnings per share from continuing operations. For the year ended December 31, 2010, our revenue was $1,563.0 million and our net income from continuing operations was $86.1 million, or $1.08 diluted earnings per share from continuing operations. Included in the results for the year ended December 31, 2010 were pre-tax management transition expenses of approximately $35.0 million.

The following table compares our operating results for the years ended December 31, 2011 and 2010 (in thousands). There was no revenue or cost of service associated with the Onshore Completion and Workover Services segment for 2011 and 2010, as the products and services that comprise this segment were legacy Complete businesses. Cost of services, rentals and sales excludes depreciation, depletion, amortization and accretion for each of our business segments.

	Revenue						Cost of Services
	2011		2010		Change		2011		%			2010		%			Change
Drilling Products and Services	$	611,101	$	474,707	$	136,394	$	220,647		36	%	$	176,463		37	%	$	44,184
Production Services		788,568		560,606		227,962		443,381		56	%		326,155		58	%		117,226
Subsea and Technical Solutions		564,663		527,730		36,933		382,381		68	%		345,874		66	%		36,507
Total	$	1,964,332	$	1,563,043	$	401,289	$	1,046,409		53	%	$	848,492		54	%	$	197,917

The following discussion analyzes our results on a segment basis.

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.

Production Services Segment

Revenue from our Production Services segment was $788.6 million for the year ended December 31, 2011, an approximate 41% increase from 2010. Cost of services decreased to 56% of segment revenue in 2011 from 58% in 2010. This segment’s revenue increased in each of our market areas. Revenue in our U.S. land market area increased approximately 58% primarily related to increased demand for pressure control tools, coiled tubing, cased hole wireline, and remedial pumping services. Revenue in our international market areas increased approximately 30% primarily attributable to hydraulic workover and snubbing services. Revenue in our Gulf of Mexico market area increased approximately 12% related to electric line and snubbing and hydraulic workover services. The increase in this market area was partially offset by decreases in demand for pressure control tools and remedial pumping services.

30

Subsea and Technical Solutions Segment

Revenue from our Subsea and Technical Solutions segment was $564.7 million for the year ended December 31, 2011, an approximate 7% increase from 2010. Cost of services increased to 68% of segment revenue in 2011 from 66% in 2010. Revenue in our U.S. land market area increased approximately 19%, primarily attributable to well control and engineering services. Revenue in our international market area increased approximately 35% primarily attributable to increased demand for well control and subsea intervention projects, along with the acquisition of our completion tools and services business in August 2010. Revenue in our Gulf of Mexico market area decreased by approximately 11% based on a decline in work on a large scale decommissioning project, along with decreased revenue from well control projects. These decreases were partially offset by stimulation and sand control revenue as a result of the acquisition of our completion tools and services business in 2010.

Depreciation, Depletion, Amortization and Accretion

Depreciation, depletion, amortization and accretion increased to $244.9 million for the year ended December 31, 2011 from $208.1 million in 2010. Depreciation and amortization expense increased within our Drilling Products and Services and Production Services segment by $16.1 million, or 14%, and $10.7 million, or 19%, respectively, due to capital expenditures. Depreciation and amortization expense increased within our Subsea and Technical Solutions segment by $10.0 million, or 27%, due to the acquisition of our completion tools and services business in August 2010, higher utilization of certain assets used in subsea intervention projects, as well as capital expenditures.

General and Administrative Expenses

General and administrative expenses increased to $376.6 million for the year ended December 31, 2011 from $332.6 million in 2010, which included approximately $35.0 million of management transition expenses. The increase in general and administrative expenses is attributable to the acquisition of our completion tools and services business, increased bonus and compensation expense due to our improved performance, as well as additional infrastructure to enhance our growth.

Discontinued Operations

Discontinued operations include operating results for both the derrick barge and liftboats with related assets that were sold in the first quarter of 2012. Losses from discontinued operations, net of tax, were $16.8 million for the year ended December 31, 2011 as compared to losses of $4.3 million for the year ended December 31, 2010. In 2011, we recorded a pre-tax reduction in value of assets of 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. In 2010, we recorded a pre-tax reduction in value of assets totaling $32.0 million in connection with liftboat components primarily related to two partially completed liftboats that we concluded were impractical to complete. Also included in the loss from discontinued operations are gains on sale of liftboats, net of tax, of approximately $6.1 million and approximately $0.7 million for the years ended December 31, 2011 and 2010, respectively.

Liquidity and Capital Resources

In the year ended December 31, 2012, we generated net cash from operating activities of $1,035.0 million as compared to $492.8 million in 2011. Our primary liquidity needs are for working capital, debt service, and to fund capital expenditures and acquisitions. Our primary sources of liquidity are cash flows from operations and available borrowings under the revolving portion of our credit facility. We had cash and cash equivalents of $91.2 million as of December 31, 2012 compared to $80.3 million as of December 31, 2011. As of December 31, 2012, approximately $62.6 million of our cash balance was held in foreign jurisdictions. Cash balances held in foreign jurisdictions could be repatriated to the U.S.; however, they would be subject to U.S. federal income

31

taxes, less applicable foreign tax credits. The Company has not provided U.S. income tax expense on earnings of its foreign subsidiaries because it expects to reinvest the undistributed earnings indefinitely.

We spent $1,141.9 million of cash on capital expenditures during the year ended December 31, 2012. Approximately $256.5 million was used to expand and maintain our Drilling Products and Services equipment inventory, and approximately $300.2 million, $321.1 million and $264.1 million was spent to expand and maintain the asset bases of our Onshore Completion and Workover, Production Services and Subsea and Technical Solutions segments, respectively.

On February 7, 2012, in connection with the Complete acquisition, we amended our bank credit facility to increase the revolving borrowing capacity to $600 million from $400 million, and to include a $400 million term loan. The principal balance of the term loan is payable in installments of $5.0 million on the last day of each fiscal quarter, which began on June 30, 2012. Any amounts outstanding on the revolving portion and the term loan of the credit facility are due on February 7, 2017. As of December 31, 2012, we had no amounts outstanding under the revolving portion of the credit facility and approximately $49.0 million of letters of credit outstanding, which reduce our availability under this portion of the credit facility. The average amount outstanding during the year ended December 31, 2012 was approximately $148.9 million with a weighted average interest rate of 3.22% per annum. The maximum amount outstanding during the year ended December 31, 2012 was $250.0 million, as this amount was borrowed for the acquisition of Complete in February 2012. As of February 18, 2013, we had approximately $85.0 million outstanding under the revolving portion of the credit facility along with approximately $57.3 million of letters of credit outstanding, which reduces our borrowing capacity under the revolving portion of the credit facility. The balance outstanding under the revolving portion of our credit facility is primarily related to a U.S. income tax payment of $123.0 million made in January 2013. 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 domestic 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.

In August 2012, we redeemed $150 million, or 50%, of the principal amount of our $300 million 6 7/8% unsecured senior notes due 2014 at 100% of face value. This redemption resulted in a loss on early extinguishment of debt of approximately $2.3 million related to the writeoff of a portion of debt acquisition costs and note discount. The indenture governing the remaining $150 million 6 7/8% senior notes outstanding requires semi-annual interest payments on June 1^st and December 1^st of each year through the maturity date of June 1, 2014. The indenture contains certain covenants that, among other things, limit us from incurring additional debt, repurchasing capital stock, paying dividends or making other distributions, incurring liens, selling assets or entering into certain mergers or acquisitions.

We have outstanding $500 million of 6 3/8% unsecured senior notes due 2019. The indenture governing the senior notes requires semi-annual interest payments on May 1^st and November 1^st of 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 also have outstanding $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^th of 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.

Our current long-term issuer credit rating is BBB—by Standard and Poor’s and Ba1 by Moody’s. Moody’s upgraded our corporate credit rating from Ba2 to Ba1 with a stable outlook on October 10, 2012.

32

The following table summarizes our contractual cash obligations and commercial commitments as of December 31, 2012 (amounts in thousands). We do not have any other material obligations or commitments.

Description	2013		2014		2015		2016		2017		Thereafter
Long-term debt, including estimated interest payments	$	134,773	$	279,225	$	123,219	$	122,369	$	395,387	$	1,575,813
Capital lease obligations, including estimated interest payments		6,225		6,225		6,225		6,225		6,225		6,744
Decommissioning liabilities, undiscounted		—		27,862		12,310		3,517		2,985		132,797
Operating leases		61,893		41,118		25,985		17,779		10,937		21,287
Vessel construction		14,917		—		—		—		—		—
Other long-term liabilities		—		61,481		21,719		14,974		3,493		19,773
Total	$	217,808	$	415,911	$	189,458	$	164,864	$	419,027	$	1,756,414

We currently believe that we will spend approximately $600 million to $700 million on capital expenditures, excluding acquisitions, during 2013. We believe that our current working capital, cash generated from our operations, and availability under our 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 late 2013.

We intend to continue implementing our growth strategy of increasing the scope of our 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, and the availability under 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 credit facility.

Off-Balance Sheet Arrangements

We have no off-balance sheet financing arrangements other than 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.

In accordance with authoritative guidance related to guarantees, we have assigned an estimated value of $2.6 million as of December 31, 2012 and 2011, which is reflected in other long-term liabilities, related to decommissioning activities in connection with oil and gas properties acquired by SPN Resources prior to its sale to Dynamic Offshore. These properties are currently owned and operated by SandRidge Energy, Inc. The Company believes that the likelihood of being required to perform these guarantees is remote. In the unlikely event of default on any remaining decommissioning liabilities by the obligor, our total maximum potential obligation under these guarantees is estimated to be approximately $125.8 million, net of the contractual right to receive payments from third parties, which is approximately $24.6 million, as of December 31, 2012. The total maximum potential obligation will decrease over time as the underlying obligations are fulfilled.

33

Hedging Activities

In April 2012, we entered into an interest rate swap related to our debt maturing in December 2021 for a notional amount of $100 million, whereby we are entitled to receive semi-annual interest payments at a fixed rate of 7 1/8% per annum and are obligated to make semi-annual interest payments at a variable rate. The variable interest rate, which is adjusted every 90 days, is based on LIBOR plus a fixed margin and is scheduled to terminate on December 15, 2021.

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, 2012 and 2011, 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 were not designated as hedges and were marked to fair market value each period. As of December 31, 2012, 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 Canada, 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.

Assets and liabilities of certain subsidiaries in Canada, the United Kingdom and Europe are translated at end of period exchange rates, while income and expenses 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.

We do not hold derivatives for trading purposes or use derivatives with complex features. 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, 2012, we had no outstanding foreign currency forward contracts.

34

Interest Rates

As of December 31, 2012, our debt (exclusive of discounts), was comprised of the following (in thousands):

	Fixed Rate Debt		Variable Rate Debt
Bank revolving credit facility due 2017	$	—	$	—
Term loan due 2017		—		385,000
6.875% Senior notes due 2014		150,000		—
6.375% Senior notes due 2019		500,000		—
7.125% Senior notes due 2021*		700,000		100,000
Total Debt	$	1,350,000	$	485,000

^(*)  In April 2012, we entered into an interest rate swap agreement for a notional amount of $100 million, whereby we are entitled to receive semi-annual interest payments at a fixed rate of 7 1/8% 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 as of December 31, 2012, a 10% increase in the variable interest rate would increase our interest expense for the year ended December 31, 2012 by approximately $1.4 million, while a 10% decrease would decrease our interest expense by approximately $1.4 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.

35

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, 2012 and 2011, and the related consolidated statements of income, comprehensive income, changes in stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2012. In connection with our audits of the consolidated financial statements, we also have audited the 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, 2012 and 2011, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2012, 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, 2012, 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, 2013 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

KPMG LLP

New Orleans, Louisiana

February 28, 2013

36

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

Consolidated Balance Sheets

December 31, 2012 and 2011

(in thousands, except share data)

	2012			2011
ASSETS
Current assets:
Cash and cash equivalents	$	91,199		$	80,274
Accounts receivable, net of allowance for doubtful accounts of $28,715 and $17,484 as of December 31, 2012 and 2011, respectively		1,027,218			540,602
Deferred income taxes		34,120			—
Prepaid expenses		93,190			34,037
Inventory and other current assets		214,630			228,309
Total current assets		1,460,357			883,222
Property, plant and equipment, net		3,255,220			1,507,368
Goodwill		2,532,065			581,379
Notes receivable		44,838			73,568
Equity-method investments		—			72,472
Intangible and other long-term assets, net		510,406			930,136
Total assets	$	7,802,886		$	4,048,145
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	252,363		$	178,645
Accrued expenses		346,490			197,574
Income taxes payable		153,212			717
Current maturities of long-term debt		20,000			810
Deferred income taxes		—			831
Current portion of decommissioning liabilities		—			14,956
Total current liabilities		772,065			393,533
Deferred income taxes		745,144			297,458
Decommissioning liabilities		93,053			108,220
Long-term debt, net		1,814,500			1,685,087
Other long-term liabilities		147,045			110,248
Stockholders’ equity:
Preferred stock of $0.01 par value. Authorized, 5,000,000 shares; none issued		—			—
Common stock of $0.001 par value.
Authorized—250,000,000, Issued—157,501,635, Outstanding—157,933,224 as of December 31, 2012
Authorized—125,000,000, Issued and Outstanding, 80,425,443 as of December 31, 2011		158			80
Additional paid in capital		2,850,855			447,007
Accumulated other comprehensive loss, net		(19,317	)		(26,936	)
Retained earnings		1,399,383			1,033,448
Total stockholders’ equity		4,231,079			1,453,599
Total liabilities and stockholders’ equity	$	7,802,886		$	4,048,145

See accompanying notes to consolidated financial statements.

37

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

Consolidated Statements of Income

Years Ended December 31, 2012, 2011 and 2010

(in thousands, except per share data)

	2012			2011			2010
Revenues	$	4,568,068		$	1,964,332		$	1,563,043
Costs and expenses:
Cost of services (exclusive of items shown separately below)		2,689,473			1,046,409			848,492
Depreciation, depletion, amortization and accretion		509,281			244,915			208,097
General and administrative expenses		662,792			376,619			332,602
Income from operations		706,522			296,389			173,852
Other income (expense):
Interest expense, net of amounts capitalized		(117,682	)		(72,994	)		(56,480	)
Interest income		3,170			6,226			5,135
Other income (expense)		853			(822	)		825
Loss on early extinguishment of debt		(2,294	)		—			—
Earnings (losses) from equity-method investments, net		(287	)		16,394			8,245
Gain on sale of equity-method investment		17,880			—			—
Income from continuing operations before income taxes		608,162			245,193			131,577
Income taxes		225,020			85,804			45,431
Net income from continuing operations		383,142			159,389			86,146
Loss from discontinued operations, net of income tax		(17,207	)		(16,835	)		(4,329	)
Net income	$	365,935		$	142,554		$	81,817
Earnings (loss) per share information:
Basic
Continuing operations	$	2.57		$	2.00		$	1.09
Discontinued operations		(0.12	)		(0.21	)		(0.05	)
Basic earnings per share	$	2.45		$	1.79		$	1.04
Diluted
Continuing operations	$	2.54		$	1.97		$	1.08
Discontinued operations		(0.12	)		(0.21	)		(0.05	)
Diluted earnings per share	$	2.42		$	1.76		$	1.03
Weighted average common shares used in computing earnings per share:
Basic		149,288			79,654			78,758
Incremental common shares from stock options		1,081			1,271			840
Incremental common shares from restricted stock units		737			170			136
Diluted		151,106			81,095			79,734

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

Consolidated Statements of Comprehensive Income

Years Ended December 31, 2012, 2011 and 2010

(in thousands)

	2012			2011			2010
Net income	$	365,935		$	142,554		$	81,817
Unrealized net loss on investment securities, net of tax		(897	)		—			—
Change in cumulative translation adjustment, net of tax		8,516			(1,236	)		(6,704	)
Comprehensive income	$	373,554		$	141,318		$	75,113

See accompanying notes to consolidated financial statements.

38

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

Consolidated Statements of Changes in Stockholders’ Equity

Years Ended December 31, 2012, 2011 and 2010

(in thousands, except share data)

	Preferred stock shares		Preferred stock		Common stock shares			Common stock		Additional paid-in capital			Accumulated other comprehensive loss, net			Retained earnings		Total
Balances, December 31, 2009		—	$	—		78,559,350		$	79	$	387,885		$	(18,996	)	$	809,077	$	1,178,045
Net income		—		—		—			—		—			—			81,817		81,817
Foreign currency translation adjustment		—		—		—			—		—			(6,704	)		—		(6,704	)
Grant of restricted stock units		—		—		—			—		950			—			—		950
Restricted stock grant and compensation expense, net of forfeitures		—		—		342,694			—		11,367			—			—		11,367
Exercise of stock options		—		—		87,150			—		927			—			—		927
Tax benefit from exercise of stock options		—		—		—			—		560			—			—		560
Stock option compensation expense		—		—		—			—		15,493			—			—		15,493
Shares issued under Employee Stock
Purchase Plan		—		—		94,250			—		2,233			—			—		2,233
Shares withheld and retired		—		—		(132,391	)		—		(4,137	)		—			—		(4,137	)
Balances, December 31, 2010		—	$	—		78,951,053		$	79	$	415,278		$	(25,700	)	$	890,894	$	1,280,551
Net income		—		—		—			—		—			—			142,554		142,554
Foreign currency translation adjustment		—		—		—			—		—			(1,236	)		—		(1,236	)
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.

39

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

Consolidated Statements of Changes in Stockholders’ Equity

Years Ended December 31, 2012, 2011 and 2010

(in thousands, except share data)

	Preferred stock shares		Preferred stock		Common stock shares			Common stock		Additional paid-in capital			Accumulated other comprehensive loss, net			Retained earnings		Total
Balances, December 31, 2011		—	$	—		80,425,443		$	80	$	447,007		$	(26,936	)	$	1,033,448	$	1,453,599
Net income		—		—		—			—		—			—			365,935		365,935
Foreign currency translation adjustment		—		—		—			—		—			8,516			—		8,516
Unrealized net loss on investment securities		—		—		—			—		—			(897	)		—		(897	)
Grant of restricted stock units		—		—		—			—		1,927			—			—		1,927
Restricted stock grant and compensation expense, net of forfeitures		—		—		295,366			—		16,981			—			—		16,981
Vesting of restricted stock assumed with acquisition of Complete Production Services, Inc.		—		—		64,356			—		—			—			—		—
Exercise of stock options		—		—		1,962,248			2		14,775			—			—		14,777
Tax expense from exercise of stock options		—		—		—			—		(675	)		—			—		(675	)
Stock option compensation expense		—		—		—			—		4,829			—			—		4,829
Shares issued to pay performance share units		—		—		43,259			—		1,140			—			—		1,140
Shares issued under Employee Stock Purchase Plan		—		—		147,026			—		3,360			—			—		3,360
Issuance of common stock in connection with acquisition of Complete Production Services, Inc.		—		—		74,699,065			76		2,361,391			—			—		2,361,467
Fair value of options exchanged in connection with acquisition of Complete Production Services, Inc.		—		—		—			—		3,932			—			—		3,932
Share issuance cost		—		—		—			—		(388	)		—			—		(388	)
Shares withheld and retired		—		—		(135,128	)		—		(3,424	)		—			—		(3,424	)
Balances, December 31, 2012		—	$	—		157,501,635		$	158	$	2,850,855		$	(19,317	)	$	1,399,383	$	4,231,079

See accompanying notes to consolidated financial statements.

40

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

Consolidated Statements of Cash Flows

Years Ended December 31, 2012, 2011 and 2010

(in thousands)

	2012			2011			2010
Cash flows from operating activities:
Net income	$	365,935		$	142,554		$	81,817
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		510,526			257,313			220,835
Deferred income taxes		11,218			48,073			8,276
Excess tax benefit from stock-based compensation		(1,555	)		(9,004	)		(560	)
Gain on sale of equity-method investment		(17,880	)		—			—
Reduction in value of assets		—			46,096			32,004
Stock based and performance share unit compensation expense		36,570			14,032			33,602
Retirement and deferred compensation plan expense		1,607			1,990			4,825
(Earnings) losses from equity-method investments, net of cash received		3,360			(13,152	)		2,905
Amortization of debt acquisition costs and note discount		9,856			25,178			23,954
(Gain) loss sale of businesses		6,649			(8,558	)		(1,083	)
Write off of debt acquisition costs and note discount		3,460			—			—
Other reconciling items, net		1,205			(6,426	)		(4,708	)
Changes in operating assets and liabilities, net of acquisitions and dispositions:
Accounts receivable		(42,946	)		(86,814	)		(89,800	)
Inventory and other current assets		62,720			2,182			85,687
Accounts payable		(30,977	)		40,289			20,303
Accrued expenses		(26,107	)		24,961			8,359
Decommissioning liabilities		(4,660	)		(504	)		(1,759	)
Income taxes		152,093			(1,378	)		10,510
Other, net		(6,031	)		15,972			20,806
Net cash provided by operating activities		1,035,043			492,804			455,973
Cash flows from investing activities:
Payments for capital expenditures		(1,141,922	)		(484,648	)		(323,244	)
Purchases of short-term investments, net		—			—			—
Sale of available-for-sale securities		41,874			—			—
Change in restricted cash held for acquisition of business		785,280			(785,280	)		—
Acquisitions of businesses, net of cash acquired		(1,091,161	)		(1,748	)		(276,077	)
Cash proceeds from sale of businesses		183,094			22,349			5,250
Cash proceeds from sale of equity-method investment		34,087			—			—
Purchase of short-term investments		—			(223,491	)		—
Proceeds from sale of short-term investments		—			223,630			—
Other		31,630			(721	)		(9,402	)
Net cash used in investing activities		(1,157,118	)		(1,249,909	)		(603,473	)
Cash flows from financing activities:
Proceeds from revolving line of credit		696,439			324,913			575,867
Payments on revolving line of credit		(771,439	)		(424,913	)		(577,867	)
Proceeds from issuance of long-term debt		400,000			1,300,000			—
Principal payments on long-term debt		(177,546	)		(400,810	)		(810	)
Payment of debt acquisition costs		(25,274	)		(24,428	)		(5,182	)
Proceeds from exercise of stock options		14,777			10,263			927
Excess tax benefit from stock-based compensation		1,555			9,004			560
Proceeds from issuance of stock through employee benefit plans		2,855			2,206			1,891
Other		(10,383	)		(9,662	)		(3,443	)
Net cash provided by (used in) financing activities		130,984			786,573			(8,057	)
Effect of exchange rate changes on cash		2,016			79			(221	)
Net increase (decrease) in cash and cash equivalents		10,925			29,547			(155,778	)
Cash and cash equivalents at beginning of period		80,274			50,727			206,505
Cash and cash equivalents at end of period	$	91,199		$	80,274		$	50,727

See accompanying notes to consolidated financial statements.

41

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Years Ended December 31, 2012, 2011 and 2010

(1) Summary of Significant Accounting Policies

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 2012 presentation.

Business

The Company is a leading provider of specialized oilfield services and equipment. As a result of the February 7, 2012 acquisition of Complete Production Services, Inc. (Complete), the Company significantly added to its geographic footprint in the U.S. land market area. The Company now offers a wider variety of products and services throughout the life cycle of an oil and gas well. The acquisition of Complete greatly expanded the Company’s ability to offer more products and services related to the completion of a well prior to full production commencing, and enhanced its full suite of intervention services used to carry out wellbore maintenance operations during a well’s producing phase. 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 a well’s life cycle.

The Company serves energy industry customers who focus on exploring, developing and producing oil and gas worldwide. The Company’s operations are managed and organized by both business units and geomarkets offering products and services within various phases of a well’s economic lifecycle. The Company reports its operating results in four segments: (1) Drilling Products and Services; (2) Onshore Completion and Workover Services; (3) Production Services; and (4) Subsea and Technical Solutions.

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.

Major Customers and Concentration of Credit Risk

The majority of the Company’s business is conducted with major and independent oil and gas 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 U.S. and select international market areas. Oil and gas companies make capital expenditures on exploration, development 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 2012, EOG Resources, Inc. accounted for approximately 13% of total revenue, primarily within the Onshore Completion and Workover segment. There were no customers that exceeded 10% of total revenues in 2011 and 2010.

42

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 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. The Company periodically evaluates the creditworthiness of financial institutions that may serve as a counterparty to its derivative instruments.

Cash Equivalents

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

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.

Inventory

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

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 certain marine assets, 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	25	years
Automobiles, trucks, tractors and trailers	3	to	7	years
Furniture and fixtures	2	to	10	years

Certain of the Company’s marine assets are depreciated using the units-of-production method based on the utilization of these assets 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 wells, are capitalized. Other costs such as geological and geophysical costs and the drilling costs of unsuccessful exploratory wells are expensed. Leasehold and well costs are depleted on a units-of-production basis based on the estimated remaining equivalent 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 $12.4 million, $7.1 million and $2.7 million of interest expense in the years ended December 31, 2012, 2011 and 2010, respectively, for various capital projects.

43

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, which 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 asset grouping’s 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 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, in February 2012, the Company entered into an agreement to sell its former Marine segment. As such, the Company concluded that indicators of impairment existed and therefore conducted a fair value assessment of the 18 liftboats comprising that segment as of 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 those liftboats. Based on this valuation analysis, the Company determined that the 18 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, which is included in discontinued operations on the consolidated statement of income. On March 30, 2012, the Company sold the 18 liftboats and related assets that had comprised its Marine segment.

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, which is included in discontinued operations on the consolidated statements of income.

Goodwill

During the fourth quarter of 2012, the Company revised the internal reporting structure that is used by its chief operating decision maker in determining how to allocate the Company’s resources and, as a result, divided the Subsea and Well Enhancement segment into three segments that better reflect the Company’s product and service offerings throughout the life cycle of a well: Onshore Completion and Workover Services, Production Services, and Subsea and Technical Solutions. The Drilling Products and Services segment remained unchanged. As a result of this internal change, the Company allocated the goodwill that had been assigned to the Subsea and Well Enhancement segment to the three new segments based on each segment’s relative fair value. The Company engaged a third party valuation firm to assist with the calculation of these fair values.

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

44

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, 2012 and 2010, as the fair value of each of the reporting units exceeded its carrying amount. As of December 31, 2012, the fair value of the Drilling and Products Services segment was substantially in excess of its carrying value. The fair values of the Onshore Completion and Workover Services and Production Services segments did not substantially exceed their respective carrying values due to the fact these reporting units are primarily composed of assets acquired and liabilities assumed through the acquisition of Complete in February 2012. Therefore, the carrying values of these segments were recorded at fair value at the date of the acquisition. Additionally, the fair value of the Subsea and Technical Solutions segment did not substantially exceed its carrying value. 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 as of 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 former Marine segment was less than its carrying amount, indicating that goodwill was potentially impaired. As such, 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 former 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 former Marine segment was less than its carrying value and fully wrote-off the goodwill balance of $10.3 million, which was recorded within loss from discontinued operations on the consolidated statement of income.

45

The following table summarizes the activity for the Company’s goodwill for the years ended December 31, 2012 and 2011 (amounts in thousands):

	Drilling Products and Services			Subsea and Well Enhancement			Onshore Completion Services		Production Services		Subsea and Technical Solutions		Marine			Total
Balance, December 31, 2010	$	139,463		$	437,684		$	—	$	—	$	—	$	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		(35	)		(296	)		—		—		—		—			(331	)
Balance, December 31, 2011	$	140,428		$	440,951		$	—	$	—	$	—	$	—		$	581,379
Acquisition activities		—			23,452			1,193,486		738,709		—		—			1,955,647
Disposition activities		—			(9,741	)		—		—		—		—			(9,741	)
Allocation of goodwill from change in internal reporting structure		—			(454,574	)		224,564		138,994		91,016		—			—
Additional consideration paid for prior acquisitions		3,000			—			—		—		—		—			3,000
Foreign currency translation adjustment		1,519			(88	)		—		349		—		—			1,780
Balance, December 31, 2012	$	144,947		$	—		$	1,418,050	$	878,052	$	91,016	$	—		$	2,532,065

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.

Notes Receivable

The Company’s wholly owned subsidiary, Wild Well Control, Inc. (Wild Well), has decommissioning obligations related to the Bullwinkle platform. Notes receivable consist of a commitment from the seller of the platform towards its eventual abandonment. 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

46

this obligation 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. During the second quarter of 2012, the Company revised its timing estimate for the Bullwinkle platform removal, resulting in a significant reduction of the present value of the notes receivable. The Company recorded interest income related to notes receivable of $2.8 million, $4.5 million and $4.5 million for the years ended December 31, 2012, 2011 and 2010, respectively.

Intangible and Other Long-Term Assets

Intangible and other long-term assets consist of the following as of December 31, 2012 and 2011 (amounts in thousands):

	December 31, 2012							December 31, 2011
	Gross Amount		Accumulated Amortization			Net Balance		Gross Amount		Accumulated Amortization			Net Balance
Customer relationships	$	348,160	$	(25,357	)	$	322,803	$	23,707	$	(6,144	)	$	17,563
Tradenames		53,063		(7,017	)		46,046		18,005		(2,706	)		15,299
Non-compete agreements		2,938		(1,062	)		1,876		1,697		(1,126	)		571
Debt issuance costs		63,829		(18,948	)		44,881		41,449		(10,039	)		31,410
Deferred compensation plan assets		11,343		—			11,343		10,598		—			10,598
Escrowed cash		50,304		—			50,304		50,196		—			50,196
Restricted cash and cash equivalents		—		—			—		785,280		—			785,280
Long-term assets held as major replacement spares		7,241		—			7,241		13,806		—			13,806
Other		26,676		(764	)		25,912		6,018		(605	)		5,413
Total	$	563,554	$	(53,148	)	$	510,406	$	950,756	$	(20,620	)	$	930,136

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 17 years, 13 years, and 3 years, respectively. Amortization expense (exclusive of debt issuance costs) was approximately $24.0 million, $3.4 million and $3.3 million for the years ended December 31, 2012, 2011 and 2010, respectively. Estimated annual amortization of intangible assets (exclusive of debt acquisition costs) will be approximately $27.1 million for 2013, $26.9 million for 2014, $26.2 million for 2015, $25.7 million for 2016 and $25.0 million for 2017, excluding the effects of any acquisitions or dispositions subsequent to December 31, 2012.

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 7 years. Amortization of debt issuance costs is recorded in interest expense, net of amounts capitalized within the consolidated statements of income.

In accordance with the asset purchase agreement between Wild Well and Shell Offshore, Inc. to acquire the Bullwinkle platform and its related assets and to assume the related decommissioning obligations, Wild Well obtained a $50.0 million performance bond and funded its portion of $50.0 million into an escrow account. Included in intangible and other long-term assets, net is escrowed cash of $50.3 million and $50.2 million as of December 31, 2012 and 2011, respectively.

In connection with the December 2011 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 limited the Company’s use of the proceeds, net of fees and expenses from the issuance, to the acquisition of Complete. As of December 31, 2011, the Company held $785.3 million in other long-term assets as net proceeds from the issuance of these notes, which were used to partially fund the acquisition of Complete on February 7, 2012.

47

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. As a result of continuing development activities, the Company revised its estimates during the second quarter of 2012 relating to the timing of decommissioning work on its Bullwinkle assets, including a 10 year postponement of the platform decommissioning. This change in estimate resulted in a significant reduction in the present value of decommissioning liabilities.

In connection with the acquisition of Complete, the Company assumed approximately $4.6 million of estimated decommissioning liabilities associated with costs to plug and abandon disposal wells at the end of the service lives of the assets.

The following table summarizes the activity for the Company’s decommissioning liabilities for the years ended December 31, 2012 and 2011 (in thousands):

	Years Ended December 31,
	2012			2011
Decommissioning liabilities, December 31, 2011 and 2010, respectively	$	123,176		$	117,716
Liabilities acquired and incurred		4,620			—
Liabilities settled		(4,660	)		(504	)
Accretion		4,670			6,752
Revision in estimated liabilities		(34,753	)		(788	)
Total decommissioning liabilities, December 31, 2012 and 2011, respectively		93,053			123,176
Less: current portion of decommissioning liabilities as of December 31, 2012 and 2011, respectively		—			14,956
Long-term decommissioning liabilities, December 31, 2012 and 2011, respectively	$	93,053		$	108,220

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’s drilling products and services are billed on a day rate basis, and revenue

48

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 contracts for the remainder of its products and services either on a day rate or turnkey basis, with a vast majority of its projects conducted on a day rate basis. The Company accounts for the revenue and related costs on large-scale platform decommissioning contracts on the percentage-of-completion method utilizing costs incurred as a percentage of total estimated costs. The Company recognizes oil and gas revenue from its interests in producing wells as oil and natural gas is sold.

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.

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.

Earnings per Share

Basic earnings per share is computed by dividing income 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, conversion of restricted stock units and the vesting of outstanding restricted stock issued in the acquisition of Complete.

Stock options for approximately 2,100,000 shares, 540,000 shares and 1,650,000 shares were excluded in the computation of diluted earnings per share for the years ended December 31, 2012, 2011 and 2010, respectively, as the effect would have been anti-dilutive.

Discontinued Operations

The Company classifies assets and liabilities of a disposal group as held for sale and discontinued operations if the following criteria are met: (1) management, with appropriate authority, commits to a plan to sell a disposal group; (2) the asset is available for immediate sale in its current condition; (3) an active program to locate a buyer and other actions to complete the sale have been initiated; (4) the sale is probable; (5) the disposal group is being actively marketed for sale at a reasonable price; and (6) actions required to complete the plan of sale indicate it is unlikely that significant changes to the plan of sale will occur or that the plan will be withdrawn. Once deemed as held for sale, the Company no longer depreciates the assets of the disposal group. Upon sale, the Company calculates the gain or loss associated with the disposition by comparing the carrying value of the assets less direct costs of the sale with the proceeds received. In the consolidated statements of income, losses from discontinued operations are presented, net of tax effect, as a separate caption below net income from continuing operations.

49

Fair Value Measurements

The company follows the 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.

Financial Instruments

The fair value of the Company’s financial instruments of cash equivalents, accounts receivable, accounts payable, accrued expenses and borrowings under its 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 $1,960.0 million and $1,749.8 million as of December 31, 2012 and 2011, 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.

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 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 income in the period in which the currency exchange rates change. For the years ended December 31, 2012, 2011 and 2010, the Company recorded approximately ($2.7) million, $1.4 million and $1.6 million of foreign currency gains (losses), respectively.

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 consolidated statement of income. 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.

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

50

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 enters into interest rate swaps. Under these agreements, the Company is entitled to receive semi-annual interest payments at a fixed rate and is obligated to make quarterly interest payments at a variable rate. The Company had fixed-rate interest on approximately 74% and 87% of its long-term debt as of December 31, 2012 and 2011, respectively. The Company had notional amounts of $100 million and $150 million, respectively, related to interest rate swaps with a variable interest rate, adjusted every 90 days, based on LIBOR plus a fixed margin as of December 31, 2012 and 2011, respectively.

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, 2012 and 2011, 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 were 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.

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 income.

Self-Insurance Reserves

The Company is self-insured, through deductibles and retentions, up to certain levels for losses under its insurance programs. With the Company’s growth, the Company has elected to retain more risk by increasing its self-insurance levels. 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, auto liability and group medical on an annual basis.

Recently Issued Accounting Pronouncements

In December 2011, the FASB issued ASU 2011-11, “Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities”. This 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 the Company’s consolidated financial position or results of operations.

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.

51

(2) Supplemental Cash Flow Information

The following table includes the Company’s supplemental cash flow information for the years ended December 31, 2012, 2011 and 2010 (amounts in thousands):

	2012			2011			2010
Cash paid for interest, net of amounts capitalized	$	109,112		$	39,539		$	34,034
Cash paid for income taxes	$	42,261		$	22,320		$	25,435
Details of business acquisitions:
Fair value of assets	$	4,364,872		$	8,650		$	515,767
Fair value of liabilities		(695,243	)		(6,902	)		(228,417	)
Common stock issued		(2,361,466	)		—			—
Cash paid		1,308,163			1,748			287,350
Less cash acquired		(217,002	)		—			(11,273	)
Net cash paid for acquisitions	$	1,091,161		$	1,748		$	276,077
Details of proceeds from sale of businesses:
Book value of assets	$	198,369		$	13,791		$	4,236
Book value of liabilities		(8,626	)		—			81
Receivable due from sale		—			—			(150	)
Gain on sale of business		(6,649	)		8,558			1,083
Proceeds from sale of businesses	$	183,094		$	22,349		$	5,250
Capital expenditures included in accounts payable and accrued expenses	$	61,035		$	23,053		$	—
Additional consideration payable on acquisitions	$	9,890		$	—		$	—
Non-cash financing activity:
Share settlement for employee tax liability	$	—		$	—		$	3,093

(3) Acquisitions

Complete Production Services

On February 7, 2012, the Company acquired Complete in a cash and stock merger transaction valued at approximately $2,914.8 million. Complete focused 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 were located throughout the U.S. and Mexico. The acquisition of Complete substantially expanded the size and scope of the Company’s services. Management believes that this acquisition positions the combined company to be better equipped to compete with the larger oilfield service companies and to expand internationally. Complete’s operations are reported within the Company’s Onshore Completion and Workover Services and Production Services segments.

Pursuant to the merger agreement, 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 $553.3 million in cash and issued approximately 74.7 million shares valued at approximately $2,308.2 million (based on the closing price of the Company’s common stock on the acquisition date of $30.90). Additionally, the Company paid $676.0 million, inclusive of a $26.0 million prepayment premium, to redeem $650 million of Complete’s 8.0% senior notes. The Company also assumed all outstanding stock options and shares of non-vested and unissued restricted stock held by Complete’s employees and directors at the time of acquisition.

52

Complete’s stock options and shares of restricted stock outstanding at closing were converted into the Company’s options and restricted stock using a conversion ratio of 1.1999. The estimated fair value associated with the Company’s options issued in exchange for Complete’s options was approximately $58.1 million based on a Black-Scholes valuation model. $56.6 million of this value was attributable to service rendered prior to the date of acquisition, of which $52.7 million was recorded as part of the consideration transferred and $3.9 million was recorded as an expense. The remaining $1.5 million will be expensed over the remaining service term of the replacement stock option awards. In addition, $0.6 million of replacement restricted stock awards was attributable to service rendered prior to the date of acquisition and recorded as part of the consideration transferred. An additional $18.2 million will be expensed over the remaining service term of the replacement restricted stock awards.

The transaction has been 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. As of December 31, 2012, the Company finalized the determination of the assets acquired and liabilities assumed. The Company recorded adjustments to the initial purchase price allocation to reflect new information obtained about facts and circumstances that existed as of the acquisition date. The following table summarizes the consideration paid and the fair value of the assets acquired and liabilities assumed as of the acquisition date (in thousands):

Assets:
Current assets	$	738,456
Property, plant and equipment		1,221,808
Goodwill		1,922,689
Intangible and other long-term assets		372,713
Liabilities:
Current liabilities		231,951
Deferred income taxes		403,403
Other long-term liabilities		29,519
Net assets acquired	$	3,590,793

Included in current assets acquired is approximately $214.6 million of cash, and accounts receivable with a fair value of approximately $443.7 million. The gross amount due from customers is approximately $449.0 million, of which approximately $5.3 million is deemed to be doubtful.

Property, Plant and Equipment

A step-up adjustment of approximately $44.2 million was recorded to present property, plant and equipment acquired at its estimated fair value. The weighted average useful life used to calculate depreciation of the step-up related to property, plant and equipment is approximately 6 years.

Goodwill

Goodwill of approximately $1,922.7 million was recognized as a result of this acquisition and was calculated as the excess of the consideration paid over the net assets recognized and represents estimated future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. It includes access to new product and service offerings, an experienced management team and workforce, and other benefits that the Company believes will result from the combination of the operations, and any other intangible assets that do not qualify for separate recognition. None of the goodwill related to this acquisition will be deductible for tax purposes. The goodwill has been allocated between the Onshore Completion and Workover Services and the Production Services segments based on the relative fair value of these segments.

53

Intangible Assets

The Company identified intangible assets related to trade names and customer relationships. The following table summarizes the fair value estimates recorded for the identifiable intangible assets (in thousands) and their estimated useful lives:

	Estimated Fair Value		Estimated Useful Life
Customer relationships	$	315,000		17 years
Tradenames		35,000		10 years
Total identifiable intangible assets	$	350,000

Deferred Income Taxes

The Company provided deferred income taxes and other tax liabilities as part of the acquisition accounting related to the estimated fair value of acquired intangible assets and property, plant and equipment, as well as for uncertain tax positions taken in prior year tax returns. An adjustment of approximately $125.5 million was recorded to present the deferred tax assets and liabilities and other tax liabilities at fair value.

Acquisition Related Expenses

Acquisition related expenses totaled approximately $33.3 million, of which approximately $28.8 million was recorded in the year ended December 31, 2012. The remainder was recorded in the three months ended December 31, 2011. These acquisition related costs include expenses directly related to acquiring Complete and have been recorded in general and administrative expenses in the consolidated statements of income.

Other Acquisitions

In August 2012, the Company acquired 100% of the equity interest in a company that provides mechanical wireline, electric line and well testing services to oil and gas companies in Argentina. This acquisition provides the Company with a platform for the continued expansion in the South American market area. The Company paid $25.5 million at closing along with an additional $5.6 million payable when shareholders’ equity as of the closing date was finalized. The Company has also recorded a current liability of approximately $6.5 million for contingent consideration based upon certain performance metrics. Additionally, the Company deposited $8.0 million in an escrow account on behalf of the sellers for the settlement of certain liabilities. Goodwill of approximately $22.6 million was recognized as a result of this acquisition and was calculated as the excess of the consideration paid over the net assets recognized and represents estimated future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. None of the goodwill related to this acquisition will be deductible for tax purposes. All of the goodwill was originally assigned to the Subsea and Well Enhancement segment. As a result of the Company’s revised internal reporting structure, the goodwill related to this acquisition was allocated among the three new segments based on each segment’s relative fair value.

Current Earnings and Pro Forma Impact of Acquisitions

The revenue and earnings related to Complete and certain other acquisitions included in the Company’s consolidated statement of income for the year ended December 31, 2012, and the revenue and earnings of the Company on a consolidated basis as if these acquisitions had occurred on January 1, 2011, are set forth in the table below (in thousands, except per share amounts). The earnings related to Complete and certain other acquisitions included in the Company’s consolidated statement of income for the year ended December 31, 2012 do not include interest expense or other corporate costs. The pro forma results include (i) the amortization associated with the acquired intangible assets, (ii) additional depreciation expense related to adjustments to property, plant and equipment, (iii) additional interest expense associated with debt used to fund a portion of the acquisitions, (iv) a reduction to interest expense associated with repayment of the acquirees’ debt, and (v) operating results of certain acquisitions of Complete prior to February 7, 2012. For the year ended December 31, 2012, these pro forma results exclude approximately $81.6 million of non-recurring expenses, of which $48.4

54

million was recorded by Complete prior to February 7, 2012. These nonrecurring expenses include banking, legal, consulting and accounting fees, and change of control and other acquisition related expenses. The pro forma results do not include any potential synergies, cost savings or other expected benefits of the acquisition. Accordingly, the pro forma results should not be considered indicative of the results that would have occurred if the acquisition and related borrowings had been consummated as of January 1, 2011, nor are they indicative of future results.

	Revenue		Net income from continuing operations		Basic earnings per share		Diluted earnings per share
Actual results of acquisitions from date of acquisitions through December 31, 2012	$	2,225,013	$	140,806	$	1.61	$	1.59
Supplemental pro forma for the Company:
Year ended December 31, 2012	$	4,858,464	$	428,276	$	2.70	$	2.70
Year ended December 31, 2011	$	4,214,617	$	390,209	$	2.53	$	2.49

The Company has no off-balance sheet financing arrangements related to potential additional consideration that may be payable as a result of the future operating performance of acquired businesses. As of December 31, 2012, the maximum additional consideration payable was approximately $10.0 million, all of which was included in accrued expenses. The Company paid additional consideration of $6.0 million during the year ended December 31, 2012, as a result of prior acquisitions. Of the consideration paid in 2012, $3.0 million was attributable to acquisitions that occurred prior to the adoption of revised authoritative guidance and therefore was capitalized during the year ended December 31, 2012 when the amount was fixed and determinable. The remaining $3.0 million paid in the year ended December 31, 2012 had been capitalized upon acquisition.

(4) Discontinued Operations

On February 15, 2012, the Company sold one of its derrick barges and received proceeds of approximately $44.5 million, inclusive of selling costs. The Company recorded a pre-tax loss of approximately $3.1 million, inclusive of approximately $9.7 million of goodwill, during the year ended December 31, 2012 in connection with this sale. This business was previously reported in the former Subsea and Well Enhancement segment. The operations and loss on the sale of this disposal group have been reported within loss from discontinued operations in the consolidated statements of income for all periods presented.

On March 30, 2012, the Company sold 18 liftboats and related assets comprising its former Marine segment. The Company received cash proceeds of approximately $138.6 million, inclusive of working capital and selling costs. In connection with the sale, the Company repaid approximately $12.5 million in U.S. Government guaranteed long-term financing (see note 8). Additionally, the Company paid approximately $4.0 million of make-whole premiums and wrote off approximately $0.7 million of unamortized loan costs as a result of this repayment. The Company’s total pre-tax loss on the disposal of this segment was approximately $56.1 million, which includes a $46.1 million write off of long-lived assets and goodwill that was recorded in the fourth quarter of 2011 in order to approximate the segment’s indicated fair value and an additional loss of $10.0 million recorded in the first quarter of 2012, comprised of an approximate $3.6 million loss on sale of assets and approximately $6.4 million of additional costs related to the disposition. During the year ended December 31, 2011, the Company sold seven liftboats from the former Marine segment for approximately $22.3 million, net of sales commissions, and recorded a pre-tax gain of approximately $8.6 million. The operations and loss on the sale of this disposal group have been reported within loss from discontinued operations in the consolidated statements of income for all periods presented.

55

The following table summarizes the components of loss from discontinued operations, net of tax for the years ended December 31, 2012, 2011 and 2010:

	2012			2011			2010
Revenues	$	16,231		$	105,834		$	118,573
Loss from discontinued operations before income tax		(8,249	)		(32,051	)		(7,558	)
Income tax benefit		(1,771	)		(9,083	)		(2,505	)
Gain (loss) on disposition, net of tax (benefit) expense of ($2,391), $2,425 and $359 for the years ended December 31, 2012, 2011 and 2010, respectively		(10,729	)		6,133			724
Loss from discontinued operations, net of tax	$	(17,207	)	$	(16,835	)	$	(4,329	)

The following table presents the assets and liabilities of these disposal groups as of December 31, 2011 (in thousands):

Accounts receivable, net	$	16,342
Prepaid expenses		1,900
Inventory and other current assets		2,371
Current assets of discontinued operations	$	20,613
Property, plant and equipment, net		170,222
Goodwill		9,740
Intangible and other long-term assets, net		3,875
Long-term assets of discontinued operations	$	183,837
Accounts payable	$	1,231
Accrued expenses		13,421
Current maturities of long-term debt		810
Current liabilities of discontinued operations	$	15,462
Long-term debt	$	11,736

(5) Property, Plant and Equipment

A summary of property, plant and equipment as of December 31, 2012 and 2011 (in thousands) is as follows:

	2012			2011
Buildings, improvements and leasehold improvements	$	230,457		$	139,432
Marine vessels and equipment		199,819			417,413
Machinery and equipment		3,500,112			1,596,580
Automobiles, trucks, tractors and trailers		60,805			38,770
Furniture and fixtures		59,124			40,575
Construction-in-progress		410,425			171,108
Land		59,824			29,518
Oil and gas producing assets		77,285			44,109
		4,597,851			2,477,505
Accumulated depreciation and depletion		(1,342,631	)		(970,137	)
Property, plant and equipment, net	$	3,255,220		$	1,507,368

56

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 the 18 liftboats that comprised the former Marine segment during the year ended December 31, 2011 as the indicated valuation from potential buyers for such assets was less than their carrying values. During 2010, the Company recorded a reduction in the value of assets totaling $32.0 million in connection with liftboat components primarily related to partially completed liftboats.

The Company had approximately $63.5 million and $23.2 million of leasehold improvements as of December 31, 2012 and 2011, 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 $480.0 million, $224.6 million, and $207.7 million for the years ended December 31, 2012, 2011 and 2010, respectively, which includes amounts recorded within loss from discontinued operations on the consolidated statements of income.

(6) Inventory and Other Current Assets

Inventory and other current assets includes approximately $136.5 million and $83.1 million of inventory as of December 31, 2012 and 2011, respectively. The Company’s inventory balance as of December 31, 2012 consisted of approximately $63.7 million of finished goods, $6.0 million of work-in-process, $5.0 million of raw materials and $61.8 million of supplies and consumables. The Company’s inventory balance as of 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.

Inventory and other current assets also includes approximately $18.5 million and $133.4 million of costs incurred and estimated earnings in excess of billings on uncompleted contracts as of December 31, 2012 and 2011, respectively. The Company follows the percentage-of-completion method of accounting for applicable contracts. In December 2007, Wild Well entered into contractual arrangements pursuant to which it decommissioned seven downed oil and gas platforms and related well facilities located in the Gulf of Mexico for a fixed sum of $750 million. The contract contained certain covenants primarily related to Wild Well’s performance of the work. As of December 31, 2012, the work on this project was complete, and all amounts due the Company pursuant to this contract have been collected. As of December 31, 2011, there were approximately $129.7 million of costs and estimated earnings in excess of billings related to this contract included in other current assets.

Additionally, available-for-sale securities are included in inventory and other current assets. On April 17, 2012, SandRidge Energy Inc. (NYSE: SD) (SandRidge) completed its acquisition of Dynamic Offshore, at which time the Company received approximately $34.1 million in cash and approximately $51.6 million in shares of SandRidge stock (approximately 7.0 million shares valued at $7.33 per share) in consideration for its 10% interest in Dynamic Offshore (see note 7). In accordance with authoritative guidance related to equity securities, the Company is accounting for the shares received through this transaction as available-for-sale securities. The changes in fair values, net of applicable taxes, on available-for-sale securities are recorded as unrealized holding gains (losses) on securities as a component of accumulated other comprehensive loss in shareholders’ equity. During the year ended December 31, 2012, the Company sold approximately 5.6 million shares of SandRidge stock for approximately $41.9 million, resulting in a realized gain of approximately $0.9 million.

The fair value of the remaining 1.4 million shares as of December 31, 2012 was approximately $9.2 million. During the year ended December 31, 2012, the Company recorded an unrealized loss on these securities of approximately $1.4 million, of which approximately $0.9 million was reported within accumulated other comprehensive loss, net of tax benefit of approximately $0.5 million. The Company evaluates whether unrealized losses on investments in securities are other-than-temporary, and if it is believed the unrealized losses are other-than-temporary, an impairment charge is recorded. There were no other-than-temporary impairment losses recognized during the year ended December 31, 2012.

57

(7) Equity-Method Investments

Investments in entities that are not controlled by the Company, but where the Company has the ability to exercise 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 (losses) from equity-method investments on its consolidated statements of income.

Prior to March 2011, the Company had separate equity-method investments in SPN Resources, LLC (SPN Resources) and DBH, LLC (DBH). In March 2011, the Company contributed all of its equity interests in SPN Resources and DBH to Dynamic Offshore, the majority owner of both SPN Resources and DBH, in exchange for a 10% interest in Dynamic Offshore. In April 2012, SandRidge acquired Dynamic Offshore (see note 6). The Company recorded a gain in the second quarter of 2012 of approximately $17.9 million as a result of this transaction.

The Company’s equity interest in Dynamic Offshore was accounted for as an equity-method investment with a balance of approximately $70.6 million as of December 31, 2011. The Company recorded losses from its equity-method investment in Dynamic Offshore of approximately $0.3 million and income of approximately $15.0 million for the twelve and ten months ended December 31, 2012 and 2011, respectively.

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 as of December 31, 2011. The Company also recorded revenue from Dynamic Offshore of approximately $49.8 million and $44.9 million for the twelve and ten months ended December 31, 2012 and 2011, respectively. Additionally, the Company had 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 recorded earnings from its equity-method investment in SPN Resources of approximately $0.2 million and recorded earnings from its equity-method investment in DBH of approximately $0.9 million for the two months ended February 28, 2011. The Company also recorded revenue from SPN Resources of approximately $0.3 million and from DBH of approximately $0.9 million for the two months ended February 28, 2011.

(8) Debt

The Company’s long-term debt as of December 31, 2012 and 2011 consisted of the following (in thousands):

	2012			2011
Revolving credit facility - interest payable monthly at floating rate, due December 2017	$	—		$	75,000
Term loan - interest payable monthly at floating rate and principal payable quarterly, due December 2017		385,000			—
U.S. Government guaranteed long-term financing - interest payable semiannually at 6.45%, due in semiannual installments through June 2027		—			12,546
Senior Notes - interest payable semiannually at 6 7/8%, due June 2014		150,000			300,000
Discount on 6 7/8% Senior Notes		(500	)		(1,649	)
Senior Notes - interest payable semiannually at 6 3/8%, due May 2019		500,000			500,000
Senior Notes - interest payable semiannually at 7 1/8%, due December 2021		800,000			800,000
		1,834,500			1,685,897
Less current portion		20,000			810
Long-term debt	$	1,814,500		$	1,685,087

58

On February 7, 2012, in connection with the Complete acquisition, the Company amended its credit facility to increase the revolving borrowing capacity to $600.0 million from $400.0 million, and to include a $400.0 million term loan. The principal balance of the term loan is payable in installments of $5.0 million on the last day of each fiscal quarter, which began on June 30, 2012. Any amounts outstanding on the revolving portion and the term loan of the credit facility are due on February 7, 2017. Costs associated with the credit facility totaled approximately $24.7 million. These costs have been capitalized and will be amortized over the term of the credit facility.

As of December 31, 2012, the Company had no amounts outstanding under the revolving portion of the credit facility. The Company had approximately $49.0 million of letters of credit outstanding, which reduce the Company’s borrowing availability under this portion of the credit facility. Amounts borrowed under the credit facility bear interest at LIBOR 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. As of December 31, 2012, the Company was in compliance with all such covenants.

In August 2012, the Company redeemed $150 million, or 50%, of the principal amount of its $300 million 6 7/8% unsecured senior notes due 2014 at 100% of face value. This redemption resulted in a loss on early extinguishment of debt of approximately $2.3 million related to the write off of debt acquisition costs and notes discount. The indenture governing the remaining $150 million 6 7/8% senior notes outstanding 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. As of December 31, 2012, the Company was in compliance with all such covenants.

The Company has outstanding $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^st of 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. As of December 31, 2012, the Company was in compliance with all such covenants.

The Company also has outstanding $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^th of 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. As of December 31, 2012, the Company was in compliance with all such covenants.

In connection with the sale of the assets comprising the former Marine segment in March 2012, the Company repaid $12.5 million of U.S. Government guaranteed long-term financing (see note 4). The Company also paid approximately $4.0 million of make-whole premiums and wrote off approximately $0.7 million of unamortized loan costs as a result of this repayment. These expenses have been reported in discontinued operations, net of income tax in the consolidated statement of income.

59

Annual maturities of long-term debt for each of the five fiscal years following December 31, 2012 and thereafter are as follows (in thousands):

2013	$	20,000
2014		170,000
2015		20,000
2016		20,000
2017		305,000
Thereafter		1,300,000
Total	$	1,835,000

(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 advisors (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 the 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 2012, the Company granted 78,043 non-qualified stock options under these same terms and also assumed and converted 2,668,046 non-qualified stock options related to the merger with Complete.

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, 2012, 2011 and 2010, as well as the options assumed and converted in the Complete acquisition, and the related assumptions used to calculate the fair value:

	Years Ended December 31,
	2012 Actual			2011 Actual			2010 Actual
Weighted average fair value of grants	$	21.76		$	13.54		$	10.56
Black-Scholes-Merton Assumptions:
Risk free interest rate		0.41	%		0.85	%		2.07	%
Expected life (years)		2			5			4
Volatility		55.27	%		56.31	%		49.28	%
Dividend yield		—			—			—

For 2012, the expected life of options assumed and converted in connection with the Complete acquisition was approximately two years, and the expected life of new option grants issued in 2012 was approximately five years, resulting in a weighted average life of approximately two years.

60

The Company’s compensation expense related to stock options for the years ended December 31, 2012, 2011 and 2010 was approximately $4.8 million, $3.3 million and $15.5 million, respectively, which is reflected in general and administrative expenses in the consolidated statements of income. 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, 2012, 2011 and 2010:

	Number of Options			Weighted Average Option Price		Weighted Average Remaining Contractual Term (in years)		Aggregate Intrinsic Value (in thousands)
Outstanding as of December 31, 2009		3,538,545		$	15.84
Granted		1,549,058		$	25.04
Exercised		(87,150	)	$	10.62
Outstanding as of December 31, 2010		5,000,453		$	18.78
Granted		207,183		$	28.97
Exercised		(876,435	)	$	11.71
Outstanding as of December 31, 2011		4,331,201		$	20.70
Granted		78,043		$	28.57
Assumed and converted in connection with acquisition of Complete Production Services, Inc.		2,668,046		$	10.56
Exercised		(1,962,248	)	$	7.53
Forfeited		(191,940	)	$	25.63
Outstanding as of December 31, 2012		4,923,102		$	20.52		5.3	$	16,334
Exercisable as of December 31, 2012		4,513,913		$	19.87		5.1	$	16,334
Options expected to vest		409,189		$	27.66		8.4	$	—

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, 2012 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, 2012. 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, 2012 (the difference between the stock price upon exercise and the stock option price) was approximately $40.4 million. The Company received approximately $14.8 million, $10.3 million and $0.9 million during the years ended December 31, 2012, 2011 and 2010, respectively, from employee stock option exercises. In accordance with authoritative guidance related to stock-based compensation, the Company has reported the tax benefits of approximately $0.6 million, $7.4 million, $0.6 million from the exercise of stock options for the years ended December 31, 2012, 2011 and 2010, respectively, as financing cash flows in the consolidated statement of cash flows.

61

A summary of information regarding stock options outstanding as of December 31, 2012 is as follows:

	Options Outstanding						Options Exercisable
Range of Exercise Prices	Shares		Weighted Average Remaining Contractual Life		Weighted Average Price		Shares		Weighted Average Price
$4.00-$9.72		108,453		2.7 years	$	6.56		108,453	$	6.56
$10.36-$10.90		988,771		2.8 years	$	10.61		988,771	$	10.61
$12.45-$16.56		379,204		5.6 years	$	13.53		379,204	$	13.53
$17.46-$23.00		1,696,936		5.6 years	$	20.29		1,624,210	$	20.22
$24.00-$30.00		1,283,259		7.1 years	$	26.25		994,111	$	25.76
$34.40-$37.64		458,066		5.7 years	$	35.38		410,751	$	35.45
$40.00-$40.69		8,413		5.2 years	$	40.69		8,413	$	40.69

The following table summarizes non-vested stock option activity for the year ended December 31, 2012:

	Number of Options			Weighted Average Grant Date Fair Value
Non-vested as of December 31, 2011		683,456		$	11.59
Granted		78,043		$	13.19
Assumed and converted with acquisition of Complete Production Services, Inc.		177,867		$	12.41
Vested		(384,180	)	$	11.51
Forfeited		(145,997	)	$	10.77
Non-vested as of December 31, 2012		409,189		$	12.71

As of December 31, 2012, there was approximately $4.0 million of unrecognized compensation expense related to non-vested stock options outstanding. The Company expects to recognize approximately $2.4 million and $1.6 million of compensation expense during the years 2013 and 2014, respectively, for these outstanding non-vested stock options.

Restricted Stock

During the year ended December 31, 2012, the Company granted 362,904 shares of restricted stock to its employees. Shares of restricted stock generally vest in equal annual installments over three years. On February 7, 2012 the Company also assumed and converted 609,743 shares of restricted stock related to the Complete acquisition. Non-vested shares are generally forfeited upon termination of employment. With the exception of the non-vested shares of restricted stock assumed and converted as a result of the Complete acquisition, holders of shares of restricted stock are entitled to all rights of a stockholder 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 outstanding for the years ended December 31, 2012, 2011 and 2010. The Company’s compensation expense related to restricted stock for years ended December 31, 2012, 2011 and 2010 was approximately $17.0 million, $6.0 million and $11.4 million, respectively, which is reflected in general and administrative expenses in the consolidated statements of income. 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.

62

A summary of the status of restricted stock for the year ended December 31, 2012 is presented in the table below:

	Number of Shares			Weighted Average Grant Date Fair Value
Non-vested as of December 31, 2011		1,039,717		$	27.07
Granted		362,904		$	22.87
Assumed and converted with acquisition of Complete Production Services, Inc.		609,743		$	30.90
Vested		(520,575	)	$	25.03
Forfeited		(194,896	)	$	29.98
Non-vested as of December 31, 2012		1,296,893		$	27.89

As of December 31, 2012, there was approximately $26.1 million of unrecognized compensation expense related to non-vested restricted stock. The Company expects to recognize approximately $14.0 million, $10.2 million, $2.0 million during the years 2013, 2014 and 2015, respectively, for non-vested restricted stock. In accordance with authoritative guidance related to stock-based compensation, the Company has reported tax benefits of approximately $1.0 million from the vesting of restricted stock for the year ended December 31, 2012 as financing cash flows in the consolidated statements of cash flows.

Restricted Stock Units

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 aggregate dollar value determined by the Company’s Board of Directors by the fair market value of the Company’s common stock on the day of the annual stockholders’ meeting. If the director’s election occurs at a time other than at the annual meeting, the director will receive a pro rata number of RSUs based on the number of months between his election date and the anniversary of the last annual stockholder meeting. An RSU represents the right to receive from the Company, within 30 days of the date the director ceases to serve on the Board, one share of the Company’s common stock. As of December 31, 2012, there were 257,215 RSUs outstanding. The Company’s expense related to RSUs for the years ended December 31, 2012, 2011 and 2010 was approximately $2.4 million, $1.2 million and $1.2 million, respectively, which is reflected in general and administrative expenses in the consolidated statements of income.

A summary of the activity of restricted stock units for the year ended December 31, 2012 is presented in the table below:

	Number of Restricted Stock Units		Weighted Average Grant Date Fair Value
Outstanding as of December 31, 2011		170,457	$	28.64
Granted		86,758	$	21.48
Outstanding as of December 31, 2012		257,215	$	26.23

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 stockholder return relative to those of the Company’s pre-defined “peer group.” If the participant has met specified continued service requirements, the PSUs will settle in cash or a combination of cash and up to 50% of equivalent value in the Company’s common stock, at the discretion of the Compensation Committee. As of December 31, 2012, there were 295,965 PSUs outstanding (94,562, 74,024 and 127,379 related to performance

63

periods ending December 31, 2013, 2014 and 2015, respectively). The Company’s compensation expense related to all outstanding PSUs for the years ended December 31, 2012, 2011 and 2010 was approximately $11.9 million, $3.2 million and $5.2 million, respectively, which is reflected in general and administrative expenses in the consolidated statements of income. The Company has recorded both current and long-term liabilities for this liability-based compensation award. During the year ended December 31, 2012, the Company issued approximately 43,300 shares of its common stock and paid approximately $2.7 million in cash to its employees to settle PSUs for the three year performance period ended December 31, 2011. During the year ended December 31, 2011, the Company issued approximately 67,300 shares of its common stock and paid approximately $2.8 million in cash to its employees to settle PSUs for the three year performance period ended December 31, 2010. During the year ended December 31, 2010, the Company paid approximately $6.4 million in cash to settle PSUs for the performance period ended December 31, 2009.

Employee Stock Purchase Plan

The Company has an employee stock purchase plan under which an aggregate of 1,000,000 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 $2.9 million, $2.2 million and $1.9 million related to shares issued under this plan for years ended December 31, 2012, 2011 and 2010, respectively. For the years ended December 31, 2012, 2011 and 2010, the Company recorded compensation expense of approximately $0.5 million, $0.4 million and $0.3 million, respectively, which is reflected in general and administrative expenses in the consolidated statements of income. Additionally, the Company issued approximately 147,000 shares, 75,700 shares and 94,200 shares in the years ended December 31, 2012, 2011 and 2010, respectively, related to this stock purchase plan.

401(k)/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 eligible earnings to the plan subject to the contribution limitations imposed by the Internal Revenue Service. In 2012, the Company adopted a “safe harbor” match for its 401(k) plan which includes a nondiscretionary match of 100% of an employee’s contributions to the plan, up to 4% of the employee’s salary. In 2011 and 2010, the Company provided a discretionary match, not to exceed 5% of an employee’s salary. The Company made contributions of approximately $8.4 million, $7.4 million and $3.3 million in the years ended December 31, 2012, 2011 and 2010, respectively.

Non-Qualified Deferred Compensation Plans

The Company has a non-qualified deferred compensation plan which allows certain highly compensated employees 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 PSU compensation to the plan. The Company also has a non-qualified deferred compensation plan for its non-employee directors which allows each director to defer up to 100% of their cash compensation paid by the Company to the plan. Additionally, participating directors may defer up to 100% of the shares of common stock they are entitled to receive in connection with the payout of RSUs. 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). As of December 31, 2012 and 2011, the liability of the Company to the participants was approximately $13.5 million and $13.0 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 as of December 31, 2012 and 2011, the Company had approximately $0.1 million and $2.8 million in accounts payable in anticipation of pending payments. For the years ended December 31, 2012, 2011 and 2010, the Company recorded compensation income (expense) of approximately $1.6 million, $0.1 million and ($1.8) 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,

64

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). As of December 31, 2012 and 2011, the deferred compensation plan asset was approximately $11.3 million and $10.6 million, respectively, and is recorded in intangible and other long-term assets, net. For the years ended December 31, 2012, 2011 and 2010, the Company recorded other income (expense) of ($0.7) million, ($0.2) million, $0.8 million, respectively, related to the earnings and losses of the deferred compensation plan assets.

Supplemental Executive Retirement Plan

The Company 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 2012, 2011 and 2010, the participants in the plan received contributions ranging from 5% to 35% of salary and annual cash bonus, which totaled approximately $1.8 million, $1.0 million and $5.5 million, respectively. The Company may also make discretionary contributions to a participant’s 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 compensation expense of approximately $2.4 million, $1.8 million and $5.6 million in general and administrative expenses for the years ended December 31, 2012, 2011 and 2010, respectively, inclusive of discretionary contributions. During the years ended December 31, 2012 and 2011, the Company paid approximately $6.7 million and $5.5 million, respectively, to select participants of the plan. There were no payments to participants of this plan in 2010.

(10) Income Taxes

The components of income from continuing operations before income taxes for the years ended December 31, 2012, 2011 and 2010 are as follows (in thousands):

	2012		2011		2010
Domestic	$	559,536	$	244,401	$	124,463
Foreign		48,626		792		7,114
	$	608,162	$	245,193	$	131,577

The components of income tax expense (benefit) for the years ended December 31, 2012, 2011 and 2010 are as follows (in thousands):

	2012		2011			2010
Current:
Federal	$	116,774	$	14,227		$	15,791
State		14,025		785			1,874
Foreign		33,280		19,716			17,628
		164,079		34,728			35,293
Deferred:
Federal		59,442		51,828			13,897
State		1,117		1,121			(761	)
Foreign		382		(1,873	)		(2,998	)
		60,941		51,076			10,138
	$	225,020	$	85,804		$	45,431

65

Income tax expense 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, 2012, 2011 and 2010 as follows (in thousands):

	2012			2011			2010
Computed expected tax expense	$	212,857		$	85,818		$	46,052
Increase (decrease) resulting from
State and foreign income taxes		15,046			(2,106	)		1,839
Other		(2,883	)		2,092			(2,460	)
Income tax	$	225,020		$	85,804		$	45,431

The tax effects of temporary differences that give rise to significant components of deferred income tax assets and liabilities as of December 31, 2012 and 2011 are as follows (in thousands):

	2012		2011
Deferred tax assets:
Allowance for doubtful accounts	$	9,701	$	9,054
Operating loss and tax credit carryforwards		18,020		24,101
Compensation and employee benefits		49,136		28,305
Decommissioning liabilities		28,246		39,638
Other		47,353		35,005
		152,456		136,103
Valuation allowance		—		—
Net deferred tax assets		152,456		136,103
Deferred tax liabilities:
Property, plant and equipment		650,778		317,033
Notes receivable		14,085		25,599
Goodwill and other intangible assets		145,296		22,432
Deferred revenue on long-term contracts		4,329		47,341
Other		48,992		21,987
Deferred tax liabilities		863,480		434,392
Net deferred tax liability	$	711,024	$	298,289

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 as of December 31, 2012 and 2011 as follows (in thousands):

	2012			2011
Deferred tax assets:
Current deferred income taxes	$	34,120		$	—
Deferred tax liabilities:
Current deferred income taxes		—			(831	)
Non-current deferred income taxes		(745,144	)		(297,458	)
Net deferred tax liability	$	(711,024	)	$	(298,289	)

66

As of December 31, 2012, the Company had approximately $1.6 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 $0.5 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, 2012, the Company also has various state net operating loss carryforwards with expiration dates from 2014 to 2026. A deferred tax asset of $10.9 million reflects the expected future tax benefit for the state loss carryforwards.

The Company has not provided U.S. income tax expense on earnings of its foreign subsidiaries, since the Company has reinvested or expects to reinvest outside the U.S. the undistributed earnings indefinitely. As of December 31, 2012, the undistributed earnings of the Company’s foreign subsidiaries were approximately $176 million. If these earnings are repatriated to the U.S. 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., including federal and various state filings, and certain 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 2008.

The Company had approximately $26.4 million, $21.7 million and $24.8 million of unrecorded tax benefits as of December 31, 2012, 2011 and 2010, respectively, all of which would impact the Company’s effective tax rate if recognized.

The activity in unrecognized tax benefits as of December 31, 2012, 2011 and 2010 is as follows (in thousands):

	2012			2011			2010
Unrecognized tax benefits, December 31, 2011, 2010 and 2009, respectively	$	21,692		$	24,760		$	11,013
Additions based on tax positions related to current year		—			—			36
Additions based on tax positions related to prior years		6,873			871			16,607
Reductions based on tax positions related to prior years		(2,166	)		(3,939	)		(2,896	)
Unrecognized tax benefits, December 31, 2012, 2011 and 2010, respectively	$	26,399		$	21,692		$	24,760

(11) Segment Information

Business Segments

During the fourth quarter of 2012, the Company revised the internal reporting structure that is used by the chief operating decision maker in determining how to allocate the Company’s resources and, as a result, divided the Subsea and Well Enhancement segment into three segments that better reflect the Company’s product and service offerings throughout the life cycle of a well: Onshore Completion and Workover Services, Production Services, and Subsea and Technical Solutions. The Drilling Products and Services segment remains unchanged. Accordingly, all prior period segment disclosures have been recast to reflect this change in reporting structure.

The Drilling Products and Services segment rents and sells bottom hole assemblies, premium 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 Onshore Completion and Workover Services segment provides pressure pumping services used to complete and stimulate production in new oil and gas wells, fluid handling services and well servicing rigs that provide a variety of well completion, workover and maintenance services. The Production Services segment provides

67

intervention services such as coiled tubing, cased hole and mechanical wireline, hydraulic workover and snubbing, production testing and optimization, and remedial pumping services. It also provides specialized pressure control tools used to manage and control pressure throughout the life of a well. The Subsea and Technical Solutions segment provides services typically requiring specialized engineering, manufacturing or project planning, including integrated subsea services and engineering services, well control services, well containment systems, stimulation and sand control services and well plug and abandonment services. It also includes production handling arrangements and the production and sale of oil and gas.

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 for the Company’s segments for the years ended December 31, 2012, 2011 and 2010 is shown in the following tables (in thousands):

Year Ended December 31, 2012

	Drilling Products and Services		Onshore Completion and Workover Services		Production Services		Subsea and Technical Solutions		Unallocated			Consolidated Total
Revenues	$	775,066	$	1,593,977	$	1,510,990	$	688,035	$	—		$	4,568,068
Cost of services
(exclusive of items shown separately below)		255,853		1,039,732		929,552		464,336		—			2,689,473
Depreciation, depletion, amortization and accretion		150,687		171,852		135,910		50,832		—			509,281
General and administrative expenses		131,798		185,917		211,293		133,784		—			662,792
Income from operations		236,728		196,476		234,235		39,083		—			706,522
Interest expense , net		—		—		—		—		(117,682	)		(117,682	)
Interest income		—		—		—		2,816		354			3,170
Other income		—		—		—		—		853			853
Loss on early extinguishment of debt		—		—		—		—		(2,294	)		(2,294	)
Earnings from equity-method investments, net		—		—		—		—		(287	)		(287	)
Gain on sale of equity-method investment		—		—		—		—		17,880			17,880
Income (loss) from continuing operations before income taxes	$	236,728	$	196,476	$	234,235	$	41,899	$	(101,176	)	$	608,162

68

Year Ended December 31, 2011

	Drilling Products and Services		Onshore Completion and Workover Services *			Production Services *		Subsea and Technical Solutions		Unallocated			Consolidated Total
Revenues	$	611,101	$	—		$	788,568	$	564,663	$	—		$	1,964,332
Cost of services (exclusive of items shown separately below)		220,647		—			443,381		382,381		—			1,046,409
Depreciation, depletion, amortization and accretion		130,809		—			66,825		47,281		—			244,915
General and administrative expenses		122,201		3,226			135,180		116,012		—			376,619
Income (loss) from operations		137,444		(3,226	)		143,182		18,989		—			296,389
Interest expense , net		—		—			—		—		(72,994	)		(72,994	)
Interest income		—		—			—		4,542		1,684			6,226
Other income		—		—			—		105		(927	)		(822	)
Earnings from equity-method investments, net		—		—			—		—		16,394			16,394
Income (loss) from continuing operations before income taxes	$	137,444	$	(3,226	)	$	143,182	$	23,636	$	(55,843	)	$	245,193

* Includes segment’s pro rata share of approximately $4.5 million of acquisition related expenses recorded in the year ended December 31, 2011.

Year Ended December 31, 2010

	Drilling Products and Services		Production Services		Subsea and Technical Solutions		Unallocated			Consolidated Total
Revenues	$	474,707	$	560,606	$	527,730	$	—		$	1,563,043
Cost of services
(exclusive of items shown separately below)		176,463		326,155		345,874		—			848,492
Depreciation, depletion, amortization and accretion		114,733		56,120		37,244		—			208,097
General and administrative expenses		108,845		113,738		110,019		—			332,602
Income from operations		74,666		64,593		34,593		—			173,852
Interest expense , net		—		—		—		(56,480	)		(56,480	)
Interest income		—		—		4,548		587			5,135
Other income		—		—		—		825			825
Earnings from equity-method investments, net		—		—		—		8,245			8,245
Income (loss) from continuing operations before income taxes	$	74,666	$	64,593	$	39,141	$	(46,823	)	$	131,577

Identifiable Assets

	Drilling Products and Services		Onshore Completion and Workover Services		Production Services		Subsea and Technical Solutions		Marine		Unallocated		Consolidated Total
December 31, 2012	$	1,086,804	$	3,223,984	$	2,185,779	$	1,295,134	$	—	$	11,185	$	7,802,886
December 31, 2011	$	947,679	$	560,246	$	1,140,724	$	1,162,580	$	164,444	$	72,472	$	4,048,145
December 31, 2010	$	802,785	$	—	$	714,140	$	1,055,673	$	255,883	$	79,052	$	2,907,533

69

Capital Expenditures

	Drilling Products and Services		Onshore Completion and Workover Services		Production Services		Subsea and Technical Solutions		Marine		Consolidated Total
December 31, 2012	$	246,389	$	308,317	$	334,670	$	279,729	$	—	$	1,169,105
December 31, 2011	$	219,121	$	—	$	173,562	$	112,504	$	2,514	$	507,701
December 31, 2010	$	142,942	$	—	$	56,089	$	94,224	$	29,989	$	323,244

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 the end of a period. The Company’s revenue attributed to the U.S. and to other countries and the value of its long-lived assets by those locations is as follows (in thousands):

	Revenues						Long-Lived Assets
	2012		2011		2010		2012		2011
United States	$	3,769,528	$	1,438,138	$	1,134,938	$	2,684,932	$	1,060,483
Other Countries		798,540		526,194		428,105		570,288		446,885
Total	$	4,568,068	$	1,964,332	$	1,563,043	$	3,255,220	$	1,507,368

(12) Guarantee

In accordance with authoritative guidance related to guarantees, the Company has assigned an estimated value of $2.6 million as of December 31, 2012 and 2011, which is reflected in other long-term liabilities, related to decommissioning activities in connection with oil and gas properties acquired by SPN Resources prior to its sale to Dynamic Offshore. These properties are currently owned and operated by subsidiaries of SandRidge. The Company believes that the likelihood of being required to perform these guarantees is remote. In the unlikely event of default on any remaining decommissioning liabilities, the total maximum potential obligation under these guarantees is estimated to be approximately $125.8 million, net of the contractual right to receive payments from third parties, which is approximately $24.6 million, as of December 31, 2012. The total maximum potential obligation will decrease over time as the underlying obligations are fulfilled.

(13) Commitments and Contingencies

The Company’s wholly owned subsidiary, Hallin Marine, is the lessee of a dynamically positioned subsea vessel under a capital lease expiring in 2019 with a two year renewal option. Hallin Marine owns a 5% equity interest in the entity that owns this leased asset. The lessor’s debt is 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. The vessel’s gross asset value under the capital lease was approximately $37.6 million at inception and accumulated depreciation through December 31, 2012 and 2011 was approximately $12.2 million and $8.0 million, respectively. As of December 31, 2012 and 2011, the Company had approximately $25.6 million and $29.5 million, respectively, included in other long-term liabilities, and approximately $3.9 million and $3.6 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 $3.9 million, $4.2 million, $4.6 million, $5.0 million and $5.4 million for the years ending December 31, 2013, 2014, 2015, 2016 and 2017, respectively, exclusive of interest at an annual rate of 8.5%. For the years ended December 31, 2012, 2011 and 2010, the Company recorded interest expense of approximately $2.7 million, $3.0 million, and $3.0 million respectively, in connection with this capital lease.

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 $26.3 million, $18.3 million and

70

$15.1 million in the years ended December 31, 2012, 2011 and 2010, respectively. Future minimum lease payments under non-cancelable leases for the five years ending December 31, 2013 through 2017 and thereafter are as follows: $61.9 million, $41.1 million, $26.0 million, $17.8 million, $10.9 million and $21.3 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 its business activities. Legal costs related to these matters are expensed as incurred. In management’s opinion, none of the pending litigation, disputes or claims is expected to have a material adverse effect on the Company’s financial condition, results of operations or liquidity.

(14) Fair Value Measurements

The following tables provide a summary of the financial assets and liabilities measured at fair value on a recurring basis as of December 31, 2012 and 2011 (in thousands):

	December 31,		Fair Value Measurements at Reporting Date Using
	2012		Level 1		Level 2		Level 3
Inventory and other current assets
Available-for-sale securities	$	9,224	$	9,224		—		—
Intangible and other long-term assets, net
Non-qualified deferred compensation assets	$	11,343	$	825	$	10,518		—
Interest rate swap	$	1,286		—	$	1,286		—
Accounts payable
Non-qualified deferred compensation liabilities	$	125		—	$	125		—
Contingent consideration	$	9,890		—		—	$	9,890
Other long-term liabilities
Non-qualified deferred compensation liabilities	$	13,515		—	$	13,515		—
	December 31, 2011		Level 1		Level 2		Level 3
Intangible and other long-term assets, net
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		—

Available-for-sale securities is comprised of approximately 1.4 million shares of SandRidge common stock that the Company received as partial consideration for its 10% interest in Dynamic Offshore. The securities are reported at fair value based on the stock’s closing price as reported on the New York Stock Exchange (see note 6).

The Company’s non-qualified deferred compensation plans allow officers, certain highly compensated employees and non-employee directors 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 separate trust agreements, subject to general creditors, to segregate assets of each plan and reports the accounts of the trusts 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.

71

In April 2012, the Company entered into an interest rate swap agreement related to its fixed rate debt maturing in December 2021 for a notional amount of $100 million, whereby the Company is entitled to receive semi-annual interest payments at a fixed rate of 7 1/8% per annum and is obligated to make semi-annual interest payments at a floating rate, adjusted every 90 days, based on LIBOR plus a fixed margin. The swap agreement, scheduled to terminate on December 15, 2021, is designated as a fair value hedge of a portion of the 7 1/8% unsecured senior notes, as the derivative has been tested to be highly effective in offsetting changes in the fair value of the underlying note. As this derivative is classified as a fair value hedge, the changes in the fair value of the derivative are offset against the changes in the fair value of the underlying note in interest expense, net (see note 15). The Company previously had an interest rate swap agreement for a notional amount of $150 million related to its fixed rate debt maturing in June 2014 that was designated as a fair value hedge. In February 2012, the Company sold this interest rate swap to the counterparty for approximately $1.2 million.

Included in current liabilities is $9.9 million of contingent consideration related to Complete’s acquisition of a remedial pumping and cementing company in 2011, and to the acquisition of a wireline and well testing company in 2012. The fair value of the contingent consideration was determined using a probability-weighted discounted cash flow approach at the acquisition and reporting date. The approach is based on significant inputs that are not observable in the market, which are referred to as Level 3 inputs. The fair value is based on the acquired companies reaching specific performance metrics. During the year ended December 31, 2012, the Company recorded additional purchase consideration of approximately $2.0 million related to its acquisition of the wireline and well testing company as certain performance metrics exceeded original projections. This additional consideration was recorded in general and administrative expenses in the consolidated statements of income. The following table summarizes the activity recorded using fair value of Level 3 liabilities for the year ended December 31, 2012 (in thousands):

Beginning balance as of December 31, 2011	$	—
Additions related to acquisitions		10,663
Settlements		(3,000	)
Losses included in earnings attributable to additional consideration		2,227
Beginning balance as of December 31, 2012		9,890

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 December 31, 2011, the Company wrote off approximately $46.1 million of certain long-lived assets to approximate the indicated fair value of the liftboats from the 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. The write offs related to liftboats in both 2011 and 2010 are included in discontinued operations in the consolidated statements of income for each respective period.

The following tables reflect the fair value measurements used in testing the impairment of long-lived assets during the years ended December 31, 2011 and 2010 (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		—		—		—		—		(10,334	)

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

72

(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 April 2012, the Company entered into an interest rate swap for a notional amount of $100 million related to its fixed rate debt maturing in December 2021. This transaction is 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 $1.3 million within intangible and other long term assets in the consolidated balance sheet as of December 31, 2012. 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 statement of cash flows.

The Company had an interest rate swap agreement for a notional amount of $150 million related to its fixed rate debt maturing in June 2014. This transaction was designated as a fair value hedge since the swap hedged 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 within intangible and other long-term assets in the consolidated balance sheet as of December 31, 2011. In February 2012, the Company sold this interest rate swap to the counterparty for $1.2 million.

The location and effect of the derivative instrument on the consolidated statement of income for the years ended December 31, 2012, 2011 and 2010, presented on a pre-tax basis, is as follows (in thousands):

		Amount of (gain) loss recognized in the year ended December 31,
	Location of (gain) loss recognized	2012			2011			2010
Interest rate swap	Interest expense, net of amounts capitalized	$	(3,632	)	$	793		$	(1,742	)
Hedged item - debt	Interest expense, net amounts capitalized		2,346			(2,536	)		1,581
		$	(1,286	)	$	(1,743	)	$	(161	)

For the years ended December 31, 2012, 2011 and 2010, approximately $1.3 million, $1.7 million and $0.2 million, respectively, of interest income was related to the ineffectiveness associated with these fair value hedges. 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.

(16) Related Party Transactions

The Company believes the following transactions with related parties have terms and conditions no less favorable than transactions with unaffiliated parties. Subsequent to the acquisition of Complete, the Company purchases services, products and equipment from companies affiliated with an officer of one of its subsidiaries. For the year ended December 31, 2012, these purchases totaled approximately $240.3 million, of which approximately $111.6 million was purchased from ORTEQ Energy Services, a heavy equipment construction company which also manufactures pressure pumping equipment, approximately $4.1 million was purchased from Ortowski Construction, primarily related to the manufacture of pressure pumping units, approximately $12.1 million was purchased from Resource Transport, approximately $91.9 million was purchased from Texas Specialty Sands, LLC primarily for the purchase of sand used for pressure pumping activities, approximately $18.9 million was purchased from ProFuel, LLC, and approximately $1.7 million was related to facilities leased from Timber Creek Real Estate Partners. As of December 31, 2012, the Company’s trade accounts payable includes amounts due to these companies totaling approximately $23.2 million, of which approximately $13.4 million was due ORTEQ Energy Services, approximately $1.3 million was due Resource Transport, approximately $6.9 million was due Texas Specialty Sands, and approximately $1.6 million was due ProFuel, LLC. No amounts were due Ortowski Construction and Timber Creek Real Estate Partners.

73

In May 2012, the Company’s President and Chief Executive Officer was appointed as an independent director of the board of Linn Energy, LLC (Linn), an independent oil and natural gas development company with focus areas in the mid-continent, including the Permian Basin, the Hugoton Basin, the Powder River Basin, the Williston Basin, as well as Michigan and California. The Company recorded revenues from Linn of approximately $21.1 million for the year ended December 31, 2012. The Company had trade receivables from Linn of approximately $3.3 million as of December 31, 2012.

(17) Financial Information Related to Guarantor Subsidiaries

SESI, L.L.C. (Issuer), a 100% owned subsidiary of Superior Energy Services, Inc. (Parent), has $500 million of unsecured 6 3/8% senior notes due 2019 and $800 million of unsecured 7 1/8% senior notes due 2021. The Parent, along with certain of its 100% owned domestic subsidiaries, fully and unconditionally guaranteed the senior notes, and such guarantees are joint and several. Domestic income taxes are paid by the Parent through a consolidated tax return and are accounted for by the Parent. The following tables present the consolidating balance sheets as of December 31, 2012 and 2011, and the consolidating statements of income, comprehensive income and cash flows for the years ended December 31, 2012, 2011 and 2010.

74

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

Consolidating Balance Sheets

December 31, 2012

(in thousands)

	Parent			Issuer			Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	—		$	19,486		$	11,525	$	60,188		$	—		$	91,199
Accounts receivable, net		—			1,024			825,154		284,846			(83,806	)		1,027,218
Deferred Income Taxes		34,028			—			—		92			—			34,120
Prepaid expenses		58			4,379			43,881		44,872			—			93,190
Inventory and other current assets		—			10,846			181,266		22,518			—			214,630
Intercompany interest receivable		—			—			—		122			(122	)		—
Total current assets		34,086			35,735			1,061,826		412,638			(83,928	)		1,460,357
Property, plant and equipment, net		—			6,445			2,595,892		652,883			—			3,255,220
Goodwill		—			—			2,122,837		409,228			—			2,532,065
Notes receivable		—			—			44,838		—			—			44,838
Intercompany notes receivable		—			—			—		84,000			(84,000	)		—
Investments in subsidiaries		2,223,692			4,976,314			591,675		—			(7,791,681	)		—
Intangible and other long-term assets, net		—			57,511			374,088		78,807			—			510,406
Total assets	$	2,257,778		$	5,076,005		$	6,791,156	$	1,637,556		$	(7,959,609	)	$	7,802,886
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	—		$	3,192		$	189,075	$	127,764		$	(67,668	)	$	252,363
Accrued expenses		172			49,233			206,015		107,353			(16,283	)		346,490
Income taxes payable		151,674			—			—		1,538			—			153,212
Current maturities of long-term debt		—			20,000			—		—			—			20,000
Intercompany interest payable		—			122								(122	)		—
Total current liabilities		151,846			72,547			395,090		236,655			(84,073	)		772,065
Deferred income taxes		726,436			—			—		18,708			—			745,144
Decommissioning liabilities		—			—			89,877		3,176			—			93,053
Long-term debt, net		—			1,814,500			—		—			—			1,814,500
Intercompany notes payable		—			84,000			—		—			(84,000	)		—
Intercompany payables/(receivables)		(2,858,319	)		848,000			2,512,728		21,139			(523,548	)		—
Other long-term liabilities		6,736			33,270			55,950		51,089			—			147,045
Stockholders’ equity:
Preferred stock of $.01 par value		—			—			—		—			—			—
Common stock of $.001 par value		158			—			782		4,212			(4,994	)		158
Additional paid in capital		2,850,855			124,271			687,939		1,150,859			(1,963,069	)		2,850,855
Accumulated other comprehensive income (loss), net		(19,317	)		(19,317	)		1,042		(18,420	)		36,695			(19,317	)
Retained earnings (accumulated deficit)		1,399,383			2,118,734			3,047,748		170,138			(5,336,620	)		1,399,383
Total stockholders’ equity (deficit)		4,231,079			2,223,688			3,737,511		1,306,789			(7,267,988	)		4,231,079
Total liabilities and stockholders’ equity	$	2,257,778		$	5,076,005		$	6,791,156	$	1,637,556		$	(7,959,609	)	$	7,802,886

75

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		1,650,049			2,833,659			20,062			—			(4,503,770	)		—
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		1,650,083			3,770,755			2,367,317			805,794			(4,545,804	)		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)		(96,989	)		356,668			(253,053	)		(7,276	)		650			—
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 income (loss), net		(26,936	)		(26,936	)		—			(26,936	)		53,872			(26,936	)
Retained earnings (accumulated deficit)		1,033,448			1,552,714			2,235,982			123,254			(3,911,950	)		1,033,448
Total stockholders’ equity (deficit)		1,453,599			1,650,049			2,235,982			617,739			(4,503,770	)		1,453,599
Total liabilities and stockholders’ equity	$	1,650,083		$	3,770,755		$	2,367,317		$	805,794		$	(4,545,804	)	$	4,048,145

76

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

Consolidating Statements of Operations

Year Ended December 31, 2012

(in thousands)

	Parent			Issuer			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	—		$	3,908,584		$	817,614		$	(158,130	)	$	4,568,068
Cost of services (exclusive of items shown separately below)		—			—			2,300,284			547,145			(157,956	)		2,689,473
Depreciation, depletion, amortization and accretion		—			685			425,648			82,948			—			509,281
General and administrative expenses		404			144,187			406,212			112,163			(174	)		662,792
Income (loss) from operations		(404	)		(144,872	)		776,440			75,358			—			706,522
Other income (expense):
Interest expense, net of amounts capitalized		—			(114,927	)		(6	)		(2,749	)		—			(117,682	)
Interest income		—			104			3,036			30			—			3,170
Intercompany interest income (expense)		—			(122	)		—			122			—			—
Other income (expense)		—			745			108			—			—			853
Loss on early extinguishment of debt		—			(2,294	)		—			—			—			(2,294	)
Earnings (losses) from consolidated subsidiaries		566,021			811,768			46,881			—			(1,424,670	)		—
Earnings (losses) from equity-method investments, net		—			(287	)		—			—			—			(287	)
Gain on sale of equity-method investment		—			17,880			—			—			—			17,880
Income (loss) from continuing operations before income taxes		565,617			567,995			826,459			72,761			(1,424,670	)		608,162
Income taxes		202,152			—			—			22,868			—			225,020
Net income (loss) from continuing operations		363,465			567,995			826,459			49,893			(1,424,670	)		383,142
Discontinued operations, net of income tax		2,470			(1,975	)		(14,693	)		(3,009	)		—			(17,207	)
Net income (loss)	$	365,935		$	566,020		$	811,766		$	46,884		$	(1,424,670	)	$	365,935

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

Consolidating Statements of Comprehensive Income

Year Ended December 31, 2012

(in thousands)

	Parent			Issuer			Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Consolidated
Net income (loss)	$	365,935		$	566,020		$	811,766	$	46,884	$	(1,424,670	)	$	365,935
Unrealized net loss on investment securities, net of tax		(897	)		(897	)		—		—		897			(897	)
Change in cumulative translation adjustment		8,516			8,516			1,042		8,516		(18,074	)		8,516
Comprehensive income (loss)	$	373,554		$	573,639		$	812,808	$	55,400	$	(1,441,847	)	$	373,554

77

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	$	—		$	—		$	1,624,945		$	406,843		$	(67,456	)	$	1,964,332
Cost of services (exclusive of items shown separately below)		—			—			817,551			295,998			(67,140	)		1,046,409
Depreciation, depletion, amortization and accretion		—			523			200,614			43,778			—			244,915
General and administrative expenses		683			79,672			230,972			65,608			(316	)		376,619
Income (loss) from operations		(683	)		(80,195	)		375,808			1,459			—			296,389
Other income (expense):
Interest expense, net of amounts capitalized		—			(72,414	)		(43	)		(537	)		—			(72,994	)
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 consolidated subsidiaries		218,198			330,553			2,621			—			(551,372	)		—
Earnings (losses) from equity-method investments, net		—			15,180			—			1,214			—			16,394
Income (loss) from continuing operations before income taxes		217,515			219,889			383,105			(23,944	)		(551,372	)		245,193
Income taxes		81,533			—			—			4,271			—			85,804
Net income (loss) from continuing operations		135,982			219,889			383,105			(28,215	)		(551,372	)		159,389
Discontinued operations, net of income tax		6,572			(1,691	)		(21,564	)		(152	)		—			(16,835	)
Net income (loss)	$	142,554		$	218,198		$	361,541		$	(28,367	)	$	(551,372	)	$	142,554

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

Consolidating Statements of Comprehensive Income

Year Ended December 31, 2011

(in thousands)

	Parent			Issuer			Guarantor Subsidiaries		Non- Guarantor Subsidiaries			Eliminations			Consolidated
Net income (loss)	$	142,554		$	218,198		$	361,541	$	(28,367	)	$	(551,372	)	$	142,554
Change in cumulative translation adjustment		(1,236	)		(1,236	)		—		(1,236	)		2,472			(1,236	)
Comprehensive income (loss)	$	141,318		$	216,962		$	361,541	$	(29,603	)	$	(548,900	)	$	141,318

78

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	$	—		$	—		$	1,295,946		$	337,526		$	(70,429	)	$	1,563,043
Cost of services (exclusive of items shown separately below)		—			—			687,519			231,082			(70,109	)		848,492
Depreciation, depletion, amortization and accretion		—			515			169,528			38,054			—			208,097
General and administrative expenses		322			98,220			181,234			53,146			(320	)		332,602
Income (loss) from operations		(322	)		(98,735	)		257,665			15,244			—			173,852
Other income (expense):
Interest expense, net of amounts capitalized		—			(53,716	)		(216	)		(2,548	)		—			(56,480	)
Interest income		—			150			4,459			526						5,135
Intercompany interest income (expense)		—			15,883			—			(15,883	)					—
Other income (expense)		—			825			—			—						825
Earnings (losses) from consolidated subsidiaries		119,801			255,257			3,555			—			(378,613	)		—
Earnings (losses) from equity-method investments, net		—			985			—			7,260						8,245
Income (loss) from continuing operations before income taxes		119,479			120,649			265,463			4,599			(378,613	)		131,577
Income taxes		39,722			—			—			5,709			—			45,431
Net income (loss) from continuing operations		79,757			120,649			265,463			(1,110	)		(378,613	)		86,146
Discontinued operations, net of income tax		2,060			(848	)		(5,387	)		(154	)		—			(4,329	)
Net income (loss)	$	81,817		$	119,801		$	260,076		$	(1,264	)	$	(378,613	)	$	81,817

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

Consolidating Statements of Comprehensive Income

Year ended December 31, 2010

(in thousands)

	Parent			Issuer			Guarantor Subsidiaries		Non- Guarantor Subsidiaries			Eliminations			Consolidated
Net income (loss)	$	81,817		$	119,801		$	260,076	$	(1,264	)	$	(378,613	)	$	81,817
Change in cumulative translation adjustment		(6,704	)		(6,704	)		—		(6,704	)		13,408			(6,704	)
Comprehensive income (loss)	$	75,113		$	113,097		$	260,076	$	(7,968	)	$	(365,205	)	$	75,113

79

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows

Year Ended December 31, 2012

(in thousands)

	Parent			Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:
Net income (loss)	$	365,935		$	566,020		$	811,766		$	46,884		$	(1,424,670	)	$	365,935
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		—			685			426,585			83,256			—			510,526
Deferred income taxes		7,429			—			—			3,789			—			11,218
Excess tax benefit from stock-based compensation		(1,555	)		—			—			—			—			(1,555	)
Gain on sale of equity-method investment		—			(17,880	)		—			—			—			(17,880	)
Stock-based and performance share unit compensation expense		—			36,570			—			—			—			36,570
Retirement and deferred compensation plan expense		—			1,607			—			—			—			1,607
(Earnings) losses from consolidated subsidiaries		(566,021	)		(811,768	)		(46,881	)		—			1,424,670			—
(Earnings) losses from equity-method investments, net of cash received		—			2,787			—			573			—			3,360
Amortization of debt acquisition costs and note discount		—			9,856			—			—			—			9,856
Gain on sale of business		—			—			6,649			—			—			6,649
Write-off of debt acquisition costs and discount		—			2,714			—			746			—			3,460
Other reconciling items, net		—			2,860			(3,369	)		1,714						1,205
Changes in operating assets and liabilities, net of acquisitions and dispositions:
Accounts receivable		—			(493	)		28,821			(71,274	)		—			(42,946	)
Inventory and other current assets		—			174			63,260			(714	)		—			62,720
Accounts payable		—			(1,115	)		(56,323	)		26,461			—			(30,977	)
Accrued expenses		8			(17,540	)		(47,423	)		38,848			—			(26,107	)
Decommissioning liabilities		—			—			(4,660	)		—			—			(4,660	)
Income taxes		154,879			—			—			(2,786	)					152,093
Other, net		(23	)		731			4,919			(11,658	)					(6,031	)
Net cash provided by (used in) operating activities		(39,348	)		(224,792	)		1,183,344			115,839			—			1,035,043
Cash flows from investing activities:
Payments for capital expenditures		—			(5,041	)		(982,231	)		(154,650	)		—			(1,141,922	)
Sale of available-for-sale securities		—			41,874			—			—			—			41,874
Change in restricted cash held for acquisition of business		—			785,280			—			—			—			785,280
Acquisitions of businesses, net of cash acquired		—			(1,229,327	)		103,952			34,214			—			(1,091,161	)
Cash proceeds from sale of businesses		—			183,094			—			—			—			183,094
Cash proceeds from the sale of equity-method investment		—			34,087			—			—			—			34,087
Other		—			—			26,154			5,476			—			31,630
Intercompany receivables/payables		20,550			273,952			(322,966	)		28,464			—			—
Net cash provided by (used in) investing activities		20,550			83,919			(1,175,091	)		(86,496	)		—			(1,157,118	)
Cash flows from financing activities:
Proceeds from revolving line of credit		—			696,439			—			—			—			696,439
Payments on revolving line of credit		—			(771,439	)		—			—			—			(771,439	)
Proceeds from long-term debt		—			400,000			—			—			—			400,000
Principal payments on long-term debt		—			(165,000	)		—			(12,546	)		—			(177,546	)
Payment of debt acquisition costs		—			(25,274	)		—			—			—			(25,274	)
Proceeds from exercise of stock options		14,777			—			—			—			—			14,777
Excess tax benefit from stock-based compensation		1,555			—			—			—			—			1,555
Proceeds from issuance of stock through employee benefit plans		2,855			—			—			—			—			2,855
Other		(389	)		(3,424	)		(3,000	)		(3,570	)					(10,383	)
Net cash provided by (used in) financing activities		18,798			131,302			(3,000	)		(16,116	)		—			130,984
Effect of exchange rate changes on cash		—			—			—			2,016			—			2,016
Net increase (decrease) in cash and cash equivalents		—			(9,571	)		5,253			15,243			—			10,925
Cash and cash equivalents at beginning of period		—			29,057			6,272			44,945			—			80,274
Cash and cash equivalents at end of period	$	—		$	19,486		$	11,525		$	60,188		$	—		$	91,199

80

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			Eliminations			Consolidated
Cash flows from operating activities:
Net income (loss)	$	142,554		$	218,198		$	361,541		$	(28,367	)	$	(551,372	)	$	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 plan expense		—			1,990			—			—			—			1,990
(Earnings) losses from consolidated subsidiaries		(218,198	)		(330,553	)		(2,621	)		—			551,372			—
(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 (used in) 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 business		—			(785,280	)		—			—			—			(785,280	)
Purchases of short-term investments, net		—			(223,491	)		—			—			—			(223,491	)
Proceeds from the sale of short-term investments, net		—			223,630			—			—			—			223,630
Acquisitions of businesses, net of cash acquired		—			—			(1,200	)		(548	)		—			(1,748	)
Cash 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 provided by (used in) investing activities		14,485			(660,219	)		(613,782	)		9,607			—			(1,249,909	)
Cash flows from financing activities:
Proceeds from revolving line of credit		—			324,913			—			—			—			324,913
Payments on revolving line of credit		—			(424,913	)		—			—						(424,913	)
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 acquisition 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 provided by (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

81

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			Eliminations			Consolidated
Cash flows from operating activities:
Net income (loss)	$	81,817		$	119,801		$	260,076		$	(1,264	)	$	(378,613	)	$	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		—			33,602			—			—			—			33,602
Retirement and deferred compensation plans expense		—			4,825			—			—			—			4,825
(Earnings) losses from consolidated subsidiaries		(119,801	)		(255,257	)		(3,555	)		—			378,613			—
(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			(595	)		1,735			7,181			—			8,359
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 (used in) 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 provided by (used in) investing activities		12,359			(99,706	)		(516,306	)		180			—			(603,473	)
Cash flows from financing activities:
Proceeds from revolving line of credit		—			575,867			—			—			—			575,867
Payments on revolving line of credit					(577,867	)											(577,867	)
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 provided by (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

82

(18) Interim Financial Information (Unaudited)

The following is a summary of consolidated interim financial information for the two years ended December 31, 2012 and 2011:

	Three Months Ended
	March 31			June 30			Sept. 30		Dec. 31
2012
Revenues	$	966,837		$	1,243,319		$	1,179,665	$	1,178,247
Less:
Cost of services, rentals and sales		546,767			711,284			708,608		722,814
Depreciation, depletion, amortization and accretion		102,596			135,516			128,160		143,009
Gross profit		317,474			396,519			342,897		312,424
Net income from continuing operations		70,157			142,823			93,887		76,275
Income (loss) from discontinued operations, net of tax		(16,237	)		(970	)		—		—
Earnings per share from continuing operations:
Basic	$	0.56		$	0.91		$	0.60	$	0.50
Diluted		0.55			0.90			0.59		0.50
Discontinued operations:
Basic	$	(0.13	)	$	(0.01	)	$	—	$	—
Diluted		(0.13	)		(0.01	)		—		—
	Three Months Ended
	March 31			June 30			Sept. 30		Dec. 31
2011
Revenues	$	384,997		$	479,893		$	537,042	$	562,400
Less:
Cost of services, rentals and sales		217,022			250,667			285,124		293,596
Depreciation, depletion, amortization and accretion		55,824			60,020			61,807		67,264
Gross profit		112,151			169,206			190,111		201,540
Net income from continuing operations		9,877			41,375			54,799		53,338
Income (loss) from discontinued operations, net of tax		5,626			6,734			4,781		(33,976	)
Earnings per share from continuing operations:
Basic	$	0.12		$	0.52		$	0.69	$	0.67
Diluted		0.12			0.51			0.67		0.67
Discontinued operations:
Basic	$	0.07		$	0.08		$	0.06	$	(0.42	)
Diluted		0.07			0.08			0.06		(0.42	)

(19) 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. The Company also had an interest in oil and gas operations through its equity-method investment in Dynamic Offshore (see note 7).

83

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 those companies that have significant oil - and gas-producing activities. For the years ended December 31, 2010 and 2011, the Company was deemed to have significant oil and gas activities. For the year ended December 31, 2012, those activities are no longer considered significant.

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

84

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

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

85

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

86

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.

87

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, 2012 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, 2012, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

88

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, 2012. 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, 2012 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, 2012, our internal control over financial reporting was effective based on those criteria.

Our internal control over financial reporting as of December 31, 2012 has been audited by KPMG, LLP, an independent registered public accounting firm, as stated in their report which appears herein.

89

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, 2012, 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, 2012, 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, 2012 and 2011, and the related consolidated statements of income, comprehensive income, changes in stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2012, and our report dated February 28, 2013 expressed an unqualified opinion on those consolidated financial statements.

KPMG LLP

New Orleans, Louisiana

February 28, 2013

90

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 of 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.

91

PART IV

Item 15. Exhibits, Financial Statement Schedules

(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

Consolidated Balance Sheets as of December 31, 2012 and 2011

Consolidated Statements of Income for the years ended December 31, 2012, 2011 and 2010

Consolidated Statements of Changes in Stockholders’ Equity for the years ended December 31, 2012, 2011 and 2010

Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010

Notes to Consolidated Financial Statements

Management’s Report on Internal Control over Financial Reporting

Report of Independent Registered Public Accounting Firm - Audit of Internal Control over Financial Reporting

(2) Financial Statement Schedule

Schedule II – Valuation and Qualifying Accounts for the years ended December 31, 2012, 2011 and 2010

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	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. (incorporated herein by reference to Exhibit 3.1 to Superior Energy Services, Inc.’s Form 10-K filed February 28, 2012 (File No. 001-34037)).
3.2	Amended and Restated Bylaws of Superior Energy Services, Inc. (as amended through March 7, 2012) (incorporated herein by reference to Exhibit 3.1 to Superior Energy Services, Inc.’s Form 8-K filed March 12, 2012 (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)).
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

92

Exhibit No.	Description
	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., 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)), as further amended by Supplemental Indenture, dated February 29, 2012, by and among SPN Fairway Acquisition, Inc., A&W Water Service, Inc., AWS, Inc., Hamm & Phillips Service Company, Inc., Integrated Production Services, Inc., LEED Tool Corporation, Monument Well Service Co., Pumpco Energy Services, Inc., Rising Star Services, L.P., Texas CES, Inc., and 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 by reference to Exhibit 4.1 to Superior Energy Services, Inc.’s Form 8-K filed March 1, 2012 (File No. 001-34037)), as further amended by Supplemental Indenture dated May 7, 2012, by and among CES Mid-Continent Hamm, LLC, CES Rockies, Inc., Complete Energy, LLC, SESI, L.L.C. 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 by reference to Exhibit 4.1 to Superior Energy Services, Inc.’s Form 8-K filed May 8, 2012 (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)), as amended by Supplemental Indenture, dated February 29, 2012, by and among SPN Fairway Acquisition, Inc., A&W Water Service, Inc., AWS, Inc., Hamm & Phillips Service Company, Inc., Integrated Production Services, Inc., LEED Tool Corporation, Monument Well Service Co., Pumpco Energy Services, Inc., Rising Star Services, L.P., Texas CES, Inc., and 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 by reference to Exhibit 4.2 to Superior Energy Services, Inc.’s Form 8-K filed March 1, 2012 (File No. 001-34037)), as further amended by Supplemental Indenture dated May 7, 2012, by and among CES Mid-Continent Hamm, LLC, CES Rockies, Inc., Complete Energy, LLC, SESI, L.L.C. 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 by reference to Exhibit 4.2 to Superior Energy Services, Inc.’s Form 8-K filed May 8, 2012 (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)), as amended by Supplemental Indenture, dated February 29, 2012, by and among SPN Fairway Acquisition, Inc., A&W Water Service, Inc., AWS, Inc., Hamm & Phillips Service Company, Inc., Integrated Production Services, Inc., LEED Tool Corporation, Monument Well Service Co., Pumpco Energy Services, Inc., Rising Star Services, L.P., Texas CES, Inc., and 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 by reference to Exhibit 4.3 to Superior Energy Services, Inc.’s Form 8-K filed March 1, 2012 (File No. 001-34037)), as further amended by Supplemental Indenture dated May 7, 2012, by and among CES Mid-Continent Hamm, LLC, CES Rockies, Inc., Complete Energy, LLC, SESI, L.L.C. 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 by reference to Exhibit 4.3 to Superior Energy Services, Inc.’s Form 8-K filed May 8, 2012 (File No. 001-34037)).

93

Exhibit No.	Description
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)).
10.4^	Superior Energy Services, Inc. 2007 Employee Stock Purchase Plan, as amended (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)).

94

Exhibit No.	Description
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)).
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^*	Form of Restricted Stock Award Agreement under Superior Energy Services, Inc.’s incentive plans for awards beginning in 2013.
10.24^*	Form of Performance Share Unit Award Agreement under Superior Energy Services, Inc.’s incentive plans for awards beginning in 2013.
10.25^*	Form of Stock Option Award Agreement under Superior Energy Services, Inc.’s incentive plans for awards beginning in 2013.

95

Exhibit No.	Description
10.26^	Complete Production Services, Inc. Amended and Restated 2001 Stock Incentive Plan (incorporated herein by reference to Exhibit 10.23 to Superior Energy Services, Inc.’s Form 10-K filed February 28, 2012 (File No. 001-34037)).
10.27^	Amendment No. 1 to the Complete Production Services, Inc. Amended and Restated 2001 Stock Incentive Plan (incorporated herein by reference to Exhibit 10.24 to Superior Energy Services, Inc.’s Form 10-K filed February 28, 2012 (File No. 001-34037)).
10.28^	Complete Production Services, Inc. 2008 Incentive Award Plan (incorporated herein by reference to Exhibit 10.25 to Superior Energy Services, Inc.’s Form 10-K filed February 28, 2012 (File No. 001-34037)).
10.29^	Amendment No. 1 to the Complete Production Services, Inc. 2008 Incentive Award Plan (incorporated herein by reference to Exhibit 10.26 to Superior Energy Services, Inc.’s Form 10-K filed February 28, 2012 (File No. 001-34037)).
10.30^	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)), as amended by Amendment No. 1 to Employment Agreement dated December 12, 2012 (incorporated herein by reference to Exhibit 10.3 to Superior Energy Services, Inc.’s Form 8-K filed December 18, 2012 (File No. 001-34037)).
10.31^	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)).
10.32^	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)).
10.33^	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)).
10.34^	Employment Agreement, dated June 1, 2007, between Superior Energy Services, Inc. and Gregory A. Rosenstein (incorporated herein by reference to Exhibit 10.33 to Superior Energy Services, Inc.’s Form 10-K filed February 28, 2012 (File No. 001-34037)).
10.35^	Amended and Restated Complete Production Services, Inc. Executive Agreement, dated December 31, 2008, between Complete Production Services, Inc. and Brian K. Moore (incorporated herein by reference to Exhibit 10.34 to Superior Energy Services, Inc.’s Form 10-K filed February 28, 2012 (File No. 001-34037)).
10.36^	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)).
10.37	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)).
10.38	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)).

96

Exhibit No.	Description
10.39	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)).
10.40	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)).
10.41^	Composite Form of Employment Agreement by and between Superior Energy Services, Inc. and its executive officers (incorporated herein by reference to Exhibit 10.1 to Superior Energy Services, Inc.’s Form 8-K filed December 18, 2012 (File No. 001-34037)).
10.42^	Superior Energy Services, Inc. Change of Control Severance Plan (incorporated herein by reference to Exhibit 10.2 to Superior Energy Services, Inc.’s Form 8-K filed December 18, 2012 (File No. 001-34037)).
10.43^	Superior Energy Services, Inc. Amended and Restated Legacy CPX Incentive Award Plan (incorporated herein by reference to Exhibit 10.1 to Superior Energy Services, Inc.’s Form 10-Q filed November 8, 2012 (File No. 001-34037)).
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. (incorporated herein by reference to Exhibit 99.1 to Superior Energy Services, Inc.’s Form 10-K filed February 28, 2012 ((File No. 001-34037)).
101.INS*	XBRL Instance Document
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

^ Management contract or compensatory plan or arrangement

97

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, 2013	By:	/s/ David D. Dunlap
		David D. Dunlap
		President and 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	President and Chief Executive	February 28, 2013
David D. Dunlap	Officer (Principal Executive Officer)
/s/ Robert S. Taylor	Executive Vice President,	February 28, 2013
Robert S. Taylor	Treasurer and Chief Financial Officer (Principal Financial and Accounting Officer)
/s/ Terence E. Hall	Chairman of the Board	February 28, 2013
Terence E. Hall
/s/ Harold J. Bouillion	Director	February 28, 2013
Harold J. Bouillion
/s/ Enoch L. Dawkins	Director	February 28, 2013
Enoch L. Dawkins
/s/ James M. Funk	Director	February 28, 2013
James M. Funk
/s/ Ernest E. Howard, III	Director	February 28, 2013
Ernest E. Howard, III
/s/ Peter D. Kinnear	Director	February 28, 2013
Peter D. Kinnear
/s/ Michael M. McShane	Director	February 28, 2013
Michael M. McShane
/s/ W. Matt Ralls	Director	February 28, 2013
W. Matt Ralls
/s/ Justin L. Sullivan	Director	February 28, 2013
Justin L. Sullivan

98

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIRIES

Schedule II Valuation and Qualifying Accounts

Years Ended December 31, 2012, 2011 and 2010

(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, 2012:
Allowance for doubtful accounts	$	17,484	$	13,539	$	2,308	$	28,715
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

99